diff --git a/raw/filings/0000077877/2014/0000077877-15-000012/filing.txt b/raw/filings/0000077877/2014/0000077877-15-000012/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..e935d7dcc899047fb7846b666b6ee43038893fe3 --- /dev/null +++ b/raw/filings/0000077877/2014/0000077877-15-000012/filing.txt @@ -0,0 +1,7148 @@ +10-K +1 +pdce-10kxfy14.htm +PDC ENERGY 2014 FORM 10-K +PDCE-10K-FY14 +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +T ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2014 +or +£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from __________ to _________ +Commission File Number 000-07246 +PDC ENERGY, INC. +(Exact name of registrant as specified in its charter) +Nevada +95-2636730 +(State of incorporation) +(I.R.S. Employer Identification No.) +1775 Sherman Street, Suite 3000 +Denver, Colorado 80203 +(Address of principal executive offices) (Zip code) +Registrant's telephone number, including area code: (303) 860-5800 +Securities registered pursuant to Section 12(b) of the Act: +Title of each class +Name of each exchange on which registered +Common Stock, par value $0.01 per share +NASDAQ Global Select Market +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes T No £ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes £ No T +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes T No £ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes T No £ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. £ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. +Large accelerated filer x +Accelerated filer o +Non-accelerated filer £ +(Do not check if a smaller reporting company) +Smaller reporting company o +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes £ No T +The aggregate market value of our common stock held by non-affiliates on June 30, 2014 was $2.2 billion (based on the closing price of $63.15 per share as of the last business day of the fiscal quarter ending June 30, 2014). +As of February 2, 2015 , there were 35,991,142 shares of our common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +We hereby incorporate by reference into this document the information required by Part III of this Form, which will appear in our definitive proxy statement to be filed pursuant to Regulation 14A for our 2015 Annual Meeting of Stockholders. +PDC ENERGY, INC. +2014 ANNUAL REPORT ON FORM 10-K +TABLE OF CONTENTS +PART I +Page +Items 1. and 2. +Business and Properties +2 +Item 1A. +Risk Factors +18 +Item 1B. +Unresolved Staff Comments +32 +Item 3. +Legal Proceedings +32 +Item 4. +Mine Safety Disclosures +32 +PART II +Item 5. +Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +33 +Item 6. +Selected Financial Data +35 +Item 7. +Management's Discussion and Analysis of Financial Condition and Results of Operations +36 +Item 7A. +Quantitative and Qualitative Disclosures About Market Risk +54 +Item 8. +Financial Statements and Supplementary Data +56 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +96 +Item 9A. +Controls and Procedures +96 +Item 9B. +Other Information +96 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +97 +Item 11. +Executive Compensation +97 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +97 +Item 13. +Certain Relationships and Related Transactions, and Director Independence +97 +Item 14. +Principal Accounting Fees and Services +97 +PART IV +Item15. +Exhibits, Financial Statement Schedule +97 +Signatures +99 +Glossary of Units of Measurements and Industry Terms +100 +PART I +REFERENCES TO THE REGISTRANT +Unless the context otherwise requires, references in this report to "PDC Energy," "PDC," "the Company," "we," "us," "our" or "ours" refer to the registrant, PDC Energy, Inc. and all subsidiaries consolidated for the purposes of its financial statements, including our proportionate share of the financial position, results of operations, cash flows and operating activities of our affiliated partnerships and PDC Mountaineer, LLC ("PDCM"), a joint venture owned until its sale in October 2014 50% each by PDC and Lime Rock Partners, LP. Unless the context otherwise requires, references in this report to "Appalachian Basin" refers to our operations in the Utica Shale in Ohio and Marcellus Shale in West Virginia and Pennsylvania, including PDC's proportionate share of our affiliated partnerships' and PDCM's assets, results of operations, cash flows and operating activities. See Note 1, Nature of Operations and Basis of Presentation, to our consolidated financial statements included elsewhere in this report for a description of our consolidated subsidiaries and Note 14, Assets Held for Sale, Divestitures and Discontinued Operations , for a discussion of the sale of our interest in PDCM. +GLOSSARY OF UNITS OF MEASUREMENTS AND INDUSTRY TERMS +Units of measurements and industry terms are defined in the Glossary of Units of Measurements and Industry Terms, included at the end of this report. +SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS +This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical facts included in and incorporated by reference into this report are "forward-looking statements" within the meaning of the safe harbor provisions of the United States ("U.S.") Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein. These statements relate to, among other things: estimated future production (including the components of such production), sales, expenses, cash flows and liquidity; estimated crude oil, natural gas and natural gas liquids (“NGLs”) reserves; the impact of prolonged depressed commodity prices; anticipated 2015 capital projects, expenditures and opportunities; expected timing of additional drilling rigs; availability of sufficient funding for our 2015 capital program and sources of that funding; expected 2015 capital budget allocations; future exploration, drilling and development activities, including the number of drilling rigs we expect to run during 2015 and number of locations; capital efficiencies and per well reserves expected to be realized through drilling of extended length laterals, tighter frac spacing and cost reductions; our evaluation method of our customers' and derivative counterparties' credit risk; effectiveness of our derivative program in providing a degree of price stability; future horizontal drilling projects that are economically producible at certain commodity prices and costs; anticipated reductions in our 2015 cost structure; potential for future impairments; potential acquisitions of additional acreage and other future transactions; electronic, cyber or physical security breaches; the impact of high line pressures and the timing, availability, cost and effect of additional midstream facilities and services going forward; the expected NYMEX differential at our two primary sales hubs; compliance with debt covenants; expected funding sources for conversion of our 3.25% convertible senior notes due 2016; compliance with government regulations; impact of the Colorado task force on oil and gas regulation and potential future ballot initiatives and legislation; the borrowing base under our credit facility; impact of litigation on our results of operations and financial position; the adequacy of existing insurance to cover operating hazards and the availability of such insurance on a cost effective basis in the future; that we hold good and defensible title to our leasehold; that we do not expect to pay dividends in the foreseeable future; anticipated timing of filing of a new shelf registration statement; and our future strategies, plans and objectives. +The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Consequently, forward-looking statements are inherently subject to risks and uncertainties, including known and unknown risks and uncertainties incidental to the exploration for, and the acquisition, development, production and marketing of, crude oil, natural gas and NGLs, and actual outcomes may differ materially from the results and outcomes discussed in the forward-looking statements. +Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to: +• +changes in worldwide production volumes and demand, including economic conditions that might impact demand; +• +volatility of commodity prices for crude oil, natural gas and NGLs and the risk of an extended period of depressed prices; +• +impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement related to those laws and regulations, liabilities arising thereunder and the costs to comply with those laws and regulations; +• +potential declines in the value of our crude oil, natural gas and NGLs properties resulting in impairments; +• +changes in estimates of proved reserves; +• +inaccuracy of reserve estimates and expected production rates; +• +potential for production decline rates from our wells being greater than expected; +• +timing and extent of our success in discovering, acquiring, developing and producing reserves; +• +our ability to secure leases, drilling rigs, supplies and services at reasonable prices; +• +availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production and the impact of these facilities and regional capacity on the prices we receive for our production; +1 +• +timing and receipt of necessary regulatory permits; +• +risks incidental to the drilling and operation of crude oil and natural gas wells; +• +our future cash flows, liquidity and financial condition; +• +competition within the oil and gas industry; +• +availability and cost of capital; +• +reductions in the borrowing base under our revolving credit facility; +• +our success in marketing crude oil, natural gas and NGLs; +• +effect of crude oil and natural gas derivatives activities; +• +impact of environmental events, governmental and other third-party responses to such events, and our ability to insure adequately against such events; +• +cost of pending or future litigation; +• +effect that acquisitions we may pursue have on our capital expenditures; +• +our ability to retain or attract senior management and key technical employees; and +• +success of strategic plans, expectations and objectives for our future operations. +Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under Item 1A, Risk Factors , made in this report and our other filings with the U.S. Securities and Exchange Commission ("SEC") for further information on risks and uncertainties that could affect our business, financial condition, results of operations and cash flows. We caution you not to place undue reliance on forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement. +ITEMS 1. AND 2. BUSINESS AND PROPERTIES +The Company +We are a domestic independent exploration and production company that produces, develops, acquires and explores for crude oil, natural gas and NGLs with primary operations in the Wattenberg Field in Colorado, the Utica Shale in southeastern Ohio and, until the fourth quarter of 2014, the Marcellus Shale in northern West Virginia. Our 2015 operations in the Wattenberg Field are focused in the inner and middle core areas of the Niobrara and Codell plays. We own an interest in approximately 2,900 gross producing wells, of which approximately 350 are horizontal. Production of 9.3 MMboe from continuing operations for the year ended December 31, 2014 represents an increase of 42% compared to the year ended December 31, 2013 . For the month ended December 31, 2014 , we maintained an average production rate of 30 MBoe per day. As of December 31, 2014 , we had approximately 250 MMBoe of proved reserves ( 30% of which are proved developed) with a pre-tax present value of future net revenues (“PV-10”) of $3.5 billion , representing increases of 24 MMBoe and $0.8 billion , respectively, relative to December 31, 2013 , after adjusting for the divestiture of our Marcellus Shale dry-gas assets. Proved reserves at December 31, 2014 were comprised of approximately 64% liquids and 36% natural gas. Our proved reserve additions included further downspacing in the Wattenberg Field and an increase in per well reserves in our inner core horizontal wells targeting the Niobrara formation. PV-10 is not a financial measure under accounting principles generally accepted in the United States of America (“U.S. GAAP”). See Part I, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10 and a reconciliation of our PV-10 value to our standardized measure. +The increases in our production and estimated proved reserves are primarily attributable to our successful horizontal Niobrara and Codell drilling programs in the Wattenberg Field. Future development of the Wattenberg Field provides the opportunity to add further proved, probable and possible reserves to our portfolio through continued delineation and downspacing of the horizontal Niobrara and Codell formations. Similarly, we believe the Utica Shale provides the opportunity for additional proved, probable and possible reserves in a more favorable crude oil and natural gas pricing environment. In 2014 , we spudded 116 horizontal wells in the Wattenberg Field, turned-in-line 86 horizontal wells and participated in 84 gross, 18.7 net, horizontal non-operated drilling projects. We spudded 11 horizontal Utica Shale wells in 2014 and turned-in-line eight horizontal wells. +2 +The following table presents our proved reserve estimates as of December 31, 2014 based on a reserve report prepared by Ryder Scott Company, L.P. (“Ryder Scott”), our independent petroleum engineering consulting firm, and related information: +Proved Reserves at December 31, 2014 +Proved Reserves (MMBoe) +% of Total Proved Reserves +% Proved Developed +% Liquids +Proved Reserves to Production Ratio (in years) +2014 Production (MBoe) +Wattenberg Field +245 +98 +% +29 +% +64 +% +28.9 +8,484 +Utica Shale +5 +2 +% +77 +% +53 +% +6.5 +805 +Total proved reserves +250 +100 +% +30 +% +64 +% +26.9 +9,289 +Our Strengths +• +Excellent drilling opportunities with a strong liquidity position. +◦ +Multi-year project inventory in premier crude oil, natural gas and NGLs plays. We have a significant operational presence in two key U.S. onshore basins and have identified a substantial inventory of approximately 2,650 gross proved undeveloped and probable horizontal drilling projects. We believe that this inventory will allow us to continue to grow our reserves and production, and that, with respect to the Wattenberg Field in particular, the majority of our projects will generate attractive rates of return at current commodity prices and our expected cost structure. +◦ +Access to liquidity. As of December 31, 2014 , we had a total liquidity position of $398.4 million , comprised of $16.1 million of cash and cash equivalents and $382.3 million available for borrowing under revolving credit facility. We have no near-term debt maturities and had $56.0 million outstanding on our revolving credit facility as of December 31, 2014 . In September 2014, the semi-annual redetermination of our revolving credit facility's borrowing base was completed, resulting in an increase in the borrowing base from $450 million to $700 million. We elected to maintain the aggregate commitment at $450 million. Considering the additional $250 million borrowing base available under our revolving credit facility, subject to certain terms and conditions of the agreement, our liquidity position as of December 31, 2014 would have been $648.3 million . +◦ +Derivative program. We actively hedge our future exposure to commodity price fluctuations by entering into crude oil and natural gas collars, fixed-price swaps and basis protection swaps. As of December 31, 2014 , we have hedged approximately 5,200 MBbls, or approximately 79% to 85% , of our expected crude oil production in 2015 at a weighted-average minimum price of $88.61 per Bbl and a weighted-average maximum price of $90.07 per Bbl. As of the same date, we have hedged approximately 22.5 Bcf, or approximately 74% to 79% , of our expected natural gas production in 2015 at a weighted-average minimum price of $3.90 per Mcf and and a weighted-average maximum price of $4.02 per Mcf. While our derivative program limits the upside benefits we may otherwise receive during periods of higher commodity prices, the program helps protect our cash flows, borrowing base and liquidity during periods of depressed commodity prices. +• +Track record of reserve and production growth. Our proved reserves have grown from 38 MMBoe at December 31, 2009 , after adjusting for subsequent divestitures, to approximately 250 MMBoe at December 31, 2014 , representing a compound annual growth rate (“CAGR”) of 46% . During the same time period, our proved crude oil and NGL reserves grew at a CAGR of 55% . Our annual production from continuing operations grew from 2.7 MMBoe in 2009 to 9.3 MMBoe in 2014 , representing a CAGR of 28% . +• +Horizontal drilling and completion experience. We have a proven track record of applying technical expertise toward developing unconventional resources through horizontal drilling and completion operations. We have transitioned to multi-well pad drilling, extended laterals, increased frac density and enhanced frac design to further optimize costs and enhance horizontal drilling efficiencies. These changes enable us to improve economics and increase well density in our horizontal plays. +• +Significant control in our core areas. As a result of successfully executing our strategy of acquiring largely concentrated acreage positions with a high working interest, we operate and manage approximately 89% of the wells in which we have an interest. Our high percentage of operated properties enables us to exercise a significant level of control with respect to drilling, production, operating and administrative costs, in addition to leveraging our base of technical expertise in our core operating areas. Additionally, this strategy provides us flexibility in selecting drilling locations based upon differing criteria. Our operational control is also enhanced by the fact that a majority of our Wattenberg Field leasehold is held by production. +• +Reputation for strong environmental health and safety compliance program. We believe that we have established a positive reputation for our environmental health and safety program. We believe that this is an important advantage for us in competing in today’s intensive regulatory climate and in working with local communities in which we operate. +3 +• +Community participation and outreach. We are dedicated to being an active and contributing member in the communities in which we operate. We share our success with these communities in various ways, including charitable giving and community event sponsorships. We also encourage our employees to take an active role through our charitable matching contribution fund and by participating in our “Energizing Our Community” day, during which our employees volunteer in the communities in which they work and live. +• +Management experience and operational expertise. We have a management team with a proven track record of drilling performance and a technical and operational staff with expertise in the basins in which we operate, particularly in horizontal drilling, completion and production activities in the Wattenberg Field. +Business Strategy +Our long-term business strategy focuses on generating shareholder value through the development, acquisition and exploration of crude oil and natural gas properties. We are currently focused on the organic growth of our reserves, production and cash flows in our horizontal drilling programs after having completed multiple transactions over the last several years to restructure and simplify our property portfolio. We pursue various midstream, marketing and cost reduction initiatives designed to increase our per unit operating margins while maintaining a conservative and disciplined financial strategy focused on providing sufficient liquidity and balance sheet strength to execute our business strategy. +We focus on horizontal development drilling programs in resource plays that offer repeatable results capable of driving growth in reserves, production and cash flows. We periodically review acquisition opportunities in our core areas of operation as we believe we can extract additional value from such assets through production optimization, refracturing, recompletions and development drilling. In addition, core acquisitions can potentially provide synergies that result in economies of scale from a combined position. While we believe development drilling will remain the foundation of our capital program, we expect to continue our disciplined approach to acquisitions and exploratory drilling. +Development drilling +Our leasehold interests consist of developed and undeveloped crude oil, natural gas and NGLs resources. Based upon our current acreage holdings, we have identified an inventory of approximately 2,650 gross proved undeveloped and probable capital projects for horizontal development. Our 2015 capital program forecast is $473 million , including $435 million of development capital and $38 million for lease acquisition and other capital expenditures. The capital program forecast is a revision to our original 2015 capital budget that was announced in December 2014 and has been adjusted for anticipated service cost reductions and lower non-operated spending, partially offset by increased working interests on certain planned 2015 wells. As a result of our operational flexibility, we have allocated a significantly higher percentage of our 2015 capital program forecast to our higher-return projects in the Wattenberg Field inner and middle core areas. +Wattenberg Field . Our primary focus in the Wattenberg Field is drilling in the horizontal Niobrara and Codell plays. Based on our current drilling program, and considering our inventory of approximately 2,600 gross proved undeveloped and probable horizontal projects, we have nearly 20 years of drilling activity. These projects are primarily located in the core Wattenberg Field, which is further delineated between the inner, middle and outer core. In 2015, we expect to continue to realize additional capital efficiencies through drilling extended length laterals, tighter frac spacing and shifting more of our drilling program to the inner and middle core areas of the field. We plan to enhance our completion design by decreasing the spacing between frac stages from 250 feet to 200 feet. With the modified completion design of more frac stages and anticipated cost structure savings, our gross drilling and completion costs per well for a 4,000 foot length lateral are expected to be approximately $3.6 million and are expected to be approximately $4.6 million for our extended 6,500 to 7,000 foot laterals. We expect increased per well reserves from tighter frac spacing and extended laterals. Additionally, we are drilling the majority of our wells in the inner and middle core areas, which have higher per well reserves than the outer core. +Approximately $414 million of our 2015 capital program forecast is expected to be spent on development activities in the Wattenberg Field, consisting of $358 million for our operated drilling program, of which 91% is directed towards the inner and middle core, and $56 million for non-operated projects. We expect to spud approximately 119 and turn in line 109 horizontal Niobrara or Codell wells of which 40% are expected to be extended length laterals. Approximately 60% of those wells are expected to target the Niobrara formation with the remainder targeting the Codell formation. We expect to participate in approximately 85 gross, 14.2 net, non-operated horizontal opportunities in 2015 . We plan to invest approximately $21 million on other capital expenditures in the Wattenberg Field. The 2015 capital program forecast maintains our five-rig drilling program in the Wattenberg Field and is based upon the commodity price environment experienced in the first quarter of 2015. A further deterioration of commodity prices could negatively impact our financial condition and results of operations. We may further revise our capital program forecast during the year as a result of, among other things, commodity prices, acquisitions or dispositions of assets, drilling results, changes in our borrowing capacity and/or significant changes in cash flows. +Utica Shale . During 2014, we continued to delineate and develop our leasehold position in the Utica Shale. However, based on current low commodity prices and large natural gas price differentials in Appalachia, we elected to temporarily cease drilling in the Utica Shale at the end of 2014. We recognized an impairment charge of $158.3 million to write-down our Utica Shale producing and non-producing crude oil and natural gas properties to their estimated fair value. The impairment of undeveloped acreage is primarily on acreage located outside the condensate and wet natural gas windows of the Utica Shale. For 2015, we plan to invest a total of $35 million in the Utica Shale play to complete and turn-in-line a four-well pad that was in process as of December 31, 2014 and for lease acquisition and other capital +4 +expenditures. We expect to resume our Utica Shale drilling program when commodity prices and net-back realizations rebound. We remain committed to the strong Utica Shale resource we are developing in the condensate and wet natural gas windows of the play. In 2015, we will develop production, reservoir and completion analyses from our recently drilled wells and will incorporate the data into our future drilling programs. We currently estimate that we have approximately 50 gross probable projects for horizontal drilling in the condensate and wet natural gas windows of the Utica Shale and have spudded 24 horizontal wells through December 31, 2014 . +Operational and financial risk management +We proactively employ strategies to help reduce the financial risks associated with our industry. One such strategy is to maintain a balanced production mix of liquids and natural gas. During 2014 , we produced crude oil, natural gas and NGLs with a production mix of approximately 65% liquids and 35% natural gas. This strategy of a diversified commodity mix helps mitigate the financial impact from a decline in the market price of any one of our commodities. In addition, we utilize commodity-based derivative instruments to manage a substantial portion of our exposure to price volatility with regard to our crude oil and natural gas sales and natural gas marketing segments. As of December 31, 2014 , we had natural gas and crude oil derivative positions in place for 2015 covering approximately 5,200 MBbls of our crude oil production and approximately 22.5 Bcf of our natural gas production. Currently, we do not hedge our NGL production. +Strategic acquisitions +We typically pursue the acquisition of assets that may have value from producing wells and behind-pipe reserves, but most important, from high quality undeveloped drilling locations. We seek properties with large undeveloped drilling upside where we believe we can utilize our operational abilities to add shareholder value. We have an experienced team of management, engineering, geosciences and commercial professionals who identify and evaluate acquisition opportunities. +Wattenberg Field. In June 2012, we acquired certain assets from affiliates of Merit Energy (the "Merit Acquisition") for an aggregate purchase price of $304.6 million . The acquired assets comprise approximately 30,000 net acres located almost entirely in the core Wattenberg Field and in close proximity to our then-existing acreage position. Our total position in the core Wattenberg Field is now approximately 96,000 net acres. +Utica Shale. Over the past three years, we have acquired approximately 67,000 net acres of Utica leaseholds, targeting the condensate and wet natural gas windows of the Utica Shale play in southeastern Ohio. As an early entrant into the development of the Utica Shale, we believe we have gained valuable experience in drilling and developing the condensate and wet natural gas windows of the play. +Strategic divestitures +We continue to seek ways to optimize our asset portfolio as part of our business strategy. This may include divesting lower return assets and reinvesting in our stronger economic inventory. As a result, we have divested several assets over the past few years. +Appalachian Marcellus Shale Assets. In October 2014 , we completed the sale of our entire 50% ownership interest in PDCM to an unrelated third-party for aggregate consideration, after our share of PDCM's debt repayment and other working capital adjustments, of approximately $192 million , comprised of approximately $153 million in net cash proceeds and a promissory note due in 2020 of approximately $39 million . The transaction included the buyer's assumption of our share of the firm transportation commitment related to the assets owned by PDCM, as well as our share of PDCM's natural gas hedging positions for the years 2014 through 2017. The divestiture resulted in a pre-tax gain of $76.3 million . Proceeds from the divestiture were used to reduce outstanding borrowings on our revolving credit facility and to fund a portion of our 2014 capital budget. Our proportionate share of PDCM's Marcellus Shale results of operations has been separately reported as discontinued operations in the consolidated statements of operations for all periods presented. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations , to our consolidated financial statements included elsewhere in this report for additional information regarding this divestiture. +Appalachian Shallow Upper Devonian Gas Assets. In December 2013, we divested our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin crude oil and natural gas properties previously owned directly by us, as well as through our proportionate share of PDCM, for aggregate consideration of approximately $20.6 million , of which our share of the proceeds was approximately $5.1 million . We received our proportionate share of cash proceeds and a note receivable. Concurrent with the closing of the transaction, our $6.7 million irrevocable standby letter of credit and an agreement for firm transportation services was released and novated to the buyer. +Colorado Dry Gas Assets. In June 2013, we completed the sale of our non-core Colorado dry gas assets, primarily natural gas producing properties located in the Piceance Basin, northeastern Colorado and other non-core areas, to certain affiliates of Caerus Oil and Gas LLC (“Caerus”) for consideration of $177.6 million , with an additional $17 million paid to our non-affiliated investor partners in our affiliated partnerships. The sale resulted in a pre-tax loss of $2.3 million. The proceeds from the asset disposition were used to pay down our revolving credit facility and to fund a portion of our 2013 capital budget. +Selective exploration +With the current commodity pricing environment, we do not expect our exploration activity to be significant in 2015. Historically, we have pursued a disciplined exploration program intended to replenish our portfolio and to position us for production and reserve growth in future years. We have attempted to identify potential plays in their early stages in order to accumulate significant leasehold positions +5 +prior to competitive forces driving up the cost of entry and to invest in leasehold positions that are in the proximity of existing or emerging midstream infrastructure. +Business Segments +We divide our operating activities into two segments: (1) Oil and Gas Exploration and Production and (2) Gas Marketing. +Oil and Gas Exploration and Production +Our Oil and Gas Exploration and Production segment primarily reflects revenues and expenses from the production and sale of crude oil, natural gas and NGLs, commodity price risk management, net, and well operations and pipeline income. The exploration and production of crude oil, natural gas and NGLs involves the acquisition or leasing of mineral rights to proved reserves and related surface rights. Prior to development of these properties, we assess the economic viability of potential well development opportunities. We then develop the reserves through the drilling of oil and gas wells, which are drilled, completed and put into production. Subsequent to completion, we operate and maintain the wells while controlling associated production costs. Upon extraction of the estimated recoverable reserves from a well, it is plugged and surface disturbance surrounding the well and producing facilities is remediated. In some cases, we may also own a working interest in wells operated by unrelated third-parties. The Oil and Gas Exploration and Production segment's most significant customers are currently Suncor Energy Marketing, Inc., Concord Energy, LLC, DCP Midstream, LP and Teppco Crude Oil, LLC. Sales to each of these parties constitute more than 10% of our revenues. +Our crude oil, natural gas and NGLs production is gathered, marketed and sold as follows: +• +Crude oil . We do not refine any of our crude oil production. In the Wattenberg Field, crude oil is sold at each individual well site and transported by the purchasers via truck, pipeline or rail to markets under various purchase contracts with monthly pricing provisions based on NYMEX pricing, adjusted for differentials. We have entered into a five-year agreement, beginning in the second quarter of 2015, which will allow crude oil sold to these purchasers to be transported via pipeline to Cushing, Oklahoma. In addition, we have signed a long term agreement for gathering of crude oil at the wellhead by pipeline from several of our wells and transportation to at least one central point in the Wattenberg Field, with a view toward reducing costs and minimizing truck traffic. In the Utica Shale, crude oil and condensate is sold to local purchasers at each individual well site based on NYMEX pricing, adjusted for differentials, and is typically transported by the purchasers via truck to local refineries, rail facilities or barge loading terminals on the Ohio River. +• +Natural gas . We primarily sell our natural gas to midstream service providers, marketers and utilities. Our natural gas is transported through third-party gathering systems and pipelines and we incur gathering, processing and transportation expenses to move our natural gas from the wellhead to a purchaser-specified delivery point. We generally sell the natural gas that we produce under contracts with indexed, NYMEX or CIG monthly pricing provisions, with the remaining production sold under contracts with daily pricing provisions. Virtually all of our contracts include provisions whereby prices change monthly with changes in the market, with certain adjustments that may be made based on whether a well delivers to a gathering or transmission line and the quality of the natural gas. Therefore, the price of the natural gas fluctuates to remain competitive with other available natural gas supplies. In certain instances, we enter into firm transportation, processing and sales agreements to provide for pipeline capacity to flow and sell a portion of our natural gas volumes. In the Wattenberg Field, the majority of our leasehold is dedicated to our primary midstream provider, DCP Midstream, LP, which gathers and processes wet natural gas produced in the basin and sells our residue gas to various markets. In the fourth quarter of 2014, we entered into an agreement with AKA Energy Group ("AKA") whereby we have committed production from a specified number of new horizontal wells to be drilled and completed prior to mid-2016. Pursuant to the agreement, AKA is required to install and operate, or contract for use of, facilities necessary to receive and purchase production volume committed under the agreement. In the Utica Shale, wet natural gas produced in our northern acreage is gathered and processed pursuant to a firm transportation agreement with MarkWest Utica EMG ("MarkWest") while wet natural gas produced in our southern acreage is gathered and processed by Blue Racer Midstream LLC ("Blue Racer"). We market our Utica residue gas to various purchasers based on a pipeline basis or NYMEX pricing. We are currently selling all of our residue gas from the MarkWest plant at a daily price based on the Chicago Citygate market, and plan to do so through October 2015. +• +NGLs . In the Wattenberg Field, all of our NGLs are sold at the tailgate of the third-party midstream service provider processing plants based on a combination of prices from the Conway hub in Kansas and Mt. Belvieu in Texas where this production is marketed. In the Utica Shale, our NGLs are fractionated and marketed by MarkWest and Blue Racer and sold based on month-to-month pricing in various markets. Our NGL production is sold under both short- and long-term contracts. +Gas Marketing +Our Gas Marketing segment is comprised solely of the operating activities of our wholly-owned subsidiary Riley Natural Gas ("RNG"). RNG specializes in the purchase, aggregation and sale of natural gas production in the Appalachian Basin. Financial results from our gas marketing segment were not material to our consolidated financial statements for any of the periods presented in this report and we do not expect them to be material in the future. RNG purchases for resale natural gas produced by third-party producers, as well as natural gas produced by us in the Utica Shale. The natural gas is marketed to third-party marketers, natural gas utilities and industrial and commercial +6 +customers through transportation services provided by regulated interstate/intrastate pipeline companies. RNG is party to long-term firm transportation, sales and processing agreements for pipeline capacity through August 2022. Following the sale of our 50% ownership interest in PDCM in October 2014, RNG's marketing activities were scaled down and are limited to purchasing, aggregating and selling natural gas production to attempt to meet such volume commitments. After the long-term firm transportation agreements expire, we expect to discontinue this segment. +For additional information regarding our business segments, see Note 17, Business Segments , to our consolidated financial statements included elsewhere in this report. +Areas of Operations +The following map presents the general locations of our development and production activities as of December 31, 2014 : +• +Wattenberg Field, DJ Basin, Colorado. Currently, horizontal wells drilled in this area target the reservoirs in the Niobrara and Codell formations. These horizontal wells have a vertical depth ranging from approximately 6,500 to 7,500 feet, with lateral lengths of approximately 4,000 to 7,000 feet. Using pad drilling, we have increased well density in the horizontal Niobrara and Codell plays, which results in reduced per-well costs. We currently estimate that we have 2,600 gross proved undeveloped and probable horizontal projects in the Wattenberg Field drilling inventory. In addition to our horizontal drilling program, we currently operate approximately 2,450 vertical wells in the Wattenberg Field. +• +Utica Shale, southeastern Ohio. Wells drilled in this area primarily target the Point Pleasant member of the Utica Shale formation. Our acreage targets the condensate and wet natural gas windows of the Utica Shale play throughout southeastern Ohio. The horizontal wells have a vertical depth ranging from approximately 7,000 to 8,000 feet, with lateral lengths of approximately 4,000 to 7,500 feet. We currently estimate that we have approximately 50 gross probable projects for horizontal drilling in the condensate and wet natural gas windows of the Utica Shale. +7 +Properties +Productive Wells +The following table presents our productive wells: +Productive Wells +As of December 31, 2014 +Crude Oil +Natural Gas +Total +Operating Region/Area +Gross +Net +Gross +Net +Gross +Net +Wattenberg Field +403 +246.9 +2,445 +2,200.1 +2,848 +2,447.0 +Utica Shale +16 +12.7 +3 +3.0 +19 +15.7 +Total productive wells +419 +259.6 +2,448 +2,203.1 +2,867 +2,462.7 +Proved Reserves +Our proved reserves are sensitive to future crude oil, natural gas and NGLs sales prices and the related effect on the economic productive life of producing properties. Increases in commodity prices may result in a longer economic productive life of a property or result in recognition of more economically viable proved undeveloped reserves. Decreases in commodity prices may result in negative impacts of this nature. +All of our proved reserves are located onshore in the U.S. Our proved reserve estimates are prepared using the definitions for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a) and other applicable SEC rules. As of December 31, 2014 , all of our proved reserves, including our proportionate share of our affiliated partnerships' reserves, have been estimated by Ryder Scott. +We have a comprehensive process that governs the determination and reporting of our proved reserves. As part of our internal control process, our reserves are reviewed annually by an internal team composed of reservoir engineers, geologists and accounting personnel for adherence to SEC guidelines through a detailed review of land records, available geological and reservoir data, and production performance data. The process includes a review of applicable working and net revenue interests and cost and performance data. The internal team compiles the reviewed data and forwards the data to Ryder Scott. +When preparing our reserve estimates, Ryder Scott did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, production volumes, well test data, historical costs of operations and development, product prices or any agreements relating to current and future operations of properties and sales of production. Ryder Scott prepares an estimate of our reserves in conjunction with an ongoing review by our engineers. A final comparison of data is performed to ensure that the reserve estimates are complete, determined pursuant to acceptable industry methods and with a level of detail we deem appropriate. The final estimated reserve report is reviewed by our engineering staff and management prior to issuance by Ryder Scott. +The professional qualifications of the internal lead engineer primarily responsible for overseeing the preparation of our reserve estimates qualify the engineer as a Reserves Estimator, as defined in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the Society of Petroleum Engineers. This person holds a Bachelor of Science degree in Petroleum and Chemical Refining Engineering with a minor in Petroleum Engineering, has over 37 years of experience in reservoir engineering, is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers and is a registered Professional Engineer in the State of Colorado. +The SEC's reserve rules allow the use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. We used a combination of production and pressure performance, wireline wellbore measurements, offset analogies, seismic data and interpretation, wireline formation tests, geophysical logs and core data to calculate our reserve estimates, including the material additions to the 2014 reserve estimates. All of our proved undeveloped reserves conform to the SEC five-year rule requirement as all proved undeveloped locations are scheduled, according to an adopted development plan, to be drilled within five years of each location’s initial booking date. +Reserve estimates involve judgments and cannot be measured exactly. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. Neither the estimated future net cash flows nor the standardized measure of discounted future net cash flows ("standardized measure") is intended to represent the current market value of our proved reserves. For additional information regarding both of these measures, as well as other information regarding our proved reserves, see the unaudited Supplemental Information - Crude Oil and Natural Gas Information provided with our consolidated financial statements included elsewhere in this report. The following tables provide information regarding our estimated proved reserves: +8 +As of December 31, +2014 +2013 (3) +2012 (3)(4)(5) +Proved reserves +Crude oil and condensate (MMBbls) +101 +94 +59 +Natural gas (Bcf) +537 +740 +604 +NGLs (MMBbls) +60 +49 +33 +Total proved reserves (MMBoe) +250 +266 +193 +Proved developed reserves (MMBoe) +75 +76 +82 +Estimated future net cash flows (in millions) (1) +$ +4,938 +$ +4,323 +$ +2,756 +PV-10 ( in millions) (2) +$ +3,450 +$ +2,704 +$ +1,709 +Standardized measure (in millions) +$ +2,306 +$ +1,782 +$ +1,168 +___________ +(1) +Amount represents undiscounted pre-tax future net cash flows estimated by Ryder Scott of approximately $7.3 billion , $6.4 billion and $4.0 billion as of December 31, 2014 , 2013 and 2012 , respectively, less an internally-estimated future income tax expense of approximately $2.3 billion , $2.1 billion and $1.2 billion , respectively. +(2) +PV-10 is a non-U.S. GAAP financial measure. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in accordance with U.S. GAAP, but rather should be considered in addition to the standardized measure. See Part I, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10 and a reconciliation of our PV-10 value to the standardized measure. +(3) +Includes estimated reserve data related to our Marcellus Shale crude oil and natural gas properties, which were divested in October 2014. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of these assets. +The following table sets forth information regarding estimated proved reserves for our Marcellus Shale crude oil and natural gas properties: +As of December 31, +2013 +2012 +Proved reserves +Natural gas (Bcf) +237 +179 +Total proved reserves (MMBoe) +40 +30 +Proved developed reserves (MMBoe) +9 +7 +Estimated future net cash flows (in millions) +$ +394 +$ +135 +(4) +Includes estimated reserve data related to our Piceance and northeast Colorado ("NECO") crude oil and natural gas properties which were divested in June 2013. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Piceance and NECO assets. +The following table sets forth information regarding estimated proved reserves for our Piceance and NECO assets: +December 31, 2012 +Proved reserves +Crude oil and condensate (MMBbls) +0.1 +Natural gas (Bcf) +84 +Total proved reserves (MMBoe) +14 +Proved developed reserves (MMBoe) +14 +Estimated future net cash flows (in millions) +$ +56 +(5) +Includes estimated reserve data related to our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin crude oil and natural gas properties, which were divested in December 2013. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to these assets. +9 +The following table sets forth information regarding estimated proved reserves for our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin crude oil and natural gas properties: +December 31, 2012 +Proved reserves +Natural gas (Bcf) +11 +Total proved reserves (MMBoe) +2 +Proved developed reserves (MMBoe) +2 +Estimated future net cash flows (in millions) +$ +3 +The following table presents our estimated proved developed and undeveloped reserves by category and area: +As of December 31, 2014 +Operating Region/Area +Crude Oil and Condensate (MBbls) +Natural Gas +(MMcf) +NGLs +(MBbls) +Crude Oil +Equivalent +(MBoe) +Percent +Proved developed +Wattenberg Field +25,339 +174,680 +16,397 +70,849 +95 +% +Utica Shale +1,459 +11,953 +605 +4,056 +5 +% +Total proved developed +26,798 +186,633 +17,002 +74,905 +100 +% +Proved undeveloped +Wattenberg Field +73,185 +347,525 +42,913 +174,019 +99 +% +Utica Shale +532 +2,814 +204 +1,205 +1 +% +Total proved undeveloped +73,717 +350,339 +43,117 +175,224 +100 +% +Proved reserves +Wattenberg Field +98,524 +522,205 +59,310 +244,868 +98 +% +Utica Shale +1,991 +14,767 +809 +5,261 +2 +% +Total proved reserves +100,515 +536,972 +60,119 +250,129 +100 +% +We have stress-tested our proved reserve estimates as of December 31, 2014 to determine the impact of low commodity prices. Replacing the 2014 NYMEX commodity prices used in estimating our reported proved reserves (see Supplemental Information - Crude Oil and Natural Gas Information, provided with our consolidated financial statements included elsewhere in this report) with those shown on the table below, and leaving all other parameters unchanged, results in a decrease in our estimated proved reserves of 9% or less. +Pricing Scenario - NYMEX +Crude Oil (per Bbl)* +Natural Gas (per MMBtu)* +Proved Reserves (MMBoe) +% Change from December 31, 2014 Estimated Reserves +2014 Reserve Report +$ +94.99 +$ +4.35 +250.1 +— +Scenario A +70.00 +4.00 +238.0 +(5 +)% +Scenario B +60.00 +3.50 +234.0 +(7 +)% +Scenario C +50.00 +3.25 +227.0 +(9 +)% +__________ +* +These prices are indices and do not include basin differentials for crude oil and natural gas. The above reserve stress-test scenarios were calculated using the indicated index prices, less the year-end 2014 differentials we experienced for the respective commodity by basin. +10 +Developed and Undeveloped Acreage +The following table presents our developed and undeveloped lease acreage: +As of December 31, 2014 +Developed +Undeveloped (1) +Total +Operating Region/Area +Gross +Net +Gross +Net +Gross +Net +Wattenberg Field +97,900 +88,500 +8,100 +7,000 +106,000 +95,500 +Utica Shale +3,600 +3,000 +68,200 +63,800 +71,800 +66,800 +Total acreage +101,500 +91,500 +76,300 +70,800 +177,800 +162,300 +__________ +(1) +Approximately 2% , 8% and 20% of our undeveloped leaseholds expire during 2015, 2016 and 2017, respectively, primarily in the Utica Shale. Substantially all of our undeveloped acreage in the Wattenberg Field is related to leaseholds that are held by production. +In 2014, we recognized an impairment charge of $158.3 million to write-down our Utica Shale producing and non-producing crude oil and natural gas properties to their estimated fair value, $45.7 million of which related to capitalized leasehold costs on approximately 27,500 gross, 22,800 net, undeveloped acres primarily located outside the condensate and wet natural gas windows of the Utica Shale. See Note 6, Properties and Equipment, to our consolidated financial statements included elsewhere in this report for additional information. +Drilling Activity +The following table presents information regarding the number of wells drilled or participated in for the period presented: +Year Ended December 31, +2014 +2013 +2012 +Operating Region +Gross +Net +Gross +Net +Gross +Net +Wattenberg Field +158 +85.9 +97 +61.2 +66 +43.0 +Utica Shale +9 +8.0 +11 +8.7 +1 +1.0 +Other (1) +4 +2.0 +10 +5.0 +16 +12.5 +Total wells drilled +171 +95.9 +118 +74.9 +83 +56.5 +__________ +(1) +Includes drilling activity in the Marcellus Shale crude oil and natural gas properties, which were divested in October 2014. +The following tables set forth our developmental and exploratory well drilling activity for the periods presented. There is no necessary correlation between the number of productive wells completed during any period and the aggregate reserves attributable to those wells. Productive wells consist of wells spudded, turned-in-line and producing during the period. In-process wells represent wells that are in the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection as of the date shown. +Net Development Well Drilling Activity +Year Ended December 31, +2014 +2013 +2012 +Operating Region/Area +Productive +In-Process +Dry +Productive +In-Process +Dry +Productive +In-Process +Dry +Wattenberg Field +90.7 +42.8 +1.7 +(1) +53.5 +15.6 +0.1 +31.3 +7.7 +— +Utica Shale +7.0 +3.0 +1.0 +(1) +3.0 +2.0 +— +— +— +— +Other (2) +2.0 +— +— +3.5 +2.0 +— +1.5 +— +— +Total net development wells +99.7 +45.8 +2.7 +60.0 +19.6 +0.1 +32.8 +7.7 +— +__________ +(1) +Represents two mechanical failures in the Wattenberg Field and one mechanical failure in the Utica Shale that resulted in the plugging and abandonment of the respective wells. +(2) +Includes activity in the Marcellus Shale crude oil and natural gas properties, which were divested in October 2014. +11 +Net Exploratory Well Drilling Activity +Year Ended December 31, +2014 +2013 +2012 +Operating Region/Area +Productive +In-Process +Dry +Productive +In-Process +Dry +Productive +In-Process +Dry +Utica Shale +— +— +— +4.2 +— +— +— +1.5 +1.7 +Other (1) +— +— +— +1.5 +— +— +— +— +— +Total net exploratory wells +— +— +— +5.7 +— +— +— +1.5 +1.7 +__________ +(1) +Includes activity in the Marcellus Shale crude oil and natural gas properties, which were divested in October 2014. +Title to Properties +We believe that we hold good and defensible leasehold title to substantially all of our crude oil and natural gas properties in accordance with standards generally accepted in the industry. A preliminary title examination is typically conducted at the time the undeveloped properties are acquired. Prior to the commencement of drilling operations, a title examination is conducted and remedial curative work is performed with respect to discovered defects which we deem to be significant. Title examinations have been performed with respect to substantially all of our producing properties. +The properties we own are subject to royalty, overriding royalty and other outstanding interests. The properties may also be subject to additional burdens, liens or encumbrances customary in the industry, including items such as operating agreements, current taxes, development obligations under crude oil and natural gas leases, farm-out agreements and other restrictions. We do not believe that any of these burdens will materially interfere with our use of the properties. +Substantially all of our crude oil and natural gas properties, excluding our share of properties held by the limited partnerships that we sponsor, have been mortgaged or pledged as security for our revolving credit facility. See Note 8, Long-Term Debt , to our consolidated financial statements included elsewhere in this report. +Facilities +We lease 56,163 square feet of office space in Denver, Colorado, which serves as our corporate office, through February 2021. We own a 32,000 square foot administrative office building located in Bridgeport, West Virginia, where we also lease approximately 18,600 square feet of office space in a second building through April 2015. This lease is not expected to be renewed. +We own or lease field operating facilities in Evans, Colorado and Marietta, Ohio. +Governmental Regulation +While the prices of crude oil and natural gas are market driven, other aspects of our business and the industry in general are heavily regulated. The availability of a ready market for crude oil and natural gas production depends on several factors that are beyond our control. These factors include, but are not limited to, regulation of production, federal and state regulations governing environmental quality and pollution control, the amount of crude oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. In general, state and federal regulations are intended to protect consumers from unfair treatment and undue control, reduce environmental and health risks from the development and transportation of crude oil and natural gas, prevent misuse of crude oil and natural gas and protect rights among owners in a common reservoir. Pipelines are subject to the jurisdiction of various federal, state and local agencies. We believe that we are in compliance with such statutes, rules, regulations and governmental orders in all material respects, although there can be no assurance that this is or will remain the case. The following summary discussion on the regulation of the U.S. oil and gas industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental directives to which our operations may be subject. +Regulation of Crude Oil and Natural Gas Exploration and Production . Our exploration and production business is subject to various federal, state and local laws and regulations relating to the taxation of crude oil and natural gas, the development, production and marketing of crude oil and natural gas and environmental and safety matters. State and local laws and regulations require drilling permits and govern the spacing and density of wells, rates of production, water discharge, prevention of waste and other matters. Prior to commencing drilling activities for a well, we must procure permits and/or approvals for the various stages of the drilling process from the applicable state and local agencies where the well being drilled is located. Additionally, other regulated matters include: +• +bond requirements in order to drill or operate wells; +• +well locations; +• +drilling and casing methods; +• +surface use and restoration of well properties; +• +well plugging and abandoning; +12 +• +fluid disposal; and +• +air emissions. +Colorado Governor Hickenlooper has created a task force charged with crafting recommendations to help minimize land use conflicts relating to the location of oil and gas facilities. The task force was created pursuant to a compromise under which certain potential ballot initiatives that would have impacted the oil and natural gas industry in Colorado were withdrawn from the November 2014 ballot. The task force, which is called the Task Force on State and Local Regulation of Oil and Gas Operations, is comprised of 21 members representing various interests. Recommendations of the task force regarding new or amended legislation, appropriations or other action must be approved by a two-thirds vote of the members and will be submitted to the Governor by no later than February 27, 2015. We cannot predict the outcome of this process or the proposals that are approved by the task force. In addition, depending on the outcome of the task force process and any related legislative or administrative activity, ballot initiatives affecting our operations may be proposed and adopted by the voters in future elections. +In addition, our drilling activities involve hydraulic fracturing, which may be subject to additional federal and state disclosure and regulatory requirements discussed in "Environmental Matters" below and in Item 1A, Risk Factors . +Our operations are also subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells which may be drilled and the unitization or pooling of lands and leases. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is primarily or exclusively voluntary, it may be more difficult to form units, and therefore, more difficult to drill and develop our leases where we own less than 100% of the leases located within the proposed unit. State laws may establish maximum rates of production from crude oil and natural gas wells, prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. Leases covering state or federal lands often include additional regulations and conditions. The effect of these conservation laws and regulations may limit the amount of crude oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Such laws and regulations may increase the costs of planning, designing, drilling, installing, operating and abandoning our crude oil and natural gas wells and other facilities. These laws and regulations, and any others that are passed by the jurisdictions where we have production, can limit the total number of wells drilled or the allowable production from successful wells, which can limit our reserves. As a result, we are unable to predict the future cost or effect of complying with such regulations. +Regulation of Transportation of Natural Gas . We move natural gas through pipelines owned by other companies and sell natural gas to other companies that also utilize common carrier pipeline facilities. Natural gas pipeline interstate transmission and storage activities are subject to regulation by the Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act of 1938 ("NGA") and under the Natural Gas Policy Act of 1978, and, as such, rates and charges for the transportation of natural gas in interstate commerce, accounting, and the extension, enlargement or abandonment of jurisdictional facilities, among other things, are subject to regulation. Each natural gas pipeline company holds certificates of public convenience and necessity issued by FERC authorizing ownership and operation of all pipelines, facilities and properties for which certificates are required under the NGA. Each natural gas pipeline company is also subject to the Natural Gas Pipeline Safety Act of 1968, as amended, which regulates safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. FERC regulations govern how interstate pipelines communicate and do business with their affiliates. Interstate pipelines may not operate their pipeline systems to preferentially benefit their marketing affiliates. +Each interstate natural gas pipeline company establishes its rates primarily through FERC's rate-making process. Key determinants in the ratemaking process are: +• +costs of providing service, including depreciation expense; +• +allowed rate of return, including the equity component of the capital structure and related income taxes; and +• +volume throughput assumptions. +The availability, terms and cost of transportation affect our natural gas sales. Competition among suppliers has greatly increased. Furthermore, gathering is exempt from regulation under the Natural Gas Act, thus allowing gatherers to charge unregulated rates. Historically, producers were able to flow supplies into interstate pipelines on an interruptible basis; however, recently we have seen the increased need to acquire firm transportation on pipelines in order to avoid curtailments or shut-in gas, which could adversely affect cash flows from the affected area. +Additional proposals and proceedings that might affect the industry occur frequently in Congress, FERC, state commissions, state legislatures and the courts. The industry historically has been very heavily regulated and there is no assurance that the current regulatory approach recently taken by FERC and Congress will continue. We cannot determine to what extent our future operations and earnings will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels. +13 +Environmental Matters +Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public demand for the protection of the environment has increased dramatically in recent years. The trend of more expansive environmental legislation and regulations is expected to continue. To the extent laws are enacted or other governmental actions are taken which restrict drilling or impose environmental protection requirements resulting in increased costs, our business and prospects may be adversely affected. +We generate wastes that may be subject to the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S. Environmental Protection Agency ("EPA") and various state agencies have adopted requirements that limit the approved disposal methods for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by our operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore may subject us to more rigorous and costly operating and disposal requirements. +Hydraulic fracturing is commonly used to stimulate production of crude oil and/or natural gas from dense subsurface rock formations. We routinely apply fracturing in our crude oil and natural gas production programs. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the crude oil or natural gas to more easily flow to the wellbore. The process is generally subject to regulation by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over certain fracturing activities involving diesel fuel under the federal Safe Drinking Water Act ("SDWA") and issued draft guidance related to this asserted regulatory authority in February 2014. The guidance explains the EPA’s interpretation of the term “diesel fuel” for permitting purposes, describes existing Underground Injection Control Class II program requirements for permitting underground injection of diesel fuels in hydraulic fracturing and also provides recommendations for EPA permit writers in implementing these requirements. From time to time, Congress has considered legislation that would provide for broader federal regulation of hydraulic fracturing and disclosure of the chemicals used in the hydraulic fracturing process. +The White House Council on Environmental Quality continues to coordinate an administration-wide review of hydraulic fracturing. The EPA continues its study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a draft report expected in 2015, and a final, peer-reviewed report expected in 2016. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. These ongoing studies, depending on their degree of development and nature of results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. The U.S. Department of the Interior, through the Bureau of Land Management (the “BLM”), is also conducting a rulemaking to require disclosure of chemicals used, mandate well integrity measures, and impose other requirements relating to hydraulic fracturing on federal lands. A final rule is expected in 2015. +The states in which we operate, Colorado and Ohio, have adopted regulations regarding permitting, transparency and well construction requirements with respect to hydraulic fracturing operations and may in the future adopt additional regulations or otherwise seek to ban fracturing activities altogether. Colorado requires that all chemicals used in the hydraulic fracturing of a well be reported in a publicly searchable registry website developed and maintained by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission ("Frac Focus"). The Colorado rules also require operators seeking new location approvals to provide certain information to surface owners and adjacent property owners within 500 feet of a new well. Similarly, Colorado has implemented a baseline groundwater sampling rule and a rule governing setback distances of oil and gas wells located near population centers. In December 2013, the Colorado Oil and Gas Conservation Commission (the "COGCC") issued new, more restrictive rules regarding spill reporting and remediation. See further discussion in Item 1A, Risk Factors . +In addition, during 2014, the Colorado Oil and Gas Conservation Act was amended to increase the potential sanctions for violating the Act or its implementing regulations, orders, or permits. These amendments increase the maximum penalty per violation per day from $1,000 to $15,000; eliminate a $10,000 maximum penalty for violations that do not result in significant waste of oil and gas resources, damage to correlative rights, or adverse impact to public health, safety, or welfare; require the COGCC to assess a penalty for each day there is evidence of a violation; and authorize the COGCC to prohibit the issuance of new permits and suspend certificates of clearance for egregious violations resulting from gross negligence or knowing and willful misconduct. In December 2014, the COGCC convened a hearing to consider proposed amendments to its regulations to implement this new legislation and address certain other issues. Among other things, the proposed amendments would create a new process for calculating penalties, new standards for determining days of violation and penalty amounts, and new restrictions on the use of informal enforcement procedures and penalty reductions for voluntary disclosures. A number of state and local government agencies, oil and gas companies, and non-governmental organizations are actively participating in this rulemaking process. We cannot predict the outcome of this rulemaking process, except that any regulatory amendments must be consistent with the 2014 legislation and, according to the COGCC, will have prospective effect. Nor can we predict how such regulatory amendments would affect the penalties assessed by the COGCC in future enforcement cases involving us. Although the proposed amendments could significantly increase future penalty amounts, the COGCC staff has stated that they will seek to ensure that penalties are fair and appropriate. In addition, any penalty must be approved by COGCC order, and any penalty order will be subject to judicial review. +In November 2013, the Ohio Department of Natural Resources ("ODNR") proposed draft regulations pertaining to well pad construction requirements and increased bonding for construction, and these regulations were finalized in 2014. +14 +In Colorado, local governing bodies have begun to issue drilling moratoriums, develop jurisdictional siting, permitting and operating requirements and conduct air quality studies to identify potential public health impacts. For instance, in 2013, the City of Fort Collins, Colorado, adopted a ban on drilling and fracturing of new wells within city limits. In the November 2013 election, voters in the cities of Boulder, Lafayette, Fort Collins and Brighton passed hydraulic fracturing bans. Although we do not currently have operations in any of these areas, see Item 1A, Risk Factors, for a more detailed discussion of these bans. If new laws or regulations that significantly restrict hydraulic fracturing or well locations continue to be adopted at local levels or are adopted at the state level, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of hydrocarbons, may preclude our ability to drill wells. If hydraulic fracturing becomes more heavily regulated as a result of federal legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements and permitting delays, as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of crude oil and natural gas that we are ultimately able to produce from our reserves. We continue to be active in stakeholder and interest groups and to engage with regulatory agencies in an open, proactive dialogue regarding these matters. +We currently own or lease numerous properties that for many years have been used for the exploration and production of crude oil and natural gas. Although we believe that we have utilized good operating and waste disposal practices, and when necessary, appropriate remediation techniques, prior owners and operators of these properties may not have utilized similar practices and techniques and hydrocarbons or other wastes may have been disposed of or released on or under the properties that we own or lease or on or under locations where such wastes have been taken for disposal. These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), RCRA and analogous state laws, as well as state laws governing the management of crude oil and natural gas wastes. Under such laws, we may be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or remediate property contamination (including surface and groundwater contamination) or to perform remedial plugging operations to prevent future contamination. +CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for release of hazardous substances under CERCLA may be subject to full liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Under state laws, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. As an owner and operator of crude oil and natural gas wells, we may be liable pursuant to CERCLA and state laws. +Our operations are subject to the federal Clean Air Act ("CAA") and comparable state and local requirements. The CAA contains provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and states continue the development of regulations to implement these requirements. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. Greenhouse gas record keeping and reporting requirements of the CAA became effective in 2011 and will continue into the future with increased costs for administration and implementation of controls. Federal New Source Performance Standards regarding oil and gas operations ("NSPS OOOO") became effective in 2012, with more amendments effective in 2013 and 2014, all of which have added administrative and operational costs. In addition, EPA has announced a comprehensive strategy to further reduce methane emissions from the oil and gas sector. EPA plans a hybrid approach using both voluntary and regulatory reduction measures. A proposed rule mandating additional reduction measures is expected in 2015 with a final rule expected in 2016. Colorado adopted new regulations to meet the requirements of NSPS OOOO and promulgated significant new rules in February 2014 relating specifically to crude oil and natural gas operations that are more stringent than NSPS OOOO and directly regulate methane emissions from affected facilities. In April 2014, the Ohio Environmental Protection Agency Division of Air Pollution Control adopted new General Permit requirements for High Volume Horizontal Hydraulic Fracturing, Oil and Gas Well Site Production Operations. +EPA has proposed to revise and lower the existing 75 part per billion ("ppb") national ambient air quality standard ("NAAQS") for ozone under the CAA to a range within 65-70 ppb. The EPA is also taking public comment on whether the ozone NAAQS should be revised to as low as 60 ppb. A lower ozone NAAQS in a range of 60-70 ppb could result in a significant expansion of ozone nonattainment areas across the United States, including areas in which we operate. Oil and natural gas operations in ozone nonattainment areas would likely be subject to increased regulatory burdens in the form of more stringent emission controls, emission offset requirement and increased permitting delays and costs. +The federal Clean Water Act ("CWA") and analogous state laws impose strict controls against the discharge of pollutants and fill material, including spills and leaks of crude oil and other substances. The CWA also requires approval and/or permits prior to construction, where construction will disturb wetlands or other waters of the U.S. The CWA also regulates storm water run-off from crude oil and natural gas facilities and requires storm water discharge permits for certain activities. Spill Prevention, Control, and Countermeasure ("SPCC") requirements of the CWA require appropriate secondary containment loadout controls, piping controls, berms and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture or leak. The EPA and U.S. Army Corps of Engineers released a Connectivity Report in September 2013 which determined that virtually all tributary streams, wetlands, open water in floodplains and riparian areas are connected. This report supported the drafting of proposed rules providing updated standards for what will be considered jurisdictional waters of the U.S. The proposed rules have been submitted for public comment and are expected to be finalized in 2015. +15 +The Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. Some of our operations may be located in areas that are or may be designated as habitats for endangered or threatened species. The U.S. Fish and Wildlife Service in May 2014 proposed a rule to alter how it identifies critical habitat for endangered and threatened species. It is unclear when this rule will be finalized. +Crude oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of crude oil spills. Federal regulations require certain owners or operators of facilities that store or otherwise handle crude oil, including us, to procure and implement additional SPCC measures relating to the possible discharge of crude oil into surface waters. The Oil Pollution Act of 1990 ("OPA") subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from crude oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Historically, we have not experienced any significant crude oil discharge or crude oil spill problems. Our shift in production since mid-2010 to a greater percentage of crude oil increases our risks related to soil and water contamination from any future oil spills. +Our costs relating to protecting the environment have risen over the past few years and are expected to continue to rise in 2015 and beyond. Environmental regulations have increased our costs and planning time, but have had no materially adverse effect on our ability to operate to date. However, no assurance can be given that environmental regulations or interpretations of such regulations will not, in the future, result in a curtailment of production or otherwise have a materially adverse effect on our business, financial condition or results of operations. See Note 11, Commitments and Contingencies , to our consolidated financial statements included elsewhere in this report. +Operating Hazards and Insurance +Our exploration and production operations include a variety of operating risks, including, but not limited to, the risk of fire, explosions, blowouts, cratering, pipe failure, casing collapse, abnormally pressured formations and environmental hazards such as gas leaks, ruptures and discharges of crude oil and natural gas. The occurrence of any of these events could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Our pipeline, gathering and distribution operations are subject to the many hazards inherent in the industry. These hazards include damage to wells, pipelines and other related equipment, damage to property caused by hurricanes, floods, fires and other acts of God, inadvertent damage from construction equipment, leakage of natural gas and other hydrocarbons, fires and explosions and other hazards that could also result in personal injury and loss of life, pollution and suspension of operations. In 2013, we experienced widespread flooding in our Wattenberg Field operations in Weld County, Colorado, which resulted in a shut-in of approximately 200 vertical wells. We incurred significant costs to replace damaged well equipment and to bring vertical wells back on-line. In 2014, we experienced three mechanical failures during drilling that resulted in the discharge of oil and related material. The mechanical failures did not have a material adverse effect on our financial condition or results of operations. +Among the regulatory developments involving operating hazards that could impact us going forward are recent investigations by the U.S. Occupational Health and Safety Administration (“OSHA”) and other governmental authorities regarding potential worker exposure to hydrocarbon vapors from certain petroleum transfer and related tasks. Several recent worker fatalities at oil and gas facilities nationwide are being reviewed by OSHA and other governmental authorities for a potential link to hydrocarbon vapor exposure. Regulatory requirements generally relating to worker exposure to hydrocarbon vapors could be increased or receive heightened scrutiny going forward. +Any significant problems related to our facilities could adversely affect our ability to conduct our operations. In accordance with customary industry practice, we maintain insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant event not fully insured against could materially adversely affect our operations and financial condition. We cannot predict whether insurance will continue to be available at premium levels that justify our purchase or will be available at all. Furthermore, we are not insured against our economic losses resulting from damage or destruction to third-party property, such as transportation pipelines, crude oil refineries or natural gas processing facilities. Such an event could result in significantly lower regional prices or our inability to deliver our production. +Competition and Technological Changes +We believe that our production, exploration and drilling capabilities and the experience of our management and professional staff enable us to compete effectively in our industry. We encounter competition from numerous other crude oil and natural gas companies, drilling and income programs and partnerships in all areas of operations, including drilling and marketing crude oil and natural gas, obtaining desirable crude oil and natural gas leases on producing properties, obtaining drilling, pumping and other services, attracting and retaining qualified employees and obtaining capital. International developments may influence other companies to increase their domestic crude oil and natural gas exploration. Competition among companies for favorable prospects can be expected to continue and it is anticipated that the cost of acquiring properties will increase in the future. Many of our competitors possess larger staffs and greater financial resources than we do, which may enable them to identify and acquire desirable producing properties and drilling prospects more economically. Our ability to acquire additional properties and to explore for crude oil and natural gas prospects in the future depends upon our ability to conduct our operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment. We also face intense competition in other aspects of our business, including the marketing of natural gas from competitors including other producers and marketing companies. +16 +The oil and gas industry is characterized by rapid and significant technological advancements and introduction of new products and services using new technologies. If one or more of the technologies we use now or in the future become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, results of operations and cash flows could be materially adversely affected. +Employees +As of December 31, 2014 , we had 343 employees. Our employees are not covered by collective bargaining agreements. We consider relations with our employees to be good. +WHERE YOU CAN FIND ADDITIONAL INFORMATION +We file annual, quarterly and current reports, proxy statements and other information with the SEC. Our SEC filings are available free of charge from the SEC’s website at www.sec.gov or from our website at www.pdce.com. You may also read or copy any document we file at the SEC’s public reference room in Washington, D.C., located at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at (800) SEC-0330 for further information on the public reference room. We also make available free of charge any of our SEC filings by mail. For a mailed copy of a report, please contact PDC Energy Inc., Investor Relations, 1775 Sherman Street, Suite 3000, Denver, CO 80203, or call (800) 624-3821. +We recommend that you view our website for additional information, as we routinely post information that we believe is important for investors. Our website can be used to access such information as our recent news releases, committee charters, code of business conduct and ethics, shareholder communication policy, director nomination procedures and our whistle blower hotline. While we recommend that you view our website, the information available on our website is not part of this report and is not incorporated by reference. +17 +ITEM 1A. RISK FACTORS +You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock or other securities. +Crude oil, natural gas and NGL prices fluctuate and a decline in these prices can significantly affect the value of our assets and our financial results and impede our growth. +Our revenue, profitability, cash flows and liquidity depend in large part upon the prices we receive for our crude oil, natural gas and NGLs. Changes in prices affect many aspects of our business, including: +• +our revenue, profitability and cash flows; +• +our liquidity; +• +the quantity and present value of our reserves; +• +the borrowing base under our revolving credit facility and access to other sources of capital; and +• +the nature and scale of our operations. +The markets for crude oil, natural gas and NGLs are often volatile, and prices may fluctuate in response to, among other things: +• +relatively minor changes in regional, national or global supply and demand; +• +regional, national or global economic conditions, and perceived trends in those conditions; +• +geopolitical factors, such as events that may reduce or increase production from particular oil-producing regions and/or from members of the Organization of Petroleum Exporting Countries, or OPEC; and +• +regulatory changes. +The price of oil fell significantly in the second half of 2014, from a high of $107.26 per barrel in June to a low of $53.27 per barrel in December, in each case based on WTI prices, due to a combination of factors including increased U.S. supply, global economic concerns and a decision by OPEC not to reduce supply. This decline has adversely affected, among other things, our revenue and reserves, and has caused us to reduce our budgeted 2015 capital program relative to 2014 and contributed to the recognition of an impairment charge of $158.3 million to write-down our Utica Shale producing and non-producing crude oil and natural gas properties to their estimated fair value. An extended period of continued lower oil prices, or additional price declines, will have further adverse effects on us. +In addition to factors affecting the price of crude oil, natural gas and NGLs generally, the prices we receive for our production are affected by factors specific to us and to the local markets where the production occurs. The prices that we receive for our production are generally lower than the relevant benchmark prices that are used for calculating commodity derivative positions. These differences, or differentials, are difficult to predict and may widen or narrow in the future based on market forces. Differentials can be influenced by, among other things, local or regional supply and demand factors and the terms of our sales contracts. Over the longer term, differentials will be significantly affected by factors such as investment decisions made by providers of midstream facilities and services, refineries and other industry participants, and the overall regulatory and economic climate. For example, increases in U.S. domestic oil production generally may result in widening differentials, particularly for production from some basins. We may be materially and adversely impacted by widening differentials on our production. +The marketability of our production is dependent upon transportation and processing facilities the capacity and operation of which we do not control. Market conditions or operational impediments, including high line pressures, particularly in the Wattenberg Field, and other impediments affecting midstream facilities and services, could hinder our access to crude oil, natural gas and NGL markets, increase our costs or delay production and thereby adversely affect our profitability. +Our ability to market our production depends in substantial part on the availability, proximity and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. If adequate midstream facilities and services are not available to us on a timely basis and at acceptable costs, our production and results of operations will be adversely affected. These risks are greater for us than for some of our competitors because our operations are focused on areas where there is currently a substantial amount of development activity, which increases the likelihood that there will be periods of time in which there is insufficient midstream capacity to accommodate the resulting increases in production. For example, due to ongoing drilling activities by us and third parties, and hot temperatures during the summer months, the principal third-party provider we use in the Wattenberg area for midstream facilities and services experiences increased gathering system pressures during those warmer months. The resulting capacity constraints typically reduce the productivity of some of our older vertical wells and may on occasion limit incremental production from some of our newer horizontal wells. This constrains our production and reduces our revenue from the affected wells. Capacity constraints affecting natural gas production also impact the associated NGLs. We are also dependent on the availability and capacity of crude oil purchasers for our production. For example, reductions in purchases by a local crude oil refinery beginning in late 2013 increased the amount of oil that we had to transport out of the Wattenberg area for sale. This increased our transportation costs and reduced the price we received for the affected production for much of 2014. We expect this situation could occur again in the future. In addition, the use of alternative forms of transportation such as trucks or rail involve risks. For example, well-publicized accidents involving trains delivering crude oil could result in increased levels of regulation and transportation costs, and possibly shortages of railcars that meet new safety standards. We face similar risks in other areas, including our Utica operating area, as gathering/processing infrastructure is currently in the development phase and development activity has increased in recent years. In addition to causing p +18 +roduction curtailments, capacity constraints can also reduce the price we receive for the crude oil, natural gas and NGLs we produce. +A substantial part of our crude oil, natural gas and NGLs production is located in the Wattenberg Field, making us vulnerable to risks associated with operating primarily in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing formations. +Our operations are focused primarily on the Wattenberg Field, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Approximately $435 million , or 92% , of our 2015 capital program forecast is expected to be spent on development activities in the Wattenberg Field. Because our operations are not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including: +• +fluctuations in prices of crude oil, natural gas and NGLs produced from the wells in the area; +• +natural disasters such as the flooding that occurred in the area in September 2013; +• +restrictive governmental regulations; and +• +curtailment of production or interruption in the availability of gathering, processing or transportation infrastructure and services, and any resulting delays or interruptions of production from existing or planned new wells. +For example, recent increases in activity in the Wattenberg Field have contributed to bottlenecks in processing and transportation that have negatively affected our results of operations, and these adverse effects may be disproportionately severe to us compared to our more geographically diverse competitors. Similarly, the concentration of our assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules, that could adversely affect development activities or production relating to those formations. Such an event could have a material adverse effect on our results of operations and financial condition. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the Wattenberg Field, the demand for, and cost of, drilling rigs, equipment, supplies, personnel and oilfield services increase. Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations. +Federal, state and local legislation and regulations relating to hydraulic fracturing could result in increased costs, additional drilling and operating restrictions or delays in the production of crude oil, natural gas and NGLs, and could prohibit hydraulic fracturing activities. +Most of our drilling uses hydraulic fracturing. Hydraulic fracturing is an important and commonly used process in the completion of unconventional wells in shale, coalbed, and tight sand formations. Proposals have been introduced in the U.S. Congress to regulate hydraulic fracturing operations and related injection of fracturing fluids and propping agents used by the crude oil and natural gas industry in fracturing fluids under the Safe Drinking Water Act (“SDWA”), and to require the disclosure of chemicals used in the hydraulic fracturing process under the SDWA, the Emergency Planning and Community Right-to-Know Act (“EPCRA”), or other laws. Sponsors of these bills, which have been subject to various proceedings in the legislative process, including in the House Energy and Commerce Committee and the Senate Environmental and Public Works Committee, have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies and otherwise cause adverse environmental impacts. In March 2011, the EPA announced its intention to conduct a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. EPA issued an initial report about the study in December 2012. The initial report described the focus of the continuing study but did not include any data concerning EPA’s efforts to date, nor did it draw any conclusions about the safety of hydraulic fracturing. A draft of the report is expected in 2015 and a final, peer reviewed report is expected in 2016. +EPA has begun a Toxic Substances Control Act rulemaking which will collect expansive information on the chemicals used in hydraulic fracturing fluid, as well as other health-related data, from chemical manufacturers and processors. EPA has not indicated when it intends to issue a proposed rule, but it issued an Advanced Notice of Proposed Rulemaking in May 2014, seeking public comment on a variety of issues related to the rulemaking. Concurrently, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. +EPA also finalized major new CAA standards (New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants) applicable to hydraulically fractured natural gas wells and certain storage vessels in August 2012. The standards require, among other things, use of reduced emission completions, or green completions, to reduce volatile organic compound emissions during well completions as well as new controls applicable to a wide variety of storage tanks and other equipment, including compressors, controllers, and dehydrators. Following administrative reconsideration of a portion of the 2012 rules, EPA issued one set of final amendments to the rule in September 2013 related to storage tanks, and a second set of final amendments largely related to reduced emissions completion requirements in December 2014. Most key provisions in the new CAA standards become effective in 2015. The rules and associated amendments are substantial and will increase future costs of our operations and will require us to make modifications to our operations and install new equipment. In January 2015, EPA announced a comprehensive strategy to further reduce methane emissions from the oil and gas sector. EPA’s hybrid approach will rely partly on voluntary measures and partly on regulatory requirements. A proposed rule is expected in 2015, with a final rule to be issued in 2016. Potential new requirements under such rules could include, but are not limited to, new leak detection and repair standards, control requirements at oil well completions, replacement of certain pneumatic pumps, and additional control requirements for gathering, +19 +boosting, and compressor stations. These additional methane reduction requirements could increase future costs of our operations and require us to make modifications to our operations and install new equipment. +EPA has also issued permitting guidance under the SDWA for the underground injection of liquids from hydraulically fractured (and other) wells where diesel is used. Depending upon how it is implemented, this guidance may create duplicative requirements in certain areas, further slow down the permitting process in certain areas, increase the costs of operations, and result in expanded regulation of hydraulic fracturing activities by EPA and may therefore adversely affect even companies, such as PDC, that do not use diesel fuel in hydraulic fracturing activities. Certain other federal agencies are analyzing, or have been requested to review, environmental issues associated with hydraulic fracturing. Most notably, the U.S. Department of the Interior, through the BLM, is currently conducting a rulemaking that will require, among other things, disclosure of chemicals and more stringent well integrity measures associated with hydraulic fracturing operations on public land. The rule is in its final stages and BLM is expected to issue the rule in 2015. +In addition, the governments of certain states, including Colorado and Ohio, have adopted or are considering adopting laws and regulations that impose or could impose, among other requirements, stringent permitting or air emission control requirements, disclosure, wastewater disposal, baseline sampling, seismic monitoring, well construction and well location requirements on hydraulic fracturing operations or otherwise seek to ban underground injection of fracturing wastewater or fracturing activities altogether. For example, in January 2012, the ODNR issued a temporary moratorium on the development of hydraulic fracturing disposal wells in northeast Ohio in order to study the relationship between these wells and minor earthquakes reported in the area. As a result, ODNR promulgated new and more stringent regulations for certain underground injection wells, including requirements for a complete suite of geophysical logs, analytical interpretation of the logs, and enhanced monitoring and recording. More recently, in April 2014, ODNR shut down a number of well sites after a series of small earthquakes in northeast Ohio. After investigating the earthquakes and determining that the connection to hydraulic fracturing was “probable,” ODNR implemented new permit conditions, requiring that operators of well sites within three miles of a known fault must install sensitive seismic-monitoring equipment. Operators must also halt drilling if a seismic event exceeds 1.0 magnitude. New York has also placed a permanent moratorium on all hydraulic fracturing activities within the state. Similar initiatives could spread to states in which we operate. +At the local level, some municipalities and local governments have adopted or are considering bans on hydraulic fracturing. Voters in the cities of Fort Collins, Boulder, and Lafayette, Colorado recently approved bans of varying length on hydraulic fracturing within their respective city limits. The bans in Longmont, Lafayette, and Fort Collins were overturned by local district courts; the Boulder and Broomfield moratoria remain in place, and the Boulder County moratorium was recently extended to 2018. The Longmont City Council has appealed the district court’s decision to overturn the ban, and Fort Collins is appealing that court decision as well. Municipal bans on oil and gas development in New York were upheld in 2014 by the New York Court of Appeals. Voters in Youngstown and Bowling Green, Ohio considered bans on hydraulic fracturing, though the votes in late 2013 and early 2014 were rejected. The town of Oberlin, Ohio passed a ban on hydraulic fracturing, and other voter initiatives may seek to ban hydraulic fracturing as well. Such bans, if successful, could increase the costs of our operations, impact our profitability, and even prevent us from drilling in certain locations. +In addition, lawsuits have been filed against unrelated third parties in several states, including Colorado and Ohio, and several other states alleging contamination of drinking water by hydraulic fracturing. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to crude oil, natural gas and NGL production activities using hydraulic fracturing techniques. Additional legislation, regulation, litigation, or moratoria could also lead to operational delays or lead us to incur increased operating costs in the production of crude oil, natural gas and NGLs, including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing or other drilling activities. If these legislative, regulatory, litigation, and other initiatives cause a material decrease in the drilling of new wells or an increase in drilling costs, our profitability could be materially impacted. +Ballot initiatives have been proposed in Colorado that could vastly expand the right of local governments to limit or prohibit oil and natural gas production and development in their jurisdictions and could impose additional regulations on production and development activities. If any initiative or legislation of this nature is implemented and survives legal challenge, additional limitations or prohibitions could be placed on crude oil and natural gas production and development within certain areas of Colorado or the state as a whole. This could adversely affect the cost, manner, and feasibility of development activities in Colorado, particularly those involving hydraulic fracturing, and significantly affect the value of our assets and our financial results and impede our growth. +Certain interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, have advanced various options for ballot initiatives aimed at significantly limiting or preventing oil and natural gas development. Signatures for two such proposals were submitted for a vote at the November 2014 election. One proposed to amend the Colorado constitution to establish an “environmental bill of rights” that would have allowed local governments in Colorado the right, without limitation, to prohibit crude oil and natural gas development within their respective jurisdictions. The second proposal would have imposed a statewide mandatory minimum spacing, or setback, between oil and gas wells and occupied structures of 2,000 feet. As part of a compromise negotiated by Governor John Hickenlooper, both initiatives were withdrawn prior to the election and were not voted upon. However, these or similar proposals may be made in the future. Should any such proposal be successful and survive legal challenge, it could have a materially adverse impact on our ability to drill and/or produce crude oil and natural gas in certain areas in Colorado, or the state generally, and could materially impact our results of operations, production and reserves. +Moreover, pursuant to the compromise that resulted in the withdrawal of the 2014 proposals, Governor Hickenlooper has created a task force charged with crafting recommendations to help minimize land use and other conflicts relating to the location of oil and gas facilities. The task force has 21 members representing various interests. Recommendations of the task force regarding new or amended legislation must be approved by a two-thirds vote of the members and will be submitted to the Governor by no later than February 27, 2015. We cannot predict the outcome of this process, the proposals to be formulated by the task force or the result of any related legislative process. +20 +Our business could be negatively impacted by security threats, including cybersecurity threats, and other disruptions. +We face various security threats, including attempts by third parties to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. There can be no assurance that the procedures and controls we use to monitor these threats and mitigate our exposure to them will be sufficient in preventing them from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial condition, results of operations, or cash flows. +In particular, the oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling activities, conduct reservoir modeling and reserves estimation, and to process and record financial and operating data. +We depend on digital technology, including information systems and related infrastructure as well as cloud application and services, to store, transmit, process and record sensitive information (including trade secrets, employee information and financial and operating data), communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil and gas reserves and for many other activities related to our business. The complexity of the technologies needed to explore for and develop oil, natural gas and NGLs make certain information more attractive to thieves. +Our business partners, including vendors, service providers, operating partners, purchasers of our production, and financial institutions, are also dependent on digital technology. Some of these business partners may be provided limited access to our sensitive information or our information systems and related infrastructure in the ordinary course of business. +As dependence on digital technologies has increased, cyber incidents, including deliberate attacks and unintentional events, have also increased. A cyber-attack could include an attempt to gain unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption. Certain countries are believed to possess cyber warfare capabilities and are credited with attacks on American companies and government agencies. Well publicized recent cyber-attacks include those directed at Anthem, Inc. and Sony Pictures, but lower profile attacks are also common. +Our technologies, systems and networks, and those of our business partners, may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, theft of property or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Given the politically sensitive nature of hydraulic fracturing and the controversy generated by its opponents, our technologies, systems and networks may be of particular interest to certain groups with political agendas, which may seek to launch cyber-attacks as a method of promoting their message. A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations. Although to date we have not experienced any significant cyber-attacks, there can be no assurance that we will not be the target of such attacks in the future. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any security vulnerabilities. +Environmental and overall public scrutiny focused on the oil and gas industry is increasing. The current trend is to increase regulation of our operations and the industry. We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business. +Our exploration, development, production, and marketing operations are regulated extensively at the federal, state, and local levels. Environmental and other governmental laws and regulations have increased the costs of planning, designing, drilling, installing, operating, and abandoning crude oil and natural gas wells and associated facilities. Under these laws and regulations, we could also be liable for personal injuries, property damage, and natural resource or other damages. Similar to our competitors, we incur substantial operating and capital costs to comply with such laws and regulations. These compliance costs may put us at a competitive disadvantage compared to larger companies in the industry which can more easily capture economies of scale with respect to compliance. Failure to comply with these laws and regulations may result in the suspension or termination of our operations or other operational impediments and subject us to administrative, civil, and criminal penalties. Moreover, public interest in environmental protection has increased in recent years-particularly with respect to hydraulic fracturing-and environmental organizations have opposed, with some success, certain drilling projects. +In addition, our activities are subject to regulations governing conservation practices, protection of wildlife and habitat, and protection of correlative rights by state governments. For example, the federal Endangered Species Act (“ESA”) and analogous state laws restrict activities that may adversely affect endangered and threatened species or their habitat. The designation of previously unidentified endangered or threatened species or their habitat in areas where we operate could cause us to incur additional costs or become subject to operating delays, restrictions or bans. For example, the U.S. Fish and Wildlife Service in May 2014 proposed a rule to alter how that agency designates critical habitat. It is unclear when that rule may be finalized, but it could expand the reach of the ESA. These regulations affect our operations, increase our costs of exploration and production, and limit the quantity of crude oil, natural gas and NGLs that we can produce and market. A major risk inherent in our drilling plans is the possibility that we will be unable to obtain needed drilling permits from relevant governmental authorities in a timely manner. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit +21 +for a well, or the receipt of a permit with unreasonable conditions or costs could have a material adverse effect on our ability to explore or develop our properties. +Additionally, the crude oil and natural gas regulatory environment could change in ways that substantially increase our financial and managerial compliance costs, increase our exposure to potential damages or limit our activities. At the state level, for instance, the Colorado Oil and Gas Conservation Commission (“COGCC”) issued a rule in 2013 governing mandatory minimum setbacks between oil and gas wells and occupied buildings and other areas. Also in 2013, the COGCC issued rules that require baseline sampling of certain ground and surface water in most areas of Colorado and impose stringent spill reporting and remediation requirements. These new sampling requirements could increase the costs of developing wells in certain locations. Other regulatory amendments and policies recently adopted by the COGCC address wellbore integrity, hydraulic fracturing, well control, waste management, and spill reporting. In addition to increasing costs of operation, some of these rules and policies could prevent us from drilling wells on certain locations we plan to develop, thereby reducing our reserves as well as our future revenues. In 2014, the Colorado Oil and Gas Conservation Act was amended to increase the potential sanctions for violating the Act or its implementing regulations, orders, or permits. In January 2015, the COGCC amended its regulations to implement this new legislation. These legislative and regulatory amendments expand the COGCC’s enforcement authority and tools by, for example, mandating monetary penalties for certain types of violations, requiring a penalty to be assessed for each day of violation, and significantly increasing the maximum daily penalty amount. These changes could significantly increase both the frequency and the amount of future administrative penalties assessed by the COGCC. +In addition, in February 2014, the Colorado Department of Public Health and Environment’s Air Quality Control Commission (“AQCC”) finalized regulations imposing stringent new requirements relating to air emissions from oil and gas facilities in Colorado. The new rules impose significantly more stringent control, monitoring, recordkeeping, and reporting requirements than those required under comparable new federal rules, promulgated at 40 C.F.R. Part 60, Subpart OOOO. In addition, as part of the rule, the AQCC approved the direct regulation of hydrocarbon (i.e., methane) emissions from the Colorado oil and gas sector. Such state-only, direct regulation of methane (a greenhouse gas) from a single industry sector in the absence of comparable federal regulation is a significant new authority being asserted at the state level and has the potential to adversely affect operations in Colorado as well as in other parts of the country. Along the same lines, local governments are undertaking air quality studies to assess potential public health impacts from oil and gas operations. These studies, in combination with other air quality-related studies that are national in scope, may result in the imposition of additional regulatory requirements on oil and gas operations. +The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA” or the “Superfund law”) and some comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment This includes potential liability for activities on properties we may currently own or operate upon, but where previous owner/operators caused the release of a hazardous substance. In addition, we may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. Regulatory focus on worker safety and health regulations involving operating hazards in oil and natural gas exploration and production activities is also increasing. One example is a recent investigation by OSHA and other governmental authorities regarding potential worker exposure to hydrocarbon vapors from certain fuel transfer and related tasks. Several recent worker fatalities at oil and gas facilities nationwide are being reviewed by OSHA and other governmental authorities for a potential link to hydrocarbon vapor exposure. Regulatory requirements generally relating to worker exposure to hydrocarbon vapors could be increased or receive heightened scrutiny going forward. +Other potential laws and regulations affecting us include new or increased severance taxes proposed in several states, including Ohio. This could adversely affect our existing operations in the state and the economic viability of future drilling. Additional laws, regulations, or other changes could significantly reduce our future growth, increase our costs of operations, and reduce our cash flows, in addition to undermining the demand for the crude oil, natural gas and NGLs we produce. +Our ability to produce crude oil, natural gas and NGLs could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of the water we use at a reasonable cost and within applicable environmental rules. +Our operations could be adversely impacted if we are unable to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations. Currently, the quantity of water required in certain completion operations, such as hydraulic fracturing, and changing regulations governing usage may lead to water constraints and supply concerns (particularly in some parts of the country). In addition, Colorado has a relatively arid climate and experiences drought conditions from time to time. As a result, future availability of water from certain sources used in the past may become limited. +The imposition of new environmental initiatives relating to wastewater could restrict our ability to conduct certain operations such as hydraulic fracturing. This includes potential restrictions on waste disposal, including, but not limited to, produced water, drilling fluids, and other wastes associated with the exploration, development, or production of hydrocarbons. For example, in 2010 a petition was filed by the Natural Resources Defense Council with EPA requesting that the agency reassess its prior and long-standing determination that certain oil and natural gas exploration and production wastes would not be regulated as hazardous waste under Subtitle C of the RCRA. EPA has not yet acted on the petition and it remains pending. Were EPA to begin treating some or all of these wastes as “hazardous” under Subtitle C in response to the petition, the consequences for our operations would be serious, and would include a significant increase in costs associated with waste treatment and disposal and a potential inability to conduct operations in some instances. +22 +The CWA and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas waste, into navigable waters or other regulated federal and state waters. Permits or other approvals must be obtained to discharge fill and pollutants into regulated waters and to conduct construction activities in such waters and wetlands. Uncertainty regarding regulatory jurisdiction over wetlands and other regulated waters of the United States has complicated, and will continue to complicate and increase the cost of, obtaining such permits or other approvals. Most recently, EPA and the U.S. Army Corps of Engineers have issued a proposed rule on defining jurisdictional waters of the United States. An expansive definition of such jurisdictional waters could affect our ability to operate in certain areas, increase costs of operations, and cause significant scrutiny and delays in permitting. While generally exempt under federal programs, many state agencies have also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. These permits, in turn, impose far-ranging monitoring, flow control, and other obligations that have generated, and will continue to generate, increased costs for our operations. +In October 2011, EPA announced its intention to develop federal pretreatment standards for wastewater discharges associated with hydraulic fracturing activities. If adopted, the pretreatment rules will require shale gas operations to pretreat wastewater before transfer to treatment facilities. Proposed rules are expected in early 2015. Some states, including Pennsylvania, have banned the treatment of fracturing wastewater at publicly owned treatment facilities. There has been recent nationwide concern, particularly in Ohio, over earthquakes associated with Class II underground injection control wells, a predominant storage method for crude oil and gas wastewater. As seen in Ohio, it is likely that new rules and regulations will be developed to address these concerns, possibly eliminating access to Class II wells in certain locations, and increasing the cost of disposal in others. +Finally, the EPA study noted above has focused and will continue to focus on various stages of water use in hydraulic fracturing operations. It is possible that, following the conclusion of EPA’s study, the agency will move to more strictly regulate the use of water in hydraulic fracturing operations. While we cannot predict the impact that these changes may have on our business at this time, they may be material to our business, financial condition, and operations. In addition, an inability to meet our water supply needs to conduct our completion operations may adversely impact our business. These water-related concerns are heightened by the potential for flooding events in Colorado such as those that occurred in 2013. For example, during that flood we experienced damage to some of our facilities as well as other operational impediments. +Reduced commodity prices could result in significant impairment charges and significant downward revisions of proved reserves. +Crude oil prices fell dramatically in the second half of 2014 and the domestic natural gas market remains weak. Low commodity prices could result in, among other adverse effects, significant impairment charges. The cash flow model we use to assess properties for impairment includes numerous assumptions, such as management’s estimates of future oil and gas production and commodity prices, market outlook on forward commodity prices and operating and development costs. All inputs to the cash flow model must be evaluated at each date that the estimate of future cash flows for each producing basin is calculated. However, a significant decrease in long-term forward prices alone could result in a significant impairment for our properties that are sensitive to declines in prices. In December 2012, we recognized an impairment charge of $161.2 million associated with our Piceance Basin proved crude oil and natural gas properties. In 2013, we recognized additional charges of $48.8 million associated with our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties. In December 2014, we recognized a charge of $158.3 million associated with our Utica Shale properties. Similar charges could occur in the future. In addition, low commodity prices could result in significant downward revisions to our proved reserves. +Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our production and reserves, and ultimately our profitability. +Our industry is capital intensive. We expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of crude oil, natural gas and NGL reserves. To date, we have financed capital expenditures primarily with bank borrowings under our revolving credit facility, cash generated by operations and proceeds from capital markets transactions and the sale of properties. We intend to finance our future capital expenditures utilizing similar financing sources. Our cash flows from operations and access to capital are subject to a number of variables, including: +• +our proved reserves; +• +the amount of crude oil, natural gas and NGLs we are able to produce from existing wells; +• +the prices at which crude oil, natural gas and NGLs are sold; +• +the costs to produce crude oil, natural gas and NGLs; and +• +our ability to acquire, locate and produce new reserves. +If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower commodity prices, operating difficulties or for any other reason, our need for capital from other sources could increase, and there can be no assurance that such other sources of capital would be available at that time on reasonable terms or at all. If we raise funds by issuing additional equity securities, this would have a dilutive effect on existing shareholders. If we raise funds through the incurrence of debt, the risks we face with respect to our indebtedness would increase and we would incur additional interest expense. Our inability to obtain sufficient financing on acceptable terms would adversely affect our financial condition and profitability. +Our estimated crude oil and natural gas reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves. +23 +Calculating reserves for crude oil, natural gas and NGLs requires subjective estimates of remaining volumes of underground accumulations of hydrocarbons. Assumptions are also made concerning commodity prices, production levels, and operating and development costs over the economic life of the properties. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate. Independent petroleum engineers prepare our estimates of crude oil, natural gas and NGLs reserves using pricing, production, cost, tax and other information that we provide. The reserve estimates are based on certain assumptions regarding commodity prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual results could greatly affect: +• +the economically recoverable quantities of crude oil, natural gas and NGLs attributable to any particular group of properties; +• +future depreciation, depletion and amortization (“DD&A”) rates and amounts; +• +impairments in the value of our assets; +• +the classifications of reserves based on risk of recovery; +• +estimates of future net cash flows; +• +timing of our capital expenditures; and +• +the amount of funds available for us to utilize under our revolving credit facility. +Some of our reserve estimates must be made with limited production histories, which renders these reserve estimates less reliable than estimates based on longer production histories. Horizontal drilling in the Wattenberg Field is a relatively recent development, whereas vertical drilling has been used by producers in this field for over 40 years. As a result, the amount of production data from horizontal wells available to reserve engineers is relatively small, and future reserve estimates will be affected by additional production data as it becomes available. Horizontal drilling in the Utica Shale has an even more limited history, particularly in the southern part of the play where most of our acreage is located. Further, reserve estimates are based on the volumes of crude oil, natural gas and NGLs that are anticipated to be economically recoverable from a given date forward based on economic conditions that exist at that date. The actual quantities of crude oil, natural gas and NGLs recovered will be different than the reserve estimates since they will not be produced under the same economic conditions as used for the reserve calculations. In addition, quantities of probable and possible reserves by definition are inherently more risky than proved reserves and are less likely to be recovered. +At December 31, 2014 , approximately 70% of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflected our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including approximately $2.3 billion during the five years ending December 31, 2019. The estimated development costs may not be accurate, development may not occur as scheduled and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, and we may therefore be required to downgrade to probable or possible any PUDs that are not developed within this five-year time frame. +The present value of the estimated future net cash flows from our proved reserves is not necessarily the same as the current market value of those reserves. Pursuant to SEC rules, the estimated discounted future net cash flows from our proved reserves, and the estimated quantity of those reserves, were based on the prior 12-month average crude oil and natural gas index prices. However, factors such as actual prices we receive for crude oil and natural gas and hedging instruments, the amount and timing of actual production, the amount and timing of future development costs, the supply of and demand for crude oil, natural gas and NGLs and changes in governmental regulations or taxation, also affect our actual future net cash flows from our properties. Because market prices for crude oil at the end of 2014 were significantly lower than the average price for the year determined under SEC rules, the estimated quantity and present values of our reserves presented in this report are higher than they would be if we had used year-end oil prices instead. Moreover, the lower year-end prices may be more reflective of future economic conditions. +The timing of both our production and incurrence of expenses in connection with the development and production of crude oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor (the rate required by the SEC) we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates currently in effect and risks associated with our properties or the industry in general. +Unless reserves are replaced as they are produced, our reserves and production will decline, which would adversely affect our future business, financial condition and results of operations. We may not be able to develop our identified drilling locations as planned. +Producing crude oil, natural gas and NGL reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline may change over time and may exceed our estimates. Our future reserves and production and, therefore, our cash flows and income, are highly dependent on our ability to efficiently develop and exploit our current reserves and to economically find or acquire additional recoverable reserves. We may not be able to develop, discover or acquire additional reserves to replace our current and future production at acceptable costs. Our failure to do so would adversely affect our future operations, financial condition and results of operations. +We have identified a number of well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including: +24 +• +crude oil, natural gas and NGL prices; +• +the availability and cost of capital; +• +drilling and production costs; +• +availability of drilling services and equipment; +• +drilling results; +• +lease expirations; +• +midstream constraints; +• +access to and availability of water sourcing and distribution systems; +• +regulatory approvals; and +• +other factors. +Because of these factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce crude oil, natural gas or NGLs from these or any other potential well locations. We reduced our budgeted capital expenditures in 2015 relative to 2014 in response to significant declines in the market price of crude oil, and we expect to drill fewer wells during the year - and none targeting the Utica Shale - as a result. In addition, the number of drilling locations available to us will depend in part on the spacing of wells in our operating areas. An increase in well density in an area could result in additional locations in that area, but a reduced production performance from the area on a per-well basis. Further, certain of the horizontal wells we intend to drill in the future may require pooling of our lease interests with the interests of third parties. If these third parties are unwilling to pool their interests with ours, and we are unable to require such pooling on a timely basis or at all, this may limit the total locations we can drill. As such, our actual drilling activities may materially differ from those presently identified. Further, our inventory of drilling projects includes locations in addition to those that we currently classify as proved, probable and possible. The development of and results from these additional projects are more uncertain than those relating to probable and possible locations, and significantly more uncertain than those relating to proved locations. +The wells we drill may not yield crude oil, natural gas or NGLs in commercially viable quantities, and productive wells may be less successful than we expect. +A prospect is a property on which our geologists have identified what they believe, based on available information, to be indications of hydrocarbon-bearing rocks. However, our geologists cannot know conclusively prior to drilling and testing whether crude oil, natural gas or NGLs will be present in sufficient quantities to repay drilling or completion costs and generate a profit given the available data and technology. Furthermore, even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques do not enable our geologists to be certain as to whether hydrocarbons are, in fact, present in those structures or the quantity of the hydrocarbons. In addition, the use of 3-D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures, which may result in a reduction in our returns or losses. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline. If a well is determined to be dry or uneconomic, which can occur even though it contains some crude oil, natural gas or NGLs, it is classified as a dry hole and must be plugged and abandoned in accordance with applicable regulations. This generally results in the loss of the entire cost of drilling and completion to that point, the cost of plugging, and lease costs associated with the prospect. Even wells that are completed and placed into production may not produce sufficient crude oil, natural gas and NGLs to be profitable, or they may be less productive and/or profitable than we expected. If we drill a dry hole or unprofitable well on a current or future prospect, the profitability of our operations will decline and the value of our properties will likely be reduced. These risks are greater in developing areas such as the Utica Shale. Exploratory drilling is typically subject to substantially greater risk than development drilling. In addition, initial results from a well are not necessarily indicative of its performance over a longer period. +Drilling for and producing crude oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations. +Drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling can be unprofitable, not only due to dry holes, but also due to curtailments, delays or cancellations as a result of other factors, including: +• +unusual or unexpected geological formations; +• +pressures; +• +fires; +• +floods; +• +loss of well control; +• +loss of drilling fluid circulation; +• +title problems; +• +facility or equipment malfunctions; +• +unexpected operational events; +• +shortages or delays in the delivery of equipment and services; +• +unanticipated environmental liabilities; +• +compliance with environmental and other governmental requirements; and +• +adverse weather conditions. +25 +Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and regulatory penalties. For example, a loss of containment of hydrocarbons during drilling activities could potentially subject us to civil and/or criminal liability and the possibility of substantial costs, including for environmental remediation, depending upon the circumstances of the loss of containment, the nature and scope of the loss and the applicable laws and regulations. We maintain insurance against various losses and liabilities arising from operations; however, insurance against certain operational risks may not be available or may be prohibitively expensive relative to the perceived risks presented. For example, we may not have coverage with respect to a pollution event if we are unaware of the event while it is occurring and are therefore unable to report the occurrence of the event to our insurance company within the time frame required under our insurance policy. Thus, losses could occur for uninsurable or uninsured risks or for amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance and/or governmental or third party responses to an event could have a material adverse effect on our business activities, financial condition and results of operations. We are currently involved in various remedial and investigatory activities at some of our wells and related sites. +Our business strategy focuses on production in our liquid-rich and high impact shale plays. In this regard, we plan to allocate our capital to an active horizontal drilling program. Historically, most of the wells we drilled were vertical wells. Since 2012, however, we have devoted the majority of our capital budget to drilling horizontal wells. Drilling horizontal wells is technologically more difficult than drilling vertical wells - including as a result of risks relating to our ability to fracture stimulate the planned number of stages and to successfully run casing the length of the well bore - and the risk of failure is therefore greater than the risk involved in drilling vertical wells. Additionally, drilling a horizontal well is typically far costlier than drilling a vertical well. This means that the risks of our drilling program will be spread over a smaller number of wells, and that, in order to be economic, each horizontal well will need to produce at a higher level in order to cover the higher drilling costs. In addition, we have transitioned to the use of multi-well pads instead of single-well sites. The use of multi-well pad drilling increases some operational risks because problems affecting the pad or a single well could adversely affect production from all of the wells on the pad. Pad drilling can also make our overall production, and therefore our revenue and cash flows, more volatile, because production from multiple wells on a pad will typically commence simultaneously. While we believe that we will be better served by drilling horizontal wells using multi-well pads, the risk component involved in such drilling will be increased in some respects, with the result that we might find it more difficult to achieve economic success in our drilling program. +Under the “successful efforts” accounting method that we use, unsuccessful exploratory wells must be expensed in the period when they are determined to be non-productive, which reduces our net income in such periods and could have a negative effect on our profitability. +We conduct exploratory drilling in order to identify additional opportunities for future development. Under the “successful efforts” method of accounting that we use, the cost of unsuccessful exploratory wells must be charged to expense in the period in which the wells are determined to be unsuccessful. In addition, lease costs for acreage condemned by the unsuccessful well must also be expensed. In contrast, unsuccessful development wells are capitalized as a part of the investment in the field where they are located. Because exploratory wells generally are more likely to be unsuccessful than development wells, we anticipate that some or all of our exploratory wells may not be productive. The costs of such unsuccessful exploratory wells could result in a significant reduction in our profitability in periods when the costs are required to be expensed. +Increasing finding and development costs may impair our profitability. +In order to continue to grow and maintain our profitability, we must add new reserves that exceed our production over time at a finding and development cost that yields an acceptable operating margin and DD&A rate. Without cost effective exploration, development or acquisition activities, our production, reserves and profitability will decline over time. Given the relative maturity of most crude oil and natural gas basins in North America and the level of activity in the industry, the cost of finding new reserves through exploration and development operations is high in some basins. The acquisition market for properties has become extremely competitive among producers for additional production and expanded drilling opportunities in North America. Acquisition values for crude oil properties have climbed in recent years and may increase in the future. This increase in finding and development costs results in higher DD&A rates. If the upward trend in crude oil finding and development costs continues, we will be exposed to an increased likelihood of a write-down in the carrying value of our crude oil properties in response to decreases in commodity prices and/or reduction in the profitability of our operations. +We have a substantial amount of debt and the cost of servicing, and risks related to refinancing, that debt could adversely affect our business. Those risks could increase if we incur more debt. +We have a substantial amount of indebtedness. As a result, a significant portion of our cash flows will be required to pay interest and principal on our indebtedness, and we may not generate sufficient cash flows from operations, or have future borrowing capacity available, to enable us to repay our indebtedness or to fund other liquidity needs. +Servicing our indebtedness and satisfying our other obligations will require a significant amount of cash. Our cash flows from operating activities and other sources may not be sufficient to fund our liquidity needs. Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend on our future operating performance and financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions, including depressed commodity pricing, and financial, business and other factors, many of which are beyond our control. +A substantial decrease in our operating cash flows or an increase in our expenses could make it difficult for us to meet our debt service requirements and could require us to modify our operations, including by curtailing our exploration and drilling programs, selling +26 +assets, refinancing all or a portion of our existing debt or obtaining additional financing. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. In addition, the terms of future debt agreements may, and our existing debt agreements do, restrict us from implementing some of these alternatives. In the absence of adequate cash from operations and other available capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. We may not be able to consummate these dispositions for fair market value, in a timely manner or at all. Furthermore, any proceeds that we could realize from any dispositions may not be adequate to meet our debt service or other obligations then due. Because the cash required to service our indebtedness is not available to finance our operations and other business activities, our indebtedness limits our flexibility in planning for or reacting to changes in our business and the industry in which we operate and increases our vulnerability to economic downturns and sustained declines in commodity prices. +Covenants in our debt agreements currently impose, and future financing agreements may impose, significant operating and financial restrictions. +The indenture governing our senior notes and our revolving credit facility contain restrictions, and future financing agreements may contain additional restrictions, on our activities, including covenants that restrict our and certain of our subsidiaries’ ability to: +• +incur additional debt; +• +pay dividends on, redeem or repurchase stock; +• +create liens; +• +make specified types of investments; +• +apply net proceeds from certain asset sales; +• +engage in transactions with our affiliates; +• +engage in sale and leaseback transactions; +• +merge or consolidate; +• +restrict dividends or other payments from restricted subsidiaries; +• +sell equity interests of restricted subsidiaries; and +• +sell, assign, transfer, lease, convey or dispose of assets. +Our revolving credit facility is secured by all of our crude oil and natural gas properties as well as a pledge of all ownership interests in our operating subsidiaries. The restrictions contained in our debt agreements may prevent us from taking actions that we believe would be in the best interest of our business, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. We may also incur future debt obligations that might subject us to additional restrictive covenants that could affect our financial and operational flexibility. +Our revolving credit facility has substantial restrictions and financial covenants and our ability to comply with those restrictions and covenants is uncertain. Our lenders can unilaterally reduce our borrowing availability based on anticipated commodity prices. +We depend in large part on our revolving credit facility for future capital needs. The terms of the credit agreement require us to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flows from operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the revolving credit facility or other debt agreements could result in a default under those agreements, which could cause all of our existing indebtedness to be immediately due and payable. +The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based upon projected revenues from the properties securing their loan. The significant recent decrease in the price of crude oil is likely to have an adverse effect on the borrowing base. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other crude oil and natural gas properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility. Our inability to borrow additional funds under our revolving credit facility could adversely affect our operations and our financial results. +If we are unable to comply with the restrictions and covenants in the agreements governing our indebtedness, there would be a default under the terms of these agreements, which could result in an acceleration of payment of funds that we have borrowed and would impact our ability to make principal and interest payments on our indebtedness and satisfy our other obligations. +Any default under the agreements governing our indebtedness, including a default under our revolving credit facility that is not waived by the required lenders, and the remedies sought by the holders of any such indebtedness, could make us unable to pay principal and interest on our indebtedness and satisfy our other obligations. If we are unable to generate sufficient cash flows and are otherwise unable to obtain the funds necessary to meet required payments of principal and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our revolving credit +27 +facility could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation. If our operating performance declines, we may in the future need to seek to obtain waivers from the required lenders under our revolving credit facility to avoid being in default and we may not be able to obtain such a waiver. If this occurs, we would be in default under our revolving credit facility, the lenders could exercise their rights as described above, and we could be forced into bankruptcy or liquidation. We cannot assure you that we will be granted waivers or amendments to our debt agreements if for any reason we are unable to comply with these agreements, or that we will be able to refinance our debt on terms acceptable to us, or at all. +Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly. +Borrowings under our revolving credit facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase although the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness and for other purposes would decrease. +Notwithstanding our current indebtedness levels and restrictive covenants, we may still be able to incur substantial additional debt, which could exacerbate the risks described above. +We may be able to incur additional debt in the future. Although our debt agreements contain restrictions on our ability to incur indebtedness, those restrictions are subject to a number of exceptions. In particular, we may borrow under the revolving credit facility, and expect to do so in 2015. We may also consider investments in joint ventures or acquisitions that may increase our indebtedness. Adding new debt to current debt levels could intensify the related risks that we and our subsidiaries now face. +Seasonal weather conditions and lease stipulations can adversely affect our operations. +Seasonal weather conditions and lease stipulations designed to protect wildlife affect operations in some areas. In certain areas drilling and other activities may be restricted or prohibited by lease stipulations, or prevented by weather conditions, for significant periods of time. This limits our operations in those areas and can intensify competition during the active months for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to additional or increased costs or periodic shortages. These constraints and the resulting high costs or shortages could delay our operations and materially increase operating and capital costs and therefore adversely affect our profitability. Similarly, hot weather during some recent periods adversely impacted the operation of certain midstream facilities, and therefore our production. Similar events could occur in the future and could negatively impact our results of operations and cash flows. +We have limited control over activities on properties in which we own an interest but we do not operate, which could reduce our production and revenues. +We operate approximately 89% of the wells in which we own an interest. If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of the underlying properties. The success and timing of drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise (including safety and environmental compliance) and financial resources, inclusion of other participants in drilling wells, and use of technology. The failure by an operator to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce production and revenues and adversely affect our profitability. These risks have been increasing for us in recent years as our capital expenditures for non-operated projects have risen significantly. Our lack of control over non-operated properties also makes it more difficult for us to forecast capital expenditures, production and related matters. +Our derivative activities could result in financial losses or reduced income from failure to perform by our counterparties or could limit our potential gains from increases in prices. +We use derivatives for a portion of the production from our own wells and for natural gas purchases and sales by our marketing subsidiary to achieve more predictable cash flows, to reduce exposure to adverse fluctuations in commodity prices, and to allow our natural gas marketing company to offer pricing options to natural gas sellers and purchasers. These arrangements expose us to the risk of financial loss in some circumstances, including when purchases or sales are different than expected or the counterparty to the derivative contract defaults on its contractual obligations. Based on current commodity prices and our current hedging position, we may receive significant revenues from our hedging positions in 2015, increasing the adverse consequences to us if a derivative counterparty fails to perform. In addition, many of our derivative contracts are based on WTI or another oil or natural gas index price. The risk that the differential between the index price and the price we receive for the relevant production may change unexpectedly makes it more difficult to hedge effectively and increases the risk of a hedging-related loss. +Also, derivative arrangements may limit the benefit we would otherwise receive from increases in the prices for the relevant commodity, and they may require the use of our resources to meet cash margin requirements. Since we do not designate our derivatives as hedges, we do not currently qualify for use of hedge accounting; therefore, changes in the fair value of derivatives are recorded in our income statements, and our net income is subject to greater volatility than it would be if our derivative instruments qualified for hedge accounting. For instance, if commodity prices rise significantly, this could result in significant non-cash charges during the relevant period, which could have a material negative effect on our net income. +28 +The inability of one or more of our customers or other counterparties to meet their obligations may adversely affect our financial results. +Substantially all of our accounts receivable result from our crude oil, natural gas and NGLs sales or joint interest billings to a small number of third parties in the energy industry. This concentration of customers and joint interest owners may affect our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our derivatives as well as the derivatives used by our marketing subsidiary expose us to credit risk in the event of nonperformance by counterparties. Nonperformance by our customers or derivative counterparties may adversely affect our financial condition and profitability. We face similar risks with respect to our other counterparties, including the lenders under our revolving credit facility and the providers of our insurance coverage. +Our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur. +The occurrence of a significant accident or other event not fully covered by insurance or in excess of our insurance coverage could have a material adverse effect on our operations and financial condition. Insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. We also do not carry contingent business interruption insurance related to the purchasers of our production. In addition, pollution and environmental risks are generally not fully insurable. +We may not be able to keep pace with technological developments in our industry. +Our industry is characterized by rapid and significant technological advancements. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those or other new technologies at substantial cost. In addition, our competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we were unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected. +Competition in our industry is intense, which may adversely affect our ability to succeed. +Our industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce crude oil, natural gas and NGLs, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, larger companies may have a greater ability to continue exploration activities during periods of low commodity prices. Larger competitors may also be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which could adversely affect our competitive position. These factors could adversely affect the success of our operations and our profitability. +Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel. +Our future success depends to a large extent on the services of our key employees. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise. +Acquisitions of properties are subject to the uncertainties of evaluating recoverable reserves and potential liabilities, including environmental uncertainties. +Acquisitions of producing properties and undeveloped properties have been an important part of our historical and recent growth. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, development potential, future commodity prices, operating costs, title issues and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we perform engineering, environmental, geological and geophysical reviews of the acquired properties, which we believe are generally consistent with industry practices. However, such reviews are not likely to permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well prior to an acquisition and our ability to evaluate undeveloped acreage is inherently imprecise. Even when we inspect a well, we may not always discover structural, subsurface and environmental problems that may exist or arise. In some cases, our review prior to signing a definitive purchase agreement may be even more limited. In addition, we often acquire acreage without any warranty of title except as to claims made by, through or under the transferor. +When we acquire properties, we will generally have potential exposure to liabilities and costs for environmental and other problems existing on the acquired properties, and these liabilities may exceed our estimates. Often we are not entitled to contractual indemnification associated with acquired properties. We often acquire interests in properties on an “as is” basis with no or limited remedies for breaches of representations and warranties. Therefore, we could incur significant unknown liabilities, including environmental liabilities, or losses due to +29 +title defects, in connection with acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, the acquisition of undeveloped acreage is subject to many inherent risks and we may not be able to realize efficiently, or at all, the assumed or expected economic benefits of acreage that we acquire. +Additionally, significant acquisitions can change the nature of our operations depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or may be in different geographic locations than our existing properties. These factors can increase the risks associated with an acquisition. Acquisitions also present risks associated with the additional indebtedness that may be required to finance the purchase price, and any related increase in interest expense or other related charges. +Certain federal income tax deductions currently available with respect to crude oil and natural gas and exploration and development may be eliminated as a result of future legislation. +The administration of U.S. President Barack Obama has proposed to eliminate certain key U.S. federal income tax preferences currently available with respect to crude oil and natural gas exploration and production. The proposals include, but are not limited to (i) the repeal of the percentage depletion allowance for crude oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is not possible at this time to predict how legislation or new regulations that may be adopted to address these proposals would impact our business, but any such future laws and regulations could result in higher federal income taxes, which could negatively affect our financial condition and results of operations. In addition, proposals are made from time to time in states where we operate to implement or increase severance or other taxes at the state level, and any such additional taxes would have similarly adverse effects on us. +Derivatives legislation and regulation could adversely affect our ability to hedge crude oil and natural gas prices and increase our costs and adversely affect our profitability. +In July 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”). The Dodd-Frank Act regulates derivative transactions, including our commodity hedging swaps, and could have a number of adverse effects on us, including the following: +• +The Dodd-Frank Act may limit our ability to enter into hedging transactions, thus exposing us to additional risks related to commodity price volatility; commodity price decreases would then have an increased adverse effect on our profitability and revenues. Reduced hedging may also impair our ability to have certainty with respect to a portion of our cash flows, which could lead to decreases in capital spending and, therefore, decreases in future production and reserves. +• +If, as a result of the Dodd-Frank Act or its implementing regulations, we are required to post cash collateral in connection with our derivative positions, this would likely make it impracticable to implement our current hedging strategy. +• +Our derivatives counterparties will be subject to significant new capital, margin and business conduct requirements imposed as a result of the Dodd-Frank Act. We expect that these requirements will increase the cost to hedge because there will be fewer counterparties in the market and increased counterparty costs will be passed on to us. +The above factors could also affect the pricing of derivatives and make it more difficult for us to enter into hedging transactions on favorable terms. +Climate change legislation or regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the crude oil, natural gas and NGLs that we produce while physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. +In December 2009, EPA published its findings that emissions of carbon dioxide, methane, and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are, according to EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings provide the basis for EPA to adopt and implement regulations that would restrict emissions of greenhouse gases under existing provisions of the CAA. In June 2010, EPA published its final rule to address the permitting of greenhouse gas emissions from stationary sources under the CAA’s Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of greenhouse gas emissions in a multi-step process, with the largest sources first subject to permitting. It was widely expected that facilities required to obtain PSD permits for their greenhouse gas emissions would be required to also reduce those emissions according to “best available control technology” (“BACT”) standards. In its permitting guidance for greenhouse gases, issued in November 2010, EPA recommended options for BACT from the largest sources, which include improved energy efficiency, among others. EPA also issued a final rule in July 2013 retaining the “tailored” permitting thresholds, opting not to extend greenhouse gas permitting requirements to smaller stationary sources at that time. +In June 2012, the United States Court of Appeals for the District of Columbia Circuit issued an opinion and order in Coalition for Responsible Regulation v. Environmental Protection Agency , upholding EPA’s greenhouse gas-related rules, including the “tailoring rule,” against challenges from various state and industry group petitioners. In October 2013, the United States Supreme Court in Utility Air Regulatory Group v. EPA , accepted a petition for certiorari to decide whether EPA correctly determined that its regulation of greenhouse gases from mobile sources triggered permitting requirements under the CAA for stationary sources that emit greenhouse gases. In June 2014, the Supreme Court upholded a portion of EPA’s GHG stationary source program, but invalidated a portion of it. The Court held that stationary sources already subject to the PSD or Title V program for non-GHG criteria pollutants remained subject to GHG BACT requirements, but ruled that sources +30 +subject to the PSD or Title V program only for GHGs could not be forced to comply with GHG BACT requirements. Upon remand, EPA is considering how to implement the Court’s decision. Depending on what EPA does, it is possible that any regulatory or permitting obligation that limits emissions of greenhouse gases could extend to smaller stationary sources and require us to incur costs to reduce and monitor emissions of greenhouse gases associated with our operations and also adversely affect demand for the crude oil and natural gas that we produce. +In the past, Congress has considered various pieces of legislation to reduce emissions of greenhouse gases. Congress has not adopted any significant legislation in this respect to date, but could do so in the future. For example, if Congress undertakes comprehensive tax reform in the coming year, it is possible that such measures could include a carbon tax, which could result in additional direct costs to our operations. In the absence of such national legislation, many states and regions have taken legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. For example, in February 2014, Colorado adopted rules directly regulating methane emissions from the oil and gas sector. +President Obama has indicated that climate change and greenhouse gas regulation is a significant priority for his second term. The President issued a Climate Action Plan in June 2013 that, among other things, calls for a reduction in methane emissions from the oil and gas sector. In November 2013, the President released an Executive Order charging various federal agencies, including EPA, with devising and pursuing strategies to improve the country’s preparedness and resilience to climate change. In part through these executive actions, the direct regulation of methane emissions from the oil and gas sector continues to be a focus of regulation. Most notably, in March 2014, EPA published a series of Methane White Papers addressing suspected methane emissions from the oil and gas sector. The agency announced in early 2015 that it will be proposing new rules aimed at further reducing methane emissions from the oil and gas sector in 2015, with final rules expected in 2016. These rules will build on the Methane White Papers and will likely include new regulatory requirements affecting our operations. In addition to the proposed Colorado rules discussed above and in “Business and Properties-Governmental Regulation-Environmental Matters,” a lawsuit has been filed by several northeastern states that would require EPA to more stringently regulate methane emissions from the oil and gas sector. The passage of legislation, or executive and other initiatives that limit emissions of greenhouse gases from our equipment and operations, could require us to incur costs to reduce the greenhouse gas emissions, and it could also adversely affect demand for the crude oil and natural gas that we produce. +Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. Flooding that occurred in Colorado in 2013 is an example of an extreme weather event that negatively impacted our operations. If such events were to continue to occur, or become more frequent, our operations could be adversely affected in various ways, including through damage to our facilities from increased costs for insurance. +Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our fuels could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business. +The cost of defending any suits brought against us, and any judgments or settlements resulting from such suits, could have an adverse effect on our results of operations and financial condition. +Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. For example, in recent years, we have been subject to lawsuits regarding royalty practices and payments and matters relating to certain of our affiliated partnerships. The outcome of pending legal proceedings is inherently uncertain. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, the resolution of such a proceeding could result in penalties or sanctions, settlement costs and/or judgments, consent decrees or orders requiring a change in our business practices, any of which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties, sanctions or costs may be insufficient. Judgments and estimates to determine accruals or the anticipated range of potential losses related to legal and other proceedings could change from one period to the next, and such changes could be material. +Our articles of incorporation, bylaws, stockholders rights plan and Nevada law contain provisions that may have an anti-takeover effect and may delay, defer or prevent a tender offer or takeover attempt, which may adversely affect the market price of our common stock. +Our articles of incorporation authorize our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. We have adopted a stockholders rights plan that will dilute the stock ownership of certain acquirers of our common stock upon the occurrence of certain events. In addition, some provisions of our articles of incorporation, bylaws and Nevada law could make it more difficult for a third party to acquire control of us, including: +• +the organization of our board of directors as a classified board, which allows no more than one-third of our directors to be elected each year; +• +limitations on the ability of our shareholders to call special meetings; and +• +certain Nevada anti-takeover statutes. +31 +Because we have no plans to pay dividends on our common stock, investors must look solely to stock appreciation for a return on their investment in us. +We have never declared or paid cash dividends on our common stock. We currently intend to retain all future earnings and other cash resources, if any, for the operation and development of our business and do not anticipate paying cash dividends in the foreseeable future. Payment of any future dividends will be at the discretion of our board of directors after taking into account many factors, including our financial condition, operating results, current and anticipated cash needs and plans for expansion. In addition, our revolving credit facility and the indenture governing our senior notes limit our ability to pay cash dividends on our common stock. Any future dividends may also be restricted by any debt agreements which we may enter into from time to time. +A failure to complete successful acquisitions would limit our growth. +Because our crude oil and natural gas properties are depleting assets, our future reserves, production volumes and cash flows depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. Acquiring additional crude oil and natural gas properties, or businesses that own or operate such properties, when attractive opportunities arise is a significant component of our strategy. We may not be able to identify attractive acquisition opportunities. If we do identify an appropriate acquisition candidate, we may be unable to negotiate mutually acceptable terms with the seller, finance the acquisition or obtain the necessary regulatory approvals. If we are unable to complete suitable acquisitions, it will be more difficult to replace our reserves, and an inability to replace our reserves would have a material adverse effect on our financial condition and results of operations. +Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities. +Unless production is established within the spacing units covering the undeveloped acres on which some of our drilling locations are identified, our leases for such acreage will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may differ materially from our current expectations, which could adversely affect our business. These risks are greater at times and in areas where the pace of our exploration and development activity slows, such as currently in the Utica Shale, where we have suspended drilling activity due to lower commodity prices. In addition, we do not operate a substantial portion of our Utica Shale acreage. Our relative lack of control over this non-operated acreage increases the risk that some of our leases will expire. +We may incur losses as a result of title defects in the properties in which we invest. +It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. Leases in the Utica area are particularly vulnerable to title deficiencies due the long history of land ownership in the area and correspondingly extensive and complex chains of title. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property. +ITEM 1B. UNRESOLVED STAFF COMMENTS +None. +ITEM 3. LEGAL PROCEEDINGS +Information regarding our legal proceedings can be found in Note 11, Commitments and Contingencies – Litigation , to our consolidated financial statements included elsewhere in this report. +ITEM 4. MINE SAFETY DISCLOSURES +Not applicable. +32 +PART II +ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Our common stock, par value $0.01 per share, is traded on the NASDAQ Global Select Market under the symbol PDCE. The following table sets forth the range of high and low sales prices for our common stock for each of the periods presented: +High +Low +January 1 - March 31, 2013 +$ +53.80 +$ +33.39 +April 1 - June 30, 2013 +55.56 +38.02 +July 1 - September 30, 2013 +66.03 +51.46 +October 1 - December 31, 2013 +73.93 +51.32 +January 1 - March 31, 2014 +64.27 +44.72 +April 1 - June 30, 2014 +70.44 +56.88 +July 1 - September 30, 2014 +63.73 +49.82 +October 1 - December 31, 2014 +50.95 +27.91 +As of February 2, 2015 , we had approximately 696 shareholders of record. Since inception, no cash dividends have been declared on our common stock. Cash dividends are restricted under the terms of our revolving credit facility and the indenture governing our 7.75% senior notes due 2022 and we presently intend to continue a policy of using retained earnings for expansion of our business. See Note 8, Long-term Debt , to our consolidated financial statements included elsewhere in this report. +The following table presents information about our purchases of our common stock during the three months ended December 31, 2014 : +Period +Total Number of Shares Purchased (1) +Average Price Paid per Share +October 1 - 31, 2014 +5,632 +$ +45.94 +November 1 - 30, 2014 +2,083 +34.33 +December 1 - 31, 2014 +15,304 +41.27 +Total fourth quarter purchases +23,019 +41.79 +__________ +(1) +Purchases primarily represent shares purchased from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans. +33 +SHAREHOLDER PERFORMANCE GRAPH +The performance graph below compares the cumulative total return of our common stock over the five-year period ended December 31, 2014 , with the cumulative total returns for the same period for the Standard and Poor's ("S&P") 500 Index and the Standard Industrial Code ("SIC") Index. The SIC Index is a weighted composite of 253 crude petroleum and natural gas companies. The cumulative total shareholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on December 31, 2009 and in the S&P 500 Index and the SIC Index on the same date. The results shown in the graph below are not necessarily indicative of future performance. +34 +ITEM 6. SELECTED FINANCIAL DATA +Year Ended/As of December 31, +2014 +2013 +2012 +2011 +2010 +(in millions, except per share data and as noted) +Statement of Operations (From Continuing Operations): +Crude oil, natural gas and NGLs sales +$ +471.4 +$ +340.8 +$ +228.0 +$ +216.1 +$ +144.8 +Commodity price risk management gain (loss), net +310.3 +$ +(23.9 +) +29.3 +39.4 +59.4 +Total revenues +856.2 +392.7 +307.1 +323.3 +274.8 +Income (loss) from continuing operations +107.3 +(21.1 +) +(19.4 +) +23.2 +23.8 +Earnings per share from continuing operations: +Basic +$ +3.00 +$ +(0.65 +) +$ +(0.70 +) +$ +0.98 +$ +1.23 +Diluted +2.93 +(0.65 +) +(0.70 +) +0.97 +1.21 +Statement of Cash Flows: +Net cash from: +Operating activities +$ +236.7 +$ +159.2 +$ +174.7 +$ +151.8 +$ +143.9 +Investing activities +(474.1 +) +(217.1 +) +(451.9 +) +(300.9 +) +(142.3 +) +Financing activities +60.3 +248.7 +271.4 +171.5 +(20.6 +) +Capital expenditures +628.6 +394.9 +347.7 +162.7 +143.0 +Acquisitions of crude oil and natural gas properties +— +9.7 +312.2 +158.1 +— +Balance Sheet: +Total assets +$ +2,340.6 +$ +2,025.2 +$ +1,698.0 +$ +1,389.0 +$ +1,250.3 +Working capital +30.3 +112.4 +(22.0 +) +16.2 +32.9 +Long-term debt +664.9 +605.0 +532.2 +295.7 +280.7 +Total equity +1,137.4 +967.6 +664.1 +642.2 +538.6 +Pricing and Lease Operating Expenses From to Continuing Operations (per Boe): +Average sales price (excluding net settlements on derivatives) +$ +50.72 +$ +52.23 +$ +46.85 +$ +49.97 +$ +43.38 +Average lease operating expenses +4.36 +4.78 +4.57 +4.56 +3.97 +Production (MBoe): +Production from continuing operations +9,294.4 +6,524.7 +4,866.5 +4,324.4 +3,336.6 +Production from discontinued operations +1,093.0 +2,032.6 +3,458.7 +3,596.3 +3,102.8 +Total production +10,387.4 +8,557.3 +8,325.2 +7,920.7 +6,439.4 +Total proved reserves (MMBoe) (1)(2)(3) +250.1 +265.8 +192.8 +169.3 +143.4 +______________ +(1) +Includes total proved reserves related to our Marcellus Shale and shallow Upper Devonian Appalachian Basin assets of 40 MMBoe, 30 MMBoe, 22 MMBoe and 11MMBoe as of December 31, 2013, 2012, 2011 and 2010, respectively. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Marcellus Shale and shallow Upper Devonian Appalachian Basin assets. +(2) +Includes total proved reserves related to our Piceance Basin and NECO assets of 14 MMBoe, 59 MMBoe, and 76 MMBoe as of December 31, 2012, 2011 and 2010, respectively. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Piceance Basin and NECO assets. +(3) +Includes total proved reserves related to our Permian Basin assets of 11 MMBoe and 5 MMBoe as of December 31, 2011 and 2010, respectively. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Permian Basin assets. +35 +ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +The following discussion and analysis, as well as other sections in this report, should be read in conjunction with our consolidated financial statements and related notes to consolidated financial statements included elsewhere in this report. Further, we encourage you to revisit the Special Note Regarding Forward-Looking Statements in Part I of this report. +EXECUTIVE SUMMARY +2014 Financial Overview +Crude oil, natural gas and NGLs sales from continuing operations increased in 2014 by $130.6 million , or 38% , compared to 2013 . The growth in crude oil, natural gas and NGLs sales was the result of increased production. For the month ended December 31, 2014 , we maintained an average production rate of 30 MBoe per day. Production of 9.3 MMboe from continuing operations for the year ended December 31, 2014 represents an increase of 42% as compared to the year ended December 31, 2013 , primarily attributable to our successful horizontal Niobrara and Codell drilling program in the Wattenberg Field. Crude oil production from continuing operations increased 49% in 2014 , while NGLs production from continuing operations increased 68% . Our liquids percentage of total production from continuing operations was 65% in 2014 . Natural gas production from continuing operations increased 25% in 2014 compared to 2013 . Higher natural gas index prices at derivatives settlement during 2014 were the primary reason for negative net settlements on derivative positions of $0.8 million in 2014 compared to positive net settlements of $11.2 million in 2013 . Crude oil, natural gas and NGLs sales, including the impact of net settlements on derivatives, was $470.6 million in 2014 compared to $352.0 million in 2013 . This represents an increase of 34% in 2014 compared to 2013 . +Other significant changes impacting our 2014 results of operations include the following: +• +Positive net change in the fair value of unsettled derivatives in 2014 was $311.1 million compared to a negative net change in the fair value of unsettled derivative positions of $35.1 million in 2013, as the crude oil and natural gas forward curves shifted significantly lower during the later months of 2014; +• +Impairment of crude oil and natural gas properties increased to $163.5 million in 2014 compared to $52.5 million in 2013, primarily related to the $158.3 million write-down of our Utica Shale producing and non-producing crude oil and natural gas properties to their estimated fair value, $112.6 million of which was for proved producing properties and $45.7 million for unproved properties; +• +General and administrative expense increased to $115.9 million in 2014 compared to $60.0 million in 2013, primarily attributable to $40.3 million recorded in 2014 in connection with settlement of certain partnership-related class action litigation and litigation arising from bankruptcy proceedings of certain affiliated partnerships; +• +Depreciation, depletion and amortization expense increased to $192.5 million compared to $115.6 million in 2013 , mainly due to the increase in production; and +• +Gain on sale of properties and equipment classified as discontinued operations increased to $76.5 million compared to a loss on sale of properties and equipment classified as discontinued operations of $1.7 million in 2013. +Available liquidity as of December 31, 2014 was $398.4 million compared to $647.0 million as of December 31, 2013 . Available liquidity is comprised of $16.1 million of cash and cash equivalents and $382.3 million available for borrowing under our revolving credit facility. In addition to our currently elected commitment of $450 million, we have an additional $250 million of borrowing base availability under our revolving credit facility, subject to certain terms and conditions of the agreement. Considering the additional $250 million, our liquidity position as of December 31, 2014 would have been $648.3 million . With our current derivative position, available liquidity and expected cash flows from operations, we believe we have sufficient liquidity to allow us to execute our expected capital program through 2015. +Operational Overview +Drilling Activities. During 2014 , we continued to execute our strategic plan of increasing production, reserves and cash flows from drilling operations in the Wattenberg Field in Colorado and the Utica Shale play in southeastern Ohio. In the Wattenberg Field, we are currently running five drilling rigs. In 2014 , we spudded 116 horizontal wells in the Wattenberg Field, turned-in-line 86 horizontal wells and participated in 84 gross, 18.7 net, horizontal non-operated drilling projects. We spudded 11 horizontal Utica wells in 2014 and turned-in-line eight horizontal wells. +Divestiture of Appalachian Marcellus Shale Assets. In October 2014 , we completed the sale of our entire 50% ownership interest in PDCM to an unrelated third-party for aggregate consideration, after our share of PDCM's debt repayment and other working capital adjustments, of approximately $192 million , comprised of approximately $153 million in net cash proceeds and a promissory note due in 2020 of approximately $39 million . The transaction included the buyer's assumption of our share of the firm transportation commitment related to the assets owned by PDCM, as well as our share of PDCM's natural gas hedging positions for the years 2014 through 2017. The divestiture resulted in a pre-tax gain of $76.3 million . Proceeds from the divestiture were used to reduce outstanding borrowings on our revolving credit facility and to fund a portion of our 2014 capital budget. +2015 Operational Outlook +We expect our production for 2015 to range between 13.5 MMBoe to 14.5 MMBoe and that our production rate will average approximately 38,400 Boe per day at the mid-point of that range. Our projected expenditures for our 2015 capital program has been reduced to +36 +approximately $473 million . The updated 2015 capital program maintains our five-rig drilling program in the Wattenberg Field, but has been adjusted for anticipated service cost reductions and lower non-operated spending, partially offset by increased working interests on certain planned 2015 wells. Our 2015 capital program forecast is expected to be directed primarily to development drilling in the Wattenberg Field, completion of a four-well pad in the Utica Shale and for other miscellaneous projects. Our 2015 capital program forecast includes $435 million of development capital and $38 million for lease acquisition and other capital expenditures. A further deterioration of commodity prices could negatively impact our financial condition and results of operations. We may further revise our capital program forecast during the year as a result of, among other things, commodity prices, acquisitions or dispositions of assets, drilling results, changes in our borrowing capacity and/or significant changes in cash flows. +Wattenberg Field. We expect to invest approximately $435 million in the Wattenberg Field in 2015 , continuing with a five -rig drilling program. The capital program forecast is expected to consist of $379 million for our operated drilling program and $56 million for non-operated projects. We expect to spud approximately 119 and turn-in-line 109 horizontal Niobrara or Codell wells, of which 40% are expected to be extended length laterals of approximately 6,500 feet to 7,000 feet. Approximately 60% of the wells are expected to target the Niobrara formation, with the remainder targeting the Codell formation. We expect to participate in approximately 85 gross, 14.2 net, non-operated horizontal opportunities in 2015 . +Utica Shale. Based on current low commodity prices and large natural gas price differentials in Appalachia, we have elected to temporarily cease drilling in the Utica Shale in favor of allocating more of our 2015 capital program to our higher return projects in the Wattenberg inner and middle core areas. In 2015, we plan to invest a total of $35 million in the Utica Shale to complete and turn-in-line the four-well Cole pad that was in-process as of December 31, 2014 and for lease acquisitions and other capital expenditures. We expect to resume our Utica Shale drilling program when commodity prices and net-back realizations rebound. +Non-U.S. GAAP Financial Measures +We use "adjusted cash flows from operations," "adjusted net income (loss)," "adjusted EBITDA" and "PV-10," non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and, in some cases, providing public guidance on possible future results. These measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss) or cash flows from operations, investing or financing activities, or standardized measure, as applicable, and should not be viewed as liquidity measures or indicators of cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. Also, in the future, we may disclose different non-U.S. GAAP financial measures in order to help our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure. See Reconciliation of Non-U.S. GAAP Financial Measures for a detailed description of these measures, as well as a reconciliation of each to the most comparable U.S. GAAP measure. +37 +Results of Operations +Summary Operating Results +The following table presents selected information regarding our operating results from continuing operations: +Year Ended December 31, +Percent Change +2014 +2013 +2012 +2014-2013 +2013-2012 +(dollars in millions, except per unit data) +Production (1) +Crude oil (MBbls) +4,321.9 +2,909.7 +1,987.8 +48.5 +% +46.4 +% +Natural gas (MMcf) +19,298.0 +15,431.2 +12,247.8 +25.1 +% +26.0 +% +NGLs (MBbls) +1,756.2 +1,043.2 +837.3 +68.3 +% +24.6 +% +Crude oil equivalent (MBoe) (2) +9,294.4 +6,524.7 +4,866.5 +42.4 +% +34.1 +% +Average MBoe per day +25.5 +17.9 +13.3 +42.4 +% +34.4 +% +Crude Oil, Natural Gas and NGLs Sales +Crude oil +$ +348.6 +$ +261.6 +$ +173.5 +33.3 +% +20.4 +% +Natural gas +74.7 +50.0 +31.6 +49.4 +% +58.2 +% +NGLs +48.1 +29.2 +22.9 +64.7 +% +27.5 +% +Total crude oil, natural gas and NGLs sales +$ +471.4 +$ +340.8 +$ +228.0 +38.3 +% +49.5 +% +Net Settlements on Derivatives (3) +Natural gas +$ +(3.1 +) +$ +14.3 +$ +44.1 +* +(67.6 +)% +Crude oil +2.3 +(3.1 +) +(0.5 +) +* +* +Total net settlements on derivatives +$ +(0.8 +) +$ +11.2 +$ +43.6 +* +(74.3 +)% +Average Sales Price (excluding net settlements on derivatives) +Crude oil (per Bbl) +$ +80.67 +$ +89.92 +$ +87.27 +(10.3 +)% +3.0 +% +Natural gas (per Mcf) +3.87 +3.24 +2.58 +19.4 +% +25.6 +% +NGLs (per Bbl) +27.39 +27.97 +27.33 +(2.1 +)% +2.3 +% +Crude oil equivalent (per Boe) +50.72 +52.23 +46.85 +(2.9 +)% +11.5 +% +Average Lease Operating Expenses (per Boe) +Wattenberg Field +$ +4.60 +$ +4.37 +$ +3.88 +5.3 +% +12.6 +% +Utica Shale +1.82 +1.50 +5.86 +21.3 +% +* +Other +2.04 +13.53 +12.11 +(84.9 +)% +11.7 +% +Weighted-average +4.36 +4.78 +4.57 +(8.8 +)% +4.6 +% +Natural Gas Marketing Contribution Margin (4) +$ +(0.4 +) +$ +(0.3 +) +$ +0.4 +(33.3 +)% +* +Other Costs and Expenses +Exploration expense +$ +0.9 +$ +6.3 +$ +18.2 +(85.0 +)% +(65.2 +)% +Impairment of crude oil and natural gas properties +163.5 +52.5 +5.0 +* +* +General and administrative expense +115.9 +60.0 +54.8 +93.2 +% +9.4 +% +Depreciation, depletion and amortization +192.5 +115.6 +91.1 +66.5 +% +26.9 +% +Loss on extinguishment of debt +$ +— +$ +— +$ +23.3 +* +* +Interest expense +$ +47.8 +$ +50.1 +$ +47.5 +(4.6 +)% +5.6 +% +* +Percentage change is not meaningful or equal to or greater than 300%. +Amounts may not recalculate due to rounding. +38 +______________ +(1) +Production is net and determined by multiplying the gross production volume of properties in which we have an interest by our ownership percentage. For total production volume, including discontinued operations, see Part I, Item 6, Selected Financial Data. +(2) +One Bbl of crude oil or NGL equals six Mcf of natural gas. +(3) +Represents net settlements on derivatives related to crude oil and natural gas sales, which do not include net settlements on derivatives related to natural gas marketing. +(4) +Represents sales from natural gas marketing, net of costs of natural gas marketing, including net settlements and net change in fair value of unsettled derivatives related to natural gas marketing activities. +Crude Oil, Natural Gas and NGLs Sales +The following tables present crude oil, natural gas and NGLs production and weighted-average sales price for continuing operations: +Year Ended December 31, +Change +Production by Operating Region +2014 +2013 +2012 +2014-2013 +2013-2012 +Crude oil (MBbls) +Wattenberg Field +4,026.7 +2,783.1 +1,979.1 +44.7 +% +40.6 +% +Utica Shale +295.2 +122.8 +3.0 +140.4 +% +* +Other +— +3.8 +5.7 +* +(33.3 +)% +Total +4,321.9 +2,909.7 +1,987.8 +48.5 +% +46.4 +% +Natural gas (MMcf) +Wattenberg Field +17,108.9 +12,724.3 +9,844.7 +34.5 +% +29.3 +% +Utica Shale +2,152.9 +561.1 +2.1 +283.7 +% +* +Other +36.2 +2,145.8 +2,401.0 +(98.3 +)% +(10.6 +)% +Total +19,298.0 +15,431.2 +12,247.8 +25.1 +% +26.0 +% +NGLs (MBbls) +Wattenberg Field +1,605.7 +1,034.4 +837.3 +55.2 +% +23.5 +% +Utica Shale +150.5 +8.8 +— +* +* +Total +1,756.2 +1,043.2 +837.3 +68.3 +% +24.6 +% +Crude oil equivalent (MBoe) +Wattenberg Field +8,483.8 +5,938.2 +4,457.3 +42.9 +% +33.2 +% +Utica Shale +804.6 +225.2 +3.3 +257.3 +% +* +Other +6.0 +361.3 +405.9 +(98.3 +)% +(11.0 +)% +Total +9,294.4 +6,524.7 +4,866.5 +42.4 +% +34.1 +% +* +Percentage change is not meaningful or equal to or greater than 300%. +Amounts may not recalculate due to rounding. +39 +Year Ended December 31, +Average Sales Price by Operating Region +Change +(excluding net settlements on derivatives) +2014 +2013 +2012 +2014-2013 +2013-2012 +Crude oil (per Bbl) +Wattenberg Field +$ +80.61 +$ +89.83 +$ +87.27 +(10.3 +)% +2.9 +% +Utica Shale +81.52 +91.90 +76.57 +(11.3 +)% +20.0 +% +Other +— +92.88 +92.72 +* +0.2 +% +Weighted-average price +80.67 +89.92 +87.27 +(10.3 +)% +3.0 +% +Natural gas (per Mcf) +Wattenberg Field +3.94 +3.25 +2.61 +21.2 +% +24.5 +% +Utica Shale +3.35 +2.74 +1.66 +22.3 +% +65.1 +% +Other +3.90 +3.31 +2.49 +17.8 +% +32.9 +% +Weighted-average price +3.87 +3.24 +2.58 +19.4 +% +25.6 +% +NGLs (per Bbl) +Wattenberg Field +25.95 +27.83 +27.33 +(6.8 +)% +1.8 +% +Utica Shale +42.76 +43.70 +— +(2.2 +)% +* +Weighted-average price +27.39 +27.97 +27.33 +(2.1 +)% +2.3 +% +Crude oil equivalent (per Bbl) +Wattenberg Field +51.10 +53.91 +49.64 +(5.2 +)% +8.6 +% +Utica Shale +46.87 +58.68 +69.55 +(20.1 +)% +(15.6 +)% +Other +23.42 +20.59 +16.02 +13.7 +% +28.5 +% +Weighted-average price +50.72 +52.23 +46.85 +(2.9 +)% +11.5 +% +* +Percentage change is not meaningful or equal to or greater than 300%. +Amounts may not recalculate due to rounding. +The year-over-year change in crude oil, natural gas and NGLs sales revenue were primarily due to the following: +Year Ended December 31, +2014 +2013 +(in millions) +Increase in production +$ +159.5 +$ +94.3 +Increase (decrease) in average crude oil price +(40.0 +) +7.7 +Increase in average natural gas price +12.1 +10.2 +Increase (decrease) in average NGLs price +(1.0 +) +0.6 +Total increase in crude oil, natural gas and NGLs sales revenue +$ +130.6 +$ +112.8 +Crude oil, natural gas and NGLs sales in 2014 increased 38% compared to 2013. The increase was primarily attributable to significantly higher volumes sold, in particular liquids, which resulted in a liquids percentage of total production of approximately 65% in 2014. Our average daily sales volumes increased to 25 MBoe per day in 2014 compared to 18 MBoe per day in 2013, primarily due to the success of the horizontal Niobrara and Codell drilling program in the Wattenberg Field. Contributing to the increase in crude oil, natural gas and NGLs sales was a 19% increase in the average price of natural gas in 2014 over 2013. +Crude oil, natural gas and NGLs sales in 2013 increased 49% compared to 2012. The increase was primarily attributable to an increase in volumes sold, in particular liquids, which resulted in a liquids percentage of total production of approximately 61% in 2013. Our average daily sales volumes increased to 18 MBoe per day in 2013 compared to 13 MBoe per day in 2012. The increase in crude oil, natural gas and NGLs sales was also due to increases in the average price of natural gas, crude oil and NGLs of 26% , 3% and 2% , respectively, in 2013. +As expected, we experienced higher than normal gathering system pressures in the Wattenberg Field by our primary third-party midstream provider during 2014 and we had previously factored in these higher line pressures into our production estimates for the year. The line pressures in 2014 were within our expectations and lower than they were in 2012 and the first three quarters of 2013, primarily due to the commissioning of the O’Connor gas plant in the fall of 2013, the startup of an additional compressor station in 2014 and relatively mild summer temperatures in 2014. Ongoing industry drilling activity in the area has continued to increase volumes on the gathering system and pressures remained at 2014 summer levels through the end of 2014. We believe our midstream service provider will be challenged to keep pace with industry drilling activity with new midstream infrastructure at least until the new Lucerne II plant is completed in mid-2015. This project should result in a significant increase in processing capacity and we anticipate that it will address system pressure issues until well into 2016, when the next significant midstream infrastructure projects are projected to be completed. We and other operators in the field are working with the midstream service provider, who continues to implement a multi-year facility expansion program that will significantly increase the long-term gathering +40 +and processing capacity of the system. Like most producers, we rely on our third-party midstream service providers to construct compression, gathering and processing facilities to keep pace with our production growth. As a result, the timing and availability of additional facilities going forward is beyond our control. +Crude Oil, Natural Gas and NGLs Pricing. Our results of operations depend upon many factors, particularly the price of crude oil, natural gas and NGLs and our ability to market our production effectively. Crude oil, natural gas and NGLs prices are among the most volatile of all commodity prices. The price of crude oil and natural gas weakened significantly in the second half of 2014 due to a combination of factors including increased U.S. supply, global economic concerns and a decision by the Organization of the Petroleum Exporting Countries not to reduce supply. These price variations can have a material impact on our financial results and capital expenditures. +Crude oil pricing is predominately driven by the physical market, supply and demand, financial markets and national and international politics. In the Wattenberg Field, crude oil is sold under various purchase contracts with monthly pricing provisions based on NYMEX pricing, adjusted for differentials. We are currently pursuing various alternatives with respect to oil transportation, particularly in the Wattenberg Field, with a view toward improving pricing and takeaway capacity. We recently reached agreement to commit a significant portion of our Wattenberg Field crude oil production to White Cliffs Pipeline, LLC, which will allow crude oil to be transported via pipeline to the Cushing, Oklahoma market starting in May of 2015. In addition, we have signed a long-term agreement for gathering of crude oil at the wellhead by pipeline from several of our wells and transported to at least one central point in the Wattenberg Field, with a view toward reducing costs and minimizing truck traffic and overall physical footprint. In the Utica Shale, crude oil and condensate is sold to local purchasers at each individual well site based on NYMEX pricing, adjusted for differentials. Natural gas prices vary by region and locality, depending upon the distance to markets, availability of pipeline capacity and supply and demand relationships in that region or locality. The price we receive for our natural gas produced in the Wattenberg Field is based on CIG prices, adjusted for certain deductions, while natural gas produced in the Utica Shale has been based on TETCO M-2 and Dominion pricing, adjusted for certain deductions. Starting in 2015, all of our Utica Shale gas has access to the TETCO M-2 pipeline. The differentials at our sales points for the Utica Shale widened substantially in 2014, primarily due to an oversupply of gas in the Appalachian region. We have been able to sell a portion of our Utica gas to a Midwest market which has helped to mitigate the impact of these differentials. We anticipate that the widened Appalachian differentials will continue at least through the remainder of 2015. Our price for NGLs produced in the Wattenberg Field is based on a combination of prices from the Conway hub in Kansas and Mt. Belvieu in Texas where this production is marketed. The NGLs produced in the Utica Shale are sold based on month-to-month pricing to various markets. +We currently use the "net-back" method of accounting for crude oil, natural gas and NGLs production from the Wattenberg Field and crude oil from the Utica Shale as the majority of the purchasers of these commodities also provide transportation, gathering and processing services. We sell our commodities at the wellhead and collect a price and recognize revenues based on the wellhead sales price as transportation and processing costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based. Natural gas and NGLs sales related to production from the Utica Shale are recognized based on gross prices as the purchasers do not provide transportation, gathering or processing services and we recognize expenses relating to those services as production costs. +Production Costs +Production costs include lease operating expenses, production taxes, transportation and gathering expense and certain production and engineering staff-related overhead costs as follows: +Year Ended December 31, +2014 +2013 +2012 +(in millions, except per unit data) +Lease operating expenses +$ +40.5 +$ +31.2 +$ +22.2 +Production taxes +25.6 +21.8 +13.9 +Transportation, gathering and processing expenses +4.6 +5.2 +2.8 +Overhead and other production expenses +12.9 +6.7 +10.5 +Total production costs +$ +83.6 +$ +64.9 +$ +49.4 +Total production costs per Boe +$ +9.00 +$ +9.94 +$ +10.15 +Lease operating expenses. Lease operating expenses per Boe were $4.36 , $4.78 and $4.57 for 2014 , 2013 and 2012 , respectively. The $9.3 million increase in lease operating expenses in 2014 as compared to 2013 was primarily due to an increase of $2.9 million to mitigate high line pressures in the Wattenberg Field, including costs for the rental of additional compressors, as well as additional well maintenance incurred in order to increase the operating efficiency of older vertical wells, $1.1 million for workover and maintenance related projects, including additional costs incurred for the plugging of older vertical wells, $1.9 million for environmental compliance and remediation projects, $1.9 million for lease operating expenses incurred on the increasing number of non-operated wells and $1.0 million in additional wages and benefits due to increased headcount. The $9.0 million increase in lease operating expenses in 2013 as compared to 2012 was due to an increase of $3.5 million for workover, compliance and maintenance related projects, an increase of $2.1 million for the rental of additional compressors used to mitigate high line pressures in the Wattenberg Field, an increase of $1.2 million in additional wages and employee benefits due to increased headcount and $0.9 million of expenses for wells impacted by the September 2013 Colorado flood. +41 +Production taxes. Production taxes are directly related to crude oil, natural gas and NGLs sales. The $3.8 million , or 17% , increase in production taxes for 2014 compared to 2013 is primarily related to the 38% increase in crude oil, natural gas and NGLs sales. Similarly, the $7.9 million , or 57% , increase in production taxes for 2013 compared to 2012 is primarily related to the 49% increase in crude oil, natural gas and NGLs sales. +Transportation, gathering and processing expenses . The $0.6 million , or 12% , decrease in transportation, gathering and processing expenses for 2014 compared to 2013 was primarily attributable to a $2.5 million reduction in our unutilized takeaway capacity and other transportation costs resulting from the divestiture of our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties and a $0.4 million decrease in compressor and refrigeration unit rentals in the Utica Shale, offset by a $2.3 million net increase in transportation and processing expenses due to higher production levels, primarily in the Utica Shale region. The $2.4 million , or 86% , increase in transportation, gathering and processing expenses for 2013 compared to 2012 was primarily attributable to an increase in unutilized takeaway capacity costs in our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties. +Overhead and other production expenses . Overhead and other production expenses increased $6.2 million in 2014 compared to 2013 mainly attributable to a $3.2 million increase in wages and employee benefits, mostly attributable to moving Utica Shale employee costs to production expense from exploration expense, and an increase of $2.9 million for the write-off of costs due to changes in our capital and future development plan. The decrease of $3.8 million in 2013 compared to 2012 was mainly the result of $3.2 million of expense recognized in 2012 related to the sale of crude oil inventory that had been acquired at fair market value in the Merit Acquisition. +Commodity Price Risk Management, Net +We use various derivative instruments to manage fluctuations in natural gas and crude oil prices. We have in place a variety of collars, fixed-price swaps and basis swaps on a portion of our estimated natural gas and crude oil production. Because we sell all of our natural gas and crude oil production at prices similar to the indexes inherent in our derivative instruments, adjusted for certain fees and surcharges stipulated in the applicable sales agreements, we ultimately realize a price, before contract fees, related to our collars of no less than the floor and no more than the ceiling and, for our commodity swaps, we ultimately realize the fixed price related to our swaps. See Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this report and Item 7A, Quantitative and Qualitative Disclosures About Market Risk , for a discussion of how each derivative type impacts our cash flows and a detailed presentation of our derivative positions as of December 31, 2014 . +Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments and the change in fair value of unsettled derivatives related to our crude oil and natural gas production. Commodity price risk management, net, does not include derivative transactions related to our natural gas marketing, which are included in sales from and cost of natural gas marketing. See Note 3, Fair Value of Financial Instruments , and Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this report for additional details of our derivative financial instruments. +Net settlements are primarily the result of crude oil and natural gas index prices at maturity of our derivative instruments compared to the respective strike prices. Net change in fair value of unsettled derivatives is comprised of the net asset increase or decrease in the beginning-of-period fair value of derivative instruments that settled during the period and the net change in fair value of unsettled derivatives during the period. The corresponding impact of settlement of the derivative instruments that settled during the period is included in net settlements for the period as discussed above. Net change in fair value of unsettled derivatives during the period is primarily related to shifts in the crude oil and natural gas forward curves and changes in certain differentials. See Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this report for a detailed description of net settlements on our various derivatives. +42 +The following table presents net settlements and net change in fair value of unsettled derivatives included in commodity price risk management, net: +Year Ended December 31, +2014 +2013 +2012 +(in millions) +Commodity price risk management gain (loss), net: +Net settlements: +Natural gas +$ +(3.1 +) +$ +14.3 +$ +44.1 +Crude oil +2.3 +(3.1 +) +(0.5 +) +Total net settlements +(0.8 +) +11.2 +43.6 +Change in fair value of unsettled derivatives: +Reclassification of settlements included in prior period changes in fair value of derivatives +13.3 +(28.7 +) +(25.1 +) +Natural gas fixed price swaps +30.6 +4.3 +(0.2 +) +Natural gas basis swaps +— +(4.3 +) +(0.5 +) +Natural gas collars +11.1 +3.8 +2.1 +Crude oil fixed price swaps +206.5 +(9.1 +) +7.7 +Crude oil collars +49.6 +(1.1 +) +1.7 +Net change in fair value of unsettled derivatives +311.1 +(35.1 +) +(14.3 +) +Total commodity price risk management gain (loss), net +$ +310.3 +$ +(23.9 +) +$ +29.3 +Natural Gas Marketing +Fluctuations in our natural gas marketing's income contribution are primarily due to fluctuations in commodity prices, cash settlements upon maturity of derivative instruments and the change in fair value of unsettled derivatives, and volumes sold and purchased. +The following table presents the components of sales from and costs of natural gas marketing: +Year Ended December 31, +2014 +2013 +2012 +(in millions) +Natural gas sales revenue +$ +71.4 +$ +68.9 +$ +44.9 +Net settlements from derivatives +(0.2 +) +0.5 +2.2 +Net change in fair value of unsettled derivatives +0.4 +0.4 +(1.7 +) +Total sales from natural gas marketing +71.6 +69.8 +45.4 +Costs of natural gas purchases +70.1 +68.1 +43.3 +Net settlements from derivatives +(0.3 +) +0.3 +2.0 +Net change in fair value of unsettled derivatives +0.4 +0.4 +(1.6 +) +Other +1.8 +1.3 +1.3 +Total costs of natural gas marketing +72.0 +70.1 +45.0 +Natural gas marketing contribution margin +$ +(0.4 +) +$ +(0.3 +) +$ +0.4 +The increase in natural gas sales revenue and costs of natural gas purchases in 2014 compared to 2013 is primarily attributable to a 7.5% increase in volumes slightly offset by a 2.8% decrease in the average natural gas price. The increase in natural gas sales revenue and costs of natural gas purchases in 2013 compared to 2012 is primarily attributable to a 30% increase in the average natural gas price and a 14% increase in volumes. +Derivative instruments related to natural gas marketing include both physical and cash-settled derivatives. We offer fixed-price derivative contracts for the purchase or sale of physical natural gas and enter into cash-settled derivative positions with counterparties in order to offset those same physical positions. See Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this report and Item 7A, Quantitative and Qualitative Disclosures About Market Risk , for a discussion of how each derivative type impacts our cash flows and detailed presentation of our derivative positions as of December 31, 2014 . +43 +Exploration Expense +The following table presents the major components of exploration expense: +Year Ended December 31, +2014 +2013 +2012 +(in millions) +Exploratory dry hole costs +$ +— +$ +— +$ +14.5 +Geological and geophysical costs +— +0.7 +0.7 +Operating, personnel and other +0.9 +5.6 +3.0 +Total exploration expense +$ +0.9 +$ +6.3 +$ +18.2 +Exploratory dry hole costs. There were no exploratory dry holes in 2014 and 2013. In 2012, two vertical stratigraphic test wells in southeastern Ohio were expensed at a cost of $12.2 million. The remaining 2012 expense relates to the unsuccessful testing of an exploratory zone in two existing wells in the Wattenberg Field and three Rose Run test wells in Ohio that were determined to have found noncommercial quantities of hydrocarbons. +Geological and geophysical costs. Geological and geophysical costs in 2013 and 2012 were primarily related to costs associated with reservoir studies in the Utica Shale. +Operating, personnel and other . The $4.7 million decrease in 2014 compared to 2013 is primarily related to a reduction in personnel costs in the Utica Shale resulting from the reassignment of former exploration department personnel to production departments and to general and administrative expense. The $2.6 million increase in 2013 compared to 2012 was mainly attributable to an increase in payroll and employee benefits in the exploration division as a result of increased employee headcount in the Utica Shale. +Impairment of Crude Oil and Natural Gas Properties +The following table sets forth the major components of our impairments of crude oil and natural gas properties expense: +Year Ended December 31, +2014 +2013 +2012 +(in millions) +Continuing operations: +Impairment of proved properties +$ +112.6 +$ +48.8 +$ +— +Impairment of unproved properties +45.7 +0.5 +1.0 +Amortization of individually insignificant unproved properties +4.4 +3.2 +4.0 +Other +0.8 +— +— +Total impairment of crude oil and natural gas properties +$ +163.5 +$ +52.5 +$ +5.0 +Impairment of proved properties . In 2014, we recognized an impairment charge of $112.6 million to write-down certain capitalized well costs on our Utica Shale proved producing properties. The impairment charge represented the amount by which the carrying value of the Utica Shale proved producing properties exceeded the estimated fair value due to the current low commodity prices, large natural gas price differentials in the Appalachian Basin and changes in our Utica Shale drilling plans. The estimated fair value was determined based on estimated future discounted net cash flows, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. A significant decrease in future expected crude oil and natural gas prices could result in further impairments of these properties.The impairment charge was included in the consolidated statements of operations line item impairment of crude oil and natural gas properties. +In 2013, we recognized an impairment charge of approximately $48.8 million related to all of our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties located in West Virginia and Pennsylvania previously owned directly by us, as well as through our proportionate share of PDCM. The impairment charge represented the excess of the carrying value of the assets over the estimated fair value, less the cost to sell. The fair value of the assets was determined based upon estimated future cash flows from unrelated third-party bids, a Level 3 input. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the sale of these properties. +Impairment of unproved properties . In 2014, we also recognized an impairment charge of $45.7 million to write-down certain capitalized leasehold costs on our Utica Shale unproved properties. The impairment was due to the current low commodity prices, large natural gas price differentials in the Appalachian Basin and changes in our Utica Shale drilling plans. The $0.5 million decrease in 2013 compared to 2012 is +44 +primarily related to two significant leases that were written off in 2012 in the Wattenberg Field for $1.0 million compared to a single lease in non-Utica Ohio acreage written off in 2013 for $0.5 million. +General and Administrative Expense +General and administrative expense increased $55.9 million , or 93.2% , in 2014 compared to 2013. The increase was mainly attributable to $40.3 million recorded in 2014 in connection with settlement of certain partnership-related class action litigation and litigation arising from bankruptcy proceedings of certain affiliated partnerships. Additional increases were an $8.8 million increase in payroll and employee benefits, of which $3.9 million was related to stock-based compensation, and a $4.6 million increase in legal fees, primarily related to the aforementioned partnership-related class action litigation, consulting and other professional services. +General and administrative expense increased $5.1 million , or 9.4% , in 2013 compared to 2012. The increase was primarily due to a $4.9 million increase in payroll, employee benefits and stock-based compensation and a $1.5 million increase in other general and administrative expenses. These increases were offset in part by a decrease in professional and consulting fees of $1.3 million. +Depreciation, Depletion and Amortization +Crude oil and natural gas properties. DD&A expense related to crude oil and natural gas properties is directly related to proved reserves and production volumes. DD&A expense related to crude oil and natural gas properties was $188.5 million in 2014 compared to $111.6 million in 2013 . The increase in 2014 compared to 2013 was comprised of $48.9 million due to higher production and $28.0 million due to a higher weighted-average DD&A expense rate. +The following table presents our DD&A expense rates for crude oil and natural gas properties: +Year Ended December 31, +Operating Region/Area +2014 +2013 +2012 +(per Boe) +Wattenberg Field +$ +19.26 +$ +17.68 +$ +18.20 +Utica Shale +31.19 +24.87 +— +Other +— +2.66 +12.50 +Total weighted-average +20.28 +17.05 +17.74 +The decrease in the Wattenberg Field DD&A rate in 2013 was the result of the property acquisition costs of the Merit Acquisition being depleted over our entire proved reserves, whereas the majority of our DD&A expense is depleted over our proved developed reserves. The increase in the Utica Shale DD&A expense rate in 2014 compared to 2013 was mainly the result of depleting the entire capitalized well costs of a Utica Shale horizontal well that experienced a mechanical failure during the year. +Non-crude oil and natural gas properties. Depreciation expense for non-crude oil and natural gas properties was $4.1 million for 2014 compared to $4.0 million for 2013 and $4.8 million for 2012 . +Accretion of Asset Retirement Obligations +Accretion of asset retirement obligations ("ARO") for 2014 decreased by $1.2 million , or 25.2% , compared to 2013 . The decrease in 2014 is primarily attributable to the sale of our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties in 2013. Accretion of ARO for 2013 increased by $0.9 million , or 24.4% , compared to 2012. The increase in 2013 is primarily attributable to the properties acquired in the Merit Acquisition in 2012. +Gain (Loss) on Sale of Properties and Equipment +The loss on sale of properties and equipment of $0.5 million in 2014 primarily relates to the sale of certain affiliate partnership wells and various drilling equipment. The gain on sale of properties and equipment of $2.0 million in 2013 primarily relates to the sale of our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties. The gain on sale of properties and equipment in 2012 was not material. +Interest Expense +Interest expense decreased by approximately $2.3 million in 2014 compared to 2013 . The decrease is primarily comprised of a $1.8 million decrease attributable to an increase in the interest expense capitalized in 2014. +Interest expense increased by approximately $2.6 million in 2013 compared to 2012 . The increase is primarily related to $39.6 million of interest expense resulting from the issuance of $500 million of 7.75% senior notes due 2022 in October 2012. Partially offsetting this increase +45 +were decreases of $31.1 million related to the November 2012 redemption of previously-outstanding 12% senior notes due 2018 and $5.3 million as a result of lower average borrowings on our revolving credit facility during 2013 as compared to 2012. +Interest costs capitalized in 2014 , 2013 and 2012 were $3.5 million , $1.7 million and $0.9 million , respectively. +Loss on Extinguishment of Debt +The $23.3 million loss on extinguishment of debt in 2012 related to the redemption of the previously-outstanding 12% senior notes due 2018 in October 2012. The pre-tax loss consisted of an $18.9 million make-whole premium and the write-off of both unamortized debt discount of $1.5 million and unamortized debt issuance costs of $2.9 million . +Provision for Income Taxes +For 2014, the effective tax rate (the "rate") of 39.5% on income from continuing operations differs from the statutory tax rate of 35% primarily due to state income taxes. For 2013, the rate of 36.0% on loss from continuing operations differs from the statutory tax rate primarily due to state income taxes and nondeductible executive compensation, partially offset by the percentage depletion deduction. The 2012 rate of 36.9% on loss from continuing operations differs from the statutory tax rate primarily due to the percentage depletion deduction. See Note 7, Income Taxes , to our consolidated financial statements included elsewhere in this report for our rate reconciliation for each of the years in the three-year period ended December 31, 2014 . +We are current with our income tax filings in all applicable state jurisdictions and are not currently under examination. We continue voluntary participation in the Internal Revenue Service’s (the "IRS") Compliance Assurance Program (the "CAP Program") for the 2014 and 2015 tax years. We have received a full acceptance “no change” notice from the IRS for our filed 2013 federal tax return. +Discontinued Operations +Appalachian Marcellus Shale Assets. In October 2014 , we completed the sale of our entire 50% ownership interest in PDCM to an unrelated third-party for aggregate consideration, after our share of PDCM's debt repayment and other working capital adjustments, of approximately $192 million , comprised of approximately $153 million in net cash proceeds and a promissory note due in 2020 of approximately $39 million . The transaction included the buyer's assumption of our share of the firm transportation commitment related to the assets owned by PDCM, as well as our share of PDCM's natural gas hedging positions for the years 2014 through 2017. The divestiture resulted in a pre-tax gain of $76.3 million . The divestiture represents a strategic shift in our operations. Accordingly, our proportionate share of PDCM's Marcellus Shale results of operations have been separately reported as discontinued operations in the consolidated statements of operations for all periods presented. +Piceance Basin and NECO . In June 2013, we divested our Piceance Basin, NECO and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets for total consideration of approximately $177.6 million , with an additional $17.0 million paid to our non-affiliated investor partners in our affiliated partnerships. Following the sale, we do not have significant continuing involvement in the operations of, or cash flows from, the Piceance Basin and NECO oil and gas properties. Accordingly, the results of operations related to these assets have been reported as discontinued operations for all periods presented in the accompanying consolidated statements of operations included in this report. +For operating results related to our discontinued operations, see Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report. +Net Income (Loss)/Adjusted Net Income (Loss) +The changes in net income in 2014 compared to net loss in 2013 and 2012 are discussed above. These same reasons similarly impacted adjusted net income (loss), a non-U.S. GAAP financial measure, with the exception of the net change in fair value of unsettled derivatives, adjusted for taxes, of $193.1 million , $22.8 million and $10.6 million in 2014 , 2013 and 2012 , respectively. Adjusted net loss, a non-U.S. GAAP financial measure, was $37.7 million and $120.1 million in 2014 and 2012 , respectively, compared to an adjusted net income of $0.5 million in 2013 . See Reconciliation of Non-U.S. GAAP Financial Measures , below, for a more detailed discussion of this non-U.S. GAAP financial measure. +Financial Condition, Liquidity and Capital Resources +Historically, our primary sources of liquidity have been cash flows from operating activities, our revolving credit facility, proceeds raised in debt and equity market transactions and asset sales. In 2014 , our primary sources of liquidity were net cash flows from operating activities of $236.7 million , net cash proceeds received from the sale of our entire 50% ownership interest in PDCM of approximately $152.8 million , net borrowings under our revolving credit facility of $63.8 million and the remaining proceeds from the August 2013 equity transaction. +Our primary source of cash flows from operating activities is the sale of crude oil, natural gas and NGLs. Fluctuations in our operating cash flows are substantially driven by commodity prices and changes in our production volumes. Commodity prices have historically been volatile and we manage this volatility through our use of derivatives. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the instrument. For instruments that mature in three years or less, our debt covenants restrict us from entering into hedges that would exceed 85% of our expected future production from total proved reserves for such related time period (proved developed producing, proved developed non-producing and proved undeveloped). For instruments that mature later than three years, but no +46 +more than our designated maximum maturity, our debt covenants limit us from entering into hedges that would exceed 85% of our expected future production from proved developed producing properties during that time period. In addition, we may not hedge the maximum amounts permitted under our covenants. Therefore, we may still have significant fluctuations in our cash flows from operating activities due to the remaining non-hedged portion of our future production. Given the depressed commodity prices entering 2015 relative to our 2015 hedge prices, we expect that positive net settlements on our derivative positions will be a significant positive component of our 2015 cash flows from operations. +Our working capital fluctuates for various reasons, including, but not limited to, changes in the fair value of our commodity derivative instruments and changes in our cash and cash equivalents due to our practice of utilizing excess cash to reduce the outstanding borrowings under our revolving credit facility. At December 31, 2014 , we had a working capital surplus of $30.3 million compared to a surplus of $112.4 million at December 31, 2013 . The reduction in working capital is due to our utilization of the 2013 year-end cash balance to fund our 2014 capital program and an increase in current deferred tax liability, partially offset by a significant increase in the fair value of unsettled derivatives. +We ended 2014 with cash and cash equivalents of $16.1 million and availability under our revolving credit facility of $382.3 million , for a total liquidity position of $398.4 million , compared to $647.0 million at December 31, 2013 . The decrease in liquidity of $248.6 million , or 38.4% , was primarily attributable to capital expenditures of $628.6 million during 2014 , offset in part by cash flows provided by operating activities of $236.7 million and $154.5 million received from the sale of our entire 50% ownership interest in PDCM and other properties and equipment. In addition to our currently elected commitment of $450 million, we have an additional $250 million of borrowing base availability under our revolving credit facility, subject to certain terms and conditions of the agreement. Our forecast estimates our adjusted cash flows from operations will range from $350 million to $375 million in 2015, based on estimated NYMEX crude oil and natural gas prices of $51.72 per barrel and $2.86 per Mcf, respectively, before the effects of differentials or hedges. Due to the derivative hedges in place as of December 31, 2014, a $10 per barrel change in the price of crude oil would change our estimated adjusted cash flows from operations by approximately $20 million to $25 million. Based on our current commodity mix and hedge position, we estimate that a decline in the price of natural gas will not have a material impact on our adjusted cash flows from operations in 2015. With our current derivative position, liquidity position and expected cash flows from operations, we believe that we have sufficient capital to fund our planned drilling operations in 2015 . +In recent periods, we have been able to access borrowings under our revolving credit facility and to obtain proceeds from the issuance of debt and equity securities. We cannot, however, assure this will continue to be the case in the future. In light of recent weakened commodity prices, we continue to monitor market conditions and their potential impact on each of our revolving credit facility lenders, many of which are counterparties in our derivative transactions. Our revolving credit facility borrowing base is subject to a redetermination each May and November, based upon a quantification of our proved reserves at each June 30 and December 31, respectively. In September 2014 , the semi-annual redetermination of our revolving credit facility's borrowing base was completed, resulting in an increase in the borrowing base from $450 million to $700 million . However, we have elected to maintain the aggregate commitment at $450 million . We had $56.0 million outstanding under our revolving credit facility as of December 31, 2014 . Our next scheduled redetermination is in May 2015, and recent declines in commodity prices increase the risk of a reduction in our borrowing base. While we have added and expect to continue to add producing reserves through our drilling operations, these reserve additions could be offset by other factors including, among other things, a prolonged decrease in commodity prices. +In January 2012, we filed an automatic shelf registration statement on Form S-3 with the SEC, pursuant to which we sold 5.2 million shares of our common stock in August 2013 in an underwritten public offering at a price to us of $53.37 per share. That registration statement has since expired, and we intend to file a new automatic shelf registration on Form S-3 with the SEC in the first half of 2015. +Our revolving credit facility contains financial maintenance covenants. The covenants require that we maintain: (i) total debt of less than 4.25 times earnings before interest, taxes, depreciation, depletion and amortization, change in fair value of unsettled derivatives, exploration expense, gains (losses) on sales of assets and other non-cash, extraordinary or non-recurring gains (losses) ("EBITDAX") and (ii) an adjusted current ratio of at least 1.0 to 1.0. Our adjusted current ratio is adjusted by eliminating the impact on our current assets and liabilities of recording the fair value of crude oil and natural gas derivative instruments. Additionally, available borrowings under our revolving credit facility are added to the current asset calculation and the current portion of our revolving credit facility debt is eliminated from the current liabilities calculation. At December 31, 2014 , we were in compliance with all debt covenants with a 2.1 times debt to EBITDAX ratio and a 1.7 to 1.0 current ratio. We expect to remain in compliance throughout the next year, taking into account the current pricing environment. +The indenture governing our 7.75% senior notes due 2022 contains customary restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (a) incur additional debt, (b) make certain investments or pay dividends or distributions on our capital stock or purchase, redeem or retire capital stock, (c) sell assets, including capital stock of our restricted subsidiaries, (d) restrict the payment of dividends or other payments by restricted subsidiaries to us, (e) create liens that secure debt, (f) enter into transactions with affiliates and (g) merge or consolidate with another company. At December 31, 2014 , we were in compliance with all covenants and expect to remain in compliance throughout the next year. +The conversion rights on our Convertible Notes could be triggered prior to the maturity date. We have initially elected a net-settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the Convertible Notes in cash and to settle the excess conversion value in shares, as well as cash in lieu of fractional shares. In the event that a holder elects to convert its note, we expect to fund the cash settlement of any such conversion from working capital and/or borrowings under our revolving credit facility. We expect to utilize the net-settlement method to satisfy our conversion obligation upon the maturity of the Convertible Notes in May 2016. The conversion right is not expected to have a material impact on our financial position. The Convertible Notes were not convertible at the option of holders as of December 31, 2014 . +See Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk , for our discussion of credit risk. +47 +Cash Flows +Operating Activities. Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes, net settlements from our derivative positions, operating costs and general and administrative expenses. Cash flows provided by operating activities increased in 2014 compared to 2013 . The $77.5 million increase was mainly attributable to the increase in crude oil, natural gas and NGLs sales of $130.6 million and the decrease in changes in assets and liabilities of $35.1 million related to the timing of cash payments and receipts. These increases were offset in part by increases in general and administrative expense of $55.9 million , production costs of $15.8 million, net of prepaid well cost write-offs of $2.9 million, and the decrease in net settlements on derivative positions of $15.1 million . Cash flows provided by operating activities decreased in 2013 compared to 2012. The $15.6 million decrease was mainly attributable to changes in assets and liabilities of $59.4 million related to the timing of cash payments and receipts, the decrease in net settlements on derivative positions of $36.5 million and increases in production costs, net of inventory adjustments and prepaid well cost write-offs, of $26.2 million, general and administrative expense of $5.2 million and interest expense of $3.6 million. The decrease was offset in part by the increase in crude oil, natural gas and NGLs sales of $121.0 million. The key components for the changes in our cash flows provided by operating activities are described in more detail in Results of Operations above. +Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased by $42.4 million in 2014 and $43.9 million in 2013 when compared to the respective prior years. These changes were primarily due to the same factors mentioned above for changes in cash flows provided by operating activities, without regard to timing of cash payments and/or receipts of our assets and liabilities of $13.5 million and $48.6 million in 2014 and 2013 , respectively. +Adjusted EBITDA, a non-U.S. GAAP financial measure, increased by $120.0 million in 2014 from 2013 , primarily due to a $130.6 million increase in crude oil, natural gas and NGLs sales and a $72.3 million increase in contribution margins related to divested crude oil and natural gas assets, offset in part by a $55.9 million increase in general and administrative expense, a $18.7 million increase in production costs and a $12.1 million decrease in net settlements on derivatives. Adjusted EBITDA increased by $44.1 million in 2013 from 2012, primarily due to a $112.8 million increase in crude oil, natural gas and NGLs sales, offset in part by a $32.4 million decrease in net settlements on derivatives, a $26.1 million decrease in contribution margins related to divested crude oil and natural gas assets and a $15.5 million increase in production costs. +See Reconciliation of Non-U.S. GAAP Financial Measures , below, for a more detailed discussion of non-U.S. GAAP financial measures. +Investing Activities. Because crude oil and natural gas production from a well declines rapidly in the first few years of production, we need to continue to commit significant amounts of capital in order to maintain and grow our production and replace our reserves. If capital is not available or is constrained in the future, we will be limited to our cash flows from operations and liquidity under our revolving credit facility as the sources for funding our capital expenditures. We would not be able to maintain our current level of crude oil, natural gas and NGLs production and cash flows from operating activities if capital markets were unavailable, commodity prices were to become depressed and/or the borrowing base under our revolving credit facility was significantly reduced. The occurrence of such an event may result in our election to defer a substantial portion of our planned capital expenditures and could have a material negative impact on our operations in the future. +Cash flows from investing activities primarily consist of the acquisition, exploration and development of crude oil and natural gas properties, net of dispositions of crude oil and natural gas properties. In 2014 , our drilling program consisted of five drilling rigs operating in the horizontal Niobrara and Codell plays in our Wattenberg Field and one drilling rig in the Utica Shale. See Part I, Properties - Drilling Activities , for additional details on our drilling activities. Net cash used in investing activities of $474.1 million during 2014 was primarily related to cash utilized for our drilling operations of $628.6 million , offset in part by the $152.8 million net cash proceeds received from the sale of our entire 50% ownership interest in PDCM. Net cash used in investing activities of $217.1 million during 2013 was primarily related to cash utilized for our drilling operations of $394.9 million, offset in part by the $187.5 million received from the sale of properties and equipment, including acquisition adjustments. In 2013, we also paid approximately $9.7 million for the acquisition of crude oil and natural gas properties. In 2012, net cash used in investing activities was primarily related to the $304.6 million expended in June 2012 for the Merit Acquisition and $347.7 million for our drilling operations and acquisition of Utica Shale acreage, offset in part by $189.2 million received from the divestiture of our Permian assets in February 2012 and $28.9 million received related to title defects discovered from PDCM's Seneca-Upshur acquisition in October 2011, of which $14.5 million represented our share. +Financing Activities. Net cash from financing activities in 2014 were primarily comprised of net borrowings under our revolving credit facility of $63.8 million to execute our capital budget. Net cash from financing activities in 2013 was primarily related to the $275.8 million received from the issuance of our common stock in August 2013, partially offset by net payments of approximately $23.3 million to pay down amounts borrowed under revolving credit facilities. Net cash from financing activities in 2012 includes gross proceeds of $500 million from our October 2012 issuance of the 7.75% senior notes due 2022 and $164.5 million from our May 2012 sale of common stock. The net proceeds from the issuance of the 7.75% senior notes due 2022 were used to fund the redemption of our previously-outstanding 12% senior notes due 2018 for a total redemption price of approximately $222 million and to repay a portion of amounts outstanding under our revolving credit facility. The proceeds from the sale of common stock in May 2012 were used to finance a portion of the Merit Acquisition. +48 +Contractual Obligations and Contingent Commitments +The following table presents our contractual obligations and contingent commitments as of December 31, 2014 : +Payments due by period +Less than +1-3 +3-5 +More than +Contractual Obligations and Contingent Commitments +Total +1 year +years +years +5 years +(in millions) +Long-term liabilities reflected on the consolidated balance sheet (1) +Long-term debt (2) +$ +671.0 +$ +— +$ +115.0 +$ +56.0 +$ +500.0 +Derivative contracts (3) +0.8 +0.6 +0.2 +— +— +Production tax liability +47.7 +21.3 +26.4 +— +— +Asset retirement obligations +73.9 +1.9 +8.5 +9.9 +53.6 +Other liabilities (4) +3.6 +0.3 +0.5 +0.7 +2.1 +797.0 +24.1 +150.6 +66.6 +555.7 +Commitments, contingencies and other arrangements (5) +Interest on long-term debt (6) +319.1 +46.0 +86.0 +78.9 +108.2 +Operating leases +12.8 +2.5 +4.4 +3.8 +2.1 +Firm transportation and processing agreements (7) +95.9 +14.5 +34.8 +32.6 +14.0 +427.8 +63.0 +125.2 +115.3 +124.3 +Total +$ +1,224.8 +$ +87.1 +$ +275.8 +$ +181.9 +$ +680.0 +__________ +(1) +Table does not include deferred income tax liability to taxing authorities of $125.7 million , due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. +(2) +Amount presented does not agree with the consolidated balance sheets in that it excludes $6.1 million in unamortized debt discount. See Note 8, Long-Term Debt, to our consolidated financial statements included elsewhere in this report. +(3) +Represents our gross liability related to the fair value of derivative positions. +(4) +Includes deferred compensation to former executive officers and deferred payments related to firm transportation agreements. +(5) +Table does not include an undrawn $11.7 million irrevocable standby letter of credit pending issuance to a transportation service provider. See Note 8, Long-Term Debt, to our consolidated financial statements included elsewhere in this report. Additionally, the table does not include the annual repurchase obligations to investing partners or termination benefits related to employment agreements with our executive officers, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. See Note 11, Commitments and Contingencies - Partnership Repurchase Provision; Employment Agreements with Executive Officers, to our consolidated financial statements included elsewhere in this report. +(6) +Amounts presented include $301.9 million to the holders of our 7.75% senior notes due 2022 and $5.1 million payable to the holders of our 3.25% convertible senior notes due 2016. Amounts also include $12.1 million payable to the participating banks in our revolving credit facility, of which interest of $4.9 million is related to unutilized commitments at a rate of .38% per annum, $7.1 million related to the outstanding borrowings on our revolving credit facility of $56.0 million and $0.1 million related to our undrawn letters of credit. +(7) +Represents our gross commitment. See Note 11, Commitments and Contingencies - Firm Transportation, Processing and Sales Agreements, to our consolidated financial statements included elsewhere in this report. +As the managing general partner of affiliated partnerships, we have liability for potential casualty losses in excess of the partnership assets and insurance. We believe that the casualty insurance coverage we and our subcontractors carry is adequate to meet this potential liability. +For information regarding our legal proceedings, see Note 11, Commitments and Contingencies – Litigation , to our consolidated financial statements included elsewhere in this report. From time to time, we are a party to various other legal proceedings in the ordinary course of business. We are not currently a party to any litigation that we believe would have a materially adverse effect on our business, financial condition, results of operations or liquidity. +49 +Critical Accounting Policies and Estimates +We have identified the following policies as critical to business operations and the understanding of our results of operations. This is not a comprehensive list of all of the accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by U.S. GAAP, with no need for our judgment in the application. There are also areas in which our judgment in selecting available alternatives would not produce a materially different result. However, certain of our accounting policies are particularly important to the portrayal of our financial position and results of operations and we may use significant judgment in the application. As a result, they are subject to an inherent degree of uncertainty. In applying those policies, we use our judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on historical experience, observation of trends in the industry and information available from other outside sources, as appropriate. For a more detailed discussion on the application of these and other accounting policies, see Note 2, Summary of Significant Accounting Policies , to our consolidated financial statements included elsewhere in this report. +Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. +Annually, we engage independent petroleum engineers to prepare reserve and economic evaluations of all our properties on a well-by-well basis as of December 31. We adjust our crude oil and natural gas reserves for major acquisitions, new drilling and divestitures during the year as needed. The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. Although every reasonable effort is made to ensure that reserve estimates reported represent our most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect our DD&A expense, a change in our estimated reserves could have an effect on our net income. +Exploration costs, including geological and geophysical expenses, and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but are charged to expense if the well is determined to be nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as the well has found a sufficient quantity of reserves to justify completion as a producing well and we are making sufficient progress assessing our reserves and economic and operating viability. If an in-progress exploratory well is found to be unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the well is classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time when we are able to make a final determination of a well’s productive status, the well is removed from the suspended well status and the proper accounting treatment is applied. +The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired or amortized. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed, and any impairment in value is charged to impairment of crude oil and natural gas properties. The amount of impairment recognized on unproved properties which are not individually significant is determined by amortizing the costs of such properties within appropriate fields based on our historical experience, acquisition dates and average lease terms, with the amortization recognized in impairment of crude oil and natural gas properties. The valuation of unproved properties is subjective and requires us to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values. +We assess our crude oil and natural gas properties for possible impairment upon a triggering event by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. Any impairment in value is charged to impairment of crude oil and natural gas properties. The estimates of future prices may differ from current market prices of crude oil and natural gas. Any downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs could result in a triggering event, and therefore, a reduction in undiscounted future net cash flows and an impairment of our crude oil and natural gas properties. Although our cash flow estimates are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. +Crude Oil, Natural Gas and NGLs Sales Revenue Recognition . Crude oil, natural gas and NGLs sales are recognized when production is sold to a purchaser at a determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes and prices received. We receive payment for sales from one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded two months later. Historically, these differences have been immaterial. +Fair Value of Financial Instruments. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is +50 +based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. +Derivative Financial Instruments. We measure the fair value of our derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. +We validate our fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. While we believe our valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value. +Net settlements on our derivative instruments are initially recorded to accounts receivable or payable, as applicable, and may not be received from or paid to counterparties to our derivative contracts within the same accounting period. Such settlements typically occur the month following the maturity of the derivative instrument. We have evaluated the credit risk of the counterparties holding our derivative assets, which are primarily financial institutions who are also major lenders in our revolving credit facility, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our counterparties on the fair value of our derivative instruments is not significant. +Deferred Income Tax Asset Valuation Allowance. Deferred income tax assets are recognized for deductible temporary differences, net operating loss carry-forwards and credit carry-forwards if it is more likely than not that the tax benefits will be realized. To the extent a deferred tax asset is not expected to be realized under the preceding criteria, we establish a valuation allowance. The factors which we consider in assessing whether we will realize the value of deferred income tax assets involve judgments and estimates of both amount and timing, which could differ from actual results, achieved in future periods. The judgments used in applying these policies are based on our evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results may differ from those estimates. +Accounting for Acquisitions Using Purchase Accounting. We utilize the purchase method to account for acquisitions. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. The purchase price allocations are based on appraisals, discounted cash flows, quoted market prices and estimates by management. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. +In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped, unproved crude oil and natural gas properties and other non-crude oil and natural gas properties. To estimate the fair values of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. +We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. +51 +Recent Accounting Standards +See Note 2, Summary of Significant Accounting Policies - Recent Accounting Standards , to our consolidated financial statements included elsewhere in this report. +Reconciliation of Non-U.S. GAAP Financial Measures +Adjusted cash flows from operations. We define adjusted cash flows from operations as the cash flows earned or incurred from operating activities, without regard to changes in operating assets and liabilities. We believe it is important to consider adjusted cash flows from operations, as well as cash flows from operations, as we believe it often provides more transparency into what drives the changes in our operating trends, such as production, prices, operating costs and related operational factors, without regard to whether the related asset or liability was received or paid during the same period. We also use this measure because the timing of cash received from our assets, cash paid to obtain an asset or payment of our obligations has been only a timing issue from one period to the next as we have not had accounts receivable collection problems, nor been unable to purchase assets or pay our obligations. See the Consolidated Statements of Cash Flows included elsewhere in this report. +Adjusted net income (loss). We define adjusted net income (loss) as net income (loss), plus loss on commodity derivatives, less gain on commodity derivatives and net settlements on commodity derivatives, each adjusted for tax effect. We believe it is important to consider adjusted net income (loss), as well as net income (loss). We believe this measure often provides more transparency into our operating trends, such as production, prices, operating costs, net settlements from derivatives and related factors, without regard to changes in our net income (loss) from our mark-to-market adjustments resulting from net changes in the fair value of unsettled derivatives. +Adjusted EBITDA. We define adjusted EBITDA as net income (loss), plus loss on commodity derivatives, interest expense, net of interest income, income taxes, impairment of crude oil and natural gas properties, depreciation, depletion and amortization, accretion of asset retirement obligations and loss on debt extinguishment, less gain on commodity derivatives and net settlements on commodity derivatives. Adjusted EBITDA is not a measure of financial performance or liquidity under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss), nor as an indicator of cash flows reported in accordance with U.S. GAAP. Adjusted EBITDA includes certain non-cash costs incurred by us and does not take into account changes in operating assets and liabilities. Other companies in our industry may calculate adjusted EBITDA differently than we do, limiting its usefulness as a comparative measure. We believe adjusted EBITDA is relevant because it is a measure of our operational and financial performance, as well as a measure of our liquidity, and is used by our management, investors, commercial banks, research analysts and others to analyze such things as: +• +operating performance and return on capital as compared to our peers; +• +financial performance of our assets and our valuation without regard to financing methods, capital structure or historical cost basis; +• +ability to generate sufficient cash to service our debt obligations; and +• +viability of acquisition opportunities and capital expenditure projects, including the related rate of return. +PV-10 . We define PV-10 as the estimated present value of the future net cash flows from our proved reserves before income taxes, discounted using a 10% discount rate. We believe that PV-10 provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. We believe that PV-10 is relevant and useful for evaluating the relative monetary significance of our reserves. Professional analysts and sophisticated investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies' reserves. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable in evaluating us and our reserves. PV-10 is not intended to represent the current market value of our estimated reserves. +52 +The following table presents a reconciliation of our non-U.S. GAAP financial measures to its most comparable U.S. GAAP measure: +Year Ended December 31, +2014 +2013 +2012 +(in millions) +Adjusted cash flows from operations: +Adjusted cash flows from operations +$ +250.2 +$ +207.8 +$ +163.9 +Changes in assets and liabilities +(13.5 +) +(48.6 +) +10.8 +Net cash from operating activities +$ +236.7 +$ +159.2 +$ +174.7 +Adjusted net income (loss): +Adjusted net income (loss) +$ +(37.7 +) +$ +0.5 +$ +(120.1 +) +Gain (loss) on commodity derivative instruments +309.3 +(23.7 +) +32.4 +Net settlements on commodity derivative instruments +2.0 +(13.1 +) +(49.5 +) +Tax effect of above adjustments +(118.2 +) +14.0 +6.5 +Net income (loss) +$ +155.4 +$ +(22.3 +) +$ +(130.7 +) +Adjusted EBITDA to net income (loss): +Adjusted EBITDA +$ +361.0 +$ +241.0 +$ +196.9 +Gain (loss) on commodity derivative instruments +309.3 +(23.7 +) +32.4 +Net settlements on commodity derivative instruments +2.0 +(13.1 +) +(49.5 +) +Interest expense, net +(48.6 +) +(51.4 +) +(48.3 +) +Income tax provision +(99.2 +) +12.6 +80.2 +Impairment of crude oil and natural gas properties +(164.0 +) +(53.4 +) +(168.2 +) +Depreciation, depletion and amortization +(201.7 +) +(129.5 +) +(146.9 +) +Accretion of asset retirement obligations +(3.4 +) +(4.8 +) +(4.0 +) +Loss on extinguishment of debt +— +— +(23.3 +) +Net income (loss) +$ +155.4 +$ +(22.3 +) +$ +(130.7 +) +Adjusted EBITDA to net cash from operating activities: +Adjusted EBITDA +$ +361.0 +$ +241.0 +$ +196.9 +Interest expense, net +(48.6 +) +(51.4 +) +(48.3 +) +Exploratory dry hole costs +— +— +15.3 +Stock-based compensation +17.5 +12.9 +8.5 +Amortization of debt discount and issuance costs +6.9 +6.8 +7.9 +(Gain) loss on sale of properties and equipment +(76.0 +) +3.7 +(24.3 +) +Other +(10.6 +) +(5.2 +) +7.9 +Changes in assets and liabilities +(13.5 +) +(48.6 +) +10.8 +Net cash from operating activities +$ +236.7 +$ +159.2 +$ +174.7 +PV-10: +PV-10 +$ +3,450.1 +$ +2,703.9 +$ +1,708.9 +Present value of estimated future income tax discounted at 10% +(1,143.6 +) +(921.7 +) +(540.4 +) +Standardized measure of discounted future net cash flows +$ +2,306.5 +$ +1,782.2 +$ +1,168.5 +Amounts above include results from continuing and discontinued operations. +53 +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK +Market-Sensitive Instruments and Risk Management +We are exposed to market risks associated with interest rate risks, commodity price risk and credit risk. We have established risk management processes to monitor and manage these market risks. +Interest Rate Risk +Changes in interest rates affect the amount of interest we earn on our interest bearing cash, cash equivalents and restricted cash accounts and the interest we pay on borrowings under our revolving credit facility. Our 7.75% senior notes due 2022 and 3.25% convertible senior notes due 2016 have fixed rates and, therefore, near-term changes in interest rates do not expose us to risk of earnings or cash flow loss with respect to these instruments; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt. +As of December 31, 2014 , our interest-bearing deposit accounts included money market accounts, certificates of deposit and checking and savings accounts with various banks. The amount of our interest-bearing cash, cash equivalents and restricted cash as of December 31, 2014 was $0.7 million, with a weighted-average interest rate of 0.1%. Based on a sensitivity analysis of our interest bearing deposits as of December 31, 2014 , we estimate that if market interest rates would have increased 1% in 2014 , the impact of the interest income would have been immaterial. +As of December 31, 2014 , excluding the $11.7 million irrevocable standby letter of credit, we had $56.0 million outstanding on our revolving credit facility. We estimate that if market interest rates would have increased or decreased by 1%, our 2014 interest expense would have changed by approximately $0.6 million. +Commodity Price Risk +We are exposed to the potential risk of loss from adverse changes in the market price of crude oil, natural gas and NGLs. Pursuant to established policies and procedures, we manage a portion of the risks associated with these market fluctuations using derivative instruments. These instruments help us predict with greater certainty the effective crude oil and natural gas prices we will receive for our hedged production. We believe that our derivative policies and procedures are effective in achieving our risk management objectives. +The following table presents our derivative positions related to crude oil and natural gas sales in effect as of December 31, 2014 : +Collars +Fixed-Price Swaps +Basis Protection Swaps +Commodity/ Index/ +Maturity Period +Quantity +(Gas - +BBtu (1) +Oil - MBbls) +Weighted-Average +Contract Price +Quantity +(Gas - +BBtu (1) +Oil - MBbls) +Weighted- +Average +Contract +Price +Quantity +(BBtu) (1) +Weighted- +Average +Contract +Price +Fair Value +December 31, +2014 (2) +(in millions) +Floors +Ceilings +Natural Gas +NYMEX +2015 +7,340.0 +$ +3.93 +$ +4.31 +12,415.0 +$ +4.04 +9,600.0 +$ +(0.24 +) +$ +19.1 +2016 +7,820.0 +3.88 +4.24 +19,680.0 +3.98 +— +— +14.0 +2017 +5,130.0 +3.91 +4.34 +10,100.0 +3.99 +— +— +4.0 +CIG +2015 +— +— +— +2,730.0 +4.01 +— +— +3.4 +Total Natural Gas +20,290.0 +44,925.0 +9,600.0 +$ +40.5 +Crude Oil +NYMEX +2015 +686.0 +$ +85.63 +$ +96.86 +4,514.0 +$ +89.12 +— +$ +— +$ +164.4 +2016 +1,740.0 +77.59 +97.55 +2,400.0 +90.37 +— +— +94.6 +Total Crude Oil +2,426.0 +6,914.0 +— +259.0 +Total Natural Gas and Crude Oil +$ +299.5 +_____________ +(1) +A standard unit of measurement for natural gas (one BBtu equals one MMcf). +(2) +Approximately 20.8% of the fair value of our derivative assets and none of our derivative liabilities were measured using significant unobservable inputs (Level 3). See Note 3, Fair Value Measurements, to the consolidated financial statements included elsewhere in this report. +54 +The following table presents annual average NYMEX, CIG and TETCO M-2 closing prices for crude oil and natural gas for the years ended December 31, 2014 and 2013 , as well as average sales prices we realized for our crude oil, natural gas and NGLs production: +Year Ended December 31, +2014 +2013 +Average Index Closing Price: +Crude oil (per Bbl) +NYMEX +$ +92.91 +$ +97.97 +Natural gas (per MMBtu) +NYMEX +$ +4.42 +$ +3.65 +CIG +4.17 +3.45 +TETCO M-2 (1) +3.35 +3.50 +Average Sales Price Realized: +Excluding net settlements on derivatives +Crude oil (per Bbl) +$ +80.67 +$ +89.92 +Natural gas (per Mcf) +3.87 +3.29 +NGLs (per Bbl) +27.39 +27.97 +_____________ +(1) TETCO M-2 is an index price upon which a majority of our natural gas produced in the Utica Shale is sold. +Based on a sensitivity analysis as of December 31, 2014 , we estimate that a 10% increase in crude oil and natural gas prices, inclusive of basis, over the entire period for which we have derivatives in place, would have resulted in a decrease in fair value of the derivatives of $73.4 million; whereas a 10% decrease in prices would have resulted in an increase in fair value of $73.9 million. +See Note 3, Fair Value of Financial Instruments , and Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this report for a summary of our open derivative positions, as well as a discussion of how we determine the fair value of and account for our derivative contracts. +Credit Risk +Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure and entering into transactions with high-quality counterparties. When exposed to significant credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. While we believe that our credit risk analysis and monitoring procedures are reasonable, no amount of analysis can assure performance by our counterparties. +Our Oil and Gas Exploration and Production segment's crude oil, natural gas and NGLs sales are concentrated with a few predominately large customers. This concentrates our credit risk exposure with a small number of large customers. Amounts due to our Gas Marketing segment are from a diverse group of entities, including major upstream and midstream energy companies, financial institutions and end-users in various industries. We monitor their creditworthiness through our credit committee, which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. To date, we have had no material counterparty default losses in either segment. +Our derivative financial instruments may expose us to the risk of nonperformance by the instrument's contract counterparty. We primarily use financial institutions which are lenders in our revolving credit facility as counterparties for our derivative financial instruments. We monitor the creditworthiness of our counterparties through our credit committee, which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. While we believe that our monitoring procedures are reasonable, no amount of analysis can assure performance by a financial institution. In addition, disruption in the credit markets, changes in commodity prices and other factors may have a significant adverse impact on a number of financial institutions. To date, we have had no material counterparty default losses from our derivative financial instruments; however, we cannot be sure such losses will not occur in the future. See Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this report for more detail on our derivative financial instruments. +Disclosure of Limitations +Because the information above includes only those exposures that existed at December 31, 2014 , it does not consider those exposures or positions which could arise after that date. As a result, our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, our commodity price risk management strategies at the time and interest rates and commodity prices at the time. +55 +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Index to Consolidated Financial Statements, Financial Statement Schedule and Supplemental Information +Financial Statements: +Report of Independent Registered Public Accounting Firm +57 +Consolidated Balance Sheets - December 31, 201 4 and 2013 +57 +Consolidated Statements of Operations - Years Ended December 31, 2 014, 2013 and 2012 +58 +Consolidated Statements of Cash Flows - Years Ended December 31, 201 4, 2013 and 2012 +59 +Consolidated Statements of Equity - Years Ended December 31, 201 4, 2013 and 2012 +60 +Notes to Consolidated Financial Statements +60 +Supplemental Information - Unaudited: +Crude Oil and Natural Gas Information +88 +Quarterly Financial Information +94 +Financial Statement Schedule: +Schedule II - Valuation and Qualifying Accounts +95 +56 +Report of Independent Registered Public Accounting Firm +To the Board of Directors and Shareholders of PDC Energy, Inc.: +In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of PDC Energy, Inc. and its subsidiaries at December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. +As discussed in Note 2 to the consolidated financial statements, the Company changed the manner in which it accounts for discontinued operations in 2014. +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ PricewaterhouseCoopers LLP +Pittsburgh, Pennsylvania +February 18, 2015 +PDC ENERGY, INC. +Consolidated Balance Sheets +(in thousands, except share and per share data) +As of December 31, +2014 +2013 +Assets +Current assets: +Cash and cash equivalents +$ +16,066 +$ +192,642 +Restricted cash +— +2,211 +Accounts receivable, net +131,204 +88,111 +Accounts receivable affiliates +512 +6,614 +Fair value of derivatives +187,495 +1,521 +Deferred income taxes +— +22,374 +Assets held for sale +— +7,661 +Prepaid expenses and other current assets +5,442 +4,679 +Total current assets +340,719 +325,813 +Properties and equipment, net +1,800,186 +1,480,986 +Assets held for sale +2,874 +182,136 +Fair value of derivatives +112,819 +4,503 +Other assets +83,990 +31,765 +Total Assets +$ +2,340,588 +$ +2,025,203 +Liabilities and Shareholders' Equity +Liabilities +Current liabilities: +Accounts payable +$ +130,321 +$ +101,688 +Accounts payable affiliates +— +41 +Production tax liability +21,314 +22,232 +Fair value of derivatives +570 +14,689 +Funds held for distribution +27,186 +31,040 +Accrued interest payable +9,109 +9,033 +Deferred income taxes +59,174 +— +Liabilities held for sale +— +12,069 +Other accrued expenses +62,717 +22,628 +Total current liabilities +310,391 +213,420 +Long-term debt +664,923 +604,990 +Deferred income taxes +125,693 +118,767 +Asset retirement obligation +71,992 +37,638 +Fair value of derivatives +197 +2,842 +Liabilities held for sale +— +55,915 +Other liabilities +30,033 +24,037 +Total liabilities +1,203,229 +1,057,609 +Commitments and contingent liabilities +Shareholders' equity +Preferred shares - par value $0.01 per share, 50,000,000 shares authorized, none issued +— +— +Common shares - par value $0.01 per share, 150,000,000 authorized, 35,927,985 and 35,675,656 issued as of December 31, 2014 and 2013, respectively +359 +357 +Additional paid-in capital +689,209 +674,211 +Retained earnings +448,702 +293,267 +Treasury shares - at cost, 21,643 and 5,508 as of December 31, 2014 and 2013, respectively +(911 +) +(241 +) +Total shareholders' equity +1,137,359 +967,594 +Total Liabilities and Shareholders' Equity +$ +2,340,588 +$ +2,025,203 +57 +PDC ENERGY, INC. +Consolidated Statements of Operations +(in thousands, except per share data) +Year Ended December 31, +2014 +2013 +2012 +Revenues +Crude oil, natural gas and NGLs sales +$ +471,413 +$ +340,795 +$ +227,990 +Sales from natural gas marketing +71,571 +69,787 +45,371 +Commodity price risk management gain (loss), net +310,304 +(23,919 +) +29,279 +Well operations, pipeline income and other +2,919 +6,002 +4,496 +Total revenues +856,207 +392,665 +307,136 +Costs, expenses and other +Production costs +83,624 +64,850 +49,383 +Cost of natural gas marketing +72,015 +70,084 +45,023 +Exploration expense +947 +6,334 +18,202 +Impairment of crude oil and natural gas properties +163,532 +52,509 +5,020 +General and administrative expense +115,859 +59,956 +54,817 +Depreciation, depletion and amortization +192,528 +115,624 +91,111 +Accretion of asset retirement obligations +3,415 +4,566 +3,670 +(Gain) loss on sale of properties and equipment +507 +2,022 +(183 +) +Total cost, expenses and other +632,427 +375,945 +267,043 +Income from operations +223,780 +16,720 +40,093 +Interest expense +(47,842 +) +(50,143 +) +(47,505 +) +Interest income +1,290 +460 +7 +Loss on extinguishment of debt +— +— +(23,283 +) +Income (loss) from continuing operations before income taxes +177,228 +(32,963 +) +(30,688 +) +Provision for income taxes +(69,967 +) +11,852 +11,333 +Income (loss) from continuing operations +107,261 +(21,111 +) +(19,355 +) +Income (loss) from discontinued operations, net of tax +48,174 +(1,190 +) +(111,357 +) +Net income (loss) +$ +155,435 +$ +(22,301 +) +$ +(130,712 +) +Earnings per share: +Basic +Income (loss) from continuing operations +$ +3.00 +$ +(0.65 +) +$ +(0.70 +) +Income (loss) from discontinued operations, net of tax +1.34 +(0.04 +) +(4.02 +) +Net income (loss) +$ +4.34 +$ +(0.69 +) +$ +(4.72 +) +Diluted +Income (loss) from continuing operations +$ +2.93 +$ +(0.65 +) +$ +(0.70 +) +Income (loss) from discontinued operations, net of tax +1.31 +(0.04 +) +(4.02 +) +Net income (loss) +$ +4.24 +$ +(0.69 +) +$ +(4.72 +) +Weighted-average common shares outstanding: +Basic +35,784 +32,426 +27,677 +Diluted +36,678 +32,426 +27,677 +See accompanying Notes to Consolidated Financial Statements +58 +PDC ENERGY, INC. +Consolidated Statements of Cash Flows +(in thousands) +Year Ended December 31, +2014 +2013 +2012 +Cash flows from operating activities: +Net income (loss) +$ +155,435 +$ +(22,301 +) +$ +(130,712 +) +Adjustments to net income (loss) to reconcile to net cash from operating activities: +Net change in fair value of unsettled derivatives +(311,281 +) +36,801 +17,134 +Depreciation, depletion and amortization +201,656 +129,518 +146,879 +Impairment of crude oil and natural gas properties +163,965 +53,438 +168,149 +Prepaid well costs write-offs +3,062 +74 +3,916 +Loss on extinguishment of debt +— +— +23,283 +Exploratory dry hole costs +— +— +15,347 +Accretion of asset retirement obligation +3,455 +4,747 +4,060 +Stock-based compensation +17,518 +12,880 +8,495 +Excess tax benefits from stock-based compensation +(1,999 +) +(2,489 +) +— +(Gain) loss from sale of properties and equipment +(75,972 +) +3,722 +(24,273 +) +Amortization of debt discount and issuance costs +6,938 +6,783 +7,864 +Deferred income taxes +88,474 +(15,883 +) +(80,379 +) +Other +(1,076 +) +460 +4,123 +Total adjustments to net income (loss) to reconcile to net cash from operating activities: +94,740 +230,051 +294,598 +Changes in assets and liabilities: +Accounts receivable +(34,598 +) +(41,509 +) +6,843 +Other assets +(3,296 +) +3,461 +(2,908 +) +Restricted cash +2,214 +(8 +) +8,859 +Production tax liability +3,358 +4,121 +2,499 +Accounts payable and accrued expenses +21,453 +(11,485 +) +(5,050 +) +Other liabilities +(2,617 +) +(3,165 +) +592 +Total changes in assets and liabilities +(13,486 +) +(48,585 +) +10,835 +Net cash from operating activities +236,689 +159,165 +174,721 +Cash flows from investing activities: +Capital expenditures +(628,592 +) +(394,948 +) +(347,729 +) +Acquisition of crude oil and natural gas properties, net of cash acquired +— +(9,658 +) +(312,223 +) +Proceeds from acquisition adjustments +— +7,579 +14,469 +Proceeds from sale of properties and equipment, net +154,457 +179,919 +193,544 +Net cash from investing activities +(474,135 +) +(217,108 +) +(451,939 +) +Cash flows from financing activities: +Proceeds from revolving credit facility +263,750 +260,250 +682,000 +Repayment of revolving credit facility +(200,000 +) +(283,500 +) +(839,750 +) +Proceeds from senior notes offering +— +— +500,000 +Redemption of senior notes +— +— +(221,840 +) +Payment of debt issuance costs +(88 +) +(2,352 +) +(11,969 +) +Proceeds from sale of common stock, net of issuance costs +— +275,847 +164,496 +Excess tax benefits from stock-based compensation +1,999 +2,489 +— +Purchase of treasury shares +(5,392 +) +(4,133 +) +(1,500 +) +Proceeds from exercise of stock options +— +128 +— +Net cash from financing activities +60,269 +248,729 +271,437 +Net change in cash and cash equivalents +(177,177 +) +190,786 +(5,781 +) +Cash and cash equivalents, beginning of year +193,243 +2,457 +8,238 +Cash and cash equivalents, end of year +$ +16,066 +$ +193,243 +$ +2,457 +Supplemental cash flow information: +Cash payments for (receipts from): +Interest, net of capitalized interest +$ +46,809 +$ +48,844 +$ +41,768 +Income taxes +1,800 +(3,014 +) +1,845 +Non-cash investing activities: +Change in accounts payable related to capital expenditures +39,667 +33,328 +288 +Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposal +33,250 +2,112 +11,967 +Change in accounts receivable related to sale of properties and equipment +— +808 +— +Change in other assets related to sale of properties and equipment +39,048 +3,350 +— +See Note 15, Acquisitions , for non-cash transactions related to our acquisitions +See accompanying Notes to Consolidated Financial Statements +59 +PDC ENERGY, INC. +Consolidated Statements of Equity +(in thousands, except share and per share data) +Year Ended December 31, +2014 +2013 +2012 +Common shares, issued: +Shares beginning of year +35,675,656 +30,294,224 +23,634,958 +Shares issued pursuant to sale of equity +— +5,175,000 +6,500,000 +Exercise of stock options +— +10,763 +— +Issuance of stock awards, net of forfeitures +253,032 +212,926 +173,737 +Retirement of treasury shares +(703 +) +(17,257 +) +(14,471 +) +Shares end of year +35,927,985 +35,675,656 +30,294,224 +Treasury shares: +Shares beginning of year +5,508 +5,059 +2,938 +Purchase of treasury shares +97,646 +84,642 +44,576 +Issuance of treasury shares +(83,208 +) +(67,334 +) +(28,587 +) +Retirement of treasury shares +(703 +) +(17,257 +) +(14,471 +) +Non-employee directors' deferred compensation plan +2,400 +398 +603 +Shares end of year +21,643 +5,508 +5,059 +Common shares outstanding +35,906,342 +35,670,148 +30,289,165 +Equity: +Shareholders' equity +Preferred shares, par value $0.01 per share: +Balance beginning and end of year +$ +— +$ +— +$ +— +Common shares, par value $0.01 per share: +Balance beginning of year +357 +303 +236 +Shares issued pursuant to sale of equity +— +52 +65 +Issuance of stock awards, net of forfeitures +2 +2 +2 +Balance end of year +359 +357 +303 +Additional paid-in capital: +Balance beginning of year +674,211 +387,494 +217,707 +Proceeds from sale of equity, net of issuance costs +— +275,795 +164,431 +Exercise of stock options +— +125 +— +Stock-based compensation expense +17,851 +12,402 +8,495 +Issuance of treasury shares +(4,817 +) +(3,270 +) +(955 +) +Retirement of treasury shares +(35 +) +(824 +) +(491 +) +Tax impact of stock-based compensation +1,999 +2,489 +(1,693 +) +Balance end of year +689,209 +674,211 +387,494 +Retained earnings: +Balance beginning of year +293,267 +315,568 +446,280 +Net income (loss) attributable to shareholders +155,435 +(22,301 +) +(130,712 +) +Balance end of year +448,702 +293,267 +315,568 +Treasury shares, at cost: +Balance beginning of year +(241 +) +(184 +) +(111 +) +Purchase of treasury shares +(5,392 +) +(4,133 +) +(1,500 +) +Issuance of treasury shares +4,817 +3,271 +955 +Retirement of treasury shares +35 +824 +491 +Non-employee directors' deferred compensation plan +(130 +) +(19 +) +(19 +) +Balance end of year +(911 +) +(241 +) +(184 +) +Total shareholders' equity +1,137,359 +967,594 +703,181 +NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION +PDC Energy, Inc. is a domestic independent exploration and production company that produces, develops, acquires and explores for crude oil, natural gas and NGLs with primary operations in the Wattenberg Field in Colorado, the Utica Shale in southeastern Ohio and, until the fourth quarter of 2014, the Marcellus Shale in northern West Virginia. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Ohio operations are focused in the Utica Shale play. As of December 31, 2014 , we owned an interest in approximately 2,900 gross wells. We are engaged in two business segments: Oil and Gas Exploration and Production and Gas Marketing. In October 2014 , we sold our entire 50% ownership interest in PDC Mountaineer, LLC ("PDCM") to an unrelated third-party. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information. +The consolidated financial statements include the accounts of PDC, our wholly-owned subsidiaries, and our proportionate share of PDCM (until the fourth quarter of 2014) and our affiliated partnerships. As of December 31, 2014 , we had four remaining affiliated partnerships that continue to conduct crude oil and natural gas producing activities. Pursuant to the proportionate consolidation method, our accompanying consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation. +The preparation of our consolidated financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of crude oil, natural gas and NGLs sales revenue, crude oil, natural gas and NGLs reserves, future cash flows from crude oil and natural gas properties, valuation of derivative instruments, impairment of proved and unproved properties and valuation of deferred income tax assets. +Certain reclassifications have been made to prior period financial statements to conform to the current year presentation. The reclassifications are attributable to reporting as discontinued operations the results of operations related to PDCM's Marcellus Shale assets and reporting as held for sale our proportionate share of PDCM's Marcellus Shale assets and liabilities, as well as a parcel of land. These reclassifications had no impact on previously reported cash flows, net income, earnings per share or shareholders' equity. +NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Cash Equivalents. We consider all highly liquid investments with original maturities of three months or less to be cash equivalents. +Restricted Cash. We are required by certain government agencies or agreements to maintain bonds or cash accounts for various operating activities. As of December 31, 2014 , we had collateral in the form of certificates of deposit and cash totaling $0.7 million included in other assets. As of December 31, 2013 , we had collateral in the form of certificates of deposit and cash totaling $3.3 million which consisted of $2.2 million and $1.1 million included in restricted cash and other assets, respectively. +Inventory. Inventory consists of crude oil, stated at the lower of cost to produce or market, and other production supplies intended to be used in our crude oil and natural gas operations. As of December 31, 2014 and 2013 , inventory of $0.8 million and $0.9 million , respectively, is included in prepaid expenses and other current assets on the consolidated balance sheets. +Derivative Financial Instruments. We are exposed to the effect of market fluctuations in the prices of crude oil, natural gas and NGLs. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy prohibits the use of crude oil and natural gas derivative instruments for speculative purposes. +All derivative assets and liabilities are recorded on our consolidated balance sheets at fair value. We have elected not to designate any of our derivative instruments as hedges. Accordingly, changes in the fair value of our derivative instruments are recorded in the consolidated statements of operations. Classification of net settlements resulting from maturities and changes in fair value of unsettled derivatives depends on the purpose for issuing or holding the derivative. Changes in the fair value of derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Changes in the fair value of derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of natural gas marketing. +The validation of the derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. See Note 3, Fair Value of Financial Instruments , and Note 4, Derivative Financial Instruments , for a discussion of our derivative fair value measurements and a summary fair value table of our open positions as of December 31, 2014 and 2013 , respectively. +See accompanying Notes to Consolidated Financial Statements +60 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Properties and Equipment. Significant accounting polices related to our properties and equipment are discussed below. +Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. We calculate quarterly depreciation, depletion and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted to add back fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the consolidated statements of operations as a gain or loss. Upon the sale of individual wells or a portion of a field, the proceeds are credited to accumulated DD&A. +Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the proper accounting treatment is recorded. See Note 6, Properties and Equipment , for disclosures related to changes in our capitalized exploratory well costs. +Proved Property Impairment. Upon a triggering event, we assess our producing crude oil and natural gas properties for possible impairment by comparing net capitalized costs, or carrying value, to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. The estimates of future prices may differ from current market prices of crude oil, natural gas and NGLs. Certain events, including but not limited to downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of our proved crude oil and natural gas properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis and is measured by the amount by which the net capitalized costs exceed their fair value. Impairments are included in the consolidated statements of operations line item impairment of crude oil and natural gas properties, with a corresponding impact on accumulated DD&A on the consolidated balance sheets. +Unproved Property Impairment. The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired or amortized. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized, by field, based on our historical experience, acquisition dates and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statements of operations line item impairment of crude oil and natural gas properties. +Other Property and Equipment. Other property and equipment is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of the asset exceeds our estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. Total impairments to other property and equipment was $0.8 million in 2014 . There were no impairments to other property and equipment in 2013 or 2012 . +The following table presents the estimated useful lives of our other property and equipment: +Pipelines and related facilities +10 - 17 years +Transportation and other equipment +3 - 20 years +Buildings +20 - 30 years +Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed from the accounts, the proceeds are applied thereto and any resulting gain or loss is reflected in income. Total depreciation expense related to other property and equipment was $4.1 million , $4.0 million and $4.8 million in 2014 , 2013 and 2012 , respectively. +Capitalized Interest. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A is not currently recorded and on which exploration or development +61 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our debt outstanding by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $3.5 million , $1.7 million and $0.9 million in 2014 , 2013 and 2012 , respectively. +Assets Held for Sale. Assets held for sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques such as a discounted cash flow model, valuations performed by third parties, earnings multiples or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets to be divested once they are classified as held for sale. Assets classified as held for sale are expected to be disposed of within one year. Assets to be divested are classified in the consolidated financial statements as held for sale and the activities of assets to be divested are classified either as discontinued operations or continuing operations. For assets classified as discontinued operations, the results of operations are reclassified from their historical presentation to discontinued operations on the consolidated statements of operations for all periods presented. The gains or losses associated with these divested assets are recorded in discontinued operations on the consolidated statements of operations. For businesses classified as held for sale that do not qualify for discontinued operations treatment, the results of operations continue to be reported in continuing operations. +Production Tax Liability. Production tax liability represents estimated taxes, primarily severance, ad valorem and property, to be paid to the states and counties in which we produce crude oil, natural gas and NGLs, including the production of our affiliated partnerships. Our share of these taxes is expensed to production costs. Affiliated partnerships' share, not owned by us, is recognized as a receivable in accounts receivable affiliates on the consolidated balance sheets. The long-term portion of the production tax liability is included in other liabilities on the consolidated balance sheets and was $26.4 million and $22.1 million in December 31, 2014 and 2013 , respectively. +Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable. As of December 31, 2014 and 2013 , we had no valuation allowance. +Debt Issuance Costs. Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. As of December 31, 2014 and 2013 , included in other assets were $13.7 million and $16.6 million , respectively, related to debt issuance costs. The December 31, 2014 amount included $0.7 million in costs related to the issuance of our 3.25% convertible senior notes due 2016, $8.7 million related to our 7.75% senior notes due 2022 and $4.3 million related to our revolving credit facility. The December 31, 2013 amount included $1.3 million in costs related to the issuance of our 3.25% convertible senior notes due 2016, $9.8 million related to our 7.75% senior notes due 2022 and $5.5 million related to our revolving credit facility and the PDCM credit facility. +Asset Retirement Obligations. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from changes in retirement costs or the estimated timing of settling asset retirement obligations. See Note 9, Asset Retirement Obligations , for a reconciliation of the changes in our asset retirement obligation. +Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in shareholders’ equity in the consolidated balance sheets. When we retire treasury shares, we charge any excess of cost over the par value entirely to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings. +Revenue Recognition. Significant accounting polices related to our revenue recognition are discussed below. +Crude oil, natural gas and NGLs sales. Crude oil, natural gas and NGLs revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. We currently use the "net-back" method of accounting for crude oil, natural gas and NGLs production from the Wattenberg Field and crude oil from the Utica Shale as the majority of the purchasers of these commodities also provide transportation, gathering and processing services. We sell our commodities at the wellhead and collect a price and recognize revenues based on the wellhead sales price as transportation and processing costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based. Natural gas and NGLs sales related to production from the Utica Shale are recognized based on gross prices as the purchasers do not provide transportation, gathering or processing services and we recognize expenses relating to those services as production costs. +62 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Natural gas marketing. Natural gas marketing is reported on the gross method of accounting, based on the nature of the agreements between our natural gas marketing subsidiary, RNG, suppliers and customers. RNG purchases gas from many small producers and bundles the gas together for a price advantage to sell in larger amounts to purchasers of natural gas. RNG has latitude in establishing price and discretion in supplier and purchaser selection. Natural gas marketing revenues and expenses reflect the full cost and revenue of those transactions because RNG takes title to the gas it purchases from the various producers and bears the risks and rewards of that ownership. Both the net settlements and net change in fair value of unsettled derivatives of the RNG commodity-based derivative transactions for natural gas marketing are included in sales from or cost of natural gas marketing, as applicable. +Well operations and pipeline income . We are paid a monthly operating fee for each well we operate and the natural gas transported for outside owners, including the affiliated partnerships we sponsor. Well operations and pipeline income is recognized when persuasive evidence of an arrangement exists, the sales price is fixed or determinable, services have been rendered and collection of revenues is reasonably assured. +Accounting for Acquisitions. We utilize the purchase method to account for acquisitions. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows, quoted market prices and estimates by management. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. +In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped, unproved crude oil and natural gas properties and other non-crude oil and natural gas properties. To estimate the fair value of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. +We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. +Stock-Based Compensation. Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock based compensation expense is recognized in the financial statements on a straight-line basis over the vesting period for the entire award. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statements of operations. No amounts for stock-based compensation were capitalized in 2014 , 2013 and 2012 . +Allowance for Doubtful Accounts. Inherent to our industry is the concentration of crude oil, natural gas and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs and overall creditworthiness of our customers. Further, consideration is given to well production data for receivables related to well operations. +Interest Income. Interest income on our note receivable is recognized over its term using the effective interest method. +Recent Accounting Standards. +Recently Adopted Accounting Standard. On January 1, 2014, we adopted changes issued by the Financial Accounting Standards Board ("FASB") regarding the accounting for income taxes. The change provides clarification on the presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss or a tax credit carryforward exists. Adoption of these changes had no impact on the consolidated financial statements. +In April 2014, the FASB issued changes related to the criteria for determining which disposals can be presented as discontinued operations and modified related disclosure requirements. Under the new pronouncement, a discontinued operation is defined as a component of an entity that either has been disposed of or is classified as held for sale and represents a strategic shift that has a major effect on the entity's operations and financial results. These changes were required to be applied prospectively for new disposals or components of an entity classified as held for sale during interim and annual periods beginning after December 15, 2014, with early adoption permitted. On July 1, 2014, we elected to early adopt the new pronouncement. +63 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Recently Issued Accounting Standard. In May 2014, the FASB and the International Accounting Standards Board ("IASB") issued their converged standard on revenue recognition that provides a single, comprehensive model that entities will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (a) identify the contract with the customer, (b) identify the separate performance obligations in the contract, (c) determine the transaction price, (d) allocate the transaction price to separate performance obligations and (e) recognize revenue when (or as) each performance obligation is satisfied. The revenue standard is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period, and can be adopted under the full retrospective method or simplified transition method. Early adoption is not permitted. We plan to adopt the revenue standard beginning January 1, 2017 and are currently evaluating the impact these changes will have on our consolidated financial statements. +In August 2014, the FASB issued a new standard related to the disclosure of uncertainties about an entity's ability to continue as a going concern. The new standard will explicitly require management to assess an entity's ability to continue as a going concern every reporting period and to provide related footnote disclosures in certain circumstances. The new standard will be effective for all entities in the first annual period ending after December 15, 2016, with early adoption permitted. We are currently evaluating the impact these changes will have on our consolidated financial statements. +In November 2014, the FASB issued an update to accounting for derivatives and hedging instruments.The update clarifies how current accounting guidance should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. Specifically, the accounting update clarifies that an entity should consider all relevant terms and features, including the embedded derivative feature being evaluated for bifurcation, in evaluating the nature of the host contract. Furthermore, the update clarifies that no single term or feature would necessarily determine the economic characteristics and risks of the host contract. Rather, the nature of the host contract depends upon the economic characteristics and risks of the entire hybrid financial instrument. The assessment of the substance of the relevant terms and features should incorporate a consideration of the characteristics of the terms and features themselves, the circumstances under which the hybrid financial instrument was issued or acquired, and the potential outcomes of the hybrid financial instrument, as well as the likelihood of those potential outcomes. The accounting update is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. We are currently evaluating the impact these changes will have on our consolidated financial statements. +In January 2015, the FASB issued new accounting guidance eliminating from current accounting guidance the concept of extraordinary items, which, among other things, required an entity to segregate extraordinary items considered to be unusual and infrequent from the results of ordinary operations and show the item separately in the income statement, net of tax, after income from continuing operations. This guidance is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. The adoption of this guidance is not expected to have a significant impact on our consolidated financial statements. +NOTE 3 - FAIR VALUE OF FINANCIAL INSTRUMENTS +Derivative Financial Instruments +Determination of fair value. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. +Derivative Financial Instruments. We measure the fair value of our derivative instruments based on a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. +64 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +We validate our fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques and believe our valuation method is appropriate and consistent with those used by other market participants, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. +Our fixed-price swaps, basis swaps and physical purchases are included in Level 2 and our collars and physical sales are included in Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis: +As of December 31, +2014 +2013 +Significant Other +Observable +Inputs +(Level 2) +Significant +Unobservable +Inputs +(Level 3) +Total +Significant Other +Observable +Inputs +(Level 2) +Significant +Unobservable +Inputs +(Level 3) +Total +(in thousands) +Assets: +Commodity-based derivative contracts +$ +237,939 +$ +62,356 +$ +300,295 +$ +3,852 +$ +2,098 +$ +5,950 +Basis protection derivative contracts +19 +— +19 +74 +— +74 +Total assets +237,958 +62,356 +300,314 +3,926 +2,098 +6,024 +Liabilities: +Commodity-based derivative contracts +742 +— +742 +16,539 +987 +17,526 +Basis protection derivative contracts +25 +— +25 +5 +— +5 +Total liabilities +767 +— +767 +16,544 +987 +17,531 +Net asset (liability) +$ +237,191 +$ +62,356 +$ +299,547 +$ +(12,618 +) +$ +1,111 +$ +(11,507 +) +The following table presents a reconciliation of our Level 3 assets measured at fair value: +2014 +2013 +2012 +(in thousands) +Fair value, net asset, beginning of period +$ +1,111 +$ +13,610 +$ +22,107 +Changes in fair value included in statement of operations line item: +Commodity price risk management gain (loss), net +62,003 +(1,748 +) +7,517 +Sales from natural gas marketing +(22 +) +13 +63 +Changes in fair value included in balance sheet line item (1): +Accounts payable affiliates +— +— +(319 +) +Settlements included in statement of operations line items: +Commodity price risk management gain (loss), net +(737 +) +(6,361 +) +(15,644 +) +Sales from natural gas marketing +1 +(37 +) +(114 +) +Loss from discontinued operations, net of tax +— +(4,366 +) +— +Fair value, net asset end of period +$ +62,356 +$ +1,111 +$ +13,610 +Net change in fair value of unsettled derivatives included in statement of operations line item: +Commodity price risk management gain (loss), net +$ +15,632 +$ +(2,731 +) +$ +3,665 +Sales from natural gas marketing +3 +4 +1 +Total +$ +15,635 +$ +(2,727 +) +$ +3,666 +__________ +(1) +Represents the change in fair value related to derivative instruments entered into by us and designated to our affiliated partnerships. +The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. There has been no change in the methodology we apply to measure the fair value of our Level 3 derivative contracts. +65 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Non-Derivative Financial Assets and Liabilities +The carrying value of the financial instruments included in current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. See Note 2, Summary of Significant Accounting Policies - Properties and Equipment, Crude Oil and Natural Gas Properties and Asset Retirement Obligations, for a discussion of how we determined fair value for these assets and liabilities. +The liability associated with our non-qualified deferred compensation plan for non-employee directors may be settled in cash or shares of our common stock. The carrying value of this obligation is based on the quoted market price of our common stock, which is a Level 1 input. The liability related to this plan, which was included in other liabilities on the consolidated balance sheets, was immaterial as of December 31, 2014 and 2013 . +The portion of our long-term debt related to our revolving credit facility approximates fair value due to the variable nature of related interest rates. We have not elected to account for the portion of our debt related to our senior notes under the fair value option; however, as of December 31, 2014 , we estimate the fair value of the portion of our long-term debt related to our 3.25% convertible senior notes due 2016 to be $137.5 million , or 119.6% of par value, and the portion related to our 7.75% senior notes due 2022 to be $452.5 million , or 90.5% of par value. We determined these valuations based upon measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. +NOTE 4 - DERIVATIVE FINANCIAL INSTRUMENTS +Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas, we utilize the following economic hedging strategies for each of our business segments. +• +For crude oil and natural gas sales, we enter into derivative contracts to protect against price declines in future periods. While we structure these derivatives to reduce our exposure to changes in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price increases in the physical market; and +• +For natural gas marketing, we enter into fixed-price physical purchase and sale agreements that qualify as derivative contracts. In order to offset the fixed-price physical derivatives in our natural gas marketing, we enter into financial derivative instruments that have the effect of locking in the prices we will receive or pay for the same volumes and period, offsetting the physical derivative. +We believe our derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of December 31, 2014 , we had derivative instruments in place for a portion of our anticipated production through 2017 for a total of 65,215 BBtu of natural gas and 9,340 MBbls of crude oil. The majority of our derivative contracts are entered into at no cost to us as we hedge our anticipated production at the then-prevailing commodity market prices. +As of December 31, 2014 , our derivative instruments were comprised of commodity swaps, collars, basis protection swaps and physical sales and purchases. +• +Collars contain a fixed floor price and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty; +• +Swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty; +• +Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For CIG-basis protection swaps, which had a negative differential to NYMEX for the majority of 2014, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. If the market price and contract price are the same, no payment is due to or from the counterparty; and +• +Physical sales and purchases are derivatives for fixed-priced physical transactions where we sell or purchase third-party supply at fixed rates. These physical derivatives are offset by financial swaps: for a physical sale the offset is a swap purchase and for a physical purchase the offset is a swap sale. +66 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the balance sheet location and fair value amounts of our derivative instruments on the consolidated balance sheets as of December 31, 2014 and 2013 : +Derivative instruments: +Balance sheet line item +2014 +2013 +(in thousands) +Derivative assets: +Current +Commodity contracts +Related to crude oil and natural gas sales +Fair value of derivatives +$ +186,886 +$ +1,086 +Related to natural gas marketing +Fair value of derivatives +590 +361 +Basis protection contracts +Related to crude oil and natural gas sales +Fair value of derivatives +19 +74 +187,495 +1,521 +Non-current +Commodity contracts +Related to crude oil and natural gas sales +Fair value of derivatives +112,599 +4,225 +Related to natural gas marketing +Fair value of derivatives +220 +278 +112,819 +4,503 +Total derivative assets +$ +300,314 +$ +6,024 +Derivative liabilities: +Current +Commodity contracts +Related to crude oil and natural gas sales +Fair value of derivatives +$ +— +$ +14,437 +Related to natural gas marketing +Fair value of derivatives +545 +247 +Basis protection contracts +Related to crude oil and natural gas sales +Fair value of derivatives +25 +— +Related to natural gas marketing +Fair value of derivatives +— +5 +570 +14,689 +Non-current +Commodity contracts +Related to crude oil and natural gas sales +Fair value of derivatives +— +2,609 +Related to natural gas marketing +Fair value of derivatives +197 +233 +197 +2,842 +Total derivative liabilities +$ +767 +$ +17,531 +67 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the impact of our derivative instruments on our consolidated statements of operations: +Year Ended December 31, +Consolidated statement of operations line item +2014 +2013 +2012 +Commodity price risk management gain (loss), net +Net settlements +$ +(837 +) +$ +11,177 +$ +43,591 +Net change in fair value of unsettled derivatives +311,141 +(35,096 +) +(14,312 +) +Total commodity price risk management gain (loss), net +$ +310,304 +$ +(23,919 +) +$ +29,279 +Sales from natural gas marketing +Net settlements +$ +(208 +) +$ +446 +$ +2,170 +Net change in fair value of unsettled derivatives +364 +429 +(1,658 +) +Total sales from natural gas marketing +$ +156 +$ +875 +$ +512 +Cost of natural gas marketing +Net settlements +$ +346 +$ +(257 +) +$ +(2,029 +) +Net change in fair value of unsettled derivatives +(451 +) +(412 +) +1,601 +Total cost of natural gas marketing +$ +(105 +) +$ +(669 +) +$ +(428 +) +All of our financial derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. Our fixed-price physical purchase and sale agreements that qualify as derivative contracts are not subject to master netting provisions and are not significant. We have elected not to offset the fair value positions recorded on our consolidated balance sheets. +The following table reflects the impact of netting agreements on gross derivative assets and liabilities as of December 31, 2014 and 2013 : +As of December 31, 2014 +Derivative instruments, recorded in consolidated balance sheet, gross +Effect of master netting agreements +Derivative instruments, net +(in thousands) +Asset derivatives: +Derivative instruments, at fair value +$ +300,314 +$ +(29 +) +$ +300,285 +Liability derivatives: +Derivative instruments, at fair value +$ +767 +$ +(29 +) +$ +738 +As of December 31, 2013 +Derivative instruments, recorded in consolidated balance sheet, gross +Effect of master netting agreements +Derivative instruments, net +(in thousands) +Asset derivatives: +Derivative instruments, at fair value +$ +6,024 +$ +(4,637 +) +$ +1,387 +Liability derivatives: +Derivative instruments, at fair value +$ +17,531 +$ +(4,637 +) +$ +12,894 +NOTE 5 - CONCENTRATION OF RISK +Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts: +As of December 31, +2014 +2013 +(in thousands) +Crude oil, natural gas and NGLs sales +$ +49,531 +$ +61,197 +Joint interest billings +52,841 +20,085 +Derivative counterparties +12,582 +1,025 +Insurance reimbursement +11,212 +— +Other +5,524 +6,700 +Allowance for doubtful accounts +(486 +) +(896 +) +Accounts receivable, net +$ +131,204 +$ +88,111 +Our accounts receivable primarily relate to sales of our crude oil, natural gas and NGLs production, other third parties that own working interests in the properties we operate and derivative counterparties. For the years ended December 31, 2014 , 2013 and 2012 , amounts written off to allowance for doubtful accounts were not material. As of December 31, 2014 , we had two customers representing 10% or greater of our accounts receivable balance: Suncor Energy Marketing, Inc. and Concord Energy, representing 11.1% and 10.3% , respectively, of our accounts receivable balance. +Major Customers. The following table presents the individual customers constituting 10% or more of total revenues: +Year Ended December 31, +Customer +2014 +2013 +2012 +Suncor Energy Marketing, Inc. +19.7 +% +35.9 +% +39.1 +% +Concord Energy +18.3 +% +— +% +— +% +DCP Midstream, LP +15.1 +% +13.9 +% +16.0 +% +Teppco Crude Oil, LLC +12.9 +% +8 +% +2.4 +% +The concentration of revenue represented by the customers noted above relate to our oil and gas exploration and production segment. +Derivative Counterparties. A significant portion of our liquidity is concentrated in derivative instruments that enable us to manage a portion of our exposure to price volatility from producing crude oil and natural gas. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also major lenders under our revolving credit facility as counterparties to our derivative contracts. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our current counterparties on the fair value of our derivative instruments is not significant. +The following table presents the counterparties that expose us to credit risk as of December 31, 2014 , with regard to our derivative assets: +Fair Value of +Derivative Assets +Counterparty Name +As of December 31, 2014 +(in thousands) +JP Morgan Chase Bank, N.A (1) +$ +95,294 +Canadian Imperial Bank of Commerce (1) +61,570 +NATIXIS (1) +45,214 +Wells Fargo Bank, N.A. (1) +41,844 +Key Bank N.A. (1) +24,899 +Bank of Nova Scotia (1) +23,760 +Other lenders in our revolving credit facility +7,726 +Various (2) +7 +Total +$ +300,314 +____________ +(1) Major lender in our revolving credit facility. See Note 8, Long-Term Debt. +(2) Represents a total of 2 counterparties. +Note Receivable +The following table presents information regarding our note receivable outstanding as of December 31, 2014 : +Amount +(in thousands) +Note Receivable: +Principal outstanding, October 14, 2014 +$ +39,048 +Paid-In-Kind interest +659 +Principal outstanding, December 31, 2014 +$ +39,707 +In October 2014, we sold our entire 50% ownership interest in PDCM to an unrelated third-party. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations , for additional information regarding the sale. As part of the consideration, we received a promissory note (the “Note”) for a principal sum of $39.0 million , bearing varying interest rates beginning at 8% and increasing annually. Pursuant to the Note agreement, interest shall be paid quarterly, in arrears, commencing December 2014 and continuing on the last business day of each fiscal quarter thereafter. At the option of the issuer of the Note, an unrelated third-party, interest can be paid-in-kind (the “PIK Interest”) and any such PIK Interest will be added to the outstanding principal amount of the Note. As of December 31, 2014, the issuer of the Note had elected to pay-in-kind interest on the Note. The principal and any unpaid interest shall be due and payable in full in September 2020, and can be prepaid, in whole or in part, at any time without premium or penalty. The Note is secured by a pledge of stock in certain subsidiaries of the unrelated third-party, debt securities issued and certain assets. +Under the effective interest method, we recognized $0.9 million of interest income for the year ended December 31, 2014, of which $0.7 million was PIK Interest. As of December 31, 2014, the $39.7 million outstanding balance on the Note was included in the consolidated balance sheet line item other assets. +68 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 6 - PROPERTIES AND EQUIPMENT +The following table presents the components of properties and equipment, net of accumulated DD&A: +As of December 31, +2014 +2013 +(in thousands) +Properties and equipment, net: +Crude oil and natural gas properties +Proved +$ +2,267,165 +$ +1,677,271 +Unproved +188,206 +253,464 +Total crude oil and natural gas properties +2,455,371 +1,930,735 +Equipment and other +29,562 +28,832 +Land and buildings +9,015 +9,782 +Construction in progress +137,937 +41,180 +Properties and equipment, at cost +2,631,885 +2,010,529 +Accumulated DD&A +(831,699 +) +(529,543 +) +Properties and equipment, net +$ +1,800,186 +$ +1,480,986 +The following table presents impairment charges recorded for crude oil and natural gas properties: +Year Ended December 31, +2014 +2013 +2012 +(in thousands) +Continuing operations: +Impairment of proved properties +$ +112,557 +$ +48,750 +$ +— +Impairment of unproved properties +45,732 +517 +1,011 +Amortization of individually insignificant unproved properties +4,465 +3,242 +4,009 +Other +778 +— +— +Total continuing operations +163,532 +52,509 +5,020 +Discontinued operations: +Impairment of proved properties +— +— +161,185 +Impairment of unproved properties +433 +566 +931 +Amortization of individually insignificant unproved properties +— +363 +1,013 +Total discontinued operations +433 +929 +163,129 +Total impairment of crude oil and natural gas properties +$ +163,965 +$ +53,438 +$ +168,149 +In 2014, we recognized an impairment charge of $158.3 million to write-down our Utica Shale producing and non-producing crude oil and natural gas properties to their estimated fair value, $112.6 million of which was for capitalized well costs on proved producing properties and $45.7 million for capitalized leasehold costs on unproved properties. The impairment charge represented the amount by which the carrying value of the Utica Shale crude oil and natural gas properties exceeded the estimated fair value and was therefore not recoverable. The estimated fair value was determined based on estimated future discounted net cash flows, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. The impairment charge was included in the consolidated statements of operations line item impairment of crude oil and natural gas properties. +In 2013, we recognized an impairment charge of approximately $48.8 million related to all of our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties located in West Virginia and Pennsylvania previously owned directly by us, as well as through our proportionate share of PDCM. The impairment charge represented the excess of the carrying value of the assets over the estimated fair value, less the cost to sell. The fair value of the assets was determined based upon estimated future cash flows from unrelated third-party bids, a Level 3 input. The impairment charge was included in the consolidated statements of operations line item impairment of crude oil and natural gas properties. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding these properties. +In 2012, we recognized an impairment charge of $161.2 million to write-down our Piceance Basin proved oil and natural gas properties to their estimated fair value. The fair value was based on estimated future cash flows from an unrelated third-party bid, a Level 3 input. The impairment charge was included in the consolidated statements of operations line item income from discontinued operations, net of tax. +69 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Suspended Well Costs +The following table presents the capitalized exploratory well costs pending determination of proved reserves included in properties and equipment on the consolidated balance sheets: +2013 +(in thousands) +Balance beginning of year, January 1, +$ +19,567 +Additions to capitalized exploratory well costs pending the determination of proved reserves +2,105 +Reclassifications to wells, facilities and equipment based on the determination of proved reserves +(21,672 +) +Capitalized exploratory well costs charged to expense +— +Balance end of year, December 31, +$ +— +Number of wells pending determination at December 31, +— +As of December 31, 2014 , there were no suspended well costs or wells pending determination. +NOTE 7 - INCOME TAXES +The table below presents the components of our provision for income taxes from continuing operations for the years presented: +Year Ended December 31, +2014 +2013 +2012 +(in thousands) +Current: +Federal +$ +(1,514 +) +$ +1,355 +$ +— +State +966 +199 +(199 +) +Total current income taxes +(548 +) +1,554 +(199 +) +Deferred: +Federal +(60,698 +) +8,238 +10,896 +State +(8,721 +) +2,060 +636 +Total deferred income taxes +(69,419 +) +10,298 +11,532 +Income tax benefit (expense) from continuing operations +$ +(69,967 +) +$ +11,852 +$ +11,333 +In the last three years, we continued to utilize tax deferral strategies such as bonus depreciation, accelerated depreciation and intangible drilling cost ("IDC") expense elections or accelerated IDC amortization to minimize our current taxes. As a result of these elections and deferral strategies, we generated federal and state net operating losses (“NOLs”) in 2012 and prior. In 2013 these deferral strategies enabled us to offset any taxable gain on the sale of our non-core Colorado assets and also preserved some of our NOLs to carry forward for use against our anticipated 2014 taxable income. In 2014, these same deferral strategies, along with carried forward federal and state NOLs, credits, and suspended deductions, permitted us to offset the majority of the tax gain on the sale of PDCM. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding the sale of our non-core Colorado assets and the sale of our entire 50% ownership interest in PDCM. +70 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents a reconciliation of the statutory rate to the effective tax rate related to our provision for income taxes from continuing operations: +Year Ended December, 31, +2014 +2013 +2012 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income tax, net +2.8 +4.0 +0.9 +Percentage depletion +(0.3 +) +2.2 +2.0 +Non-deductible compensation +0.7 +(4.2 +) +(0.5 +) +Other +1.3 +(1.0 +) +(0.5 +) +Effective tax rate +39.5 +% +36.0 +% +36.9 +% +The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2014 and 2013 are presented below: +As of December 31, +2014 +2013 +(in thousands) +Deferred tax assets: +Net change in fair value of unsettled derivatives +$ +— +$ +6,205 +Deferred compensation +10,459 +8,507 +Asset retirement obligations +28,051 +11,630 +State NOL and tax credit carryforwards, net +3,761 +5,182 +Percentage depletion - carryforward +— +4,570 +Alternative minimum tax - credit carryforward +2,906 +3,165 +Federal NOL carryforward +— +4,601 +Settlement of class action litigation +12,259 +— +Other +3,144 +6,229 +Deferred tax assets +60,580 +50,089 +Deferred tax liabilities: +Properties and equipment +130,155 +120,746 +Investment in PDCM +— +21,962 +Net change in fair value of unsettled derivatives +113,007 +— +Convertible debt +2,285 +3,774 +Total gross deferred tax liabilities +245,447 +146,482 +Net deferred tax liability +$ +184,867 +$ +96,393 +Classification in the consolidated balance sheets: +Deferred income tax assets +$ +— +$ +22,374 +Deferred income tax liability - current +59,174 +— +Deferred income tax liability - non-current +125,693 +118,767 +Net deferred tax liability +$ +184,867 +$ +96,393 +Deferred tax assets increased, primarily due to the addition of the deferred tax asset associated with asset retirement obligations and a legal accrual associated with the settlement of certain partnership-related class action litigation. These increases were partially offset by the utilization of our federal NOL and percentage depletion carryforwards and removal of the deferred tax asset associated with the unrealized tax loss for the fair value of unsettled derivatives. +Deferred tax liabilities for properties and equipment increased as a result of our continued use of statutory provisions for expensing and accelerated amortization of IDCs and accelerated tax depreciation. The increase from the use of these accelerated tax deductions was partially offset by the deferred tax asset for the impairment of some of our crude oil and natural gas properties. The sale of our entire 50% ownership interest in PDCM also resulted in a decrease to our deferred tax liability. In addition, the fair value of unsettled derivatives at December 31, 2014 resulted in an unrealized tax gain versus an unrealized loss at December 31, 2013. +71 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +As of December 31, 2014 , we have state NOL carryforwards of $90.0 million that begin to expire in 2030 and state credit carryforwards of $1.3 million that begin to expire in 2023 . +Unrecognized tax benefits and related accrued interest and penalties were immaterial for the three-year period ended December 31, 2014. The total amount of unrecognized tax benefits that would affect the effective tax rate decreased to zero in the current year due to the expiration of the statute of limitations. The statute of limitations for most of our state tax jurisdictions is open from 2010 forward. +In accordance with the CAP program, the IRS completed its “post filing review” of our 2012 and 2013 tax returns in January 2014 and 2015, respectively. We have been issued a “no change” letter for both of the reviewed tax years. The CAP audit employs a real-time review of our books and tax records by the IRS that is intended to permit issue resolution prior to, or shortly after, the filing of the tax returns. We are currently participating in the CAP program for the review of our 2014 tax year and we have been invited and have accepted continued participation in the program for our 2015 tax year. Participation in the CAP program has enabled us to currently have no uncertain tax benefits associated with our federal tax return filings. +As of December 31, 2014 , we were current with our income tax filings in all applicable state jurisdictions. In 2013, the State of Colorado examined our 2008 through 2011 Colorado corporate income tax returns and proposed no adjustments. +NOTE 8 - LONG-TERM DEBT +Long-term debt consists of the following: +As of December 31, +2014 +2013 +(in thousands) +Senior notes: +3.25% Convertible senior notes due 2016: +Principal amount +$ +115,000 +$ +115,000 +Unamortized discount +(6,077 +) +(10,010 +) +3.25% Convertible senior notes due 2016, net of discount +108,923 +104,990 +7.75% Senior notes due 2022 +500,000 +500,000 +Total senior notes +608,923 +604,990 +Revolving credit facility +56,000 +— +Long-term debt +664,923 +604,990 +PDCM credit facility +— +37,000 +PDCM second lien term loan +— +15,000 +PDCM long-term debt (included in liabilities held for sale - non-current) +— +52,000 +Total debt +$ +664,923 +$ +656,990 +Senior Notes +3.25% Convertible Senior Notes Due 2016. In November 2010 , we issued $115 million aggregate principal amount 3.25% convertible senior notes due 2016 (the "Convertible Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is May 15, 2016 . Interest is payable semi-annually in arrears on each May 15 and November 15 . The Convertible Notes are senior, unsecured obligations and rank senior in right of payment to our existing and future indebtedness that is expressly subordinated in right of payment to the Convertible Notes; equal in right of payment to our existing and future unsecured indebtedness that is not expressly subordinated (including our 2022 Senior Notes); effectively junior in right of payment to any of our secured indebtedness (including our obligations under our revolving credit facility) to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our subsidiaries. The indenture governing the Convertible Notes does not contain any restrictive financial covenants. The Convertible Notes and the common stock issuable upon conversion of the Convertible Notes, if any, have not been registered under the Securities Act of 1933 or any state securities laws, nor are we required to register such Convertible Notes or common shares. The Convertible Notes are governed by an indenture between the Company and the Bank of New York Mellon, as trustee. +We may not redeem the Convertible Notes prior to their maturity. However, prior to November 15, 2015 , holders of the Convertible Notes may convert upon specified events as defined in the governing indenture. The notes are convertible at any time thereafter at an initial conversion rate of 23.5849 shares per $1,000 principal amount, which is equal to a conversion price of approximately $42.40 per share. The +72 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +conversion rate is subject to adjustment upon certain events. Upon conversion, the Convertible Notes may be settled, at our election, in shares of our common stock, cash or a combination of cash and shares of our common stock. We have initially elected a net-settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the Convertible Notes in cash and to settle the excess conversion value in shares, as well as cash in lieu of fractional shares. +We allocated the gross proceeds of the Convertible Notes between the liability and equity components of the debt. The initial $94.3 million liability component was determined based on the fair value of similar debt instruments with similar terms, excluding the conversion feature, and priced on the same day we issued the Convertible Notes. The initial $20.7 million equity component represents the debt discount and was calculated as the difference between the liability component of the debt and the gross proceeds of the Convertible Notes. As of December 31, 2014 , the unamortized debt discount will be amortized over the remaining contractual term to maturity of the Convertible Notes of 1.4 years using an effective interest rate of 7.4% . For 2014 , interest expense related to the indebtedness and the amortization of the discount was $3.7 million and $3.9 million , respectively, compared to $3.7 million each in 2013 and $3.7 million and $3.4 million , respectively, in 2012 . As of December 31, 2014 , notwithstanding the inability to convert, the principal amount exceeded the “if-converted” value of the Convertible Notes by approximately $3.1 million . +7.75% Senior Notes Due 2022. In October 2012 , we issued $500 million aggregate principal amount 7.75% senior notes due October 15, 2022 (the "2022 Senior Notes") in a private placement to qualified institutional buyers. The 2022 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually in arrears on April 15 and October 15 . Approximately $11 million in costs associated with the issuance of the 2022 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. The 2022 Senior Notes are senior unsecured obligations and rank senior in right of payment to any of our future indebtedness that is expressly subordinated to the notes. The 2022 Senior Notes rank equally in right of payment with all our existing and future senior indebtedness (including our Convertible Notes) and rank effectively junior in right of payment to all of our secured indebtedness (to the extent of the value of the collateral securing such indebtedness), including borrowings under our revolving credit facility. +In connection with the issuance of the 2022 Senior Notes, we entered into a registration rights agreement with the initial purchasers in which we agreed to file a registration statement with the SEC related to an offer to exchange the notes for substantially identical registered notes and to use commercially reasonable efforts to cause the exchange offer to be completed on or prior to September 28, 2013. The registration statement was declared effective by the SEC in July 2013 and the exchange offer was completed in August 2013. +At any time prior to October 15, 2015 , we may redeem up to 35% of the outstanding 2022 Senior Notes with proceeds from certain equity offerings at a redemption price of 107.75% of the principal amount of the notes redeemed, plus accrued and unpaid interest, as long as at least 65% of the aggregate principal amount of the notes issued on October 3, 2012 remains outstanding after each such redemption and the redemption occurs within 180 days after the closing of the equity offering. At any time prior to October 15, 2017 , we may redeem all or part of the 2022 Senior Notes at a make-whole price set forth in the indenture, and on or after October 15, 2017 , we may redeem the notes at fixed redemption prices, plus accrued and unpaid interest, if any, to the date of redemption. +Upon the occurrence of a "change of control" as defined in the indenture for the 2022 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101% of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we will be required to use the net cash proceeds of the asset sale to make an offer to purchase the notes at 100% of the principal amount, together with any accrued and unpaid interest to the date of purchase. +The indenture governing the 2022 Senior Notes contains covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make certain investments; create certain liens; restrict dividends or other payments by restricted subsidiaries; enter into transactions with affiliates; sell assets; and merge or consolidate with another company. +As of December 31, 2014 , we were in compliance with all covenants related to the Convertible Notes and the 2022 Senior Notes, and expect to remain in compliance throughout the next twelve-month period. +73 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Credit Facility +Revolving Credit Facility . In May 2013 , we entered into a Third Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A. as administrative agent and other lenders party thereto. This agreement amends and restates the credit agreement dated November 2010 and expires in May 2018 . The revolving credit facility is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes and to support letters of credit. The revolving credit facility provides for a maximum of $1 billion in allowable borrowing capacity, subject to the borrowing base. The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our and our subsidiaries' crude oil and natural gas interests, excluding proved reserves attributable to our affiliated partnerships. The borrowing base is subject to a semi-annual size redetermination based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. In September 2014 , the semi-annual redetermination of our revolving credit facility's borrowing base was completed, resulting in an increase in the borrowing base from $450 million to $700 million . We have elected to maintain the aggregate commitment at $450 million . The revolving credit facility is secured by a pledge of the stock of certain of our subsidiaries, mortgages of certain producing crude oil and natural gas properties and substantially all of our and such subsidiaries' other assets. Our affiliated partnerships are not guarantors of our obligations under the revolving credit facility. We had an outstanding balance of $56.0 million on our revolving credit facility as of December 31, 2014 compared to no outstanding balance as of December 31, 2013 . The weighted-average borrowing rate on our revolving credit facility, exclusive of the letter of credit noted below, was 4.1% per annum as of December 31, 2014 . +The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greater of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus a premium and 1-month LIBOR plus a premium), or at our election, a rate equal to the rate for dollar deposits in the London interbank market for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. No principal payments are required until the credit agreement expires in May 2018 , or in the event that the borrowing base falls below the outstanding balance. +The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.00 to 1.00 and (b) not exceed a maximum leverage ratio of 4.25 to 1.00. As of December 31, 2014 , we were in compliance with all the revolving credit facility covenants and expect to remain in compliance throughout the next twelve-month period. +The revolving credit facility contains restrictions as to when we can directly or indirectly, retire, redeem, repurchase or prepay in cash any part of the principal of the 2022 Senior Notes or the Convertible Notes. Among other things, the restriction on redemption of the Convertible Notes requires that immediately after giving effect to any such retirement, redemption, defeasance, repurchase, settlement or prepayment, the aggregate commitment under the revolving credit facility exceed the aggregate credit exposure under such facility by at least the greater of $115 million or an amount equal to or greater than 30% of such aggregate commitment. The restriction on redemption of the 2022 Senior Notes permits redemption only with the proceeds of issuances of "Permitted Refinancing Indebtedness," which may not exceed $750 million. +As of December 31, 2014 , RNG had an irrevocable standby letter of credit of approximately $11.7 million in favor of a third-party transportation service provider to secure firm transportation of the natural gas produced by third-party producers for whom we market production in the Appalachian Basin. The letter of credit, which expires in September 2015, reduces the amount of available funds under our revolving credit facility by an equal amount. As of December 31, 2014 , the available funds under our revolving credit facility, including the reduction for the $11.7 million letter of credit, was $382.3 million . In addition to our currently elected commitment of $450 million , we have an additional $250 million of borrowing base availability under the revolving credit facility, subject to certain terms and conditions of the agreement. +PDCM +On October 14, 2014 , we closed the sale of our entire 50% ownership interest in PDCM to an unrelated third-party. The transaction included the repayment of the PDCM credit facility and Second Lien Credit Agreement ("Term Loan Agreement") by the buyer. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations , for additional information. +74 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 9 - ASSET RETIREMENT OBLIGATIONS +The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interest in crude oil and natural gas properties: +2014 +2013 +(in thousands) +Balance at beginning of period, January 1, 2014 +$ +41,030 +$ +62,563 +Revisions in estimated cash flows +31,945 +612 +Obligations incurred with development activities +1,170 +2,389 +Accretion expense +3,455 +4,747 +Obligations discharged with divestitures of properties and asset retirements +(3,745 +) +(29,281 +) +Balance end of period, December 31, 2014 +73,855 +41,030 +Less: Liabilities held for sale (1) +— +(2,234 +) +Less: Current portion +(1,863 +) +(1,158 +) +Long-term portion +$ +71,992 +$ +37,638 +______________ +(1) +Represents asset retirement obligations related to assets held for sale. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information. +The revisions in estimated cash flows during 2014 were due to changes in estimates of costs for materials and services related to the plugging and abandonment of certain vertical wells in the Wattenberg Field, as well as a decrease in the estimated useful life of these wells. The increase in estimated costs is primarily the result of various recent federal, state and local laws that regulate plugging operations and techniques. The revision in the asset retirement obligation did not have an immediate effect in the 2014 statement of operations as the increase in the revised obligation was offset by a capitalized amount, which will be depreciated over the useful lives of respective wells. +NOTE 10 - EMPLOYEE BENEFIT PLANS +We sponsor a qualified retirement plan covering substantially all of our employees. The plan consists of both a traditional and a Roth 401(k) component, as well as a profit sharing component. The 401(k) components enable eligible employees to contribute a portion of their compensation through payroll deductions in accordance with specific guidelines. We provide a discretionary matching contribution based on a percentage of the employees' contributions up to certain limits. Our contribution to the profit sharing component is discretionary. Our total combined expense for the plan was $3.9 million , $3.7 million and $3.4 million for 2014 , 2013 and 2012 , respectively. +We provide a supplemental retirement benefit of deferred compensation under terms of the various employment agreements with certain former executive officers. Expenses related to this plan are charged to general and administrative expenses and the related costs were immaterial in 2014 , 2013 and 2012 . As of December 31, 2014 and 2013 , the liability related to this benefit was $1.5 million and $1.8 million , respectively, which was included in other liabilities on the consolidated balance sheets, with the exception of $0.3 million included in other accrued expenses as of December 31, 2014 and 2013 . +We provide a supplemental health care benefit covering certain former executive officers and their spouses in accordance with each officer's employment agreement. Expenses incurred during 2014 , 2013 and 2012 related to this plan were immaterial. As of December 31, 2014 and 2013 , the related liability of $0.7 million is included in other liabilities on the consolidated balance sheets. +We maintain a non-qualified deferred compensation plan for our non-employee directors. The amount of compensation deferred by each participant is based on participant elections. The amounts deferred pursuant to the plan are invested in our common stock, maintained in a rabbi trust and are classified in the consolidated balance sheets as treasury shares as a component of shareholders' equity. The plan may be settled in either cash or shares as requested by the participant. The liability related to this plan, which was included in other liabilities on the consolidated balance sheets, was immaterial as of December 31, 2014 and 2013 . +NOTE 11 - COMMITMENTS AND CONTINGENCIES +Firm Transportation, Processing and Sales Agreements. We enter into contracts that provide firm transportation, sales and processing agreements on pipeline systems through which we transport or sell crude oil and natural gas. Satisfaction of the volume requirements includes volumes produced by us, purchased from third parties and produced by our affiliated partnerships and other third-party working interest owners. We record in our financial statements only our share of costs based upon our working interest in the wells. These contracts require us to pay these transportation and processing charges, whether the required volumes are delivered or not. +75 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents gross volume information related to our long-term firm transportation, sales and processing agreements for pipeline capacity: +Year Ending December 31, +Area +2015 +2016 +2017 +2018 +2019 and +Through +Expiration +Total +Expiration +Date +Natural gas (MMcf) +Appalachian Basin +7,117 +7,136 +7,117 +7,117 +25,803 +54,290 +August 31, 2022 +Utica Shale +2,737 +2,745 +2,737 +2,737 +12,549 +23,505 +July 22, 2023 +Total +9,854 +9,881 +9,854 +9,854 +38,352 +77,795 +Crude oil (MBbls) +Wattenberg Field +1,818 +2,420 +2,413 +2,413 +3,010 +12,074 +April 30, 2020 +Dollar commitment (in thousands) +$ +14,481 +$ +17,624 +$ +17,158 +$ +16,327 +$ +30,361 +$ +95,951 +In September 2014, we entered into a long-term firm transportation agreement with White Cliffs Pipeline, LLC, to ship crude oil from southern Weld County, Colorado, to Cushing, Oklahoma. The primary term of the agreement is five years commencing on the first delivery of crude oil to the pipeline system, which we currently expect to begin in May 2015. The agreement includes minimum volume commitments as shown in the table above, with certain fees assessed for any shortfall. Concurrently, we entered into a crude oil purchase and sale agreement with Concord Energy, LLC, whereby we agreed to sell and Concord Energy, LLC agreed to purchase the entire minimum volume commitments under the long-term firm transportation agreement. +On October 14, 2014 , we closed the sale of our entire 50% ownership interest in PDCM to an unrelated third-party. The transaction included the buyer's assumption of approximately 134,875 MMcf and $30.4 million of our Appalachian Basin firm transportation commitment. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations , for additional information. +Litigation. The Company is involved in various legal proceedings that it considers normal to its business. The Company reviews the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in the best interests of the Company. There is no assurance that settlements can be reached on acceptable terms or that adverse judgments, if any, in the remaining litigation will not exceed the amounts reserved. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity. +Class Action Regarding 2010 and 2011 Partnership Purchases +In December 2011, the Company and its wholly-owned merger subsidiary were served with an alleged class action on behalf of unit holders of 12 former limited partnerships, related to its repurchase of the 12 partnerships, which were formed beginning in late 2002 through 2005. The mergers were completed in 2010 and 2011. The action was filed in U.S. District Court for the Central District of California and is titled Schulein v. Petroleum Development Corp . The complaint primarily alleges that the disclosures in the proxy statements issued in connection with the mergers were inadequate, and a state law breach of fiduciary duty. In January 2014, the plaintiffs were certified as a class by the court. +In October 2014, the Company and plaintiffs’ counsel reached an oral settlement agreement, subject to the contingencies noted below. That agreement was reduced to writing and signed in December 2014. Under this agreement the plaintiffs would receive a cash payment of $37.5 million , of which PDC would pay $31.5 million and insurers would pay $6 million . This all-cash settlement agreement is a different structure than the initial agreement in principle, which was structured as part up-front cash and part interests in future wells. The proposed all-cash settlement remains subject to the satisfaction of various conditions, including but not limited to final court approval; the hearing regarding final approval is currently scheduled for March 16, 2015. Preliminary approval by the court was received on December 30, 2014, and notice of the settlement was mailed to class members in mid-January 2015. Any class member elections to opt out of the settlement are due in February 2015. In late January 2015, PDC deposited the $37.5 million , including the $6 million paid directly to the Company by its insurers, into escrow, as provided in the agreement. As a result of this litigation, the Company accrued $31.5 million of expense in 2014, which is included in general and administrative expense in the consolidated statements of operations. As of December 31, 2014, the Company has accrued a total gross liability of $37.5 million related to this litigation, of which $31.5 million represents our expense and $6 million represents the portion our insurers would pay, which is our best estimate of the amount required to settle the case. The liability is included in other accrued expenses in the consolidated balance sheets. There is also a corresponding receivable due from our insurers of $6 million included in accounts receivable in the consolidated balance sheets, which was received from the insurers in January 2015. +Under this settlement agreement, the class action would be dismissed with prejudice and all claims would be released. If the matter proceeds to trial, the plaintiffs have indicated that they will seek damages of approximately $175 million , plus pre-judgment interest. In such event, we continue to believe we would have good defenses to both the asserted claims and plaintiffs’ damage calculations. +76 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Partnership Liquidation Lawsuit +In October 2014, following three days of court ordered mediation PDC entered into a written settlement term sheet pursuant to which PDC agreed to pay approximately $8.8 million in resolution of an adversary proceeding filed against PDC in June 2014 titled Eastern 1996D Limited Partnership, et al. v. PDC Energy, Inc . Adv. Pro. No. 14-03080 (the “Adversary Proceeding”) related to Jointly Administered bankruptcy Case No. 13-34773-HDH-11, currently pending in the United States Bankruptcy Court for the Northern District of Texas (the “Bankruptcy Court”). The bankruptcy case relates to 12 limited partnerships formed from1996 to 2002, for which PDC is the managing general partner. These partnerships filed bankruptcy in September 2013 to pursue an orderly liquidation of their assets and distribute the resulting proceeds to partners. The Adversary Proceeding primarily alleged claims for breach of fiduciary duty and breach of contract against PDC as managing general partner of the partnerships. In October 2014, the Bankruptcy Court approved the proposed disclosure statement in support of the debtors’ joint liquidating plan and the manner of solicitation of votes on such plan. The plan incorporated approval of the above proposed settlement. The plan, disclosure statement and ballot were mailed to the partners in November 2014. In December 2014 the Bankruptcy Court held a confirmation hearing and issued its final approval of the plan and settlement agreement. Thereafter, PDC deposited such monies into escrow. On December 31, 2014 the monies were released to the partnerships from escrow and distributed in accordance with the plan. In 2014, PDC recorded a litigation charge of $8.8 million related to this matter, included in general and administrative expense in the consolidated statements of operations. +Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to avoid environmental contamination and mitigate the risks from environmental contamination. We conduct periodic reviews to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. As of December 31, 2014 and December 31, 2013 , we had accrued environmental liabilities in the amount of $0.8 million and $5.4 million , respectively, included in other accrued expenses on the consolidated balance sheets. We are not aware of any environmental claims existing as of December 31, 2014 which have not been provided for or would otherwise have a material impact on our financial statements. However, there can be no assurance that current regulatory requirements will not change or unknown past non-compliance with environmental laws will not be discovered on our properties. +Lease Agreements. We entered into operating leases, principally for the leasing of natural gas compressors, office space and general office equipment. +The following table presents the minimum future lease payments under the non-cancelable operating leases as of December 31, 2014 : +Year Ending December 31, +2015 +2016 +2017 +2018 +2019 +Thereafter +Total +(in thousands) +Minimum Lease Payments +$ +2,517 +$ +2,285 +$ +2,099 +$ +1,908 +$ +1,937 +$ +2,091 +$ +12,837 +Operating lease expense for the years ended 2014 , 2013 and 2012 was $7.0 million , $7.0 million and $6.1 million , respectively. +Employment Agreements with Executive Officers . Each of our senior executive officers may be entitled to a severance payment and certain other benefits upon the termination of the officer's employment pursuant to the officer's employment agreement and/or the Company's executive severance compensation plan. The nature and amount of such benefits would vary based upon, among other things, whether the termination followed a change of control of the Company. +NOTE 12 - COMMON STOCK +Sale of Equity Securities +In August 2013 , we completed a public offering of 5,175,000 shares of our common stock, par value $0.01 per share, at a price to us of $53.37 per share. Net proceeds of the offering were approximately $275.8 million , after deducting offering expenses and underwriting discounts, of which $51,750 is included in common shares-par value and approximately $275.8 million is included in APIC on the consolidated balance sheets. The shares were issued pursuant to an effective shelf registration statement on Form S-3 filed with the SEC in January 2012. +In May 2012 , we completed a public offering of 6,500,000 shares of our common stock at an offering price of $26.50 per share. Net proceeds of the offering were approximately $164.5 million , after deducting underwriting discounts and commissions and offering expenses, of which $65,000 is included in common shares-par value and $164.4 million is included in APIC on the consolidated balance sheets. The shares were issued pursuant to an effective shelf registration statement on Form S-3 filed with the SEC in January 2012. +77 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Stock-Based Compensation Plans +2010 Long-Term Equity Compensation Plan . In June 2010 , our shareholders approved a long-term equity compensation plan for our employees and non-employee directors (the "2010 Plan"). The plan was amended in June 2013. In accordance with the 2010 Plan, up to 3,000,000 new shares of our common stock are authorized for issuance. Shares issued may be either authorized but unissued shares, treasury shares or any combination of these shares. Additionally, the 2010 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited or, in the case of stock appreciation rights ("SARs"), paid out in the form of cash. Awards may be issued to our employees in the form of incentive or non-qualified stock options, SARs, restricted stock, restricted stock units ("RSUs"), performance shares and performance units, and to our non-employee directors in the form of non-qualified stock options, SARs, restricted stock and RSUs. Awards may vest over periods set at the discretion of the Compensation Committee of our Board of Directors (the "Compensation Committee") with certain minimum vesting periods. With regard to incentive or non-qualified stock options and SARs, awards have a maximum exercisable period of ten years. In no event may an award be granted under the 2010 Plan on or after April 1, 2020. As of December 31, 2014 , 1,401,953 shares remain available for issuance pursuant to the 2010 Plan. +2004 Long-Term Equity Compensation Plan. As approved by the shareholders in June 2004, we maintain a long-term equity compensation plan for our officers and certain key employees (the "2004 Plan"). Awards pursuant to the plan vest over periods set at the discretion of the Compensation Committee and, with regard to options, have a maximum exercisable period of ten years. We no longer issue awards pursuant to the 2004 Plan. As of December 31, 2014 , all awards granted pursuant to the 2004 Plan had vested and are exercisable through April 19, 2020. +The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented: +Year Ended December 31, +2014 +2013 +2012 +(in thousands) +Stock-based compensation expense +$ +17,518 +$ +12,880 +$ +8,495 +Income tax benefit +(5,955 +) +(4,697 +) +(3,245 +) +Net stock-based compensation expense +$ +11,563 +$ +8,183 +$ +5,250 +SARs +The SARs vest ratably over a three-year period and may be exercised at any point after vesting through ten years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance. +In January 2014 , the Compensation Committee awarded 88,248 SARs to our executive officers. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions: +Year Ended December 31, +2014 +2013 +2012 +Expected term of award +6 years +6 years +6 years +Risk-free interest rate +2.1 +% +1.0 +% +1.1 +% +Expected volatility +65.6 +% +65.5 +% +64.3 +% +Weighted-average grant date fair value per share +$ +29.96 +$ +21.96 +$ +17.61 +The expected term of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. We do not expect to pay or declare dividends in the foreseeable future. +78 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the changes in our SARs: +Year Ended December 31, +2014 +2013 +2012 +Number of +SARs +Weighted-Average +Exercise +Price +Average Remaining Contractual +Term (in years) +Aggregate Intrinsic +Value (in thousands) +Number of +SARs +Weighted-Average +Exercise +Price +Aggregate Intrinsic +Value (in thousands) +Number of +SARs +Weighted-Average +Exercise +Price +Aggregate Intrinsic +Value (in thousands) +Outstanding beginning of year, January 1, +190,763 +$ +33.77 +8.2 +$ +3,711 +118,832 +$ +30.80 +$ +486 +50,471 +$ +31.61 +$ +341 +Awarded +88,248 +49.57 +— +— +87,078 +37.18 +— +68,361 +30.19 +— +Exercised +— +— +— +— +(15,147 +) +30.06 +425 +— +— +— +Outstanding at December 31, +279,011 +38.77 +7.8 +1,472 +190,763 +33.77 +3,711 +118,832 +30.80 +486 +Exercisable at December 31, +139,334 +36.27 +7.3 +982 +51,922 +29.97 +1,207 +27,458 +28.84 +187 +Total compensation cost related to SARs granted, net of estimated forfeitures, and not yet recognized in our consolidated statements of operations as of December 31, 2014 , was $2.3 million . The cost is expected to be recognized over a weighted-average period of 1.7 years. +Restricted Stock Awards +Time-Based Awards. The fair value of the time-based restricted shares is amortized ratably over the requisite service period, primarily three or four years. The time-based shares vest ratably on each annual anniversary following the grant date that a participant is continuously employed. +In January 2014 , the Compensation Committee awarded a total of 104,467 time-based restricted shares to our executive officers that vest ratably over the three year period ending on January 16, 2017. +The following table presents the changes in non-vested time-based awards during 2014 : +Shares +Weighted-Average +Grant-Date +Fair Value +Non-vested at December 31, 2013 +651,781 +$ +36.36 +Granted +291,370 +56.45 +Vested +(328,071 +) +36.26 +Forfeited +(50,748 +) +45.04 +Non-vested at December 31, 2014 +564,332 +46.02 +As of/Year Ended December 31, +2014 +2013 +2012 +(in thousands, except per share data) +Total intrinsic value of time-based awards vested +$ +18,278 +$ +13,640 +$ +5,950 +Total intrinsic value of time-based awards non-vested +23,290 +34,688 +21,470 +Market price per common share as of December 31, +41.27 +53.22 +33.21 +Weighted-average grant date fair value per share +56.45 +45.53 +26.59 +Total compensation cost related to non-vested time-based awards, net of estimated forfeitures, and not yet recognized in our consolidated statements of operations as of December 31, 2014 was $17.0 million . This cost is expected to be recognized over a weighted-average period of 1.8 years. +Market-Based Awards. The fair value of the market-based restricted shares is amortized ratably over the requisite service period, primarily three years. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of five years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. +79 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +In January 2014 , the Compensation Committee awarded a total of 42,151 market-based restricted shares to our executive officers. In addition to continuous employment, the vesting of these shares is contingent on the Company's total shareholder return ("TSR"), which is essentially the Company’s stock price change including any dividends, as compared to the TSR of a set group of 15 peer companies. The shares are measured over a three-year period ending on December 31, 2016 and can result in a payout between 0% and 200% of the total shares awarded. The weighted-average grant date fair value per market-based share for these awards granted was computed using the Monte Carlo pricing model using the following assumptions: +Year Ended December 31, +2014 +2013 +Expected term of award +3 years +3 years +Risk-free interest rate +0.8 +% +0.4 +% +Expected volatility +55.2 +% +56.6 +% +Weighted-average grant date fair value per share +$ +56.87 +$ +49.04 +The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our historical volatility. +The following table presents the change in non-vested market-based awards during 2014 : +Shares +Weighted-Average +Grant-Date +Fair Value per Share +Non-vested at December 31, 2013 +72,111 +$ +43.75 +Granted +42,151 +56.87 +Vested +(30,541 +) +36.54 +Non-vested at December 31, 2014 +83,721 +52.98 +As of/Year Ended December 31, +2014 +2013 +2012 +(in thousands, except per share data) +Total intrinsic value of market-based awards vested +$ +1,260 +$ +724 +$ +— +Total intrinsic value of market-based awards non-vested +3,455 +3,838 +1,352 +Market price per common share as of December 31, +41.27 +53.22 +33.21 +Weighted-average grant date fair value per share +56.87 +49.04 +36.54 +Total compensation cost related to non-vested market-based awards, net of estimated forfeitures, and not yet recognized in our consolidated statements of operations as of December 31, 2014 was $2.3 million . This cost is expected to be recognized over a weighted-average period of 1.7 years. +Stock Option Awards +We have granted stock options pursuant to various stock compensation plans. Outstanding options expire ten years from the date of grant and become exercisable ratably over a four year period . We have not issued any new stock option awards since 2006. As of December 31, 2014 , all compensation cost related to stock options has been fully recognized in our consolidated statements of operations. +80 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the changes in our stock option awards. The aggregate intrinsic value of options outstanding for each period presented was immaterial: +Year Ended December 31, +2014 +2013 +2012 +Number of +Shares +Underlying +Options +Weighted-Average +Exercise +Price +Per Share +Weighted- Average +Remaining +Contractual +Term (in years) +Aggregate Intrinsic +Value (in thousands) +Number of +Shares +Underlying +Options +Weighted-Average +Exercise +Price +Per Share +Number of +Shares +Underlying +Options +Weighted-Average +Exercise +Price +Per Share +Outstanding beginning of year, January 1, +3,523 +$ +44.95 +2.2 +$ +— +6,973 +$ +41.09 +6,973 +$ +41.09 +Exercised +— +— +— +— +(3,450 +) +37.15 +— +— +Outstanding end of year, December 31, +3,523 +44.95 +1.2 +— +3,523 +44.95 +6,973 +41.09 +Exercisable at December 31, +3,523 +44.95 +1.2 +— +3,523 +44.95 +6,973 +41.09 +Treasury Share Purchases +In accordance with our stock-based compensation plans, employees and directors may surrender shares of the Company's common stock to pay tax withholding obligations upon the vesting and exercise of share-based awards. Shares acquired that had been issued pursuant to the 2004 Plan are retired, while those issued pursuant to the 2010 Plan are reissued to service awards. For shares that are retired, we first charge any excess of cost over the par value to APIC to the extent we have amounts in APIC, with any remaining excess cost charged to retained earnings. For shares reissued to service awards under the 2010 Plan, shares are recorded at cost and upon reissuance we reduce the carrying value of shares acquired and held pursuant to the 2010 Plan by the weighted-average cost per share with an offsetting charge to APIC. During the year ended December 31, 2014 , we acquired 97,646 shares pursuant to our stock-based compensation plans for payment of tax liabilities, of which 703 shares were retired and 83,208 shares reissued and 13,735 shares are available for reissuance pursuant to our 2010 Plan. +Shareholders’ Rights Agreement +In 2007, we entered into a rights agreement. The rights agreement is designed to improve the ability of our Board to protect the interest of our shareholders in the event of an unsolicited takeover attempt. Our Board declared a dividend of one right for each outstanding share of our common stock. The right dividend was paid to shareholders of record in September 2007 . A "distribution date," as defined in the rights agreement, can occur after any individual shareholder exceeds 15% ownership of our outstanding common stock. In certain circumstances, the right entitles each holder, other than an "acquiring person" (as defined in the agreement), to purchase shares of our common stock (or, in certain circumstances, cash, property or other securities) having a then-current value equal to two times the exercise price of the right (i.e., for the $240 exercise price, the rights holder receives $480 worth of common stock). The exercise price is subject to adjustment for various corporate actions which affect all shareholders, such as a stock split. The rights agreement and all rights will expire in September 2017 . +Preferred stock +We are authorized, pursuant to shareholder approval in 2008 , to issue 50,000,000 shares of preferred stock, par value $0.01, which may be issued in one or more series, with such rights, preferences, privileges and restrictions as shall be fixed by our Board from time to time. As of December 31, 2014 , no preferred shares had been issued. +NOTE 13 - EARNINGS PER SHARE +Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, stock options, convertible notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. +81 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents a reconciliation of the weighted-average diluted shares outstanding: +Year Ended December 31, +2014 +2013 +2012 +(in thousands) +Weighted-average common shares outstanding - basic +35,784 +32,426 +27,677 +Dilutive effect of: +Restricted stock +279 +— +— +Stock options +1 +— +— +SARs +45 +— +— +Non-employee director deferred compensation +5 +— +— +Convertible notes +564 +— +— +Weighted-average common shares and equivalents outstanding - diluted +36,678 +32,426 +27,677 +For 2013 and 2012, we reported a net loss. As a result, our basic and diluted weighted-average common shares outstanding were the same as the effect of the common share equivalents was anti-dilutive. +The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect: +Year Ended December 31, +2014 +2013 +2012 +(in thousands) +Weighted-average common share equivalents excluded from diluted earnings +per share due to their anti-dilutive effect: +Restricted stock +8 +823 +694 +SARs +26 +72 +116 +Stock options +— +7 +7 +Non-employee director deferred compensation +— +4 +3 +Convertible notes +— +518 +— +Total anti-dilutive common share equivalents +34 +1,424 +820 +In November 2010, we issued our Convertible Notes, which give the holders the right to convert the aggregate principal amount into 2.7 million shares of our common stock at a conversion price of $42.40 per share. The Convertible Notes could be included in the dilutive earnings per share calculation using the treasury stock method if the average market share price exceeds the $42.40 conversion price during the period presented. Shares issuable upon conversion of the Convertible Notes were included in the diluted earnings per share calculation for the year ended December 31, 2014 as the average market price during the period exceeded the conversion price. Shares issuable upon conversion of the Convertible Notes were excluded from the diluted earnings per share calculation for the year ended December 31, 2013 as the effect would be anti-dilutive to our earnings per share. Shares issuable upon conversion of the Convertible Notes were excluded from the diluted earnings per share calculation for the year ended December 31, 2012 as the conversion price was greater than the average market price of our common stock during the period. +NOTE 14 - ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS +The tables below set forth selected financial information related to net assets divested and operating results related to discontinued operations. Net assets held for sale represents the assets that were or are expected to be sold, net of liabilities, that were assumed by the purchaser. While the reclassification of revenues and expenses related to discontinued operations for prior periods had no impact upon previously reported net earnings, the consolidated statements of operations table presents the revenues and expenses that were reclassified from the specified consolidated statements of operations line items to discontinued operations. +82 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents consolidated balance sheet data related to net assets held for sale: +Consolidated balance sheet +As of December 31, 2014 +As of December 31, 2013 +Assets +Current assets +Cash and cash equivalents +$ +— +$ +601 +Other current assets +— +7,060 +Assets held for sale - current +— +7,661 +Non-current assets +Properties and equipment, net +2,874 +175,244 +Other assets +— +6,892 +Assets held for sale - non-current +2,874 +182,136 +Liabilities +Liabilities held for sale - current +— +12,069 +Non-current liabilities +Long-term debt +— +52,000 +Asset retirement obligation +— +2,234 +Other liabilities +— +1,681 +Liabilities held for sale - non-current +— +55,915 +Net Assets +$ +2,874 +$ +121,813 +Assets held for sale as of December 31, 2014 represents the carrying value of approximately 12 acres of land located adjacent to a regional office. Assets held for sale as of December 31, 2013 represents our proportionate share of PDCM's net assets and the carrying value of approximately 12 acres of land located adjacent to our Bridgeport, West Virginia, regional headquarters. +83 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents consolidated statements of operations data related to our discontinued operations: +Year Ended December 31, +Consolidated statements of operations - discontinued operations +2014 +2013 +2012 +(in thousands) +Revenues +Crude oil, natural gas and NGLs sales +$ +24,149 +$ +39,001 +$ +46,793 +Sales from natural gas marketing +— +2,825 +1,708 +Commodity price risk management gain (loss), net +(1,085 +) +14 +3,060 +Well operations, pipeline income and other +48 +922 +1,926 +Total revenues +23,112 +42,762 +53,487 +Costs, expenses and other +Production costs +7,120 +16,515 +27,770 +Cost of natural gas marketing +— +2,673 +1,529 +Impairment of crude oil and natural gas properties +433 +929 +163,129 +Depreciation, depletion and amortization +9,128 +13,894 +55,768 +Other +3,445 +7,266 +8,791 +(Gain) loss on sale of properties and equipment +(76,479 +) +1,700 +(24,090 +) +Total costs, expenses and other +(56,353 +) +42,977 +232,897 +Interest expense +(2,222 +) +(1,755 +) +(782 +) +Interest income +194 +10 +1 +Income (loss) from discontinued operations +77,437 +(1,960 +) +(180,191 +) +Provision for income taxes +(29,263 +) +770 +68,834 +Income (loss) from discontinued operations, net of tax +$ +48,174 +$ +(1,190 +) +$ +(111,357 +) +The following table presents supplemental cash flows information related to our 50% ownership interest in PDCM, which is classified as discontinued operations: +Year Ended December 31, +Supplemental cash flows information - discontinued operations +2014 +2013 +2012 +(in thousands) +Cash flows from investing activities: +Capital expenditures +$ +(17,253 +) +$ +(45,277 +) +$ +(25,530 +) +Significant non-cash investing items: +Change in accounts payable related to purchases of properties and equipment +(5,727 +) +(4,738 +) +(3,592 +) +Appalachian Basin. In December 2013, we divested our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin crude oil and natural gas properties previously owned directly by us, as well as through our proportionate share of PDCM, for aggregate consideration of approximately $20.6 million , of which our share of the proceeds was approximately $5.1 million . We received our proportionate share of cash proceeds and a note receivable. Concurrent with the closing of the transaction, our $6.7 million irrevocable standby letter of credit and an agreement for firm transportation services was released and novated to the buyer. +In October 2014 , we completed the sale of our entire 50% ownership interest in PDCM to an unrelated third-party for aggregate consideration, after our share of PDCM's debt repayment and other working capital adjustments, of approximately $192 million , comprised of approximately $153 million in net cash proceeds and a promissory note due in 2020 of approximately $39 million . The transaction included the buyer's assumption of our share of the firm transportation commitment related to the assets owned by PDCM, as well as our share of PDCM's natural gas hedging positions for the years 2014 through 2017. The divestiture resulted in a pre-tax gain of $76.3 million . Proceeds from the divestiture were used to reduce outstanding borrowings on our revolving credit facility and to fund a portion of our 2014 capital budget. As the divestiture represents a strategic shift that will have a major effect on our operations as our organization structure will no longer have joint venture partners and we no longer have dry gas assets, our proportionate share of PDCM's Marcellus Shale results of operations have been separately reported as discontinued operations in the consolidated statements of operations for all periods presented. +84 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Piceance Basin and NECO. In February 2013, we entered into a purchase and sale agreement pursuant to which we agreed to sell to an unrelated third-party our Piceance Basin, NECO and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets. Additionally, certain firm transportation commitments and natural gas hedging positions were assumed by the buyer. In June 2013, this divestiture was completed with total consideration of approximately $177.6 million , with an additional $17.0 million paid to our non-affiliated investor partners in our affiliated partnerships. The sale resulted in a pre-tax loss of $2.3 million . The proceeds from the asset divestiture were used to pay down our revolving credit facility and to fund a portion of our 2013 capital budget. Following the sale, we do not have significant continuing involvement in the operations of, or cash flows from, the Piceance Basin and NECO oil and gas properties. Accordingly, the results of operations related to these assets have been separately reported as discontinued operations in the consolidated statements of operations for all periods presented. The sale of our other non-core Colorado oil and gas properties did not meet the requirements to be accounted for as discontinued operations. +NOTE 15 - ACQUISITIONS +The following table presents the adjusted purchase price and the allocations thereof, based on our estimates of fair value, for the acquisition of crude oil and natural gas properties during 2012: +Year Ended December 31, 2012 +(in thousands) +Total acquisition cost +$ +304,643 +Recognized amounts of identifiable assets acquired and liabilities assumed: +Assets acquired: +Crude oil and natural gas properties - proved +$ +180,696 +Crude oil and natural gas properties - unproved +151,428 +Other assets +3,631 +Total assets acquired +335,755 +Liabilities assumed: +Asset retirement obligation +14,833 +Other accrued expenses +9,574 +Other liabilities +6,705 +Total liabilities assumed +31,112 +Total identifiable net assets acquired +$ +304,643 +The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows and a market-based weighted-average cost of capital rate. These inputs require significant judgments and estimates by management at the time of the valuation and are sensitive and subject to change. +Merit Acquisition. In June 2012 , we completed the acquisition of certain Wattenberg Field oil and natural gas properties, leasehold mineral interests and related assets located in Weld, Adams and Boulder Counties, Colorado from affiliates of Merit Energy. The aggregate purchase price of these properties was approximately $304.6 million . We financed the purchase with cash from the May 2012 offering of our common stock and a draw on our revolving credit facility. +This acquisition was accounted for under the acquisition method of accounting. Accordingly, we conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. +Pro Forma Information. The results of operations for the Merit Acquisition have been included in our consolidated financial statements since the June 2012 closing date. The following unaudited pro forma financial information presents a summary of the consolidated results of operations for the years ended December 31, 2012 assuming the Merit Acquisition had been completed as of January 1, 2012, including adjustments to reflect the values assigned to the net assets acquired. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the Merit Acquisition had been effective as of these dates, or of future results. +85 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Year Ended December 31, 2012 +(in thousands, except per share amounts) +Total revenues +$ +370,488 +Total costs, expenses and other +521,178 +Net income (loss) +$ +(119,343 +) +Earnings per share: +Basic +$ +(4.31 +) +Diluted +$ +(4.31 +) +NOTE 16 - TRANSACTIONS WITH AFFILIATES +PDCM and Affiliated Partnerships. Our Gas Marketing segment marketed the natural gas produced by our affiliated partnerships and, until the fourth quarter of 2014, by PDCM. Our cost of natural gas marketing includes $1.3 million and $0.5 million in 2013 and 2012, respectively, related to the marketing of natural gas on behalf of our affiliated partnerships and $23.2 million , $18.1 million and $10.9 million in 2014 , 2013 and 2012 , respectively, related to the marketing of natural gas on behalf of PDCM. +Amounts due from/to affiliates primarily relate to certain well operating and administrative costs incurred on behalf of our affiliated partnerships and will be recouped through future partnership revenue distributions. Prior to October 2014, amounts due from/to affiliates also included amounts billed for certain well operating and administrative services provided to PDCM. Amounts billed to PDCM for these services were $5.7 million , $14.5 million and $12.1 million in 2014 , 2013 and 2012 , respectively. Our consolidated statements of operations include only our proportionate share of these billings. All amounts billed to PDCM for operating and administrative services in 2014 have been collected. Accordingly, we had no amounts due from PDCM as of December 31, 2014 compared to $4.6 million as of December 31, 2013. +NOTE 17 - BUSINESS SEGMENTS +We separate our operating activities into two segments: Oil and Gas Exploration and Production and Gas Marketing. All material inter-company accounts and transactions between segments have been eliminated. +Oil and Gas Exploration and Production. Our Oil and Gas Exploration and Production segment includes all of our crude oil and natural gas properties. The segment represents revenues and expenses from the production and sale of crude oil, natural gas and NGLs. Segment revenue includes crude oil, natural gas and NGLs sales, commodity price risk management, net, and well operation and pipeline income. Segment income (loss) consists of segment revenue less production cost, exploration expense, impairment of crude oil and natural gas properties, direct general and administrative expense and DD&A expense. Segment DD&A expense was $188.5 million , $111.6 million and $86.3 million in 2014 , 2013 and 2012 , respectively. +Gas Marketing. Our Gas Marketing segment purchases, aggregates and resells natural gas produced by us and others. Segment income (loss) primarily represents sales from natural gas marketing and direct interest income less costs of natural gas marketing, transportation and direct general and administrative expense. +Unallocated amounts. Unallocated income includes unallocated other revenue, less corporate general administrative expense, corporate DD&A expense, interest income and interest expense. Unallocated assets include assets utilized for corporate, general and administrative purposes, as well as assets not specifically included in our two business segments. +86 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following tables present our segment information: +2014 +2013 +2012 +(in thousands) +Year Ended December 31, +Segment revenues: +Oil and gas exploration and production +$ +784,636 +$ +322,878 +$ +261,765 +Gas marketing +71,571 +69,787 +45,371 +Total revenues +$ +856,207 +$ +392,665 +$ +307,136 +Segment income (loss) before income taxes: +Oil and gas exploration and production +$ +344,149 +$ +81,913 +$ +101,324 +Gas marketing +(445 +) +(297 +) +348 +Unallocated +(166,476 +) +(114,579 +) +(132,360 +) +Income (loss) before income taxes +$ +177,228 +$ +(32,963 +) +$ +(30,688 +) +Expenditures for segment long-lived assets: +Oil and gas exploration and production +$ +623,912 +$ +403,227 +$ +656,443 +Unallocated +4,680 +1,379 +3,509 +Total +$ +628,592 +$ +404,606 +$ +659,952 +As of December 31, +Segment assets: +Oil and gas exploration and production +$ +2,254,751 +$ +1,751,106 +Gas marketing +6,979 +20,342 +Unallocated +75,984 +63,958 +Assets held for sale +2,874 +189,797 +Total assets +$ +2,340,588 +$ +2,025,203 +87 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +SUPPLEMENTAL INFORMATION - UNAUDITED +CRUDE OIL AND NATURAL GAS INFORMATION - UNAUDITED +Net Proved Reserves +All of our crude oil, natural gas and NGLs reserves are located in the U.S. We utilize the services of independent petroleum engineers to estimate our crude oil, natural gas, condensate and NGL reserves. As of December 31, 2014 , 2013 and 2012 , all of our estimates of proved reserves were based on reserve reports prepared by Ryder Scott. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC. +Proved reserves estimates may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. Our net proved reserve estimates have been adjusted as necessary to reflect all contractual agreements, royalty obligations and interests owned by others at the time of the estimate. Proved developed reserves are the quantities of crude oil, natural gas and NGLs expected to be recovered through existing wells with existing equipment and operating methods. In some cases, proved undeveloped reserves may require substantial new investments in additional wells and related facilities. +The price used to estimate our reserves, by commodity, are presented below. +Price Used to Estimate Reserves +As of December 31, +Crude Oil +(per Bbl) +Natural Gas +(per Mcf) +NGLs +(per Bbl) +2014 +$ +84.65 +$ +3.92 +$ +32.27 +2013 +82.18 +3.22 +29.92 +2012 +87.51 +2.35 +28.02 +88 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +The following tables present the changes in our estimated quantities of proved reserves: +Crude Oil, Condensate (MBbls) +Natural Gas +(MMcf) +NGLs +(MBbls) +Total +(MBoe) +Proved Reserves: +Proved reserves, January 1, 2012 (1) +37,636 +672,145 +19,588 +169,248 +Revisions of previous estimates +(6,729 +) +(289,436 +) +(3,671 +) +(58,639 +) +Extensions, discoveries and other additions +27,482 +172,933 +11,637 +67,941 +Purchases of reserves +10,801 +87,212 +8,084 +33,420 +Dispositions +(7,854 +) +(6,406 +) +(1,970 +) +(10,891 +) +Production +(2,026 +) +(32,410 +) +(841 +) +(8,269 +) +Proved reserves, December 31, 2012 (2) +59,310 +604,038 +32,827 +192,810 +Revisions of previous estimates +(18,420 +) +(117,068 +) +(8,549 +) +(46,480 +) +Extensions, discoveries and other additions +55,759 +365,563 +25,249 +141,935 +Purchases of reserves +343 +2,894 +217 +1,043 +Dispositions +(252 +) +(94,927 +) +(30 +) +(16,104 +) +Production +(2,910 +) +(20,860 +) +(1,043 +) +(7,430 +) +Proved reserves, December 31, 2013 (3) +93,830 +739,640 +48,671 +265,774 +Revisions of previous estimates +(29,777 +) +(149,064 +) +(10,204 +) +(64,825 +) +Extensions, discoveries and other additions +40,792 +202,957 +23,411 +98,029 +Purchases of reserves +5 +43 +5 +17 +Dispositions +(13 +) +(237,306 +) +(8 +) +(39,572 +) +Production +(4,322 +) +(19,298 +) +(1,756 +) +(9,294 +) +Proved reserves, December 31, 2014 +100,515 +536,972 +60,119 +250,129 +Proved Developed Reserves, as of: +January 1, 2012 (1) +16,910 +299,369 +11,753 +78,558 +December 31, 2012 (2) +20,412 +281,925 +14,353 +81,753 +December 31, 2013 (3) +23,997 +220,387 +14,825 +75,553 +December 31, 2014 +26,798 +186,633 +17,002 +74,905 +Proved Undeveloped Reserves, as of: +January 1, 2012 (1) +20,726 +372,776 +7,835 +90,690 +December 31, 2012 (2) +38,898 +322,113 +18,474 +111,058 +December 31, 2013 (3) +69,833 +519,253 +33,846 +190,221 +December 31, 2014 +73,717 +350,339 +43,117 +175,224 +__________ +(1) +Includes estimated reserve data related to our Permian Basin assets, which were divested in February 2012. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Permian Basin assets. Total proved reserves included 7,825 MBbls of crude oil, 6,242 MMcf of natural gas and 1,970 MBbls of NGLs, for an aggregate of 10,835 Mboe of crude oil equivalent, related to our Permian assets. Total proved developed reserves related to those assets included 1,815 MBbls, 1,750 MMcf, 550 MBbls and 2,657 MBoe, respectively, and proved undeveloped reserves included 6,010 MBbls, 4,492 MMcf, 1,420 MBbls and 8,179 MBoe, respectively. +(2) +Includes estimated reserve data related to our Piceance and NECO assets, which were divested in June 2013. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Piceance and NECO assets. Total proved reserves include 148 MBbls of crude oil and 83,656 MMcf of natural gas, for an aggregate of 14,091 MBoe of crude oil equivalent related to our Piceance and NECO assets. There were no proved undeveloped reserves attributable to the Piceance and NECO assets as of December 31, 2012. +(3) +Includes estimated reserve data related to our Marcellus Shale assets, which were divested in October 2014. See Note 14, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Marcellus Shale assets. Total proved reserves included 235,950 MMcf of natural gas, for an aggregate of 39,325 Mboe of crude oil equivalent, related to our Marcellus Shale assets. Total proved developed reserves related to those assets included 53,904 MMcf and 8,984 MBoe, respectively, and proved undeveloped reserves included 182,046 MMcf and 30,341 MBoe, respectively. +89 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Developed +Undeveloped +Total +(MBoe) +Beginning proved reserves, January 1, 2012 +78,558 +90,690 +169,248 +Undeveloped reserves converted to developed +7,655 +(7,655 +) +— +Revisions of previous estimates +(18,318 +) +(40,321 +) +(58,639 +) +Extensions, discoveries and other additions +11,298 +56,643 +67,941 +Purchases of reserves +13,542 +19,878 +33,420 +Dispositions +(2,713 +) +(8,178 +) +(10,891 +) +Production +(8,269 +) +— +(8,269 +) +Ending proved reserves, December 31, 2012 +81,753 +111,057 +192,810 +Undeveloped reserves converted to developed +3,212 +(3,212 +) +— +Revisions of previous estimates +(6,751 +) +(39,729 +) +(46,480 +) +Extensions, discoveries and other additions +19,830 +122,105 +141,935 +Purchases of reserves +1,043 +— +1,043 +Dispositions +(16,104 +) +— +(16,104 +) +Production +(7,430 +) +— +(7,430 +) +Ending proved reserves, December 31, 2013 +75,553 +190,221 +265,774 +Undeveloped reserves converted to developed +12,730 +(12,730 +) +— +Revisions of previous estimates +(22,827 +) +(41,998 +) +(64,825 +) +Extensions, discoveries and other additions +27,957 +70,072 +98,029 +Purchases of reserves +17 +— +17 +Dispositions +(9,231 +) +(30,341 +) +(39,572 +) +Production +(9,294 +) +— +(9,294 +) +Ending proved reserves, December 31, 2014 +74,905 +175,224 +250,129 +2014 Activity. Overall, our proved reserves decreased by 16 MMBoe as of December 31, 2014 as compared to December 31, 2013. In 2014, we produced 9.3 MMBoe and we recorded a downward revision of our previous estimate of proved reserves of approximately 65 MMBoe. The revision was primarily related to decreases of approximately 55 MMBoe for adjustments to our development plans in the Wattenberg Field, 8 MMBoe of Utica Shale PUDs that are no longer in our drilling plans and 2 MMBoe due to various other factors. Discoveries and extensions resulted in an increase of approximately 98 MMBoe in 2014, of which approximately 96 MMBoe was added in the Wattenberg Field, primarily related to Niobrara and Codell projects, and approximately 2 MMBoe was added in the Utica Shale. The reserve increases in the Wattenberg Field are primarily due to the addition of approximately 16 MMBoe of previously unbooked locations which were developed in the current year, 78 MMBoe due to new proved undeveloped reserves as a result of adjustments in well spacing in the Wattenberg Field and our development plan and 2 MMBoe due to various other factors. We acquired minimal proved reserves. We divested a total of 40 MMBoe in 2014, primarily from our Marcellus Shale assets. Based on the economic conditions on December 31, 2014, our approved development plan provides for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. Our 2014 drilling program focused on testing increased well density in the Wattenberg Field. This resulted in a PUD conversion rate of approximately 7% and allowed us to add considerable PUD reserves to the 2014 reserve report as noted above. Because we expect to continue to drill primarily proven downspaced Wattenberg Field locations in 2015, our PUD conversion rate is expected to be approximately 16% . The balance of the locations are scheduled to be drilled over the remaining four years with total PUD conversion rates of 27% in 2016, 22% in 2017, 19% in 2018 and 16% in 2019. This level of capital spending is consistent with the most recent years and our outlook for future activity. +2013 Activity. Overall, our proved reserves increased by 73 MMBoe as of December 31, 2013 as compared to December 31, 2012. In 2013, we recorded a downward revision of our previous estimate of proved reserves of approximately 46 MMBoe. The revision was primarily due to a decrease of approximately 55 MMBoe of which approximately 32 MMBoe is due to adjustments in previous PUD well spacing plans in the Wattenberg Field and the Marcellus Shale (which were offset by replacements in the extension category), approximately 9 MMBoe is due to expired leases, approximately 11 MMBoe is due to our shift from vertical to horizontal drilling in the Wattenberg Field and approximately 3 MMBoe is to remove Wattenberg Field PUDs that are no longer in our core drilling area. This was partially offset by an increase of 1 MMBoe due to higher gas pricing and lower operating costs in the vertical Wattenberg Field wells and horizontal Marcellus Shale wells, an increase of approximately 3 MMBoe due to non-acquisition interest adjustments, approximately 2 MMBoe due to asset performance and approximately 2 MMBoe due to production from wells that were either uneconomic, added or divested in the current year. Discoveries and extensions of approximately 142 MMBoe in 2013 are due to the addition of approximately 17 MMBoe of proved developed reserves from non-PUD drilling and the addition of approximately 125 MMBoe of new proved undeveloped reserves including 32 MMBoe due to adjustments in well spacing in the Wattenberg Field and the Marcellus Shale. Approximately 18 MMBoe was added in the Marcellus Shale, approximately 14 MMBoe was added in the Utica Shale and approximately 110 MMBoe was added in the Wattenberg Field, mostly related to the Niobrara and Codell formations. We acquired approximately 1 MMBoe of proved reserves due to an acquisition in the Appalachian-Marcellus Shale area and the acquisition of non-affiliated investor partner interests in shallow Upper Devonian wells. We divested a total of 16 MMBoe in 2013, primarily our Piceance +90 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Basin, NECO and shallow Upper Devonian (non-Marcellus Shale) assets. Based on the economic conditions on December 31, 2013, our approved development plan provides for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. Our 2013 drilling program focused on locations that were not included in proved undeveloped reserves in the December 31, 2012 reserve report due to increased well density testing in the Wattenberg Field. The success of this increased well density testing allowed us to add considerable PUD reserves in the 2013 reserve report. +2012 Activity. In 2012, we recorded a downward revision of our previous estimate of proved reserves of approximately 59 MMBoe. The revision was primarily due to a decrease of approximately 40 MMBoe due to lower gas pricing, mostly related to the Piceance Basin, approximately 1 MMBoe due to increased operating costs, approximately 8 MMBoe due to adjustments for geological reasons and approximately 13 MMBoe due to the removal of certain proved undeveloped reserves to comply with the SEC's five-year rule. This was partially offset by an increase of approximately 0.5 MMBoe due to non-acquisition interest adjustments and approximately 2 MMBoe due to asset performance. Discoveries and extensions of approximately 68 MMBoe in 2012 are due to the drilling of 44 gross horizontal wells and the addition of new proved undeveloped reserves. Approximately 10 MMBoe were added in the Marcellus Shale and approximately 59 MMBoe were added in the Wattenberg Field, mostly related to the Niobrara formation. We acquired approximately 33 MMBoe of proved reserves due to an acquisition in the Wattenberg Field. We divested a total of 11 MMBoe in 2012, primarily our core Permian Basin assets. Based on the economic conditions on December 31, 2012, our approved development plan provided for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. Based on our decision to drill predominantly horizontal wells in 2012, our drilling program focused on locations that were not included in proved undeveloped reserves in the December 2011 reserve report. By focusing on non-PUD drilling locations in 2012, we were able to add considerable PUD reserves in the 2012 reserve report. +Results of Operations for Crude Oil and Natural Gas Producing Activities +The results of operations for crude oil and natural gas producing activities are presented below. The results include activities related to both continuing and discontinued operations and exclude activities related to natural gas marketing and well operations and pipeline services. +Year Ended December 31, +2014 +2013 +2012 +(in thousands) +Revenue: +Crude oil, natural gas and NGLs sales +$ +495,562 +$ +379,796 +$ +274,783 +Commodity price risk management gain, net +309,219 +(23,905 +) +32,339 +804,781 +355,891 +307,122 +Expenses: +Production costs +90,744 +81,365 +77,537 +Exploration expense +948 +7,071 +22,605 +Impairment of proved crude oil and natural gas properties +163,965 +53,438 +162,287 +Depreciation, depletion, and amortization +201,656 +124,202 +146,879 +Accretion of asset retirement obligations +3,455 +4,747 +4,060 +(Gain) loss on sale of properties and equipment +(75,972 +) +3,722 +(24,273 +) +384,796 +274,545 +389,095 +Results of operations for crude oil and natural gas producing +activities before provision for income taxes +419,985 +81,346 +(81,973 +) +Provision for income taxes +(163,647 +) +(29,400 +) +31,163 +Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs +$ +256,338 +$ +51,946 +$ +(50,810 +) +Production costs include those costs incurred to operate and maintain productive wells and related equipment, including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, production and severance taxes and associated administrative expenses. DD&A expense includes those costs associated with capitalized acquisition, exploration and development costs, but does not include the depreciation applicable to support equipment. The provision for income taxes is computed using effective tax rates. +91 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Costs Incurred in Crude Oil and Natural Gas Property Acquisition, Exploration and Development Activities +Costs incurred in crude oil and natural gas property acquisition, exploration and development are presented below. +Year Ended December 31, +2014 +2013 +2012 +(in thousands) +Acquisition of properties: (1) +Proved properties +$ +11,973 +$ +28,698 +$ +105,303 +Unproved properties +45,999 +3,390 +276,225 +Development costs (2) +590,855 +332,250 +233,144 +Exploration costs: (3) +Exploratory drilling +— +58,988 +18,803 +Geological and geophysical +1 +752 +1,925 +Total costs incurred +$ +648,828 +$ +424,078 +$ +635,400 +__________ +(1) +Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property. +(2) +Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells and provide facilities to extract, treat, gather and store crude oil, natural gas and NGLs. Of these costs incurred for the years ended December 31, 2014 , 2013 and 2012 , $125.2 million , $40.1 million and $62.0 million , respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. +(3) +Exploration costs - represents costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas and NGLs. +Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities +Aggregate capitalized costs related to crude oil and natural gas exploration and production activities with applicable accumulated DD&A are presented below: +As of December 31, +2014 +2013 +(in thousands) +Proved crude oil and natural gas properties +$ +2,267,165 +$ +1,677,271 +Unproved crude oil and natural gas properties +188,206 +253,463 +Uncompleted wells, equipment and facilities +137,134 +40,745 +Capitalized costs +2,592,505 +1,971,479 +Less accumulated DD&A +(808,431 +) +(507,510 +) +Capitalized costs, net +$ +1,784,074 +$ +1,463,969 +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves +The standardized measure below has been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to our year-end estimated proved reserves. Prices for each of the three years were adjusted by field for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of our commodity derivatives. Production and development costs were based on prices as of December 31 for each of the respective years presented. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service or to depreciation, depletion and amortization expense. Production and development costs include those cash flows associated with the expected ultimate settlement of our asset retirement obligation. Future estimated income tax expense is computed by applying the statutory rate in effect at the end of each year to the projected future pre-tax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits and allowances related to the properties. +The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for crude oil, natural gas and NGLs, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves. +92 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +As of December 31, +2014 +2013 +2012 +(in thousands) +Future estimated cash flows +$ +12,550,515 +$ +11,550,917 +$ +7,529,292 +Future estimated production costs +(2,816,776 +) +(2,329,836 +) +(1,690,453 +) +Future estimated development costs +(2,458,790 +) +(2,778,148 +) +(1,852,177 +) +Future estimated income tax expense +(2,336,510 +) +(2,119,615 +) +(1,230,294 +) +Future net cash flows +4,938,439 +4,323,318 +2,756,368 +10% annual discount for estimated timing of cash flows +(2,631,974 +) +(2,541,155 +) +(1,587,871 +) +Standardized measure of discounted future estimated net cash flows +$ +2,306,465 +$ +1,782,163 +$ +1,168,497 +The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows: +Year Ended December 31, +2014 +2013 +2012 +(in thousands) +Sales of crude oil, natural gas and NGLs production, net of production costs +$ +(387,789 +) +$ +(286,021 +) +$ +(194,346 +) +Net changes in prices and production costs (1) +129,213 +89,527 +95,501 +Extensions, discoveries, and improved recovery, less related costs (2) +1,444,581 +1,529,006 +632,781 +Sales of reserves (3) +(402,595 +) +(142,724 +) +(86,902 +) +Purchases of reserves (4) +238 +10,610 +296,208 +Development costs incurred during the period +161,404 +46,366 +69,198 +Revisions of previous quantity estimates (5) +(654,318 +) +(397,738 +) +(452,775 +) +Changes in estimated income taxes (6) +(221,874 +) +(381,369 +) +(131,256 +) +Net changes in future development costs +46,499 +(40,707 +) +(3,979 +) +Accretion of discount +270,389 +142,040 +124,105 +Timing and other +138,554 +44,676 +(121,247 +) +Total +$ +524,302 +$ +613,666 +$ +227,288 +__________ +(1) +Our weighted-average price, net of production costs per Boe, in our 2014 reserve report increased to $37.78 as compared to $30.82 in our 2013 reserve report. This is due to the divestiture of our Marcellus Shale reserves during 2014 which further increased our liquids as a percentage of proved reserves. Our weighted-average price, net of production costs per Boe, in our 2013 reserve report increased to $30.82 from $30.28 in our 2012 report due to the divestiture of our Piceance, NECO and our shallow Upper Devonian (non-Marcellus Shale) reserves during 2013 which increased our liquids as a percentage of proved reserves. +(2) +The 6% decrease in 2014 as compared to 2013 is primarily due to a scheduled maximum rig count of six rigs by 2016 as compared to a scheduled maximum rig count of seven in the 2013 year-end reserve report, partially offset by our increased PUD count in the Wattenberg Field resulting from successful downspacing tests in 2014. The 142% increase in 2013 as compared to 2012 is primarily due to the addition of PUDs in the Utica Shale and our continued focus on our Wattenberg Field drilling program. Our increased PUD count in the Wattenberg Field is a result of successful downspacing tests in 2013 leading to a scheduled maximum rig count of seven rigs by 2016 as compared to a scheduled maximum rig count of five in the 2012 year-end reserve report. +(3) +The increase in sales of reserves in 2014 as compared to 2013 was due to the divestiture of our Marcellus shale assets in October 2014. The increase in sales of reserves in 2013 as compared to 2012 was due to the divestiture of our Piceance and NECO assets in June 2013 and our shallow Upper Devonian (non-Marcellus Shale) assets in December of 2013. +(4) +The decrease in purchases of reserves in 2014 and 2013 as compared to the respective prior years was due to no material acquisitions having occurred. +(5) +The change in revisions of our previous quantity estimates in 2014 as compared to 2013 was primarily due to adjustments due to our drilling schedule. The change in revisions of our previous quantity estimates in 2013 as compared to 2012 was primarily due to adjustment in our drilling schedule. +(6) +The change in estimated income taxes for each year as compared to the prior year is the direct result of the significant increase in discounted future net cash flows, as the projected deferred tax rate remained relatively unchanged at approximately 38% , 38% and 38.2% for the years ended December 31, 2014, 2013 and 2012, respectively. In addition, the Company continued to capitalize and amortize the majority of its yearly capital expenditures and there were no changes in the assumptions as to the tax deductibility of beginning unamortized capital, additional current year capital or future development capital. +The data presented should not be viewed as representing the expected cash flows from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the recent average prices and current costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein. +93 +PDC ENERGY, INC. +QUARTERLY FINANCIAL INFORMATION - UNAUDITED +Quarterly financial data for the years ended December 31, 2014 and 2013 is presented below. The sum of the quarters may not equal the total of the year's net income or loss per share due to changes in the weighted-average shares outstanding throughout the year. +2014 +Quarter Ended +March 31 +June 30 +September 30 +December 31 +Year Ended +(in thousands, except per share data) +Revenues: +Crude oil, natural gas and NGLs sales +$ +120,013 +$ +131,017 +$ +120,526 +$ +99,857 +$ +471,413 +Sales from natural gas marketing +26,937 +22,415 +13,297 +8,922 +71,571 +Commodity price risk management gain (loss), net +(24,909 +) +(52,643 +) +90,213 +297,643 +310,304 +Well operations, pipeline income and other +616 +514 +520 +1,269 +2,919 +Total revenues +122,657 +101,303 +224,556 +407,691 +856,207 +Costs, expenses and other: +Production costs +18,083 +23,774 +22,754 +19,013 +83,624 +Cost of natural gas marketing +26,870 +22,428 +13,347 +9,370 +72,015 +Exploration expense +307 +276 +190 +174 +947 +Impairment of crude oil and natural gas properties +910 +848 +1,863 +159,911 +163,532 +General and administrative expense +22,484 +39,440 +34,625 +19,310 +115,859 +Depreciation, depletion and amortization +42,889 +49,636 +49,640 +50,363 +192,528 +Accretion of asset retirement obligations +841 +840 +861 +873 +3,415 +(Gain) loss on sale of properties and equipment +579 +(23 +) +21 +(70 +) +507 +Total costs, expenses and other +112,963 +137,219 +123,301 +258,944 +632,427 +Income (loss) from operations +9,694 +(35,916 +) +101,255 +148,747 +223,780 +Interest expense +(12,183 +) +(12,195 +) +(11,821 +) +(11,643 +) +(47,842 +) +Interest income +187 +83 +39 +981 +1,290 +Income (loss) from continuing operations before income taxes +(2,302 +) +(48,028 +) +89,473 +138,085 +177,228 +Provision for income taxes +894 +18,650 +(35,396 +) +(54,115 +) +(69,967 +) +Income (loss) from continuing operations +(1,408 +) +(29,378 +) +54,077 +83,970 +107,261 +Income (loss) from discontinued operations, net of tax +(719 +) +1,191 +(80 +) +47,782 +48,174 +Net income (loss) +$ +(2,127 +) +$ +(28,187 +) +$ +53,997 +$ +131,752 +$ +155,435 +Earnings per share: +Basic +Income (loss) from continuing operations +$ +(0.04 +) +$ +(0.82 +) +$ +1.51 +$ +2.34 +$ +3.00 +Income (loss) from discontinued operations +(0.02 +) +0.03 +— +1.33 +1.34 +Net income (loss) +$ +(0.06 +) +$ +(0.79 +) +$ +1.51 +$ +3.67 +$ +4.34 +Diluted +Income (loss) from continuing operations +$ +(0.04 +) +$ +(0.82 +) +$ +1.47 +$ +2.32 +$ +2.93 +Income (loss) from discontinued operations +(0.02 +) +0.03 +— +1.32 +1.31 +Net income (loss) +$ +(0.06 +) +$ +(0.79 +) +$ +1.47 +$ +3.64 +$ +4.24 +Weighted-average common shares outstanding: +Basic +35,690 +35,762 +35,834 +35,847 +35,784 +Diluted +35,690 +35,762 +36,828 +36,146 +36,678 +94 +PDC ENERGY, INC. +2013 +Quarter Ended +March 31 +June 30 +September 30 +December 31 +Year Ended +(in thousands, except per share data) +Revenues: +Crude oil, natural gas and NGLs sales +$ +75,950 +$ +73,695 +$ +77,340 +$ +113,810 +$ +340,795 +Sales from natural gas marketing +13,670 +18,079 +16,946 +21,092 +69,787 +Commodity price risk management gain (loss), net +(19,765 +) +21,828 +(24,138 +) +(1,844 +) +(23,919 +) +Well operations, pipeline income and other +1,060 +954 +1,667 +2,321 +6,002 +Total revenues +70,915 +114,556 +71,815 +135,379 +392,665 +Costs, expenses and other: +Production costs +14,381 +14,274 +17,036 +19,159 +64,850 +Cost of natural gas marketing +13,736 +18,065 +17,127 +21,156 +70,084 +Exploration expense +1,540 +1,266 +1,841 +1,687 +6,334 +Impairment of crude oil and natural gas properties +46,260 +1,298 +4,236 +715 +52,509 +General and administrative expense +14,037 +14,849 +15,052 +16,018 +59,956 +Depreciation, depletion and amortization +25,431 +25,488 +26,957 +37,748 +115,624 +Accretion of asset retirement obligations +1,143 +1,167 +1,181 +1,075 +4,566 +(Gain) loss on sale of properties and equipment +(30 +) +(1 +) +(100 +) +2,153 +2,022 +Total costs, expenses and other +116,498 +76,406 +83,330 +99,711 +375,945 +Income (loss) from operations +(45,583 +) +38,150 +(11,515 +) +35,668 +16,720 +Interest expense +(13,088 +) +(12,838 +) +(11,957 +) +(12,260 +) +(50,143 +) +Interest income +— +3 +130 +327 +460 +Income (loss) from continuing operations before income taxes +(58,671 +) +25,315 +(23,342 +) +23,735 +(32,963 +) +Provision for income taxes +20,798 +(9,444 +) +9,435 +(8,937 +) +11,852 +Income (loss) from continuing operations +(37,873 +) +15,871 +(13,907 +) +14,798 +(21,111 +) +Income (loss) from discontinued operations, net of tax +(1,545 +) +4,047 +(2,093 +) +(1,599 +) +(1,190 +) +Net income (loss) +$ +(39,418 +) +$ +19,918 +$ +(16,000 +) +$ +13,199 +$ +(22,301 +) +Earnings per share: +Basic +Income (loss) from continuing operations +$ +(1.25 +) +$ +0.53 +$ +(0.42 +) +$ +0.42 +$ +(0.65 +) +Income (loss) from discontinued operations +(0.05 +) +0.13 +(0.06 +) +(0.04 +) +(0.04 +) +Net income (loss) attributable to shareholders +$ +(1.30 +) +$ +0.66 +$ +(0.48 +) +$ +0.38 +$ +(0.69 +) +Diluted +Income (loss) from continuing operations +$ +(1.25 +) +$ +0.51 +$ +(0.42 +) +$ +0.40 +$ +(0.65 +) +Income (loss) from discontinued operations +(0.05 +) +0.13 +(0.06 +) +(0.04 +) +(0.04 +) +Net income (loss) attributable to shareholders +$ +(1.30 +) +$ +0.64 +$ +(0.48 +) +$ +0.36 +$ +(0.69 +) +Weighted-average common shares outstanding +Basic +30,270 +30,332 +33,413 +35,620 +32,426 +Diluted +30,270 +31,014 +33,413 +36,836 +32,426 +FINANCIAL STATEMENT SCHEDULE +Schedule II -VALUATION AND QUALIFYING ACCOUNTS +Description +Beginning +Balance +January 1 +Charged to +Costs and +Expenses +Deductions (1) +Ending +Balance +December 31 +(in thousands) +2014: +Allowance for doubtful accounts +$ +896 +$ +78 +$ +488 +$ +486 +Valuation allowance for unproved crude oil and natural gas properties +5,142 +4,465 +314 +9,293 +2013: +Allowance for doubtful accounts +718 +322 +144 +896 +Valuation allowance for unproved crude oil and natural gas properties +5,690 +3,038 +3,586 +5,142 +2012: +Allowance for doubtful accounts +644 +222 +148 +718 +Valuation allowance for unproved crude oil and natural gas properties +10,711 +3,332 +8,353 +5,690 +___ ____________ +(1) +For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For valuation allowance for unproved crude oil and natural gas properties, deductions represent accumulated amortization of expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset. +95 +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +As of December 31, 2014 , we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). Based on the results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2014 . +Management's Report on Internal Control Over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate. +Management has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2014 , based upon the criteria established in "Internal Control – Integrated Framework (2013)" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2014 . +The effectiveness of the Company's internal control over financial reporting as of December 31, 2014 , has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. +Changes in Internal Control over Financial Reporting +During the fourth quarter of 2014 , we made no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. +ITEM 9B. OTHER INFORMATION +None. +96 +PART III +ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2015 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 11. EXECUTIVE COMPENSATION +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2015 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2015 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2015 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2015 Annual Stockholders' meeting and is incorporated by reference in this report. +PART IV +ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULE +(a) +(1) +Exhibits: +See Exhibits Index on the following page. +97 +Exhibits Index +Incorporated by Reference +Exhibit Number +Exhibit Description +Form +SEC File Number +Exhibit +Filing Date +Filed Herewith +3.1 +Fourth Amended and Restated Articles of Incorporation of PDC Energy, Inc. (the "Company") +8-K +000-07246 +3.1 +6/10/2014 +3.2 +By-laws of the Company. +10-Q +000-07246 +3.2 +8/2/2012 +4.1 +Rights Agreement by and between the Company and Transfer Online, Inc., as Rights Agent, dated as of September 11, 2007, including the forms of Rights Certificates and Summary of Stockholder Rights Plan attached thereto as Exhibits A and B. +8-K +000-07246 +4.1 +9/17/2007 +4.2 +Indenture, dated November 23, 2010, between the Company and The Bank of New York Mellon, including the form of 3.25% Convertible Senior Note due 2016. +8-K +000-07246 +4.1 +11/24/2010 +4.3 +Indenture, dated as of October 3, 2012, by and between the Company and U.S. Bank Trust National Association, as Trustee, including the form of 7.75% Senior Notes due 2022. +8-K +000-07246 +4.1 +10/3/2012 +10.1* +Form of Indemnification Agreement with Non-Employee Directors. +8-K +000-07246 +10.1 +6/13/2012 +10.2* +The Company 401(k) and Profit Sharing Plan, as amended on January 1, 2015. +X +10.3* +Amended and Restated Non-Employee Director Deferred Compensation Plan. +10-K +000-07246 +10.3 +2/21/2014 +10.4* +2004 Long-Term Equity Compensation Plan amended and restated as of March 8, 2008 ("2004 Plan"). +10-K +000-07246 +10.26 +2/27/2009 +10.4.1* +Summary of 2010 Stock Appreciation Rights and Restricted Stock Awards under the 2004 Plan. +8-K +000-07246 +4/23/2010 +10.5* +Form of 2011 Restricted Stock/Stock Appreciation Rights Agreement. +10-K +000-07246 +10.5.2 +2/21/2014 +10.5.1* +Form of 2012 Performance Share Agreement. +8-K +000-07246 +10.1 +1/20/2012 +10.5.2* +Form of 2013 Performance Share Agreement. +10-K +000-07246 +10.9 +2/27/2013 +10.5.3* +Form of 2013 Restricted Stock/Stock Appreciation Rights Agreement. +10-K +000-07246 +10.10 +2/27/2013 +10.5.4* +Form of 2014 Performance Share Agreement +X +10.5.5* +Form of 2014 Restricted Stock/Stock Appreciation Rights Agreement +X +10.5.6* +Form of 2015 Performance Share Agreement +X +10.5.7* +Form of 2015 Restricted Stock Unit Agreement +X +10.5.8* +Form of 2015 Stock Appreciation Rights Agreement +X +10.6* +Employment Agreement with Gysle R. Shellum, Chief Financial Officer, dated as of April 19, 2010. +8-K +000-07246 +10.2 +4/23/2010 +10.7* +Employment Agreement with Daniel W. Amidon, General Counsel and Corporate Secretary, dated as of April 19, 2010. +8-K +000-07246 +10.3 +4/23/2010 +10.8* +Employment Agreement with Lance A. Lauck, Senior Vice President of Business Development, dated as of April 19, 2010. +8-K +000-07246 +10.4 +4/23/2010 +10.9* +Employment Agreement with Barton R. Brookman, Jr., dated as of April 19, 2010. +8-K +000-07246 +10.5 +4/23/2010 +10.10 +Contribution Agreement by and among PDC Mountaineer, LLC, as the Company, Petroleum Development Corporation, as the Contributor, and LR-Mountaineer Holdings, L.P., as the Investor, dated October 29, 2009. +8-K +000-07246 +2.1 +11/4/2009 +10.11 +Second Amended and Restated Limited Liability Company Agreement of PDC Mountaineer, LLC, dated December 23, 2013. +10-K +000-07246 +10.12 +2/21/2014 +98 +Incorporated by Reference +Exhibit Number +Exhibit Description +Form +SEC File Number +Exhibit +Filing Date +Filed Herewith +10.12 +Third Amended and Restated Credit Agreement dated as of May 21, 2013, among PDC Energy, Inc. as Borrower, Riley Natural Gas Company, a Subsidiary of PDC Energy, Inc., as Guarantor, JP Morgan Chase Bank, N.A. as Administrative Agent, J.P. Morgan Securities LLC as Sole Bookrunner and Co-Lead Arranger, Wells Fargo Bank, N.A. as Syndication Agent, and Wells Fargo Securities, LLC as Co-Lead Arranger, and Certain Lenders. +8-K +000-07246 +10.1 +5/28/2013 +10.13 +Purchase and Sale Agreement by and among the Company, LR-Mountaineer Holdings, L.P., PDC Mountaineer, LLC and PDC Mountaineer Holdings, LLC, dated July 29, 2014. +8-K +000-07246 +2.1 +8/1/2014 +10.14* +Consulting Agreement with James M. Trimble, dated as of June 18, 2014. +10-Q +000-07246 +10.1 +8/8/2014 +12.1 +Computation of Ratio of Earnings to Fixed Charges. +X +21.1 +Subsidiaries. +X +23.1 +Consent of PricewaterhouseCoopers LLP. +X +23.2 +Consent of Ryder Scott Company, L.P., Petroleum Consultants. +X +31.1 +Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +31.2 +Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +32.1** +Certifications by Chief Executive Officer and Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. +99.1 +Report of Independent Petroleum Consultants - Ryder Scott Company, L.P. +X +101.INS +XBRL Instance Document +X +101.SCH +XBRL Taxonomy Extension Schema Document +X +101.CAL +XBRL Taxonomy Extension Calculation Linkbase Document +X +101.DEF +XBRL Taxonomy Extension Definition Linkbase Document +X +101.LAB +XBRL Taxonomy Extension Label Linkbase Document +X +101.PRE +XBRL Taxonomy Extension Presentation Linkbase Document +X +*Management contract or compensatory plan or arrangement. +** Furnished herewith. +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +PDC ENERGY, INC. +By: /s/ Barton R. Brookman +Barton R. Brookman +President and Chief Executive Officer +February 19, 2015 +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated: +Signature +Title +Date +/s/ Barton R. Brookman +President, Chief Executive Officer and Director +February 19, 2015 +Barton R. Brookman +(principal executive officer) +/s/ Gysle R. Shellum +Chief Financial Officer +February 19, 2015 +Gysle R. Shellum +(principal financial officer) +/s/ R. Scott Meyers +Chief Accounting Officer +February 19, 2015 +R. Scott Meyers +(principal accounting officer) +/s/ Jeffrey C. Swoveland +Chairman and Director +February 19, 2015 +Jeffrey C. Swoveland +/s/ Joseph E. Casabona +Director +February 19, 2015 +Joseph E. Casabona +/s/ Anthony J. Crisafio +Director +February 19, 2015 +Anthony J. Crisafio +/s/ Larry F. Mazza +Director +February 19, 2015 +Larry F. Mazza +/s/ David C. Parke +Director +February 19, 2015 +David C. Parke +/s/ James M. Trimble +Director +February 19, 2015 +James M. Trimble +/s/ Kimberly Luff Wakim +Director +February 19, 2015 +Kimberly Luff Wakim +99 +GLOSSARY OF UNITS OF MEASUREMENT AND INDUSTRY TERMS +UNITS OF MEASUREMENT +The following presents a list of units of measurement used throughout the document. +Bbl – One barrel of crude oil or NGL or 42 gallons of liquid volume. +Bcf – One billion cubic feet of natural gas volume. +Boe – One barrel of crude oil equivalent. +Btu – British thermal unit. +BBtu – One billion British thermal units. +MBoe – One thousand barrels of crude oil equivalent. +MBbls – One thousand barrels of crude oil. +Mcf – One thousand cubic feet of natural gas volume. +MMBoe – One million barrels of crude oil equivalent. +MMBtu – One million British thermal units. +MMcf – One million cubic feet of natural gas volume. +GLOSSARY OF INDUSTRY TERMS +The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report: +Behind-pipe reserves - Crude oil and natural gas reserves expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production. Generally, these are reserves in reservoirs above currently producing zones. +CIG - Colorado Interstate Gas. +Completion - Refers to the work performed and the installation of permanent equipment for the production of crude oil and natural gas from a recently drilled well. +Crude oil well - A well whose reserves are expected to produce less than 15 Mcf of gas per barrel of crude oil. +Delineation - A drilling technique carried out to gain a better understanding of the structure and extent of a deposit in order to decide whether or not to conduct further drilling activities. +Developed acreage - Acreage assignable to productive wells. +Development well - A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. +Differentials - The difference between the crude oil and natural gas index spot price and the corresponding cash spot price in a specified location. +Dry gas or dry natural gas - Natural gas is considered dry when its composition is over 90% pure methane. +Dry well or dry hole - A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well. +Exploratory well - A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. +Extensions and discoveries - As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates. +Farm-out - Transfer of all or part of the operating rights from a working interest owner to an assignee, who assumes all or some of the burden of development in return for an interest in the property. The assignor usually retains an overriding royalty interest but may retain any type of interest. +Fracture or Fracturing - Procedure to stimulate production by forcing a mixture of fluid and proppant into the formation under high pressure. Fracturing creates artificial fractures in the reservoir rock to increase permeability and porosity, thereby allowing the release of trapped hydrocarbons. +Gross acres or wells - Refers to the total acres or wells in which we have a working interest. +Horizontal drilling - A drilling technique that permits the operator to drill a horizontal well shaft from the bottom of a vertical well and thereby to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons. +100 +Joint interest billing - Process of billing/invoicing the costs related to well drilling, completions and production operations among working interest partners. +Natural gas liquid(s) or NGL(s) - Hydrocarbons which can be extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs include ethane, propane, butane, and other natural gasolines. +Net acres or wells - Refers to gross acres or wells we own multiplied, in each case, by our percentage working interest. References to net acres or wells include our proportionate share of PDCM's and our affiliated partnerships' net acres or wells. +Net production - Crude oil and natural gas production that we own, less royalties and production due to others. References to net production include our proportionate share of PDCM's and our affiliated partnerships' net production. +Non-operated - A project in which we are not the operator. +NYMEX - New York Mercantile Exchange. +Operator - The individual or company responsible for the exploration, development and/or production of an oil or gas well or lease. +Overriding royalty - An interest which is created out of the operating or working interest. Its term is coextensive with that of the operating interest. +Possible reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability to exceed the sum of proved, probable and possible reserves. When probabilistic methods are used, there must be at least a 10 percent probability that the actual quantities recovered will equal or exceed the sum of proved, probable and possible estimates. +Present value of future net revenues or (PV-10) - The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, of proved reserves calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using pricing and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. PV-10 is pre-tax and therefore a non-U.S. GAAP financial measure. +Probable reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Similarly, when probabilistic methods are used, there must be at least a 50 percent probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. +Productive well - A well that is not a dry well or dry hole, as defined above, and includes wells that are mechanically capable of production. +Proved developed non-producing reserves - Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and/or (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells. +Proved developed producing reserves or PDPs - Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods. +Proved developed reserves - The combination of proved developed producing and proved developed non-producing reserves. +Proved reserves - This term means "proved oil and gas reserves" as defined in SEC Regulation S-X Section 4-10(a) and refers to those quantities of crude oil and condensate, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +Proved undeveloped reserves or PUDs - Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. +Recomplete or Recompletion - The modification of an existing well for the purpose of producing crude oil and natural gas from a different producing formation. +Refracture - A refracture occurs when we stimulate a well by fracturing a producing zone to increase its production as well as its PDP reserves. +101 +Reserves - Estimated remaining quantities of crude oil, natural gas, NGLs and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering crude oil, natural gas and NGLs or related substances to market, and all permits and financing required to implement the project. +Royalty - An interest in a crude oil and natural gas lease or mineral interest that gives the owner of the royalty the right to receive a portion of the production from the leased acreage or mineral interest (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +Section - A square tract of land one mile by one mile, containing 640 acres. +Spud - To begin drilling; the act of beginning a hole. Past tense: spudded . +Standardized measure of discounted future net cash flows or standardized measure - Future net cash flows discounted at a rate of 10%. Future net cash flows represent the estimated future revenues to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment and (ii) future income tax expense. +Stratigraphic test well - A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. +TETCO M2 - Texas Eastern Transmission Corporation M-2 receipts. +Unconventional resource(s) - Crude oil and natural gas that cannot be produced at economic flow rates in economic volumes unless the well is stimulated by a large hydraulic fracture treatment, a horizontal wellbore, or by using multilateral wellbores or some other technique to expose more of the resources to the wellbore. +Undeveloped acreage - Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas, regardless of whether such acreage contains proved reserves. +Wet gas or wet natural gas - Natural gas that contains a larger quantity of hydrocarbon liquids than dry natural gas, such as NGLs, condensate and crude oil. +Working interest - An interest in a crude oil and natural gas lease that gives the owner of the interest the right to drill and produce crude oil and natural gas on the leased acreage. It requires the owner to pay its share of the costs of drilling and production operations. +Workover - Major remedial operations on a producing well to restore, maintain or improve the well's production. +102 \ No newline at end of file diff --git a/raw/filings/0000077877/2014/0000077877-15-000012/filing_metadata.csv b/raw/filings/0000077877/2014/0000077877-15-000012/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..e8f874855d6466a5f4b8f30183a5dbbe332a64fe --- /dev/null +++ b/raw/filings/0000077877/2014/0000077877-15-000012/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000077877,PDCE,"PDC ENERGY, INC.",10-K,2015-02-19,2014-12-31,2015-02-19T13:37:35.000Z,0000077877-15-000012,pdce-10kxfy14.htm,PDC ENERGY 2014 FORM 10-K,27167065,1,0,https://www.sec.gov/Archives/edgar/data/77877/000007787715000012/pdce-10kxfy14.htm,https://www.sec.gov/Archives/edgar/data/77877/000007787715000012/,2014,2014,1 diff --git a/raw/filings/0000077877/2014/0000077877-15-000012/item1.txt b/raw/filings/0000077877/2014/0000077877-15-000012/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2014/0000077877-15-000012/item13.txt b/raw/filings/0000077877/2014/0000077877-15-000012/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..7794f2f2ef6a75d33b193d7a4776d312097883cc --- /dev/null +++ b/raw/filings/0000077877/2014/0000077877-15-000012/item13.txt @@ -0,0 +1,2 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2015 Annual Stockholders' meeting and is incorporated by reference in this report. \ No newline at end of file diff --git a/raw/filings/0000077877/2014/0000077877-15-000012/item9a.txt b/raw/filings/0000077877/2014/0000077877-15-000012/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..f3f3d7bc75750dd70328c78a154814d08e469334 --- /dev/null +++ b/raw/filings/0000077877/2014/0000077877-15-000012/item9a.txt @@ -0,0 +1,9 @@ +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +As of December 31, 2014 , we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). Based on the results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2014 . +Management's Report on Internal Control Over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate. +Management has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2014 , based upon the criteria established in "Internal Control – Integrated Framework (2013)" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2014 . +The effectiveness of the Company's internal control over financial reporting as of December 31, 2014 , has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. +Changes in Internal Control over Financial Reporting +During the fourth quarter of 2014 , we made no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. \ No newline at end of file diff --git a/raw/filings/0000077877/2014/0000077877-15-000012/rp_note.txt b/raw/filings/0000077877/2014/0000077877-15-000012/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2014/0000077877-15-000012/rpt_disclosure.txt b/raw/filings/0000077877/2014/0000077877-15-000012/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..4f9a34ec720c56e9c8cc64aab1c1867725dc07a8 --- /dev/null +++ b/raw/filings/0000077877/2014/0000077877-15-000012/rpt_disclosure.txt @@ -0,0 +1,18 @@ +TRANSACTIONS WITH RELATED PERSONS +Related Transactions +From January 1, 2015 to the present, there was no transaction or series of transactions, nor is there any currently +proposed transaction involving an amount exceeding $120,000 in which the Company is a participant and/or in which any Director, executive officer, known holder of more than five percent of the Company’s voting securities, or any member of the +immediate family of any of the foregoing persons, had or will have a direct or indirect material interest for which disclosure is required under Item 404 of Regulation S-K. +Policies and Procedures With Respect to Transactions with Related Persons +The Board has adopted a written policy for the review, approval and ratification of transactions that involve related parties +and potential conflicts of interest. The related party transaction policy applies to each Director and executive officer of the Company, any nominee for election as a Director, any security holder who is known to own more than five percent of the +Company’s voting securities, any immediate family member of any of the foregoing persons and any corporation, firm or association in which one or more of the Company’s Directors are directors or officers, or have a substantial financial +interest. +Under our related-party transaction policy, a related person transaction is a transaction or arrangement +involving a related person in which the Company is a participant or that would require disclosure in the Company’s filings with the SEC as a transaction with a related person. The related person must disclose to the Audit Committee any +potential related person transactions and must disclose all material facts with respect to such transaction and relationship. All related person transactions so disclosed will be reviewed by the Audit Committee. In determining whether to approve or +ratify a transaction, the Audit Committee will consider the relevant facts and circumstances of the transaction, which may include factors such as the relationship of the related person with the Company, the materiality or significance of the +transaction to the Company and the business purpose and reasonableness of the transaction, whether the transaction is comparable to a transaction that could be available to the Company on an arms-length basis and the impact of the transaction on the +Company’s business and operations. +25 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0000077877/2015/0000077877-16-000070/filing.txt b/raw/filings/0000077877/2015/0000077877-16-000070/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..0d245862dc5fa40204f82757c3c02f5f7f2f5a6e --- /dev/null +++ b/raw/filings/0000077877/2015/0000077877-16-000070/filing.txt @@ -0,0 +1,6895 @@ +10-K +1 +pdce-10kxfy15.htm +PDC ENERGY 2015 FORM 10-K +10-K +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +T ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2015 +or +£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from __________ to _________ +Commission File Number 001-37419 +PDC ENERGY, INC. +(Exact name of registrant as specified in its charter) +Delaware +95-2636730 +(State of incorporation) +(I.R.S. Employer Identification No.) +1775 Sherman Street, Suite 3000 +Denver, Colorado 80203 +(Address of principal executive offices) (Zip code) +Registrant's telephone number, including area code: (303) 860-5800 +Securities registered pursuant to Section 12(b) of the Act: +Title of each class +Name of each exchange on which registered +Common Stock, par value $0.01 per share +NASDAQ Global Select Market +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes T No £ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes £ No T +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes T No £ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes T No £ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. £ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. +Large accelerated filer x +Accelerated filer o +Non-accelerated filer £ +(Do not check if a smaller reporting company) +Smaller reporting company o +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes £ No T +The aggregate market value of our common stock held by non-affiliates on June 30, 2015 was $2.1 billion (based on the closing price of $53.64 per share as of the last business day of the fiscal quarter ending June 30, 2015). +As of February 1, 2016 , there were 40,269,891 shares of our common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +We hereby incorporate by reference into this document the information required by Part III of this Form, which will appear in our definitive proxy statement to be filed pursuant to Regulation 14A for our 2016 Annual Meeting of Stockholders. +PDC ENERGY, INC. +2015 ANNUAL REPORT ON FORM 10-K +TABLE OF CONTENTS +PART I +Page +Items 1. and 2. +Business and Properties +2 +Item 1A. +Risk Factors +17 +Item 1B. +Unresolved Staff Comments +32 +Item 3. +Legal Proceedings +32 +Item 4. +Mine Safety Disclosures +32 +PART II +Item 5. +Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +33 +Item 6. +Selected Financial Data +35 +Item 7. +Management's Discussion and Analysis of Financial Condition and Results of Operations +36 +Item 7A. +Quantitative and Qualitative Disclosures About Market Risk +54 +Item 8. +Financial Statements and Supplementary Data +56 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +98 +Item 9A. +Controls and Procedures +98 +Item 9B. +Other Information +98 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +99 +Item 11. +Executive Compensation +99 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +99 +Item 13. +Certain Relationships and Related Transactions, and Director Independence +99 +Item 14. +Principal Accounting Fees and Services +99 +PART IV +Item15. +Exhibits, Financial Statement Schedules +99 +Signatures +102 +Glossary of Units of Measurements and Industry Terms +103 +PART I +REFERENCES TO THE REGISTRANT +Unless the context otherwise requires, references in this report to "PDC Energy," "PDC," "the Company," "we," "us," "our" or "ours" refer to the registrant, PDC Energy, Inc. and all subsidiaries consolidated for the purposes of its financial statements, including our proportionate share of the financial position, results of operations, cash flows and operating activities of our affiliated partnerships and PDC Mountaineer, LLC ("PDCM"), a joint venture owned 50% each by PDC and Lime Rock Partners, LP until its sale in October 2014 . Unless the context otherwise requires, references in this report to "Appalachian Basin" refers to our operations in the Utica Shale in Ohio and Marcellus Shale in West Virginia and Pennsylvania, including PDC's proportionate share of our affiliated partnerships' and PDCM's assets, results of operations, cash flows and operating activities. See Note 1, Nature of Operations and Basis of Presentation, to our consolidated financial statements included elsewhere in this report for a description of our consolidated subsidiaries and Note 15, Assets Held for Sale, Divestitures and Discontinued Operations , for a discussion of the sale of our interest in PDCM. PDC is a Delaware corporation, having reincorporated from Nevada in 2015. +GLOSSARY OF UNITS OF MEASUREMENTS AND INDUSTRY TERMS +Units of measurements and industry terms are defined in the Glossary of Units of Measurements and Industry Terms, included at the end of this report. +SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS +This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical facts included in and incorporated by reference into this report are "forward-looking statements" within the meaning of the safe harbor provisions of the United States ("U.S.") Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein. These statements relate to, among other things: estimated future production (including the components of such production), sales, expenses, cash flows, liquidity and balance sheet attributes; estimated crude oil, natural gas and natural gas liquids (“NGLs”) reserves; the impact of prolonged depressed commodity prices including potentially reduced production and associated cash flow; anticipated 2016 capital projects, expenditures and opportunities, including our expectation that 2016 cash flows from operations will approximate cash flows from investing activities; expected 2016 capital budget allocations; our operational flexibility and ability to revise our 2016 development plan; availability of sufficient funding and liquidity for our 2016 capital program and sources of that funding; expected losses of Riley Natural Gas ("RNG") through 2022 and expected discontinuation of RNG's business; future exploration, drilling and development activities, including non-operated activity, the number of drilling rigs we expect to run during 2016 , number of locations and lateral lengths; opportunity in the Utica Shale to add reserves in a more favorable price environment; capital efficiencies and per well reserves expected to be realized; expected 2016 production and cash flow ranges; our evaluation method of our customers' and derivative counterparties' credit risk; effectiveness of our derivative program in providing a degree of price stability; future horizontal drilling locations that are economically producible at certain commodity prices and costs; potential for future impairments; potential acquisitions of additional acreage and other future transactions; electronic, cyber or physical security breaches; the impact of high line pressures and the timing, availability, cost and effect of additional midstream facilities and services going forward; compliance with debt and senior notes covenants; expected funding sources for conversion of our 3.25% convertible senior notes due 2016; compliance with government regulations; impact of the Colorado task force on oil and gas regulation and potential future ballot initiatives and legislation; the level of our borrowing base under our credit facility; impact of litigation on our results of operations and financial position; the adequacy of existing insurance to cover operating hazards and the availability of such insurance on a cost effective basis in the future; that we hold good and defensible title to our leasehold; that we do not expect to pay dividends in the foreseeable future; and our future strategies, plans and objectives. +The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this report or accompanying materials, we may use the terms “projection” or similar terms or expressions, or indicate that we have “modeled” certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or the industry in periods beyond the current fiscal year. Because such statements relate to events or conditions further in the future, they are subject to increased levels of uncertainty. +Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to: +• +changes in worldwide production volumes and demand, including economic conditions that might impact demand; +• +volatility of commodity prices for crude oil, natural gas and NGLs and the risk of an extended period of depressed prices; +• +reductions in the borrowing base under our revolving credit facility; +• +impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement related to those laws and regulations, liabilities arising thereunder and the costs to comply with those laws and regulations; +• +declines in the value of our crude oil, natural gas and NGLs properties resulting in further impairments; +• +changes in estimates of proved reserves; +1 +• +inaccuracy of reserve estimates and expected production rates; +• +potential for production decline rates from our wells being greater than expected; +• +timing and extent of our success in discovering, acquiring, developing and producing reserves; +• +availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production and the impact of these facilities and regional capacity on the prices we receive for our production; +• +timing and receipt of necessary regulatory permits; +• +risks incidental to the drilling and operation of crude oil and natural gas wells; +• +future cash flows, liquidity and financial condition; +• +competition within the oil and gas industry; +• +availability and cost of capital; +• +our success in marketing crude oil, natural gas and NGLs; +• +effect of crude oil and natural gas derivatives activities; +• +impact of environmental events, governmental and other third-party responses to such events, and our ability to insure adequately against such events; +• +cost of pending or future litigation; +• +effect that acquisitions we may pursue have on our capital expenditures; +• +our ability to retain or attract senior management and key technical employees; and +• +success of strategic plans, expectations and objectives for our future operations. +Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under Item 1A, Risk Factors , made in this report and our other filings with the U.S. Securities and Exchange Commission ("SEC") for further information on risks and uncertainties that could affect our business, financial condition, results of operations and cash flows. We caution you not to place undue reliance on forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement. +ITEMS 1. AND 2. BUSINESS AND PROPERTIES +The Company +We are a domestic independent exploration and production company that produces, develops, acquires and explores for crude oil, natural gas and NGLs with operations in the Wattenberg Field in Colorado and the Utica Shale in southeastern Ohio. Our 2016 drilling and completion operations in the Wattenberg Field are expected to focus on the middle core area of the Niobrara and Codell plays. As of December 31, 2015 , we own an interest in approximately 3,000 gross producing wells, of which approximately 650 are horizontal. Production of 15.4 MMboe for the year ended December 31, 2015 represents an increase of 65% compared to the year ended December 31, 2014 . For the month ended December 31, 2015 , we maintained an average production rate of 52 MBoe per day. We were able to achieve this strong growth rate while maintaining a liquidity position of $402.2 million as of December 31, 2015 and a debt to EBITDAX ratio, as defined in our revolving credit facility agreement, of 1.4 times. As of December 31, 2015 , we had approximately 273 MMBoe of proved reserves ( 26% of which are proved developed). Proved reserves at December 31, 2015 were comprised of approximately 60% liquids and 40% natural gas, and represent an increase of 23 MMBoe relative to December 31, 2014 . Our proved reserve additions were primarily a result of the increased well density of proved undeveloped locations in the middle core area of the Niobrara formation in the Wattenberg Field, which allowed for the optimization of our five-year development plan. While the significant decrease in SEC commodity prices utilized in the 2015 year-end reserve report had a minimal impact on our quantities of proved reserves, this decrease in pricing resulted in a 61% decline in the pre-tax present value of future net revenues (“PV-10”) relative to December 31, 2014 . PV-10 is not a financial measure under accounting principles generally accepted in the United States of America (“U.S. GAAP”). See Part I, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10 and a reconciliation of our PV-10 value to our standardized measure. +Our Strengths +• +Multi-year project inventory in premier crude oil, natural gas and NGLs plays. We have a significant operational presence in the Wattenberg Field, a key U.S. onshore basin, and have identified a substantial inventory of 791 gross proved undeveloped horizontal drilling locations and approximately 1,400 probable horizontal drilling locations in this play. These location counts are based on wells expected to be drilled with an average lateral length of approximately 4,700 feet. Further, with our leaseholds in Ohio, we have the ability to pursue developmental drilling in the emerging Utica Shale play and are focusing our development in the condensate and wet natural gas window of the play. We believe that this inventory will allow us to continue to grow our reserves and production, and that, with respect to the Wattenberg Field in particular, the majority of our projects will generate attractive rates of return at current commodity price projections and our current projected cost structure. +2 +• +Strong liquidity position. As of December 31, 2015 , we had a total liquidity position of $402.2 million , comprised of $0.9 million of cash and cash equivalents and $401.3 million available for borrowing under our revolving credit facility. We had $37.0 million outstanding on our revolving credit facility as of December 31, 2015 . Our liquidity position will be reduced by $115 million upon the maturity of our 3.25% convertible senior notes in May 2016. Pursuant to the related indenture, we will settle the principal amount of the notes in cash and issue common stock for the excess conversion value upon maturity. In September 2015, we completed the semi-annual redetermination of the borrowing base under our revolving credit facility, which resulted in the reaffirmation of the borrowing base at $700 million. We elected to maintain the aggregate commitment at $450 million. Considering the additional $250 million borrowing base available under our revolving credit facility, subject to certain terms and conditions of the agreement, our liquidity position as of December 31, 2015 could have been $652.2 million . +• +Significant control in our core areas. Our operational control is enhanced by the fact that substantially all of our Wattenberg Field leasehold position is held-by-production. We remain flexible in terms of rig activity and capital deployment due to short-term rig contracts and held-by-production acreage. As a result, we can adjust our drilling plans if commodity prices deteriorate further in order to balance cash flows from operations and cash flows from investing activities, which primarily consist of our capital expenditures. Our leaseholds that are held-by-production further enhance our operational control by providing us flexibility in selecting drilling locations based upon various operational criteria. Additionally, as a result of successfully executing our strategy of acquiring largely concentrated acreage positions with a high working interest, we operate and manage approximately 87% of the wells in which we have an interest. Our high percentage of operated properties enables us to exercise a significant level of control with respect to drilling, production, operating and administrative costs, in addition to leveraging our base of technical expertise in our core operating areas. +• +2016 derivative program. We have hedged a portion of our short-term future exposure to commodity price fluctuations by entering into crude oil and natural gas collars, fixed-price swaps and basis protection swaps. While our derivative program limits the upside benefits we may otherwise receive during periods of higher commodity prices, the program helps protect our cash flows, borrowing base and liquidity during periods of depressed commodity prices. As of December 31, 2015 , we had hedge positions covering approximately 4,140 MBbls of 2016 crude oil production, or approximately 45% to 50% of our expected crude oil production for the year. These hedges were at a weighted-average minimum price of $77.26 per Bbl and a weighted-average maximum price of $86.88 per Bbl. As of the same date, we had hedged approximately 29.8 Bcf, or approximately 59% to 65% , of our expected natural gas production in 2016 , at a weighted-average minimum price of $3.62 per Mcf and a weighted-average maximum price of $3.72 per Mcf. As of December 31, 2015 , we had hedged a much lower percentage of our expected production for the next 12 to 24 months than we have hedged historically. +• +Technology focused team. We have a proven track record of continuing improvement in both costs and productivity of our well operations. Recently, our teams have focused on transitioning to multi-well pad drilling, extended laterals, increased frac stage density, enhanced frac design and drilling efficiencies. In 2015, we introduced tighter frac stage density and, in 40% of our spuds, extended reach laterals that are 6,500 to 7,000 feet in length. We also began testing plug-and-perf completions along with diverting agents that have provided an uplift to our new well production. We have completed wells at various densities ranging from 16 wells per section equivalent to 26 wells per section equivalent, providing added information on the reserves that can potentially be recovered. Finally, our drilling team has made great strides in reducing drill times for one mile laterals from an average of approximately 14 days to seven days spud-to-spud over the year. +• +Track record of reserve and production growth. Our proved reserves have grown from 50 MMBoe at December 31, 2010 , after adjusting for subsequent divestitures, to approximately 273 MMBoe at December 31, 2015 , representing a compound annual growth rate (“CAGR”) of 40% . During the same time period, our proved crude oil and NGL reserves grew at a CAGR of 42% . Our annual production from continuing operations grew from 3.3 MMBoe in 2010 to 15.4 MMBoe in 2015 , representing a CAGR of 36% . Future development of the Wattenberg Field provides the opportunity to add further proved, probable and possible reserves to our portfolio. Similarly, we believe the Utica Shale provides the opportunity for additional proved, probable and possible reserves in a more favorable crude oil and natural gas pricing environment. As a result of data generated from our downspacing testing in the Wattenberg Field, Ryder Scott Company, L.P. (“Ryder Scott”), our independent petroleum engineering consulting firm, has increased the density of our proven undeveloped locations, year-over-year, in the Niobrara formation. In general, at December 31, 2013, Niobrara PUD locations were booked at an equivalent density of six wells per section, at December 31, 2014, Niobrara PUD locations were booked at an equivalent density of eight wells per section and at December 31, 2015, Niobrara PUD locations are booked at the equivalent density of 16 wells per section. +• +Strong environmental health and safety compliance programs. We have focused on establishing effective environmental health and safety programs that are able to earn trust and respect from regulatory agencies and public officials. We believe this is an important part of our strategy in competing in today’s intensive regulatory and public debate climate, and in working with the local communities in which we operate. +• +Community participation and outreach. We are dedicated to being an active and contributing member of the communities in which we operate. We share our success with these communities in various ways, including charitable giving and community event sponsorships. We also encourage our employees to take an active role through our charitable matching contribution fund and by participating in our “Energizing Our Community” day, during which our employees volunteer in the communities in which they work and live. +3 +Business Strategy +Our long-term business strategy focuses on generating shareholder value through the development, acquisition and exploration of crude oil and natural gas properties. We are currently focused on the organic growth of our reserves, production and cash flows in our horizontal drilling programs after having completed multiple transactions in recent years to restructure and simplify our property portfolio. We pursue various midstream, marketing and cost reduction initiatives designed to increase our per unit operating margins while maintaining a conservative and disciplined financial strategy focused on providing sufficient liquidity and balance sheet strength to execute our business strategy. +We focus on horizontal development drilling programs in resource plays that offer repeatable results and the potential for attractive returns on investment in the current commodity price environment. Our current inventory of drilling locations supports our planned organic growth over the next several years. We expect it to drive increases in reserves, production and cash flows. In addition to development drilling, we routinely review acquisition and acreage swap opportunities in our core areas of operation as we believe we can extract additional value from such assets through production optimization and increasing our working interest in our development drilling locations. As a result, these types of core acquisitions and acreage swaps can potentially provide synergies that result in economies of scale. We also pursue a limited, but disciplined, exploration program with the goal of replenishing our portfolio with new exploration projects capable of positioning us for significant production and reserve growth in future years. +Development drilling +The following map presents the general locations of our development and production activities as of December 31, 2015 : +Our leasehold interests consist of developed and undeveloped crude oil, natural gas and NGLs resources. Based upon well cost savings resulting from the continued deterioration of commodity prices, our current 2016 capital forecast is a range between $420 million and $450 million. We have allocated over 90% of our 2016 capital forecast to our higher-return projects in the Wattenberg Field, primarily in the middle core area. We may decrease our 2016 capital forecast during the year as a result of, among other things, a further decline in commodity prices, a reduction of our current internal outlook for commodity prices, drilling results, unfavorable changes in our borrowing capacity and/or a significant decline in cash flows. +Wattenberg Field . Our primary focus in the Wattenberg Field is drilling in the horizontal Niobrara and Codell plays. Based on our current drilling program, we have an inventory of 791 gross proved undeveloped horizontal drilling locations and approximately 1,400 gross probable horizontal drilling locations. These locations are in the core Wattenberg Field, which is further delineated between the inner, middle and outer core. In 2016 , we expect to continue to realize additional capital efficiencies through drilling extended length laterals, use of a diverting agent with plug-and-perf completions, well-orientation and mono-bore drilling. We plan to drill standard reach lateral (“SRL”), mid-length lateral (“MRL”) and extended reach lateral (“XRL”) wells in 2016, the majority of which will be in the middle core area of the field. In 2016, we plan to spud 135 and turn-in-line approximately 160 horizontal Niobrara or Codell wells as outlined below. +4 +SRL +MRL +XRL +Estimated average lateral length (in feet) +4,200 +6,900 +9,500 +Expected drilling days (spud-to-spud) +7 +11 +14 +Estimated percentage of 2016 wells spud +36% +34% +30% +Estimated percentage of 2016 wells turned-in-line +50% +40% +10% +Estimated cost per well (in millions)(1) +$2.6 +$3.6 +$4.6 +___________ +(1) Estimated well costs include plug-and-perf technology. +The 2016 capital forecast anticipates a four-rig drilling program in the Wattenberg Field based on our current commodity price outlook. Approximately $400 million of our 2016 capital forecast is expected to be spent on development activities in the Wattenberg Field, comprised of approximately $350 million for our operated drilling program and approximately $35 million for non-operated projects. The remainder of the Wattenberg Field capital forecast is expected to be used for leasing, workover projects and other capital improvements, including the remodeling of our new field office in Greeley, Colorado. We expect to participate in approximately 35 gross, 7.0 net, non-operated horizontal opportunities in 2016 . +Utica Shale . Our operations in the Utica Shale are currently less significant, and include horizontal drilling locations in the condensate and wet natural gas window of the play. In early 2015, based upon low commodity prices and large natural gas price differentials in Appalachia, we elected to temporarily cease drilling in the Utica Shale and limited our activity to completing and turning-in-line a four-well pad that was in process as of December 31, 2014. Due to a further significant decline in commodity prices and a decrease in net-back realizations, in the third quarter of 2015 we recorded an impairment charge of $150.3 million to write-down our Utica Shale producing and non-producing crude oil and natural gas properties. Based on the production results from our most recently drilled wells and the significant decrease in well costs, in 2016 we plan on executing a modest drilling operation in the condensate and wet natural gas window of the play. Early in 2016, we plan to spend approximately $35 million in the Utica Shale to drill, complete and turn-in-line five wells, all of which will have laterals of at least 6,000 feet. The planned activity will focus on further delineation of our southern acreage, determining the impact of well-orientation on productivity and testing improved capital efficiency of a 10,000 foot lateral length well. +While we expect to outspend our cash flows from operations during the first half of 2016, we believe that our cash flows from operations will exceed our cash flows from investing activities, which primarily consist of our capital expenditures, in the second half of 2016. As a result, we expect our overall 2016 cash flows from operations to approximate our cash flows from investing activities. However, a further deterioration of commodity prices could negatively impact our results of operations, financial condition and future development plans. We may decrease our 2016 capital forecast during the year as a result of, among other things, a further decline in commodity prices, drilling results, unfavorable changes in our borrowing capacity and/or a significant decline in cash flows. If commodity pricing falls short of our internal expectations, we would likely look to reduce our capital investment in the second quarter of 2016 to maintain our goal of capital expenditures approximating operational cash flows. We may change our capital expenditure plans from time to time for other reasons as well, including as a result of regulatory issues, drilling results or acquisition or divestiture opportunities. Our liquidity position will be reduced by the cash payment of approximately $115 million upon the maturity of our 3.25% convertible senior notes in May 2016. See Part I, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - 2016 Operational Flexibility, for additional information. +Operational and financial risk management +We proactively employ strategies to help reduce the financial risks associated with our industry. One such strategy is to utilize commodity-based derivative instruments to manage a portion of our short-term exposure to price volatility with regard to our crude oil and natural gas sales and natural gas marketing segments. As of December 31, 2015 , we had natural gas and crude oil derivative positions in place for 2016 covering approximately 4,140 MBbls of our crude oil production and approximately 29.8 Bcf of our natural gas production and for 2017 covering approximately 1,440 MBbls of our crude oil production and approximately 32.5 Bcf of our natural gas production. Currently, we do not hedge our NGL production. +Strategic acquisitions +We examine and evaluate acquisition opportunities as they present themselves and pursue those that meet our strategic plan and that we believe would increase shareholder value. We typically pursue the acquisition of assets with high quality undeveloped drilling locations, producing wells and/or behind-pipe reserves. We seek properties with large undeveloped drilling upside where we believe we can utilize our operational abilities to add shareholder value. In addition, we may pursue opportunities to swap acreage with other producers in order to optimize our portfolio by consolidating and concentrating our core assets. The large contiguous acreage blocks created through swapping of acreage provide the opportunity to optimize drilling activities and add more extended-reach lateral wells to our drilling program. We have an experienced team of management, engineering, geosciences and commercial professionals who identify and evaluate acquisition opportunities. +Selective exploration +In the current commodity pricing environment, we do not expect our exploration activity to be significant in 2016. Historically, we have pursued a disciplined exploration program intended to replenish our portfolio and to position us for production and reserve growth in future +5 +years. We have attempted to identify potential plays in their early stages in order to accumulate significant leasehold positions prior to competitive forces driving up the cost of entry and to invest in leasehold positions that are in the proximity of existing or emerging midstream infrastructure. +Business Segments +We divide our operating activities into two segments: (1) Oil and Gas Exploration and Production and (2) Gas Marketing. +Oil and Gas Exploration and Production +Our Oil and Gas Exploration and Production segment primarily reflects revenues and expenses from the production and sale of crude oil, natural gas and NGLs, commodity price risk management and well operations. The exploration for and production of crude oil, natural gas and NGLs involves the acquisition or leasing of mineral rights to proved reserves and related surface rights. Prior to development of these properties, we assess the economic viability of potential well development opportunities. We then develop the reserves through the drilling of oil and gas wells, which are drilled, completed and put into production. Subsequent to completion, we operate and maintain the wells while controlling associated production costs. Upon extraction of the estimated recoverable reserves from a well, it is plugged and surface disturbance surrounding the well and producing facilities is remediated. In some cases, we may also own a working interest in wells operated by unrelated third-parties. The Oil and Gas Exploration and Production segment's most significant customers are currently Suncor Energy Marketing, Inc., Concord Energy, LLC, DCP Midstream, LP and Shell Trading Company. Sales to each of these parties constitute more than 10% of our revenues. +Our crude oil, natural gas and NGLs production is gathered, marketed and sold as follows: +• +Crude oil . We do not refine any of our crude oil production. In the Wattenberg Field, crude oil is sold under various purchase contracts with monthly and longer term pricing provisions based on NYMEX pricing, adjusted for differentials. We have entered into longer term commitments ranging from three months to one year to deliver crude oil to competitive markets and these agreements have resulted in significantly improved deductions compared to earlier in 2015. We continue to pursue various alternatives with respect to oil transportation, particularly in the Wattenberg Field, with a view toward further improving pricing and limiting our use of trucking of production. We began delivering crude oil in accordance with our long term commitment to the White Cliffs Pipeline, LLC ("White Cliffs") pipeline in July 2015. This is one of several agreements we have entered into to facilitate deliveries of a portion of our crude oil to the Cushing, Oklahoma market. In addition, we have signed a long-term agreement for gathering of crude oil at the wellhead by pipeline from several of our pads in the Wattenberg Field, with a view toward minimizing truck traffic, increasing reliability and reducing the overall physical footprint of our well pads. We began delivering crude oil into this pipeline during the fourth quarter of 2015 and expect the system to be fully operational in the first quarter of 2016. In the Utica Shale, crude oil and condensate is sold to local purchasers at each individual well site based on NYMEX pricing, adjusted for differentials, and is typically transported by the purchasers via truck to local refineries, rail facilities or barge loading terminals on the Ohio River. +• +Natural gas . We primarily sell our natural gas to midstream service providers, marketers and utilities. Our natural gas is transported through third-party gathering systems and pipelines and we incur gathering, processing and transportation expenses to move our natural gas from the wellhead to a purchaser-specified delivery point. We generally sell the natural gas that we produce in the Wattenberg Field under contracts with indexed, NYMEX or CIG monthly pricing provisions, with the remaining production sold under contracts with daily pricing provisions. Virtually all of our contracts include provisions whereby prices change with the market, with certain adjustments that may be made based on whether a well delivers to a gathering or transmission line and the quality of the natural gas. We have entered into firm gathering and processing agreements for all of our gas production to ensure there is infrastructure available to process the gas and get it to market. In the Wattenberg Field, the majority of our leasehold is dedicated to our primary midstream provider, DCP Midstream, LP, which gathers and processes wet natural gas produced in the basin and sells our residue gas to various markets. In the fourth quarter of 2014, we entered into an agreement with AKA Energy Group ("AKA") whereby we have committed production from a specified number of new horizontal wells to be drilled and completed by the end of 2016. Pursuant to the agreement, AKA is required to install and operate, or contract for use of, facilities necessary to receive and purchase the production volumes committed under the agreement. In the Utica Shale, wet natural gas produced in our northern acreage is gathered and processed pursuant to a firm gathering and processing agreement with MarkWest Utica EMG ("MarkWest") while wet natural gas produced in our southern acreage is gathered and processed by Blue Racer Midstream LLC ("Blue Racer"). The natural gas sales from the Blue Racer Plant are based on TETCO M-2 pricing. The gas sold at the tailgate of the MarkWest plant is sold at a price relative to the Chicago/Midwest market. Our sale of a significant portion of our Utica Shale gas to the Midwest market has helped to reduce the impact of the significant differentials that exist between the TETCO M-2 realizations and the NYMEX gas price. We anticipate that the significant Appalachian pipeline differentials that impact our Utica Shale natural gas, which make economics challenging, will continue well into 2016. +• +NGLs . In the Wattenberg Field, all of our NGLs are sold at the tailgate of the third-party midstream service provider processing plants based on a combination of prices from the Conway hub in Kansas and Mt. Belvieu in Texas where this production is marketed. In the Utica Shale, our NGLs are fractionated and marketed by MarkWest and Blue Racer and sold based on month-to-month pricing in various markets. Our NGL production is sold under both short- and long-term contracts. Due to an oversupply and growing inventories of nearly all domestic NGLs products, our realized sales price for NGLs declined significantly during 2015 and, while these prices have stabilized, we expect pricing to remain at depressed levels well into 2016 and perhaps beyond. +6 +Gas Marketing +Our Gas Marketing segment is comprised solely of the operating activities of our wholly-owned subsidiary RNG. RNG specializes in the purchase, aggregation and sale of natural gas production in the Appalachian Basin. Financial results from our gas marketing segment were not material to our consolidated financial statements for any of the periods presented in this report and we do not expect them to be material in the future. RNG purchases for resale natural gas produced by third-party producers. The natural gas is marketed to third-party marketers, natural gas utilities and industrial and commercial customers through transportation services provided by regulated interstate/intrastate pipeline companies. RNG is party to long-term firm transportation, sales and processing agreements for pipeline capacity through August 2022. As of December 31, 2015, the dollar commitment related to this long-term firm transportation, sales and processing agreement was approximately $20.6 million. This long-term pipeline capacity commitment was made on behalf of our third-party producers, and also includes an unutilized portion; however, we remain obligated to fulfill this commitment regardless of whether or not our third-party producers meet their commitments. As natural gas prices continue to remain depressed, certain third-party producers under our Gas Marketing segment have begun and may continue to experience financial distress, which has led to certain contractual defaults and litigation. To date, we have had no material counterparty default losses; however, we expect continued deterioration in the financial position of some counterparties. In 2015, we recorded an allowance for doubtful accounts of approximately $0.5 million . We have initiated several legal actions for collection against some of the third-party producers, which have resulted in no collections and some of the third-party producers shutting-in wells. As a result, we expect RNG's expenses to exceed its revenues by approximately $1 million to $2 million per year through 2022, assuming a continuation of current economic conditions. Following the sale of our 50% ownership interest in PDCM in October 2014, RNG's marketing activities were scaled down and are focused on selling natural gas production to meet its volume commitments. After the long-term firm transportation agreements expire, we expect to discontinue this segment. +For additional information regarding our business segments, see Note 17, Business Segments , to our consolidated financial statements included elsewhere in this report. +Properties +Productive Wells +The following table presents our productive wells: +Productive Wells +As of December 31, 2015 +Crude Oil +Natural Gas +Total +Operating Region/Area +Gross +Net +Gross +Net +Gross +Net +Wattenberg Field +625 +380.9 +2,329 +2,102.9 +2,954 +2,483.8 +Utica Shale +25 +19.9 +3 +3.0 +28 +22.9 +Total productive wells +650 +400.8 +2,332 +2,105.9 +2,982 +2,506.7 +Proved Reserves +The following table presents our proved reserve estimates as of December 31, 2015 based on a reserve report prepared by Ryder Scott and related information: +Proved Reserves at December 31, 2015 +Proved Reserves (MMBoe) +% of Total Proved Reserves +% Proved Developed +% Liquids +Proved Reserves to Production Ratio (in years) +2015 Production (MBoe) +Wattenberg Field +270 +99 +% +25 +% +60 +% +18.9 +14,232 +Utica Shale +3 +1 +% +100 +% +55 +% +2.8 +1,138 +Total proved reserves +273 +100 +% +26 +% +60 +% +17.8 +15,370 +Our proved reserves are sensitive to future crude oil, natural gas and NGLs sales prices and the related effect on the economic productive life of producing properties. Increases in commodity prices may result in a longer economic productive life of a property or result in recognition of more economically viable proved undeveloped reserves. Decreases in commodity prices may result in negative impacts of this nature. +All of our proved reserves are located onshore in the U.S. Our proved reserve estimates are prepared using the definitions for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a) and other applicable SEC rules. As of December 31, 2015 , all of our proved reserves, including our proportionate share of our affiliated partnerships' reserves, have been estimated by Ryder Scott. +7 +We have a comprehensive process that governs the determination and reporting of our proved reserves. As part of our internal control process, our reserves are reviewed annually by an internal team composed of reservoir engineers, geologists and accounting personnel for adherence to SEC guidelines through a detailed review of land records, available geological and reservoir data, and production performance data. The process includes a review of applicable working and net revenue interests and cost and performance data. The internal team compiles the reviewed data and forwards the data to Ryder Scott. +When preparing our reserve estimates, Ryder Scott did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, production volumes, well test data, historical costs of operations and development, product prices or any agreements relating to current and future operations of properties and sales of production. Ryder Scott prepares an estimate of our reserves in conjunction with an ongoing review by our engineers. A final comparison of data is performed to ensure that the reserve estimates are complete, determined pursuant to acceptable industry methods and with a level of detail we deem appropriate. The final estimated reserve report is reviewed by our engineering staff and management prior to issuance by Ryder Scott. +The professional qualifications of the internal lead engineer primarily responsible for overseeing the preparation of our reserve estimates qualify the engineer as a Reserves Estimator, as defined in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the Society of Petroleum Engineers. This person holds a Bachelor of Science degree in Petroleum and Chemical Refining Engineering with a minor in Petroleum Engineering, has over 39 years of experience in reservoir engineering, is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers and is a registered Professional Engineer in the State of Colorado. +The SEC's reserve rules allow the use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. We used a combination of performance methods including decline curve analysis and other computational methods, offset analogies, and seismic data and interpretation to calculate our 2015 reserve estimates. All of our proved undeveloped reserves conform to the SEC five-year rule requirement as all proved undeveloped locations are scheduled, according to an adopted development plan, to be drilled within five years of each location’s initial booking date. +Reserve estimates involve judgments and cannot be measured exactly. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geological and geophysical data and economic changes. Neither the estimated future net cash flows nor the standardized measure of discounted future net cash flows ("standardized measure") is intended to represent the current market value of our proved reserves. For additional information regarding both of these measures, as well as other information regarding our proved reserves, see the unaudited Supplemental Information - Crude Oil and Natural Gas Information provided with our consolidated financial statements included elsewhere in this report. The following tables provide information regarding our estimated proved reserves: +As of December 31, +2015 +2014 +2013 (3) +Proved reserves +Crude oil and condensate (MMBbls) +99 +101 +94 +Natural gas (Bcf) +661 +537 +740 +NGLs (MMBbls) +64 +60 +49 +Total proved reserves (MMBoe) +273 +250 +266 +Proved developed reserves (MMBoe) +70 +75 +76 +Estimated future net cash flows (in millions) (1) +$ +2,259 +$ +4,938 +$ +4,323 +PV-10 ( in millions) (2) +$ +1,338 +$ +3,450 +$ +2,704 +Standardized measure (in millions) +$ +1,097 +$ +2,306 +$ +1,782 +___________ +(1) +Amount represents undiscounted pre-tax future net cash flows estimated by Ryder Scott of approximately $2.8 billion , $7.3 billion and $6.4 billion as of December 31, 2015 , 2014 and 2013 , respectively, less an internally-estimated future income tax expense of approximately $0.5 billion , $2.3 billion and $2.1 billion , respectively. +(2) +PV-10 is a non-U.S. GAAP financial measure. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in accordance with U.S. GAAP, but rather should be considered in addition to the standardized measure. See Part I, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10 and a reconciliation of our PV-10 value to the standardized measure. +(3) +Includes estimated reserve data related to our Marcellus Shale crude oil and natural gas properties, which were divested in October 2014. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of these assets. +The following table sets forth information regarding estimated proved reserves for our Marcellus Shale crude oil and natural gas properties: +8 +December 31, 2013 +Proved reserves +Natural gas (Bcf) +237 +Total proved reserves (MMBoe) +40 +Proved developed reserves (MMBoe) +9 +Estimated future net cash flows (in millions) +$ +394 +The following table presents our estimated proved developed and undeveloped reserves by category and area: +As of December 31, 2015 +Operating Region/Area +Crude Oil and Condensate (MBbls) +Natural Gas +(MMcf) +NGLs +(MBbls) +Crude Oil +Equivalent +(MBoe) +Percent +Proved developed +Wattenberg Field +25,240 +166,679 +14,284 +67,304 +95 +% +Utica Shale +1,017 +8,688 +727 +3,192 +5 +% +Total proved developed +26,257 +175,367 +15,011 +70,496 +100 +% +Proved undeveloped +Wattenberg Field +72,718 +485,370 +48,716 +202,329 +100 +% +Utica Shale +— +— +— +— +— +% +Total proved undeveloped +72,718 +485,370 +48,716 +202,329 +100 +% +Proved reserves +Wattenberg Field +97,958 +652,049 +63,000 +269,633 +99 +% +Utica Shale +1,017 +8,688 +727 +3,192 +1 +% +Total proved reserves +98,975 +660,737 +63,727 +272,825 +100 +% +We have stress-tested our proved reserve estimates as of December 31, 2015 to determine the impact of lower crude oil prices. Replacing the 2015 NYMEX commodity prices used in estimating our reported proved reserves (see Supplemental Information - Crude Oil and Natural Gas Information, provided with our consolidated financial statements included elsewhere in this report) with those shown on the table below, and leaving all other parameters unchanged, results in a decrease in our estimated proved reserves as shown below. +Pricing Scenario - NYMEX +Crude Oil (per Bbl) (1) +Natural Gas (per MMBtu) (1) +Proved Reserves (MMBoe) +% Change from December 31, 2015 Estimated Reserves +2015 Reserve Report (2) +$ +50.28 +$ +2.59 +272.8 +— +Scenario A +40.00 +2.59 +266.1 +(2 +)% +Scenario B +30.00 +2.59 +256.5 +(6 +)% +__________ +(1) +These prices are indices and do not include basin differentials for crude oil and natural gas. The above scenarios were calculated using the indicated index prices, less any basin differentials, transport fees, contractual adjustments and any Btu adjustments we experienced for the respective commodity. +(2) +The NYMEX prices used for the 2015 Reserve Report are based on SEC price parameters using the unweighted average of the prices in effect on the first day of the month for each month within the period of January 2015 through December 2015. +9 +Developed and Undeveloped Acreage +The following table presents our developed and undeveloped lease acreage: +As of December 31, 2015 +Developed +Undeveloped +Total +Operating Region/Area +Gross +Net +Gross +Net +Gross +Net +Wattenberg Field +97,600 +89,400 +7,600 +6,300 +105,200 +95,700 +Utica Shale +3,166 +2,670 +66,132 +62,044 +69,298 +64,714 +Total acreage +100,766 +92,070 +73,732 +68,344 +174,498 +160,414 +Substantially all of our undeveloped acreage in the Wattenberg Field is related to leaseholds that are held-by-production. Approximately 8% , 21% and 7% of our undeveloped leaseholds in the Utica Shale are scheduled to expire during 2016, 2017 and 2018, respectively. While the undeveloped leaseholds expiring in 2016 in the Utica Shale are not significant, we believe that our planned modest investment in the Utica Shale in 2016 will provide production, reservoir and completion analyses that will provide us with a better understanding of our Utica Shale acreage as we exit 2016 and may influence our re-leasing decisions as more undeveloped leaseholds expire in 2017. In the event these leaseholds are not renewed, we do not expect a significant charge as the carrying value of our Utica Shale acreage as of December 31, 2015 is not material as a result of impairments recorded in 2014 and 2015. +Drilling Activity +The following table presents information regarding the number of wells drilled or participated in for the period presented. The number of wells drilled refers to the number of wells completed at any time during the fiscal year, regardless of when drilling was initiated. +Year Ended December 31, +2015 +2014 +2013 +Operating Region +Gross +Net +Gross +Net +Gross +Net +Wattenberg Field, operated wells +140 +113.5 +88 +71.0 +62 +53.3 +Wattenberg Field, non-operated wells +58 +9.3 +70 +14.9 +35 +7.9 +Utica Shale +4 +3.0 +9 +8.0 +11 +8.7 +Other (1) +— +— +4 +2.0 +10 +5.0 +Total wells drilled +202 +125.8 +171 +95.9 +118 +74.9 +__________ +(1) +Includes drilling activity in the Marcellus Shale crude oil and natural gas properties, which were divested in October 2014. +The following tables set forth our developmental and exploratory well drilling activity for the periods presented. There is no necessary correlation between the number of productive wells completed during any period and the aggregate reserves attributable to those wells. Productive wells consist of wells spud, turned-in-line and producing during the period. In-process wells represent wells that are in the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection as of the date shown. +Net Development Well Drilling Activity +Year Ended December 31, +2015 +2014 +2013 +Operating Region/Area +Productive +In-Process +Dry (1) +Productive +In-Process +Dry (1) +Productive +In-Process +Dry +Wattenberg Field, operated wells +110.8 +50.6 +2.7 +75.8 +36.5 +1.7 +40.5 +— +— +Wattenberg Field, non-operated wells +9.3 +4.6 +— +14.9 +6.3 +— +13.0 +15.6 +0.1 +Utica Shale +3.0 +4.2 +— +7.0 +3.0 +1.0 +3.0 +2.0 +— +Other (2) +— +— +— +2.0 +— +— +3.5 +2.0 +— +Total net development wells +123.1 +59.4 +2.7 +99.7 +45.8 +2.7 +60.0 +19.6 +0.1 +__________ +(1) +Represents mechanical failures that resulted in the plugging and abandonment of the respective wells. +(2) +Includes activity in the Marcellus Shale crude oil and natural gas properties, which were divested in October 2014. +10 +We had no exploratory well drilling activity in 2015 and 2014. The following table presents our net exploratory well drilling activity in 2013: +Net Exploratory Well Drilling Activity +December 31, 2013 +Operating Region/Area +Productive +In-Process +Dry +Utica Shale +4.2 +— +— +Other (1) +1.5 +— +— +Total net exploratory wells +5.7 +— +— +__________ +(1) +Includes activity in the Marcellus Shale crude oil and natural gas properties, which were divested in October 2014. +Title to Properties +We believe that we hold good and defensible leasehold title to substantially all of our crude oil and natural gas properties in accordance with standards generally accepted in the industry. A preliminary title examination is typically conducted at the time the undeveloped properties are acquired. Prior to the commencement of drilling operations, a title examination is conducted and remedial curative work is performed with respect to discovered defects which we deem to be significant. Title examinations have been performed with respect to substantially all of our producing properties. +The properties we own are subject to royalty, overriding royalty and other outstanding interests. The properties may also be subject to additional burdens, liens or encumbrances customary in the industry, including items such as operating agreements, current taxes, development obligations under crude oil and natural gas leases, farm-out agreements and other restrictions. We do not believe that any of these burdens will materially interfere with our use of the properties. +Substantially all of our crude oil and natural gas properties, excluding our share of properties held by the limited partnerships that we sponsor, have been mortgaged or pledged as security for our revolving credit facility. See Note 8, Long-Term Debt , to our consolidated financial statements included elsewhere in this report. +Facilities +We lease 56,000 square feet of office space in Denver, Colorado, which serves as our corporate office, through February 2021. We own a 32,000 square foot administrative office building located in Bridgeport, West Virginia and a newly acquired 60,000 square foot field operating facility in Greeley, Colorado. +We own or lease field operating facilities in Evans, Colorado and Marietta, Ohio. +Governmental Regulation +While the prices of crude oil and natural gas are market driven, other aspects of our business and the industry in general are heavily regulated. The availability of a ready market for crude oil and natural gas production depends on several factors that are beyond our control. These factors include, but are not limited to, regulation of production, federal and state regulations governing environmental quality and pollution control, the amount of crude oil and natural gas available for sale, the availability of adequate pipeline and other transportation and processing facilities and the marketing of competitive fuels. In general, state and federal regulations are intended to protect consumers from unfair treatment and undue control, reduce environmental and health risks from the development and transportation of crude oil and natural gas, prevent misuse of crude oil and natural gas and protect rights among owners in a common reservoir. Pipelines are subject to the jurisdiction of various federal, state and local agencies. We believe that we are in compliance with such statutes, rules, regulations and governmental orders in all material respects, although there can be no assurance that this is or will remain the case. The following summary discussion of the regulation of the U.S. oil and gas industry is not intended to constitute a complete discussion of the various statutes, rules, regulations and environmental directives to which our operations may be subject. +Regulation of Crude Oil and Natural Gas Exploration and Production . Our exploration and production business is subject to various federal, state and local laws and regulations relating to the taxation of crude oil and natural gas, the development, production and marketing of crude oil and natural gas and environmental and safety matters. State and local laws and regulations require drilling permits and govern the spacing and density of wells, rates of production, water discharge, prevention of waste and other matters. Prior to commencing drilling activities for a well, we must procure permits and/or approvals for the various stages of the drilling process from the applicable state and local agencies where the well being drilled is located. Additionally, other regulated matters include: +• +bond requirements in order to drill or operate wells; +• +well locations; +• +drilling and casing methods; +11 +• +surface use and restoration of well properties; +• +well plugging and abandoning; +• +fluid disposal; and +• +air emissions. +In 2014, Colorado Governor Hickenlooper created a task force charged with crafting recommendations to help minimize land use conflicts relating to the location of oil and gas facilities. The task force was created pursuant to a compromise under which certain potential ballot initiatives that would have impacted the oil and natural gas industry in Colorado were withdrawn from the November 2014 ballot. The task force, which was called the Task Force on State and Local Regulation of Oil and Gas Operations, was comprised of 21 members representing various interests. Recommendations of the task force regarding new or amended legislation, appropriations or other action were submitted to the Governor in February 2015. In 2015 and into 2016, the Colorado Oil and Gas Conservation Commission (the “COGCC”) conducted a rulemaking to implement two of these task force recommendations related to the permitting of large-scale facilities in urban mitigation areas and municipality notice provisions. Both rulemakings were finalized in January 2016 and new rules will become effective in spring 2016. In addition, depending on the outcome of the task force process and any related legislative or administrative activity, ballot initiatives, like those proposed in December 2015 and again in January 2016, affecting our operations may be proposed and adopted by the voters in future elections. +In addition, our drilling activities involve hydraulic fracturing, which may be subject to additional federal and state disclosure and regulatory requirements discussed in "Environmental Matters" below and in Item 1A, Risk Factors . +Our operations also are subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells which may be drilled and the unitization or pooling of lands and leases. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is primarily or exclusively voluntary, it may be more difficult to form units, and therefore, more difficult to drill and develop our leases where we own less than 100% of the leases located within the proposed unit. State laws may establish maximum rates of production from crude oil and natural gas wells, prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. Leases covering state or federal lands often include additional regulations and conditions. The effect of these conservation laws and regulations may limit the amount of crude oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Such laws and regulations may increase the costs of planning, designing, drilling, installing, operating and abandoning our crude oil and natural gas wells and other facilities. These laws and regulations, and any others that are passed by the jurisdictions where we have production, can limit the total number of wells drilled or the allowable production from successful wells, which can limit our reserves. As a result, we are unable to predict the future cost or effect of complying with such regulations. +Regulation of Transportation of Natural Gas . We move natural gas through pipelines owned by other companies and sell natural gas to other companies that also utilize common carrier pipeline facilities. Natural gas pipeline interstate transmission and storage activities are subject to regulation by the Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act of 1938 ("NGA") and under the Natural Gas Policy Act of 1978, and, as such, rates and charges for the transportation of natural gas in interstate commerce, accounting, and the extension, enlargement or abandonment of jurisdictional facilities, among other things, are subject to regulation. Each natural gas pipeline company holds certificates of public convenience and necessity issued by FERC authorizing ownership and operation of all pipelines, facilities and properties for which certificates are required under the NGA. Each natural gas pipeline company is also subject to the Natural Gas Pipeline Safety Act of 1968, as amended, which imposes safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities. FERC regulations govern how interstate pipelines communicate and do business with their affiliates. Interstate pipelines may not operate their pipeline systems to preferentially benefit their marketing affiliates. +Each interstate natural gas pipeline company establishes its rates primarily through FERC's rate-making process. Key determinants in the ratemaking process are: +• +costs of providing service, including depreciation expense; +• +allowed rate of return, including the equity component of the capital structure and related income taxes; and +• +volume throughput assumptions. +The availability, terms and cost of transportation affect our natural gas sales. Competition among suppliers has greatly increased. Furthermore, gathering is exempt from regulation under the Natural Gas Act, thus allowing gatherers to charge unregulated rates. Historically, producers were able to flow supplies into interstate pipelines on an interruptible basis; however, recently we have seen the increased need to acquire firm transportation on pipelines in order to avoid curtailments or shut-in gas, which could adversely affect cash flows from the affected area. +Additional proposals and proceedings that might affect the industry occur frequently in Congress, FERC, state commissions, state legislatures and the courts. The industry historically has been very heavily regulated and there is no assurance that the current regulatory approach recently taken by FERC and Congress will continue. We cannot determine to what extent our future operations and earnings will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels. +12 +Environmental Matters +Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public demand for the protection of the environment has increased dramatically in recent years. The trend towards more expansive environmental legislation and regulations is expected to continue. To the extent laws are enacted or other governmental actions are taken which restrict drilling or impose environmental protection requirements resulting in increased costs, our business and prospects may be adversely affected. +We generate wastes that may be subject to the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S. Environmental Protection Agency ("EPA") and various state agencies have adopted requirements that limit the approved disposal methods for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by our operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore may subject us to more rigorous and costly operating and disposal requirements. +Hydraulic fracturing is commonly used to stimulate production of crude oil and/or natural gas from dense subsurface rock formations. We routinely apply fracturing in our crude oil and natural gas production programs. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the crude oil or natural gas to more easily flow to the wellbore. The process is generally subject to regulation by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over certain fracturing activities involving diesel fuel under the federal Safe Drinking Water Act ("SDWA") and issued draft guidance related to this asserted regulatory authority in February 2014. The guidance explains the EPA’s interpretation of the term “diesel fuel” for permitting purposes, describes existing Underground Injection Control Class II program requirements for permitting underground injection of diesel fuels in hydraulic fracturing and also provides recommendations for EPA permit writers in implementing these requirements. From time to time, Congress has considered legislation that would provide for broader federal regulation of hydraulic fracturing and disclosure of the chemicals used in the hydraulic fracturing process. +The White House Council on Environmental Quality continues to coordinate an administration-wide review of hydraulic fracturing. The EPA continues its study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater and issued a draft assessment in June 2015, with a final, peer-reviewed report expected in 2016. In addition, the U.S. Department of Energy has investigated practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. These ongoing studies, depending on their degree of development and nature of results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. The U.S. Department of the Interior, through the Bureau of Land Management (the “BLM”), also finalized a rule in 2015 requiring the disclosure of chemicals used, mandating well integrity measures, and imposing other requirements relating to hydraulic fracturing on federal lands. The rule is currently stayed and not effective pending ongoing litigation. +The states in which we operate, Colorado and Ohio, have adopted regulations regarding permitting, transparency and well construction requirements with respect to hydraulic fracturing operations and may in the future adopt additional regulations or otherwise seek to ban fracturing activities altogether. Colorado requires that all chemicals used in the hydraulic fracturing of a well be reported in a publicly searchable registry website developed and maintained by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission ("Frac Focus"). The Colorado rules also require operators seeking new location approvals to provide certain information to surface owners and adjacent property owners within 500 feet of a new well. Similarly, Colorado has implemented a baseline groundwater sampling rule, a rule governing setback distances of oil and gas wells located near population centers, and recently adopted new rules governing the development of large-scale facilities in urban mitigation areas and additional municipality notice requirements. In December 2013, the COGCC issued new, more restrictive rules regarding spill reporting and remediation. See further discussion in Item 1A, Risk Factors . +In addition, during 2014, the Colorado Oil and Gas Conservation Act was amended to increase the potential sanctions for violating the Act or its implementing regulations, orders, or permits. These amendments increase the maximum penalty per violation per day from $1,000 to $15,000; eliminate a $10,000 maximum penalty for violations that do not result in significant waste of oil and gas resources, damage to correlative rights, or adverse impact to public health, safety, or welfare; require the COGCC to assess a penalty for each day there is evidence of a violation; and authorize the COGCC to prohibit the issuance of new permits and suspend certificates of clearance for egregious violations resulting from gross negligence or knowing and willful misconduct. In December 2014, the COGCC convened a hearing and adopted proposed amendments to its regulations to implement this new legislation and address certain other issues. Among other things, the amendments create a new process for calculating penalties, new standards for determining days of violation and penalty amounts, new restrictions on the use of informal enforcement procedures and penalty reductions for voluntary disclosures. Following the adoption of this new penalty scheme, Colorado operators have experienced increased penalties for violations within COGCC’s jurisdiction. +In 2015, the COGCC convened hearings on regulations for large facilities located in urban mitigation areas. These new rules, which are anticipated to be effective in March 2016, require best available technology and include required mitigations for emissions, flaring, fire, fluid leak detection, repair, reporting, automated well shut-in, storage tank pressure control and proppant dust control. During these hearings, COGCC staff reported there would also be site-specific mitigation requirements for noise, ground and surface water protection, visual impacts and remote stimulation. After debate, the rule did not include duration limits despite an opinion from the State Attorney General Office that the COGCC possessed authority to impose duration limits under current and existing statutes. +In November 2013, the Ohio Department of Natural Resources ("ODNR") proposed draft regulations pertaining to well pad construction requirements and increased bonding for construction, and these regulations were finalized in 2014. +13 +In October 2015, the ODNR proposed draft regulations pertaining to incident notification. These rules are not yet final and we do not have an anticipated effective date. Additionally, in November 2015, the ODNR Assistant Chief announced draft rules in progress include waste management, waste classification, secondary containment, emergency reporting, site remediation standards, well spacing and simultaneous operations. We continue to be an active participant in the rule making process in Ohio. +In Colorado, local governing bodies have begun to issue drilling moratoriums, develop jurisdictional siting, permitting and operating requirements and conduct air quality studies to identify potential public health impacts. For instance, in 2013, the City of Fort Collins, Colorado, adopted a ban on drilling and fracturing of new wells within city limits. In the November 2013 election, voters in the cities of Boulder, Lafayette, Fort Collins and Brighton passed hydraulic fracturing bans. See Item 1A, Risk Factors , for a more detailed discussion of these bans. If new laws or regulations that significantly restrict hydraulic fracturing or well locations continue to be adopted at local levels or are adopted at the state level, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of hydrocarbons, may preclude our ability to drill wells. If hydraulic fracturing becomes more heavily regulated as a result of federal or state legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements and permitting delays, as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of crude oil and natural gas that we are ultimately able to produce from our reserves. We continue to be active in stakeholder and interest groups and to engage with regulatory agencies in an open, proactive dialogue regarding these matters. +We currently own or lease numerous properties that for many years have been used for the exploration and production of crude oil and natural gas. Although we believe that we have generally utilized good operating and waste disposal practices, and when necessary, appropriate remediation techniques, prior owners and operators of these properties may not have utilized similar practices and techniques and hydrocarbons or other wastes may have been disposed of or released on or under the properties that we own or lease or on or under locations where such wastes have been taken for disposal. These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), RCRA and analogous state laws, as well as state laws governing the management of crude oil and natural gas wastes. Under such laws, we may be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators) or remediate property contamination (including surface and groundwater contamination) or to perform remedial plugging operations to prevent future contamination. +CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for release of hazardous substances under CERCLA may be subject to full liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Under state laws, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. As an owner and operator of crude oil and natural gas wells, we may be liable pursuant to CERCLA and similar state laws. +Our operations are subject to the federal Clean Air Act ("CAA") and comparable state and local requirements. The CAA contains provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and states continue the development of regulations to implement these requirements. We may be required to incur certain capital expenditures in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. Greenhouse gas record keeping and reporting requirements of the CAA became effective in 2011 and will continue into the future with increased costs for administration and implementation of controls. Federal New Source Performance Standards regarding oil and gas operations ("NSPS OOOO") became effective in 2012, with more amendments effective in 2013 and 2014, all of which have added administrative and operational costs. In addition, as part of its comprehensive strategy to further reduce methane emissions from the oil and gas sector, EPA proposed amendments to NSPS OOOO in 2015 that would impose additional control and other requirements to reduce such emissions. A final rule is expected in the summer of 2016. Colorado adopted new regulations to meet the requirements of NSPS OOOO and promulgated significant new rules in February 2014 relating specifically to crude oil and natural gas operations that are more stringent than NSPS OOOO and directly regulate methane emissions from affected facilities. In April 2014, the Ohio Environmental Protection Agency Division of Air Pollution Control adopted new General Permit requirements for High Volume Horizontal Hydraulic Fracturing, Oil and Gas Well Site Production Operations. In October 2015, the EPA strengthened the National Ambient Air Quality Standards (“NAAQS”) for ground level ozone to 70 parts per billion (“ppb”) from 75 ppb. In addition, the EPA extended the ozone monitoring season for 32 states, including Colorado and Ohio. By October 2016, states are expected to have revised state implementation plans and proposed regulations to meet the new standard. +The federal Clean Water Act ("CWA") and analogous state laws impose strict controls against the discharge of pollutants and fill material, including spills and leaks of crude oil and other substances. The CWA also requires approval and/or permits prior to construction, where construction will disturb wetlands or other waters of the U.S. The CWA also regulates storm water run-off from crude oil and natural gas facilities and requires storm water discharge permits for certain activities. Spill Prevention, Control, and Countermeasure ("SPCC") requirements of the CWA require appropriate secondary containment loadout controls, piping controls, berms and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture or leak. The EPA and U.S. Army Corps of Engineers released a Connectivity Report in September 2013 which determined that the vast majority of tributary streams, wetlands, open water in floodplains and riparian areas are connected. This report supported the final rule issued in June 2015 defining the scope of jurisdictional Waters of the U.S. This final rule has been stayed pending the resolution of ongoing litigation. +14 +The Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. Some of our operations may be located in areas that are or may be designated as habitats for endangered or threatened species. The U.S. Fish and Wildlife Service in May 2014 proposed a rule to alter how it identifies critical habitat for endangered and threatened species. It is unclear when this rule will be finalized. +Crude oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of crude oil spills. Federal regulations require certain owners or operators of facilities that store or otherwise handle crude oil, including us, to procure and implement additional SPCC measures relating to the possible discharge of crude oil into surface waters. The Oil Pollution Act of 1990 ("OPA") subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from crude oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Historically, we have not experienced any significant crude oil discharge or crude oil spill problems. Our shift in production since mid-2010 to a greater percentage of crude oil increases our risks related to soil and water contamination from any future oil spills. +Our costs relating to protecting the environment have risen over the past few years and are expected to continue to rise in 2016 and beyond. Environmental regulations have increased our costs and planning time, but have had no materially adverse effect on our ability to operate to date. However, no assurance can be given that environmental regulations or interpretations of such regulations will not, in the future, result in a curtailment of production or otherwise have a materially adverse effect on our business, financial condition or results of operations. See Note 12, Commitments and Contingencies , to our consolidated financial statements included elsewhere in this report. +Operating Hazards and Insurance +Our exploration and production operations include a variety of operating risks, including, but not limited to, the risk of fire, explosions, blowouts, cratering, pipe failure, casing collapse, abnormally pressured formations and environmental hazards such as gas leaks, ruptures and discharges of crude oil and natural gas. The occurrence of any of these events could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation and penalties and suspension of operations. Our pipeline, gathering and distribution operations are subject to the many hazards inherent in the industry. These hazards include damage to wells, pipelines and other related equipment, damage to property caused by hurricanes, floods, fires and other acts of God, inadvertent damage from construction equipment, leakage of natural gas and other hydrocarbons, fires and explosions and other hazards that could also result in personal injury and loss of life, pollution and suspension of operations. In 2013, we experienced widespread flooding in our Wattenberg Field operations in Weld County, Colorado, which resulted in a shut-in of approximately 200 vertical wells. We incurred significant costs to replace damaged well equipment and to bring vertical wells back on-line. In 2014 and 2015, we experienced three mechanical failures during drilling that resulted in the discharge of oil and related material. The mechanical failures did not have a material adverse effect on our financial condition or results of operations. +Among the regulatory developments involving operating hazards that could impact us going forward are recent investigations by the U.S. Occupational Health and Safety Administration (“OSHA”) and other governmental authorities regarding potential worker exposure to hydrocarbon vapors from certain petroleum transfer and related tasks. Several recent worker fatalities at oil and gas facilities nationwide are being reviewed by OSHA and other governmental authorities for a potential link to hydrocarbon vapor exposure. Regulatory requirements generally relating to worker exposure to hydrocarbon vapors could be increased or receive heightened scrutiny going forward. +Any significant problems related to our facilities could adversely affect our ability to conduct our operations. In accordance with customary industry practice, we maintain insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant event not fully insured against could materially adversely affect our operations and financial condition. We cannot predict whether insurance will continue to be available at premium levels that justify our purchase or will be available at all. Furthermore, we are not insured against our economic losses resulting from damage or destruction to third-party property, such as transportation pipelines, crude oil refineries or natural gas processing facilities. Such an event could result in significantly lower regional prices or our inability to deliver our production. +Competition and Technological Changes +We believe that our production, exploration and drilling capabilities and the experience of our management and professional staff enable us to compete effectively in our industry. We encounter competition from numerous other crude oil and natural gas companies, drilling and income programs and partnerships in all areas of operations, including drilling and marketing crude oil and natural gas, obtaining desirable crude oil and natural gas leases on producing properties, obtaining drilling, pumping and other services, attracting and retaining qualified employees and obtaining capital. International developments may influence other companies to increase their domestic crude oil and natural gas exploration. Competition among companies for favorable prospects can be expected to continue and it is anticipated that the cost of acquiring properties will increase in the future. Many of our competitors possess larger staffs and greater financial resources than we do, which may enable them to identify and acquire desirable producing properties and drilling prospects more economically. Our ability to acquire additional properties and to explore for crude oil and natural gas prospects in the future depends upon our ability to conduct our operations, evaluate and select suitable properties and consummate transactions in this highly competitive environment. We also face intense competition in other aspects of our business, including the marketing of natural gas from competitors including other producers and marketing companies. +The oil and gas industry is characterized by rapid and significant technological advancements and introduction of new products and services using new technologies. If one or more of the technologies we use now or in the future become obsolete or if we are unable to use the +15 +most advanced commercially available technology, our business, financial condition, results of operations and cash flows could be materially adversely affected. +Employees +As of December 31, 2015 , we had 362 full-time employees. Our employees are not covered by collective bargaining agreements. We consider relations with our employees to be good. +WHERE YOU CAN FIND ADDITIONAL INFORMATION +We file annual, quarterly and current reports, proxy statements and other information with the SEC. Our SEC filings are available free of charge from the SEC’s website at www.sec.gov or from our website at www.pdce.com. You may also read or copy any document we file at the SEC’s public reference room in Washington, D.C., located at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at (800) SEC-0330 for further information on the public reference room. We also make available free of charge any of our SEC filings by mail. For a mailed copy of a report, please contact PDC Energy Inc., Investor Relations, 1775 Sherman Street, Suite 3000, Denver, CO 80203, or call (800) 624-3821. +We recommend that you view our website for additional information, as we routinely post information that we believe is important for investors. Our website can be used to access such information as our recent news releases, committee charters, code of business conduct and ethics, shareholder communication policy, director nomination procedures and our whistle blower hotline. While we recommend that you view our website, the information available on our website is not part of this report and is not incorporated by reference. +16 +ITEM 1A. RISK FACTORS +You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock or other securities. +Risks Relating to Our Business and the Industry +Crude oil, natural gas and NGL prices fluctuate and declines in these prices, or an extended period of continuing low prices, can significantly affect the value of our assets and our financial results and impede our growth. +Our revenue, profitability, cash flows and liquidity depend in large part upon the prices we receive for our crude oil, natural gas and NGLs. Changes in prices affect many aspects of our business, including: +• +our revenue, profitability and cash flows; +• +our liquidity; +• +the quantity and present value of our reserves; +• +the borrowing base under our revolving credit facility and access to other sources of capital; and +• +the nature and scale of our operations. +The markets for crude oil, natural gas and NGLs are often volatile, and prices may fluctuate in response to, among other things: +• +relatively minor changes in regional, national or global supply and demand; +• +regional, national or global economic conditions, and perceived trends in those conditions; +• +geopolitical factors, such as events that may reduce or increase production from particular oil-producing regions and/or from members of the Organization of Petroleum Exporting Countries, or OPEC; and +• +regulatory changes. +The price of oil has fallen dramatically since mid-2014, with a high over $100 per barrel in June 2014 to recent lows below $30 per barrel, in each case based on WTI prices, due to a combination of factors including increased U.S. supply, global economic concerns, the likely resumption of oil exports from Iran and OPEC’s decision not to reduce supply. Prices for natural gas and NGLs have experienced declines of similar magnitude. These declines have adversely affected, among other things, our revenue and reserves, and has caused us to reduce our company-wide budgeted 2016 capital program relative to 2015 and contributed to the recognition of impairment charges, including charges of $158.3 million and $150.3 million to write-down our Utica Shale producing and non-producing crude oil and natural gas properties to their estimated fair value in 2014 and 2015, respectively. An extended period of continued lower oil prices, or additional price declines, will have further adverse effects on us. For example, if we reduce our capital expenditures further due to low prices, natural declines in production from our wells will likely result in reduced production and therefore reduced cash flow from operations, which would in turn further limit our ability to make the capital expenditures necessary to replace our reserves and production. +In addition to factors affecting the price of crude oil, natural gas and NGLs generally, the prices we receive for our production are affected by factors specific to us and to the local markets where the production occurs. The prices that we receive for our production are generally lower than the relevant benchmark prices that are used for calculating commodity derivative positions. These differences, or differentials, are difficult to predict and may widen or narrow in the future based on market forces. Differentials can be influenced by, among other things, local or regional supply and demand factors and the terms of our sales contracts. Over the longer term, differentials will be significantly affected by factors such as investment decisions made by providers of midstream facilities and services, refineries and other industry participants, and the overall regulatory and economic climate. For example, increases in U.S. domestic oil production generally may result in widening differentials, particularly for production from some basins. We may be materially and adversely impacted by widening differentials on our production. +A substantial part of our crude oil, natural gas and NGLs production is located in the Wattenberg Field, making us vulnerable to risks associated with operating primarily in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing formations. +Our operations are focused primarily on the Wattenberg Field, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Approximately $400 million , or 91% , of our 2016 capital forecast is expected to be spent on development activities in the Wattenberg Field. Because our operations are not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including: +• +fluctuations in prices of crude oil, natural gas and NGLs produced from the wells in the area; +• +natural disasters such as the flooding that occurred in the area in September 2013; +• +restrictive governmental regulations; and +• +curtailment of production or interruption in the availability of gathering, processing or transportation infrastructure and services, and any resulting delays or interruptions of production from existing or planned new wells. +17 +For example, bottlenecks in processing and transportation that have occurred in some recent periods in the Wattenberg Field have negatively affected our results of operations, and these adverse effects may be disproportionately severe to us compared to our more geographically diverse competitors. Similarly, the concentration of our assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules, that could adversely affect development activities or production relating to those formations. Such an event could have a material adverse effect on our results of operations and financial condition. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the Wattenberg Field, the demand for, and cost of, drilling rigs, equipment, supplies, personnel and oilfield services increase. Shortages or the high cost of drilling rigs, equipment, supplies, personnel or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital forecast, which could have a material adverse effect on our business, financial condition or results of operations. +Federal, state and local laws and regulations relating to hydraulic fracturing could result in increased costs, additional drilling and operating restrictions or delays in the production of crude oil, natural gas and NGLs, and could prohibit hydraulic fracturing activities. +Substantially all of our drilling uses hydraulic fracturing. Hydraulic fracturing is an important and commonly used process in the completion of unconventional wells in shale, coalbed, and tight sand formations. Proposals have been introduced in the U.S. Congress to regulate hydraulic fracturing operations and related injection of fracturing fluids and propping agents used by the crude oil and natural gas industry in fracturing fluids under the Safe Drinking Water Act (“SDWA”), and to require the disclosure of chemicals used in the hydraulic fracturing process under the SDWA, the Emergency Planning and Community Right-to-Know Act (“EPCRA”), or other laws. Sponsors of these bills, which have been subject to various proceedings in the legislative process, including in the House Energy and Commerce Committee and the Senate Environmental and Public Works Committee, have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies and otherwise cause adverse environmental impacts. In March 2011, the EPA announced its intention to conduct a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. In June 2015, the EPA released a draft assessment of the potential impacts to drinking water resources from hydraulic fracturing for public comment and peer review. The assessment concludes that while there are mechanisms by which hydraulic fracturing can impact drinking water resources, there was no evidence that these mechanisms have led to widespread, systemic impacts on drinking water resources in the United States. EPA’s science advisory board, however, has subsequently questioned several elements and conclusions in EPA’s draft assessment. In addition, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. +EPA has begun a Toxic Substances Control Act rulemaking which will collect expansive information on the chemicals used in hydraulic fracturing fluid, as well as other health-related data, from chemical manufacturers and processors. EPA has not indicated when it intends to issue a proposed rule, but it issued an Advanced Notice of Proposed Rulemaking in May 2014, seeking public comment on a variety of issues related to the rulemaking. In October 2015, EPA also granted, in part, a petition filed by several national environmental advocacy groups to add the oil and gas extraction industry to the list of industries required to report releases of certain “toxic chemicals” under the Toxics Release Inventory (“TRI”) program under EPCRA. EPA determined that natural gas processing facilities may be appropriate for addition to the scope of TRI and will conduct a rulemaking process to propose such action. +EPA also finalized major new U.S. Clean Air Act (“CAA”) standards (New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants) applicable to hydraulically fractured natural gas wells and certain storage vessels in August 2012. The standards require, among other things, use of reduced emission completions, or green completions, to reduce volatile organic compound emissions during well completions as well as new controls applicable to a wide variety of storage tanks and other equipment, including compressors, controllers, and dehydrators. Following administrative reconsideration of a portion of the 2012 rules, EPA issued one set of final amendments to the rule in September 2013 related to storage tanks, and a second set of final amendments largely related to reduced emissions completion requirements in December 2014. Most key provisions in the new CAA standards became effective in 2015. In January 2015, President Obama announced a comprehensive strategy to further reduce methane emissions from the oil and gas sector. As part of this strategy, in September 2015 EPA published proposed amendments to the 2012 NSPS Quad OOOO rules focused on achieving additional methane and volatile organic compound reductions from the oil and natural gas industry. The proposed rule would include, among others, new requirements for leak detection and repair, control requirements at oil well completions, replacement of certain pneumatic pumps and controllers, and additional control requirements for gathering, boosting, and compressor stations. If finalized, these additional methane reduction requirements could increase future costs of our operations and require us to make modifications to our operations and install new equipment. These CAA rules and associated amendments are substantial and will increase future costs of our operations and will require us to make modifications to our operations and install new equipment. +On the same day EPA proposed amendments to NSPS Quad OOOO, EPA also published a proposed rule regarding source determination and permitting requirements for the onshore oil and gas industry under the CAA. The proposed rule sought public comment on two approaches for defining the term “adjacent,” which is one of three factors used to determine whether stationary sources (including oil and gas equipment and activities) are considered part of a source that is subject to major source permitting requirements under the CAA. Depending on EPA’s final approach, the oil and gas industry and our operations could be subject to increased permitting costs and more stringent control requirements. +EPA has also issued permitting guidance under the SDWA for the underground injection of liquids from hydraulically fractured (and other) wells where diesel is used. Depending upon how it is implemented, this guidance may create duplicative requirements in certain areas, further slow the permitting process in certain areas, increase the costs of operations, and result in expanded regulation of hydraulic fracturing activities by EPA and may therefore adversely affect even companies, such as PDC, that do not use diesel fuel in hydraulic fracturing activities. +Certain other federal agencies are analyzing, or have been requested to review, environmental issues associated with hydraulic fracturing. Most notably, in 2015 the U.S. Department of the Interior, through the Bureau of Land Management (the “BLM”), finalized regulations regarding +18 +chemical disclosure requirements and other regulations specific to well stimulation activities, including hydraulic fracturing, on federal and tribal lands. Due to pending litigation, however, the effective date of the rule has been postponed. In January 2016, BLM proposed rules to further regulate venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. The rules, which would require additional controls and impose new emissions and other standards on certain operations on applicable leases, are expected to be finalized in 2016. In October 2015, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) proposed to expand its regulations in a number of ways, including increased regulation of gathering lines, even in rural areas. The public comment period for this proposal closed January 8, 2016. In May 2015, the U.S. Department of Transportation also issued a final rule regarding the safe transportation of flammable liquids by rail. The final rule imposes certain requirements on “offerors” of crude oil, including sampling, testing, and certification requirements. +In addition, the governments of certain states, including Colorado and Ohio, have adopted or are considering adopting laws and regulations that impose or could impose, among other requirements, stringent permitting or air emission control requirements, disclosure, wastewater disposal, baseline sampling, seismic monitoring, well construction and well location requirements on hydraulic fracturing operations, more stringent notification or consultation processes, or otherwise seek to ban underground injection of fracturing wastewater or fracturing activities altogether. For example, in January 2012, the Ohio Department of Natural Resources (“ODNR”) issued a temporary moratorium on the development of hydraulic fracturing disposal wells in northeast Ohio in order to study the relationship between these wells and earthquakes reported in the area. As a result, ODNR promulgated new and more stringent regulations for certain underground injection wells, including requirements for a complete suite of geophysical logs, analytical interpretation of the logs, and enhanced monitoring and recording. More recently, in April 2014, ODNR shut down a number of well sites after a series of small earthquakes in northeast Ohio. After investigating the earthquakes and determining that the connection to hydraulic fracturing was “probable,” ODNR implemented new permit conditions, requiring that operators of well sites within three miles of a known fault must install sensitive seismic-monitoring equipment. Operators must also halt drilling if a seismic event exceeds 1.0 magnitude. New York has also placed a permanent moratorium on all hydraulic fracturing activities within the state. Similar initiatives could spread to states in which we operate. In addition, oil and gas producers may be subject to lawsuits brought by landowners for earthquake-related damages. +At the local level, some municipalities and local governments have adopted or are considering bans on hydraulic fracturing. Beginning in 2012, voters in the cities of Fort Collins, Boulder, Longmont, Broomfield and Lafayette, Colorado approved bans of varying length on hydraulic fracturing within their respective city limits. In 2014, Boulder and Larimer county lower courts overturned the bans. The cities of Longmont and Fort Collins appealed the decisions. In August 2015, the Court of Appeals requested that the Colorado Supreme Court rule on the issue. The Colorado Supreme Court heard oral arguments on December 9, 2015, and a decision is expected in the first half of 2016. If the Colorado Supreme Court determines the bans are valid, such a decision could increase the costs of our operations, impact our profitability, and prevent us from drilling in certain locations. In Ohio, several municipalities have passed hydraulic fracturing bans. In February 2015, the Ohio Supreme Court ruled that local governments cannot regulate hydraulic fracturing, finding that the State of Ohio has exclusive authority over regulating this activity under the State’s oil and gas preemption law, passed in 2004. In light of the recent Ohio Supreme Court decision, activists in Ohio are calling for the repeal of the oil and gas preemption law. +In addition, lawsuits have been filed against unrelated third parties in several states, including Colorado and Ohio, alleging contamination of drinking water by hydraulic fracturing. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to crude oil, natural gas and NGL production activities using hydraulic fracturing techniques. Additional legislation, regulation, litigation, or moratoria could also lead to operational delays or lead us to incur increased operating or capital costs in the production of crude oil, natural gas and NGLs, including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing or other drilling activities. If these legislative, regulatory, litigation, and other initiatives cause a material decrease in the drilling of new wells or an increase in drilling costs, our profitability could be materially impacted. +Ballot initiatives have been proposed in Colorado that could vastly expand the right of local governments to limit or prohibit oil and natural gas production and development in their jurisdictions and could impose additional regulations on production and development activities. If any initiative or legislation of this nature is implemented and survives legal challenge, additional limitations or prohibitions could be placed on crude oil, natural gas and NGL production and development within certain areas of Colorado or the state as a whole. Similar initiatives could be proposed in other states. This could adversely affect the cost, manner, and feasibility of development activities in Colorado or elsewhere, particularly those involving hydraulic fracturing, and significantly affect the value of our assets and our financial results and impede our growth. +Certain interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, have advanced various options for ballot initiatives aimed at significantly limiting or preventing oil and natural gas development. Signatures for two such proposals were submitted for a vote at the November 2014 election. One proposed to amend the Colorado constitution to establish an “environmental bill of rights” that would have allowed local governments in Colorado the right, without limitation, to prohibit crude oil and natural gas development within their respective jurisdictions. The second proposal would have imposed a statewide mandatory minimum spacing, or setback, between oil and gas wells and occupied structures of 2,000 feet. As part of a compromise negotiated by Governor John Hickenlooper, both initiatives were withdrawn prior to the election and were not voted upon. In December 2015, interest groups filed a package of 11 potential ballot initiatives focused on restricting oil and gas development in Colorado. Among other things, these initiatives, if successful, could require mandatory setbacks, allow local control over drilling, and impose prohibitions on drilling. Additional proposals of this nature may be made in the future, including in other states. Should any such proposal be successful and survive legal challenge, it could have a materially adverse impact on our ability to drill and/or produce crude oil and natural gas in Colorado or elsewhere, and could materially impact our results of operations, production and reserves. +19 +Moreover, pursuant to the compromise that resulted in the withdrawal of the 2014 ballot proposals, in February 2015, a task force created by the State of Colorado made recommendations for minimizing land use and other conflicts concerning the location of new oil and gas facilities. The task force ultimately approved and sent to Governor Hickenlooper for his review nine proposals. Three of the proposals required further legislative action, while the other six proposals required rulemaking or other regulatory action. The proposals contemplated (i) a senate bill that would postpone expiration of recently adopted regulations regarding air emissions; (ii) tasking the COGCC with crafting new rules related to siting of “large-scale” pads and facilities; (iii) requiring the industry to provide advance information about development plans to local governments; (iv) improving the COGCC’s local government liaison and designee programs; (v) adding 11 full-time staffers to the COGCC to improve inspections and field operations; (vi) bolstering the inspection staff and equipment for monitoring oil and gas facility air emissions and setting up a hotline for citizen health complaints at the Colorado Department of Public Health and Environment; (vii) creating a statewide oil and gas information clearinghouse; (viii) studying ways to ameliorate the impact of oil and gas truck traffic and (ix) creating a compliance-assistance program at the COGCC to help operators comply with the state’s changing rules and ensure consistent enforcement of rules by state inspectors. A number of additional proposals did not receive sufficient task force support to be included with the nine proposals, but may nevertheless result in future legislation or rulemakings. +In 2015 and into 2016, COGCC began a rulemaking to implement two of these recommendations (in particular items (ii) and (iii) identified above). With respect to recommendation (ii) above, the COGCC has finalized rules to permit “large-scale facilities” in “urban mitigation areas.” With respect to recommendation (iii) above, the COGCC finalized rules requiring operators to provide certain municipalities with public notice prior to engaging in operations. Both rules will become effective later in 2016. These rulemakings could impact our ability to develop and operate in certain areas in Colorado. The other seven recommendations, which were ministerial in nature and did not require a separate rulemaking, have been or are being implemented. +The marketability of our production is dependent upon transportation and processing facilities the capacity and operation of which we do not control. Market conditions or operational impediments, including high line pressures, particularly in the Wattenberg Field, and other impediments affecting midstream facilities and services, could hinder our access to crude oil, natural gas and NGL markets, increase our costs or delay production and thereby adversely affect our profitability. +Our ability to market our production depends in substantial part on the availability, proximity and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. If adequate midstream facilities and services are not available to us on a timely basis and at acceptable costs, our production and results of operations will be adversely affected. For example, in some recent periods, due to ongoing drilling activities by us and third parties and hot temperatures during the summer months, the principal third-party provider we use in the Wattenberg area for midstream facilities and services experienced increased gathering system pressures during those warmer months. The resulting capacity constraints reduced the productivity of some of our older vertical wells and limited incremental production from some of our newer horizontal wells. This constrained our production and reduced our revenue from the affected wells. Capacity constraints affecting natural gas production also impacted the associated NGLs. Similar events could occur in the future. We are also dependent on the availability and capacity of crude oil purchasers for our production. For example, reductions in purchases by a local crude oil refinery beginning in late 2013 increased the amount of oil that we had to transport out of the Wattenberg area for sale. This increased our transportation costs and reduced the price we received for the affected production for much of 2014. We expect this situation could occur again in the future. In addition, the use of alternative forms of transportation such as trucks or rail involve risks, including the risk that increased regulation could lead to increased costs or shortages of trucks or railcars. We face similar risks in our Utica operating area. In addition to causing production curtailments, capacity constraints can also reduce the price we receive for the crude oil, natural gas and NGLs we produce. Falling commodity prices have resulted in reduced investment in midstream facilities by some third parties, increasing the risk that sufficient midstream infrastructure will not be available in future periods. +Our business could be negatively impacted by security threats, including cybersecurity threats, and other disruptions. +We face various security threats, including attempts by third parties to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. There can be no assurance that the procedures and controls we use to monitor these threats and mitigate our exposure to them will be sufficient in preventing them from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial condition, results of operations, or cash flows. +In particular, the oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling activities, conduct reservoir modeling and reserves estimation, and to process and record financial and operating data. +We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to store, transmit, process and record sensitive information (including trade secrets, employee information and financial and operating data), communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil and gas reserves and for many other activities related to our business. The complexity of the technologies needed to explore for and develop oil, natural gas and NGLs make certain information more attractive to thieves. +Our business partners, including vendors, service providers, operating partners, purchasers of our production, and financial institutions, are also dependent on digital technology. Some of these business partners may be provided limited access to our sensitive information or our +20 +information systems and related infrastructure. Nevertheless, a vulnerability in the cyber security of one or more of our vendors could facilitate an attack on our systems. +As dependence on digital technologies has increased, cyber incidents, including deliberate attacks and unintentional events, have also increased. A cyber-attack could include an attempt to gain unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption. “Phishing” and other types of attempts to obtain unauthorized information or access are often sophisticated and difficult to detect or defeat. Certain countries are believed to possess cyber warfare capabilities and are credited with attacks on American companies and government agencies. Well publicized recent cyber-attacks include those directed at the U.S. Government’s Federal Office of Personnel Management, Anthem, Inc. and Sony Pictures, but lower profile attacks are also common. +Our technologies, systems and networks, and those of our business partners, may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, theft of property or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Given the politically sensitive nature of hydraulic fracturing and the controversy generated by its opponents, our technologies, systems and networks may be of particular interest to certain groups with political agendas, which may seek to launch cyber-attacks as a method of promoting their message. A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations. Although to date we have not experienced any significant cyber-attacks, there can be no assurance that we will not be the target of such attacks in the future. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any security vulnerabilities. +Environmental and overall public scrutiny focused on the oil and gas industry is increasing. The current trend is to increase regulation of our operations and the industry. We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business. +Our exploration, development, production, and marketing operations are regulated extensively at the federal, state, and local levels. Environmental and other governmental laws and regulations have increased the costs of planning, designing, drilling, installing, operating, and abandoning crude oil and natural gas wells and associated facilities. Under these laws and regulations, we could also be liable for personal injuries, property damage, and natural resource or other damages. Similar to our competitors, we incur substantial operating and capital costs to comply with such laws and regulations. These compliance costs may put us at a competitive disadvantage compared to larger companies in the industry which can more easily capture economies of scale with respect to compliance. Failure to comply with these laws and regulations may result in various sanctions, including the suspension or termination of our operations or other operational impediments, and could subject us to administrative, civil, and criminal penalties. Moreover, public interest in environmental protection has increased in recent years-particularly with respect to hydraulic fracturing-and environmental organizations have opposed, with some success, certain drilling projects. These regulations also affect our operations, increase our costs of exploration and production, and limit the quantity of crude oil, natural gas and NGLs that we can produce and market. +A major risk inherent in our drilling plans is the possibility that we will be unable to obtain needed drilling permits from relevant governmental authorities in a timely manner. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well, or the receipt of a permit with unreasonable or unexpected conditions or costs could have a material adverse effect on our ability to explore or develop our properties. Additionally, the crude oil and natural gas regulatory environment could change in ways that substantially increase our financial and managerial compliance costs, increase our exposure to potential damages or limit our activities. +In August 2015, we received a Clean Air Act Section 114 Information Request (the "Information Request") from the EPA. The Information Request seeks, among other things, information related to the design, operation, and maintenance of our production facilities in the Denver-Julesburg Basin of Colorado. The Information Request focuses primarily on 46 of our production facilities and asks that we conduct certain sampling and analyses at the identified 46 facilities. We responded to the Information Request in January 2016. We cannot predict the outcome of this matter at this time. Certain other operators in the area have been assessed penalties following similar information requests. +In a related Clean Air Act development, on October 1, 2015, EPA announced its final rule lowering the existing 75 part per billion ("ppb") NAAQS for ozone under the CAA to 70 ppb. The lower ozone NAAQS could result in a significant expansion of ozone nonattainment areas across the United States, including areas in which we operate. Oil and natural gas operations in ozone nonattainment areas would likely be subject to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs. In addition, the state of Colorado’s non-attainment status was bumped up from “marginal” to “moderate” for the Denver Metro North Front Range Ozone 8-Hour Non-Attainment area. This increase in non-attainment status triggers significant additional obligations for the State under the CAA and will result in a state rulemaking to address the new “moderate” status. This rulemaking may result in more stringent standards or additional control requirements applicable to our operations in Colorado. +In addition, our activities are subject to regulations governing conservation practices, protection of wildlife and habitat, and protection of correlative rights by state governments. For example, the federal Endangered Species Act (“ESA”) and analogous state laws restrict activities that may adversely affect endangered and threatened species or their habitat. The designation of previously unidentified endangered or threatened species or their habitat in areas where we operate could cause us to incur additional costs or become subject to operating delays, restrictions or bans. For example, the U.S. Fish and Wildlife Service in May 2014 proposed a rule to alter how that agency designates critical habitat. That rule is expected to be finalized in 2016 and could expand the reach of the ESA. +21 +At the state level the COGCC issued a rule in 2013 governing mandatory minimum setbacks between oil and gas wells and occupied buildings and other areas. Also in 2013, the COGCC issued rules that require baseline sampling of certain ground and surface water in most areas of Colorado and impose stringent spill reporting and remediation requirements. These new sampling requirements could increase the costs of developing wells in certain locations. Other regulatory amendments and policies recently adopted or being proposed by the COGCC address wellbore integrity, hydraulic fracturing, well control, waste management, spill reporting, development of large scale facilities in urban mitigation areas, and certain local government notice requirements. In addition to increasing costs of operation and permitting times, some of these rules and policies could prevent us from drilling wells on certain locations we plan to develop, thereby reducing our reserves as well as our future revenues. In 2014, the Colorado Oil and Gas Conservation Act was amended to increase the potential sanctions for violating the Act or its implementing regulations, orders, or permits. In January 2015, the COGCC amended its regulations to implement this new legislation. These legislative and regulatory amendments expand the COGCC’s enforcement authority and tools by, for example, mandating monetary penalties for certain types of violations, requiring a penalty to be assessed for each day of violation, and significantly increasing the maximum daily penalty amount. These changes could significantly increase both the frequency and the amount of future administrative penalties assessed by the COGCC. +In February 2014, the Colorado Department of Public Health and Environment’s Air Quality Control Commission (“AQCC”) finalized regulations imposing stringent new requirements relating to air emissions from oil and gas facilities in Colorado. The new rules impose significantly more stringent control, monitoring, recordkeeping, and reporting requirements than those required under comparable new federal rules. In addition, as part of the rule, the AQCC approved the direct regulation of hydrocarbon (i.e., methane) emissions from the Colorado oil and gas sector. Such state-only, direct regulation of methane (a greenhouse gas) from a single industry sector in the absence of comparable federal regulation is a significant new authority being asserted at the state level and has the potential to adversely affect operations in Colorado as well as in other parts of the country. In 2015, EPA proposed similar “methane” amendments to Subpart OOOO, which if finalized, could impose additional control or other regulatory requirements on our operations. Along the same lines, local governments are undertaking air quality studies to assess potential public health impacts from oil and gas operations. These studies, in combination with other air quality-related studies that are national in scope, may result in the imposition of additional regulatory requirements on oil and gas operations. +CERCLA (or the “Superfund law”) and some comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. This includes potential liability for activities on properties we may currently own or operate upon, but where previous owner/operators caused the release of a hazardous substance. In addition, we may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been or threaten to be released into the environment. From time to time, we are involved in remediation activities at such properties. +Regulatory focus on worker safety and health regulations involving operating hazards in oil and natural gas exploration and production activities is also increasing. One example is a recent investigation by the U.S. Occupational Safety and Health Administration (“OSHA”) and other governmental authorities regarding potential worker exposure to hydrocarbon vapors from certain fuel transfer and related tasks. Several recent worker fatalities at oil and gas facilities nationwide are being reviewed by OSHA and other governmental authorities for a potential link to hydrocarbon vapor exposure. Regulatory requirements generally relating to worker exposure to hydrocarbon vapors could be increased or receive heightened scrutiny going forward. For example, in December 2015, the Department of Labor and the Department of Justice, Environment and Natural Resources Division released a Memorandum of Understanding (“MOU”), announcing an inter-agency effort to increase workplace safety crimes that occur in conjunction with environmental crimes. Consistent with this MOU, DOJ will look for additional felony violations (such as false statements and willful violations of certain standards) when prosecuting safety crimes in order to heighten prospective penalties and strengthen enforcement. +Other potential laws and regulations affecting us include new or increased severance taxes proposed in several states, including Ohio. This could adversely affect our existing operations in the state and the economic viability of future drilling. Additional laws, regulations, or other changes could significantly reduce our future growth, increase our costs of operations, and reduce our cash flows, in addition to undermining the demand for the crude oil, natural gas and NGLs we produce. +Our ability to produce crude oil, natural gas and NGLs could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of the water we use at a reasonable cost and within applicable environmental rules. +Our operations could be adversely impacted if we are unable to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations. Currently, the quantity of water required in certain completion operations, such as hydraulic fracturing, and changing regulations governing usage may lead to water constraints and supply concerns (particularly in some parts of the country). In addition, Colorado has a relatively arid climate and experiences drought conditions from time to time. As a result, future availability of water from certain sources used in the past may become limited. +The imposition of new environmental initiatives relating to wastewater could restrict our ability to conduct certain operations such as hydraulic fracturing. This includes potential restrictions on waste disposal, including, but not limited to, produced water, drilling fluids, and other wastes associated with the exploration, development, or production of hydrocarbons. For example, in 2010 a petition was filed by the Natural Resources Defense Council with EPA requesting that the agency reassess its prior and long-standing determination that certain oil and natural gas exploration and production wastes would not be regulated as hazardous waste under Subtitle C of the Resource Conservation and Recovery Act. EPA has not yet acted on the petition and it remains pending. Were EPA to begin treating some or all of these wastes as “hazardous” under +22 +Subtitle C in response to the petition, the consequences for our operations would be serious, and would include a significant increase in costs associated with waste treatment and disposal and a potential inability to conduct operations in some instances. +The U.S. Clean Water Act (“CWA”) and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas waste, into navigable waters or other regulated federal and state waters. Permits or other approvals must be obtained to discharge fill and pollutants into regulated waters and to conduct construction activities in such waters and wetlands. Uncertainty regarding regulatory jurisdiction over wetlands and other regulated waters of the United States has complicated, and will continue to complicate and increase the cost of, obtaining such permits or other approvals. In June 2015, EPA and the U.S. Army Corps of Engineers issued a final rule that clarifies the scope of the agencies’ jurisdiction under section 404 of the CWA to regulate certain activities occurring in Waters of the United States. This rule, known as the Clean Water Rule, has been challenged by various parties in multiple federal courts, and as a result of this litigation is currently stayed and not yet effective. An expansive definition of such jurisdictional waters could affect our ability to operate in certain areas, increase costs of operations, and cause significant scrutiny and delays in permitting. While generally exempt under federal programs, many state agencies have also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. These permits, in turn, impose far-ranging monitoring, flow control, and other obligations that have generated, and will continue to generate, increased costs for our operations. +In April 2015, EPA published proposed pretreatment standards for the oil and gas extraction industry. The proposed regulations would address discharges of wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned treatment works. Some states, including Pennsylvania, have banned the treatment of fracturing wastewater at publicly owned treatment facilities. There also has been recent nationwide concern, particularly in Ohio and Oklahoma, over earthquakes associated with Class II underground injection control wells, a predominant storage method for crude oil and gas wastewater. As seen in Ohio, it is likely that new rules and regulations will be developed to address these concerns, possibly eliminating access to Class II wells in certain locations, and increasing the cost of disposal in others. +Finally, the EPA study on hydraulic fracturing noted above focused on various stages of water use in hydraulic fracturing operations. It is possible that, following the conclusion and finalization of EPA’s study, the agency will move to more strictly regulate the use of water in hydraulic fracturing operations. While we cannot predict the impact that these changes may have on our business at this time, they may be material to our business, financial condition, and operations. In addition, an inability to meet our water supply needs to conduct our completion operations may adversely impact our business. These water-related concerns are heightened by the potential for flooding events in Colorado such as those that occurred in 2013. For example, during that flood we experienced damage to some of our facilities as well as other operational impediments. +Reduced commodity prices could result in significant impairment charges and significant downward revisions of proved reserves. +Crude oil prices fell dramatically in the second half of 2014, with further declines in 2015 and 2016, and the domestic natural gas market remains weak. Low commodity prices could result in, among other adverse effects, significant impairment charges. The cash flow model we use to assess properties for impairment includes numerous assumptions, such as management’s estimates of future oil and gas production and commodity prices, market outlook on forward commodity prices and operating and development costs. All inputs to the cash flow model must be evaluated at each date that the estimate of future cash flows for each producing basin is calculated. However, a significant decrease in long-term forward prices alone could result in a significant impairment for our properties that are sensitive to declines in prices. In December 2012, we recognized an impairment charge of $161.2 million associated with our Piceance Basin proved crude oil and natural gas properties. In 2013, we recognized additional charges of $48.8 million associated with our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties. In December 2014, we recognized a charge of $158.3 million associated with our Utica Shale properties, and we recognized an additional charge of $150.3 million with respect to those properties in the third quarter of 2015. Similar charges could occur in the future. In addition, low commodity prices could result in significant downward revisions to the estimated quantity and value of our proved reserves. +Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our production and reserves, and ultimately our profitability. +Our industry is capital intensive. We expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of crude oil, natural gas and NGL reserves. To date, we have financed capital expenditures primarily with bank borrowings under our revolving credit facility, cash generated by operations and proceeds from capital markets transactions and the sale of properties. We intend to finance our future capital expenditures utilizing similar financing sources. Our cash flows from operations and access to capital are subject to a number of variables, including: +• +our proved reserves; +• +the amount of crude oil, natural gas and NGLs we are able to produce from existing wells; +• +the prices at which crude oil, natural gas and NGLs are sold; +• +the costs to produce crude oil, natural gas and NGLs; and +• +our ability to acquire, locate and produce new reserves. +If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower commodity prices, operating difficulties or for any other reason, our need for capital from other sources could increase, and there can be no assurance that such other sources of capital would be available at that time on reasonable terms or at all. If we raise funds by issuing additional equity securities, this would have a dilutive effect on existing shareholders. If we raise funds through the incurrence of debt, the risks we face with respect to our indebtedness would increase and we would incur additional interest expense. Our inability to obtain sufficient financing on acceptable terms would adversely affect our financial condition and profitability. +23 +Our estimated crude oil and natural gas reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves. +Calculating reserves for crude oil, natural gas and NGLs requires subjective estimates of remaining volumes of underground accumulations of hydrocarbons. Assumptions are also made concerning commodity prices, production levels, and operating and development costs over the economic life of the properties. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate. Independent petroleum engineers prepare our estimates of crude oil, natural gas and NGLs reserves using pricing, production, cost, tax and other information that we provide. The reserve estimates are based on certain assumptions regarding commodity prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual results could greatly affect: +• +the economically recoverable quantities of crude oil, natural gas and NGLs attributable to any particular group of properties; +• +future depreciation, depletion and amortization (“DD&A”) rates and amounts; +• +impairments in the value of our assets; +• +the classifications of reserves based on risk of recovery; +• +estimates of future net cash flows; +• +timing of our capital expenditures; and +• +the amount of funds available for us to utilize under our revolving credit facility. +Some of our reserve estimates must be made with limited production histories, which renders these reserve estimates less reliable than estimates based on longer production histories. Horizontal drilling in the Wattenberg Field is a relatively recent development, whereas vertical drilling has been used by producers in this field for over 40 years. As a result, the amount of production data from horizontal wells available to reserve engineers is relatively small, and future reserve estimates will be affected by additional production data as it becomes available. Horizontal drilling in the Utica Shale has an even more limited history, particularly in the southern part of the play where most of our acreage is located. Further, reserve estimates are based on the volumes of crude oil, natural gas and NGLs that are anticipated to be economically recoverable from a given date forward based on economic conditions that exist at that date. The actual quantities of crude oil, natural gas and NGLs recovered will be different than the reserve estimates since they will not be produced under the same economic conditions as used for the reserve calculations. In addition, quantities of probable and possible reserves by definition are inherently more risky than proved reserves, in part because they have greater uncertainty associated with the recoverable quantities of hydrocarbons. +At December 31, 2015, approximately 74% of our estimated proved reserves were undeveloped. These reserve estimates reflect our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including approximately $2.0 billion during the five years ending December 31, 2020. The estimated development costs may not be accurate, development may not occur as scheduled and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of initial booking, and we may therefore be required to downgrade to probable or possible any PUDs that are not developed within this five-year time frame. In December 2015, we received a comment letter from the staff of the SEC requesting certain information regarding our PUD disclosures in prior years, and we cannot predict the outcome of the comment process. +The present value of the estimated future net cash flows from our proved reserves is not necessarily the same as the current market value of those reserves. Pursuant to SEC rules, the estimated discounted future net cash flows from our proved reserves, and the estimated quantity of those reserves, were based on the prior year’s first day of the month 12-month average crude oil and natural gas index prices. However, factors such as actual prices we receive for crude oil and natural gas and hedging instruments, the amount and timing of actual production, the amount and timing of future development costs, the supply of and demand for crude oil, natural gas and NGLs and changes in governmental regulations or taxation, also affect our actual future net cash flows from our properties. Because market prices for crude oil at the end of 2015 were significantly lower than the average price for the year determined under SEC rules, the estimated quantity and present values of our reserves presented in this report using SEC pricing are higher than they would be if we had used year-end commodity prices instead. +The timing of both our production and incurrence of expenses in connection with the development and production of crude oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor (the rate required by the SEC) we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates currently in effect and risks associated with our properties or the industry in general. +Unless reserves are replaced as they are produced, our reserves and production will decline, which would adversely affect our future business, financial condition and results of operations. We may not be able to develop our identified drilling locations as planned. +Producing crude oil, natural gas and NGL reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline may change over time and may exceed our estimates. Our future reserves and production and, therefore, our cash flows and income, are highly dependent on our ability to efficiently develop and exploit our current reserves and to economically find or acquire additional recoverable reserves. We may not be able to develop, discover or acquire additional reserves to replace our current and future production at acceptable costs. Our failure to do so would adversely affect our future operations, financial condition and results of operations. As we continue to develop our position in the Wattenberg Field, and as the field in general matures +24 +as a horizontal drilling play, it will be increasingly important for us to develop or acquire additional drilling opportunities there or elsewhere to replace our reserves as they are developed. +We have identified a number of well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including: +• +crude oil, natural gas and NGL prices; +• +the availability and cost of capital; +• +drilling and production costs; +• +availability of drilling services and equipment; +• +drilling results; +• +lease expirations; +• +midstream constraints; +• +access to and availability of water sourcing and distribution systems; +• +regulatory approvals; and +• +other factors. +Because of these factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce crude oil, natural gas or NGLs from these or any other potential well locations. We reduced our forecasted company-wide capital expenditures in 2016 relative to 2015 in response to significant declines in the market price of crude oil, and we expect to drill fewer wells during the year. In addition, the number of drilling locations available to us will depend in part on the spacing of wells in our operating areas. An increase in well density in an area could result in additional locations in that area, but a reduced production performance from the area on a per-well basis. Further, certain of the horizontal wells we intend to drill in the future may require pooling of our lease interests with the interests of third parties. If these third parties are unwilling to pool their interests with ours, we may be unable to require such pooling on a timely basis or at all, and this would limit the total locations we can drill. As such, our actual drilling activities may materially differ from those presently identified. Further, our inventory of drilling projects includes locations in addition to those that we currently classify as proved, probable and possible. The development of and results from these additional projects are more uncertain than those relating to probable and possible locations, and significantly more uncertain than those relating to proved locations. +The wells we drill may not yield crude oil, natural gas or NGLs in commercially viable quantities and productive wells may be less successful than we expect. +A prospect is a property on which our geologists have identified what they believe, based on available information, to be indications of hydrocarbon-bearing rocks. However, our geologists cannot know conclusively prior to drilling and testing whether crude oil, natural gas or NGLs will be present in sufficient quantities to repay drilling or completion costs and generate a profit given the available data and technology. Furthermore, even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques do not enable our geologists to be certain as to whether hydrocarbons are, in fact, present in those structures or the quantity of the hydrocarbons. In addition, the use of 3-D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures, which may result in a reduction in our returns or losses. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline. If a well is determined to be dry or uneconomic, which can occur even though it contains some crude oil, natural gas or NGLs, it is classified as a dry hole and must be plugged and abandoned in accordance with applicable regulations. This generally results in the loss of the entire cost of drilling and completion to that point, the cost of plugging, and lease costs associated with the prospect. Even wells that are completed and placed into production may not produce sufficient crude oil, natural gas and NGLs to be profitable, or they may be less productive and/or profitable than we expected. Recent reductions in drilling and completion costs, which have accompanied lower commodity prices, may not be continued or sustained. If we drill a dry hole or unprofitable well on a current or future prospect, the profitability of our operations will decline and the value of our properties will likely be reduced. These risks are greater in developing areas such as the Utica Shale. Exploratory drilling is typically subject to substantially greater risk than development drilling. In addition, initial results from a well are not necessarily indicative of its performance over a longer period. +Drilling for and producing crude oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations. +Drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling can be unprofitable, not only due to dry holes, but also due to curtailments, delays or cancellations as a result of other factors, including: +• +unusual or unexpected geological formations; +• +pressures; +• +fires; +• +floods; +• +loss of well control; +• +loss of drilling fluid circulation; +• +title problems; +25 +• +facility or equipment malfunctions; +• +unexpected operational events; +• +shortages or delays in the delivery of equipment and services; +• +unanticipated environmental liabilities; +• +compliance with environmental and other governmental requirements; and +• +adverse weather conditions. +Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and regulatory penalties. For example, a loss of containment of hydrocarbons during drilling activities could potentially subject us to civil and/or criminal liability and the possibility of substantial costs, including for environmental remediation, depending upon the circumstances of the loss of containment, the nature and scope of the loss and the applicable laws and regulations. We maintain insurance against various losses and liabilities arising from our operations; however, insurance against certain operational risks may not be available or may be prohibitively expensive relative to the perceived risks presented. For example, we may not have coverage with respect to a pollution event if we are unaware of the event while it is occurring and are therefore unable to report the occurrence of the event to our insurance company within the time frame required under our insurance policy. Thus, losses could occur for uninsurable or uninsured risks or for amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance and/or governmental or third party responses to an event could have a material adverse effect on our business activities, financial condition and results of operations. We are currently involved in various remedial and investigatory activities at some of our wells and related sites. +Our business strategy focuses on production in our liquid-rich shale plays. In this regard, we plan to allocate our capital to an active horizontal drilling program. Historically, most of the wells we drilled were vertical wells. Since 2012, however, we have devoted the majority of our capital budget to drilling horizontal wells. Drilling horizontal wells is technologically more difficult than drilling vertical wells - including as a result of risks relating to our ability to fracture stimulate the planned number of stages and to successfully run casing the length of the well bore - and the risk of failure is therefore greater than the risk involved in drilling vertical wells. Additionally, drilling a horizontal well is typically far costlier than drilling a vertical well. This means that the risks of our drilling program will be spread over a smaller number of wells, and that, in order to be economic, each horizontal well will need to produce at a higher level in order to cover the higher drilling costs. In addition, we have transitioned to the use of multi-well pads instead of single-well sites. The use of multi-well pad drilling increases some operational risks because problems affecting the pad or a single well could adversely affect production from all of the wells on the pad. Pad drilling can also make our overall production, and therefore our revenue and cash flows, more volatile, because production from multiple wells on a pad will typically commence simultaneously. While we believe that we will be better served by drilling horizontal wells using multi-well pads, the risk component involved in such drilling will be increased in some respects, with the result that we might find it more difficult to achieve economic success in our drilling program. +Under the “successful efforts” accounting method that we use, unsuccessful exploratory wells must be expensed in the period when they are determined to be non-productive, which reduces our net income in such periods and could have a negative effect on our profitability. +We conduct exploratory drilling in order to identify additional opportunities for future development. Under the “successful efforts” method of accounting that we use, the cost of unsuccessful exploratory wells must be charged to expense in the period in which the wells are determined to be unsuccessful. In addition, lease costs for acreage condemned by the unsuccessful well must also be expensed. In contrast, unsuccessful development wells are capitalized as a part of the investment in the field where they are located. Because exploratory wells generally are more likely to be unsuccessful than development wells, we anticipate that some or all of our exploratory wells may not be productive. The costs of such unsuccessful exploratory wells could result in a significant reduction in our profitability in periods when the costs are required to be expensed. +We have a substantial amount of debt and the cost of servicing, and risks related to refinancing, that debt could adversely affect our business. Those risks could increase if we incur more debt. +We have a substantial amount of indebtedness. As a result, a significant portion of our cash flows will be required to pay interest and principal on our indebtedness, and we may not generate sufficient cash flows from operations, or have future borrowing capacity available, to enable us to repay our indebtedness or to fund other liquidity needs. +Servicing our indebtedness and satisfying our other obligations will require a significant amount of cash. Our cash flows from operating activities and other sources may not be sufficient to fund our liquidity needs. Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend on our future operating performance and financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions, including possibly depressed commodity pricing, and financial, business and other factors, many of which are beyond our control. We believe the current market environment for some types of financing, including high-yield notes, to be highly adverse. In addition, we expect that some commercial lenders may look to reduce their exposure to exploration and production companies due to regulatory pressures they face and/or independent business considerations. This could adversely affect our liquidity and our ability to refinance our debt. +A substantial decrease in our operating cash flows or an increase in our expenses could make it difficult for us to meet our debt service requirements and could require us to modify our operations, including by curtailing our exploration and drilling programs, selling assets, refinancing all or a portion of our existing debt or obtaining additional financing. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the +26 +capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. In addition, the terms of future debt agreements may, and our existing debt agreements do, restrict us from implementing some of these alternatives. In the absence of adequate cash from operations and other available capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. We may not be able to consummate these dispositions for fair market value, in a timely manner or at all. Furthermore, any proceeds that we could realize from any dispositions may not be adequate to meet our debt service or other obligations then due. Because the cash required to service our indebtedness is not available to finance our operations and other business activities, our indebtedness limits our flexibility in planning for or reacting to changes in our business and the industry in which we operate and increases our vulnerability to economic downturns and sustained declines in commodity prices. +Covenants in our debt agreements currently impose, and future financing agreements may impose, significant operating and financial restrictions. +The indenture governing our senior notes and our revolving credit facility contain restrictions, and future financing agreements may contain additional restrictions, on our activities, including covenants that restrict our and certain of our subsidiaries’ ability to: +• +incur additional debt; +• +pay dividends on, redeem or repurchase stock; +• +create liens; +• +make specified types of investments; +• +apply net proceeds from certain asset sales; +• +engage in transactions with our affiliates; +• +engage in sale and leaseback transactions; +• +merge or consolidate; +• +restrict dividends or other payments from restricted subsidiaries; +• +sell equity interests of restricted subsidiaries; and +• +sell, assign, transfer, lease, convey or dispose of assets. +Our revolving credit facility is secured by all of our crude oil and natural gas properties as well as a pledge of all ownership interests in our operating subsidiaries. The restrictions contained in our debt agreements may prevent us from taking actions that we believe would be in the best interest of our business, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. We may also incur future debt obligations that might subject us to additional restrictive covenants that could affect our financial and operational flexibility. +Our revolving credit facility has substantial restrictions and financial covenants and our ability to comply with those restrictions and covenants is uncertain. Our lenders can unilaterally reduce our borrowing availability based on anticipated commodity prices. +We depend in large part on our revolving credit facility for future capital needs. The terms of the credit agreement require us to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flows from operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the revolving credit facility or other debt agreements could result in a default under those agreements, which could cause all of our existing indebtedness to be immediately due and payable. +The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based upon projected revenues from the properties securing their loan. Significant recent decreases in the price of crude oil are likely to have an adverse effect on the borrowing base. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other crude oil and natural gas properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility. Our inability to borrow additional funds under our revolving credit facility could adversely affect our operations and our financial results. +If we are unable to comply with the restrictions and covenants in the agreements governing our indebtedness, there would be a default under the terms of these agreements, which could result in an acceleration of payment of funds that we have borrowed and would impact our ability to make principal and interest payments on our indebtedness and satisfy our other obligations. +Any default under the agreements governing our indebtedness, including a default under our revolving credit facility that is not waived by the required lenders, and the remedies sought by the holders of any such indebtedness, could make us unable to pay principal and interest on our indebtedness and satisfy our other obligations. If we are unable to generate sufficient cash flows and are otherwise unable to obtain the funds necessary to meet required payments of principal and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our revolving credit facility could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation. If our operating performance declines, we may in the future need to seek to obtain waivers from the required lenders under our revolving credit facility to avoid being in default and we may not be able to obtain such a waiver. If this occurs, we would be in default +27 +under our revolving credit facility, the lenders could exercise their rights as described above, and we could be forced into bankruptcy or liquidation. We cannot assure you that we will be granted waivers or amendments to our debt agreements if for any reason we are unable to comply with these agreements, or that we will be able to refinance our debt on terms acceptable to us, or at all. +Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly. +Borrowings under our revolving credit facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase although the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness and for other purposes would decrease. +Notwithstanding our current indebtedness levels and restrictive covenants, we may still be able to incur substantial additional debt, which could exacerbate the risks described above. +We may be able to incur additional debt in the future. Although our debt agreements contain restrictions on our ability to incur indebtedness, those restrictions are subject to a number of exceptions. In particular, we may borrow under the revolving credit facility, and may do so in 2016. We may also consider investments in joint ventures or acquisitions that may increase our indebtedness. Adding new debt to current debt levels could intensify the related risks that we now face. +Seasonal weather conditions and lease stipulations can adversely affect our operations. +Seasonal weather conditions and lease stipulations designed to protect wildlife affect operations in some areas. In certain areas drilling and other activities may be restricted or prohibited by lease stipulations, or prevented by weather conditions, for significant periods of time. This limits our operations in those areas and can intensify competition during the active months for drilling rigs, oil field equipment, services, supplies and qualified personnel, which may lead to additional or increased costs or periodic shortages. These constraints and the resulting high costs or shortages could delay our operations and materially increase operating and capital costs and therefore adversely affect our profitability. Similarly, hot weather during some recent periods adversely impacted the operation of certain midstream facilities, and therefore our production. Similar events could occur in the future and could negatively impact our results of operations and cash flows. +We have limited control over activities on properties in which we own an interest but we do not operate, which could reduce our production and revenues. +We operate approximately 87% of the wells in which we own an interest. If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of the underlying properties. The success and timing of drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise (including safety and environmental compliance) and financial resources, inclusion of other participants in drilling wells, and use of technology. The failure by an operator to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce production and revenues and adversely affect our profitability. These risks are heightened in some respects in periods of depressed commodity prices as operators may propose operations that we believe to be economically unattractive, leading us to incur non-consent penalties. Our lack of control over non-operated properties also makes it more difficult for us to forecast capital expenditures, production and related matters. +Our derivative activities could result in financial losses or reduced income from failure to perform by our counterparties, could limit our potential gains from increases in prices and could result in volatility in our net income. +We use derivatives for a portion of the production from our own wells and for natural gas purchases and sales by our marketing subsidiary to achieve more predictable cash flows, to reduce exposure to adverse fluctuations in commodity prices, and to allow our natural gas marketing company to offer pricing options to natural gas sellers and purchasers. These arrangements expose us to the risk of financial loss in some circumstances, including when purchases or sales are different than expected or the counterparty to the derivative contract defaults on its contractual obligations. Based on current commodity prices and our current derivative position, we may receive significant revenues from our derivative positions in 2016, increasing the adverse consequences to us if a derivative counterparty fails to perform. In addition, many of our derivative contracts are based on WTI or another oil or natural gas index price. The risk that the differential between the index price and the price we receive for the relevant production may change unexpectedly makes it more difficult to hedge effectively and increases the risk of a hedging-related loss. +Also, derivative arrangements may limit the benefit we would otherwise receive from increases in the prices for the relevant commodity, and they may require the use of our resources to meet cash margin requirements. +In addition, at December 31, 2015, we had hedged a total of 5.6 million barrels of oil volumes and 77,320 BBtu of natural gas hedged for 2016, 2017 and 2018. These hedges may be inadequate to protect us from continuing and prolonged declines in oil and natural gas prices, and our current hedge position is smaller than it has been in recent years. To the extent that oil and natural gas prices remain at current levels or decline further, we will not be able to hedge future production at the same pricing level as our current hedges and this could negatively impact our results of operations and financial condition. +Since we do not designate our derivatives as hedges, we do not currently qualify for use of hedge accounting; therefore, changes in the fair value of derivatives are recorded in our income statements, and our net income is subject to greater volatility than it would be if our +28 +derivative instruments qualified for hedge accounting. For instance, if commodity prices rise significantly, this could result in significant non-cash charges during the relevant period, which could have a material negative effect on our net income. +The inability of one or more of our customers or other counterparties to meet their obligations may adversely affect our financial results. +Substantially all of our accounts receivable result from our crude oil, natural gas and NGLs sales or joint interest billings to a small number of third parties in the energy industry. This concentration of customers and joint interest owners may affect our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our derivatives as well as the derivatives used by our marketing subsidiary expose us to credit risk in the event of nonperformance by counterparties. Nonperformance by our customers or derivative counterparties may adversely affect our financial condition and profitability. We face similar risks with respect to our other counterparties, including the lenders under our revolving credit facility and the providers of our insurance coverage. +We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects. +We frequently own less than 100% of the working interest in the oil and gas leases on which we conduct operations, and other parties will own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in oil, natural gas and NGL prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, a partner may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial position. +Our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur. +The occurrence of a significant accident or other event not fully covered by insurance or in excess of our insurance coverage could have a material adverse effect on our operations and financial condition. Insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. We also do not carry contingent business interruption insurance related to the purchasers of our production. In addition, pollution and environmental risks are generally not fully insurable. +We may not be able to keep pace with technological developments in our industry. +Our industry is characterized by rapid and significant technological advancements. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those or other new technologies at substantial cost. In addition, our competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we were unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected. +Competition in our industry is intense, which may adversely affect our ability to succeed. +Our industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce crude oil, natural gas and NGLs, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, larger companies may have a greater ability to continue exploration activities during periods of low commodity prices. Larger competitors may also be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which could adversely affect our competitive position. These factors could adversely affect the success of our operations and our profitability. +Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel. +Our future success depends to a large extent on the services of our key employees. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise. +A failure to complete successful acquisitions would limit our growth. +29 +Because our crude oil and natural gas properties are depleting assets, our future reserves, production volumes and cash flows depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. In addition, we continue to strive to achieve greater efficiencies in our drilling program, and our ability to do so is dependent in part on our ability to complete land swaps or exchanges and other acquisitions that allow us to increase our working interests in particular properties. Acquiring additional crude oil and natural gas properties, or businesses that own or operate such properties, when attractive opportunities arise is a significant component of our strategy. We may not be able to identify attractive acquisition opportunities. If we do identify an appropriate acquisition candidate, we may be unable to negotiate mutually acceptable terms with the seller, finance the acquisition or obtain the necessary regulatory approvals. In the current commodity price environment, it may be difficult to agree on the economic terms of a transaction, as a potential seller may be unwilling to accept a price that we believe to be appropriately reflective of prevailing economic conditions. If we are unable to complete suitable acquisitions, it will be more difficult to replace our reserves, and an inability to replace our reserves would have a material adverse effect on our financial condition and results of operations. +Acquisitions of properties are subject to the uncertainties of evaluating recoverable reserves and potential liabilities, including environmental uncertainties. +Acquisitions of producing properties and undeveloped properties have been an important part of our growth over time. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, development potential, future commodity prices, operating costs, title issues and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we generally perform engineering, environmental, geological and geophysical reviews of the acquired properties, which we believe are generally consistent with industry practices. However, such reviews are not likely to permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well prior to an acquisition and our ability to evaluate undeveloped acreage is inherently imprecise. Even when we inspect a well, we may not always discover structural, subsurface and environmental problems that may exist or arise. In some cases, our review prior to signing a definitive purchase agreement may be even more limited. In addition, we often acquire acreage without any warranty of title except as to claims made by, through or under the transferor. +When we acquire properties, we will generally have potential exposure to liabilities and costs for environmental and other problems existing on the acquired properties, and these liabilities may exceed our estimates. Often we are not entitled to contractual indemnification associated with acquired properties. We often acquire interests in properties on an “as is” basis with no or limited remedies for breaches of representations and warranties. Therefore, we could incur significant unknown liabilities, including environmental liabilities, or losses due to title defects, in connection with acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, the acquisition of undeveloped acreage is subject to many inherent risks and we may not be able to realize efficiently, or at all, the assumed or expected economic benefits of acreage that we acquire. +Additionally, significant acquisitions can change the nature of our operations depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or may be in different geographic locations than our existing properties. These factors can increase the risks associated with an acquisition. Acquisitions also present risks associated with the additional indebtedness that may be required to finance the purchase price, and any related increase in interest expense or other related charges. +Some of our acquisitions are structured as land swaps or exchanges. These transactions may give rise to any or all of the foregoing risks. In addition, transactions of this type create a risk that we will undervalue the properties we transfer to the counterparty in the swap or exchange. Such an undervaluation would result in the transaction being less favorable to us than we expected. +Certain federal income tax deductions currently available with respect to crude oil and natural gas and exploration and development may be eliminated as a result of future legislation. +The administration of U.S. President Barack Obama has proposed to eliminate certain key U.S. federal income tax preferences currently available with respect to crude oil and natural gas exploration and production. The proposals include, but are not limited to (i) the repeal of the percentage depletion deduction for crude oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. In addition, the President has recently proposed a $10.25 per barrel tax on oil companies. It is not possible at this time to predict how legislation or new regulations that may be adopted to address these proposals would impact our business, but any such future laws and regulations could result in higher federal income taxes, which could negatively affect our financial condition and results of operations. In addition, proposals are made from time to time in states where we operate to implement or increase severance or other taxes at the state level, and any such additional taxes would have similarly adverse effects on us. +Derivatives legislation and regulation could adversely affect our ability to hedge crude oil and natural gas prices and increase our costs and adversely affect our profitability. +In July 2010, President Obama signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”). The Dodd-Frank Act regulates derivative transactions, including our commodity hedging swaps, and could have a number of adverse effects on us, including the following: +• +The Dodd-Frank Act may limit our ability to enter into hedging transactions, thus exposing us to additional risks related to commodity price volatility; commodity price decreases would then have an increased adverse effect on our profitability and +30 +revenues. Reduced hedging may also impair our ability to have certainty with respect to a portion of our cash flows, which could lead to decreases in capital spending and, therefore, decreases in future production and reserves. +• +If, as a result of the Dodd-Frank Act or its implementing regulations, we are required to post cash collateral in connection with our derivative positions, this would likely make it impracticable to implement our current hedging strategy. +• +Our derivatives counterparties are, or will be, subject to significant new capital, margin and business conduct requirements imposed as a result of the Dodd-Frank Act. We expect that these requirements will increase the cost to hedge because there will be fewer counterparties in the market and increased counterparty costs will be passed on to us. +The above factors could also affect the pricing of derivatives and make it more difficult for us to enter into hedging transactions on favorable terms. +Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the crude oil, natural gas and NGLs that we produce while physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. +In December 2009, EPA published its findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such GHGs are, according to EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings provide the basis for EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the U.S. Clean Air Act (“CAA”). In June 2010, EPA began regulating GHG emissions from stationary sources under the CAA’s Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. It was widely expected that facilities required to obtain PSD permits for their GHG emissions would be required to also reduce those emissions according to “best available control technology” (“BACT”) standards. In its permitting guidance for GHGs, issued in November 2010, EPA recommended options for BACT from the largest sources, which include improved energy efficiency, among others. EPA also issued a final rule in July 2013 retaining the “tailored” permitting thresholds, opting not to extend GHG permitting requirements to smaller stationary sources at that time. +In June 2012, the United States Court of Appeals for the District of Columbia Circuit issued an opinion and order in Coalition for Responsible Regulation v. Environmental Protection Agency, upholding EPA’s GHG-related rules against challenges from various state and industry group petitioners. In October 2013, the United States Supreme Court in Utility Air Regulatory Group v. EPA , accepted a petition for certiorari to decide whether EPA correctly determined that its regulation of GHGs from mobile sources triggered permitting requirements under the CAA for stationary sources that emit GHGs. In June 2014, the Supreme Court upheld a portion of EPA’s GHG stationary source program, but invalidated a portion of it. The Court held that stationary sources already subject to the PSD or Title V program for non-GHG criteria pollutants remained subject to GHG BACT requirements, but ruled that sources subject to the PSD or Title V program only for GHGs could not be forced to comply with GHG BACT requirements. Upon remand, the D.C. Circuit issued an amended judgment, which, among other things, vacated the PSD and Title V regulations under review in that case to the extent they require a stationary source to obtain a PSD or Title V permit solely because the source emits or has the potential to emit GHGs above the applicable major source thresholds. EPA intends to conduct future rulemaking to make appropriate revisions in light of the court rulings. Depending on what EPA does, it is possible that any regulatory or permitting obligation that limits emissions of GHGs could extend to smaller stationary sources and require us to incur costs to reduce and monitor emissions of GHGs associated with our operations and also adversely affect demand for the crude oil and natural gas that we produce. +In the past, Congress has considered various pieces of legislation to reduce emissions of GHGs. Congress has not adopted any significant legislation in this respect to date, but could do so in the future. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such measures could include a carbon tax, which could result in additional direct costs to our operations. In the absence of such national legislation, many states and regions have taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. For example, in February 2014, Colorado adopted rules directly regulating methane emissions from the oil and gas sector. +President Obama indicated that climate change and GHG regulation was a significant priority for his second term. The President issued a Climate Action Plan in June 2013 that, among other things, calls for a reduction in methane emissions from the oil and gas sector. In November 2013, the President released an Executive Order charging various federal agencies, including EPA, with devising and pursuing strategies to improve the country’s preparedness and resilience to climate change. In part through these executive actions, the direct regulation of methane emissions from the oil and gas sector continues to be a focus. Following the publication in March 2014 of a series of Methane White Papers addressing suspected methane emissions from the oil and gas sector, EPA proposed new rules in 2015 aimed at further reducing methane emissions from the oil and gas sector, with final rules expected in 2016. These rules, which build on the Methane White Papers, include new regulatory requirements affecting our operations. In addition, a lawsuit has been filed by several northeastern states that would require EPA to more stringently regulate methane emissions from the oil and gas sector. Finally, the Obama administration reached an agreement during the December 2015 United Nations climate change conference in Paris pursuant to which the United States initially pledged to make a 26-28% reduction in its GHG emissions by 2025 against a 2005 baseline and committed to periodically update this pledge every five years starting in 2020. The passage of legislation or executive and other initiatives, including those made to implement the pledges made in Paris, that limit emissions of GHGs from our equipment and operations could require us to incur costs to reduce GHG emissions, and it could also adversely affect demand for the crude oil, natural gas and NGLs that we produce. +Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. Flooding that occurred in Colorado in 2013 is an example of an extreme weather event that negatively impacted our operations. If such events were to continue to occur, or become more frequent, our operations could be adversely affected in various ways, including through damage to our facilities or from increased costs for insurance. +31 +Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our fuels could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business. +The cost of defending any suits brought against us, and any judgments or settlements resulting from such suits, could have an adverse effect on our results of operations and financial condition. +Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. For example, in recent years, we have been subject to lawsuits regarding royalty practices and payments and matters relating to certain of our affiliated partnerships. In addition, as discussed above, in August 2015 we received a Clean Air Act Section 114 Information Request from the EPA, and this request could result in penalties or other liabilities. The outcome of pending legal proceedings is inherently uncertain. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, the resolution of such a proceeding could result in penalties or sanctions, settlement costs and/or judgments, consent decrees or orders requiring a change in our business practices, any of which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties, sanctions or costs may be insufficient. Judgments and estimates to determine accruals or the anticipated range of potential losses related to legal and other proceedings could change from one period to the next, and such changes could be material. +Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities. +Unless production is established within the spacing units covering the undeveloped acres on which some of our drilling locations are identified, our leases for such acreage will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may differ materially from our current expectations, which could adversely affect our business. These risks are greater at times and in areas where the pace of our exploration and development activity slows. In addition, a substantial portion of our Utica Shale acreage is held-by-production by a third party operator’s shallow vertical wells. Our relative lack of control over this acreage increases the risk that some of our leases will expire. +We may incur losses as a result of title defects in the properties in which we invest. +It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. Leases in the Utica area are particularly vulnerable to title deficiencies due the long history of land ownership in the area and correspondingly extensive and complex chains of title. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property. +ITEM 1B. UNRESOLVED STAFF COMMENTS +On December 21, 2015, we received a comment letter from the staff of the Division of Corporation Finance of the SEC (the "Staff"). The comments from the Staff were issued with respect to its review of our Annual Report on Form 10-K for the fiscal year ended December 31, 2014. We responded to all of the Staff’s comments in a letter we filed with the SEC dated January 29, 2016. Included in our response were the supplemental analyses and information requested by the Staff. On February 18, 2016, we received a follow-up comment letter from the Staff, which we are currently reviewing. As of the date of the filing of this Annual Report on Form 10-K, we are continuing to work with the Staff on our responses and, therefore, these comments remain unresolved. +ITEM 3. LEGAL PROCEEDINGS +Information regarding our legal proceedings can be found in Note 12, Commitments and Contingencies – Litigation , to our consolidated financial statements included elsewhere in this report. +ITEM 4. MINE SAFETY DISCLOSURES +Not applicable. +32 +PART II +ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Our common stock, par value $0.01 per share, is traded on the NASDAQ Global Select Market under the symbol PDCE. The following table sets forth the range of high and low sales prices for our common stock for each of the periods presented: +High +Low +January 1 - March 31, 2014 +$ +64.27 +$ +44.72 +April 1 - June 30, 2014 +70.44 +56.88 +July 1 - September 30, 2014 +63.73 +49.82 +October 1 - December 31, 2014 +50.95 +27.91 +January 1 - March 31, 2015 +55.47 +37.62 +April 1 - June 30, 2015 +61.41 +51.01 +July 1 - September 30, 2015 +61.55 +41.17 +October 1 - December 31, 2015 +64.99 +52.46 +As of February 1, 2016 , we had approximately 650 shareholders of record. Since inception, no cash dividends have been declared on our common stock. Cash dividends are restricted under the terms of our revolving credit facility and the indenture governing our 7.75% senior notes due 2022 and we presently intend to continue a policy of using retained earnings for expansion of our business. See Note 8, Long-term Debt , to our consolidated financial statements included elsewhere in this report. +The following table presents information about our purchases of our common stock during the three months ended December 31, 2015 : +Period +Total Number of Shares Purchased (1) +Average Price Paid per Share +October 1 - 31, 2015 +3,190 +$ +54.76 +November 1 - 30, 2015 +3,598 +61.19 +December 1 - 31, 2015 +20,178 +53.78 +Total fourth quarter purchases +26,966 +54.89 +__________ +(1) +Purchases primarily represent shares purchased from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans. +33 +SHAREHOLDER PERFORMANCE GRAPH +The performance graph below compares the cumulative total return of our common stock over the five-year period ended December 31, 2015 , with the cumulative total returns for the same period for the Standard and Poor's ("S&P") 500 Index and the Standard Industrial Code ("SIC") Index. The SIC Index is a weighted composite of 235 crude petroleum and natural gas companies. The cumulative total shareholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on December 31, 2010 and in the S&P 500 Index and the SIC Index on the same date. The results shown in the graph below are not necessarily indicative of future performance. +34 +ITEM 6. SELECTED FINANCIAL DATA +Year Ended/As of December 31, +2015 +2014 +2013 +2012 +2011 +(in millions, except per share data and as noted) +Statement of Operations (From Continuing Operations): +Crude oil, natural gas and NGLs sales +$ +378.7 +$ +471.4 +$ +340.8 +$ +228.0 +$ +216.1 +Commodity price risk management gain (loss), net +203.2 +$ +310.3 +(23.9 +) +29.3 +39.4 +Total revenues +595.3 +856.2 +392.7 +307.1 +323.3 +Income (loss) from continuing operations +(68.3 +) +107.3 +(21.1 +) +(19.4 +) +23.2 +Earnings per share from continuing operations: +Basic +$ +(1.74 +) +$ +3.00 +$ +(0.65 +) +$ +(0.70 +) +$ +0.98 +Diluted +(1.74 +) +2.93 +(0.65 +) +(0.70 +) +0.97 +Statement of Cash Flows: +Net cash from: +Operating activities +$ +411.1 +$ +236.7 +$ +159.2 +$ +174.7 +$ +166.8 +Investing activities +(604.3 +) +(474.1 +) +(217.1 +) +(451.9 +) +(456.4 +) +Financing activities +178.0 +60.3 +248.7 +271.4 +243.4 +Capital expenditures +604.7 +628.6 +394.9 +347.7 +334.5 +Acquisitions of crude oil and natural gas properties +— +— +9.7 +312.2 +145.9 +Balance Sheet: +Total assets +$ +2,370.5 +$ +2,331.1 +$ +1,991.7 +$ +1,777.9 +$ +1,676.1 +Working capital +30.7 +89.5 +90.0 +(67.6 +) +(38.1 +) +Total debt, net of unamortized discount and debt issuance costs +642.4 +655.5 +593.9 +637.5 +502.4 +Total equity +1,287.2 +1,137.4 +967.6 +703.2 +664.1 +Pricing and Lease Operating Expenses From Continuing Operations (per Boe): +Average sales price (excluding net settlements on derivatives) +$ +24.64 +$ +50.72 +$ +52.23 +$ +46.85 +$ +49.97 +Average lease operating expenses +3.71 +4.56 +5.18 +5.54 +4.95 +Production (MBoe): +Production from continuing operations +15,369.4 +9,294.4 +6,524.7 +4,866.5 +4,324.4 +Production from discontinued operations +— +1,093.0 +2,032.6 +3,458.7 +3,596.3 +Total production +15,369.4 +10,387.4 +8,557.3 +8,325.2 +7,920.7 +Total proved reserves (MMBoe) (1)(2)(3) +272.8 +250.1 +265.8 +192.8 +169.3 +______________ +(1) +Includes total proved reserves related to our Marcellus Shale and shallow Upper Devonian Appalachian Basin assets of 40 MMBoe, 30 MMBoe and 22 MMBoe as of December 31, 2013, 2012 and 2011, respectively. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Marcellus Shale and shallow Upper Devonian Appalachian Basin assets. +(2) +Includes total proved reserves related to our Piceance Basin and North Eastern Colorado ("NECO") assets of 14 MMBoe and 59 MMBoe as of December 31, 2012 and 2011, respectively. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Piceance Basin and NECO assets. +(3) +Includes total proved reserves related to our Permian Basin assets of 11 MMBoe as of December 31, 2011. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the divestiture of our Permian Basin assets. +35 +ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +The following discussion and analysis, as well as other sections in this report, should be read in conjunction with our consolidated financial statements and related notes to consolidated financial statements included elsewhere in this report. Further, we encourage you to revisit the Special Note Regarding Forward-Looking Statements in Part I of this report. +EXECUTIVE SUMMARY +2015 Financial Overview +Production volumes from continuing operations increased substantially to 15.4 MMboe in 2015 compared to 9.3 MMboe in 2014 , representing an increase of 65% . The increase in production volumes was primarily attributable to our successful horizontal Niobrara and Codell drilling program in the Wattenberg Field. Crude oil production from continuing operations increased 62% in 2015 , while NGL production from continuing operations increased 61% . Crude oil production comprised approximately 45% of total production from continuing operations in 2015 . Natural gas production from continuing operations increased 73% in 2015 compared to 2014 as we shifted our focus to the higher rate of return drilling projects located in the higher gas to oil ratio inner and middle core areas of the Wattenberg Field. For the month ended December 31, 2015 , we maintained an average production rate of 52 MBoe per day, up from 30 MBoe per day for the month ended December 31, 2014 . +Crude oil, natural gas and NGLs sales from continuing operations, coupled with the impact of settlement of derivatives, increased in 2015 . Increased production and positive net settlements on derivative positions more than offset the effect of declines in commodity prices during the year. Lower crude oil and natural gas index prices in 2015 were the primary reason for significant positive net settlements of $238.9 million on derivative positions compared to negative net settlements of $0.8 million in 2014 . Crude oil, natural gas and NGLs sales, including the impact of net settlements on derivatives, was $617.6 million in 2015 compared to $470.6 million in 2014 . This represents an increase of 31% in 2015 compared to 2014 . +Other significant changes impacting our 2015 results of operations include the following: +• +Crude oil, natural gas and NGLs sales decreased to $378.7 million in 2015 compared to $471.4 million in 2014 , due to a 51% decrease in the weighted-average realized prices of crude oil, natural gas and NGLs, offset in part by a 65% increase in production; +• +Negative net change in the fair value of unsettled derivative positions in 2015 was $35.8 million compared to a positive net change in the fair value of unsettled derivative positions of $311.1 million in 2014 , primarily attributable to crude oil and natural gas derivatives that settled in 2015 ; +• +General and administrative expense decreased to $90.0 million in 2015 compared to $123.6 million in 2014 , primarily attributable to $40.3 million recorded in 2014 in connection with certain partnership-related class action litigation and estimates relating to litigation arising from bankruptcy proceedings of certain affiliated partnerships; +• +Impairment of crude oil and natural gas properties was $161.6 million in 2015 compared to $166.8 million in 2014 , both primarily related to the write-down of our Utica Shale producing and non-producing crude oil and natural gas properties; and +• +Depreciation, depletion and amortization expense increased to $303.3 million in 2015 compared to $192.5 million in 2014 , primarily due to increased production, offset in part by lower weighted-average depreciation, depletion and amortization rates. +Available liquidity as of December 31, 2015 was $402.2 million compared to $398.4 million as of December 31, 2014. Available liquidity as of December 31, 2015 is comprised of $0.9 million of cash and cash equivalents and $401.3 million available for borrowing under our revolving credit facility. These amounts exclude an additional $250 million available under our revolving credit facility, subject to certain terms and conditions of the agreement. In September 2015, we completed the semi-annual redetermination of the borrowing base under our revolving credit facility, which resulted in the reaffirmation of the borrowing base at $700 million . We have elected to maintain the aggregate commitment level at $450 million. +In March 2015, we completed a public offering of 4,002,000 shares of our common stock for net proceeds of approximately $203 million , after deducting offering expenses and underwriting discounts. We used a portion of the proceeds of the offering to repay all amounts then outstanding on our revolving credit facility, and used the remaining amounts to fund a portion of our capital program. With our current derivative position, available liquidity and expected cash flows from operations, we believe we have sufficient liquidity to allow us to execute our expected capital program through 2016. +36 +2015 Operational Overview +During 2015 , we continued to execute our strategic plan of increasing production, reserves and cash flows from drilling operations in the Wattenberg Field in Colorado and from completion activities in the Utica Shale play in southeastern Ohio. In the Wattenberg Field, we reduced our rig count in December to four automated drilling rigs from five due to the increases in our drilling rig efficiencies. In 2015 , we spud 174 horizontal wells in the Wattenberg Field and turned-in-line 136 horizontal wells. We also participated in 54 gross, 8.1 net, horizontal non-operated wells that were spud and 58 gross, 9.3 net, horizontal non-operated wells which were turned-in-line. We began implementing several horizontal well-recovery enhancements in 2015, including tighter spacing between frac intervals on all wells and by drilling 40% of our wells with extended reach laterals of 6,500 feet to 7,000 feet. We have been able to improve our drilling time due to several factors, including the use of automated drilling rigs that minimize downtime, improved drilling team cohesion and utilizing analytics to improve drilling efficiencies. In the Utica Shale, we completed and turned-in-line a four-well pad during the first half of 2015. As a result of the turn-in-line of a four-well pad in late 2014 and a four-well pad in the second quarter of 2015, production volumes from the Utica Shale increased 41% in 2015 compared to 2014. +2016 Operational Outlook +We expect our production for 2016 to range between 20.0 MMBoe to 22.0 MMBoe and that our production rate will average approximately 55,000 to 60,000 Boe per day. Our 2016 capital forecast of approximately $435 million at the midpoint is focused on continuing to provide value-driven production growth by exploiting our extensive inventory of reasonable rate-of-return projects in the Wattenberg Field. Capital spending is expected to be weighted to the front half of 2016 as we complete Wattenberg Field in-process wells spud in 2015 and execute our Utica Shale drilling program. +Wattenberg Field. The 2016 capital forecast anticipates a four-rig drilling program in the Wattenberg Field based on our December 2015 outlook for future commodity prices. Approximately $400 million of our 2016 capital forecast is expected to be spent on development activities in the Wattenberg Field, comprised of approximately $350 million for our operated drilling program and approximately $35 million for non-operated projects. The remainder of the Wattenberg Field capital forecast is expected to be used for leasing, workover projects and other capital improvements, including the remodeling of our Greeley, Colorado, field operating facilities. We plan to spud 135 and turn-in-line 160 horizontal Niobrara or Codell wells and participate in approximately 35.0 gross, 7.0 net, non-operated horizontal opportunities in 2016 . +Utica Shale. Based on the production results from recently drilled wells and decreases in well costs, in 2016 we plan on executing a modest drilling operation in the condensate and wet natural gas window of the play. Early in 2016, we plan to spend approximately $35 million in the Utica Shale to drill, complete and turn-in-line five wells, all of which are at least 6,000 foot laterals. The planned activity will focus on further delineation of our southern acreage, determining the impact of well-orientation on productivity and testing improved capital efficiency of a 10,000 foot lateral well. +2016 Operational Flexibility +In December 2015, the Board of Directors approved our 2016 development plan as described above. This plan, which primarily focuses on a four-rig drilling program in the Wattenberg Field, was based upon our December 2015 internal outlook for crude oil and natural gas prices, favorable debt metrics and the strength of our balance sheet, including our strong hedge position for 2016. In 2016, our goal continues to be preserving this balance sheet strength by managing our capital spending to approximate our cash flows from operations. +Since approving our 2016 development plan in December 2015, future commodity prices have continued to decline. Concurrently, capital costs to drill and complete Wattenberg Field wells have decreased, while crude oil differentials in the field have improved. We expect that our capital forecast of $420 million to $450 million will fund the same level of drilling and completions activity as projected prior to the aforementioned changes. Moreover, despite commodity prices decreasing in early 2016, we are anticipating reasonable rates of return in our middle core acreage in the Wattenberg Field. +The Company maintains significant operational flexibility in 2016 to reduce the pace of our capital spending. We will continue to monitor future commodity prices throughout 2016, and should prices remain depressed or continue to further deteriorate, we believe an adjustment to our development plan would be appropriate. We have ample opportunities to reduce capital spending, including but not limited to: working with our vendors to achieve further cost reductions; reducing the number of rigs being utilized in our drilling program; and/or managing our completion schedule. The production impact of reduced 2016 capital spending would be felt primarily in 2017 and thereafter, as our anticipated long-term production growth would likely be reduced. This operational flexibility is maintained with little exposure to incurring additional costs, given that all of our acreage in the Wattenberg Field is held by production, a reduction in rigs would not cause us to incur substantial idling costs as our rig commitments are short term (30 to 90 days), and we do not anticipate having additional material unfulfilled transportation commitment fees. Further, throughout 2016, such a reduction would be consistent with maintaining compliance well within the limits of our debt covenants. +As we go through 2016, our priority remains ensuring ample liquidity and protecting the strength of our balance sheet, and we will adjust our development plans as necessary to this end. We remain in close contact with the banks in our credit facility and are evaluating the increased risk that lenders may seek to reduce our borrowing base due to regulatory pressure to reduce their exposure to the energy industry or for other reasons. Further, we continue to monitor debt, equity and hedging markets for opportunities to strengthen our liquidity position. +37 +Results of Operations +Summary Operating Results +The following table presents selected information regarding our operating results from continuing operations: +Year Ended December 31, +Percent Change +2015 +2014 +2013 +2015-2014 +2014-2013 +(dollars in millions, except per unit data) +Production (1) +Crude oil (MBbls) +6,983.8 +4,321.9 +2,909.7 +61.6 +% +48.5 +% +Natural gas (MMcf) +33,301.7 +19,298.0 +15,431.2 +72.6 +% +25.1 +% +NGLs (MBbls) +2,835.3 +1,756.2 +1,043.2 +61.4 +% +68.3 +% +Crude oil equivalent (MBoe) (2) +15,369.4 +9,294.4 +6,524.7 +65.4 +% +42.4 +% +Average MBoe per day +42.1 +25.5 +17.9 +65.4 +% +42.4 +% +Crude Oil, Natural Gas and NGLs Sales +Crude oil +$ +280.3 +$ +348.6 +$ +261.6 +(19.6 +)% +33.3 +% +Natural gas +68.0 +74.7 +50.0 +(9.0 +)% +49.4 +% +NGLs +30.4 +48.1 +29.2 +(36.8 +)% +64.7 +% +Total crude oil, natural gas and NGLs sales +$ +378.7 +$ +471.4 +$ +340.8 +(19.7 +)% +38.3 +% +Net Settlements on Derivatives (3) +Natural gas +$ +30.0 +$ +(3.1 +) +$ +14.3 +* +* +Crude oil +208.9 +2.3 +(3.1 +) +* +* +Total net settlements on derivatives +$ +238.9 +$ +(0.8 +) +$ +11.2 +* +* +Average Sales Price (excluding net settlements on derivatives) +Crude oil (per Bbl) +$ +40.14 +$ +80.67 +$ +89.92 +(50.2 +)% +(10.3 +)% +Natural gas (per Mcf) +2.04 +3.87 +3.24 +(47.3 +)% +19.4 +% +NGLs (per Bbl) +10.72 +27.39 +27.97 +(60.9 +)% +(2.1 +)% +Crude oil equivalent (per Boe) +24.64 +50.72 +52.23 +(51.4 +)% +(2.9 +)% +Average Lease Operating Expenses (per Boe) (4) +Wattenberg Field +$ +3.78 +$ +4.82 +$ +4.68 +(21.6 +)% +3.0 +% +Utica Shale +2.79 +1.87 +2.63 +49.2 +% +(28.9 +)% +Other +— +3.19 +14.81 +* +(78.5 +)% +Weighted-average +3.71 +4.56 +5.18 +(18.6 +)% +(12.0 +)% +Natural Gas Marketing Contribution Margin (5) +$ +(0.8 +) +$ +(0.4 +) +$ +(0.3 +) +(100.0 +)% +(33.3 +)% +Other Costs and Expenses +Production taxes +$ +18.4 +$ +25.6 +$ +21.8 +(28.0 +)% +17.7 +% +Transportation, gathering and processing expenses +10.2 +4.6 +5.2 +121.1 +% +(10.9 +)% +Exploration expense +1.1 +0.9 +6.3 +16.4 +% +(85.0 +)% +Impairment of crude oil and natural gas properties +161.6 +166.8 +52.9 +(3.1 +)% +215.6 +% +General and administrative expense +90.0 +123.6 +63.7 +(27.2 +)% +93.9 +% +Depreciation, depletion and amortization +303.3 +192.5 +115.6 +57.5 +% +66.5 +% +Interest expense +$ +47.6 +$ +47.8 +$ +50.1 +(0.6 +)% +(4.6 +)% +* +Percentage change is not meaningful or equal to or greater than 300%. +Amounts may not recalculate due to rounding. +38 +______________ +(1) +Production is net and determined by multiplying the gross production volume of properties in which we have an interest by our ownership percentage. For total production volume, including discontinued operations, see Part I, Item 6, Selected Financial Data. +(2) +One Bbl of crude oil or NGL equals six Mcf of natural gas. +(3) +Represents net settlements on derivatives related to crude oil and natural gas sales, which do not include net settlements on derivatives related to natural gas marketing. +(4) +Represents lease operating expenses, exclusive of production taxes, on a per unit basis. +(5) +Represents sales from natural gas marketing, net of costs of natural gas marketing, including net settlements and net change in fair value of unsettled derivatives related to natural gas marketing activities. +Crude Oil, Natural Gas and NGLs Sales +The following tables present crude oil, natural gas and NGLs production and weighted-average sales price for continuing operations: +Year Ended December 31, +Change +Production by Operating Region +2015 +2014 +2013 +2015-2014 +2014-2013 +Crude oil (MBbls) +Wattenberg Field +6,490.4 +4,026.7 +2,783.1 +61.2 +% +44.7 +% +Utica Shale +493.4 +295.2 +122.8 +67.1 +% +140.4 +% +Other +— +— +3.8 +* +* +Total +6,983.8 +4,321.9 +2,909.7 +61.6 +% +48.5 +% +Natural gas (MMcf) +Wattenberg Field +30,752.8 +17,108.9 +12,724.3 +79.7 +% +34.5 +% +Utica Shale +2,548.9 +2,152.9 +561.1 +18.4 +% +283.7 +% +Other +— +36.2 +2,145.8 +* +(98.3 +)% +Total +33,301.7 +19,298.0 +15,431.2 +72.6 +% +25.1 +% +NGLs (MBbls) +Wattenberg Field +2,615.9 +1,605.7 +1,034.4 +62.9 +% +55.2 +% +Utica Shale +219.4 +150.5 +8.8 +45.8 +% +* +Total +2,835.3 +1,756.2 +1,043.2 +61.4 +% +68.3 +% +Crude oil equivalent (MBoe) +Wattenberg Field +14,231.7 +8,483.8 +5,938.2 +67.8 +% +42.9 +% +Utica Shale +1,137.7 +804.6 +225.2 +41.4 +% +257.3 +% +Other +— +6.0 +361.3 +* +(98.3 +)% +Total +15,369.4 +9,294.4 +6,524.7 +65.4 +% +42.4 +% +* +Percentage change is not meaningful or equal to or greater than 300%. +Amounts may not recalculate due to rounding. +39 +Year Ended December 31, +Average Sales Price by Operating Region +Change +(excluding net settlements on derivatives) +2015 +2014 +2013 +2015-2014 +2014-2013 +Crude oil (per Bbl) +Wattenberg Field +$ +40.03 +$ +80.61 +$ +89.83 +(50.3 +)% +(10.3 +)% +Utica Shale +41.59 +81.52 +91.90 +(49.0 +)% +(11.3 +)% +Other +— +— +92.88 +* +* +Weighted-average price +40.14 +80.67 +89.92 +(50.2 +)% +(10.3 +)% +Natural gas (per Mcf) +Wattenberg Field +2.06 +3.94 +3.25 +(47.7 +)% +21.2 +% +Utica Shale +1.85 +3.35 +2.74 +(44.8 +)% +22.3 +% +Other +— +3.90 +3.31 +* +17.8 +% +Weighted-average price +2.04 +3.87 +3.24 +(47.3 +)% +19.4 +% +NGLs (per Bbl) +Wattenberg Field +10.58 +25.95 +27.83 +(59.2 +)% +(6.8 +)% +Utica Shale +12.43 +42.76 +43.70 +(70.9 +)% +(2.2 +)% +Weighted-average price +10.72 +27.39 +27.97 +(60.9 +)% +(2.1 +)% +Crude oil equivalent (per Bbl) +Wattenberg Field +24.64 +51.10 +53.91 +(51.8 +)% +(5.2 +)% +Utica Shale +24.59 +46.87 +58.68 +(47.5 +)% +(20.1 +)% +Other +— +23.42 +20.59 +* +13.7 +% +Weighted-average price +24.64 +50.72 +52.23 +(51.4 +)% +(2.9 +)% +* +Percentage change is not meaningful or equal to or greater than 300%. +Amounts may not recalculate due to rounding. +The year-over-year change in crude oil, natural gas and NGLs sales revenue were primarily due to the following: +Year Ended December 31, +2015 +2014 +(in millions) +Increase in production +$ +298.5 +$ +159.5 +Decrease in average crude oil price +(283.1 +) +(40.0 +) +Increase (decrease) in average natural gas price +(60.9 +) +12.1 +Decrease in average NGLs price +(47.2 +) +(1.0 +) +Total increase (decrease) in crude oil, natural gas and NGLs sales revenue +$ +(92.7 +) +$ +130.6 +Crude oil, natural gas and NGLs sales in 2015 decreased 20% compared to 2014 . The decrease was primarily attributable to a significant decrease in commodity prices, resulting in a 51% decline in the price of a barrel of crude oil equivalent in 2015 compared to 2014. The decrease was offset in part by higher volumes sold in 2015 of 15.4 million Boe, up from 9.3 million Boe in 2014 . Our average daily sales volumes increased to 42 MBoe per day in 2015 compared to 25 MBoe per day in 2014 , as a result of continued drilling and completion activities as discussed in Operational Overview . +Crude oil, natural gas and NGLs sales in 2014 increased 38% compared to 2013 . The increase was primarily attributable to significantly higher volumes sold, in particular liquids, which resulted in a liquids percentage of total production of approximately 65% in 2014 . Our average daily sales volumes increased to 25 MBoe per day in 2014 compared to 18 MBoe per day in 2013 , primarily due to the success of the horizontal Niobrara and Codell drilling program in the Wattenberg Field. Contributing to the increase in crude oil, natural gas and NGLs sales was a 19% increase in the average price of natural gas in 2014 over 2013 . +We continued to experience high line pressures on the midstream system in the Wattenberg Field in the first half of 2015, but the Lucerne II processing plant and additional new compressor stations on the gathering system began initial operations in June 2015, resulting in immediate reductions in line pressures. We have experienced further line pressure reductions in the fourth quarter of 2015, particularly in December of 2015 when our primary service provider, DCP Midstream, completed its Grand Parkway gas gathering project. As a result of the reductions in line pressures during the second half of 2015, production from our Wattenberg Field vertical wells increased by 35% in the second half of 2015 when compared to the first half. Further, we expect sustained relief of gathering system pressure on our primary gatherer's system through 2016, depending upon the impact of reduced drilling activity in the field going forward. Our secondary midstream service provider, which currently gathers and processes approximately 30% of our Wattenberg Field gas, has indicated it will have limitations on its capital program in 2016, which may result in a curtailment of certain of our projected 2016 volumes. We rely on our third-party midstream service providers to +40 +construct compression, gathering and processing facilities to keep pace with our production growth. As a result, the timing and availability of additional facilities going forward is beyond our control. Falling commodity prices have resulted in reduced investment in midstream facilities by some third parties, increasing the risk that sufficient midstream infrastructure will not be available in future periods. +Crude Oil, Natural Gas and NGLs Pricing. Our results of operations depend upon many factors, particularly the price of crude oil, natural gas and NGLs and our ability to market our production effectively. Crude oil, natural gas and NGLs prices are among the most volatile of all commodity prices. The price of crude oil decreased during the second half of 2015 compared to the first half of 2015 amid continuing concerns regarding high U.S. inventories and slowing global demand for crude oil. Natural gas prices in 2015 were at significantly lower levels than the comparable periods of 2014. NGL prices declined significantly during 2015 and, while they have stabilized somewhat, also remain at low levels relative to those experienced in 2014. See Item 1 and 2. Business and Properties - Business Segments - Oil and Gas Exploration and Production for additional information regarding the marketing and pricing provisions of our crude oil, natural gas and NGLs. +Our crude oil, natural gas and NGLs sales are recorded under either the “net-back” or "gross" method of accounting, depending upon the related purchase agreement. We use the "net-back" method of accounting for natural gas and NGLs, as well as a portion of our crude oil production, from the Wattenberg Field and for crude oil from the Utica Shale as the majority of the purchasers of these commodities also provide transportation, gathering and processing services. We sell our commodities at the wellhead and collect a price and recognize revenues based on the wellhead sales price as transportation and processing costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based. We use the "gross" method of accounting for Wattenberg Field crude oil delivered through the White Cliffs pipeline and for natural gas and NGLs sales related to production from the Utica Shale as the purchasers do not provide transportation, gathering or processing services. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses as a component of production costs. As a result of the White Cliffs agreement, our Wattenberg Field crude oil average sales price increased approximately $1.28 per barrel in 2015 attributable to recognizing these costs for transportation on the White Cliffs pipeline as an increase in transportation expense, rather than a deduction from revenues. +Lease Operating Expenses +Lease operating expenses were $57.0 million in 2015 compared to $42.4 million in 2014 . The $14.6 million increase in lease operating expenses in 2015 as compared to 2014 was primarily due to an increase of $4.2 million for environmental remediation and regulatory compliance projects, an increase of $3.4 million for additional wages and employee benefits, including costs for additional contract labor, $2.0 million for workover and maintenance related projects, $1.4 million to mitigate high line pressures in the Wattenberg Field, including costs for the rental of additional compressors, $1.0 million for the increasing number of non-operated wells in the Wattenberg Field and $0.9 million for additional costs pertaining to water hauling and disposal. Lease operating expenses per Boe were $3.71 and $4.56 for 2015 and 2014 , respectively. +Lease operating expenses were $42.4 million in 2014 compared to $33.8 million in 2013 . The $8.6 million increase in lease operating expenses in 2014 as compared to 2013 was primarily due to an increase of $2.9 million to mitigate high line pressures in the Wattenberg Field, including costs for the rental of additional compressors, as well as additional well maintenance incurred in order to increase the operating efficiency of older vertical wells, $1.1 million for workover and maintenance related projects, including additional costs incurred for the plugging of older vertical wells, $1.9 million for environmental compliance and remediation projects, $1.9 million for lease operating expenses incurred on the increasing number of non-operated wells and $1.0 million in additional wages and benefits due to increased headcount. Lease operating expenses per Boe were $4.56 and $5.18 for 2014 and 2013 , respectively. +Production Taxes +Production taxes are directly related to crude oil, natural gas and NGLs sales. The $7.2 million , or 28% , decrease in production taxes for 2015 compared to 2014 is primarily related to the 20% decrease in crude oil, natural gas and NGLs sales and lower production tax rates. Similarly, the $3.9 million , or 18% , increase in production taxes for 2014 compared to 2013 is primarily related to the 38% increase in crude oil, natural gas and NGLs sales. +Transportation, Gathering and Processing Expenses +The $5.6 million , or 121% , increase in transportation, gathering and processing expenses for 2015 compared to 2014 was mainly attributable to oil transportation cost on the White Cliffs pipeline in the Wattenberg Field as we began delivering crude oil to the pipeline at the beginning of July 2015. We expect to continue to incur these oil transportation costs pursuant to our long-term firm transportation agreement. The $0.6 million , or 11% , decrease in transportation, gathering and processing expenses for 2014 compared to 2013 was primarily attributable to a $2.5 million reduction in our unutilized takeaway capacity and other transportation costs resulting from the divestiture of our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties and a $0.4 million decrease in compressor and refrigeration unit rentals in the Utica Shale, offset by a $2.3 million net increase in transportation and processing expenses due to higher production levels, primarily in the Utica Shale region. +41 +Commodity Price Risk Management, Net +We use various derivative instruments to manage fluctuations in natural gas and crude oil prices. We have in place a variety of collars, fixed-price swaps and basis swaps on a portion of our estimated natural gas and crude oil production. Because we sell all of our natural gas and crude oil production at prices similar to the indexes inherent in our derivative instruments, adjusted for certain fees and surcharges stipulated in the applicable sales agreements, we ultimately realize a price, before contract fees, related to our collars of no less than the floor and no more than the ceiling and, for our commodity swaps, we ultimately realize the fixed price related to our swaps, less deductions. See Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this report and Item 7A, Quantitative and Qualitative Disclosures About Market Risk , for a discussion of how each derivative type impacts our cash flows and a detailed presentation of our derivative positions as of December 31, 2015 . +Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments and the change in fair value of unsettled derivatives related to our crude oil and natural gas production. Commodity price risk management, net, does not include derivative transactions related to our natural gas marketing, which are included in sales from and cost of natural gas marketing. See Note 3, Fair Value of Financial Instruments , and Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this report for additional details of our derivative financial instruments. +Net settlements are primarily the result of crude oil and natural gas index prices at maturity of our derivative instruments compared to the respective strike prices. Net change in fair value of unsettled derivatives is comprised of the net asset increase or decrease in the beginning-of-period fair value of derivative instruments that settled during the period and the net change in fair value of unsettled derivatives during the period. The corresponding impact of settlement of the derivative instruments that settled during the period is included in net settlements for the period as discussed above. Net change in fair value of unsettled derivatives during the period is primarily related to shifts in the crude oil and natural gas forward curves and changes in certain differentials. See Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this report for a detailed description of net settlements on our various derivatives. +The following table presents net settlements and net change in fair value of unsettled derivatives included in commodity price risk management, net: +Year Ended December 31, +2015 +2014 +2013 +(in millions) +Commodity price risk management gain (loss), net: +Net settlements: +Natural gas +$ +30.0 +$ +(3.1 +) +$ +14.3 +Crude oil +208.9 +2.3 +(3.1 +) +Total net settlements +238.9 +(0.8 +) +11.2 +Change in fair value of unsettled derivatives: +Reclassification of settlements included in prior period changes in fair value of derivatives +(186.9 +) +13.3 +(28.7 +) +Natural gas fixed price swaps +40.5 +30.6 +4.3 +Natural gas basis swaps +(1.4 +) +— +(4.3 +) +Natural gas collars +12.8 +11.1 +3.8 +Crude oil fixed price swaps +57.0 +206.5 +(9.1 +) +Crude oil collars +42.3 +49.6 +(1.1 +) +Net change in fair value of unsettled derivatives +(35.7 +) +311.1 +(35.1 +) +Total commodity price risk management gain (loss), net +$ +203.2 +$ +310.3 +$ +(23.9 +) +42 +Natural Gas Marketing +Fluctuations in our natural gas marketing's income contribution are primarily due to fluctuations in commodity prices, cash settlements upon maturity of derivative instruments and the change in fair value of unsettled derivatives, and volumes sold and purchased. +The following table presents the components of sales from and costs of natural gas marketing: +Year Ended December 31, +2015 +2014 +2013 +(in millions) +Natural gas sales revenue +$ +10.4 +$ +71.4 +$ +68.9 +Net settlements from derivatives +0.8 +(0.2 +) +0.5 +Net change in fair value of unsettled derivatives +(0.3 +) +0.4 +0.4 +Total sales from natural gas marketing +10.9 +71.6 +69.8 +Costs of natural gas purchases +10.3 +70.1 +68.1 +Net settlements from derivatives +0.7 +(0.3 +) +0.3 +Net change in fair value of unsettled derivatives +(0.3 +) +0.4 +0.4 +Other +1.0 +1.8 +1.3 +Total costs of natural gas marketing +11.7 +72.0 +70.1 +Natural gas marketing contribution margin +$ +(0.8 +) +$ +(0.4 +) +$ +(0.3 +) +Natural gas sales revenue and cost of natural gas purchases decreased in 2015 compared to 2014 as our Gas Marketing segment markets less natural gas following the divestiture of our Appalachian Basin natural gas properties and due to the significant decrease in natural gas prices. Our Gas Marketing segment sold approximately 4.4 Bcf of natural gas at an average price of $1.37 per Mcf in 2015 , compared to approximately 19.8 Bcf of natural gas at an average price of $3.39 per Mcf in 2014 . Our Gas Marketing segment sold approximately 18.4 Bcf of natural gas at an average price of $3.48 per Mcf in 2013 . +Derivative instruments related to natural gas marketing include both physical and cash-settled derivatives. We offer fixed-price derivative contracts for the purchase or sale of physical natural gas and enter into cash-settled derivative positions with counterparties in order to offset those same physical positions. See Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this report and Item 7A, Quantitative and Qualitative Disclosures About Market Risk , for a discussion of how each derivative type impacts our cash flows and a detailed presentation of our derivative positions as of December 31, 2015 . +As natural gas prices continue to remain depressed, certain third-party producers under our Gas Marketing segment have begun and may continue to experience financial distress, which has led to certain contractual defaults and litigation. To date, we have had no material counterparty default losses; however, we expect continued deterioration in the financial condition of some counterparties. In 2015, we recorded an allowance for doubtful accounts of approximately $0.5 million . We have initiated several legal actions for collection against some of the third-party producers, which have resulted in no collections and some of the third-party producers shutting-in their wells. As a result, we expect RNG's expenses to exceed its revenues by approximately $1 million to $2 million per year through 2022, assuming a continuation of current economic conditions. Although some third-party producers have defaulted on their firm transportation fees owed to us, RNG remains obligated to fulfill this commitment regardless of whether or not our third-party producers meet their commitments. As of December 31, 2015, the dollar commitment over the next several years related to this long-term firm transportation, sales and processing agreement was approximately $20.6 million. +Exploration Expense +The following table presents the major components of exploration expense: +Year Ended December 31, +2015 +2014 +2013 +(in millions) +Geological and geophysical costs +$ +— +$ +— +$ +0.7 +Operating, personnel and other +1.1 +0.9 +5.6 +Total exploration expense +$ +1.1 +$ +0.9 +$ +6.3 +43 +Geological and geophysical costs. Geological and geophysical costs in 2013 were primarily related to costs associated with reservoir studies in the Utica Shale. +Operating, personnel and other . The $4.7 million decrease in 2014 compared to 2013 is primarily related to a reduction in personnel costs in the Utica Shale resulting from the reassignment of former exploration department personnel to production departments and to general and administrative expense. +Impairment of Crude Oil and Natural Gas Properties +The following table sets forth the major components of our impairments of crude oil and natural gas properties expense: +Year Ended December 31, +2015 +2014 +2013 +(in millions) +Continuing operations: +Impairment of proved and unproved properties +$ +154.6 +$ +161.6 +$ +49.7 +Amortization of individually insignificant unproved properties +7.0 +4.4 +3.2 +Other +— +0.8 +— +Total impairment of crude oil and natural gas properties +$ +161.6 +$ +166.8 +$ +52.9 +Impairment of proved and unproved properties . Due to a significant decline in commodity prices and a decrease in net-back realizations, we experienced a triggering event that required us to assess our crude oil and natural gas properties for possible impairment during the third quarter of 2015. As a result of our assessment, we recorded an impairment charge of $150.3 million to write-down our Utica Shale proved and unproved properties. Of this impairment charge, $24.7 million was recorded to write-down certain capitalized well costs on our Utica Shale proved producing properties. The impairment charge represented the amount by which the carrying value of these crude oil and natural gas properties exceeded the estimated fair value. The estimated fair value of approximately $27.9 million was determined based on estimated future discounted net cash flows, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. Additionally, as a result of the current outlook for future commodity prices, we recorded an impairment charge of $125.6 million to write-down all of our Utica Shale lease acquisition costs and pad development costs for pads not in production. Further deterioration of commodity prices could result in additional impairment charges to our crude oil and natural gas properties. +In 2014, we recognized an impairment charge of $112.6 million to write-down certain capitalized well costs on our Utica Shale proved producing properties. The impairment charge represented the amount by which the carrying value of the Utica Shale proved producing properties exceeded the estimated fair value due to low commodity prices, large natural gas price differentials in the Appalachian Basin and changes in our Utica Shale drilling plans. The estimated fair value was determined based on estimated future discounted net cash flows, a Level 3 input, using estimated production and prices at which we reasonably expected the crude oil and natural gas would be sold. The impairment charge was included in the consolidated statements of operations line item impairment of crude oil and natural gas properties. In 2014, we also recognized an impairment charge of $45.7 million to write-down certain capitalized leasehold costs on our Utica Shale unproved properties. The impairment was due to low commodity prices, large natural gas price differentials in the Appalachian Basin and changes in our Utica Shale drilling plans. +In 2013, we recognized an impairment charge of approximately $48.8 million related to all of our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties located in West Virginia and Pennsylvania previously owned directly by us, as well as through our proportionate share of PDCM. The impairment charge represented the excess of the carrying value of the assets over the estimated fair value, less the cost to sell. The fair value of the assets was determined based upon estimated future cash flows from unrelated third-party bids, a Level 3 input. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report for additional details related to the sale of these properties. +Amortization of individually insignificant unproved properties. The increase in 2015 compared to 2014 was primarily related to a higher number of insignificant leases that were subject to amortization, primarily in the Utica Shale where we have altered drilling plans due to lower commodity prices and, as a result, expect certain leases to expire. +General and Administrative Expense +General and administrative expense decreased $33.6 million , or 27% , in 2015 compared to 2014. The decrease was primarily attributable to $40.3 million recorded in 2014 in connection with certain partnership-related class action litigation and estimates relating to litigation arising from bankruptcy proceedings of certain affiliated partnerships and a $1.8 million decrease in costs for legal and other professional services in 2015. The decreases were offset in part by an $8.2 million increase in payroll and employee benefits in 2015, of which $3.3 million was related to stock-based compensation. +44 +General and administrative expense increased $59.8 million , or 94% , in 2014 compared to 2013. The increase was mainly attributable to $40.3 million recorded in 2014 in connection with settlement of certain partnership-related class action litigation and litigation arising from bankruptcy proceedings of certain affiliated partnerships. Additional increases were an $13.0 million increase in payroll and employee benefits, of which $4.0 million was related to stock-based compensation, and a $4.6 million increase in legal fees, primarily related to the aforementioned partnership-related class action litigation, consulting and other professional services. +Depreciation, Depletion and Amortization +Crude oil and natural gas properties. DD&A expense related to crude oil and natural gas properties is directly related to proved reserves and production volumes. DD&A expense related to crude oil and natural gas properties was $298.8 million , $188.5 million and $111.6 million in 2015 , 2014 and 2013 , respectively. The year-over-year change in DD&A expense related to crude oil and natural gas properties were primarily due to the following: +Year Ended December 31, +2015 +2014 +(in millions) +Increase in production +$ +123.4 +$ +48.9 +Increase (decrease) in weighted-average depreciation, depletion and amortization rates +(13.1 +) +28.0 +Total increase in DD&A expense related to crude oil and natural gas properties +$ +110.3 +$ +76.9 +The following table presents our DD&A expense rates for crude oil and natural gas properties: +Year Ended December 31, +Operating Region/Area +2015 +2014 +2013 +(per Boe) +Wattenberg Field +$ +20.13 +$ +19.26 +$ +17.68 +Utica Shale +10.74 +31.19 +24.87 +Other +— +— +2.66 +Total weighted-average +19.44 +20.28 +17.05 +The decrease in the Utica Shale DD&A expense rate in 2015 compared to 2014 was primarily due to the effect of impairments recorded in December 2014 and September 2015 to write-down certain capitalized well costs on our Utica Shale proved producing properties, which lowered the net book value of the properties by approximately $137.3 million. As a result of the decrease in proved developed reserves in 2015 as compared to 2014, we expect the weighted-average DD&A expense rate in 2016 to increase as compared to 2015. The increase in the Utica Shale DD&A expense rate in 2014 compared to 2013 was mainly the result of depleting the entire capitalized well costs of a Utica Shale horizontal well that experienced a mechanical failure in 2014. +Non-crude oil and natural gas properties. Depreciation expense for non-crude oil and natural gas properties was $4.5 million for 2015 compared to $4.1 million for 2014 and $4.0 million for 2013 . +Accretion of Asset Retirement Obligations +Accretion of asset retirement obligations ("ARO") for 2015 increased by $2.9 million , or 84% , compared to 2014 . The increase in 2015 is primarily attributable to a decrease in the estimated useful life of certain vertical wells in the Wattenberg Field and increased plugging and abandonment of these wells to allow for horizontal drilling. As a result of the upward revision in estimated cash flows during 2015, we expect an increase in accretion expense for ARO in 2016 as compared to 2015. Accretion of ARO for 2014 decreased by $1.2 million , or 25% , compared to 2013. The decrease in 2014 is primarily attributable to the sale of our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties in 2013. +Interest Expense +Interest expense decreased by approximately $0.3 million in 2015 compared to 2014 . The decrease is primarily comprised of a $1.6 million decrease attributable to an increase in capitalized interest, offset in part by a $0.9 million increase due to higher average borrowings on our revolving credit facility in 2015. +Interest expense decreased by approximately $2.3 million in 2014 compared to 2013 . The decrease is primarily comprised of a $1.8 million decrease attributable to an increase in capitalized interest in 2014. +45 +Interest costs capitalized in 2015 , 2014 and 2013 were $5.1 million , $3.5 million and $1.7 million , respectively. +Provision for Income Taxes +For 2015 , the effective tax rate (the "rate") of 35.9% on loss from continuing operations differs from the statutory tax rate of 35% primarily due to state taxes, percentage depletion and domestic production deduction, partially offset by nondeductible expenses that consist primarily of officers' compensation and government lobbying expenses. For 2014 , the rate of 39.5% on income from continuing operations differs from the statutory tax rate of 35% primarily due to state income taxes. The 2013 rate of 36.0% on loss from continuing operations differs from the statutory tax rate primarily due to state income taxes and the percentage depletion deduction, partially offset by nondeductible executive compensation. See Note 7, Income Taxes , to our consolidated financial statements included elsewhere in this report for our rate reconciliation for each of the years in the three-year period ended December 31, 2015 . +As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions and are not currently under any state income tax examinations. We continue voluntary participation in the Internal Revenue Service’s ("IRS") Compliance Assurance Program (the "CAP Program") for the 2014, 2015 and 2016 tax years. We have received a partial acceptance notice from the IRS for our filed 2014 federal tax return and the IRS's post filing review is continuing. +Discontinued Operations +Appalachian Marcellus Shale Assets. In October 2014 , we completed the sale of our entire 50% ownership interest in PDCM to an unrelated third-party for aggregate consideration, after our share of PDCM's debt repayment and other working capital adjustments, of approximately $192 million , comprised of approximately $153 million in net cash proceeds and a promissory note due in 2020 of approximately $39 million . The transaction included the buyer's assumption of our share of the firm transportation commitment related to the assets owned by PDCM, as well as our share of PDCM's natural gas hedging positions for the years 2014 through 2017. The divestiture resulted in a pre-tax gain of $76.3 million . The divestiture represented a strategic shift in our operations. Accordingly, our proportionate share of PDCM's Marcellus Shale results of operations have been separately reported as discontinued operations in the consolidated statements of operations for all periods presented. +Piceance Basin and NECO . In June 2013, we divested our Piceance Basin, NECO and certain other non-core Colorado oil and gas properties, leasehold mineral interests and related assets for total consideration of approximately $177.6 million , with an additional $17.0 million paid to our non-affiliated investor partners in our affiliated partnerships. Following the sale, we do not have significant continuing involvement in the operations of, or cash flows from, the Piceance Basin and NECO oil and gas properties. Accordingly, the results of operations related to these assets have been reported as discontinued operations for all periods presented in the accompanying consolidated statements of operations included in this report. +For operating results related to our discontinued operations, see Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, to our consolidated financial statements included elsewhere in this report. +Net Income (Loss)/Adjusted Net Income (Loss) +The factors resulting in changes in net loss in 2015 and 2013 compared to net income in 2014 are discussed above. These same reasons similarly impacted adjusted net income (loss), a non-U.S. GAAP financial measure, with the exception of the net change in fair value of unsettled derivatives, adjusted for taxes, of $22.2 million , $193.1 million and $22.8 million in 2015 , 2014 and 2013 , respectively. Adjusted net loss, a non-U.S. GAAP financial measure, was $46.1 million and $37.7 million in 2015 and 2014 , respectively, compared to an adjusted net income of $0.5 million in 2013 . See Reconciliation of Non-U.S. GAAP Financial Measures , below, for a more detailed discussion of this non-U.S. GAAP financial measure. +Financial Condition, Liquidity and Capital Resources +Historically, our primary sources of liquidity have been cash flows from operating activities, our revolving credit facility, proceeds raised in debt and equity market transactions and asset sales. In 2015 , our primary sources of liquidity were net cash flows from operating activities of $411.1 million and the proceeds received from the March 2015 public offering of our common stock of approximately $203 million . We used a portion of the proceeds of the offering to repay all amounts then outstanding on our revolving credit facility and used the remaining amounts to fund a portion of our capital program. +Our primary source of cash flows from operating activities is the sale of crude oil, natural gas and NGLs. Fluctuations in our operating cash flows are substantially driven by commodity prices and changes in our production volumes. Commodity prices have historically been volatile and we manage this volatility through our use of derivatives. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the instrument. For instruments that mature in three years or less, our debt covenants restrict us from entering into hedges that would exceed 85% of our expected future production from total proved reserves for such related time period (proved developed producing, proved developed non-producing and proved undeveloped). For instruments that mature later than three years, but no more than our designated maximum maturity, our debt covenants limit us from entering into hedges that would exceed 85% of our expected future production from proved developed producing properties during that time period. In addition, we may choose not to hedge the maximum amounts permitted under our covenants. Therefore, we may still have significant fluctuations in our cash flows from operating activities due to the remaining non-hedged portion of our future production. Given current commodity prices and our hedge position, we expect that positive net settlements on our derivative positions will continue to be a significant positive component of our 2016 cash flows from operations. +46 +Our working capital fluctuates for various reasons, including, but not limited to, changes in the fair value of our commodity derivative instruments and changes in our cash and cash equivalents due to our practice of utilizing excess cash to reduce the outstanding borrowings under our revolving credit facility. At December 31, 2015 , we had a working capital surplus of $30.7 million compared to a surplus of $89.5 million at December 31, 2014 . The reduction in working capital is primarily the result of classifying as a current liability the carrying value of the Convertible Notes, net of discount, as the stated maturity of the Convertible Notes is May 2016 , offset in part by an decrease in accounts payable and an increase in the fair value of unsettled derivatives. +We ended 2015 with cash and cash equivalents of $0.9 million and availability under our revolving credit facility of $401.3 million , for a total liquidity position of $402.2 million , compared to $398.4 million at December 31, 2014 . These amounts exclude an additional $250 million available under our revolving credit facility, subject to certain terms and conditions of the agreement. The increase in liquidity of $3.8 million , or 0.9% , was primarily attributable to net cash flows from operating activities of $411.1 million , and the proceeds received from the March 2015 public offering of our common stock of approximately $203 million , offset in part by capital expenditures of $604.7 million during 2015 . Our liquidity position will be reduced by the cash payment of approximately $115 million upon the maturity of our Convertible Notes. With our current derivative position, liquidity position and expected cash flows from operations, we believe that we have sufficient capital to fund our planned drilling operations in 2016 . +In March 2015, we filed an automatic shelf registration statement on Form S-3 with the SEC. Effective upon filing, the shelf provides for the potential sale of an unspecified amount of debt securities, common stock or preferred stock, either separately or represented by depository shares, warrants or purchase contracts, as well as units that may include any of these securities or securities of other entities. The shelf registration statement is intended to allow us to be proactive in our ability to raise capital and to have the flexibility to raise such funds in one or more offerings should we perceive market conditions to be favorable. Pursuant to this shelf registration, we sold approximately four million shares of our common stock in March 2015 in an underwritten public offering at a price to us of approximately $50.73 per share. +In recent periods, including the year ended December 31, 2015 , we have been able to access borrowings under our revolving credit facility and to obtain proceeds from the issuance of securities. We cannot, however, assure this will continue to be the case in the future. In light of recent weakened commodity prices, we continue to monitor market conditions and their potential impact on each of our revolving credit facility lenders, many of which are counterparties in our derivative transactions. In addition, we expect that some commercial lenders may look to reduce their exposure to exploration and production companies due to regulatory pressures they face and/or independent business considerations. This could adversely affect our liquidity and our ability to refinance our debt. Our revolving credit facility borrowing base is subject to a redetermination each May and November, based upon a quantification of our proved reserves at each June 30 and December 31, respectively. In September 2015, we completed the semi-annual redetermination of our revolving credit facility, which resulted in the reaffirmation of our borrowing base at $700 million . Further, we entered into a Second Amendment to Third Amended and Restated Credit Agreement that extended the maturity date of our revolving credit facility to May 2020. However, we have elected to maintain the aggregate commitment level at $450 million . We had $37.0 million outstanding on our revolving credit facility as of December 31, 2015 . While we have added and expect to continue to add producing reserves through our drilling operations, the effect of any such reserve additions on our borrowing base could be offset by other factors including, among other things, a prolonged period of depressed commodity prices or regulatory pressure on lenders to reduce their exposure to exploration and production companies. +Our revolving credit facility contains financial maintenance covenants. The covenants require that we maintain: (i) total debt of less than 4.25 times the trailing 12 months earnings before interest, taxes, depreciation, depletion and amortization, change in fair value of unsettled derivatives, exploration expense, gains (losses) on sales of assets and other non-cash, extraordinary or non-recurring gains (losses) ("EBITDAX") and (ii) an adjusted current ratio of at least 1.0 to 1.0. Our adjusted current ratio is adjusted by eliminating the impact on our current assets and liabilities of recording the fair value of crude oil and natural gas derivative instruments. Additionally, available borrowings under our revolving credit facility are added to the current asset calculation and the current portion of our revolving credit facility debt is eliminated from the current liabilities calculation. At December 31, 2015 , we were in compliance with all debt covenants with a 1.4 times debt to EBITDAX ratio and a 1.7 to 1.0 current ratio. We expect to remain in compliance throughout the next year. +The indenture governing our 7.75% senior notes due 2022 contains customary restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (a) incur additional debt, (b) make certain investments or pay dividends or distributions on our capital stock or purchase, redeem or retire capital stock, (c) sell assets, including capital stock of our restricted subsidiaries, (d) restrict the payment of dividends or other payments by restricted subsidiaries to us, (e) create liens that secure debt, (f) enter into transactions with affiliates and (g) merge or consolidate with another company. At December 31, 2015 , we were in compliance with all covenants and expect to remain in compliance throughout the next year. +Pursuant to the indenture governing the Convertible Notes, the conversion rights on our Convertible Notes were triggered on November 15, 2015. We have elected to settle the $115 million principal amount of the notes in cash and issue common stock for the excess conversion value upon maturity in May 2016. We expect to fund the cash settlement of any such conversion from working capital and/or borrowings under our revolving credit facility. +See Part II, Item 7A, Quantitative and Qualitative Disclosures about Market Risk , for our discussion of credit risk. +47 +Cash Flows +Operating Activities. Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes, net settlements from our derivative positions, operating costs and general and administrative expenses. Cash flows provided by operating activities increased in 2015 compared to 2014 . The $174.4 million increase in cash provided by operating activities was primarily due to the increase in net settlements from our derivative positions of $241.0 million and a decrease in general and administrative expense of $33.6 million and production taxes of $7.2 million . The increase was partially offset by the decrease in crude oil, natural gas and NGLs sales of $92.7 million and an increase in lease operating costs of $14.6 million . Cash flows provided by operating activities increased in 2014 compared to 2013. The $77.5 million increase was mainly attributable to the increase in crude oil, natural gas and NGLs sales of $130.6 million and the decrease in changes in assets and liabilities of $35.1 million related to the timing of cash payments and receipts. These increases were offset in part by increases in general and administrative expense of $59.8 million , lease operating costs of $8.6 million and the decrease in net settlements on derivative positions of $15.1 million. The key components for the changes in our cash flows provided by operating activities are described in more detail in Results of Operations above. +Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased by $170.6 million in 2015 and $42.4 million in 2014 when compared to the respective prior years. These changes were primarily due to the same factors mentioned above for changes in cash flows provided by operating activities, without regard to timing of cash payments and/or receipts of our assets and liabilities of $9.7 million and $13.5 million in 2015 and 2014 , respectively. +Adjusted EBITDA, a non-U.S. GAAP financial measure, increased by $78.9 million in 2015 from 2014 , primarily as a result of the increase in net settlements from our derivative positions of $241.0 million and a decrease in general and administrative expense of $33.6 million . The increase was partially offset by the decrease in crude oil, natural gas and NGLs sales of $92.7 million , an $88.8 million decrease in contribution margins from discontinued operations and a $14.6 million increase in lease operating costs. Adjusted EBITDA increased by $122.9 million in 2014 from 2013 , primarily due to a $130.6 million increase in crude oil, natural gas and NGLs sales and a $72.3 million increase in contribution margins related to divested crude oil and natural gas assets, offset in part by a $59.8 million increase in general and administrative expense, an $8.6 million increase in lease operating costs and a $12.1 million decrease in net settlements on derivatives. +See Reconciliation of Non-U.S. GAAP Financial Measures , below, for a more detailed discussion of non-U.S. GAAP financial measures. +Investing Activities. Because crude oil and natural gas production from a well declines rapidly in the first few years of production, we need to continue to commit significant amounts of capital in order to maintain and grow our production and replace our reserves. If capital markets are not available in the future, we will be limited to our cash flows from operations and liquidity under our revolving credit facility as the sources for funding our capital expenditures. We would not be able to maintain our current level of crude oil, natural gas and NGLs production and cash flows from operating activities if capital markets were unavailable, commodity prices were to become depressed for a prolonged period and/or the borrowing base under our revolving credit facility was significantly reduced. The occurrence of such an event may result in our election to defer a substantial portion of our planned capital expenditures and could have a material negative impact on our operations in the future. +Cash flows from investing activities primarily consist of the acquisition, exploration and development of crude oil and natural gas properties, net of dispositions of crude oil and natural gas properties. Our drilling program during the majority of 2015 consisted of five automated drilling rigs operating in the horizontal Niobrara and Codell plays in our Wattenberg Field. We reduced our rig count to four automated drilling rigs in December 2015. See Part I, Items 1 and 2, Business and Properties - Properties - Drilling Activities , for additional details on our drilling activities. Net cash used in investing activities of $604.3 million during 2015 was primarily related to cash utilized for our drilling operations. Net cash used in investing activities of $474.1 million during 2014 was primarily related to cash utilized for our drilling operations of $628.6 million, offset in part by the $152.8 million net cash proceeds received from the sale of our entire 50% ownership interest in PDCM. Net cash used in investing activities of $217.1 million during 2013 was primarily related to cash utilized for our drilling operations of $394.9 million, offset in part by the $187.5 million received from the sale of properties and equipment, including acquisition adjustments. In 2013, we also paid approximately $9.7 million for the acquisition of crude oil and natural gas properties. +Financing Activities. Net cash from financing activities in 2015 was primarily related to the $202.9 million received from the issuance of our common stock in March 2015, partially offset by net payments of approximately $19.0 million to pay down amounts borrowed under our revolving credit facility. Net cash from financing activities in 2014 were primarily comprised of net borrowings under our revolving credit facility of $63.8 million to execute our capital budget. Net cash from financing activities in 2013 was primarily related to the $275.8 million received from the issuance of our common stock in August 2013, partially offset by net payments of approximately $23.3 million to pay down amounts borrowed under revolving credit facilities. +48 +Contractual Obligations and Contingent Commitments +The following table presents our contractual obligations and contingent commitments as of December 31, 2015 : +Payments due by period +Less than +1-3 +3-5 +More than +Contractual Obligations and Contingent Commitments +Total +1 year +years +years +5 years +(in millions) +Long-term liabilities reflected on the consolidated balance sheet (1) +Long-term debt (2) +$ +652.0 +$ +115.0 +$ +— +$ +37.0 +$ +500.0 +Derivative contracts (3) +2.3 +1.6 +0.7 +— +— +Capital leases (4) +1.4 +0.4 +1.0 +— +— +Production tax liability +45.5 +26.5 +19.0 +— +— +Asset retirement obligations +89.5 +5.5 +12.9 +14.0 +57.1 +Other liabilities (5) +4.3 +0.3 +1.3 +1.5 +1.2 +795.0 +149.3 +34.9 +52.5 +558.3 +Commitments, contingencies and other arrangements (6) +Interest on long-term debt (7) +275.8 +42.9 +82.5 +81.0 +69.4 +Operating leases +10.5 +2.4 +4.1 +3.9 +0.1 +Firm transportation and processing agreements (8) +84.6 +17.6 +33.4 +26.4 +7.2 +370.9 +62.9 +120.0 +111.3 +76.7 +Total +$ +1,165.9 +$ +212.2 +$ +154.9 +$ +163.8 +$ +635.0 +__________ +(1) +Table does not include deferred income tax liability to taxing authorities of $143.5 million , due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. +(2) +Amount presented does not agree with the consolidated balance sheets in that it excludes $1.9 million of unamortized debt discount and $7.8 million of unamortized debt issuance costs. See Note 8, Long-Term Debt, to our consolidated financial statements included elsewhere in this report. +(3) +Represents our gross liability related to the fair value of derivative positions. +(4) +Short-term capital lease obligations are included in other accrued expenses on the consolidated balance sheets. Long-term capital lease obligations are included in other liabilities on the consolidated balance sheets. +(5) +Includes deferred compensation to former executive officers and deferred payments related to firm transportation agreements. +(6) +Table does not include an undrawn $11.7 million irrevocable standby letter of credit pending issuance to a transportation service provider. See Note 8, Long-Term Debt, to our consolidated financial statements included elsewhere in this report. Additionally, the table does not include the annual repurchase obligations to investing partners or termination benefits related to employment agreements with our executive officers, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. See Note 12, Commitments and Contingencies - Partnership Repurchase Provision; Employment Agreements with Executive Officers, to our consolidated financial statements included elsewhere in this report. +(7) +Amounts presented include $263.2 million to the holders of our 7.75% senior notes due 2022 and $1.4 million payable to the holders of our 3.25% convertible senior notes due 2016. Amounts also include $11.0 million payable to the participating banks in our revolving credit facility, of which interest of $6.6 million is related to unutilized commitments at a rate of 0.38% per annum, $4.3 million related to the outstanding borrowings on our revolving credit facility of $37.0 million and $0.2 million related to our undrawn letters of credit. +(8) +Represents our gross commitment. See Note 12, Commitments and Contingencies - Firm Transportation, Processing and Sales Agreements, to our consolidated financial statements included elsewhere in this report. +As the managing general partner of affiliated partnerships, we have liability for potential casualty losses in excess of the partnership assets and insurance. We believe that the casualty insurance coverage we and our subcontractors carry is adequate to meet this potential liability. +For information regarding our legal proceedings, see Note 12, Commitments and Contingencies – Litigation , to our consolidated financial statements included elsewhere in this report. From time to time, we are a party to various other legal proceedings in the ordinary course of business. We are not currently a party to any litigation that we believe would have a materially adverse effect on our business, financial condition, results of operations or liquidity. +49 +Critical Accounting Policies and Estimates +We have identified the following policies as critical to business operations and the understanding of our results of operations. This is not a comprehensive list of all of the accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by U.S. GAAP, with no need for our judgment in the application. There are also areas in which our judgment in selecting available alternatives would not produce a materially different result. However, certain of our accounting policies are particularly important to the portrayal of our financial position and results of operations and we may use significant judgment in the application. As a result, they are subject to an inherent degree of uncertainty. In applying those policies, we use our judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on historical experience, observation of trends in the industry and information available from other outside sources, as appropriate. For a more detailed discussion on the application of these and other accounting policies, see Note 2, Summary of Significant Accounting Policies , to our consolidated financial statements included elsewhere in this report. +Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. +Annually, we engage independent petroleum engineers to prepare reserve and economic evaluations of all our properties on a well-by-well basis as of December 31. We adjust our crude oil and natural gas reserves for major acquisitions, new drilling and divestitures during the year as needed. The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. Although every reasonable effort is made to ensure that reserve estimates reported represent our most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect our DD&A expense, a change in our estimated reserves could have an effect on our net income. +Exploration costs, including geological and geophysical expenses, and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but are charged to expense if the well is determined to be nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as the well has found a sufficient quantity of reserves to justify completion as a producing well and we are making sufficient progress assessing our reserves and economic and operating viability. If an in-progress exploratory well is found to be unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the well is classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time when we are able to make a final determination of a well’s productive status, the well is removed from the suspended well status and the proper accounting treatment is applied. +The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired or amortized. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed, and any impairment in value is charged to impairment of crude oil and natural gas properties. The amount of impairment recognized on unproved properties which are not individually significant is determined by amortizing the costs of such properties within appropriate fields based on our historical experience, acquisition dates and average lease terms, with the amortization recognized in impairment of crude oil and natural gas properties. The valuation of unproved properties is subjective and requires us to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values. +We assess our crude oil and natural gas properties for possible impairment upon a triggering event by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. Any impairment in value is charged to impairment of crude oil and natural gas properties. The estimates of future prices may differ from current market prices of crude oil and natural gas. Any downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs could result in a triggering event, and therefore, a reduction in undiscounted future net cash flows and an impairment of our crude oil and natural gas properties. Although our cash flow estimates are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. +Crude Oil, Natural Gas and NGLs Sales Revenue Recognition . Crude oil, natural gas and NGLs sales are recognized when production is sold to a purchaser at a determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes and prices received. We receive payment for sales from one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded two months later. Historically, these differences have been immaterial. +Fair Value of Financial Instruments. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is +50 +based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. +Derivative Financial Instruments. We measure the fair value of our derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. +We validate our fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. While we believe our valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value. +Net settlements on our derivative instruments are initially recorded to accounts receivable or payable, as applicable, and may not be received from or paid to counterparties to our derivative contracts within the same accounting period. Such settlements typically occur the month following the maturity of the derivative instrument. We have evaluated the credit risk of the counterparties holding our derivative assets, which are primarily financial institutions who are also major lenders in our revolving credit facility, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our counterparties on the fair value of our derivative instruments is not significant. +Deferred Income Tax Asset Valuation Allowance. Deferred income tax assets are recognized for deductible temporary differences, net operating loss carry-forwards and credit carry-forwards if it is more likely than not that the tax benefits will be realized. To the extent a deferred tax asset is not expected to be realized under the preceding criteria, we establish a valuation allowance. The factors which we consider in assessing whether we will realize the value of deferred income tax assets involve judgments and estimates of both amount and timing, which could differ from actual results, achieved in future periods. The judgments used in applying these policies are based on our evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results may differ from those estimates. +Accounting for Acquisitions Using Purchase Accounting. We utilize the purchase method to account for acquisitions. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. The purchase price allocations are based on appraisals, discounted cash flows, quoted market prices and estimates by management. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. +In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped, unproved crude oil and natural gas properties and other non-crude oil and natural gas properties. To estimate the fair values of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. +We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. +51 +Recent Accounting Standards +See Note 2, Summary of Significant Accounting Policies - Recently Adopted Accounting Standards , to our consolidated financial statements included elsewhere in this report. +Reconciliation of Non-U.S. GAAP Financial Measures +Adjusted cash flows from operations. We define adjusted cash flows from operations as the cash flows earned or incurred from operating activities, without regard to changes in operating assets and liabilities. We believe it is important to consider adjusted cash flows from operations, as well as cash flows from operations, as we believe it often provides more transparency into what drives the changes in our operating trends, such as production, prices, operating costs and related operational factors, without regard to whether the related asset or liability was received or paid during the same period. We also use this measure because the timing of cash received from our assets, cash paid to obtain an asset or payment of our obligations has been only a timing issue from one period to the next as we have not had accounts receivable collection problems, nor been unable to purchase assets or pay our obligations. See the Consolidated Statements of Cash Flows included elsewhere in this report. +Adjusted net income (loss). We define adjusted net income (loss) as net income (loss), plus loss on commodity derivatives, less gain on commodity derivatives and net settlements on commodity derivatives, each adjusted for tax effect. We believe it is important to consider adjusted net income (loss), as well as net income (loss). We believe this measure often provides more transparency into our operating trends, such as production, prices, operating costs, net settlements from derivatives and related factors, without regard to changes in our net income (loss) from our mark-to-market adjustments resulting from net changes in the fair value of unsettled derivatives. +Adjusted EBITDA. We define adjusted EBITDA as net income (loss), plus loss on commodity derivatives, interest expense, net of interest income, income taxes, impairment of crude oil and natural gas properties, depreciation, depletion and amortization, accretion of asset retirement obligations and loss on debt extinguishment, less gain on commodity derivatives and net settlements on commodity derivatives. Adjusted EBITDA is not a measure of financial performance or liquidity under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss), nor as an indicator of cash flows reported in accordance with U.S. GAAP. Adjusted EBITDA includes certain non-cash costs incurred by us and does not take into account changes in operating assets and liabilities. Other companies in our industry may calculate adjusted EBITDA differently than we do, limiting its usefulness as a comparative measure. We believe adjusted EBITDA is relevant because it is a measure of our operational and financial performance, as well as a measure of our liquidity, and is used by our management, investors, commercial banks, research analysts and others to analyze such things as: +• +operating performance and return on capital as compared to our peers; +• +financial performance of our assets and our valuation without regard to financing methods, capital structure or historical cost basis; +• +ability to generate sufficient cash to service our debt obligations; and +• +viability of acquisition opportunities and capital expenditure projects, including the related rate of return. +PV-10 . We define PV-10 as the estimated present value of the future net cash flows from our proved reserves before income taxes, discounted using a 10% discount rate. We believe that PV-10 provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. We believe that PV-10 is relevant and useful for evaluating the relative monetary significance of our reserves. Professional analysts and sophisticated investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies' reserves. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable in evaluating us and our reserves. PV-10 is not intended to represent the current market value of our estimated reserves. +52 +The following table presents a reconciliation of our non-U.S. GAAP financial measures to its most comparable U.S. GAAP measure: +Year Ended December 31, +2015 +2014 +2013 +(in millions) +Adjusted cash flows from operations: +Adjusted cash flows from operations +$ +420.8 +$ +250.2 +$ +207.8 +Changes in assets and liabilities +(9.7 +) +(13.5 +) +(48.6 +) +Net cash from operating activities +$ +411.1 +$ +236.7 +$ +159.2 +Adjusted net income (loss): +Adjusted net income (loss) +$ +(46.1 +) +$ +(37.7 +) +$ +0.5 +Gain on commodity derivative instruments +203.2 +309.3 +(23.7 +) +Net settlements on commodity derivative instruments +(239.0 +) +2.0 +(13.1 +) +Tax effect of above adjustments +13.6 +(118.2 +) +14.0 +Net income (loss) +$ +(68.3 +) +$ +155.4 +$ +(22.3 +) +Adjusted EBITDA to net income (loss): +Adjusted EBITDA +$ +443.2 +$ +364.3 +$ +241.4 +Gain on commodity derivative instruments +203.2 +309.3 +(23.7 +) +Net settlements on commodity derivative instruments +(239.0 +) +2.0 +(13.1 +) +Interest expense, net +(42.8 +) +(48.6 +) +(51.4 +) +Income tax provision +38.3 +(99.2 +) +12.6 +Impairment of crude oil and natural gas properties +(161.6 +) +(167.3 +) +(53.8 +) +Depreciation, depletion and amortization +(303.3 +) +(201.7 +) +(129.5 +) +Accretion of asset retirement obligations +(6.3 +) +(3.4 +) +(4.8 +) +Net income (loss) +$ +(68.3 +) +$ +155.4 +$ +(22.3 +) +Adjusted EBITDA to net cash from operating activities: +Adjusted EBITDA +$ +443.2 +$ +364.3 +$ +241.4 +Interest expense, net +(42.8 +) +(48.6 +) +(51.4 +) +Stock-based compensation +20.1 +17.5 +12.9 +Amortization of debt discount and issuance costs +7.0 +6.9 +6.8 +(Gain) loss on sale of properties and equipment +(0.4 +) +(76.0 +) +3.7 +Other +(6.3 +) +(13.9 +) +(5.6 +) +Changes in assets and liabilities +(9.7 +) +(13.5 +) +(48.6 +) +Net cash from operating activities +$ +411.1 +$ +236.7 +$ +159.2 +PV-10: +PV-10 +$ +1,337.5 +$ +3,450.1 +$ +2,703.9 +Present value of estimated future income tax discounted at 10% +(240.6 +) +(1,143.6 +) +(921.7 +) +Standardized measure of discounted future net cash flows +$ +1,096.9 +$ +2,306.5 +$ +1,782.2 +Amounts above include results from continuing and discontinued operations. +53 +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK +Market-Sensitive Instruments and Risk Management +We are exposed to market risks associated with interest rate risks, commodity price risk and credit risk. We have established risk management processes to monitor and manage these market risks. +Interest Rate Risk +Changes in interest rates affect the amount of interest we earn on our interest bearing cash, cash equivalents and restricted cash accounts and the interest we pay on borrowings under our revolving credit facility. Our 7.75% senior notes due 2022 and our Convertible Notes have fixed rates and, therefore, near-term changes in interest rates do not expose us to risk of earnings or cash flow loss; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt. +As of December 31, 2015 , our interest-bearing deposit accounts included money market accounts, certificates of deposit and checking and savings accounts with various banks. The amount of our interest-bearing cash, cash equivalents and restricted cash as of December 31, 2015 was $0.7 million, with a weighted-average interest rate of 0.1%. Based on a sensitivity analysis of our interest bearing deposits as of December 31, 2015 , it was estimated that if market interest rates would have increased 1% in 2015 , the impact of the interest income would have been insignificant. +As of December 31, 2015 , excluding the $11.7 million irrevocable standby letter of credit, we had a $37.0 million outstanding balance on our revolving credit facility. It was estimated that if market interest rates would have increased or decreased 1%, our 2015 interest expense would have changed by approximately $0.4 million. +Commodity Price Risk +We are exposed to the potential risk of loss from adverse changes in the market price of crude oil, natural gas and NGLs. Pursuant to established policies and procedures, we manage a portion of the risks associated with these market fluctuations using derivative instruments. These instruments help us predict with greater certainty the effective crude oil and natural gas prices we will receive for our hedged production. We believe that our derivative policies and procedures are effective in achieving our risk management objectives. +The following table presents our derivative positions related to crude oil and natural gas sales in effect as of December 31, 2015 : +Collars +Fixed-Price Swaps +Basis Protection Swaps +Commodity/ Index/ +Maturity Period +Quantity +(Gas - +BBtu (1) +Oil - MBbls) +Weighted-Average +Contract Price +Quantity +(Gas - +BBtu (1) +Oil - MBbls) +Weighted- +Average +Contract +Price +Quantity +(BBtu) (1) +Weighted- +Average +Contract +Price +Fair Value +December 31, +2015 (2) +(in millions) +Floors +Ceilings +Natural Gas +NYMEX +2016 +7,820.0 +$ +3.88 +$ +4.24 +21,930.0 +$ +3.93 +27,600.0 +$ +(0.29 +) +$ +41.2 +2017 +7,920.0 +3.59 +4.13 +24,590.0 +3.62 +12,000.0 +(0.28 +) +26.5 +2018 +1,230.0 +3.00 +3.67 +13,830.0 +3.05 +— +— +2.1 +Total Natural Gas +16,970.0 +60,350.0 +39,600.0 +$ +69.8 +Crude Oil +NYMEX +2016 +1,740.0 +$ +77.59 +$ +97.55 +2,400.0 +$ +90.37 +— +$ +— +$ +178.8 +2017 +960.0 +54.06 +73.77 +480.0 +56.99 +— +— +15.1 +Total Crude Oil +2,700.0 +2,880.0 +— +193.9 +Total Natural Gas and Crude Oil +$ +263.7 +_____________ +(1) +A standard unit of measurement for natural gas (one BBtu equals one MMcf). +(2) +Approximately 34.3% of the fair value of our derivative assets were measured using significant unobservable inputs (Level 3). See Note 3, Fair Value Measurements, to the consolidated financial statements included elsewhere in this report. +54 +The following table presents average NYMEX, CIG and TETCO M-2 closing prices for crude oil and natural gas for the periods identified, as well as average sales prices we realized for our crude oil, natural gas and NGLs production: +Year Ended December 31, +2015 +2014 +Average Index Closing Price: +Crude oil (per Bbl) +NYMEX +$ +48.80 +$ +92.91 +Natural gas (per MMBtu) +NYMEX +$ +2.66 +$ +4.42 +CIG +2.44 +4.17 +TETCO M-2 (1) +1.49 +3.35 +Average Sales Price Realized: +Excluding net settlements on derivatives +Crude oil (per Bbl) +$ +40.14 +$ +80.67 +Natural gas (per Mcf) +2.04 +3.87 +NGLs (per Bbl) +10.72 +27.39 +_____________ +(1) TETCO M-2 is an index price upon which a majority of our natural gas produced in the Utica Shale is sold. +Based on a sensitivity analysis as of December 31, 2015 , it was estimated that a 10% increase in natural gas and crude oil prices, inclusive of basis, over the entire period for which we have derivatives in place, would have resulted in a decrease in the fair value of our derivative positions of $41.0 million, whereas a 10% decrease in prices would have resulted in an increase in fair value of $41.4 million. +See Note 3, Fair Value of Financial Instruments , and Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this report for a summary of our open derivative positions, as well as a discussion of how we determine the fair value of and account for our derivative contracts. +Credit Risk +Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure and entering into transactions with high-quality counterparties. When exposed to significant credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We monitor the creditworthiness of significant counterparties through our credit committee, which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. While we believe that our credit risk analysis and monitoring procedures are reasonable, no amount of analysis can assure performance by our counterparties. +Our Oil and Gas Exploration and Production segment's crude oil, natural gas and NGLs sales are concentrated with a few predominately large customers. This concentrates our credit risk exposure with a small number of large customers. Amounts due to our Gas Marketing segment are from a diverse group of entities, including major upstream and midstream energy companies, financial institutions and end-users in various industries. As commodity prices continue to remain depressed, certain customers under our Gas Marketing segment have begun and may continue to experience financial distress, which has led to certain contractual defaults. To date, we have had no material counterparty default losses relating to customers in either segment. +We primarily use financial institutions which are lenders in our revolving credit facility as counterparties for our derivative financial instruments. Disruption in the credit markets, changes in commodity prices and other factors may have a significant adverse impact on a number of financial institutions. To date, we have had no material counterparty default losses from our derivative financial instruments. See Note 4, Derivative Financial Instruments , to our consolidated financial statements included elsewhere in this report for more detail on our derivative financial instruments. +Disclosure of Limitations +Because the information above included only those exposures that existed at December 31, 2015 , it does not consider those exposures or positions which could arise after that date. As a result, our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, our commodity price risk management strategies at the time and interest rates and commodity prices at the time. +55 +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Index to Consolidated Financial Statements, Financial Statement Schedule and Supplemental Information +Financial Statements: +Report of Independent Registered Public Accounting Firm +57 +Consolidated Balance Sheets - December 31, 201 5 and 2014 +58 +Consolidated Statements of Operations - Years Ended December 31, 2 015, 2014 and 2013 +59 +Consolidated Statements of Cash Flows - Years Ended December 31, 201 5, 2014 and 2013 +60 +Consolidated Statements of Equity - Years Ended December 31, 201 5, 2014 and 2013 +61 +Notes to Consolidated Financial Statements +62 +Supplemental Information - Unaudited: +Crude Oil and Natural Gas Information +89 +Quarterly Financial Information +95 +Financial Statement Schedule: +Schedule II - Valuation and Qualifying Accounts +97 +56 +Report of Independent Registered Public Accounting Firm +To the Board of Directors and Shareholders of PDC Energy, Inc.: +In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, cash flows, and equity present fairly, in all material respects, the financial position of PDC Energy, Inc. and its subsidiaries at December 31, 2015 and December 31, 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for each of the three years ended December 31, 2015, appearing under Item 8, presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. +As discussed in Note 2 to the consolidated financial statements, the Company changed the manner in which it accounts for the presentation of debt issuance costs and deferred taxes in 2015 as well as the manner in which it accounts for discontinued operations in 2014. +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ PricewaterhouseCoopers LLP +Denver, Colorado +February 22, 2016 +57 +PDC ENERGY, INC. +Consolidated Balance Sheets +(in thousands, except share and per share data) +As of December 31, +2015 +2014 +Assets +Current assets: +Cash and cash equivalents +$ +850 +$ +16,066 +Accounts receivable, net +104,274 +131,204 +Fair value of derivatives +221,659 +187,495 +Prepaid expenses and other current assets +5,266 +5,954 +Total current assets +332,049 +340,719 +Properties and equipment, net +1,937,678 +1,827,454 +Assets held for sale +2,874 +2,874 +Fair value of derivatives +44,387 +112,819 +Other assets +53,555 +47,274 +Total Assets +$ +2,370,543 +$ +2,331,140 +Liabilities and Shareholders' Equity +Liabilities +Current liabilities: +Accounts payable +$ +92,613 +$ +130,321 +Production tax liability +26,524 +21,314 +Fair value of derivatives +1,595 +570 +Funds held for distribution +29,894 +27,186 +Current portion of long-term debt +112,940 +— +Accrued interest payable +9,057 +9,109 +Other accrued expenses +28,709 +62,717 +Total current liabilities +301,332 +251,217 +Long-term debt +529,437 +655,475 +Deferred income taxes +143,452 +184,867 +Asset retirement obligation +84,032 +71,992 +Fair value of derivatives +695 +197 +Other liabilities +24,398 +30,033 +Total liabilities +1,083,346 +1,193,781 +Commitments and contingent liabilities +Shareholders' equity +Preferred shares - par value $0.01 per share, 50,000,000 shares authorized, none issued +— +— +Common shares - par value $0.01 per share, 150,000,000 authorized, 40,174,776 and 35,927,985 issued as of December 31, 2015 and 2014, respectively +402 +359 +Additional paid-in capital +907,382 +689,209 +Retained earnings +380,422 +448,702 +Treasury shares - at cost, 20,220 and 21,643 as of December 31, 2015 and 2014, respectively +(1,009 +) +(911 +) +Total shareholders' equity +1,287,197 +1,137,359 +Total Liabilities and Shareholders' Equity +$ +2,370,543 +$ +2,331,140 +See accompanying Notes to Consolidated Financial Statements +58 +PDC ENERGY, INC. +Consolidated Statements of Operations +(in thousands, except per share data) +Year Ended December 31, +2015 +2014 +2013 +Revenues +Crude oil, natural gas and NGLs sales +$ +378,713 +$ +471,413 +$ +340,795 +Sales from natural gas marketing +10,920 +71,571 +69,787 +Commodity price risk management gain (loss), net +203,183 +310,304 +(23,919 +) +Well operations, pipeline income and other +2,510 +2,919 +6,002 +Total revenues +595,326 +856,207 +392,665 +Costs, expenses and other +Lease operating expenses +56,992 +42,402 +33,817 +Production taxes +18,443 +25,615 +21,758 +Transportation, gathering and processing expenses +10,151 +4,592 +5,152 +Cost of natural gas marketing +11,717 +72,015 +70,084 +Exploration expense +1,102 +947 +6,334 +Impairment of crude oil and natural gas properties +161,620 +166,847 +52,873 +General and administrative expense +89,959 +123,559 +63,715 +Depreciation, depletion and amortization +303,258 +192,528 +115,624 +Accretion of asset retirement obligations +6,293 +3,415 +4,566 +(Gain) loss on sale of properties and equipment +(385 +) +507 +2,022 +Total cost, expenses and other +659,150 +632,427 +375,945 +Income (loss) from operations +(63,824 +) +223,780 +16,720 +Interest expense +(47,571 +) +(47,842 +) +(50,143 +) +Interest income +4,807 +1,290 +460 +Income (loss) from continuing operations before income taxes +(106,588 +) +177,228 +(32,963 +) +Provision for income taxes +38,308 +(69,967 +) +11,852 +Income (loss) from continuing operations +(68,280 +) +107,261 +(21,111 +) +Income (loss) from discontinued operations, net of tax +— +48,174 +(1,190 +) +Net income (loss) +$ +(68,280 +) +$ +155,435 +$ +(22,301 +) +Earnings per share: +Basic +Income (loss) from continuing operations +$ +(1.74 +) +$ +3.00 +$ +(0.65 +) +Income (loss) from discontinued operations, net of tax +— +1.34 +(0.04 +) +Net income (loss) +$ +(1.74 +) +$ +4.34 +$ +(0.69 +) +Diluted +Income (loss) from continuing operations +$ +(1.74 +) +$ +2.93 +$ +(0.65 +) +Income (loss) from discontinued operations, net of tax +— +1.31 +(0.04 +) +Net income (loss) +$ +(1.74 +) +$ +4.24 +$ +(0.69 +) +Weighted-average common shares outstanding: +Basic +39,153 +35,784 +32,426 +Diluted +39,153 +36,678 +32,426 +See accompanying Notes to Consolidated Financial Statements +59 +PDC ENERGY, INC. +Consolidated Statements of Cash Flows +(in thousands) +Year Ended December 31, +2015 +2014 +2013 +Cash flows from operating activities: +Net income (loss) +$ +(68,280 +) +$ +155,435 +$ +(22,301 +) +Adjustments to net income (loss) to reconcile to net cash from operating activities: +Net change in fair value of unsettled derivatives +35,791 +(311,281 +) +36,801 +Depreciation, depletion and amortization +303,258 +201,656 +129,518 +Impairment of crude oil and natural gas properties +161,620 +167,280 +53,802 +Accretion of asset retirement obligation +6,293 +3,455 +4,747 +Stock-based compensation +20,068 +17,518 +12,880 +Excess tax benefits from stock-based compensation +(1,361 +) +(1,999 +) +(2,489 +) +(Gain) loss from sale of properties and equipment +(385 +) +(75,972 +) +3,722 +Amortization of debt discount and issuance costs +7,040 +6,938 +6,783 +Deferred income taxes +(41,415 +) +88,474 +(15,883 +) +Other +(1,855 +) +(1,329 +) +170 +Total adjustments to net income (loss) to reconcile to net cash from operating activities: +489,054 +94,740 +230,051 +Changes in assets and liabilities: +Accounts receivable +24,769 +(34,598 +) +(41,509 +) +Other assets +(2,264 +) +(3,296 +) +3,461 +Restricted cash +46 +2,214 +(8 +) +Production tax liability +(1,629 +) +3,358 +4,121 +Accounts payable and accrued expenses +(30,310 +) +21,453 +(11,485 +) +Other liabilities +(313 +) +(2,617 +) +(3,165 +) +Total changes in assets and liabilities +(9,701 +) +(13,486 +) +(48,585 +) +Net cash from operating activities +411,073 +236,689 +159,165 +Cash flows from investing activities: +Capital expenditures +(604,668 +) +(628,592 +) +(394,948 +) +Acquisition of crude oil and natural gas properties, net of cash acquired +— +— +(9,658 +) +Proceeds from acquisition adjustments +— +— +7,579 +Proceeds from sale of properties and equipment, net +405 +154,457 +179,919 +Net cash from investing activities +(604,263 +) +(474,135 +) +(217,108 +) +Cash flows from financing activities: +Proceeds from revolving credit facility +397,000 +263,750 +260,250 +Repayment of revolving credit facility +(416,000 +) +(200,000 +) +(283,500 +) +Payment of debt issuance costs +(974 +) +(88 +) +(2,352 +) +Proceeds from sale of common stock, net of issuance costs +202,851 +— +275,847 +Excess tax benefits from stock-based compensation +1,361 +1,999 +2,489 +Purchase of treasury shares +(6,056 +) +(5,392 +) +(4,133 +) +Principal payments under capital lease obligations +(208 +) +— +— +Proceeds from exercise of stock options +— +— +128 +Net cash from financing activities +177,974 +60,269 +248,729 +Net change in cash and cash equivalents +(15,216 +) +(177,177 +) +190,786 +Cash and cash equivalents, beginning of year +16,066 +193,243 +2,457 +Cash and cash equivalents, end of year +$ +850 +$ +16,066 +$ +193,243 +Supplemental cash flow information: +Cash payments for (receipts from): +Interest, net of capitalized interest +$ +45,642 +$ +46,809 +$ +48,844 +Income taxes +10,049 +1,800 +(3,014 +) +Non-cash investing activities: +Change in accounts payable related to capital expenditures +(45,230 +) +39,667 +33,328 +Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposal +14,030 +33,250 +2,112 +Change in accounts receivable related to sale of properties and equipment +— +— +808 +Change in other assets related to sale of properties and equipment +— +39,048 +3,350 +Purchase of properties and equipment under capital leases +1,601 +— +— +See accompanying Notes to Consolidated Financial Statements +60 +PDC ENERGY, INC. +Consolidated Statements of Equity +(in thousands, except share and per share data) +Year Ended December 31, +2015 +2014 +2013 +Common shares, issued: +Shares beginning of year +35,927,985 +35,675,656 +30,294,224 +Shares issued pursuant to sale of equity +4,002,000 +— +5,175,000 +Exercise of stock options +7,720 +— +10,763 +Issuance of stock awards, net of forfeitures +237,071 +253,032 +212,926 +Retirement of treasury shares +— +(703 +) +(17,257 +) +Shares end of year +40,174,776 +35,927,985 +35,675,656 +Treasury shares: +Shares beginning of year +21,643 +5,508 +5,059 +Purchase of treasury shares +120,864 +97,646 +84,642 +Issuance of treasury shares +(127,159 +) +(83,208 +) +(67,334 +) +Retirement of treasury shares +— +(703 +) +(17,257 +) +Non-employee directors' deferred compensation plan +4,872 +2,400 +398 +Shares end of year +20,220 +21,643 +5,508 +Common shares outstanding +40,154,556 +35,906,342 +35,670,148 +Equity: +Shareholders' equity +Preferred shares, par value $0.01 per share: +Balance beginning and end of year +$ +— +$ +— +$ +— +Common shares, par value $0.01 per share: +Balance beginning of year +359 +357 +303 +Shares issued pursuant to sale of equity +40 +— +52 +Issuance of stock awards, net of forfeitures +3 +2 +2 +Balance end of year +402 +359 +357 +Additional paid-in capital: +Balance beginning of year +689,209 +674,211 +387,494 +Proceeds from sale of equity, net of issuance costs +202,811 +— +275,795 +Exercise of stock options +— +— +125 +Stock-based compensation expense +20,207 +17,851 +12,402 +Issuance of treasury shares +(6,206 +) +(4,817 +) +(3,270 +) +Retirement of treasury shares +— +(35 +) +(824 +) +Tax impact of stock-based compensation +1,361 +1,999 +2,489 +Balance end of year +907,382 +689,209 +674,211 +Retained earnings: +Balance beginning of year +448,702 +293,267 +315,568 +Net income (loss) attributable to shareholders +(68,280 +) +155,435 +(22,301 +) +Balance end of year +380,422 +448,702 +293,267 +Treasury shares, at cost: +Balance beginning of year +(911 +) +(241 +) +(184 +) +Purchase of treasury shares +(6,055 +) +(5,392 +) +(4,133 +) +Issuance of treasury shares +6,206 +4,817 +3,271 +Retirement of treasury shares +— +35 +824 +Non-employee directors' deferred compensation plan +(249 +) +(130 +) +(19 +) +Balance end of year +(1,009 +) +(911 +) +(241 +) +Total shareholders' equity +$ +1,287,197 +$ +1,137,359 +$ +967,594 +See accompanying Notes to Consolidated Financial Statements +61 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION +PDC Energy, Inc. (the "Company," "we," "us," or "our") is a domestic independent exploration and production company that produces, develops, acquires and explores for crude oil, natural gas and NGLs, with primary operations in the Wattenberg Field in Colorado and the Utica Shale in southeastern Ohio. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Ohio operations are focused in the Utica Shale play. As of December 31, 2015 , we owned an interest in approximately 3,000 gross wells. We are engaged in two business segments: Oil and Gas Exploration and Production and Gas Marketing. In October 2014 , we sold our entire 50% ownership interest in our joint venture, PDCM, to an unrelated third-party. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information. +The accompanying audited consolidated financial statements include the accounts of PDC, our wholly-owned subsidiary Riley Natural Gas ("RNG"), our proportionate share of our four affiliated partnerships and, for the year ended December 31, 2014 and 2013, our proportionate share of PDCM. As of December 31, 2015 , we had four remaining affiliated partnerships that continue to conduct crude oil and natural gas producing activities. Pursuant to the proportionate consolidation method, our accompanying consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation. +The preparation of our consolidated financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of crude oil, natural gas and NGLs sales revenue, crude oil, natural gas and NGLs reserves, future cash flows from crude oil and natural gas properties, valuation of derivative instruments, impairment of proved and unproved properties and valuation of deferred income tax assets. +During the fourth quarter of 2015, we reclassified certain amounts within our costs and expenses in the consolidated statements of operations and assets and liabilities in the consolidated balance sheets. Specifically, production costs has been segregated into lease operating expenses, production taxes and transportation, gathering and processing expenses. This reclassification has been made to prior period financial statements to conform to the current year presentation. We believe these changes allow users of our financial statements to better understand our expense structure and make our financial statements more comparable to those of peer companies. +Further, we have noted the following misclassifications in prior year filings, which have been corrected in the current year presentation: +• +Production-related general and administrative costs totaling $7.7 million and $3.8 million for 2014 and 2013, respectively, have been reclassified from production costs to general and administrative expense; +• +Prepaid well costs write-offs totaling $3.3 million and $0.4 million for 2014 and 2013, respectively, have been reclassified from production costs to impairment of crude oil and natural gas properties; and +• +Prepaid well costs totaling $27.3 million in the December 31, 2014 consolidated balance sheet have been reclassified from other assets to properties and equipment, net; +We evaluated the impact of these misclassifications and determined they were not material to the prior periods presented. +Additionally, as a result of adopting the accounting standards update on the balance sheet classification of debt issuance costs and deferred taxes, the following reclassifications have been made to the prior period financial statements: +• +Debt issuance costs totaling $9.4 million in the December 31, 2014 consolidated balance sheet have been reclassified from other assets and are presented as a direct deduction from the carrying amount of long-term debt; and +• +Current deferred income tax liabilities totaling $59.2 million in the December 31, 2014 consolidated balance sheet have been reclassified to non-current pursuant to the income tax accounting standards update issued and adopted in 2015. +These reclassifications had no impact on previously reported cash flows, net income, earnings per share or shareholders' equity. +NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Cash Equivalents. We consider all highly liquid investments with original maturities of three months or less to be cash equivalents. +Restricted Cash. We are required by certain government agencies or agreements to maintain bonds or cash accounts for various operating activities. As of December 31, 2015 and 2014 , we had collateral in the form of certificates of deposit and cash totaling $0.7 million included in other assets. +Inventory. Inventory consists of crude oil, stated at the lower of cost to produce or market, and other production supplies intended to be used in our crude oil and natural gas operations. As of December 31, 2015 and 2014 , inventory of $0.6 million and $0.8 million , respectively, is included in prepaid expenses and other current assets on the consolidated balance sheets. Additionally, as of December 31, 2015 , inventory for the White Cliffs pipeline line fill of $1.1 million is included in other assets on the consolidated balance sheets. +Derivative Financial Instruments. We are exposed to the effect of market fluctuations in the prices of crude oil, natural gas and NGLs. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy prohibits the use of crude oil and natural gas derivative instruments for speculative purposes. +62 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +All derivative assets and liabilities are recorded on our consolidated balance sheets at fair value. We have elected not to designate any of our derivative instruments as hedges. Accordingly, changes in the fair value of our derivative instruments are recorded in the consolidated statements of operations. Classification of net settlements resulting from maturities and changes in fair value of unsettled derivatives depends on the purpose for issuing or holding the derivative. Changes in the fair value of derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Changes in the fair value of derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of natural gas marketing. +The validation of the derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. See Note 3, Fair Value of Financial Instruments , and Note 4, Derivative Financial Instruments , for a discussion of our derivative fair value measurements and a summary fair value table of our open positions as of December 31, 2015 and 2014 , respectively. +Properties and Equipment. Significant accounting polices related to our properties and equipment are discussed below. +Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. We calculate quarterly depreciation, depletion and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted to add back fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the consolidated statements of operations as a gain or loss. Upon the sale of individual wells or a portion of a field, the proceeds are credited to accumulated DD&A. +Exploration costs, including geological and geophysical expenses and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the proper accounting treatment is recorded. See Note 6, Properties and Equipment , for disclosures related to changes in our capitalized exploratory well costs, if any. +Proved Property Impairment. Upon a triggering event, we assess our producing crude oil and natural gas properties for possible impairment by comparing net capitalized costs, or carrying value, to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. The estimates of future prices may differ from current market prices of crude oil, natural gas and NGLs. Certain events, including but not limited to downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event and, therefore, a possible impairment of our proved crude oil and natural gas properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis and is measured by the amount by which the net capitalized costs exceed their fair value. Impairments are included in the consolidated statements of operations line item impairment of crude oil and natural gas properties, with a corresponding impact on accumulated DD&A on the consolidated balance sheets. +Unproved Property Impairment. The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired or amortized. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized, by field, based on our historical experience, acquisition dates and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statements of operations line item impairment of crude oil and natural gas properties. +63 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Other Property and Equipment. Other property and equipment is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of the asset exceeds our estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. There were no impairments to other property and equipment in 2015 and 2013 , respectively. Total impairments to other property and equipment was $0.8 million in 2014 . +The following table presents the estimated useful lives of our other property and equipment: +Transportation and other equipment +3 - 20 years +Buildings +20 - 30 years +Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed from the accounts, the proceeds are applied thereto and any resulting gain or loss is reflected in income. Total depreciation expense related to other property and equipment was $4.5 million , $4.1 million and $4.0 million in 2015 , 2014 and 2013 , respectively. +Capitalized Interest. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our debt outstanding by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $5.1 million , $3.5 million and $1.7 million in 2015 , 2014 and 2013 , respectively. +Assets Held for Sale. Assets held for sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques such as a discounted cash flow model, valuations performed by third parties, earnings multiples or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets to be divested once they are classified as held for sale. Assets classified as held for sale are expected to be disposed of within one year. Assets to be divested are classified in the consolidated financial statements as held for sale and the activities of assets to be divested are classified either as discontinued operations or continuing operations. For assets classified as discontinued operations, the results of operations are reclassified from their historical presentation to discontinued operations on the consolidated statements of operations for all periods presented. The gains or losses associated with these divested assets are recorded in discontinued operations on the consolidated statements of operations. For businesses classified as held for sale that do not qualify for discontinued operations treatment, the results of operations continue to be reported in continuing operations. +Production Tax Liability. Production tax liability represents estimated taxes, primarily severance, ad valorem and property, to be paid to the states and counties in which we produce crude oil, natural gas and NGLs, including the production of our affiliated partnerships. Our share of these taxes is expensed and included in the statement of operations line item production taxes. Affiliated partnerships' share, not owned by us, is recognized as a receivable in accounts receivable affiliates on the consolidated balance sheets. The long-term portion of the production tax liability is included in other liabilities on the consolidated balance sheets and was $19.0 million and $26.4 million in December 31, 2015 and 2014 , respectively. +Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable. As of December 31, 2015 and 2014 , we had no valuation allowance. +Debt Issuance Costs. Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs capitalized as of December 31, 2015 and 2014 were $11.4 million and $13.7 million , respectively. The December 31, 2015 amount included $0.2 million in costs related to the issuance of our 3.25% convertible senior notes due 2016 and $7.6 million related to our 7.75% senior notes due 2022, both shown as a reduction in the related debt, and $3.6 million related to our revolving credit facility shown as a long-term asset. The December 31, 2014 amount included $0.7 million in costs related to the issuance of our 3.25% convertible senior notes due 2016, $8.7 million related to our 7.75% senior notes due 2022 and $4.3 million related to our revolving credit facility. +Asset Retirement Obligations. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the well is completed. Upon initial recognition of an asset retirement obligation, we increase the +64 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from changes in retirement costs or the estimated timing of settling asset retirement obligations. See Note 10, Asset Retirement Obligations , for a reconciliation of the changes in our asset retirement obligation. +Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in shareholders’ equity in the consolidated balance sheets. When we retire treasury shares, we charge any excess of cost over the par value entirely to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings. +Revenue Recognition. Significant accounting polices related to our revenue recognition are discussed below. +Crude oil, natural gas and NGLs sales. Crude oil, natural gas and NGLs revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. Our crude oil, natural gas and NGLs sales are recorded under either the “net-back” or "gross" method of accounting, depending upon the transportation method used. We use the "net-back" method of accounting for natural gas and NGLs, as well as a portion of our crude oil production, from the Wattenberg Field and for crude oil from the Utica Shale as the majority of the purchasers of these commodities also provide transportation, gathering and processing services. We sell our commodities at the wellhead and collect a price and recognize revenues based on the wellhead sales price as transportation and processing costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based. We use the "gross" method of accounting for Wattenberg Field crude oil delivered through the White Cliffs pipeline and for natural gas and NGLs sales related to production from the Utica Shale as the purchasers do not provide transportation, gathering or processing services. Under this method, we recognize revenues based on the gross selling price. +Natural gas marketing. Natural gas marketing is reported on the gross method of accounting, based on the nature of the agreements between our natural gas marketing subsidiary, RNG, suppliers and customers. RNG purchases gas from many small producers and bundles the gas together for a price advantage to sell in larger amounts to purchasers of natural gas. RNG has latitude in establishing price and discretion in supplier and purchaser selection. Natural gas marketing revenues and expenses reflect the full cost and revenue of those transactions because RNG takes title to the gas it purchases from the various producers and bears the risks and rewards of that ownership. Both the net settlements and net change in fair value of unsettled derivatives of the RNG commodity-based derivative transactions for natural gas marketing are included in sales from or cost of natural gas marketing, as applicable. +Well operations and pipeline income . We are paid a monthly operating fee for each well we operate and the natural gas transported for outside owners, including the affiliated partnerships we sponsor. Well operations and pipeline income is recognized when persuasive evidence of an arrangement exists, the sales price is fixed or determinable, services have been rendered and collection of revenues is reasonably assured. +Accounting for Acquisitions. We utilize the purchase method to account for acquisitions. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows, quoted market prices and estimates by management. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. +In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped, unproved crude oil and natural gas properties and other non-crude oil and natural gas properties. To estimate the fair value of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. +We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. +Stock-Based Compensation. Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock based compensation expense is recognized in the financial statements on a straight-line basis over the vesting period for the entire award. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statements of operations. No amounts for stock-based compensation were capitalized in 2015 , 2014 and 2013 . +65 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Allowance for Doubtful Accounts. Inherent to our industry is the concentration of crude oil, natural gas and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs and overall creditworthiness of our customers. Further, consideration is given to well production data for receivables related to well operations. +Interest Income. Interest income on our note receivable is recognized over its term using the effective interest method. +Recently Adopted Accounting Standards. +In November 2014, the FASB issued an update to accounting for derivatives and hedging instruments. The update clarifies how current accounting guidance should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. Specifically, the accounting update clarifies that an entity should consider all relevant terms and features, including the embedded derivative feature being evaluated for bifurcation, in evaluating the nature of the host contract. Furthermore, the update clarifies that no single term or feature would necessarily determine the economic characteristics and risks of the host contract. Rather, the nature of the host contract depends upon the economic characteristics and risks of the entire hybrid financial instrument. The assessment of the substance of the relevant terms and features should incorporate a consideration of the characteristics of the terms and features themselves, the circumstances under which the hybrid financial instrument was issued or acquired, and the potential outcomes of the hybrid financial instrument, as well as the likelihood of those potential outcomes. The accounting update is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. We elected to early adopt this guidance on October 1, 2015. Adoption of this guidance did not have a significant impact on our consolidated financial statements. +In January 2015, the FASB issued new accounting guidance eliminating from current accounting guidance the concept of extraordinary items, which, among other things, required an entity to segregate extraordinary items considered to be unusual and infrequent from the results of ordinary operations and show the item separately in the income statement, net of tax, after income from continuing operations. This guidance is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. We elected to early adopt this guidance on October 1, 2015. Adoption of this guidance did not have a significant impact on our consolidated financial statements. +In February 2015, the FASB issued an accounting update modifying existing consolidation guidance for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. The amendments in this update are effective for fiscal years and interim periods within those years beginning after December 15, 2015, and require either a retrospective or a modified retrospective approach to adoption. Early adoption is permitted. We elected to early adopt this guidance on October 1, 2015. Adoption of this guidance did not have a significant impact on our consolidated financial statements. +In April 2015, the FASB issued an accounting update simplifying the presentation of debt issuance costs and requiring that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The update did not affect the recognition and measurement guidance for debt issuance costs. This guidance is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted. We elected to early adopt this guidance on October 1, 2015. Adoption of this guidance did not have a significant impact on our consolidated financial statements. See Note 1, Nature of Operations and Basis of Presentation, for the amounts reclassified in the December 31, 2014 consolidated balance sheet. +In July 2015, the FASB issued an accounting update requiring all entities to measure inventory at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This guidance is effective for public entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016. We elected to early adopt this guidance on October 1, 2015. Adoption of this guidance did not have a significant impact on our consolidated financial statements. +In September 2015, the FASB issued an accounting update requiring adjustments to provisional amounts that are identified during the measurement period of a business combination to be recognized in the reporting period in which the adjustment amounts are determined. The accounting update also requires an entity to present separately on the face of the income statement, or disclose in the notes, the portion of the amount recorded in current-period earnings, by line item, that would have been recorded in previous reporting periods if the adjustment to the estimated amounts had been recognized as of the acquisition date. This guidance is effective for public entities for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. The accounting update should be applied prospectively to adjustments to provisional amounts that occur after the effective date with earlier application permitted for financial statements that have not been issued. We elected to early adopt this guidance on October 1, 2015. Adoption of this guidance did not have a significant impact on our consolidated financial statements. +In November 2015, the FASB issued an accounting update simplifying the presentation of deferred income taxes by requiring that all deferred tax liabilities and assets, along with any related valuation allowance, be classified as non-current in a classified statement of financial position. This guidance is effective for financial statements issued for annual periods beginning after December 15, 2016, and interim periods +66 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +within those annual periods. Early adoption is permitted. We elected to early adopt this guidance on October 1, 2015. See Note 1, Nature of Operations and Basis of Presentation, for the amounts reclassified in the December 31, 2014 consolidated balance sheet. +Recently Issued Accounting Standards. +In May 2014, the Financial Accounting Standards Board ("FASB") and the International Accounting Standards Board issued their converged standard on revenue recognition that provides a single, comprehensive model that entities will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (1) identify the contract with the customer, (2) identify the separate performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to separate performance obligations and (5) recognize revenue when (or as) each performance obligation is satisfied. In August 2015, the FASB deferred the effective date of the revenue standard to annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The revenue standard can be adopted under the full retrospective method or simplified transition method. Entities are permitted to adopt the revenue standard early, beginning with annual reporting periods after December 15, 2016. We are currently evaluating the impact these changes may have on our consolidated financial statements. +In August 2014, the FASB issued a new standard related to the disclosure of uncertainties about an entity's ability to continue as a going concern. The new standard will explicitly require management to assess an entity's ability to continue as a going concern every reporting period and to provide related footnote disclosures in certain circumstances. The new standard will be effective for all entities in the first annual period ending after December 15, 2016, with early adoption permitted. Adoption of this guidance is not expected to have a significant impact on our consolidated financial statements. +NOTE 3 - FAIR VALUE OF FINANCIAL INSTRUMENTS +Derivative Financial Instruments +Determination of fair value. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. +Derivative Financial Instruments. We measure the fair value of our derivative instruments based on a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. +We validate our fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques and believe our valuation method is appropriate and consistent with those used by other market participants, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. +Our fixed-price swaps, basis swaps and physical purchases are included in Level 2 and our collars and physical sales are included in Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis: +67 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +As of December 31, +2015 +2014 +Significant Other +Observable +Inputs +(Level 2) +Significant +Unobservable +Inputs +(Level 3) +Total +Significant Other +Observable +Inputs +(Level 2) +Significant +Unobservable +Inputs +(Level 3) +Total +(in thousands) +Assets: +Commodity-based derivative contracts +$ +174,657 +$ +91,288 +$ +265,945 +$ +237,939 +$ +62,356 +$ +300,295 +Basis protection derivative contracts +101 +— +101 +19 +— +19 +Total assets +174,758 +91,288 +266,046 +237,958 +62,356 +300,314 +Liabilities: +Commodity-based derivative contracts +738 +— +738 +742 +— +742 +Basis protection derivative contracts +1,552 +— +1,552 +25 +— +25 +Total liabilities +2,290 +— +2,290 +767 +— +767 +Net asset +$ +172,468 +$ +91,288 +$ +263,756 +$ +237,191 +$ +62,356 +$ +299,547 +The following table presents a reconciliation of our Level 3 assets measured at fair value: +2015 +2014 +2013 +(in thousands) +Fair value, net asset beginning of period +$ +62,356 +$ +1,111 +$ +13,610 +Changes in fair value included in statement of operations line item: +Commodity price risk management gain (loss), net +65,018 +62,003 +(1,748 +) +Sales from natural gas marketing +146 +(22 +) +13 +Settlements included in statement of operations line items: +Commodity price risk management gain (loss), net +(36,169 +) +(737 +) +(6,361 +) +Sales from natural gas marketing +(63 +) +1 +(37 +) +Loss from discontinued operations, net of tax +— +— +(4,366 +) +Fair value, net asset end of period +$ +91,288 +$ +62,356 +$ +1,111 +Net change in fair value of unsettled derivatives included in statement of operations line item: +Commodity price risk management gain (loss), net +$ +43,540 +$ +15,632 +$ +(2,731 +) +Sales from natural gas marketing +— +3 +4 +Total +$ +43,540 +$ +15,635 +$ +(2,727 +) +The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. There has been no change in the methodology we apply to measure the fair value of our Level 3 derivative contracts. +Non-Derivative Financial Assets and Liabilities +The carrying value of the financial instruments included in current assets and current liabilities, excluding the current portion of long-term debt, approximate fair value due to the short-term maturities of these instruments. See Note 2, Summary of Significant Accounting Policies - Properties and Equipment, Crude Oil and Natural Gas Properties and Asset Retirement Obligations, for a discussion of how we determined fair value for these assets and liabilities. +The liability associated with our non-qualified deferred compensation plan for non-employee directors may be settled in cash or shares of our common stock. The carrying value of this obligation is based on the quoted market price of our common stock, which is a Level 1 input. The liability related to this plan, which was included in other liabilities on the consolidated balance sheets, was immaterial as of December 31, 2015 and 2014 . +The portion of our long-term debt related to our revolving credit facility approximates fair value due to the variable nature of related interest rates. We have not elected to account for the portion of our debt related to our senior notes under the fair value option; however, as of +68 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +December 31, 2015 , we estimate the fair value of the portion of our long-term debt related to our 3.25% convertible senior notes due 2016 to be $150.2 million , or 130.6% of par value, and the portion related to our 7.75% senior notes due 2022 to be $485.0 million , or 97.0% of par value. We determined these valuations based upon measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. +The carrying value of our capital lease obligations approximates fair value due to the variable nature of the imputed interest rates and the duration of the vehicle lease. +NOTE 4 - DERIVATIVE FINANCIAL INSTRUMENTS +Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas, we utilize the following economic hedging strategies for each of our business segments. +• +For crude oil and natural gas sales, we enter into derivative contracts to protect against price declines in future periods. While we structure these derivatives to reduce our exposure to changes in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price increases in the physical market; and +• +For natural gas marketing, we enter into fixed-price physical purchase and sale agreements that qualify as derivative contracts. In order to offset the fixed-price physical derivatives in our natural gas marketing, we enter into financial derivative instruments that have the effect of locking in the prices we will receive or pay for the same volumes and period, offsetting the physical derivative. +We believe our derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of December 31, 2015 , we had derivative instruments, which were comprised of collars, fixed-price swaps, basis protection swaps and physical sales and purchases, in place for a portion of our anticipated production through 2018 for a total of 77,320 BBtu of natural gas and 5,580 MBbls of crude oil. The majority of our derivative contracts are entered into at no cost to us as we hedge our anticipated production at the then-prevailing commodity market prices. +As of December 31, 2015 , our derivative instruments were comprised of commodity swaps, collars, basis protection swaps and physical sales and purchases. +• +Collars contain a fixed floor price and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty; +• +Swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty; +• +Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For CIG-basis protection swaps, which had a negative differential to NYMEX for the majority of 2015 , we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. If the market price and contract price are the same, no payment is due to or from the counterparty; and +• +Physical sales and purchases are derivatives for fixed-priced physical transactions where we sell or purchase third-party supply at fixed rates. These physical derivatives are offset by financial swaps: for a physical sale the offset is a swap purchase and for a physical purchase the offset is a swap sale. +We have elected not to designate any of our derivative instruments as hedges, and therefore do not qualify for use of hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the statements of operations. Changes in the fair value of derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Changes in the fair value of derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of natural gas marketing. +69 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the balance sheet location and fair value amounts of our derivative instruments on the consolidated balance sheets as of December 31, 2015 and 2014 : +Derivative instruments: +Balance sheet line item +2015 +2014 +(in thousands) +Derivative assets: +Current +Commodity contracts +Related to crude oil and natural gas sales +Fair value of derivatives +$ +221,161 +$ +186,886 +Related to natural gas marketing +Fair value of derivatives +441 +590 +Basis protection contracts +Related to crude oil and natural gas sales +Fair value of derivatives +57 +19 +221,659 +187,495 +Non-current +Commodity contracts +Related to crude oil and natural gas sales +Fair value of derivatives +44,292 +112,599 +Related to natural gas marketing +Fair value of derivatives +51 +220 +Basis protection contracts +Related to crude oil and natural gas sales +Fair value of derivatives +44 +— +44,387 +112,819 +Total derivative assets +$ +266,046 +$ +300,314 +Derivative liabilities: +Current +Commodity contracts +Related to natural gas marketing +Fair value of derivatives +$ +417 +$ +545 +Basis protection contracts +Related to crude oil and natural gas sales +Fair value of derivatives +1,178 +25 +1,595 +570 +Non-current +Commodity contracts +Related to crude oil and natural gas sales +Fair value of derivatives +275 +— +Related to natural gas marketing +Fair value of derivatives +46 +197 +Basis protection contracts +Related to crude oil and natural gas sales +Fair value of derivatives +374 +— +695 +197 +Total derivative liabilities +$ +2,290 +$ +767 +70 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the impact of our derivative instruments on our consolidated statements of operations: +Year Ended December 31, +Consolidated statement of operations line item +2015 +2014 +2013 +(in thousands) +Commodity price risk management gain (loss), net +Net settlements +$ +238,935 +$ +(837 +) +$ +11,177 +Net change in fair value of unsettled derivatives +(35,752 +) +311,141 +(35,096 +) +Total commodity price risk management gain (loss), net +$ +203,183 +$ +310,304 +$ +(23,919 +) +Sales from natural gas marketing +Net settlements +$ +778 +$ +(208 +) +$ +446 +Net change in fair value of unsettled derivatives +(318 +) +364 +429 +Total sales from natural gas marketing +$ +460 +$ +156 +$ +875 +Cost of natural gas marketing +Net settlements +$ +(745 +) +$ +346 +$ +(257 +) +Net change in fair value of unsettled derivatives +279 +(451 +) +(412 +) +Total cost of natural gas marketing +$ +(466 +) +$ +(105 +) +$ +(669 +) +All of our financial derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. Our fixed-price physical purchase and sale agreements that qualify as derivative contracts are not subject to master netting provisions and are not significant. We have elected not to offset the fair value positions recorded on our consolidated balance sheets. +The following table reflects the impact of netting agreements on gross derivative assets and liabilities: +As of December 31, 2015 +Derivative instruments, recorded in consolidated balance sheet, gross +Effect of master netting agreements +Derivative instruments, net +(in thousands) +Asset derivatives: +Derivative instruments, at fair value +$ +266,046 +$ +(1,921 +) +$ +264,125 +Liability derivatives: +Derivative instruments, at fair value +$ +2,290 +$ +(1,921 +) +$ +369 +As of December 31, 2014 +Derivative instruments, recorded in consolidated balance sheet, gross +Effect of master netting agreements +Derivative instruments, net +(in thousands) +Asset derivatives: +Derivative instruments, at fair value +$ +300,314 +$ +(29 +) +$ +300,285 +Liability derivatives: +Derivative instruments, at fair value +$ +767 +$ +(29 +) +$ +738 +71 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 5 - CONCENTRATION OF RISK +Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts: +As of December 31, +2015 +2014 +(in thousands) +Crude oil, natural gas and NGLs sales +$ +41,873 +$ +49,531 +Joint interest billings +35,017 +52,841 +Derivative counterparties +24,437 +12,582 +Insurance reimbursement +879 +11,212 +Other +4,077 +5,524 +Allowance for doubtful accounts +(2,009 +) +(486 +) +Accounts receivable, net +$ +104,274 +$ +131,204 +Our accounts receivable primarily relate to sales of our crude oil, natural gas and NGLs production, other third parties that own working interests in the properties we operate and derivative counterparties. For the years ended December 31, 2015 , 2014 and 2013 , amounts written off to allowance for doubtful accounts were not material. As of December 31, 2015 , we had one customer representing 10% or greater of our accounts receivable balance. Concord Energy represents 11.3% of our December 31, 2015 accounts receivable balance. As of December 31, 2014 , we had two customers representing 10% or greater of our accounts receivable balance. Suncor Energy Marketing, Inc. and Concord Energy represented 11.1% and 10.3% , respectively. +Major Customers. The following table presents the individual customers constituting 10% or more of total revenues: +Year Ended December 31, +Customer +2015 +2014 +2013 +Concord Energy +23.2 +% +18.3 +% +— +% +Suncor Energy Marketing, Inc. +14.3 +% +19.7 +% +35.9 +% +Shell Trading Company +13.8 +% +— +% +— +% +DCP Midstream, LP +13.2 +% +15.1 +% +13.9 +% +Teppco Crude Oil, LLC +— +% +12.9 +% +8.0 +% +The concentration of revenue represented by the customers noted above relate to our oil and gas exploration and production segment. +Derivative Counterparties. A significant portion of our liquidity is concentrated in derivative instruments that enable us to manage a portion of our exposure to price volatility from producing crude oil and natural gas. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also major lenders under our revolving credit facility as counterparties to our derivative contracts. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our current counterparties on the fair value of our derivative instruments is not significant at December 31, 2015 , taking into account the estimated likelihood of nonperformance. +72 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the counterparties that expose us to credit risk as of December 31, 2015 , with regard to our derivative assets: +Fair Value of +Derivative Assets +Counterparty Name +As of December 31, 2015 +(in thousands) +Canadian Imperial Bank of Commerce (1) +$ +78,102 +JP Morgan Chase Bank, N.A (1) +71,012 +Bank of Nova Scotia (1) +49,758 +Wells Fargo Bank, N.A. (1) +32,474 +NATIXIS (1) +29,754 +Other lenders in our revolving credit facility +4,856 +Other (2) +90 +Total +$ +266,046 +____________ +(1) Major lender in our revolving credit facility. See Note 8, Long-Term Debt. +(2) Represents one counterparty. +Note Receivable +The following table presents information regarding our note receivable outstanding as of December 31, 2015 : +Amount +(in thousands) +Note receivable: +Principal outstanding, December 31, 2014 +$ +39,707 +Paid-in-kind interest +3,362 +Principal outstanding, December 31, 2015 +$ +43,069 +In October 2014, we sold our entire 50% ownership interest in PDCM to an unrelated third-party. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations , for additional information regarding the sale. As part of the consideration, we received a promissory note (the “Note”) for a principal sum of $39.0 million , bearing varying interest rates beginning at 8% and increasing annually. Pursuant to the Note agreement, interest shall be paid quarterly, in arrears, commencing December 2014 and continuing on the last business day of each fiscal quarter thereafter. At the option of the issuer of the Note, an unrelated third-party, interest can be paid-in-kind (the “PIK Interest”) and any such PIK Interest will be added to the outstanding principal amount of the Note. As of December 31, 2015 , the issuer of the Note had elected the PIK Interest option for each quarterly period since inception. The principal and any unpaid interest shall be due and payable in full in September 2020 and can be prepaid in whole or in part at any time, and in certain circumstances must be repaid prior to maturity. Any such prepayment will be made without premium or penalty. The Note is secured by a pledge of stock in certain subsidiaries of the unrelated third-party, debt securities and other assets. +Under the effective interest method, we recognized $4.5 million and $0.9 million of interest income for the years ended December 31, 2015 and 2014 , respectively, of which $3.4 million and $0.7 million , respectively, was PIK Interest. As of December 31, 2015 and 2014, the $43.1 million and $39.7 million , respectively, outstanding balance on the Note was included in the consolidated balance sheet line item other assets. +73 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 6 - PROPERTIES AND EQUIPMENT +The following table presents the components of properties and equipment, net of accumulated DD&A: +As of December 31, +2015 +2014 +(in thousands) +Properties and equipment, net: +Crude oil and natural gas properties +Proved +$ +2,881,189 +$ +2,267,165 +Unproved +60,498 +188,206 +Total crude oil and natural gas properties +2,941,687 +2,455,371 +Equipment and other +30,098 +29,562 +Land and buildings +9,015 +9,015 +Construction in progress +113,115 +165,205 +Properties and equipment, at cost +3,093,915 +2,659,153 +Accumulated DD&A +(1,156,237 +) +(831,699 +) +Properties and equipment, net +$ +1,937,678 +$ +1,827,454 +The following table presents impairment charges recorded for crude oil and natural gas properties: +Year Ended December 31, +2015 +2014 +2013 +(in thousands) +Continuing operations: +Impairment of proved and unproved properties +$ +154,608 +$ +161,604 +$ +49,631 +Amortization of individually insignificant unproved properties +7,012 +4,465 +3,242 +Other +— +778 +— +Total continuing operations +161,620 +166,847 +52,873 +Discontinued operations: +Impairment of proved and unproved properties +— +433 +566 +Amortization of individually insignificant unproved properties +— +— +363 +Total discontinued operations +— +433 +929 +Total impairment of crude oil and natural gas properties +$ +161,620 +$ +167,280 +$ +53,802 +In 2015, due to a significant decline in commodity prices and a decrease in net-back realizations, we experienced a triggering event that required us to assess our crude oil and natural gas properties for possible impairment. As a result of our assessment, we recorded an impairment charge of $150.3 million to write-down our Utica Shale proved and unproved properties. Of this impairment charge, $24.7 million was recorded to write-down certain capitalized well costs on our Utica Shale proved producing properties. This impairment charge represented the amount by which the carrying value of these crude oil and natural gas properties exceeded the estimated fair value. The estimated fair value of approximately $27.9 million , excluding estimated salvage value, was determined based on estimated future discounted net cash flows, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. Additionally, as a result of the current outlook for future commodity prices, we recorded an impairment charge of $125.6 million to write-down all of our Utica Shale lease acquisition costs and pad development costs for pads not in production. These impairment charges were included in the consolidated statements of operations line item impairment of crude oil and natural gas properties. +In 2014, we recognized an impairment charge of $158.3 million to write-down our Utica Shale producing and non-producing crude oil and natural gas properties to their estimated fair value, $112.6 million of which was for capitalized well costs on proved producing properties and $45.7 million for capitalized leasehold costs on unproved properties. The impairment charge represented the amount by which the carrying value of the Utica Shale crude oil and natural gas properties exceeded the estimated fair value and was therefore not recoverable. The estimated fair value was determined based on estimated future discounted net cash flows, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. The impairment charge was included in the consolidated statements of operations line item impairment of crude oil and natural gas properties. +In 2013, we recognized an impairment charge of approximately $48.8 million related to all of our shallow Upper Devonian (non-Marcellus Shale) Appalachian Basin producing properties located in West Virginia and Pennsylvania previously owned directly by us, as well as through our proportionate share of PDCM. The impairment charge represented the excess of the carrying value of the assets over the estimated fair value, less the cost to sell. The fair value of the assets was determined based upon estimated future cash flows from unrelated third-party +74 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +bids, a Level 3 input. The impairment charge was included in the consolidated statements of operations line item impairment of crude oil and natural gas properties. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding these properties. +Suspended Well Costs +As of December 31, 2015 and 2014 , there were no suspended well costs or wells pending determination. +NOTE 7 - INCOME TAXES +The table below presents the components of our provision for income taxes from continuing operations for the years presented: +Year Ended December 31, +2015 +2014 +2013 +(in thousands) +Current: +Federal +$ +(2,944 +) +$ +(1,514 +) +$ +1,355 +State +(163 +) +966 +199 +Total current income taxes +(3,107 +) +(548 +) +1,554 +Deferred: +Federal +37,352 +(60,698 +) +8,238 +State +4,063 +(8,721 +) +2,060 +Total deferred income taxes +41,415 +(69,419 +) +10,298 +Income tax benefit (expense) from continuing operations +$ +38,308 +$ +(69,967 +) +$ +11,852 +In the last three years, we continued to utilize tax deferral strategies such as bonus depreciation, accelerated depreciation and intangible drilling cost ("IDC") expense elections or accelerated IDC amortization to minimize our current taxes. In 2013 these deferral strategies enabled us to offset any taxable gain on the sale of our non-core Colorado assets and also preserved some of our NOLs to carry forward for use against our anticipated 2014 taxable income. In 2014, these same deferral strategies, along with carried forward federal and state NOLs, credits, and suspended deductions, permitted us to offset the majority of the tax gain on the sale of PDCM. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, for additional information regarding the sale of our non-core Colorado assets and the sale of our entire 50% ownership interest in PDCM. In 2015, these continued deferral strategies offset the tax adjustments for impairments to crude oil and natural gas properties and negative net change in fair value of unsettled derivatives to enable our current income taxes to be minimized. +The following table presents a reconciliation of the statutory rate to the effective tax rate related to our provision for income taxes from continuing operations: +Year Ended December, 31, +2015 +2014 +2013 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income tax, net +2.4 +2.8 +4.0 +Percentage depletion +0.3 +(0.3 +) +2.2 +Non-deductible compensation +(1.2 +) +0.7 +(4.2 +) +Other +(0.6 +) +1.3 +(1.0 +) +Effective tax rate +35.9 +% +39.5 +% +36.0 +% +75 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2015 and 2014 are presented below: +As of December 31, +2015 +2014 +(in thousands) +Deferred tax assets: +Deferred compensation +$ +13,104 +$ +10,459 +Asset retirement obligations +34,101 +28,051 +State NOL and tax credit carryforwards, net +3,376 +3,761 +Alternative minimum tax - credit carryforward +2,812 +2,906 +Settlement of class action litigation +— +12,259 +Other +3,412 +3,144 +Deferred tax assets +56,805 +60,580 +Deferred tax liabilities: +Properties and equipment +99,191 +130,155 +Net change in fair value of unsettled derivatives +100,369 +113,007 +Convertible debt +697 +2,285 +Total gross deferred tax liabilities +200,257 +245,447 +Net deferred tax liability +$ +143,452 +$ +184,867 +Deferred tax assets decreased in 2015, primarily due to the reclassification of the deferred tax asset associated with the settlement of certain partnership-related class action litigation to properties and equipment. The cost of the settlement of this litigation has been capitalized to the value of crude oil and natural gas properties for income tax purposes. +Deferred tax liabilities for properties and equipment decreased as a result of the increase in the deferred tax asset for the impairment of some of our crude oil and natural gas properties and the reclassification of the deferred asset for litigation settlement. Both of these deferred tax assets relate to the tax basis of our crude oil and natural gas properties and are therefore netted against the deferred tax liability. This decrease from impairments and litigation settlement was partially offset by our continued use of statutory provisions for expensing and accelerated amortization of IDCs and accelerated tax depreciation. In addition, the fair value of unsettled derivatives at December 31, 2015 decreased and resulted in a decrease to our unrealized tax gain versus a larger unrealized tax gain at December 31, 2014. +As of December 31, 2015 , we have state NOL carryforwards of $74.3 million that begin to expire in 2030 and state credit carryforwards of $1.6 million that begin to expire in 2022 . +Unrecognized tax benefits and related accrued interest and penalties were immaterial for the three-year period ended December 31, 2015 . The total amount of unrecognized tax benefits that would affect the effective tax rate increased to $0.1 million in the current year due to interest recorded on a tax filing position related to our 2014 federal tax return which the IRS is in disagreement with at December 31, 2015. The statute of limitations for most of our state tax jurisdictions is open from 2011 forward. +In accordance with the CAP program, the IRS completed its “post filing review” of our 2013 tax return in January 2015 and issued a “no change” letter for the reviewed tax year. The IRS has not completed its “post filing review” of our 2014 return as one “un-agreed issue” remained at December 31, 2015. The CAP audit employs a real-time review of our books and tax records by the IRS that is intended to permit issue resolution prior to, or shortly after, the filing of the tax returns. We are currently participating in the CAP program for the review of our 2014 and 2015 tax years and we have been invited and have accepted continued participation in the program for our 2016 tax year. Participation in the CAP program has enabled us to have minimal uncertain tax benefits associated with our federal tax return filings. +As of December 31, 2015 , we were current with our income tax filings in all applicable state jurisdictions. In 2013, the State of Colorado examined our 2008 through 2011 Colorado corporate income tax returns and proposed no adjustments. +76 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 8 - LONG-TERM DEBT +Long-term debt consists of the following: +As of December 31, +2015 +2014 +(in thousands) +Senior notes: +3.25% Convertible senior notes due 2016: +Principal amount +$ +115,000 +$ +115,000 +Unamortized discount +(1,852 +) +(6,077 +) +Unamortized debt issuance costs +(208 +) +(765 +) +3.25% Convertible senior notes due 2016, net of discount and unamortized debt issuance costs +112,940 +108,158 +7.75% Senior notes due 2022: +Principal amount +500,000 +500,000 +Unamortized debt issuance costs +(7,563 +) +(8,683 +) +7.75% Senior notes due 2022, net of unamortized debt issuance costs +492,437 +491,317 +Total senior notes +605,377 +599,475 +Revolving credit facility +37,000 +56,000 +Total debt, net of discount and unamortized debt issuance costs +642,377 +655,475 +Less current portion of long-term debt +112,940 +— +Long-term debt +$ +529,437 +$ +655,475 +Senior Notes +3.25% Convertible Senior Notes Due 2016. In November 2010 , we issued $115 million aggregate principal amount 3.25% convertible senior notes due 2016 (the "Convertible Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is May 15, 2016 . Interest is payable semi-annually in arrears on each May 15 and November 15 . The Convertible Notes are senior, unsecured obligations and rank senior in right of payment to our existing and future indebtedness that is expressly subordinated in right of payment to the Convertible Notes; equal in right of payment to our existing and future unsecured indebtedness that is not expressly subordinated (including our 2022 Senior Notes); effectively junior in right of payment to any of our secured indebtedness (including our obligations under our revolving credit facility) to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our subsidiaries. The indenture governing the Convertible Notes contains certain non-financial covenants. The Convertible Notes and the common stock issuable upon conversion of the Convertible Notes, if any, have not been registered under the Securities Act of 1933 or any state securities laws, nor are we required to register such Convertible Notes or common shares. The Convertible Notes are governed by an indenture between the Company and the Bank of New York Mellon, as trustee. +Beginning in November 15, 2015 , holders of the Convertible Notes may convert the notes at an initial conversion rate of 23.5849 shares per $1,000 principal amount, which is equal to a conversion price of approximately $42.40 per share. The conversion rate is subject to adjustment upon certain events. Upon conversion, we have elected to settle the principal amount of the Convertible Notes in cash and settle the excess conversion value in shares, as well as cash in lieu of fractional shares, in May 2016. +We allocated the gross proceeds of the Convertible Notes between the liability and equity components of the debt. The initial $94.3 million liability component was determined based on the fair value of similar debt instruments with similar terms, excluding the conversion feature, and priced on the same day we issued the Convertible Notes. The initial $20.7 million equity component represents the debt discount and was calculated as the difference between the liability component of the debt and the gross proceeds of the Convertible Notes. As of December 31, 2015 , the unamortized debt discount will be amortized over the remaining contractual term to maturity of the Convertible Notes of 0.4 years using an effective interest rate of 7.4% . For 2015 , interest expense related to the indebtedness and the amortization of the discount was $3.7 million and $4.2 million , respectively, compared to $3.7 million and $3.9 million , respectively, in 2014 and $3.7 million each in 2013 . As of December 31, 2015 , the principal amount exceeded the “if-converted” value of the Convertible Notes by approximately $29.8 million . +7.75% Senior Notes Due 2022. In October 2012 , we issued $500 million aggregate principal amount 7.75% senior notes due October 15, 2022 (the "2022 Senior Notes") in a private placement to qualified institutional buyers. The 2022 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually in arrears on April 15 and October 15 . Approximately $11 million in costs associated with the issuance of the 2022 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. The 2022 Senior Notes are senior unsecured obligations and rank senior in right of payment to any of our future indebtedness that is expressly subordinated to the notes. The 2022 Senior Notes rank equally in right of payment with all our existing +77 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +and future senior indebtedness (including our Convertible Notes) and rank effectively junior in right of payment to all of our secured indebtedness (to the extent of the value of the collateral securing such indebtedness), including borrowings under our revolving credit facility. +In connection with the issuance of the 2022 Senior Notes, we entered into a registration rights agreement with the initial purchasers in which we agreed to file a registration statement with the SEC related to an offer to exchange the notes for substantially identical registered notes and to use commercially reasonable efforts to cause the exchange offer to be completed on or prior to September 28, 2013. The registration statement was declared effective by the SEC in July 2013 and the exchange offer was completed in August 2013. +At any time prior to October 15, 2017 , we may redeem all or part of the 2022 Senior Notes at a make-whole price set forth in the indenture, and on or after October 15, 2017 , we may redeem the notes at fixed redemption prices, plus accrued and unpaid interest, if any, to the date of redemption. +Upon the occurrence of a "change of control" as defined in the indenture for the 2022 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101% of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we will be required to use the net cash proceeds of the asset sale to make an offer to purchase the notes at 100% of the principal amount, together with any accrued and unpaid interest to the date of purchase. +The indenture governing the 2022 Senior Notes contains covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make certain investments; create certain liens; restrict dividends or other payments by restricted subsidiaries; enter into transactions with affiliates; sell assets; and merge or consolidate with another company. +As of December 31, 2015 , we were in compliance with all covenants related to the Convertible Notes and the 2022 Senior Notes, and expect to remain in compliance throughout the next 12-month period. +Credit Facility +Revolving Credit Facility . In September 2015 , we entered into a Second Amendment to Third Amended and Restated Credit Agreement with JPMorgan Chase Bank, N.A. as administrative agent and other lenders party thereto. This agreement amends and restates the credit agreement dated November 2010 and extends the maturity of the revolving credit facility to May 2020 . The revolving credit facility is available for working capital requirements, capital expenditures, acquisitions, general corporate purposes and to support letters of credit. The revolving credit facility provides for a maximum of $1 billion in allowable borrowing capacity, subject to the borrowing base. In September 2015, we completed the semi-annual redetermination of our revolving credit facility, which resulted in the reaffirmation of our borrowing base at $700 million ; however, we have elected to maintain the aggregate commitment at $450 million . The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests, excluding proved reserves attributable to our affiliated partnerships. The borrowing base is subject to a semi-annual size redetermination based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. The revolving credit facility is secured by a pledge of the stock of certain of our subsidiaries, mortgages of certain producing crude oil and natural gas properties and substantially all of our and such subsidiaries' other assets. Our affiliated partnerships are not guarantors of our obligations under the revolving credit facility. We had an outstanding balance of $37.0 million on our revolving credit facility as of December 31, 2015 compared to $56.0 million outstanding as of December 31, 2014 . The weighted-average borrowing rate on our revolving credit facility, exclusive of fees on the unused commitment and the letter of credit noted below, was 2.6% and 3.8% per annum as of December 31, 2015 and 2014 , respectively. +The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greater of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus a premium and 1-month LIBOR plus a premium), or at our election, a rate equal to the rate for dollar deposits in the London interbank market for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. No principal payments are required until the credit agreement expires in May 2020 , or in the event that the borrowing base falls below the outstanding balance. +The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.00 to 1.00 and (b) not exceed a maximum leverage ratio of 4.25 to 1.00. As of December 31, 2015 , we were in compliance with all the revolving credit facility covenants and expect to remain in compliance throughout the next 12-month period. +The revolving credit facility contains restrictions as to when we can directly or indirectly, retire, redeem, repurchase or prepay in cash any part of the principal of the 2022 Senior Notes or the Convertible Notes. Among other things, the restriction on redemption of the Convertible Notes requires that immediately after giving effect to any such retirement, redemption, defeasance, repurchase, settlement or prepayment, the aggregate commitment under the revolving credit facility must exceed the aggregate credit exposure under such facility by at least the greater of $115 million or an amount equal to or greater than 30% of such aggregate commitment. The restriction on redemption of the 2022 Senior Notes permits redemption only with the proceeds of issuances of "Permitted Refinancing Indebtedness," which may not exceed $750 million. +As of December 31, 2015 , RNG had an irrevocable standby letter of credit of approximately $11.7 million in favor of a third-party transportation service provider to secure firm transportation of the natural gas produced by third-party producers for whom we market production +78 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +in the Appalachian Basin. The letter of credit currently expires in September 2016 and is automatically extended annually in accordance with the letter of credit's terms and conditions. The letter of credit reduces the amount of available funds under our revolving credit facility by an amount equal to the letter of credit. As of December 31, 2015 , the available funds under our revolving credit facility, including the reduction for the $11.7 million letter of credit, was $401.3 million . In addition to our currently elected commitment of $450 million , we have an additional $250 million of borrowing base availability under the revolving credit facility, subject to certain terms and conditions of the agreement. +NOTE 9 - CAPITAL LEASES +Beginning in the first quarter of 2015, we entered into non-cancelable lease agreements for vehicles utilized by our operations and field personnel. Each lease agreement has a term of three years and is being accounted for as a capital lease, as the present value of minimum monthly lease payments, including the residual value guarantee, exceeds 90% of the fair value of the leased vehicles at inception of the lease. +The following table presents leased vehicles under capital leases as of December 31, 2015 : +Amount +(in thousands) +Vehicles +$ +1,601 +Accumulated depreciation +(211 +) +$ +1,390 +Future minimum lease payments by year and in the aggregate, under non-cancelable capital leases with terms of one year or more, consist of the following: +For the Twelve Months Ending December 31, +Amount +(in thousands) +2016 +$ +492 +2017 +492 +2018 +681 +1,665 +Less executory cost +(70 +) +Less amount representing interest +(202 +) +Present value of minimum lease payments +$ +1,393 +Short-term capital lease obligations +$ +357 +Long-term capital lease obligations +1,036 +$ +1,393 +Short-term capital lease obligations are included in other accrued expenses on the consolidated balance sheets. Long-term capital lease obligations are included in other liabilities on the consolidated balance sheets. +79 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 10 - ASSET RETIREMENT OBLIGATIONS +The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interest in crude oil and natural gas properties: +2015 +2014 +(in thousands) +Balance at beginning of period, January 1, 2015 +$ +73,855 +$ +41,030 +Revisions in estimated cash flows +11,658 +31,945 +Obligations incurred with development activities +2,373 +1,170 +Accretion expense +6,293 +3,455 +Obligations discharged with asset retirements +(4,687 +) +(3,745 +) +Balance end of period, December 31, 2015 +89,492 +73,855 +Less current portion +(5,460 +) +(1,863 +) +Long-term portion +$ +84,032 +$ +71,992 +Our estimated asset retirement obligation liability is based on historical experience in plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment cost and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. In 2015, the credit-adjusted risk-free rates used to discount our plugging and abandonment liabilities ranged from 7.6% to 8.0%. In periods subsequent to initial measurement of the liability, we must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or changes in inflation factors and changes to our credit-adjusted risk-free rate as market conditions warrant. +The revisions in estimated cash flows during 2015 were due to changes in estimates of costs for materials and services related to the plugging and abandonment of certain vertical wells in the Wattenberg Field, as well as a decrease in the estimated useful life of these wells. The increase in the current portion of asset retirement obligations in 2015 is attributable to a decrease in the estimated useful life of certain vertical wells in the Wattenberg Field and an increase in the number of wells to be plugged and abandoned to allow for the drilling of nearby horizontal wells. +The revisions in estimated cash flows during 2014 were due to changes in estimates of costs for materials and services related to the plugging and abandonment of certain vertical wells in the Wattenberg Field, as well as a decrease in the estimated useful life of these wells. The increase in estimated costs is primarily the result of various recent federal, state and local laws that regulate plugging operations and techniques. The revision in the asset retirement obligation did not have an immediate effect in the 2014 statement of operations as the increase in the revised obligation was offset by a capitalized amount, which will be depreciated over the useful lives of respective wells. +NOTE 11 - EMPLOYEE BENEFIT PLANS +We sponsor a qualified retirement plan covering substantially all of our employees. The plan consists of both a traditional and a Roth 401(k) component, as well as a profit sharing component. The 401(k) components enable eligible employees to contribute a portion of their compensation through payroll deductions in accordance with specific guidelines. We provide a discretionary matching contribution based on a percentage of the employees' contributions up to certain limits. Our contribution to the profit sharing component is discretionary. Our total combined expense for the plan was $4.9 million , $3.9 million and $3.7 million for 2015 , 2014 and 2013 , respectively. +We provide a supplemental retirement benefit of deferred compensation under terms of the various employment agreements with certain former executive officers. Expenses related to this plan are charged to general and administrative expenses and the related costs were immaterial in 2015 , 2014 and 2013 . As of December 31, 2015 and 2014 , the liability related to this benefit was $1.3 million and $1.5 million , respectively, which was included in other liabilities on the consolidated balance sheets, with the exception of $0.3 million included in other accrued expenses as of December 31, 2015 and 2014 . +We provide a supplemental health care benefit covering certain former executive officers and their spouses in accordance with each officer's employment agreement. Expenses incurred during 2015 , 2014 and 2013 related to this plan were immaterial. As of December 31, 2015 and 2014 , the related liability of $0.8 million and $0.7 million , respectively, is included in other liabilities on the consolidated balance sheets. +We maintain a non-qualified deferred compensation plan for our non-employee directors. The amount of compensation deferred by each participant is based on participant elections. The amounts deferred pursuant to the plan are invested in our common stock, maintained in a rabbi trust and are classified in the consolidated balance sheets as treasury shares as a component of shareholders' equity. The plan may be settled in either cash or shares as requested by the participant. The liability related to this plan, which was included in other liabilities on the consolidated balance sheets, was $0.6 million and $0.3 million as of December 31, 2015 and 2014 , respectively. +80 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 12 - COMMITMENTS AND CONTINGENCIES +Firm Transportation, Processing and Sales Agreements. We enter into contracts that provide firm transportation, sales and processing agreements on pipeline systems through which we transport or sell crude oil and natural gas. Satisfaction of the volume requirements includes volumes produced by us, purchased from third parties and produced by our affiliated partnerships and other third-party working interest owners. We record in our financial statements only our share of costs based upon our working interest in the wells. These contracts require us to pay these transportation and processing charges, whether or not the required volumes are delivered. As natural gas prices continue to remain depressed, certain third-party producers under our Gas Marketing segment have begun and may continue to experience financial distress, which has led to certain contractual defaults and litigation; however, to date, we have had no material counterparty default losses. In 2015, we recorded an allowance for doubtful accounts of approximately $0.5 million . We have initiated several legal actions for collection against some of the third-party producers, which have resulted in no collections and some of the third-party producers shutting-in wells. +The following table presents gross volume information related to our long-term firm transportation, sales and processing agreements for pipeline capacity: +Year Ending December 31, +Area +2016 +2017 +2018 +2019 +2020 and +Through +Expiration +Total +Expiration +Date +Natural gas (MMcf) +Gas Marketing segment +7,136 +7,117 +7,117 +7,117 +18,687 +47,174 +August 31, 2022 +Utica Shale +2,745 +2,737 +2,737 +2,737 +9,811 +20,767 +July 22, 2023 +Total +9,881 +9,854 +9,854 +9,854 +28,498 +67,941 +Crude oil (MBbls) +Wattenberg Field +2,420 +2,413 +2,413 +2,413 +1,205 +10,864 +June 30, 2020 +Dollar commitment (in thousands) +$ +17,622 +$ +17,156 +$ +16,324 +$ +16,324 +$ +17,193 +$ +84,619 +Litigation. The Company is involved in various legal proceedings that it considers normal to its business. The Company reviews the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in the best interests of the Company. There is no assurance that settlements can be reached on acceptable terms or that adverse judgments, if any, in the remaining litigation will not exceed the amounts reserved. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity. +Class Action Regarding 2010 and 2011 Partnership Purchases +In December 2011, the Company and its wholly-owned merger subsidiary were served with an alleged class action on behalf of unit holders of 12 former limited partnerships, related to its repurchase of the 12 partnerships, which were formed beginning in late 2002 through 2005. The mergers were completed in 2010 and 2011. The action was filed in U.S. District Court for the Central District of California and was titled Schulein v. Petroleum Development Corp . The complaint primarily alleged that the disclosures in the proxy statements issued in connection with the mergers were inadequate, and a state law breach of fiduciary duty. In January 2014, the plaintiffs were certified as a class by the court. +In October 2014, the Company and plaintiffs’ counsel reached a settlement agreement in principal, which was signed in December 2014 and was given final court approval in March 2015. Under this settlement agreement, the plaintiffs received a cash payment of $37.5 million in January 2015, of which the Company paid $31.5 million and insurers paid $6 million . In March 2015, the class action was dismissed with prejudice and all class claims were released. As of December 31, 2014, the Company accrued a liability of $37.5 million related to this litigation, which was included in other accrued expenses in the consolidated balance sheet. +Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. As of December 31, 2015 and 2014 , we had accrued environmental liabilities in the amount of $4.1 million and $0.8 million , respectively, included in other accrued expenses on the consolidated balance sheets. We are not aware of any environmental claims existing as of December 31, 2015 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown past non-compliance with environmental laws will not be discovered on our properties. +In August 2015, we received a Clean Air Act Section 114 Information Request (the "Information Request") from the United States Environmental Protection Agency ("EPA"). The Information Request seeks, among other things, information related to the design, operation, +81 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +and maintenance of our production facilities in the Denver-Julesburg Basin of Colorado. The Information Request focuses primarily on 46 of our production facilities and asks that we conduct certain sampling and analyses at the identified 46 facilities. We responded to the Information Request in January 2016. We cannot predict the outcome of this matter at this time. +In addition, in December 2015, we received a Compliance Advisory pursuant to C.R.S. § 25-7-115(2) from the Colorado Department of Public Health and Environment's Air Quality Control Commission's Air Pollution Control Division alleging that we failed to design, operate, and maintain certain condensate collection, storage, processing and handling operations to minimize leakage of volatile organic compounds at 65 facilities consistent with applicable standards under Colorado law. We are in the process of responding to the advisory, but cannot predict the outcome of this matter at this time. +In 2014, we experienced a loss of well control while drilling an oil and gas well in Morgan County, Ohio. The event resulted in a release of well fluids, including oil based drilling mud. We have completed the appropriate remediation to address the release. In August 2015, the EPA issued us a Notice of Intent seeking civil penalties. We and the EPA settled this matter for a civil fine of approximately $152,000 . +Lease Agreements. We entered into operating leases, principally for the leasing of natural gas compressors, office space and general office equipment. +The following table presents the minimum future lease payments under the non-cancelable operating leases as of December 31, 2015 : +Year Ending December 31, +2016 +2017 +2018 +2019 +2020 +Thereafter +Total +(in thousands) +Minimum Lease Payments +$ +2,353 +$ +2,166 +$ +1,975 +$ +1,937 +$ +1,967 +$ +124 +$ +10,522 +Operating lease expense for the years ended 2015 , 2014 and 2013 was $9.8 million , $7.0 million and $7.0 million , respectively. +Employment Agreements with Executive Officers . Each of our senior executive officers may be entitled to a severance payment and certain other benefits upon the termination of the officer's employment pursuant to the officer's employment agreement and/or the Company's executive severance compensation plan. The nature and amount of such benefits would vary based upon, among other things, whether the termination followed a change of control of the Company. +NOTE 13 - COMMON STOCK +Sale of Equity Securities +In March 2015, we completed a public offering of 4,002,000 shares of our common stock, par value $0.01 per share, at a price to us of $50.73 per share. Net proceeds of the offering were $202.9 million , after deducting offering expenses and underwriting discounts, of which $40,020 is included in common shares-par value and $202.8 million is included in additional paid-in capital ("APIC") on the December 31, 2015 consolidated balance sheet. The shares were issued pursuant to an effective shelf registration statement on Form S-3 filed with the SEC in March 2015. +In August 2013 , we completed a public offering of 5,175,000 shares of our common stock, par value $0.01 per share, at a price to us of $53.37 per share. Net proceeds of the offering were approximately $275.8 million , after deducting offering expenses and underwriting discounts, of which $51,750 is included in common shares-par value and approximately $275.8 million is included in APIC on the consolidated balance sheets. The shares were issued pursuant to an effective shelf registration statement on Form S-3 filed with the SEC in January 2012. +Stock-Based Compensation Plans +2010 Long-Term Equity Compensation Plan . In June 2010 , our shareholders approved a long-term equity compensation plan for our employees and non-employee directors (the "2010 Plan"). The plan was amended in June 2013. In accordance with the 2010 Plan, up to 3,000,000 new shares of our common stock are authorized for issuance. Shares issued may be either authorized but unissued shares, treasury shares or any combination of these shares. Additionally, the 2010 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited or, in the case of stock appreciation rights ("SARs"), paid out in the form of cash. Awards may be issued to our employees in the form of incentive or non-qualified stock options, SARs, restricted stock, restricted stock units ("RSUs"), performance shares and performance units, and to our non-employee directors in the form of non-qualified stock options, SARs, restricted stock and RSUs. Awards may vest over periods set at the discretion of the Compensation Committee of our Board of Directors (the "Compensation Committee") with certain minimum vesting periods. With regard to incentive or non-qualified stock options and SARs, awards have a maximum exercisable period of ten years. In no event may an award be granted under the 2010 Plan on or after April 1, 2020. As of December 31, 2015 , 1,101,831 shares remain available for issuance pursuant to the 2010 Plan. +82 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented: +Year Ended December 31, +2015 +2014 +2013 +(in thousands) +Stock-based compensation expense +$ +20,068 +$ +17,518 +$ +12,880 +Income tax benefit +(7,636 +) +(5,955 +) +(4,697 +) +Net stock-based compensation expense +$ +12,432 +$ +11,563 +$ +8,183 +Stock Appreciation Rights ("SARs") +The SARs vest ratably over a three-year period and may be exercised at any point after vesting through ten years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance. +In January 2015 , the Compensation Committee awarded 68,274 SARs to our executive officers. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions: +Year Ended December 31, +2015 +2014 +2013 +Expected term of award +5.2 years +6 years +6 years +Risk-free interest rate +1.4 +% +2.1 +% +1.0 +% +Expected volatility +58.0 +% +65.6 +% +65.5 +% +Weighted-average grant date fair value per share +$ +22.23 +$ +29.96 +$ +21.96 +The expected term of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. We do not expect to pay or declare dividends in the foreseeable future. +The following table presents the changes in our SARs for all periods presented: +Year Ended December 31, +2015 +2014 +2013 +Number of +SARs +Weighted-Average +Exercise +Price +Average Remaining Contractual +Term (in years) +Aggregate Intrinsic +Value (in thousands) +Number of +SARs +Weighted-Average +Exercise +Price +Aggregate Intrinsic +Value (in thousands) +Number of +SARs +Weighted-Average +Exercise +Price +Aggregate Intrinsic +Value (in thousands) +Outstanding beginning of year, January 1, +279,011 +$ +38.77 +7.8 +$ +1,472 +190,763 +$ +33.77 +$ +3,711 +118,832 +$ +30.80 +$ +486 +Awarded +68,274 +39.63 +— +— +88,248 +49.57 +— +87,078 +37.18 +— +Exercised +(20,832 +) +38.05 +— +473 +— +— +— +(15,147 +) +30.06 +425 +Outstanding at December 31, +326,453 +38.99 +7.3 +4,697 +279,011 +38.77 +1,472 +190,763 +33.77 +3,711 +Exercisable at December 31, +222,489 +37.70 +6.8 +3,489 +139,334 +36.27 +982 +51,922 +29.97 +1,207 +Total compensation cost related to SARs granted, net of estimated forfeitures, and not yet recognized in our consolidated statements of operations as of December 31, 2015 , was $1.7 million . The cost is expected to be recognized over a weighted-average period of 1.4 years. +Restricted Stock Awards +Time-Based Awards. The fair value of the time-based restricted shares is amortized ratably over the requisite service period, primarily three years. The time-based shares generally vest ratably on each anniversary following the grant date that a participant is continuously employed. +In January 2015 , the Compensation Committee awarded to our executive officers a total of 80,707 time-based restricted shares that vest ratably over a three -year period ending on January 16, 2018. +83 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the changes in non-vested time-based awards during 2015 : +Shares +Weighted-Average +Grant-Date +Fair Value +Non-vested at December 31, 2014 +564,332 +$ +46.02 +Granted +313,639 +48.88 +Vested +(333,167 +) +41.59 +Forfeited +(19,723 +) +54.29 +Non-vested at December 31, 2015 +525,081 +50.23 +The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: +As of/Year Ended December 31, +2015 +2014 +2013 +(in thousands, except per share data) +Total intrinsic value of time-based awards vested +$ +17,077 +$ +18,278 +$ +13,640 +Total intrinsic value of time-based awards non-vested +28,029 +23,290 +34,688 +Market price per common share as of December 31, +53.38 +41.27 +53.22 +Weighted-average grant date fair value per share +48.88 +56.45 +45.53 +Total compensation cost related to non-vested time-based awards, net of estimated forfeitures, and not yet recognized in our consolidated statements of operations as of December 31, 2015 was $16.4 million . This cost is expected to be recognized over a weighted-average period of 1.7 years. +Market-Based Awards. The fair value of the market-based restricted shares is amortized ratably over the requisite service period, primarily three years. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of three years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. +In January 2015 , the Compensation Committee awarded a total of 29,398 market-based restricted shares to our executive officers. In addition to continuous employment, the vesting of these shares is contingent on the Company's total shareholder return ("TSR"), which is essentially the Company’s stock price change including any dividends, as compared to the TSR of a group of peer companies. The shares are measured over a three-year period ending on December 31, 2017 and can result in a payout between 0% and 200% of the total shares awarded. The weighted-average grant date fair value per market-based share for these awards granted was computed using the Monte Carlo pricing model using the following assumptions: +Year Ended December 31, +2015 +2014 +Expected term of award +3 years +3 years +Risk-free interest rate +0.9 +% +0.8 +% +Expected volatility +53.0 +% +55.2 +% +Weighted-average grant date fair value per share +$ +66.16 +$ +56.87 +The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our historical volatility. +84 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the change in non-vested market-based awards during 2015 : +Shares +Weighted-Average +Grant-Date +Fair Value per Share +Non-vested at December 31, 2014 +83,721 +$ +52.98 +Granted +29,398 +66.16 +Vested +(41,570 +) +49.04 +Non-vested at December 31, 2015 +71,549 +63.60 +The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: +As of/Year Ended December 31, +2015 +2014 +2013 +(in thousands, except per share data) +Total intrinsic value of market-based awards vested +$ +4,293 +$ +1,260 +$ +724 +Total intrinsic value of market-based awards non-vested +3,819 +3,455 +3,838 +Market price per common share as of December 31, +53.38 +41.27 +53.22 +Weighted-average grant date fair value per share +66.16 +56.87 +49.04 +Total compensation cost related to non-vested market-based awards, net of estimated forfeitures, and not yet recognized in our consolidated statements of operations as of December 31, 2015 was $1.9 million . This cost is expected to be recognized over a weighted-average period of 1.4 years. +Treasury Share Purchases +In accordance with our stock-based compensation plans, employees and directors may surrender shares of the Company's common stock to pay tax withholding obligations upon the vesting and exercise of share-based awards. Shares acquired that had been issued pursuant to the 2010 Plan are reissued to service awards. For shares reissued to service awards under the 2010 Plan, shares are recorded at cost and upon reissuance we reduce the carrying value of shares acquired and held pursuant to the 2010 Plan by the weighted-average cost per share with an offsetting charge to APIC. During the year ended December 31, 2015 , we acquired 136,168 shares pursuant to our stock-based compensation plans for payment of tax liabilities, of which 127,159 shares were reissued and 9,009 shares are available for reissuance pursuant to our 2010 Plan. +Shareholders’ Rights Agreement +In 2007, we entered into a rights agreement. The rights agreement is designed to improve the ability of our Board to protect the interest of our shareholders in the event of an unsolicited takeover attempt. Our Board declared a dividend of one right for each outstanding share of our common stock. The right dividend was paid to shareholders of record in September 2007 . A "distribution date," as defined in the rights agreement, can occur after any individual shareholder exceeds 15% ownership of our outstanding common stock. In certain circumstances, the right entitles each holder, other than an "acquiring person" (as defined in the agreement), to purchase shares of our common stock (or, in certain circumstances, cash, property or other securities) having a then-current value equal to two times the exercise price of the right (i.e., for the $240 exercise price, the rights holder receives $480 worth of common stock). The exercise price is subject to adjustment for various corporate actions which affect all shareholders, such as a stock split. The rights agreement and all rights will expire in September 2017 . +Preferred stock +We are authorized, pursuant to shareholder approval in 2008, to issue 50,000,000 shares of preferred stock, par value $0.01, which may be issued in one or more series, with such rights, preferences, privileges and restrictions as shall be fixed by our Board from time to time. As of December 31, 2015 , no preferred shares had been issued. +85 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 14 - EARNINGS PER SHARE +Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, stock options, Convertible Notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. +The following table presents a reconciliation of the weighted-average diluted shares outstanding: +Year Ended December 31, +2015 +2014 +2013 +(in thousands) +Weighted-average common shares outstanding - basic +39,153 +35,784 +32,426 +Dilutive effect of: +Restricted stock +— +279 +— +Convertible notes +— +564 +— +Other equity-based awards +— +51 +— +Weighted-average common shares and equivalents outstanding - diluted +39,153 +36,678 +32,426 +For 2015 and 2013, we reported a net loss. As a result, our basic and diluted weighted-average common shares outstanding were the same because the effect of the common share equivalents was anti-dilutive. +The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect: +Year Ended December 31, +2015 +2014 +2013 +(in thousands) +Weighted-average common share equivalents excluded from diluted earnings +per share due to their anti-dilutive effect: +Restricted stock +831 +8 +823 +Convertible notes +562 +— +518 +Other equity-based awards +101 +26 +83 +Total anti-dilutive common share equivalents +1,494 +34 +1,424 +In November 2010, we issued our Convertible Notes, which give the holders the right to convert the aggregate principal amount into 2.7 million shares of our common stock at a conversion price of $42.40 per share. The Convertible Notes could be included in the diluted earnings per share calculation using the treasury stock method if the average market share price exceeds the $42.40 conversion price during the period presented. Shares issuable upon conversion of the Convertible Notes were excluded from the diluted earnings per share calculation for the years ended December 31, 2015 and 2013, respectively, as the effect would be anti-dilutive to our earnings per share. Shares issuable upon conversion of the Convertible Notes were included in the diluted earnings per share calculation for the year ended December 31, 2014 as the average market price during the period exceeded the conversion price. +NOTE 15 - ASSETS HELD FOR SALE, DIVESTITURES AND DISCONTINUED OPERATIONS +In October 2014 , we completed the sale of our entire 50% ownership interest in PDCM to an unrelated third-party for aggregate consideration, after our share of PDCM's debt repayment and other working capital adjustments, of approximately $192 million , comprised of approximately $153 million in net cash proceeds and a promissory note due in 2020 of approximately $39 million . The transaction included the buyer's assumption of our share of the firm transportation commitment related to the assets owned by PDCM, as well as our share of PDCM's natural gas hedging positions for the years 2014 through 2017. The divestiture resulted in a pre-tax gain of $76.3 million . Proceeds from the divestiture were used to reduce outstanding borrowings on our revolving credit facility and to fund a portion of our 2014 capital budget. As the divestiture represents a strategic shift that will have a major effect on our operations as our organization structure will no longer have joint venture partners and we no longer have dry gas assets, our proportionate share of PDCM's Marcellus Shale results of operations have been separately reported as discontinued operations in the consolidated statements of operations for all periods presented. +The tables below set forth selected financial information related to net assets divested and operating results related to discontinued operations. Net assets held for sale represents the assets that are expected to be sold. While the reclassification of revenues and expenses related to discontinued operations for prior periods had no impact upon previously reported net earnings, the consolidated statements of operations table +86 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +presents the revenues and expenses that were reclassified from the specified consolidated statements of operations line items to discontinued operations. The following table presents consolidated statements of operations data related to our discontinued operations: +Year Ended December 31, +Consolidated statements of operations - discontinued operations +2014 +2013 +(in thousands) +Revenues +Crude oil, natural gas and NGLs sales +$ +24,149 +$ +39,001 +Sales from natural gas marketing +— +2,825 +Commodity price risk management income (loss), net +(1,085 +) +14 +Well operations, pipeline income and other +48 +922 +Total revenues +23,112 +42,762 +Costs, expenses and other +Lease operating expenses +1,280 +6,522 +Production taxes +1,579 +3,716 +Transportation, gathering and processing expenses +3,536 +5,283 +Cost of natural gas marketing +— +2,673 +Impairment of crude oil and natural gas properties +433 +954 +Depreciation, depletion and amortization +9,128 +13,894 +Other +4,170 +8,235 +Gain on sale of properties and equipment +(76,479 +) +1,700 +Total costs, expenses and other +(56,353 +) +42,977 +Interest expense +(2,222 +) +(1,755 +) +Interest income +194 +10 +Income from discontinued operations +77,437 +(1,960 +) +Provision for income taxes +(29,263 +) +770 +Income (loss) from discontinued operations, net of tax +$ +48,174 +$ +(1,190 +) +The following table presents supplemental cash flows information related to our 50% ownership interest in PDCM, which is classified as discontinued operations: +Year Ended December 31, +Supplemental cash flows information - discontinued operations +2014 +2013 +(in thousands) +Cash flows from investing activities: +Capital expenditures +$ +(17,253 +) +$ +(45,277 +) +Significant non-cash investing items: +Change in accounts payable related to purchases of properties and equipment +(5,727 +) +(4,738 +) +Assets held for sale of $2.9 million as of December 31, 2015 and 2014 represents the carrying value of approximately 12 acres of land located adjacent to our Bridgeport, West Virginia, regional headquarters. +NOTE 16 - TRANSACTIONS WITH AFFILIATES +PDCM and Affiliated Partnerships. Our Gas Marketing segment marketed the natural gas produced by our affiliated partnerships and, until the fourth quarter of 2014, by PDCM. Our cost of natural gas marketing includes $1.3 million in 2013 related to the marketing of natural gas on behalf of our affiliated partnerships and $23.2 million and $18.1 million in 2014 and 2013 , respectively, related to the marketing of natural gas on behalf of PDCM. +Prior to October 2014, amounts due from/to affiliates included amounts billed for certain well operating and administrative services provided to PDCM. Amounts billed to PDCM for these services were $5.7 million and $14.5 million in 2014 and 2013, respectively. Our +87 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +consolidated statements of operations include only our proportionate share of these billings. All amounts billed to PDCM for operating and administrative services in 2014 have been collected. Accordingly, we had no amounts due from PDCM as of December 31, 2014. +NOTE 17 - BUSINESS SEGMENTS +We separate our operating activities into two segments: Oil and Gas Exploration and Production and Gas Marketing. All material inter-company accounts and transactions between segments have been eliminated. +Oil and Gas Exploration and Production. Our Oil and Gas Exploration and Production segment includes all of our crude oil and natural gas properties. The segment represents revenues and expenses from the production and sale of crude oil, natural gas and NGLs. Segment revenue includes crude oil, natural gas and NGLs sales, commodity price risk management, net, and well operation and pipeline income. Segment income (loss) consists of segment revenue less production cost, exploration expense, impairment of crude oil and natural gas properties, direct general and administrative expense and DD&A expense. Segment DD&A expense was $298.8 million , $188.5 million and $111.6 million in 2015 , 2014 and 2013 , respectively. +Gas Marketing. Our Gas Marketing segment purchases, aggregates and resells natural gas produced by us and others. Segment income (loss) primarily represents sales from natural gas marketing and direct interest income less costs of natural gas marketing, transportation and direct general and administrative expense. +Unallocated amounts. Unallocated income includes unallocated other revenue, less corporate general administrative expense, corporate DD&A expense, interest income and interest expense. Unallocated assets include assets utilized for corporate, general and administrative purposes, as well as assets not specifically included in our two business segments. +The following tables present our segment information: +2015 +2014 +— +2013 +(in thousands) +Year Ended December 31, +Segment revenues: +Oil and gas exploration and production +$ +584,406 +$ +784,636 +$ +322,878 +Gas marketing +10,920 +71,571 +69,787 +Total revenues +$ +595,326 +$ +856,207 +$ +392,665 +Segment income (loss) before income taxes: +Oil and gas exploration and production +$ +31,429 +$ +344,149 +$ +81,913 +Gas marketing +(797 +) +(445 +) +(297 +) +Unallocated +(137,220 +) +(166,476 +) +(114,579 +) +Income (loss) before income taxes +$ +(106,588 +) +$ +177,228 +$ +(32,963 +) +Expenditures for segment long-lived assets: +Oil and gas exploration and production +$ +599,617 +$ +623,912 +$ +403,227 +Unallocated +5,051 +4,680 +1,379 +Total +$ +604,668 +$ +628,592 +$ +404,606 +As of December 31, +Segment assets: +Oil and gas exploration and production +$ +2,294,288 +$ +2,258,060 +Gas marketing +4,217 +6,979 +Unallocated +69,164 +63,227 +Assets held for sale +2,874 +2,874 +Total assets +$ +2,370,543 +$ +2,331,140 +88 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +SUPPLEMENTAL INFORMATION - UNAUDITED +CRUDE OIL AND NATURAL GAS INFORMATION - UNAUDITED +Net Proved Reserves +All of our crude oil, natural gas and NGLs reserves are located in the U.S. We utilize the services of independent petroleum engineers to estimate our crude oil, natural gas and NGL reserves. As of December 31, 2015 , 2014 and 2013 , all of our estimates of proved reserves were based on reserve reports prepared by Ryder Scott Company, L.P. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC. +Proved reserves are those quantities of crude oil, natural gas and NGLs which can be estimated with reasonable certainty to be economically producible under existing economic conditions and operating methods. Proved developed reserves are the proved reserves that can be produced through existing wells with existing equipment and infrastructure and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for development. All of our proved undeveloped reserves conform to the SEC five-year rule requirement to be drilled within five years of each location’s initial booking date. +The netted back price used to estimate our reserves, by commodity, are presented below. +Price Used to Estimate Reserves* +As of December 31, +Crude Oil +(per Bbl) +Natural Gas +(per Mcf) +NGLs +(per Bbl) +2015 +$ +42.10 +$ +2.05 +$ +12.23 +2014 +84.65 +3.92 +32.27 +2013 +82.18 +3.22 +29.92 +___________ +* +These prices are based on the index prices and are net of basin differentials, any transport fees, contractual adjustments and any Btu adjustments we experienced for the respective commodity. +89 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +The following tables present the changes in our estimated quantities of proved reserves: +Crude Oil, Condensate (MBbls) +Natural Gas +(MMcf) +NGLs +(MBbls) +Total +(MBoe) +Proved Reserves: +Proved reserves, January 1, 2013 (1) +59,310 +604,038 +32,827 +192,810 +Revisions of previous estimates +(18,420 +) +(117,068 +) +(8,549 +) +(46,480 +) +Extensions, discoveries and other additions, including infill reserves in an existing proved field +55,759 +365,563 +25,249 +141,935 +Purchases of reserves +343 +2,894 +217 +1,043 +Dispositions +(252 +) +(94,927 +) +(30 +) +(16,104 +) +Production +(2,910 +) +(20,860 +) +(1,043 +) +(7,430 +) +Proved reserves, December 31, 2013 (2) +93,830 +739,640 +48,671 +265,774 +Revisions of previous estimates +(29,777 +) +(149,064 +) +(10,204 +) +(64,825 +) +Extensions, discoveries and other additions, including infill reserves in an existing proved field +40,792 +202,957 +23,411 +98,029 +Purchases of reserves +5 +43 +5 +17 +Dispositions +(13 +) +(237,306 +) +(8 +) +(39,572 +) +Production +(4,322 +) +(19,298 +) +(1,756 +) +(9,294 +) +Proved reserves, December 31, 2014 +100,515 +536,972 +60,119 +250,129 +Revisions of previous estimates +(43,268 +) +(154,775 +) +(24,407 +) +(93,471 +) +Extensions, discoveries and other additions, including infill reserves in an existing proved field +48,707 +311,709 +30,835 +131,494 +Purchases of reserves +17 +215 +23 +76 +Dispositions +(12 +) +(82 +) +(8 +) +(34 +) +Production +(6,984 +) +(33,302 +) +(2,835 +) +(15,369 +) +Proved reserves, December 31, 2015 +98,975 +660,737 +63,727 +272,825 +Proved Developed Reserves, as of: +January 1, 2013 (1) +20,412 +281,925 +14,353 +81,753 +December 31, 2013 (2) +23,997 +220,387 +14,825 +75,553 +December 31, 2014 +26,798 +186,633 +17,002 +74,905 +December 31, 2015 +26,257 +175,367 +15,011 +70,496 +Proved Undeveloped Reserves, as of: +January 1, 2013 (1) +38,898 +322,113 +18,474 +111,058 +December 31, 2013 (2) +69,833 +519,253 +33,846 +190,221 +December 31, 2014 +73,717 +350,339 +43,117 +175,224 +December 31, 2015 +72,718 +485,370 +48,716 +202,329 +__________ +(1) +Includes estimated reserve data related to our Piceance and NECO assets, which were divested in June 2013. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Piceance and NECO assets. Total proved reserves include 148 MBbls of crude oil and 83,656 MMcf of natural gas, for an aggregate of 14,091 MBoe of crude oil equivalent related to our Piceance and NECO assets. There were no proved undeveloped reserves attributable to the Piceance and NECO assets as of December 31, 2012. +(2) +Includes estimated reserve data related to our Marcellus Shale assets, which were divested in October 2014. See Note 15, Assets Held for Sale, Divestitures and Discontinued Operations, for additional details related to the divestiture of our Marcellus Shale assets. Total proved reserves included 235,950 MMcf of natural gas, for an aggregate of 39,325 Mboe of crude oil equivalent, related to our Marcellus Shale assets. Total proved developed reserves related to those assets included 53,904 MMcf and 8,984 MBoe, respectively, and proved undeveloped reserves included 182,046 MMcf and 30,341 MBoe, respectively. +90 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Developed +Undeveloped +Total +(MBoe) +Beginning proved reserves, January 1, 2013 +81,753 +111,057 +192,810 +Production +(7,430 +) +— +(7,430 +) +Undeveloped reserves converted to developed +3,212 +(3,212 +) +— +Purchases of reserves +1,043 +— +1,043 +Dispositions +(16,104 +) +— +(16,104 +) +Extensions, discoveries and other additions, including infill reserves in an existing proved field +19,830 +122,105 +141,935 +Revisions of previous estimates +(6,751 +) +(39,729 +) +(46,480 +) +Ending proved reserves, December 31, 2013 +75,553 +190,221 +265,774 +Production +(9,294 +) +— +(9,294 +) +Undeveloped reserves converted to developed +12,730 +(12,730 +) +— +Purchases of reserves +17 +— +17 +Dispositions +(9,231 +) +(30,341 +) +(39,572 +) +Extensions, discoveries and other additions, including infill reserves in an existing proved field +27,957 +70,072 +98,029 +Revisions of previous estimates +(22,827 +) +(41,998 +) +(64,825 +) +Ending proved reserves, December 31, 2014 +74,905 +175,224 +250,129 +Production +(15,369 +) +— +(15,369 +) +Undeveloped reserves converted to developed +29,090 +(29,090 +) +— +Purchases of reserves +76 +— +76 +Dispositions +(34 +) +— +(34 +) +Extensions, discoveries and other additions, including infill reserves in an existing proved field +8,703 +122,791 +131,494 +Revisions of previous estimates +(26,875 +) +(66,596 +) +(93,471 +) +Ending proved reserves, December 31, 2015 +70,496 +202,329 +272,825 +2015 Activity. Overall, our proved reserves increased by 23 MMBoe as of December 31, 2015 as compared to December 31, 2014. In 2015, we produced 15.4 MMBoe. At December 31, 2014, we projected a PUD conversion rate of 16% for 2015. Our actual conversion rate was 17% , resulting in 29 MMBoe of reserves booked as PUDs at December 31, 2014 being converted to proved developed reserves during 2015. As shown, we acquired and divested minimal volumes of proved reserves in 2015. +Extensions, discoveries and other additions, including infill reserves, of approximately 131 MMBoe in 2015 were all added in the Wattenberg Field and primarily related to horizontal Niobrara projects being added to our development plan. The reserve additions associated with these projects are largely the result of data generated from our downspacing testing. This led to increased well density of our PUD locations year-over-year and extended the field by enabling us to book more reserves per section in the Niobrara. In general, at December 31, 2014, Niobrara PUD locations were booked at an equivalent of eight wells per section and at December 31, 2015, such locations were booked at an equivalent of 16 wells per section. Additionally, due to more efficient drilling leading to shorter spud-to-spud times, we have increased the number of wells drilled per drilling rig utilized during the course of the year. We have 791 gross PUD horizontal drilling locations at December 31, 2015, which is an increase from 774 locations at December 31, 2014. Approximately 9 MMBoe of the extensions, discoveries and other additions to our developed reserves related to wells drilled that were not related to reserves booked as of prior year-end. +We recorded net downward revisions of previous estimates of proved reserves of approximately 93 MMBoe. The revision was a result of multiple factors, most notably a decrease of approximately 56 MMBoe for adjustments to our development plans in the Wattenberg Field resulting from the booking of further-downspaced PUD locations. This downspacing delayed the expected development date for many existing PUD locations beyond the limits of the SEC five-year rule. Also contributing to the downward revision was a decrease of approximately 33 MMBoe due to the significant decrease in SEC commodity prices utilized in the December 31, 2015 reserve report, including approximately 11 MMBoe specifically related to the removal of vertical re-fracs and re-completions from the proved developed reserves which no longer fall within our economic parameters. There was an additional negative revision of approximately 22 MMBoe primarily related to geology findings and leasehold factors. Partially offsetting these decreases was an upward revision approximately 18 MMBoe related to well performance and forecast adjustments. +Based on the economic conditions on December 31, 2015, our approved development plan provides for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. The continued success of our increased well density tests in the Wattenberg Field in 2015 allowed for the additional increased well density of PUD locations as of December 31, 2015. Because we expect to continue to drill primarily proven Wattenberg Field locations in 2016 and as a result of additional newly-booked downspaced PUDs at December 31, 2015, our 2016 PUD conversion rate is expected to be approximately 19% . The balance of the locations are scheduled to be +91 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +drilled over the remaining four years in accordance with our current development plan. The level of capital spending necessary to achieve this drilling schedule is consistent with our recent performance and our outlook for future development activities. +2014 Activity . Overall, our proved reserves decreased by 16 MMBoe as of December 31, 2014 as compared to December 31, 2013. In 2014, we produced 9.3 MMBoe. At December 31, 2013, we projected a PUD conversion rate of 7% for 2014. Our actual conversion rate was 7% , resulting in 13 MMBoe of reserves booked as PUDs at December 31, 2013 being converted to proved developed reserves during 2014. As shown, we acquired minimal proved reserves in 2014. We divested a total of 40 MMBoe in 2014, primarily from the sale of our Marcellus Shale assets. +Extensions, discoveries and other additions, including infill reserves, resulted in an increase of approximately 98 MMBoe in 2014, substantially all of which was added in the Wattenberg Field and primarily related to Niobrara and Codell projects. These reserve increases are primarily due to adding 78 MMBoe from new proved undeveloped reserves as a result of adjustments in well spacing, which extended the field by enabling us to book more reserves per section in the Niobrara and Codell formations. In addition approximately 16 MMBoe of previously unbooked locations were developed in the current year and 2 MMBoe due to various other factors. Approximately 2 MMBoe was added in the Utica Shale. +We recorded a downward revision of our previous estimate of proved reserves of approximately 65 MMBoe. The revision was primarily related to decreases of approximately 55 MMBoe for adjustments to our development plans in the Wattenberg Field to focus on a more balanced commodity production mix and increased well density which delayed the expected development date for many existing PUD locations beyond the limits of the SEC five-year rule. In addition, 8 MMBoe of Utica Shale PUDs are no longer in our drilling plans as we directed more capital to higher-return projects in the Wattenberg Field and 2 MMBoe that were due to various other factors. +Based on the economic conditions on December 31, 2014, our approved development plan provided for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. Our 2014 drilling program focused on testing increased well density in the Wattenberg Field. +2013 Activity. Overall, our proved reserves increased by 73 MMBoe as of December 31, 2013 as compared to December 31, 2012. In 2013, we produced 7.4 MMBoe. At December 31, 2012, we projected a PUD conversion rate of 15% to 20% for 2013. Our actual conversion rate was 3% , resulting in 3 MMBoe of reserves booked as PUDs at December 31, 2012 being converted to proved developed reserves during 2013. As shown, we acquired 1 MMBoe of proved reserves in 2013. We divested a total of 16 MMBoe in 2013, primarily related to the sales of our Piceance Basin, NECO and shallow Upper Devonian (non-Marcellus Shale) assets. +Extensions, discoveries and other additions, including infill reserves, of approximately 142 MMBoe were added in 2013, approximately 110 MMBoe, 18 MMBoe and 14 MMBoe of which were added to the Wattenberg Field, Marcellus Shale and Utica Shale, respectively. Approximately 125 MMBoe of new proved undeveloped reserves were booked, including 32 MMBoe due to adjustments in well spacing in the Wattenberg Field and Marcellus Shale. In addition, approximately 17 MMBoe of previously unbooked locations were developed in the current year. +We recorded a downward revision of our previous estimate of proved reserves of approximately 46 MMBoe. The revision was primarily due to a decrease of approximately 55 MMBoe, of which approximately 32 MMBoe is due to increased well density plans in the Wattenberg Field, which delayed the expected development date for many existing PUD locations beyond the limits of the SEC five-year rule, approximately 9 MMBoe is due to expired leases, approximately 11 MMBoe is due to our shift from vertical to horizontal drilling in the Wattenberg Field and approximately 3 MMBoe is to remove Wattenberg Field PUDs that were no longer in our core drilling area. These decreases were partially offset by various factors, including but not limited to interest adjustments, well performance and changing economics. +Based on the economic conditions on December 31, 2013, our approved development plan provided for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. Our 2013 drilling program focused on locations that were not included in proved undeveloped reserves in the December 31, 2012 reserve report due to increased well density testing in the Wattenberg Field. The success of this increased well density testing allowed us to add considerable PUD reserves in the 2013 reserve report. +92 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Results of Operations for Crude Oil and Natural Gas Producing Activities +The results of operations for crude oil and natural gas producing activities are presented below. The results include activities related to both continuing and discontinued operations and exclude activities related to natural gas marketing and well operations and pipeline services. +Year Ended December 31, +2015 +2014 +2013 +(in thousands) +Revenue: +Crude oil, natural gas and NGLs sales +$ +378,713 +$ +495,562 +$ +379,796 +Commodity price risk management gain (loss), net +203,183 +309,219 +(23,905 +) +581,896 +804,781 +355,891 +Expenses: +Lease operating expenses +56,992 +43,682 +40,339 +Production taxes +18,443 +27,194 +25,474 +Transportation, gathering and processing expenses +10,151 +8,128 +10,435 +Exploration expense +1,102 +948 +7,071 +Impairment of proved crude oil and natural gas properties +161,620 +167,280 +53,827 +Depreciation, depletion, and amortization +298,760 +201,656 +124,202 +Accretion of asset retirement obligations +6,293 +3,455 +4,747 +(Gain) loss on sale of properties and equipment +(385 +) +(75,972 +) +3,722 +552,976 +376,371 +269,817 +Results of operations for crude oil and natural gas producing +activities before provision for income taxes +28,920 +428,410 +86,074 +Provision for income taxes +(10,394 +) +(166,930 +) +(31,109 +) +Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs +$ +18,526 +$ +261,480 +$ +54,965 +Production costs include those costs incurred to operate and maintain productive wells and related equipment, including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, production and severance taxes and associated administrative expenses. DD&A expense includes those costs associated with capitalized acquisition, exploration and development costs, but does not include the depreciation applicable to support equipment. The provision for income taxes is computed using effective tax rates. +Costs Incurred in Crude Oil and Natural Gas Property Acquisition, Exploration and Development Activities +Costs incurred in crude oil and natural gas property acquisition, exploration and development are presented below. +Year Ended December 31, +2015 +2014 +2013 +(in thousands) +Acquisition of properties: (1) +Proved properties +$ +3,561 +$ +11,973 +$ +28,698 +Unproved properties +15 +45,999 +3,390 +Development costs (2) +552,104 +608,176 +338,294 +Exploration costs: (3) +Exploratory drilling +— +— +58,988 +Geological and geophysical +— +1 +752 +Total costs incurred +$ +555,680 +$ +666,149 +$ +430,122 +__________ +(1) +Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property. +(2) +Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells and provide facilities to extract, treat, gather and store crude oil, natural gas and NGLs. Of these costs incurred for the years ended December 31, 2015 , 2014 and 2013 , $207.8 million , $125.2 million and $40.1 million , respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. +(3) +Exploration costs - represents costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas and NGLs. +93 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities +Aggregate capitalized costs related to crude oil and natural gas exploration and production activities with applicable accumulated DD&A are presented below: +As of December 31, +2015 +2014 +(in thousands) +Proved crude oil and natural gas properties +$ +2,881,189 +$ +2,267,165 +Unproved crude oil and natural gas properties +60,498 +188,206 +Uncompleted wells, equipment and facilities +109,385 +164,402 +Capitalized costs +3,051,072 +2,619,773 +Less accumulated DD&A +(1,131,705 +) +(808,431 +) +Capitalized costs, net +$ +1,919,367 +$ +1,811,342 +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves +The standardized measure below has been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to our year-end estimated proved reserves. Prices for each of the three years were adjusted by field for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of our commodity derivatives. Production and development costs were based on prices as of December 31 for each of the respective years presented. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service or to depreciation, depletion and amortization expense. Production and development costs include those cash flows associated with the expected ultimate settlement of our asset retirement obligation. Future estimated income tax expense is computed by applying the statutory rate in effect at the end of each year to the projected future pre-tax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits and allowances related to the properties. +The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for crude oil, natural gas and NGLs, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves. +As of December 31, +2015 +2014 +2013 +(in thousands) +Future estimated cash flows +$ +6,297,298 +$ +12,550,515 +$ +11,550,917 +Future estimated production costs* +(1,577,393 +) +(2,816,776 +) +(2,329,836 +) +Future estimated development costs +(1,952,332 +) +(2,458,790 +) +(2,778,148 +) +Future estimated income tax expense +(508,332 +) +(2,336,510 +) +(2,119,615 +) +Future net cash flows +2,259,241 +4,938,439 +4,323,318 +10% annual discount for estimated timing of cash flows +(1,162,377 +) +(2,631,974 +) +(2,541,155 +) +Standardized measure of discounted future estimated net cash flows +$ +1,096,864 +$ +2,306,465 +$ +1,782,163 +___________ +* +Represents future estimated lease operating expenses, production taxes, transportation, gathering and processing expenses and plugging and abandonment costs, net of salvage value. +94 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows: +Year Ended December 31, +2015 +2014 +2013 +(in thousands) +Sales of crude oil, natural gas and NGLs production, net of production costs +$ +(293,127 +) +$ +(387,789 +) +$ +(286,021 +) +Net changes in prices and production costs (1) +(1,752,921 +) +129,213 +89,527 +Extensions, discoveries, and improved recovery, including infill reserves in an existing proved field, less related costs (2) +489,178 +1,444,581 +1,529,006 +Sales of reserves (3) +(463 +) +(402,595 +) +(142,724 +) +Purchases of reserves (4) +374 +238 +10,610 +Development costs incurred during the period +368,840 +161,404 +46,366 +Revisions of previous quantity estimates (5) +(1,286,462 +) +(654,318 +) +(397,738 +) +Changes in estimated income taxes (6) +902,994 +(221,874 +) +(381,369 +) +Net changes in future development costs +112,958 +46,499 +(40,707 +) +Accretion of discount +345,007 +270,389 +142,040 +Timing and other +(95,979 +) +138,554 +44,676 +Total +$ +(1,209,601 +) +$ +524,302 +$ +613,666 +__________ +(1) +Our weighted-average price, net of production costs per Boe, in our 2015 reserve report decreased to $17.30 as compared to $37.78 in our 2014 reserve report. This is due to the significant decrease in SEC commodity prices utilized in the 2015 reserve report. Our weighted-average price, net of production costs per Boe, in our 2014 reserve report increased to $37.78 from $30.82 in our 2013 reserve report. This is due to the divestiture of our Marcellus Shale reserves during 2014 which further increased our liquids as a percentage of proved reserves. +(2) +The 66% decrease in 2015 indicates a significant decrease in the value of the extensions in 2015 as compared to the value of the extensions in 2014. This is primarily due to lower SEC commodity prices utilized in the 2015 reserve report. The 6% decrease in 2014 as compared to 2013 is primarily due to a scheduled maximum rig count of six rigs by 2016 as compared to a scheduled maximum rig count of seven in the 2013 year-end reserve report, partially offset by our increased PUD count in the Wattenberg Field resulting from successful downspacing tests in 2014. +(3) +The decrease in sales of reserves in 2015 was due to the fact that no major divestitures were completed in 2015. The increase in sales of reserves in 2014 as compared to 2013 was due to the divestiture of our Marcellus shale assets in October 2014. +(4) +The decrease in purchases of reserves in 2015 and 2014 as compared to the respective prior years was due to no material acquisitions having occurred. +(5) +The change in revisions of our previous quantity estimates in 2015 as compared to 2014 was primarily due to adjustments due to our drilling schedule. The change in revisions of our previous quantity estimates in 2014 as compared to 2013 was primarily due to adjustments due to our drilling schedule. +(6) +The change in estimated income taxes for each year as compared to the prior year is the direct result of the significant changes in discounted future net cash flows, as the projected deferred tax rate remained relatively unchanged at approximately 38% for each of the three years ended December 31, 2015, 2014 and 2013. In addition, the Company continued to capitalize and amortize the majority of its yearly capital expenditures and there were no changes in the assumptions as to the tax deductibility of beginning unamortized capital, additional current year capital or future development capital. Further, future tax deductions for capital expenditures were not affected by the impairment of crude oil and natural gas properties in 2014 and 2015 as such impairments are not tax deductible. +The data presented should not be viewed as representing the expected cash flows from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the recent average prices and current costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein. +QUARTERLY FINANCIAL INFORMATION - UNAUDITED +Quarterly financial data for the years ended December 31, 2015 and 2014 is presented below. The quarterly consolidated statements of operations below reflect our revised presentation. See Note 1, Nature of Operations and Basis of Presentation . The sum of the quarters may not equal the total of the year's net income or loss per share due to changes in the weighted-average shares outstanding throughout the year. +2015 +Quarter Ended +March 31 +June 30 +September 30 +December 31 +Year Ended +(in thousands, except per share data) +Revenues: +Crude oil, natural gas and NGLs sales +$ +74,109 +$ +96,928 +$ +104,483 +$ +103,193 +$ +378,713 +Sales from natural gas marketing +3,233 +2,523 +2,580 +2,584 +10,920 +Commodity price risk management gain (loss), net +66,662 +(49,041 +) +123,549 +62,013 +203,183 +Well operations, pipeline income and other +628 +550 +488 +844 +2,510 +Total revenues +144,632 +50,960 +231,100 +168,634 +595,326 +Costs, expenses and other: +Lease operating expenses +16,285 +12,639 +13,824 +14,244 +56,992 +Production taxes +3,893 +3,837 +5,476 +5,237 +18,443 +Transportation, gathering and processing expenses +1,338 +1,308 +3,938 +3,567 +10,151 +Cost of natural gas marketing +3,258 +2,836 +2,781 +2,842 +11,717 +Exploration expense +285 +275 +252 +290 +1,102 +Impairment of crude oil and natural gas properties +2,772 +4,404 +154,031 +413 +161,620 +General and administrative expense +21,045 +20,728 +20,278 +27,908 +89,959 +Depreciation, depletion and amortization +55,820 +70,106 +80,947 +96,385 +303,258 +Accretion of asset retirement obligations +1,560 +1,588 +1,594 +1,551 +6,293 +(Gain) loss on sale of properties and equipment +(21 +) +(207 +) +(74 +) +(83 +) +(385 +) +Total costs, expenses and other +106,235 +117,514 +283,047 +152,354 +659,150 +Income (loss) from operations +38,397 +(66,554 +) +(51,947 +) +16,280 +(63,824 +) +Interest expense +(11,725 +) +(11,567 +) +(12,092 +) +(12,187 +) +(47,571 +) +Interest income +1,113 +1,135 +1,378 +1,181 +4,807 +Income (loss) from continuing operations before income taxes +27,785 +(76,986 +) +(62,661 +) +5,274 +(106,588 +) +Provision for income taxes +(10,723 +) +30,116 +21,167 +(2,252 +) +38,308 +Income (loss) from continuing operations +17,062 +(46,870 +) +(41,494 +) +3,022 +(68,280 +) +Income (loss) from discontinued operations, net of tax +— +— +— +— +— +Net income (loss) +$ +17,062 +$ +(46,870 +) +$ +(41,494 +) +$ +3,022 +$ +(68,280 +) +Earnings per share: +Basic +Income (loss) from continuing operations +$ +0.47 +$ +(1.17 +) +$ +(1.04 +) +$ +0.08 +$ +(1.74 +) +Income (loss) from discontinued operations +— +— +— +— +— +Net income (loss) +$ +0.47 +$ +(1.17 +) +$ +(1.04 +) +$ +0.08 +$ +(1.74 +) +Diluted +Income (loss) from continuing operations +$ +0.46 +$ +(1.17 +) +$ +(1.04 +) +$ +0.07 +$ +(1.74 +) +Income (loss) from discontinued operations +— +— +— +— +— +Net income (loss) +$ +0.46 +$ +(1.17 +) +$ +(1.04 +) +$ +0.07 +$ +(1.74 +) +Weighted-average common shares outstanding: +Basic +36,349 +40,035 +40,085 +40,094 +39,153 +Diluted +36,981 +40,035 +40,085 +41,264 +39,153 +95 +PDC ENERGY, INC. +2014 +Quarter Ended +March 31 +June 30 +September 30 +December 31 +Year Ended +(in thousands, except per share data) +Revenues: +Crude oil, natural gas and NGLs sales +$ +120,013 +$ +131,017 +$ +120,526 +$ +99,857 +$ +471,413 +Sales from natural gas marketing +26,937 +22,415 +13,297 +8,922 +71,571 +Commodity price risk management gain (loss), net +(24,909 +) +(52,643 +) +90,213 +297,643 +310,304 +Well operations, pipeline income and other +616 +514 +520 +1,269 +2,919 +Total revenues +122,657 +101,303 +224,556 +407,691 +856,207 +Costs, expenses and other: +Lease operating expenses +8,371 +11,961 +11,020 +11,050 +42,402 +Production taxes +6,390 +7,551 +8,724 +2,950 +25,615 +Transportation, gathering and processing expenses +1,235 +818 +1,208 +1,331 +4,592 +Cost of natural gas marketing +26,870 +22,428 +13,347 +9,370 +72,015 +Exploration expense +307 +276 +190 +174 +947 +Impairment of crude oil and natural gas properties +952 +2,019 +1,962 +161,914 +166,847 +General and administrative expense +24,529 +41,713 +36,328 +20,989 +123,559 +Depreciation, depletion and amortization +42,889 +49,636 +49,640 +50,363 +192,528 +Accretion of asset retirement obligations +841 +840 +861 +873 +3,415 +(Gain) loss on sale of properties and equipment +579 +(23 +) +21 +(70 +) +507 +Total costs, expenses and other +112,963 +137,219 +123,301 +258,944 +632,427 +Income (loss) from operations +9,694 +(35,916 +) +101,255 +148,747 +223,780 +Interest expense +(12,183 +) +(12,195 +) +(11,821 +) +(11,643 +) +(47,842 +) +Interest income +187 +83 +39 +981 +1,290 +Income (loss) from continuing operations before income taxes +(2,302 +) +(48,028 +) +89,473 +138,085 +177,228 +Provision for income taxes +894 +18,650 +(35,396 +) +(54,115 +) +(69,967 +) +Income (loss) from continuing operations +(1,408 +) +(29,378 +) +54,077 +83,970 +107,261 +Income (loss) from discontinued operations, net of tax +(719 +) +1,191 +(80 +) +47,782 +48,174 +Net income (loss) +$ +(2,127 +) +$ +(28,187 +) +$ +53,997 +$ +131,752 +$ +155,435 +Earnings per share: +Basic +Income (loss) from continuing operations +$ +(0.04 +) +$ +(0.82 +) +$ +1.51 +$ +2.34 +$ +3.00 +Income (loss) from discontinued operations +(0.02 +) +0.03 +— +1.33 +1.34 +Net income (loss) attributable to shareholders +$ +(0.06 +) +$ +(0.79 +) +$ +1.51 +$ +3.67 +$ +4.34 +Diluted +Income (loss) from continuing operations +$ +(0.04 +) +$ +(0.82 +) +$ +1.47 +$ +2.32 +$ +2.93 +Income (loss) from discontinued operations +(0.02 +) +0.03 +— +1.32 +1.31 +Net income (loss) attributable to shareholders +$ +(0.06 +) +$ +(0.79 +) +$ +1.47 +$ +3.64 +$ +4.24 +Weighted-average common shares outstanding +Basic +35,690 +35,762 +35,834 +35,847 +35,784 +Diluted +35,690 +35,762 +36,828 +36,146 +36,678 +96 +PDC ENERGY, INC. +FINANCIAL STATEMENT SCHEDULE +Schedule II -VALUATION AND QUALIFYING ACCOUNTS +Description +Beginning +Balance +January 1 +Charged to +Costs and +Expenses +Deductions (1) +Ending +Balance +December 31 +(in thousands) +2015: +Allowance for doubtful accounts +$ +486 +$ +1,700 +$ +177 +$ +2,009 +Valuation allowance for unproved crude oil and natural gas properties +9,293 +7,012 +16,161 +144 +2014: +Allowance for doubtful accounts +896 +78 +488 +486 +Valuation allowance for unproved crude oil and natural gas properties +5,142 +4,465 +314 +9,293 +2013: +Allowance for doubtful accounts +718 +322 +144 +896 +Valuation allowance for unproved crude oil and natural gas properties +5,690 +3,038 +3,586 +5,142 +___ ____________ +(1) +For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For valuation allowance for unproved crude oil and natural gas properties, deductions represent accumulated amortization of expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset. +97 +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +As of December 31, 2015 , we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). Based on the results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2015 . +Management's Report on Internal Control Over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate. +Management has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2015 , based upon the criteria established in "Internal Control – Integrated Framework (2013)" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2015 . +The effectiveness of the Company's internal control over financial reporting as of December 31, 2015 , has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. +Changes in Internal Control over Financial Reporting +During the fourth quarter of 2015 , we made no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. +ITEM 9B. OTHER INFORMATION +None. +98 +PART III +ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2016 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 11. EXECUTIVE COMPENSATION +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2016 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2016 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2016 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2016 Annual Stockholders' meeting and is incorporated by reference in this report. +PART IV +ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES +(a) +(1) +Exhibits: +See Exhibits Index on the following page. +99 +Exhibits Index +Incorporated by Reference +Exhibit Number +Exhibit Description +Form +SEC File Number +Exhibit +Filing Date +Filed Herewith +2.1 +Plan of Conversion, dated June 5, 2015, by PDC Energy, Inc. (the "Company"). +8-K12B +001-37419 +2.1 +6/8/2015 +3.1 +Certificate of Incorporation of the Company. +8-K12B +001-37419 +3.1 +6/8/2015 +3.2 +By-laws of the Company. +8-K12B +001-37419 +3.2 +6/8/2015 +4.1 +Rights Agreement by and between the Company and Transfer Online, Inc., as Rights Agent, dated as of September 11, 2007, including the forms of Rights Certificates and Summary of Stockholder Rights Plan attached thereto as Exhibits A and B. +8-K +000-07246 +4.1 +9/17/2007 +4.2 +Indenture, dated November 23, 2010, between the Company and The Bank of New York Mellon, including the form of 3.25% Convertible Senior Note due 2016. +8-K +000-07246 +4.1 +11/24/2010 +4.3 +Indenture, dated as of October 3, 2012, by and between the Company and U.S. Bank Trust National Association, as Trustee, including the form of 7.75% Senior Notes due 2022. +8-K +000-07246 +4.1 +10/3/2012 +4.4 +Form of Common Stock Certificate of the Company. +8-K12B +001-37419 +4.1 +6/8/2015 +10.1* +Form of Indemnification Agreement. +8-K +000-07246 +10.1 +6/8/2015 +10.2* +401(k) and Profit Sharing Plan, as amended on January 1, 2015. +10-K +000-07246 +10.2 +2/19/2015 +10.3* +Amended and Restated Non-Employee Director Deferred Compensation Plan. +10-K +000-07246 +10.3 +2/21/2014 +10.4* +2004 Long-Term Equity Compensation Plan amended and restated as of March 8, 2008 ("2004 Plan"). +10-K +000-07246 +10.26 +2/27/2009 +10.4.1* +Summary of 2010 Stock Appreciation Rights and Restricted Stock Awards under the 2004 Plan. +8-K +000-07246 +4/23/2010 +10.5* +Amended and Restated 2010 Long-Term Equity Compensation Plan, as amended. +X +10.6* +Executive Severance Compensation Plan, as amended. +X +10.7* +Form of 2011 Restricted Stock/Stock Appreciation Rights Agreement. +10-K +000-07246 +10.5.2 +2/21/2014 +10.7.1* +Form of 2013 Performance Share Agreement. +10-K +000-07246 +10.9 +2/27/2013 +10.7.2* +Form of 2013 Restricted Stock/Stock Appreciation Rights Agreement. +10-K +000-07246 +10.10 +2/27/2013 +10.7.3* +Form of 2014 Performance Share Agreement +10-K +000-07246 +10.5.4* +2/19/2015 +10.7.4* +Form of 2014 Restricted Stock/Stock Appreciation Rights Agreement +10-K +000-07246 +10.5.5* +2/19/2015 +10.7.5* +Form of 2015 Performance Share Agreement +10-K +000-07246 +10.5.6* +2/19/2015 +10.7.6* +Form of 2015 Restricted Stock Unit Agreement +10-K +000-07246 +10.5.7* +2/19/2015 +10.7.7* +Form of 2015 Stock Appreciation Rights Agreement +10-K +000-07246 +10.5.8* +2/19/2015 +10.7.8* +Form of 2016 Performance Share Agreement +X +10.8* +Employment Agreement with Gysle R. Shellum, Chief Financial Officer, dated as of April 19, 2010. +8-K +000-07246 +10.2 +4/23/2010 +10.9* +Employment Agreement with Daniel W. Amidon, General Counsel and Corporate Secretary, dated as of April 19, 2010. +8-K +000-07246 +10.3 +4/23/2010 +10.10* +Employment Agreement with Lance A. Lauck, Senior Vice President of Business Development, dated as of April 19, 2010. +8-K +000-07246 +10.4 +4/23/2010 +100 +Incorporated by Reference +Exhibit Number +Exhibit Description +Form +SEC File Number +Exhibit +Filing Date +Filed Herewith +10.11 +Third Amended and Restated Credit Agreement dated as of May 21, 2013, among PDC Energy, Inc. as Borrower, Riley Natural Gas Company, a Subsidiary of PDC Energy, Inc., as Guarantor, JP Morgan Chase Bank, N.A. as Administrative Agent, J.P. Morgan Securities LLC as Sole Bookrunner and Co-Lead Arranger, Wells Fargo Bank, N.A. as Syndication Agent, and Wells Fargo Securities, LLC as Co-Lead Arranger, and Certain Lenders. +8-K +000-07246 +10.1 +5/28/2013 +10.11.1 +First and Second Amendments to Third Amended and Restated Credit Agreement dated as of May 14, 2014 and September 30, 2015, respectively, among PDC Energy, Inc. as the Borrower, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders. +X +10.12* +Consulting Agreement with James M. Trimble, dated as of June 18, 2014. +10-Q +000-07246 +10.1 +8/8/2014 +10.13* +Retirement Agreement with Gysle R. Shellum, Chief Financial Officer, dated October 26, 2015. +8-K +001-37419 +10.1 +10/27/2015 +12.1 +Computation of Ratio of Earnings to Fixed Charges. +X +21.1 +Subsidiaries. +X +23.1 +Consent of PricewaterhouseCoopers LLP. +X +23.2 +Consent of Ryder Scott Company, L.P., Petroleum Consultants. +X +31.1 +Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +31.2 +Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +32.1** +Certifications by Chief Executive Officer and Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. +99.1 +Report of Independent Petroleum Consultants - Ryder Scott Company, L.P. +X +101.INS +XBRL Instance Document +X +101.SCH +XBRL Taxonomy Extension Schema Document +X +101.CAL +XBRL Taxonomy Extension Calculation Linkbase Document +X +101.DEF +XBRL Taxonomy Extension Definition Linkbase Document +X +101.LAB +XBRL Taxonomy Extension Label Linkbase Document +X +101.PRE +XBRL Taxonomy Extension Presentation Linkbase Document +X +*Management contract or compensatory arrangement. +** Furnished herewith. +101 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +PDC ENERGY, INC. +By: /s/ Barton R. Brookman +Barton R. Brookman +President and Chief Executive Officer +February 22, 2016 +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated: +Signature +Title +Date +/s/ Barton R. Brookman +President, Chief Executive Officer and Director +February 22, 2016 +Barton R. Brookman +(principal executive officer) +/s/ Gysle R. Shellum +Chief Financial Officer +February 22, 2016 +Gysle R. Shellum +(principal financial officer) +/s/ R. Scott Meyers +Chief Accounting Officer +February 22, 2016 +R. Scott Meyers +(principal accounting officer) +/s/ Jeffrey C. Swoveland +Chairman and Director +February 22, 2016 +Jeffrey C. Swoveland +/s/ Joseph E. Casabona +Director +February 22, 2016 +Joseph E. Casabona +/s/ Anthony J. Crisafio +Director +February 22, 2016 +Anthony J. Crisafio +/s/ Larry F. Mazza +Director +February 22, 2016 +Larry F. Mazza +/s/ David C. Parke +Director +February 22, 2016 +David C. Parke +/s/ James M. Trimble +Director +February 22, 2016 +James M. Trimble +/s/ Kimberly Luff Wakim +Director +February 22, 2016 +Kimberly Luff Wakim +102 +GLOSSARY OF UNITS OF MEASUREMENT AND INDUSTRY TERMS +UNITS OF MEASUREMENT +The following presents a list of units of measurement used throughout the document. +Bbl – One barrel of crude oil or NGL or 42 gallons of liquid volume. +Bcf – One billion cubic feet of natural gas volume. +Boe – One barrel of crude oil equivalent. +Btu – British thermal unit. +BBtu – One billion British thermal units. +MBoe – One thousand barrels of crude oil equivalent. +MBbls – One thousand barrels of crude oil. +Mcf – One thousand cubic feet of natural gas volume. +MMBoe – One million barrels of crude oil equivalent. +MMBtu – One million British thermal units. +MMcf – One million cubic feet of natural gas volume. +GLOSSARY OF INDUSTRY TERMS +The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report: +Behind-pipe reserves - Crude oil and natural gas reserves expected to be recovered from zones in existing wells, which will require additional completion work or future recompletion prior to the start of production. Generally, these are reserves in reservoirs above currently producing zones. +CIG - Colorado Interstate Gas. +Completion - Refers to the installation of permanent equipment for the production of crude oil and natural gas from a recently drilled well or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned. +Crude oil well - A well whose reserves are expected to produce less than 15 Mcf of gas per barrel of crude oil. +Delineation - A drilling technique carried out to gain a better understanding of the structure and extent of a deposit in order to decide whether or not to conduct further drilling activities. +Developed acreage - Acreage assignable to productive wells. +Development well - A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. +Differentials - The difference between the crude oil and natural gas index spot price and the corresponding cash spot price in a specified location. +Dry gas or dry natural gas - Natural gas is considered dry when its composition is over 90% pure methane. +Dry well or dry hole - A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well. +Exploratory well - A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. +Extensions and discoveries - As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates. +Farm-out - Transfer of all or part of the operating rights from a working interest owner to an assignee, who assumes all or some of the burden of development in return for an interest in the property. The assignor usually retains an overriding royalty interest but may retain any type of interest. +Fracture or Fracturing - Procedure to stimulate production by forcing a mixture of fluid and proppant into the formation under high pressure. Fracturing creates artificial fractures in the reservoir rock to increase permeability and porosity, thereby allowing the release of trapped hydrocarbons. +Gross acres or wells - Refers to the total acres or wells in which we have a working interest. +Horizontal drilling - A drilling technique that permits the operator to drill a horizontal well shaft from the bottom of a vertical well and thereby to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons. +103 +Joint interest billing - Process of billing/invoicing the costs related to well drilling, completions and production operations among working interest partners. +Natural gas liquid(s) or NGL(s) - Hydrocarbons which can be extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs include ethane, propane, butane, and other natural gasolines. +Net acres or wells - Refers to gross acres or wells we own multiplied, in each case, by our percentage working interest. References to net acres or wells include our proportionate share of PDCM's and our affiliated partnerships' net acres or wells. +Net production - Crude oil and natural gas production that we own, less royalties and production due to others. References to net production include our proportionate share of PDCM's and our affiliated partnerships' net production. +Non-operated - A project in which we are not the operator. +NYMEX - New York Mercantile Exchange. +Operator - The individual or company responsible for the exploration, development and/or production of an oil or gas well or lease. +Overriding royalty - An interest which is created out of the operating or working interest. Its term is coextensive with that of the operating interest. +Possible reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability to exceed the sum of proved, probable and possible reserves. When probabilistic methods are used, there must be at least a 10 percent probability that the actual quantities recovered will equal or exceed the sum of proved, probable and possible estimates. +Present value of future net revenues or (PV-10) - The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, of proved reserves calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using pricing and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. PV-10 is pre-tax and therefore a non-U.S. GAAP financial measure. +Probable reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Similarly, when probabilistic methods are used, there must be at least a 50 percent probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. +Productive well - An exploratory or developmental well that is not a dry well or dry hole, as defined above. +Proved developed non-producing reserves - Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and/or (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells. +Proved developed producing reserves or PDPs - Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods. +Proved developed reserves - The combination of proved developed producing and proved developed non-producing reserves. +Proved reserves - This term means "proved oil and gas reserves" as defined in SEC Regulation S-X Section 4-10(a) and refers to those quantities of crude oil and condensate, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +Proved undeveloped reserves or PUDs - Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. +Recomplete or Recompletion - The modification of an existing well for the purpose of producing crude oil and natural gas from a different producing formation. +Refracture - A refracture occurs when we stimulate a well by fracturing a producing zone to increase its production as well as its PDP reserves. +104 +Reserves - Estimated remaining quantities of crude oil, natural gas, NGLs and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering crude oil, natural gas and NGLs or related substances to market, and all permits and financing required to implement the project. +Royalty - An interest in a crude oil and natural gas lease or mineral interest that gives the owner of the royalty the right to receive a portion of the production from the leased acreage or mineral interest (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +Section - A square tract of land one mile by one mile, containing 640 acres. +Spud - To begin drilling; the act of beginning a hole. +Standardized measure of discounted future net cash flows or standardized measure - Future net cash flows discounted at a rate of 10%. Future net cash flows represent the estimated future revenues to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment and (ii) future income tax expense. +Stratigraphic test well - A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. +TETCO M2 - Texas Eastern Transmission Corporation M-2 receipts. +Unconventional resource(s) - Crude oil and natural gas that cannot be produced at economic flow rates in economic volumes unless the well is stimulated by a large hydraulic fracture treatment, a horizontal wellbore, or by using multilateral wellbores or some other technique to expose more of the resources to the wellbore. +Undeveloped acreage - Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas, regardless of whether such acreage contains proved reserves. +Wet gas or wet natural gas - Natural gas that contains a larger quantity of hydrocarbon liquids than dry natural gas, such as NGLs, condensate and crude oil. +Working interest - An interest in a crude oil and natural gas lease that gives the owner of the interest the right to drill and produce crude oil and natural gas on the leased acreage. It requires the owner to pay its share of the costs of drilling and production operations. +Workover - Major remedial operations on a producing well to restore, maintain or improve the well's production. +105 \ No newline at end of file diff --git a/raw/filings/0000077877/2015/0000077877-16-000070/filing_metadata.csv b/raw/filings/0000077877/2015/0000077877-16-000070/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..87236499b93cbbbd635fd69334f1cadbbc20ab2a --- /dev/null +++ b/raw/filings/0000077877/2015/0000077877-16-000070/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000077877,PDCE,"PDC ENERGY, INC.",10-K,2016-02-22,2015-12-31,2016-02-22T13:48:46.000Z,0000077877-16-000070,pdce-10kxfy15.htm,PDC ENERGY 2015 FORM 10-K,18690734,1,0,https://www.sec.gov/Archives/edgar/data/77877/000007787716000070/pdce-10kxfy15.htm,https://www.sec.gov/Archives/edgar/data/77877/000007787716000070/,2015,2015,1 diff --git a/raw/filings/0000077877/2015/0000077877-16-000070/item1.txt b/raw/filings/0000077877/2015/0000077877-16-000070/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2015/0000077877-16-000070/item13.txt b/raw/filings/0000077877/2015/0000077877-16-000070/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..3a0315d226be4caebfa510c9bfa82da383cf8403 --- /dev/null +++ b/raw/filings/0000077877/2015/0000077877-16-000070/item13.txt @@ -0,0 +1,2 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2016 Annual Stockholders' meeting and is incorporated by reference in this report. \ No newline at end of file diff --git a/raw/filings/0000077877/2015/0000077877-16-000070/item9a.txt b/raw/filings/0000077877/2015/0000077877-16-000070/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..6df63482246caea2dc23e5bf8f5fbadb2f6cd1f3 --- /dev/null +++ b/raw/filings/0000077877/2015/0000077877-16-000070/item9a.txt @@ -0,0 +1,9 @@ +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +As of December 31, 2015 , we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). Based on the results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2015 . +Management's Report on Internal Control Over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate. +Management has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2015 , based upon the criteria established in "Internal Control – Integrated Framework (2013)" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2015 . +The effectiveness of the Company's internal control over financial reporting as of December 31, 2015 , has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. +Changes in Internal Control over Financial Reporting +During the fourth quarter of 2015 , we made no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. \ No newline at end of file diff --git a/raw/filings/0000077877/2015/0000077877-16-000070/rp_note.txt b/raw/filings/0000077877/2015/0000077877-16-000070/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2015/0000077877-16-000070/rpt_disclosure.txt b/raw/filings/0000077877/2015/0000077877-16-000070/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..4f9a34ec720c56e9c8cc64aab1c1867725dc07a8 --- /dev/null +++ b/raw/filings/0000077877/2015/0000077877-16-000070/rpt_disclosure.txt @@ -0,0 +1,18 @@ +TRANSACTIONS WITH RELATED PERSONS +Related Transactions +From January 1, 2015 to the present, there was no transaction or series of transactions, nor is there any currently +proposed transaction involving an amount exceeding $120,000 in which the Company is a participant and/or in which any Director, executive officer, known holder of more than five percent of the Company’s voting securities, or any member of the +immediate family of any of the foregoing persons, had or will have a direct or indirect material interest for which disclosure is required under Item 404 of Regulation S-K. +Policies and Procedures With Respect to Transactions with Related Persons +The Board has adopted a written policy for the review, approval and ratification of transactions that involve related parties +and potential conflicts of interest. The related party transaction policy applies to each Director and executive officer of the Company, any nominee for election as a Director, any security holder who is known to own more than five percent of the +Company’s voting securities, any immediate family member of any of the foregoing persons and any corporation, firm or association in which one or more of the Company’s Directors are directors or officers, or have a substantial financial +interest. +Under our related-party transaction policy, a related person transaction is a transaction or arrangement +involving a related person in which the Company is a participant or that would require disclosure in the Company’s filings with the SEC as a transaction with a related person. The related person must disclose to the Audit Committee any +potential related person transactions and must disclose all material facts with respect to such transaction and relationship. All related person transactions so disclosed will be reviewed by the Audit Committee. In determining whether to approve or +ratify a transaction, the Audit Committee will consider the relevant facts and circumstances of the transaction, which may include factors such as the relationship of the related person with the Company, the materiality or significance of the +transaction to the Company and the business purpose and reasonableness of the transaction, whether the transaction is comparable to a transaction that could be available to the Company on an arms-length basis and the impact of the transaction on the +Company’s business and operations. +25 +Table of Contents \ No newline at end of file diff --git a/raw/filings/0000077877/2016/0000077877-17-000006/filing.txt b/raw/filings/0000077877/2016/0000077877-17-000006/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..19467fdfd6828951b12205838c98f57bc5f59751 --- /dev/null +++ b/raw/filings/0000077877/2016/0000077877-17-000006/filing.txt @@ -0,0 +1,6974 @@ +10-K +1 +pdce-10kxfy16.htm +PDCE ENERGY 2016 FORM 10-K +Document +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +T ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2016 +or +£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from __________ to _________ +Commission File Number 001-37419 +PDC ENERGY, INC. +(Exact name of registrant as specified in its charter) +Delaware +95-2636730 +(State of incorporation) +(I.R.S. Employer Identification No.) +1775 Sherman Street, Suite 3000 +Denver, Colorado 80203 +(Address of principal executive offices) (Zip code) +Registrant's telephone number, including area code: (303) 860-5800 +Securities registered pursuant to Section 12(b) of the Act: +Title of each class +Name of each exchange on which registered +Common Stock, par value $0.01 per share +NASDAQ Global Select Market +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes T No £ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes £ No T +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes T No £ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes T No £ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. £ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. +Large accelerated filer x +Accelerated filer o +Non-accelerated filer £ +(Do not check if a smaller reporting company) +Smaller reporting company o +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes £ No T +The aggregate market value of our common stock held by non-affiliates on June 30, 2016 was $2.7 billion (based on the closing price of $57.61 per share as of the last business day of the fiscal quarter ending June 30, 2016 ). +As of February 15, 2017 , there were 65,763,315 shares of our common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +We hereby incorporate by reference into this document the information required by Part III of this Form, which will appear in our definitive proxy statement to be filed pursuant to Regulation 14A for our 2017 Annual Meeting of Stockholders. +PDC ENERGY, INC. +2016 ANNUAL REPORT ON FORM 10-K +TABLE OF CONTENTS +PART I +Page +Items 1. and 2. +Business and Properties +2 +Item 1A. +Risk Factors +20 +Item 1B. +Unresolved Staff Comments +37 +Item 3. +Legal Proceedings +37 +Item 4. +Mine Safety Disclosures +37 +PART II +Item 5. +Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +38 +Item 6. +Selected Financial Data +40 +Item 7. +Management's Discussion and Analysis of Financial Condition and Results of Operations +41 +Item 7A. +Quantitative and Qualitative Disclosures About Market Risk +61 +Item 8. +Financial Statements and Supplementary Data +63 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +105 +Item 9A. +Controls and Procedures +105 +Item 9B. +Other Information +105 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +106 +Item 11. +Executive Compensation +106 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +106 +Item 13. +Certain Relationships and Related Transactions, and Director Independence +106 +Item 14. +Principal Accounting Fees and Services +106 +PART IV +Item15. +Exhibits, Financial Statement Schedules +106 +Item 16. +Form 10-K Summary +112 +Signatures +110 +Glossary of Units of Measurements and Industry Terms +111 +PART I +REFERENCES TO THE REGISTRANT +Unless the context otherwise requires, references in this report to "PDC Energy," "PDC," "the Company," "we," "us," "our," or "ours" refer to the registrant, PDC Energy, Inc., and all subsidiaries consolidated for the purposes of its financial statements, including our proportionate share of the financial position, results of operations, cash flows and operating activities of our remaining affiliated partnerships and PDC Mountaineer, LLC ("PDCM"), a joint venture owned 50 percent by PDC until its sale in October 2014 . PDC is a Delaware corporation having reincorporated from Nevada in 2015. +GLOSSARY OF UNITS OF MEASUREMENTS AND INDUSTRY TERMS +Units of measurements and industry terms are defined in the Glossary of Units of Measurements and Industry Terms, included at the end of this report. +SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS +This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding our business, financial condition, results of operations, and prospects. All statements other than statements of historical facts included in this report are "forward-looking statements" within the meaning of the safe harbor provisions of the United States ("U.S.") Private Securities Litigation Reform Act of 1995. Words such as expects, anticipates, intends, plans, believes, seeks, estimates and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements include, among other things, statements regarding future: reserves, production, costs, cash flows and earnings; drilling locations and growth opportunities; capital expenditures and projects, including expected lateral lengths of wells, drill times and number of rigs employed; rates of return; operational enhancements and efficiencies; management of lease expiration issues; financial ratios; and midstream capacity and related curtailments. +The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this report or accompanying materials, we may use the terms “projection” or similar terms or expressions, or indicate that we have “modeled” certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or the industry in periods beyond the current fiscal year. Because such statements relate to events or conditions further in the future, they are subject to increased levels of uncertainty. +Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to: +• +changes in worldwide production volumes and demand, including economic conditions that might impact demand; +• +volatility of commodity prices for crude oil, natural gas, and natural gas liquids ("NGLs") and the risk of an extended period of depressed prices; +• +reductions in the borrowing base under our revolving credit facility; +• +impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement related to those laws and regulations, liabilities arising thereunder, and the costs to comply with those laws and regulations; +• +declines in the value of our crude oil, natural gas, and NGLs properties resulting in further impairments; +• +changes in estimates of proved reserves; +• +inaccuracy of estimated reserves and production rates; +• +potential for production decline rates from our wells being greater than expected; +• +timing and extent of our success in discovering, acquiring, developing, and producing reserves; +• +availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production and the impact of these facilities and regional capacity on the prices we receive for our production; +• +timing and receipt of necessary regulatory permits; +• +risks incidental to the drilling and operation of crude oil and natural gas wells; +• +losses from our Gas Marketing segment exceeding our expectations; +• +difficulties in integrating our operations as a result of any significant acquisitions, including our recent acquisitions in the Delaware Basin; +• +increases or changes in operating costs, severance and ad valorem taxes, and increases or changes in drilling, completion and facilities costs; +• +increases or adverse changes in construction costs and procurement costs associated with future build out of mid-stream related assets; +• +future cash flows, liquidity, and financial condition; +• +competition within the oil and gas industry; +• +availability and cost of capital; +• +our success in marketing crude oil, natural gas, and NGLs; +1 +• +effect of crude oil and natural gas derivatives activities; +• +impact of environmental events, governmental and other third-party responses to such events, and our ability to insure adequately against such events; +• +cost of pending or future litigation; +• +effect that acquisitions we may pursue have on our capital investments; +• +our ability to retain or attract senior management and key technical employees; and +• +success of strategic plans, expectations and objectives for our future operations. +Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under Item 1A, Risk Factors , made in this report and our other filings with the U.S. Securities and Exchange Commission ("SEC") for further information on risks and uncertainties that could affect our business, financial condition, results of operations and cash flows. We caution you not to place undue reliance on forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement. +ITEMS 1. AND 2. BUSINESS AND PROPERTIES +The Company +We are a domestic independent exploration and production company that acquires, produces, develops, and explores for crude oil, natural gas, and NGLs. Our operations are located in the Wattenberg Field in Colorado; the Utica Shale in southeastern Ohio; and, with the closing of our $1.76 billion acquisitions of proved producing, proved undeveloped, and unproved leaseholds in December 2016, in the Delaware Basin in Texas (see "Business Strategy - Strategic acquisitions" below). +As of December 31, 2016 , we own an interest in approximately 2,900 gross ( 2,400 net) productive wells, of which approximately 25 percent are horizontal. We operate 88 percent of the wells in which we have an interest. We produced 22.2 MMBoe in 2016, including 0.2 MMBoe contributed from the newly acquired Delaware Basin assets, representing an increase of 44 percent compared to 2015. For the month ended December 31, 2016, we maintained an average production rate of 73 MBoe per day. This exit rate represents a 42 percent increase from December 2015. We were able to achieve this strong growth rate while maintaining a robust liquidity position, comprised of cash and cash equivalents and available capacity under our revolving credit facility totaling $932.4 million as of December 31, 2016 . Our debt to EBITDAX ratio as of December 31, 2016, as defined in our revolving credit facility agreement, was 2.10 to 1.00, well within our compliance limit of 4.00 to 1.00. As of December 31, 2016 , we had 341.4 MMBoe of proved reserves, 29 percent of which are proved developed, including 32.5 MMBoe related to acquisitions of properties in the Delaware Basin. Approximately 59 percent of our reserves at December 31, 2016 are liquids, which includes crude oil and NGLs. Our 341.4 MMBoe of total proved reserves as of December 31, 2016 , represented an increase of 68.6 MMBoe, or 25 percent , relative to December 31, 2015 . Our proved reserve additions were primarily a result of: 1) the development of longer lateral length well bores with higher working interests in the Wattenberg Field, which was driven by technology advancements, together with the ability to consolidate our leasehold position, and 2) the acquisitions of properties in the Delaware Basin. +Our Strengths +• +Multi-year project inventory in premier crude oil, natural gas, and NGLs plays. We have a significant operational presence in two premier U.S. onshore basins providing us with approximately 2,600 potential horizontal drilling locations from our total proved and unproved leasehold. The primary focus for development is currently in the Wattenberg Field and the Delaware Basin. We believe that our inventory of drilling locations, the majority of which reflect 4,000 to 10,000 foot horizontal laterals, will allow us to continue to grow our proved reserves and production at attractive rates of return utilizing our current internal long-term commodity price projections and our current expected cost structure. Our 2017 drilling and completion operations are expected to specifically focus on the middle core of the Wattenberg Field and our newly acquired Delaware Basin assets. In the Wattenberg Field, we have identified a substantial inventory consisting of approximately 700 proved undeveloped horizontal drilling locations and an additional approximately 1,100 probable horizontal drilling locations. Through our acquisitions in the Delaware Basin, we added approximately 20 proved undeveloped horizontal drilling locations, which were included in the 785 gross potential drilling locations that were identified on our 62,500 net acres of leasehold. At the time of the initial acquisition, our undeveloped location count was based on wells expected to be drilled with horizontal lateral lengths ranging from 4,000 to 10,000 horizontal feet. We believe that with additional development and exploration activity, together with advances in technology, we may be able to access additional productive zones in the Delaware Basin, which could significantly increase our inventory of undeveloped locations. +• +Strong liquidity position. As of December 31, 2016 , we had a total liquidity position of $932.4 million , comprised of $244.1 million of cash and cash equivalents and $688.3 million available for borrowing under our revolving credit facility. During 2016, we raised in excess of $1.4 billion of new capital, net of issuance costs. +• +In March 2016, we raised $296.6 million , net of issuance costs, from the sale of 5.9 million shares of common stock. +• +In September 2016, we issued 9.1 million shares of common stock for net proceeds of $558.5 million , $400.0 million of 6.125% senior unsecured notes due in 2024 ("2024 Senior Notes") for net proceeds of $392.2 million , and $200.0 million of 1.125% convertible senior notes due in 2021 for net proceeds of $193.9 million . +2 +• +We also issued 9.4 million shares of common stock valued at $690.7 million in December 2016 as partial consideration to the sellers for the initial Delaware Basin acquisition. +• +In December 2016, we increased the aggregate commitment under our revolving credit facility to $700 million. +We intend to continue to manage our liquidity position through investment in projects with attractive rates of return, protection of cash flows on a portion of our anticipated sales through the use of an active commodity derivative program, and access to capital markets from time to time. +• +Balanced and diversified portfolio across two premier U.S. onshore basins. We believe we have multiple years of attractive drilling opportunities in both the Wattenberg Field and the Delaware Basin. The completion of the acquisitions of Delaware Basin properties provides us the ability to allocate capital between the two basins to diversify our risk. We expect that this will improve overall economic results and drive our future production and reserve growth. We believe that we will be able to transfer much of our management expertise gained over the years in the Wattenberg Field to the newly acquired Delaware Basin assets. The successful development and exploitation of the acquired leasehold in the Delaware Basin will include execution of our asset integration plan, which consists of transferring our technological expertise to the Delaware Basin, beginning down spacing initiatives, testing various completion designs, successfully developing multiple benches, maintaining an intense focus on cost structure, and utilizing existing personnel and retaining experienced staff. Additionally, we expect the increased geographical diversity of our portfolio to mitigate risks associated with a single dominant producing area, as each basin will have its own operating and competitive dynamic in terms of commodity price markets, service cost areas, takeaway capacity, and regulatory and political considerations. +• +Significant operational control in our core areas. We have, and expect to continue to have, a substantial degree of operational control over our properties. As a result of successfully executing our strategy of acquiring largely concentrated acreage positions with a high working interest, we operate and manage approximately 88 percent of all wells in which we have an interest across all of our operating basins. Our control allows us to manage our drilling, production, operating and administrative costs, and to leverage our technical expertise in our core operating areas. Our leaseholds that are held-by-production further enhance our operational control by providing us flexibility in selecting drilling locations based upon various operational criteria. +In the Wattenberg Field, our operational control is attributable to our high working interest leasehold and large contiguous acreage blocks, which have been enhanced as a result of a 2016 acreage trade, and because substantially all of our Wattenberg Field acreage is held-by-production. We remain flexible in terms of rig activity and capital deployment due to short-term rig contracts and we are confident in our ability to manage held-by-production acreage in the Wattenberg Field in order to maintain our current level of operational control. As a result, we can adjust our drilling plans if commodity prices deteriorate in order to manage cash flows from operations relative to cash flows from investing activities. +In the Delaware Basin, our average working interest in our properties is approximately 92 percent and we operate nearly 100 percent of those properties. Additionally, we own and operate certain midstream assets in the Delaware Basin and believe this will allow for timely system expansion, well connections, water supply for completion operations, and water disposal. Approximately 30 percent of the properties acquired in the Delaware Basin were held-by-production as of December 31, 2016. The leaseholds in the Delaware Basin require a more active drilling program than in the Wattenberg Field, and in certain cases, continuous operations to maintain the underlying leaseholds. With our high percentage of operated leaseholds in the Delaware Basin, we expect to have adequate control over the location and pace of our development to manage lease expiration issues. While we believe that our current Delaware Basin drilling plan should meet these obligations for the next few years, in the event that we do not meet the obligations for certain leases, we anticipate that we will make any necessary bonus extension payments, or we will seek to renew or, re-lease in order to retain the leases. However, the payments required to do so may be significant and we may not be successful in such efforts. +• +Utilizing technology to focus on efficiency. In the Wattenberg Field, we have a proven track record of continuing improvement in both costs and productivity of our existing well operations. Our efficiencies are driven by a focus on the use of multi-well pad drilling, extended reach lateral well development, increased fracture stimulation stage density, enhanced fracture stimulation completion design, and improved drilling efficiencies. In 2016, approximately 65 percent of our Wattenberg Field horizontal well spuds were mid- or extended-reach laterals that ranged from approximately 7,000 to 9,500 horizontal feet in length. We have implemented plug-and-perforation completion techniques on all new wells, and increased the number of completion stages to provide a potential uplift to our new well production. We also began using a mono-bore drilling design to reduce drill times and well costs. Through the combination of these techniques, our drilling team has improved our drilling efficiencies with average drill results increasing to approximately 2,200 feet drilled per day in 2016 from approximately 1,800 feet drilled per day in 2015. We believe that we can generate substantial value by leveraging and applying our operating experience in the Wattenberg Field and the Utica Shale to our Delaware Basin properties. +• +Commodity derivative program. Our active use of commodity derivative instruments to protect our investment returns and cash flows was particularly important through the severe commodity price downturn in 2015 and 2016. We have continued this program and have entered into commodity derivative instruments to mitigate a portion of our short-term future exposure to commodity price fluctuations, including crude oil and natural gas collars, fixed-price swaps, and basis swaps. While our commodity derivative program limits the upside benefits we may otherwise receive during periods of higher commodity prices, the program helps protect a portion of our cash flows, borrowing base, and liquidity during periods of depressed commodity prices. We strive to scale our +3 +overall hedging position to be appropriate relative to our current and expected level of indebtedness and consistent with our goals of preserving balance sheet strength and substantial liquidity, as well as our internal price view. In 2016 and 2015, net settled derivatives contributed a significant portion of our cash flows from operating activities, thereby mitigating the effect of the depressed commodity prices. Based upon our hedge position at forward strip pricing at year-end 2016, our derivatives are now in a net liability position of $70.0 million . Therefore, because of the normal settlement of our higher value derivatives that occurred in 2015 and 2016, and because our remaining unsettled derivative contracts have future settlement prices closer to the current forward price curve, the settlement of these instruments are not expected to be a significant source of cash flow, and may result in cash outflows in 2017 and 2018. +As of December 31, 2016, we had commodity derivatives positions covering approximately 8.5 MMBbls and 4.9 MMBbls of crude oil production for 2017 and 2018, respectively. As of the same date, we had hedged approximately 35.2 Bcf and 46.5 Bcf of natural gas production for 2017 and 2018, respectively. The details of these transactions are described in the footnotes to our consolidated financial statements included elsewhere in this report. We do not currently have any commodity derivatives for any of our NGL production. +• +Strong environmental, health and safety compliance programs, and community outreach. We have focused on establishing effective environmental, health and safety programs that are intended to promote safe working practices for our employees and contractors and to help earn the trust and respect of land owners, regulatory agencies, and public officials. We believe this is an important part of our strategy in competing in today’s intensive regulatory and public debate climate. We are also dedicated to being an active and contributing member of the communities in which we operate. We share our success with these communities in various ways, including charitable giving and community event sponsorships. +• +Strong management team and operational capabilities. We have strong and stable management, led by our executive management team. Each member of the team has between 10 and 30 years of experience in the energy and natural resource industry. This experience collectively spans expertise in land, reservoir analysis, operations, accounting, finance, strategy, and general operations, and has helped us continue our growth through periods of commodity price pressure, cost inflation, and challenging operating environments. +Business Strategy +Our long-term business strategy focuses on generating stockholder value through the acquisition, exploration, and development of crude oil and natural gas properties. We are focused on the growth of our reserves, production, and cash flows through organic exploration and development of our existing and acquired leasehold in our horizontal drilling programs. Our operational focus is concentrated with a substantial presence in two basins. We pursue various midstream, marketing, and cost reduction initiatives designed to increase our per unit operating margins while maintaining a disciplined financial strategy focused on providing sufficient liquidity and balance sheet strength to execute our business strategy. +We focus on horizontal development drilling programs in resource plays that offer repeatable results and the potential for attractive returns on investment in a range of commodity price environments. Our inventory of drilling locations supports our planned organic growth over the next several years. We expect our drilling and completion activity to drive increases in proved reserves, production, and cash flows. In addition to development drilling, we routinely review acquisition and acreage swap opportunities in our core areas of operations. We believe we can extract additional value from such transactions through production optimization opportunities and increases in our working interests in our development drilling locations afforded by more concentrated acreage positions. As a result, once we have established a significant presence in an area, the use of bolt-on acquisitions and acreage trades can potentially provide synergies that result in additional economies of scale. We also pursue a limited and disciplined exploration program with the goal of replenishing our portfolio with new exploration projects capable of positioning us for significant production and reserve growth in future years. +4 +Development drilling +The following map presents the general locations of our development and production activities as of December 31, 2016 : +Our leasehold interests covers properties with developed and undeveloped crude oil, natural gas, and NGLs resources. We own approximately 2,900 gross ( 2,400 net) wells in our three operating basins. Our previously-announced 2017 capital investment program contemplates expenditures of between $725 million and $775 million. Due to recent cost escalation for services in our core areas and the modification of our drilling schedule in the Delaware Basin, where we have accelerated the deployment of an additional drilling rig, we currently expect that our 2017 capital investment will be at or near the high end of the range. These changes to our capital investment outlook are not expected to impact our 2017 production estimate, as the incremental well drills are contemplated to be turned-in-line to sales late in the year. +We have allocated substantially all of our 2017 capital investment program to our higher-return projects in the Wattenberg Field and Delaware Basin, and have elected to defer drilling operations in the Utica Shale. Based on our current production and commodity price outlook for 2017, we continue to expect capital investments to exceed cash flows from operations by approximately $200 million. Our debt to EBITDAX ratio, as defined in our revolving credit facility agreement, is expected to decrease in 2017 based on production and operational cash flow growth. A deterioration of commodity prices could negatively impact our results of operations, financial condition, and future development plans. We may increase or decrease our 2017 capital investment program during the year as a result of, among other things, changes in commodity prices or our current internal long-term outlook for commodity prices, requirements to hold acreage, the cost of services for drilling and well completion activities, drilling results, changes in our borrowing capacity, a significant change in cash flows, regulatory issues, requirements to maintain continuous activity on leaseholds or acquisition and/or divestiture opportunities. If such changes result in our election to deploy additional capital investment, amounts may further exceed our cash flow from operations. +Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays. Based on our current drilling program, we have an inventory of 700 gross proved undeveloped horizontal drilling locations and approximately 1,100 gross probable horizontal drilling locations. These locations are in the core Wattenberg Field, which is further delineated between the inner, middle, and outer core. In 2017, we expect to continue to realize additional capital efficiencies through drilling extended length laterals, an increased number of fracturing stages, plug-and-perforation completions, enhanced well orientation, and mono-bore drilling. We plan to drill standard reach lateral (“SRL”), mid-length lateral (“MRL”), and extended reach lateral (“XRL”) wells in 2017, the majority of which will be in the middle core area of the field. Wells in the Wattenberg Field typically have productive horizons at depths of approximately 6,500 to 7,500 feet below the surface. In 2017, to help balance our priorities, we now anticipate spudding 137 operated wells and turning-in-line to sales, approximately 139 horizontal operated wells as outlined below . +5 +SRL +MRL +XRL +Estimated average lateral length (in feet) +4,200 +6,900 +9,500 +Expected drilling days (spud-to-spud) +7 +10 +12 +Estimated percentage of 2017 wells spud +31% +33% +36% +Estimated percentage of 2017 wells turned-in-line +35% +30% +35% +Estimated cost per well (in millions) +$2.5 +$3.5 +$4.5 +The 2017 capital investment outlook is now approximately $470 million in the Wattenberg Field and anticipates a three to four-rig drilling program based on our current commodity price outlook. Approximately $460 million of our 2017 capital investment program is expected to be invested in development activities in the Wattenberg Field, comprised of approximately $440 million for our operated drilling program and approximately $20 million for wells drilled and operated by others. The remainder of the Wattenberg Field capital investment program is expected to be used for miscellaneous workover and capital projects. +Delaware Basin. In December 2016, we closed a series of acquisitions providing us a total of approximately 62,500 net acres in Reeves and Culberson Counties, Texas (see “ Business Strategy - Strategic acquisitions ” below). In 2017, our investment outlook now contemplates operating a two-rig to four-rig program at various times throughout the year and deploying the third rig in late Februay 2017. Total capital investment in the Delaware Basin is estimated to be $300 million, of which approximately $235 million is allocated to spud 31 wells and turn-in-line an estimated 26 wells. Based on the timing of our operations and the requirements to hold acreage, we may adapt our capital investment program to drill wells in addition to those currently anticipated, as we are continuing to analyze the terms of the leaseholds related to our recent acquisitions of properties in the basin. We plan to drill 20 wells in our eastern acreage block, nine wells in our central acreage block, and two wells in our western acreage block, with the majority of wells targeting the Wolfcamp A and B zones. Of the 26 planned turn-in-lines, 14 are expected to have laterals of approximately 10,000 horizontal feet with completion stages currently expected to range from approximately 100 to 125 feet. Similarly spaced completions are anticipated for the remaining 12 turn-in-lines. Wells in the Delaware Basin typically have productive horizons at depths of approximately 9,000 to 11,000 feet below the surface. Estimated well costs for SRL, MRL, and XRL wells are approximately $7.1 million, $8.8 million and $10.5 million, respectively. We plan to invest approximately $35 million for leasing, seismic, and technical studies with an additional $30 million for midstream related projects including gas connections, salt water disposal wells, and surface location infrastructure . +Utica Shale . At this time, we are currently evaluating all of our strategic alternatives with respect to our Utica Shale position. As a result of such evaluation, we are deferring our 2017 planned expenditure of $18 million to drill, complete, and turn-in-line two wells in Guernsey County. In 2017, our capital investment program for the Utica Shale is expected to include between $2 million to $3 million for additional leasing. Such leasing may be necessary to complete certain drilling operations if we decide to continue development of our existing position in the northern portion of our acreage. +Strategic acquisitions +As part of our overall growth strategy, we examine and evaluate acquisition opportunities as they present themselves and pursue those that meet our strategic plan and that we believe will increase stockholder value. We seek properties with large undeveloped drilling upside where we believe we can utilize our operational expertise to grow production and proved reserves. In addition, we may pursue opportunities to trade acreage with other producers or complete small bolt-on acquisitions in order to optimize our portfolio by consolidating and concentrating our core assets. The creation of large, contiguous acreage blocks through the trading of properties or bolt-on acquisitions provides the opportunity to optimize drilling activities and add more extended-reach lateral wells to our drilling program, while increasing our working interests in the related wells. We have an experienced team of management, engineering, geosciences, and commercial professionals who identify and evaluate acquisition opportunities. Our acquisition activity in 2017 is expected to be focused on our two most significant assets, the Wattenberg Field and Delaware Basin . +Delaware Basin. We recently engaged in the process of searching for and evaluating a large-scale acquisition in a new U.S. onshore basin capable of creating material long-term value-added growth, focusing on four key criteria: top-tier acreage in core geologic positions, significant drilling inventory with additional expansion through down spacing, portfolio optionality for capital allocation and diversification, and the ability to deliver long-term increases in net asset value per share. Having determined that they met these criteria, in December 2016, we closed the purchases of an aggregate of approximately 62,500 net acres, in Reeves and Culberson Counties, Texas, through two transactions, for an aggregate consideration to the sellers of approximately $1.76 billion . +• +The first transaction consisted of the acquisition of certain producing properties and approximately 57,900 acres for approximately $952.1 million in cash and the issuance of 9.4 million shares of our common stock valued at approximately $690.7 million at the time the acquisition closed, for total consideration of approximately $1.64 billion . +• +The second transaction occurred shortly thereafter and included certain developed assets and 4,600 net acres of undeveloped leasehold that is complementary to the initial transaction. This transaction was paid for in cash of $120.6 million . +The the purchase prices for the acquisitions remain subject to certain post-closing adjustments as of the date of this report. We expect that it may take into mid-2017 until all post-closing adjustments are settled. See footnotes titled Properties and Equipment - Delaware +6 +Basin Acreage Acquisition and Business Combination to our consolidated financial statements included elsewhere in this report for further information regarding these two acquisitions. +Selective exploration +Historically, we have pursued a disciplined exploration program intended to replenish our portfolio and to position us for production and reserve growth in future years. When doing so, we attempt to identify potential plays in their early stages in order to accumulate significant leasehold positions prior to competitive forces driving up the cost of entry and to invest in leasehold positions that are near existing or emerging midstream infrastructure. Our contemplated near-term exploration activity will be occurring in the Delaware Basin as there are multiple zones that have not seen development activity sufficient to record proved reserves. Such zones could provide additional potential drilling locations and/or proved reserves. +Business Segments +We divide our operating activities into two segments: (1) Oil and Gas Exploration and Production and (2) Gas Marketing. +Oil and Gas Exploration and Production +The results of our Oil and Gas Exploration and Production segment primarily reflect revenues and expenses from the production and sale of crude oil, natural gas, and NGLs, commodity price risk management, and well operations. The exploration for and production of crude oil, natural gas, and NGLs involves the acquisition or leasing of mineral rights and related surface rights. Prior to development of these properties, we assess the economic viability of potential well development opportunities. We then develop the reserves through the permitting, drilling and completion of oil and gas wells, which are then turned-in-line to sales and production. Following completion, we operate and maintain the producing wells while managing associated production, operating, and transportation costs. At the end of a well's economic life, the well is plugged and surface disturbances surrounding the well and producing facilities are remediated. The Oil and Gas Exploration and Production segment's most significant customers are Suncor Energy Marketing, Inc., DCP Midstream, LP ("DCP"), Aka Energy Group, LLC ("Aka"), Concord Energy, LLC, and Bridger Energy, LLC. Sales to each of these parties constitute more than 10 percent of our revenues in 2016. We believe that the loss of any purchaser or the aggregate loss of several customers could be managed by selling to alternative purchasers given the liquidity in the market for the sale of hydrocarbons. +Within the Oil and Gas Exploration and Production Segment, our crude oil, natural gas, and NGLs production is gathered, marketed and sold as follows: +• +Crude oil. In the Wattenberg Field, our crude oil is sold under various purchase contracts with monthly and longer term pricing provisions based on New York Mercantile Exchange ("NYMEX") pricing, adjusted for differentials. Since we do not refine any of our crude oil production, we sell to companies that either transport or resell the commodity, or process the crude oil in their own facilities. Title to the crude oil transfers at the time the crude oil leaves our lease site and is either placed in a truck or enters a pipeline. We have entered into commitments ranging in term from one month to over three years to deliver crude oil to competitive markets, resulting in improved average overall deductions of $4.39 for 2016 compared to $9.95 for 2015. During 2016, there was sufficient take away capacity in the Wattenberg Field for crude oil. This was a function of decreases in drilling activity and corresponding decreases in production from other producers, and the completion of additional crude oil pipelines to the Cushing, Oklahoma market. We believe that there will continue to be adequate take away capacity for crude oil through either pipeline or trucking options in the Wattenberg Field in the near- and mid-term. We continue to pursue various alternatives with respect to crude oil transportation, with a view toward further improving pricing and increasing the amount of crude oil transported by pipeline and limiting our use of trucking. For example, in mid-2015, we began delivering crude oil in accordance with our long term commitment to the White Cliffs Pipeline, LLC ("White Cliffs") pipeline. Our volume of crude oil sales going through the White Cliffs pipeline in 2016 was 16 percent of our Wattenberg Field crude oil production compared to 23 percent during the second half of 2015. By having a variety of off-take arrangements, we seek to optimize our marketing to result in the best possible net realized price per barrel. The White Cliffs agreement is one of several we have entered into to facilitate deliveries of a portion of our crude oil to the Cushing, Oklahoma market. In addition to the White Cliffs agreement, we have signed a long-term agreement with Saddle Butte Rockies Midstream, LLC for gathering of crude oil at the wellhead by pipeline from several of our producing pads in the Wattenberg Field, with a view toward minimizing truck traffic, increasing reliability, reducing the overall physical footprint of our well pads, and reducing emissions. We began delivering crude oil into this pipeline during the fourth quarter of 2015. The system became fully operational in 2016 and we did not experience any subsequent curtailment of operations due to lack of takeaway capacity for crude oil in the basin. We do not expect to experience any curtailments in 2017. +In the Delaware Basin, our crude oil production is sold at the wellhead and transported via trucks to pipelines that deliver the oil to the Midland, Texas, crude oil market. Given the increased level of activity in the form of acquisitions, leasing, and the increases in rig count in the Delaware Basin over the last six months, we expect the balance between production and pipeline takeaway capacity to tighten during 2017. At the current time, there are pipeline, truck and rail pathways out of the basin, all of which are available to us. We are evaluating near-term and longer-term solutions that contemplate the increased activity levels we expect, as well as our anticipated future production. These may include longer-term sales agreements. +7 +In the Utica Shale, crude oil and condensate is sold to local purchasers at each individual well site based on NYMEX pricing, adjusted for differentials, and is typically transported by the purchasers via truck to local refineries, rail facilities, or barge loading terminals on the Ohio River. To date, we have not experienced any significant issues with take away capacity in this region for our crude oil. +• +Natural gas. We sell substantially all of our natural gas to midstream service providers and marketers. We have entered into firm gathering and processing agreements for all of our natural gas production in the Wattenberg Field to ensure there is infrastructure available to process the gas and deliver our product to market. In the Wattenberg Field, the majority of our leasehold is dedicated to our primary midstream provider, DCP, which gathers and processes natural gas produced in the basin and sells our residue gas to various markets. We also sell natural gas into a system owned and operated by Aka, and have committed production from dedicated acreage and a drilling program with a specific number of wells to be drilled and completed by the end of 2017. Pursuant to the agreement, Aka is required to install and operate, or contract for the use of, facilities necessary to receive and purchase the production volumes committed under the agreement. +In the Wattenberg Field, title to the natural gas transfers at the custody transfer meter located at our wellheads, except when we have multiple wells being gathering to a common pad, in which case the natural gas is sold as it passes through the custody transfer meter located on our well pads after water and crude oil have been separated from the natural gas stream. Our Wattenberg Field natural gas is transported through third-party gathering systems and pipelines where we incur gathering, processing, and transportation expenses via percent-of-proceeds ("POP") contracts whereby the gatherer/processor markets the natural gas and NGLs on a best efforts basis and then retains a portion of the revenue attributable to the residue gas and NGL sales. Substantially all of the natural gas that we produce in the Wattenberg Field is sold by the midstream service providers and is priced based on Colorado Interstate Gas ("CIG") or local distribution company monthly/daily pricing provisions. There have been periods in the past where transportation of natural gas was a significant issue, however, such has not been the case recently based on pipeline and development activity by midstream providers, as well as relatively decreased activity levels by other operators in the other areas of the Wattenberg Field. We anticipate gathering system pressures to vary throughout the year, with increases coinciding with the warmer summer months. We plan for these increases and work with our mid-stream providers to manage production during these times. There was a new processing plant built in the portion of the Wattenberg Field in mid-2015 that provided significant relief and when coupled with the overall decrease in activity in the field near our operations, we did not experience any curtailments in 2016. We recently signed a contract to support a midstream provider's construction of an additional processing plant in the area. This midstream provider expects the plant to be placed into service towards the end of 2018. If the midstream provider is delayed in its expansion efforts, we could experience higher line pressures which could impact our production volumes. In 2016, approximately 90 percent of our production in the Wattenberg Field was delivered from horizontal wells, with the remaining 10 percent coming from vertical wells. The horizontal wells are less prone to issues than the vertical wells in that they are newer and have greater producing capacity and higher formation pressures and therefore tend to be more resilient from periodic gas system pressure issues. Based on the expected activity levels and production in the region coupled with the current and committed construction activities in the area, we anticipate that we will have adequate takeaway capacity in the region for the next few years. +In the Delaware Basin, title to the natural gas transfers at the delivery point off of our gathering systems. In certain cases, we are paid the total value of the natural gas and the value of the NGLs processed by the purchasers, and we pay specific processing costs or fees. In other cases, we incur gathering, processing, and transportation expenses via POP contracts whereby the gatherer/processor retains a portion of the revenue attributable to the residue gas and NGL sales. Our Delaware Basin midstream service providers sell the residue gas at prices based on indexed prices per MMBtu using either the Waha or El Paso Permian monthly and daily price provisions. These index prices are established monthly and daily in the gas trading market, and represent the value of the natural gas delivered to the NYMEX Henry Hub delivery point, net of the transportation and margin embedded in the basis differential. +In the Utica Shale, natural gas produced in our northern acreage is gathered and processed pursuant to a firm gathering and processing agreement with MarkWest Utica EMG ("MarkWest") under a fee based contract, while natural gas produced in our southern acreage is gathered and processed by Blue Racer Midstream LLC ("Blue Racer"), also under a fee based contract. As a result, we receive the full revenue stream attributable to the residue gas and NGL sales, less the applicable gathering and processing fees. The natural gas sales from both the Blue Racer plant and the MarkWest plant are based on TETCO M-2 index pricing per MMbtu delivered to the plant. We anticipate that the significant Appalachian pipeline differentials that impact our Utica Shale natural gas, which make economics challenging, will continue to be highly volatile into 2017. +• +NGLs. Our NGL sales are priced based upon the components of the product and are correlated to the price of crude oil. In the Wattenberg Field, all of our NGLs are sold by the midstream service provider at the tailgate of the processing plants based on a combination of prices from the Conway hub in Kansas and Mt. Belvieu in Texas where the NGLs are marketed. +As noted above, the value of the NGLs extracted from the natural gas by our midstream providers in the Delaware Basin is based on processing contracts. Based on the percentage of NGLs in the natural gas stream, we receive the net proceeds of the NGLs processed by the midstream providers as sold into the Mt. Belvieu market. +8 +In the Utica Shale, our NGLs are fractionated and marketed by MarkWest and Blue Racer and sold based on month-to-month pricing in various markets. Our NGL production is sold by our midstream service providers under both short- and long-term contracts. +Gas Marketing +Our Gas Marketing segment is comprised solely of the operating activities of our wholly-owned subsidiary Riley Natural Gas ("RNG"). RNG specializes in the purchase, aggregation, and sale of natural gas production in the Appalachian Basin. The natural gas is marketed to third-party marketers, natural gas utilities, and industrial and commercial customers through transportation services provided by regulated interstate/intrastate pipeline companies. RNG is party to long-term firm transportation, sales, and processing agreements for pipeline capacity through August 2022. RNG acquired these firm transportation rights and associated agreements at a time when PDC owned operating interests in oil and natural gas wells through a joint venture in the Appalachian Basin referred to as PDCM. Although PDC sold its interest in PDCM in 2014, RNG retained the majority of its firm natural gas transportation commitment. Financial results from our gas marketing segment have resulted in an operating loss contribution of $1.5 million , $0.8 million , and $0.4 million , for 2016, 2015, and 2014, respectively. As of December 31, 2016, the amount owed for this long-term firm transportation, sales and processing agreement was approximately $19.1 million. This long-term pipeline capacity commitment was made on behalf of our third-party producers, and also includes an unutilized portion; however, we remain obligated to fulfill this commitment regardless of whether or not our third-party producers meet their commitments. As natural gas prices remain depressed, certain third-party producers under our Gas Marketing segment have continued to experience financial distress, which has led to certain contractual defaults and litigation; however, to date, no counterparty default losses have been material to us. As of December 31, 2016, we recorded an allowance for doubtful accounts of approximately $1.3 million associated with such activity. We have initiated several legal actions for breach of contract, collection, and related claims against certain third-party producers, which have to date resulted in two default judgments. We expect RNG's expenses to exceed its revenues by approximately $1 million to $2 million per year through 2022, assuming a continuation of current economic conditions. After the long-term firm transportation agreements expire, we expect to discontinue this segment. +For additional information regarding our business segments, see the footnote titled Business Segments to our consolidated financial statements included elsewhere in this report. +Properties +Productive Wells +The following table presents our productive wells: +Productive Wells +As of December 31, 2016 +Crude Oil +Natural Gas +Total +Operating Region/Area +Gross +Net +Gross +Net +Gross +Net +Wattenberg Field +669 +436.8 +2,193 +1,908.0 +2,862 +2,344.8 +Delaware Basin +33 +31.5 +— +— +33 +31.5 +Utica Shale +27 +22.2 +3 +3.0 +30 +25.2 +Total productive wells +729 +490.5 +2,196 +1,911.0 +2,925 +2,401.5 +9 +Proved Reserves +The following table presents our proved reserve estimates as of December 31, 2016 , based on reserve reports prepared by our independent petroleum engineering consulting firms, Ryder Scott Company, L.P. ("Ryder Scott"), and Netherland, Sewell & Associates, Inc. ("NSAI"), and related information: +Proved Reserves at December 31, 2016 +Proved Reserves (MMBoe) +% of Total Proved Reserves +% Proved Developed +% Liquids +Proved Reserves to Production Ratio (in years)(1) +2016 Production (MBoe) +Wattenberg Field +305.3 +89 +% +29 +% +58 +% +14.6 +20,945 +Delaware Basin +32.5 +10 +% +22 +% +68 +% +15.2 +178 +Utica Shale +3.6 +1 +% +100 +% +56 +% +3.4 +1,053 +Total proved reserves +341.4 +100 +% +29 +% +59 +% +16.2 +22,176 +(1) As the Delaware Basin properties were purchased in December 2016, we annualized the calculation for the Delaware Basin ratio - +based on December production. +Our proved reserves are sensitive to future crude oil, natural gas, and NGLs sales prices and the related effect on the economic productive life of producing properties. Increases in commodity prices may result in a longer economic productive life of a property or result in recognition of more economically viable proved undeveloped reserves, while decreases in commodity prices may result in negative impacts of this nature. +All of our proved reserves are located onshore in the U.S. Our proved reserve estimates are prepared using the definitions for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a) and other applicable SEC rules. As of December 31, 2016 , our proved reserves, including our proportionate share of our affiliated partnerships' reserves, in the Wattenberg Field and Utica Shale have been estimated by Ryder Scott and our reserves in the Delaware Basin were estimated by NSAI. Both Ryder Scott and NSAI are independent professional engineering firms. +We have a comprehensive process that governs the determination and reporting of our proved reserves. As part of our internal control process, our reserves are reviewed annually by an internal team composed of reservoir engineers, geologists, land and accounting personnel for adherence to SEC guidelines through a detailed review of land and account records, available geological and reservoir data, and production performance data. The process includes a review of applicable historical costing, working and net revenue interests, and performance data. The internal team compiles the reviewed data and forwards the data to Ryder Scott and NSAI. +When preparing our reserve estimates, neither Ryder Scott nor NSAI independently verifies the accuracy and completeness of information and data furnished by us with respect to ownership interests, production volumes, well test data, historical costs of operations and development, product prices or any agreements relating to current and future operations of properties, and sales of production. Ryder Scott and NSAI prepare estimates of our reserves in conjunction with an ongoing review by our engineers. A final comparison of data is performed to ensure that the reserve estimates are complete, determined pursuant to acceptable industry methods and with a level of detail we deem appropriate. The final estimated reserve reports are those as prepared by Ryder Scott and NSAI and are reviewed by our engineering staff and management prior to issuance by the independent professional reserve engineering firms. +The professional qualifications of our internal lead engineer primarily responsible for overseeing the preparation of our reserve estimates, as defined in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the Society of Petroleum Engineers, qualifies this individual as a Reserve Estimator. This person holds a Bachelor of Science degree in Petroleum and Chemical Refining Engineering with a minor in Petroleum Engineering, has over 40 years of experience in reservoir engineering, is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers, and is a registered Professional Engineer in the State of Colorado. +The SEC's reserve rules allow the use of techniques that have been proved effective by evaluation of actual production from projects in the same reservoir or an analogous reservoir or by other observational evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. We used a combination of performance methods, including decline curve analysis and other computational methods, offset analogies, and seismic data and interpretation to calculate our reserve estimates. All of our proved undeveloped reserves conform to the SEC five-year rule requirement as all proved undeveloped locations are scheduled, according to an adopted development plan, to be drilled within five years of each location’s initial booking date. The SEC has also established that pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of month prices for the preceding 12 months. The NYMEX prices used in preparing the reserves are then adjusted by the required adjustments related to energy content, location and basis differentials, and other marketing deductions to arrive at the net realized price. The SEC NYMEX prices used in the preparation of reserves are as follows: +10 +As of December 31, +2016 +2015 +2014 +Crude oil (SEC NYMEX - $/Bbl) +$ +42.75 +$ +50.28 +$ +94.99 +Natural gas (SEC NYMEX - $/MMBtu) +$ +2.48 +$ +2.59 +$ +4.35 +Reserve estimates involve judgments and cannot be measured exactly. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geological and geophysical data, and economic changes. Neither the estimated future net cash flows nor the standardized measure of discounted future net cash flows ("standardized measure") is intended to represent the current market value of our proved reserves. For additional information regarding both of these measures, as well as other information regarding our proved reserves, see the Supplemental Information Unaudited - Crude Oil and Natural Gas Information - Unaudited provided with our consolidated financial statements included elsewhere in this report. The following tables provide information regarding our estimated proved reserves: +As of December 31, +2016 +2015 +2014 +Proved reserves +Crude oil and condensate (MMBbls) +118 +99 +101 +Natural gas (Bcf) +834 +661 +537 +NGLs (MMBbls) +84 +64 +60 +Total proved reserves (MMBoe) +341 +273 +250 +Proved developed reserves (MMBoe) +98 +70 +75 +Estimated undiscounted future net cash flows (in millions) (1) +$ +2,681 +$ +2,259 +$ +4,938 +Standardized measure (in millions) +$ +1,421 +$ +1,097 +$ +2,306 +PV-10 ( in millions) (2) +$ +1,675 +$ +1,338 +$ +3,450 +___________ +(1) +Amount represents aggregate undiscounted future net cash flows, before income taxes, estimated by Ryder Scott and NSAI of approximately $3.3 billion , $2.8 billion , and $7.3 billion as of December 31, 2016 , 2015 , and 2014 , respectively, less an internally-estimated undiscounted future income tax expense of approximately $0.6 billion , $0.5 billion , and $2.3 billion , respectively. +(2) +PV-10 is a non-U.S. GAAP financial measure. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in accordance with U.S. GAAP, but rather should be considered in addition to the standardized measure. See Part I, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10 and a reconciliation of our PV-10 value to the standardized measure. +The following table presents our estimated proved developed and undeveloped reserves by category and area: +11 +As of December 31, 2016 +Operating Region/Area +Crude Oil and Condensate (MMBbls) +Natural Gas +(Bcf) +NGLs +(MMBbls) +Crude Oil +Equivalent +(MMBoe) +Percent +Proved developed +Wattenberg Field +25.5 +240.6 +21.7 +87.4 +26 +% +Delaware Basin +3.4 +13.9 +1.6 +7.2 +2 +% +Utica Shale +1.1 +9.9 +0.9 +3.6 +1 +% +Total proved developed +30.0 +264.4 +24.2 +98.2 +29 +% +Proved undeveloped +Wattenberg Field +76.6 +520.6 +54.5 +217.9 +64 +% +Delaware Basin +11.6 +48.7 +5.6 +25.3 +7 +% +Utica Shale +— +— +— +— +— +% +Total proved undeveloped +88.2 +569.3 +60.1 +243.2 +71 +% +Total proved reserves +Wattenberg Field +102.1 +761.2 +76.2 +305.3 +89 +% +Delaware Basin +15.0 +62.6 +7.2 +32.5 +10 +% +Utica Shale +1.1 +9.9 +0.9 +3.6 +1 +% +Total proved reserves +118.2 +833.7 +84.3 +341.4 +100 +% +We are showing two different alternative price scenarios for crude oil as its value currently influences our proved reserves and PV-10 value most significantly. We have performed a sensitivity analysis of our proved reserve estimates as of December 31, 2016 , to present sensitivities associated with both lower and higher crude oil prices. Replacing the 2016 NYMEX commodity prices used in estimating our reported proved reserves with those shown on the table below, and leaving all other parameters unchanged, results in a changes to our estimated proved reserves as shown below. +Pricing Scenario - NYMEX +Crude Oil (per Bbl) (1) +Natural Gas (per MMBtu) (1) +Proved Reserves (MMBoe) +% Change from December 31, 2016 Estimated Reserves +PV-10 (in Millions) +PV-10 % Change from December 31, 2016 Estimate Reserves +2016 SEC Reserve Report +$ +42.75 +$ +2.48 +341.4 +— +$ +1,675.0 +— +Alternate Price Scenarios: +Lower Price Scenario +$ +30.00 +$ +2.48 +326.5 +(4 +)% +$ +705.7 +(58 +)% +Higher Price Scenario +$ +50.00 +$ +2.48 +345.7 +1 +% +$ +2,247.0 +34 +% +__________ +(1) +These prices are the SEC NYMEX prices applied to the calculation of the PV-10 value. Such prices have been applied consistently across each pricing scenario to include the impact of adjusting for deductions for any basin differentials, transportation fees, contractual adjustments, and any Btu adjustments we experienced for the respective commodity. +12 +Developed and Undeveloped Acreage +The following table presents our developed and undeveloped lease acreage: +As of December 31, 2016 +Developed +Undeveloped +Total +Operating Region/Area +Gross +Net +Gross +Net +Gross +Net +Wattenberg Field +96,700 +89,200 +7,700 +6,300 +104,400 +95,500 +Delaware Basin +19,586 +18,664 +49,645 +43,837 +69,231 +62,501 +Utica Shale +5,454 +4,291 +61,862 +58,162 +67,316 +62,453 +Total acreage +121,740 +112,155 +119,207 +108,299 +240,947 +220,454 +Substantially all of our undeveloped acreage in the Wattenberg Field is related to leaseholds that are held-by-production. In the Wattenberg Field, approximately 1 percent , 2 percent , and 1 percent of our undeveloped leaseholds are scheduled to expire during 2017, 2018 and 2019, respectively. In the Delaware Basin, there are drilling obligations or continuous drilling clauses associated with the majority of our acreage. While we believe that our current Delaware Basin drilling plan should provide sufficient drilling to meet these obligations for the next few years, in the event that we do not meet the obligations for certain leases, we anticipate that we will make any necessary bonus extension payments, or we will seek to renew or, re-lease in order to retain the leases. However, the payments required to do so may be significant and we may not be successful in such efforts. In the Utica Shale, approximately 30 percent , 7 percent , and 11 percent of our undeveloped leaseholds are scheduled to expire during 2017, 2018 and 2019, respectively. +Drilling Activity +The following tables set forth a summary of our developmental and exploratory well drilling activity for the periods presented. There is no necessary correlation between the number of productive wells completed during any period and the aggregate reserves attributable to those wells. Productive wells consist of wells that were turned-in-line to sales and commenced production during the period, regardless of when drilling was initiated. In-process wells represent wells that are in the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection as of the date shown. The in-process wells are a normal part of our activity. The Wattenberg Field activity is comprised of pad drilling operations where multiple wells are developed from the same well pad and because we operate multiple drilling rigs in the area, we expect to have in-process wells at any given time. Wells may be in-process for anywhere from days to several months. We expect that normal in-process inventory will also exist in the development of our Delaware Basin leasehold. No wells were classified as exploratory in any of the periods presented. +Gross Development Well Drilling Activity +Year Ended December 31, +2016 +2015 +2014 +Operating Region/Area +Productive +In-Process +Non-Productive (1) +Productive +In-Process +Non-Productive (1) +Productive +In-Process +Non-Productive (1) +Wattenberg Field, operated wells +140 +64 +2 +136 +78 +4 +86 +44 +2 +Wattenberg Field, non-operated wells +24 +12 +— +58 +19 +— +70 +25 +— +Delaware Basin +1 +5 +— +— +— +— +— +— +— +Utica Shale +5 +— +— +4 +5 +— +8 +4 +1 +Other (2) +— +— +— +— +— +— +4 +— +— +Total gross development wells +170 +81 +2 +198 +102 +4 +168 +73 +3 +__________ +(1) +Represents mechanical failures that resulted in the plugging and abandonment of the respective wells. +(2) +Includes activity in the Marcellus Shale crude oil and natural gas properties, which were divested in October 2014. +13 +Net Development Well Drilling Activity +Year Ended December 31, +2016 +2015 +2014 +Operating Region/Area +Productive +In-Process +Non-Productive (1) +Productive +In-Process +Non-Productive (1) +Productive +In-Process +Non-Productive (1) +Wattenberg Field, operated wells +109.7 +52.7 +1.7 +110.8 +54.6 +2.7 +75.8 +36.5 +1.7 +Wattenberg Field, non-operated wells +5.0 +2.8 +— +9.3 +4.3 +— +14.9 +6.3 +— +Delaware Basin +1.0 +4.8 +— +— +— +— +— +— +— +Utica Shale +4.5 +— +— +3.0 +4.5 +— +7.0 +3.0 +1.0 +Other (2) +— +— +— +— +— +— +2.0 +— +— +Total net development wells +120.2 +60.3 +1.7 +123.1 +63.4 +2.7 +99.7 +45.8 +2.7 +__________ +(1) +Represents mechanical failures that resulted in the plugging and abandonment of the respective wells. +(2) +Includes activity in the Marcellus Shale crude oil and natural gas properties, which were divested in October 2014. +Title to Properties +We believe that we hold good and defensible leasehold title to substantially all of our crude oil and natural gas properties in accordance with standards generally accepted in the industry. A preliminary title examination is typically conducted at the time the undeveloped properties are acquired. Prior to the commencement of drilling operations, a title examination is conducted and remedial curative work is performed, as necessary, with respect to discovered defects which we deem to be significant, in order to procure division order title opinions. Title examinations have been performed with respect to substantially all of our producing properties. +The properties we own are subject to royalty, overriding royalty, and other outstanding interests. The properties may also be subject to additional burdens, liens, or encumbrances customary in the industry, including items such as operating agreements, current taxes, development obligations under crude oil and natural gas leases, farm-out agreements, and other restrictions. We do not believe that any of these burdens will materially interfere with our use of the properties. +Substantially all of our crude oil and natural gas properties, excluding our share of properties held by the limited partnerships that we sponsor, have been mortgaged or pledged as security for our revolving credit facility. See the footnote titled Long-Term Debt to our consolidated financial statements included elsewhere in this report. +Facilities +We lease 73,000 square feet of office space in Denver, Colorado, which serves as our corporate office, through February 2023 and 47,000 square feet of office space in Evans, Colorado through November 2025. We own a 32,000 square foot administrative office building located in Bridgeport, West Virginia, and a 60,000 square foot field operating facility in Greeley, Colorado. +We own or lease field operating facilities in or near Evans, Colorado, Midland, Texas, and Marietta, Ohio. +Governmental Regulation +While the prices of crude oil and natural gas are market driven, other aspects of our business and the industry in general are heavily regulated. The availability of a ready market for crude oil and natural gas production depends on several factors that are beyond our control. These factors include, but are not limited to, regulation of production, federal and state regulations governing environmental quality and pollution control, the amount of crude oil and natural gas available for sale, the availability of adequate pipeline and other transportation, and processing facilities and the marketing of competitive fuels. In general, state and federal regulations are intended to protect consumers from unfair treatment and undue control, reduce environmental and health risks from the development and transportation of crude oil and natural gas, prevent misuse of crude oil and natural gas, and protect rights among owners in a common reservoir. Pipelines are subject to the jurisdiction of various federal, state, and local agencies. We believe that we are in compliance with such statutes, rules, regulations, and governmental orders in all material respects, although there can be no assurance that this is or will remain the case. The following summary discussion of the regulation of the U.S. oil and gas industry is not intended to constitute a complete discussion of the various statutes, rules, regulations, and environmental directives to which our operations may be subject. +Regulation of Crude Oil and Natural Gas Exploration and Production. Our exploration and production business is subject to various federal, state, and local laws and regulations relating to the taxation of crude oil and natural gas, the development, production, and marketing of crude oil, and natural gas and environmental and safety matters. State and local laws and regulations require drilling permits and govern the spacing and density of wells, rates of production, water discharge, prevention of waste, and other matters. Prior to +14 +commencing drilling activities for a well, we must procure permits and/or approvals for the various stages of the drilling process from the applicable state and local agencies where the well being drilled is located. Additionally, other regulated matters include: +• +bond requirements in order to drill or operate wells; +• +well locations; +• +drilling and casing methods; +• +surface use and restoration of well properties; +• +well plugging and abandoning; +• +fluid disposal; and +• +air emissions. +In addition, our drilling activities involve hydraulic fracturing, which may be subject to additional federal and state disclosure and regulatory requirements discussed in "Environmental Matters" below and in Item 1A, Risk Factors . +Our operations also are subject to various conservation laws and regulations. These include the regulation of the size of drilling and spacing units or proration units, the density of wells which may be drilled and the unitization or pooling of lands and leases. In this regard, some states allow the forced pooling or integration of tracts to facilitate exploration while other states rely primarily or exclusively on voluntary pooling of lands and leases. In areas where pooling is primarily or exclusively voluntary, it may be more difficult to form units, and therefore, more difficult to drill and develop our leases where we own less than 100 percent of the leases located within the proposed unit. State laws may establish maximum rates of production from crude oil and natural gas wells, may prohibit the venting or flaring of natural gas, and impose certain requirements regarding the ratability of production. Leases covering state or federal lands often include additional regulations and conditions. The effect of these conservation laws and regulations may limit the amount of crude oil and natural gas we can produce from our wells and may limit the number of wells or the locations at which we can drill. Such laws and regulations may increase the costs of planning, designing, drilling, installing, operating, and abandoning our crude oil and natural gas wells and other facilities. These laws and regulations, and any others that are passed by the jurisdictions where we have production, can limit the total number of wells drilled or the allowable production from successful wells, which can limit our reserves. As a result, we are unable to predict the future cost or effect of complying with such regulations. +Regulation of Transportation of Natural Gas. We move natural gas through pipelines owned by other companies and sell natural gas to other companies that also utilize common carrier pipeline facilities. Natural gas pipeline interstate transmission and storage activities are subject to regulation by the Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act of 1938 ("NGA") and under the Natural Gas Policy Act of 1978, and, as such, rates and charges for the transportation of natural gas in interstate commerce, accounting, and the extension, enlargement or abandonment of jurisdictional facilities, among other things, are subject to regulation. Each natural gas pipeline company holds certificates of public convenience and necessity issued by FERC authorizing ownership and operation of all pipelines, facilities and properties for which certificates are required under the NGA. Each natural gas pipeline company is also subject to the Natural Gas Pipeline Safety Act of 1968, as amended, which imposes safety requirements in the design, construction, operation, and maintenance of interstate natural gas transmission facilities. FERC regulations govern how interstate pipelines communicate and do business with their affiliates. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. Interstate pipelines may not operate their pipeline systems to preferentially benefit their marketing affiliates. +Each interstate natural gas pipeline company establishes its rates primarily through FERC's rate-making process. Key determinants in the ratemaking process are: +• +costs of providing service, including depreciation expense; +• +allowed rate of return, including the equity component of the capital structure, and related income taxes; and +• +volume throughput assumptions. +The availability, terms, and cost of transportation affect our natural gas sales. Competition among suppliers has greatly increased. Furthermore, gathering is exempt from regulation under the Natural Gas Act, thus allowing gatherers to charge unregulated rates. Historically, producers were able to flow supplies into interstate pipelines on an interruptible basis; however, recently we have seen the increased need to acquire firm transportation on pipelines in order to avoid curtailments or shut-in gas, which could adversely affect cash flows from the affected area. +Additional proposals and proceedings that might affect the industry occur frequently in Congress, FERC, state commissions, state legislatures, and the courts. The industry historically has been very heavily regulated and there is no assurance that the current regulatory approach recently taken by FERC and Congress will continue. We cannot determine to what extent our future operations and earnings will be affected by new legislation, new regulations, or changes in existing regulation, at federal, state or local levels. +15 +Environmental Matters +Our operations are subject to numerous laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Public demand for the protection of the environment has increased dramatically in recent years. The trend towards more expansive environmental legislation and regulations is expected to continue. To the extent laws are enacted or other governmental actions are taken which restrict drilling or impose environmental protection requirements resulting in increased costs, our business and prospects may be adversely affected. In addition, the change in the administration under the Executive Branch of our federal government may result in change or uncertainty with respect to the future regulatory environment affecting the oil and natural gas industry. This uncertainty may affect how our industry is regulated as well as the level of public interest in environmental protection and may result in new or different pressures being exerted. For example, public interest groups may increase their use of litigation as a means to continue to exert pressure on the oil and natural gas industry. Accordingly, while we expect regulatory and enforcement pressures on our business to continue at federal, state, and local levels, the nature, level, and source of such pressures may change. +We generate wastes that may be subject to the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S. Environmental Protection Agency ("EPA") and various state agencies have adopted requirements that limit the approved disposal methods for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by our operations that are currently exempt from treatment as "hazardous wastes" may in the future be designated as "hazardous wastes," and therefore may subject us to more rigorous and costly operating and disposal requirements. +Hydraulic fracturing is commonly used to stimulate production of crude oil and/or natural gas from dense subsurface rock formations. We routinely apply hydraulic fracturing in our crude oil and natural gas production programs. The process involves the injection of water, sand, and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations, which are held open by the grains of sand, enabling the crude oil or natural gas to more easily flow to the wellbore. The process is generally subject to regulation by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over certain fracturing activities involving diesel fuel under the federal Safe Drinking Water Act ("SDWA") and issued draft guidance related to this asserted regulatory authority in February 2014. The guidance explains the EPA’s interpretation of the term “diesel fuel” for permitting purposes, describes existing Underground Injection Control Class II program requirements for permitting underground injection of diesel fuels in hydraulic fracturing and also provides recommendations for EPA permit writers in implementing these requirements. From time to time, Congress has considered legislation that would provide for broader federal regulation of hydraulic fracturing and disclosure of the chemicals used in the hydraulic fracturing process. +The White House Council on Environmental Quality continues to coordinate an administration-wide review of hydraulic fracturing. The EPA released the final report "Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources" on December 12, 2016. The report concluded that activities involved in hydraulic fracturing can have impacts on drinking water under certain circumstances - including surface spills, injection of fluids into wells with inadequate integrity, discharge of untreated or inadequately treated wastewater, and disposal or storage in unlined pits. In addition, the U.S. Department of Energy has investigated practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. These ongoing studies, depending on their degree of development and nature of results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. The U.S. Department of the Interior, through the Bureau of Land Management (the “BLM”), also finalized a rule in 2015 requiring the disclosure of chemicals used, mandating well integrity measures, and imposing other requirements relating to hydraulic fracturing on federal lands. The rule is currently stayed and not effective pending ongoing litigation. +The states in which we operate, Colorado, Texas, and Ohio, have adopted regulations regarding permitting, transparency, and well construction requirements with respect to hydraulic fracturing operations, and disposal well rules focused on potential seismicity concerns and may in the future adopt additional regulations or otherwise seek to ban fracturing or disposal activities altogether. Colorado and Texas require that all chemicals used in the hydraulic fracturing of a well be reported in a publicly searchable registry website developed and maintained by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission ("Frac Focus"). The Colorado rules also require operators seeking new location approvals to provide certain information to surface owners and adjacent property owners within 500 feet of a new well. Similarly, Colorado has implemented a baseline groundwater sampling rule, a rule governing setback distances of oil and gas wells located near population centers, and recently adopted new rules governing the development of large-scale facilities in urban mitigation areas and additional municipality notice requirements. In December 2013, the Colorado Oil and Gas Conservation Commission ("COGCC") issued new, more restrictive rules regarding spill reporting and remediation. In addition, during 2014, the Colorado Oil and Gas Conservation Act was amended to increase the potential sanctions for violating the Act or its implementing regulations, orders, or permits. +In November 2013, the Ohio Department of Natural Resources ("ODNR") proposed draft regulations pertaining to well pad construction requirements and increased bonding for construction, and these regulations were finalized in 2014. In October 2015, the ODNR proposed draft regulations pertaining to incident notification. A final hearing on these rules was held October 18, 2016 and the final draft rule was published on October 28, 2016. The effective date is not yet known. Additionally, in November 2015, the ODNR Assistant Chief announced draft rules in progress that address waste management, waste classification, secondary containment, emergency reporting, site remediation standards, well spacing, and simultaneous operations. We continue to be an active participant in the rule making process in Ohio. +In Colorado and Texas, local governing bodies have issued drilling moratoriums, develop jurisdictional siting, permitting and operating requirements, and conduct air quality studies to identify potential public health impacts. For instance, in 2013, the City of Fort Collins, Colorado, adopted a ban on drilling and fracturing of new wells within city limits. In the November 2013 election, voters in the Colorado cities of Boulder, Lafayette, Fort Collins and Brighton passed hydraulic fracturing bans, and in November 2014, Denton, Texas +16 +passed a hydraulic fracturing ban. See Item 1A, Risk Factors , for a more detailed discussion of these bans and relevant court decisions. If new laws or regulations that significantly restrict hydraulic fracturing or well locations continue to be adopted at local levels or are adopted at the state level, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from dense subsurface rock formations and, in the event of local prohibitions against commercial production of hydrocarbons, may preclude our ability to drill wells. If hydraulic fracturing becomes more heavily regulated as a result of federal or state legislation or regulatory initiatives by the EPA or other federal agencies, our fracturing activities could become subject to additional permitting requirements and permitting delays, as well as potential increases in costs. Restrictions on hydraulic fracturing could also reduce the amount of crude oil and natural gas that we are ultimately able to produce from our reserves. We continue to be active in stakeholder and interest groups and to engage with regulatory agencies in an open, proactive dialogue regarding these matters. +We currently own or lease numerous properties that for many years have been used for the exploration and production of crude oil and natural gas. Although we believe that we have generally utilized good operating and waste disposal practices, and when necessary, appropriate remediation techniques, prior owners and operators of these properties may not have utilized similar practices and techniques and hydrocarbons or other wastes may have been disposed of or released on or under the properties that we own or lease or on or under locations where such wastes have been taken for disposal. These properties and the wastes disposed thereon may be subject to the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), RCRA and analogous state laws, as well as state laws governing the management of crude oil and natural gas wastes. Under such laws, we may be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), remediate property contamination (including surface and groundwater contamination), or perform remedial plugging operations to prevent future contamination. +CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a "hazardous substance" into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of, transported, or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for release of hazardous substances under CERCLA may be subject to full liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Under state laws, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. As an owner and operator of crude oil and natural gas wells, we may be liable pursuant to CERCLA and similar state laws. +Our operations are subject to the federal Clean Air Act ("CAA") and comparable state and local requirements. The CAA contains provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and states continue to develop regulations to implement these requirements. We may be required to incur certain capital investments in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. Greenhouse gas record keeping and reporting requirements of the CAA became effective in 2011 and will continue into the future with increased costs for administration and implementation of controls. Federal New Source Performance Standards regarding oil and gas operations and amendments to such standards ("NSPS OOOO” and “NSPS OOOOa”) became effective between 2012 and 2016, and have added administrative and operational costs. In addition, Colorado adopted new regulations to meet the requirements of NSPS OOOO and promulgated significant new rules in February 2014 relating specifically to crude oil and natural gas operations that are equally or more stringent than NSPS OOOO / NPS OOOOa and directly regulate methane emissions from affected facilities. In April 2014, the Ohio Environmental Protection Agency Division of Air Pollution Control adopted new General Permit requirements for High Volume Horizontal Hydraulic Fracturing, Oil and Gas Well Site Production Operations. In October 2015, the EPA reduced the ozone compliance levels under the National Ambient Air Quality Standards (“NAAQS”) for ground level ozone to 70 parts per billion (“ppb”) from 75 ppb. In addition, the EPA extended the ozone monitoring season for 32 states, including Colorado, Texas, and Ohio. In October 2016, Colorado submitted revisions to its ozone SIP to meet requirements caused by an increase in ozone non-attainment status to “moderate” from “marginal.” +The federal Clean Water Act ("CWA") and analogous state laws impose strict controls against the discharge of pollutants and fill material, including spills and leaks of crude oil and other substances. The CWA also requires approval and/or permits prior to construction, where construction will disturb wetlands or other waters of the U.S. The CWA also regulates storm water run-off from crude oil and natural gas facilities and requires storm water discharge permits for certain activities. Spill Prevention, Control, and Countermeasure ("SPCC") requirements of the CWA require appropriate secondary containment load out controls, piping controls, berms, and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture, or leak. The EPA and U.S. Army Corps of Engineers released a Connectivity Report in September 2013 which determined that the vast majority of tributary streams, wetlands, open water in floodplains, and riparian areas are connected. This report supported the final rule issued in June 2015 clarifying the scope of jurisdictional Waters of the U.S. This final rule has been stayed pending the resolution of ongoing litigation. +The Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened species or their habitats. Some of our operations may be located in areas that are or may be designated as habitats for endangered or threatened species. The U.S. Fish and Wildlife Service in 2016 finalized a rule to alter how it identifies critical habitat for endangered and threatened species. +Crude oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of crude oil spills. In addition to SPCC requirements, the Oil Pollution Act of 1990 ("OPA") subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from crude oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Historically, we have not experienced any +17 +significant crude oil discharge or crude oil spill problems. Our shift in production since mid-2010 to a greater percentage of crude oil increases our risks related to soil and water contamination from any future oil spills. +Our costs relating to protecting the environment have risen over the past few years and are expected to continue to rise in 2017 and beyond. Environmental regulations have increased our costs and planning time, but have had no materially adverse effect on our ability to operate to date. However, no assurance can be given that environmental regulations or interpretations of such regulations will not, in the future, result in a curtailment of production or otherwise have a materially adverse effect on our business, financial condition or results of operations. See the footnote titled Commitments and Contingencies to our consolidated financial statements included elsewhere in this report. +Operating Hazards and Insurance +Our exploration and production operations include a variety of operating risks, including, but not limited to, the risk of fire, explosions, blowouts, cratering, pipe failure, casing collapse, abnormally pressured formations, and environmental hazards such as gas leaks, ruptures, and discharges of crude oil and natural gas. The occurrence of any of these events could result in substantial losses to us due to injury and loss of life, severe damage to and destruction of property, natural resources and equipment, pollution and other environmental damage, clean-up responsibilities, regulatory investigation, and penalties and suspension of operations. Our pipeline, gathering and distribution operations are subject to the many hazards inherent in the industry. These hazards include damage to wells, pipelines and other related equipment, damage to property caused by hurricanes, floods, fires and other acts of God, inadvertent damage from construction equipment, leakage of natural gas and other hydrocarbons, fires and explosions and other hazards that could also result in personal injury and loss of life, pollution, and suspension of operations. In 2013, we experienced a significant rainfall event that created widespread flooding in our Wattenberg Field operations in Weld County, Colorado, which resulted in a shut-in of approximately 200 vertical wells. We incurred significant costs to replace damaged well equipment and to bring these vertical wells back on-line. In 2014 and 2015, we experienced three mechanical failures during drilling that resulted in the discharge of oil and related material, the effects from which have been remediated. The impact from the mechanical failures did not have a material adverse effect on our financial condition or results of operations. +Among the regulatory developments involving operating hazards that could impact us going forward are recent investigations by the U.S. Occupational Health and Safety Administration (“OSHA”) and other governmental authorities regarding potential worker exposure to hydrocarbon vapors from certain petroleum transfer and related tasks. While we have not experienced such an event, several recent worker fatalities at oil and gas facilities nationwide are being reviewed by OSHA and other governmental authorities for a potential link to hydrocarbon vapor exposure. Regulatory requirements generally relating to worker exposure to hydrocarbon vapors could be increased or receive heightened scrutiny going forward. +Any significant problems related to our facilities could adversely affect our ability to conduct our operations. In accordance with customary industry practice, we maintain insurance against some, but not all, potential risks; however, there can be no assurance that such insurance will be adequate to cover any losses or exposure for liability. The occurrence of a significant event not fully insured against could materially adversely affect our operations and financial condition. We cannot predict whether insurance will continue to be available at premium levels that justify our purchase or will be available at all. Furthermore, we are not insured against our economic losses resulting from damage or destruction to third-party property, such as transportation pipelines, crude oil refineries, or natural gas processing facilities. Such an event could result in significantly lower regional prices or our inability to deliver our production. +Competition and Technological Changes +We believe that our production, exploration and drilling capabilities, and the experience of our management and professional staff, enable us to compete effectively in our industry. We encounter competition from numerous other crude oil and natural gas companies, drilling and income programs, and partnerships in all areas of operations, including drilling and marketing crude oil and natural gas, obtaining desirable crude oil and natural gas leases on producing properties, obtaining drilling, pumping and other services, attracting and retaining qualified employees, and obtaining capital. International developments may influence other companies to increase their domestic crude oil and natural gas exploration. Competition among companies for favorable prospects can be expected to continue and it is anticipated that the cost of acquiring properties will increase in the future. Many of our competitors possess larger staffs and greater financial resources than we do, which may enable them to identify and acquire desirable producing properties and drilling prospects more economically. Our ability to acquire additional properties and to explore for crude oil and natural gas prospects in the future depends upon our ability to conduct our operations, evaluate and select suitable properties, and consummate transactions in this highly competitive environment. We also face intense competition in other aspects of our business, including the marketing of natural gas from competitors including other producers and marketing companies. +The oil and gas industry is characterized by rapid and significant technological advancements and introduction of new products and services using new technologies. If one or more of the technologies we use now or in the future become obsolete or if we are unable to use the most advanced commercially available technology, our business, financial condition, results of operations, and cash flows could be materially adversely affected. +Employees +As of December 31, 2016 , we had 395 full-time employees. Our employees are not covered by collective bargaining agreements. We consider relations with our employees to be good. +18 +WHERE YOU CAN FIND ADDITIONAL INFORMATION +We file annual, quarterly and current reports, proxy statements and other information with the SEC. Our SEC filings are available free of charge from the SEC’s website at www.sec.gov or from our website at www.pdce.com. You may also read or copy any document we file at the SEC’s public reference room in Washington, D.C., located at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at (800) SEC-0330 for further information on the public reference room. We also make available free of charge any of our SEC filings by mail. For a mailed copy of a report, please contact PDC Energy, Inc., Investor Relations, 1775 Sherman Street, Suite 3000, Denver, CO 80203, or call (800) 624-3821. +We recommend that you view our website for additional information, as we routinely post information that we believe is important for investors. Our website can be used to access such information as our recent news releases, committee charters, code of business conduct and ethics, stockholder communication policy, director nomination procedures, and our whistle blower hotline. While we recommend that you view our website, the information available on our website is not part of this report and is not incorporated by reference. +19 +ITEM 1A. RISK FACTORS +You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results, and financial condition, as well as adversely affect the value of an investment in our common stock or other securities. +Risks Relating to Our Business and the Industry +Crude oil, natural gas, and NGL prices fluctuate and declines in these prices, or an extended period of low prices, can significantly affect the value of our assets and our financial results and impede our growth. +Our revenue, profitability, cash flows and liquidity depend in large part upon the prices we receive for our crude oil, natural gas, and NGLs. Changes in prices affect many aspects of our business, including: +• +our revenue, profitability and cash flows; +• +our liquidity; +• +the quantity and present value of our reserves; +• +the borrowing base under our revolving credit facility and access to other sources of capital; and +• +the nature and scale of our operations. +The markets for crude oil, natural gas, and NGLs are often volatile, and prices may fluctuate in response to, among other things: +• +relatively minor changes in regional, national, or global supply and demand; +• +regional, national, or global economic conditions, and perceived trends in those conditions; +• +geopolitical factors, such as events that may reduce or increase production from particular oil-producing regions and/or from members of the Organization of Petroleum Exporting Countries, or OPEC; and +• +regulatory changes. +The price of oil has been volatile since mid-2014, with a high over $100 per barrel in June 2014 to lows below $30 per barrel in 2016, in each case based on WTI prices, due to a combination of factors including increased U.S. supply, global economic concerns, and the resumption of oil exports from Iran. Prices for natural gas and NGLs have experienced similar volatility. Declines in prices adversely affect, among other things, our revenue and reserves, and have contributed to the recognition of impairment charges, including charges of $158.3 million and $150.3 million to write-down our Utica Shale producing and non-producing crude oil and natural gas properties to their estimated fair value in 2014 and 2015, respectively. Any future extended period of lower oil prices, or additional price declines, will have further adverse effects on us. For example, if we reduce our capital expenditures due to low prices, natural declines in production from our wells will likely result in reduced production and therefore reduced cash flow from operations, which would in turn further limit our ability to make the capital expenditures necessary to replace our reserves and production. +In addition to factors affecting the price of crude oil, natural gas, and NGLs generally, the prices we receive for our production are affected by factors specific to us and to the local markets where the production occurs. The prices that we receive for our production are generally lower than the relevant benchmark prices that are used for calculating commodity derivative positions. These differences, or differentials, are difficult to predict and may widen or narrow in the future based on market forces. Differentials can be influenced by, among other things, local or regional supply and demand factors and the terms of our sales contracts. Over the longer term, differentials will be significantly affected by factors such as investment decisions made by providers of midstream facilities and services, refineries and other industry participants, and the overall regulatory and economic climate. For example, increases in U.S. domestic oil production generally may result in widening differentials, particularly for production from some basins. We may be materially and adversely impacted by widening differentials on our production. +The Delaware Basin acquisitions may not achieve their intended results and may result in us assuming unanticipated liabilities. +The Delaware Basin acquisitions subject us to many of the risks described below in “Acquisitions of properties are subject to the uncertainties of evaluating recoverable reserves and potential liabilities, including environmental uncertainties.” For example, we may discover title defects or adverse environmental or other conditions relating to the properties acquired in the transactions of which we are currently unaware. Environmental, title, and other problems could reduce the value of the properties to us, and, depending on the circumstances, we could have limited or no recourse to the sellers with respect to those problems. We have assumed substantially all of the liabilities associated with the acquired properties and would be entitled to indemnification in connection with those liabilities in only limited circumstances, for limited periods and in limited amounts. We cannot provide assurance that such potential remedies will be adequate for any liabilities we incur, and such liabilities could be significant. Also, it is uncertain whether our existing operations and the acquired properties and assets can be integrated in an efficient and effective manner. In addition, the success of the Delaware Basin acquisitions depend on, among other things, the accuracy of our assessment of the reserves and drilling locations associated with the acquired properties, future oil, NGL and natural gas prices and operating costs, and various other factors. The majority of the value was attributed to unproved leaseholds, which inherently have a higher risk of uncertainty than the acquisition of proved developed reserves. These assessments were based to a significant degree on information provided by the sellers and we cannot guarantee their accuracy. Although the acquired properties are subject to many of the risks and uncertainties to which acquisitions we pursue are subject generally, risks associated with the Delaware Basin acquisitions in particular include those associated with our ability to operate efficiently in a new area, the significant size of the transactions in the aggregate, the fact that a substantial majority of the acquired properties are undeveloped, and the additional indebtedness and transaction costs we incurred in connection with the acquisitions. Many of these risks also apply to acquisitions of additional Delaware Basin properties +20 +we have pursued or may pursue in the future. In addition, we expect that pursuing our future development plans for the properties will require capital in excess of our projected cash flow from operations for some period of time beginning in 2017, which may increase our need for external financing. +Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities. +Unless production is established within the spacing units covering the undeveloped acres on which some of our drilling locations are identified, our leases for such acreage will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may differ materially from our current expectations, which could adversely affect our business. These risks are greater at times and in areas where the pace of our exploration and development activity slows. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals, approvals of the Texas General Land Office for our Delaware Basin properties, and other factors. These risks are currently greater for us in the Delaware Basin area than in our other operating areas. As of December 31, 2016, approximately 30 percent of our total net acreage in the Delaware Basin was held-by-production or drilling operations. In addition, a substantial portion of our Utica Shale acreage is held-by-production by a third party operator’s shallow vertical wells. Our relative lack of control over this acreage increases the risk that some of our leases will expire. +Ballot initiatives have been proposed in Colorado from time to time that could vastly expand the right of local governments to limit or prohibit oil and natural gas production and development in their jurisdictions and could impose additional regulations on production and development activities. If any initiative or legislation of this nature is implemented and survives legal challenge, additional limitations or prohibitions could be placed on crude oil, natural gas and NGL production and development within certain areas of Colorado or the state as a whole. Similar initiatives could be proposed in other states. +During 2016, certain interest groups in Colorado opposed to oil and natural gas development generally, or hydraulic fracturing in particular, advanced various options for ballot initiatives aimed at significantly limiting or effectively preventing oil and natural gas development in the state of Colorado. Proponents of two such initiatives attempted to qualify the initiatives to appear on the ballot for the November 2016 election. On August 29, 2016, the Colorado Secretary of State issued a press release and statements of insufficiency of signatures, stating that the proponents of the proposals had failed to collect enough valid signatures to have the proposals included on the ballot. +One of the initiatives, which we refer to as the “local control” initiative, would have amended the state constitution to give city, town, and county governments the right to regulate, or to ban, oil and gas development and production within their boundaries, notwithstanding rules and approvals to the contrary at the state level. This proposal was motivated in part by a decision of the Colorado Supreme Court holding that local government restrictions on oil and gas activities are subject to preemption by state rules. +A second initiative, which we refer to as the “setback” initiative, would have amended the state constitution to require all new oil and gas development facilities to be located at least 2,500 feet away from any occupied structure or broadly defined “area of special concern,” including public and community drinking water sources, lakes, rivers, perennial or intermittent streams, creeks, irrigation canals, riparian areas, playgrounds, permanent sports fields, amphitheaters, public parks, and public open space. +If implemented, the setback initiative would have effectively prohibited the vast majority of our planned future drilling activities in Colorado and would therefore have made it impossible to pursue our current development plans. The local control proposal would potentially have had a similar effect, depending on the nature and extent of regulations implemented by relevant local governmental authorities. Pursuant to the determination of the Colorado Secretary of State, these proposals did not appear on the November 2016 ballot. However, future proposals of this nature are possible. +Because a substantial portion of our operations and reserves are located in Colorado, the risks we face with respect to such future proposals are greater than those of our competitors with more geographically diverse operations. Although we cannot predict the outcome of future ballot initiatives, statutes, or regulatory developments, such developments could materially impact our results of operations, production, and reserves. +A substantial part of our crude oil, natural gas, and NGLs production is located in the Wattenberg Field, making us vulnerable to risks associated with operating primarily in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing formations. +Although we have significant non-producing leasehold positions in the Delaware Basin in Texas and the Utica Shale in Ohio, our current production is primarily located in the Wattenberg Field in Colorado. Because our production is not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including: +• +fluctuations in prices of crude oil, natural gas, and NGLs produced from the wells in the area; +• +natural disasters such as the flooding that occurred in Northern Colorado in September 2013; +• +restrictive governmental regulations; and +• +curtailment of production or interruption in the availability of gathering, processing, or transportation infrastructure and services, and any resulting delays or interruptions of production from existing or planned new wells. +21 +For example, bottlenecks in processing and transportation that have occurred in some recent periods in the Wattenberg Field have negatively affected our results of operations, and these adverse effects may be disproportionately severe to us compared to our more geographically diverse competitors. Similarly, the concentration of our producing assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules that could adversely affect development activities or production relating to those formations. Such an event could have a material adverse effect on our results of operations and financial condition. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the Wattenberg Field and the Delaware Basin, the demand for, and cost of, drilling rigs, equipment, supplies, personnel, and oilfield services increase. Shortages or the high cost of drilling rigs, equipment, supplies, personnel, or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital forecast, which could have a material adverse effect on our business, financial condition or results of operations. +Certain of our properties are subject to land use restrictions, which could limit the manner in which we conduct our business. +Certain of our properties are subject to land use restrictions, including city ordinances, which could limit the manner in which we conduct our business. Such restrictions could affect, among other things, our access to and the permissible uses of our facilities as well as the manner in which we produce oil and natural gas and may restrict or prohibit drilling in general. The costs we incur to comply with such restrictions may be significant in nature, and we may experience delays or curtailment in the pursuit of development activities and perhaps even be precluded from drilling wells. +We may incur losses as a result of title defects in the properties in which we invest. +It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. Leases in the Utica Shale area are particularly vulnerable to title deficiencies due the long history of land ownership in the area and correspondingly extensive and complex chains of title. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property. +Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our production and reserves, and ultimately our profitability. +Our industry is capital intensive. We expect to continue to make substantial capital expenditures in our business and operations for the exploration, development, production and acquisition of crude oil, natural gas, and NGL reserves. To date, we have financed capital expenditures primarily with bank borrowings under our revolving credit facility, cash generated by operations and proceeds from capital markets transactions and the sale of properties. We intend to finance our future capital expenditures utilizing similar financing sources. Our cash flows from operations and access to capital are subject to a number of variables, including: +• +our proved reserves; +• +the amount of crude oil, natural gas, and NGLs we are able to produce from existing wells; +• +the prices at which crude oil, natural gas, and NGLs are sold; +• +the costs to produce crude oil, natural gas, and NGLs; and +• +our ability to acquire, locate and produce new reserves. +If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower commodity prices, operating difficulties or for any other reason, our need for capital from other sources could increase, and there can be no assurance that such other sources of capital would be available at that time on reasonable terms or at all. If we raise funds by issuing additional equity securities, this would have a dilutive effect on existing shareholders. If we raise funds through the incurrence of debt, the risks we face with respect to our indebtedness would increase and we would incur additional interest expense. Our inability to obtain sufficient financing on acceptable terms would adversely affect our financial condition and profitability. +Our ability to produce crude oil, natural gas, and NGLs could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of the water we use at a reasonable cost and within applicable environmental rules. +Our operations could be adversely impacted if we are unable to locate sufficient amounts of water, or dispose of or recycle water used in our exploration and production operations. Currently, the quantity of water required in certain completion operations, such as hydraulic fracturing, and changing regulations governing usage may lead to water constraints and supply concerns (particularly in some parts of the country). In addition, both eastern Colorado and western Texas have relatively arid climates and experience drought conditions from time to time. As a result, future availability of water from certain sources used in the past may become limited. +The imposition of new environmental initiatives relating to wastewater could restrict our ability to conduct certain operations such as hydraulic fracturing. This includes potential restrictions on waste disposal, including, but not limited to, produced water, drilling fluids, and other wastes associated with the exploration, development, or production of hydrocarbons. For example, in 2010 a petition was filed by the Natural Resources Defense Council with the EPA requesting that the agency reassess its prior and long-standing determination that certain oil and natural gas exploration and production wastes would not be regulated as hazardous waste under Subtitle C of the RCRA. The EPA has not yet acted on the petition and it remains pending. In a separate but related matter, a proposed consent decree filed in December 2016 between the EPA and several environmental groups commits the EPA to decide whether to revise its RCRA Subtitle D criteria regulations and state plan guidelines for the oil and natural gas sector by March 2019. If the EPA began treating some or all of these wastes as “hazardous” +22 +under Subtitle C in response to the petition or as a result of the proposed consent decree, the consequences for our operations would be serious, and would include a significant increase in costs associated with waste treatment and disposal and a potential inability to conduct operations in some instances. +The CWA and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas waste, into navigable waters or other regulated federal and state waters. Permits or other approvals must be obtained to discharge fill and pollutants into regulated waters and to conduct construction activities in such waters and wetlands. Uncertainty regarding regulatory jurisdiction over wetlands and other regulated waters of the United States has complicated, and will continue to complicate and increase the cost of, obtaining such permits or other approvals. In June 2015, the EPA and the U.S. Army Corps of Engineers issued a final rule that clarifies the scope of the agencies’ jurisdiction under section 404 of the CWA to regulate certain activities occurring in waters of the United States. This rule, known as the Clean Water Rule, has been challenged by various parties in multiple federal courts, and as a result of this litigation is currently stayed and not yet effective. An expansive definition of such jurisdictional waters could affect our ability to operate in certain areas, increase costs of operations, and cause significant scrutiny and delays in permitting. While generally exempt under federal programs, many state agencies have also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain permits for storm water discharges. These permits, in turn, impose far-ranging monitoring, flow control, and other obligations that have generated, and will continue to generate, increased costs for our operations. +In June 2016, the EPA finalized pretreatment standards for indirect discharges of wastewater from the oil and gas extraction industry. The regulation prohibits sending wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned treatment works. Some states, including Pennsylvania, have banned the treatment of fracturing wastewater at publicly owned treatment facilities. There also has been recent nationwide concern, particularly in Ohio and Oklahoma, over earthquakes associated with Class II underground injection control wells, a predominant storage method for crude oil and gas wastewater. As seen in Ohio, it is likely that new rules and regulations will be developed to address these concerns, possibly eliminating access to Class II wells in certain locations, and increasing the cost of disposal in others. +Finally, the EPA study on hydraulic fracturing noted above focused on various stages of water use in hydraulic fracturing operations. It is possible that the EPA will move to more strictly regulate the use of water in hydraulic fracturing operations. While we cannot predict the impact that these changes may have on our business at this time, they may be material to our business, financial condition, and operations. In addition, an inability to meet our water supply needs to conduct our completion operations may adversely impact our business. +The marketability of our production is dependent upon transportation and processing facilities the capacity and operation of which we do not control. Market conditions or operational impediments, including high line pressures, particularly in the Wattenberg Field, and other impediments affecting midstream facilities and services, could hinder our access to crude oil, natural gas, and NGL markets, increase our costs or delay production, and thereby adversely affect our profitability. +Our ability to market our production depends in substantial part on the availability, proximity and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. If adequate midstream facilities and services are not available to us on a timely basis and at acceptable costs, our production and results of operations will be adversely affected. For example, in some recent periods, due to ongoing drilling activities by us and third parties and hot temperatures during the summer months, the principal third-party provider we use in the Wattenberg Field area for midstream facilities and services experienced increased gathering system pressures during those warmer months. The resulting capacity constraints reduced the productivity of some of our older vertical wells and limited incremental production from some of our newer horizontal wells. This constrained our production and reduced our revenue from the affected wells. Capacity constraints affecting natural gas production also impacted the associated NGLs. Some operators in the Delaware Basin have experienced similar issues from time to time, in part due to significant increases in production in the area. Our operations in Texas and elsewhere may be adversely affected by those issues. The use of alternative forms of transportation for oil production such as trucks or rail involve risks, including the risk that increased regulation could lead to increased costs or shortages of trucks or railcars. +In addition to causing production curtailments, capacity constraints can also reduce the price we receive for the crude oil, natural gas, and NGLs we produce. +We rely on third parties to continue to construct additional midstream facilities and related infrastructure to accommodate our growth, and the ability and willingness of those parties to do so is subject to a variety of risks. For example: +• +Decreases in commodity prices in recent years have resulted in reduced investment in midstream facilities by some third parties; +• +Various interest groups have protested the construction of new pipelines, and particularly pipelines near water bodies, in various places throughout the country, and protests have at times physically interrupted pipeline construction activities; and +• +Some upstream energy companies have in the recent past sought to reject volume commitment agreements with midstream providers in bankruptcy proceedings, and the risk that such efforts will succeed, or that upstream energy company counterparties will otherwise be unable or unwilling to satisfy their volume commitments, may have the effect of reducing investment in midstream infrastructure. +Like other producers we from time to time enter into volume commitments with midstream providers in order to induce them to provide increased capacity. If we reduce the pace of our drilling activities significantly after entering into such commitments for any reason, it may be difficult or impossible for us to satisfy those commitments. +Reduced commodity prices could result in significant impairment charges and significant downward revisions of proved reserves. +23 +Crude oil prices fell dramatically in the second half of 2014, with further declines in 2015 and into 2016, and the domestic natural gas market remains weak. Low commodity prices could result in, among other adverse effects, significant impairment charges. The cash flow model we use to assess properties for impairment includes numerous assumptions, such as management’s estimates of future oil and gas production and commodity prices, market outlook on forward commodity prices and operating and development costs. All inputs to the cash flow model must be evaluated at each date that the estimate of future cash flows for each producing basin is calculated. However, a significant decrease in long-term forward prices alone could result in a significant impairment for our properties that are sensitive to declines in prices. We have incurred impairment charges in a number of recent periods, including charges of $150.3 million and $158.3 million relating to our Utica Shale properties in 2015 and 2014, respectively. Similar charges could occur in the future. In addition, low commodity prices could result in significant downward revisions to the estimated quantity and value of our proved reserves. +Our estimated crude oil and natural gas reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves. +Calculating reserves for crude oil, natural gas, and NGLs requires subjective estimates of remaining volumes of underground accumulations of hydrocarbons. Assumptions are also made concerning commodity prices, production levels, and operating and development costs over the economic life of the properties. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate. Independent petroleum engineers prepare our estimates of crude oil, natural gas, and NGLs reserves using pricing, production, cost, tax and other information that we provide. The reserve estimates are based on certain assumptions regarding commodity prices, production levels, and operating and development costs that may prove incorrect. Any significant variance from these assumptions to actual results could greatly affect: +• +the economically recoverable quantities of crude oil, natural gas, and NGLs attributable to any particular group of properties; +• +future depreciation, depletion, and amortization (“DD&A”) rates and amounts; +• +impairments in the value of our assets; +• +the classifications of reserves based on risk of recovery; +• +estimates of future net cash flows; +• +timing of our capital expenditures; and +• +the amount of funds available for us to borrow under our revolving credit facility. +Some of our reserve estimates must be made with limited production histories, which renders these reserve estimates less reliable than estimates based on longer production histories. Horizontal drilling in the Wattenberg Field is a relatively recent development, whereas vertical drilling has been used by producers in this field for over 40 years. As a result, the amount of production data from horizontal wells available to reserve engineers is relatively small, and future reserve estimates will be affected by additional production data as it becomes available. Horizontal drilling in the Utica Shale and the Delaware Basin has an even more limited history. Further, reserve estimates are based on the volumes of crude oil, natural gas, and NGLs that are anticipated to be economically recoverable from a given date forward based on economic conditions that exist at that date. The actual quantities of crude oil, natural gas, and NGLs recovered will be different than the reserve estimates since they will not be produced under the same economic conditions as used for the reserve calculations. In addition, quantities of probable and possible reserves by definition are inherently more risky than proved reserves, in part because they have greater uncertainty associated with the recoverable quantities of hydrocarbons. +At December 31, 2016, approximately 71.2 percent of our estimated proved reserves were undeveloped. These reserve estimates reflect our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including approximately $2.1 billion during the five years ending December 31, 2021, as estimated in the calculation of the standardized measure of oil and gas activity. The estimated development costs may not be accurate, development may not occur as scheduled and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of initial booking, and we may therefore be required to downgrade to probable or possible any PUDs that are not developed within this five-year time frame. +The present value of the estimated future net cash flows from our proved reserves is not necessarily the same as the current market value of those reserves. Pursuant to SEC rules, the estimated discounted future net cash flows from our proved reserves, and the estimated quantity of those reserves, were based on the prior year’s first day of the month 12-month average crude oil and natural gas index prices. However, factors such as actual prices we receive for crude oil and natural gas and hedging instruments, the amount and timing of actual production, the amount and timing of future development costs, the supply of and demand for crude oil, natural gas, and NGLs, and changes in governmental regulations or taxation, also affect our actual future net cash flows from our properties. The timing of both our production and incurrence of expenses in connection with the development and production of crude oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10 percent discount factor (the rate required by the SEC) we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates currently in effect and risks associated with our properties or the industry in general. +Unless reserves are replaced as they are produced, our reserves and production will decline, which would adversely affect our future business, financial condition and results of operations. We may not be able to develop our identified drilling locations as planned. +Producing crude oil, natural gas, and NGL reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline may change over time and may exceed our estimates. Our future reserves and production and, therefore, our cash flows and income, are highly dependent on our ability to efficiently develop and exploit our current reserves and to economically find or acquire additional recoverable reserves. We may not be able to develop, discover, or acquire additional +24 +reserves to replace our current and future production at acceptable costs. Our failure to do so would adversely affect our future operations, financial condition and results of operations. +We have identified a number of well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including: +• +crude oil, natural gas, and NGL prices; +• +the availability and cost of capital; +• +drilling and production costs; +• +availability of drilling services and equipment; +• +drilling results; +• +lease expirations; +• +midstream constraints; +• +access to and availability of water sourcing and distribution systems; +• +regulatory approvals; and +• +other factors. +Because of these factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce crude oil, natural gas, or NGLs from these or any other potential well locations. In addition, the number of drilling locations available to us will depend in part on the spacing of wells in our operating areas. An increase in well density in an area could result in additional locations in that area, but a reduced production performance from the area on a per-well basis. Further, certain of the horizontal wells we intend to drill in the future may require pooling of our lease interests with the interests of third parties. Some states, including Colorado, allow the involuntary pooling of tracts in a relatively broad number of circumstances in order to facilitate exploration. Other states, including Texas, restrict involuntary pooling to a narrower set of circumstances and consequently these states rely primarily on voluntary pooling of lands and leases. In states where pooling is accomplished primarily on a voluntary basis, it may be more difficult to form units and, therefore, more difficult to fully develop a project if we own less than 100 percent of the leasehold or one or more of our leases does not provide the necessary pooling authority. If third parties are unwilling to pool their interests with ours, we may be unable to require such pooling on a timely basis or at all, and this would limit the total locations we can drill. As such, our actual drilling activities may materially differ from those presently identified. Further, our inventory of drilling projects includes locations in addition to those that we currently classify as proved, probable, and possible. The development of and results from these additional projects are more uncertain than those relating to probable and possible locations, and significantly more uncertain than those relating to proved locations. We have generally accelerated the pace of our development activities in the Wattenberg Field over the past several years, and this has reduced our related inventory of drilling locations. +The wells we drill may not yield crude oil, natural gas, or NGLs in commercially viable quantities and productive wells may be less successful than we expect. +A prospect is a property on which our geologists have identified what they believe, based on available information, to be indications of hydrocarbon-bearing rocks. However, our geologists cannot know conclusively prior to drilling and testing whether crude oil, natural gas, or NGLs will be present in sufficient quantities to repay drilling or completion costs and generate a profit given the available data and technology. Furthermore, even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques do not enable our geologists to be certain as to whether hydrocarbons are, in fact, present in those structures or the quantity of the hydrocarbons. In addition, the use of 3-D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures, which may result in a reduction in our returns or losses. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline. If a well is determined to be dry or uneconomic, which can occur even though it contains some crude oil, natural gas, or NGLs, it is classified as a dry hole and must be plugged and abandoned in accordance with applicable regulations. This generally results in the loss of the entire cost of drilling and completion to that point, the cost of plugging, and lease costs associated with the prospect. Even wells that are completed and placed into production may not produce sufficient crude oil, natural gas, and NGLs to be profitable, or they may be less productive and/or profitable than we expected. In recent years we have been able to achieve reductions in drilling and completion costs in connection with lower commodity prices. However, as commodity prices have stabilized or increased since mid-2016, many of these costs have begun to increase, and further increases are expected. If we drill a dry hole or unprofitable well on a current or future prospect, or if drilling or completion costs increase, the profitability of our operations will decline and the value of our properties will likely be reduced. Exploratory drilling is typically subject to substantially greater risk than development drilling. In addition, initial results from a well are not necessarily indicative of its performance over a longer period. +25 +Drilling for and producing crude oil, natural gas, and NGLs are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations. +Drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling can be unprofitable, not only due to dry holes, but also due to curtailments, delays, or cancellations as a result of other factors, including: +• +unusual or unexpected geological formations; +• +pressures; +• +fires; +• +floods; +• +loss of well control; +• +loss of drilling fluid circulation; +• +title problems; +• +facility or equipment malfunctions; +• +unexpected operational events; +• +shortages or delays in the delivery of equipment and services; +• +unanticipated environmental liabilities; +• +compliance with environmental and other governmental requirements; and +• +adverse weather conditions. +Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells, and regulatory penalties. For example, a loss of containment of hydrocarbons during drilling activities could potentially subject us to civil and/or criminal liability and the possibility of substantial costs, including for environmental remediation, depending upon the circumstances of the loss of containment, the nature and scope of the loss and the applicable laws and regulations. We maintain insurance against various losses and liabilities arising from our operations; however, insurance against certain operational risks may not be available or may be prohibitively expensive relative to the perceived risks presented. For example, we may not have coverage with respect to a pollution event if we are unaware of the event while it is occurring and are therefore unable to report the occurrence of the event to our insurance company within the time frame required under our insurance policy. Thus, losses could occur for uninsurable or uninsured risks or for amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance and/or governmental or third party responses to an event could have a material adverse effect on our business activities, financial condition and results of operations. We are currently involved in various remedial and investigatory activities at some of our wells and related sites. +Our business strategy focuses on production in our liquid-rich shale plays. In this regard, we plan to allocate our capital to an active horizontal drilling program. Prior to 2012, most of the wells we drilled were vertical wells. Since 2012, however, we have devoted the majority of our capital budget to drilling horizontal wells. Drilling horizontal wells is technologically more difficult than drilling vertical wells - including as a result of risks relating to our ability to fracture stimulate the planned number of stages and to successfully run casing the length of the well bore - and the risk of failure is therefore greater than the risk involved in drilling vertical wells. Additionally, drilling a horizontal well is typically far costlier than drilling a vertical well. This means that the risks of our drilling program will be spread over a smaller number of wells, and that, in order to be economic, each horizontal well will need to produce at a higher level in order to cover the higher drilling costs. Similarly, the average lateral length of the horizontal wells we drill has generally been increasing. Longer-lateral wells are typically more expensive and require more time for preparation and permitting. In addition, we have transitioned to the use of multi-well pads instead of single-well sites. The use of multi-well pad drilling increases some operational risks because problems affecting the pad or a single well could adversely affect production from all of the wells on the pad. Pad drilling can also make our overall production, and therefore our revenue and cash flows, more volatile, because production from multiple wells on a pad will typically commence simultaneously. While we believe that we will be better served by drilling horizontal wells using multi-well pads, the risk component involved in such drilling will be increased in some respects, with the result that we might find it more difficult to achieve economic success in our drilling program. +Under the “successful efforts” accounting method that we use, unsuccessful exploratory wells must be expensed in the period when they are determined to be non-productive, which reduces our net income in such periods and could have a negative effect on our profitability. +We conduct exploratory drilling in order to identify additional opportunities for future development. Under the “successful efforts” method of accounting that we use, the cost of unsuccessful exploratory wells must be charged to expense in the period in which the wells are determined to be unsuccessful. In addition, lease costs for acreage condemned by the unsuccessful well must also be expensed. In contrast, unsuccessful development wells are capitalized as a part of the investment in the field where they are located. Because exploratory wells generally are more likely to be unsuccessful than development wells, we anticipate that some or all of our exploratory wells may not be productive. The costs of such unsuccessful exploratory wells could result in a significant reduction in our profitability in periods when the costs are required to be expensed. +We have a substantial amount of debt and the cost of servicing, and risks related to refinancing, that debt could adversely affect our business. Those risks could increase if we incur more debt. +We have a substantial amount of indebtedness. As a result, a significant portion of our cash flows will be required to pay interest and principal on our indebtedness, and we may not generate sufficient cash flows from operations, or have future borrowing capacity available, to enable us to repay our indebtedness or to fund other liquidity needs. We incurred a substantial amount of additional debt in order +26 +to finance part of the purchase price for the Delaware Basin acquisitions, and the properties acquired currently produce only modest amounts of cash flow from operations. +Servicing our indebtedness and satisfying our other obligations will require a significant amount of cash. Our cash flows from operating activities and other sources may not be sufficient to fund our liquidity needs. Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend on our future operating performance and financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions, including possibly depressed commodity pricing, and financial, business and other factors, many of which are beyond our control. We expect that some commercial lenders may look to reduce their exposure to exploration and production companies due to regulatory pressures they face and/or independent business considerations. This could adversely affect our liquidity and our ability to refinance our debt. +A substantial decrease in our operating cash flows or an increase in our expenses could make it difficult for us to meet our debt service requirements and could require us to modify our operations, including by curtailing our exploration and drilling programs, selling assets, refinancing all or a portion of our existing debt, or obtaining additional financing. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. In addition, the terms of future debt agreements may, and our existing debt agreements do, restrict us from implementing some of these alternatives. In the absence of adequate cash from operations and other available capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. We may not be able to consummate these dispositions for fair market value, in a timely manner or at all. Furthermore, any proceeds that we could realize from any dispositions may not be adequate to meet our debt service or other obligations then due. Because the cash required to service our indebtedness is not available to finance our operations and other business activities, our indebtedness limits our flexibility in planning for or reacting to changes in our business and the industry in which we operate and increases our vulnerability to economic downturns and sustained declines in commodity prices. +Covenants in our debt agreements currently impose, and future financing agreements may impose, significant operating and financial restrictions. +The indentures governing our senior notes and our revolving credit facility contain restrictions, and future financing agreements may contain additional restrictions, on our activities, including covenants that restrict our and certain of our subsidiaries’ ability to: +• +incur additional debt; +• +pay dividends on, redeem, or repurchase stock; +• +create liens; +• +make specified types of investments; +• +apply net proceeds from certain asset sales; +• +engage in transactions with our affiliates; +• +engage in sale and leaseback transactions; +• +merge or consolidate; +• +restrict dividends or other payments from restricted subsidiaries; +• +sell equity interests of restricted subsidiaries; and +• +sell, assign, transfer, lease, convey or dispose of assets. +Our revolving credit facility is secured by substantially all of our crude oil and natural gas properties as well as a pledge of all ownership interests in our operating subsidiaries. The restrictions contained in our debt agreements may prevent us from taking actions that we believe would be in the best interest of our business, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. We may also incur future debt obligations that might subject us to additional restrictive covenants that could affect our financial and operational flexibility. +Our revolving credit facility has substantial restrictions and financial covenants and our ability to comply with those restrictions and covenants is uncertain. Our lenders can unilaterally reduce our borrowing availability based on anticipated commodity prices. +We depend in large part on our revolving credit facility for future capital needs. The terms of the credit agreement require us to comply with certain financial covenants and ratios. Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of cash flows from operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the revolving credit facility or other debt agreements could result in a default under those agreements, which could cause all of our existing indebtedness to be immediately due and payable. +The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based upon projected revenues from the properties securing their loan. Decreases in the price of crude oil, natural gas, or NGLs can be expected to have an adverse effect on the borrowing base. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Outstanding borrowings in excess of the borrowing base must be repaid immediately, or we must pledge other crude oil and natural gas properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility. Our inability to borrow additional funds under our revolving credit facility could adversely affect our operations and our financial results. +27 +If we are unable to comply with the restrictions and covenants in the agreements governing our indebtedness, there would be a default under the terms of these agreements, which could result in an acceleration of payment of funds that we have borrowed and would impact our ability to make principal and interest payments on our indebtedness and satisfy our other obligations. +Any default under the agreements governing our indebtedness, including a default under our revolving credit facility that is not waived by the required lenders, and the remedies sought by the holders of any such indebtedness, could make us unable to pay principal and interest on our indebtedness and satisfy our other obligations. If we are unable to generate sufficient cash flows and are otherwise unable to obtain the funds necessary to meet required payments of principal and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. In the event of such a default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our revolving credit facility could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation. In addition, the default could result in a cross-default under other debt agreements. If our operating performance declines, we may in the future need to seek waivers from the required lenders under our revolving credit facility to avoid being in default and we may not be able to obtain such a waiver. If this occurs, we would be in default under our revolving credit facility, the lenders could exercise their rights as described above, and we could be forced into bankruptcy or liquidation. We cannot assure you that we will be granted waivers or amendments to our debt agreements if for any reason we are unable to comply with these agreements, or that we will be able to refinance our debt on terms acceptable to us, or at all. +Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly. +Borrowings under our revolving credit facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase although the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness and for other purposes would decrease. +Notwithstanding our current indebtedness levels and restrictive covenants, we may still be able to incur substantial additional debt, which could exacerbate the risks described above. +We may be able to incur additional debt in the future. Although our debt agreements contain restrictions on our ability to incur indebtedness, those restrictions are subject to a number of exceptions. In particular, we may borrow under the revolving credit facility, and may do so in 2017. We may also consider investments in joint ventures or acquisitions that may increase our indebtedness. Adding new debt to current debt levels could intensify the related risks that we now face. +Seasonal weather conditions and lease stipulations can adversely affect our operations. +Seasonal weather conditions and lease stipulations designed to protect wildlife affect operations in some areas. In certain areas drilling and other activities may be restricted or prohibited by lease stipulations, or prevented by weather conditions, for significant periods of time. This limits our operations in those areas and can intensify competition during the active months for drilling rigs, oil field equipment, services, supplies, and qualified personnel, which may lead to additional or increased costs or periodic shortages. These constraints and the resulting high costs or shortages could delay our operations and materially increase operating and capital costs and therefore adversely affect our profitability. Similarly, hot weather during some recent periods adversely impacted the operation of certain midstream facilities, and therefore our production. Similar events could occur in the future and could negatively impact our results of operations and cash flows. +We have limited control over activities on properties in which we own an interest but we do not operate, which could reduce our production and revenues. +We operate approximately 88 percent of the wells in which we own an interest. If we do not operate the properties in which we own an interest, we do not have control over normal operating procedures, expenditures or future development of the underlying properties. The success and timing of drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise (including safety and environmental compliance) and financial resources, inclusion of other participants in drilling wells, and use of technology. The failure by an operator to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce production and revenues and adversely affect our profitability. These risks are heightened in some respects in periods of depressed commodity prices as operators may propose operations that we believe to be economically unattractive, leading us to incur non-consent penalties. Our lack of control over non-operated properties also makes it more difficult for us to forecast capital expenditures, production and related matters. +Our commodity derivative activities could result in financial losses or reduced income from failure to perform by our counterparties, could limit our potential gains from increases in prices and could result in volatility in our net income. +We use commodity derivatives for a portion of the production from our own wells and for natural gas purchases and sales by our marketing subsidiary to achieve more predictable cash flows, to reduce exposure to adverse fluctuations in commodity prices, and to allow our natural gas marketing company to offer pricing options to natural gas sellers and purchasers. These arrangements expose us to the risk of financial loss in some circumstances, including when purchases or sales are different than expected or the counterparty to the commodity derivative contract defaults on its contractual obligations. In addition, many of our commodity derivative contracts are based on WTI or another oil or natural gas index price. The risk that the differential between the index price and the price we receive for the relevant production may change unexpectedly makes it more difficult to hedge effectively and increases the risk of a hedging-related loss. +Also, commodity derivative arrangements may limit the benefit we would otherwise receive from increases in the prices for the relevant commodity, and they may require the use of our resources to meet cash margin requirements. +28 +In addition, at December 31, 2016, we had hedged a total of 13,342 MBbls of crude oil and 128,036 BBtu of natural gas for 2017 and 2018. These hedges may be inadequate to protect us from continuing and prolonged declines in oil and natural gas prices, and our current hedge position is smaller than it has been in recent years. +The estimated fair value of our aggregate commodity derivative position as of December 31, 2015, was an asset balance of approximately $263.8 million . As a result of factors including the settlement of commodity derivative positions over the course of 2016 and changes in commodity prices, the estimated fair value of our aggregate commodity derivative position as of December 31, 2016 was a liability balance of approximately $70.0 million . Accordingly, based on our current commodity derivative positions and current commodity prices, we expect that cash flow from our commodity derivative activities will be substantially lower in 2017 than it was in 2016, and may be negative. +Since we do not designate our commodity derivatives as cash flow hedges, we do not currently qualify for use of hedge accounting; therefore, changes in the fair value of commodity derivatives are recorded in our income statements, and our net income is subject to greater volatility than it would be if our commodity derivative instruments qualified for hedge accounting. For instance, if commodity prices rise significantly, this could result in significant non-cash charges during the relevant period, which could have a material negative effect on our net income. +The inability of one or more of our customers or other counterparties to meet their obligations may adversely affect our financial results. +Substantially all of our accounts receivable result from our crude oil, natural gas, and NGLs sales or joint interest billings to a small number of third parties in the energy industry. This concentration of customers and joint interest owners may affect our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our commodity derivatives as well as the commodity derivatives used by our marketing subsidiary expose us to credit risk in the event of nonperformance by counterparties. Nonperformance by our customers or derivative counterparties may adversely affect our financial condition and profitability. We face similar risks with respect to our other counterparties, including the lenders under our revolving credit facility and the providers of our insurance coverage. +We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects. +We frequently own less than 100 percent of the working interest in the oil and gas leases on which we conduct operations, and other parties will own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in oil, natural gas, and NGL prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, a partner may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial position. +Our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur. +The occurrence of a significant accident or other event not fully covered by insurance or in excess of our insurance coverage could have a material adverse effect on our operations and financial condition. Insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. We also do not carry contingent business interruption insurance related to the purchasers of our production. In addition, pollution and environmental risks are generally not fully insurable. +We may not be able to keep pace with technological developments in our industry. +Our industry is characterized by rapid and significant technological advancements. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those or other new technologies at substantial cost. In addition, our competitors may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we were unable to use the most advanced commercially available technology, our business, financial condition and results of operations could be materially adversely affected. +Competition in our industry is intense, which may adversely affect our ability to succeed. +Our industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce crude oil, natural gas, and NGLs, but also carry on refining operations and market petroleum and other products on a regional, national, or worldwide basis. These companies may be able to pay more for productive properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, larger companies may have a greater ability to continue exploration activities during periods of low commodity prices. Larger competitors may also be able to absorb the burden of present and future federal, state, local, and other laws and regulations more easily than we can, which could adversely affect our competitive position. These factors could adversely affect the success of our operations and our profitability. +Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel. +29 +Our future success depends to a large extent on the services of our key employees. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise. +A failure to complete successful acquisitions would limit our growth. +Because our crude oil and natural gas properties are depleting assets, our future reserves, production volumes, and cash flows depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. In addition, we continue to strive to achieve greater efficiencies in our drilling program, and our ability to do so is dependent in part on our ability to complete land trades or exchanges and other acquisitions that allow us to increase our working interests in particular properties. Acquiring additional crude oil and natural gas properties, or businesses that own or operate such properties, when attractive opportunities arise is a significant component of our strategy. We may not be able to identify attractive acquisition opportunities. If we do identify an appropriate acquisition candidate, we may be unable to negotiate mutually acceptable terms with the seller, finance the acquisition or obtain the necessary regulatory approvals. It may be difficult to agree on the economic terms of a transaction, as a potential seller may be unwilling to accept a price that we believe to be appropriately reflective of prevailing economic conditions. If we are unable to complete suitable acquisitions, it will be more difficult to replace our reserves, and an inability to replace our reserves would have a material adverse effect on our financial condition and results of operations. +Acquisitions of properties are subject to the uncertainties of evaluating recoverable reserves and potential liabilities, including environmental uncertainties. +Acquisitions of producing properties and undeveloped properties have been an important part of our growth over time. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, development potential, future commodity prices, operating costs, title issues, and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we generally perform engineering, environmental, geological, and geophysical reviews of the acquired properties, which we believe are generally consistent with industry practices. However, such reviews are not likely to permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well prior to an acquisition and our ability to evaluate undeveloped acreage is inherently imprecise. Even when we inspect a well, we may not always discover structural, subsurface, and environmental problems that may exist or arise. In some cases, our review prior to signing a definitive purchase agreement may be even more limited. In addition, we often acquire acreage without any warranty of title except as to claims made by, through or under the transferor. +When we acquire properties, we will generally have potential exposure to liabilities and costs for environmental and other problems existing on the acquired properties, and these liabilities may exceed our estimates. Often we are not entitled to contractual indemnification associated with acquired properties. We often acquire interests in properties on an “as is” basis with no or limited remedies for breaches of representations and warranties. Therefore, we could incur significant unknown liabilities, including environmental liabilities, or losses due to title defects, in connection with acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, the acquisition of undeveloped acreage is subject to many inherent risks and we may not be able to realize efficiently, or at all, the assumed or expected economic benefits of acreage that we acquire. +Additionally, significant acquisitions can change the nature of our operations depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or may be in different geographic locations than our existing properties. These factors can increase the risks associated with an acquisition. Acquisitions also present risks associated with the additional indebtedness that may be required to finance the purchase price, and any related increase in interest expense or other related charges. +Some of our acquisitions are structured as land trades or exchanges. These transactions may give rise to any or all of the foregoing risks. In addition, transactions of this type create a risk that we will undervalue the properties we transfer to the counterparty in the trade or exchange. Such an undervaluation would result in the transaction being less favorable to us than we expected. +The cost of defending any suits brought against us, and any judgments or settlements resulting from such suits, could have an adverse effect on our results of operations and financial condition. +Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters, and personal injury or property damage matters, in the ordinary course of our business. For example, in recent years, we have been subject to lawsuits regarding royalty practices and payments and matters relating to certain of our affiliated partnerships. In addition in August 2015 we received a Clean Air Act Section 114 Information Request (the "Information Request")from the EPA, and this request could result in penalties or other liabilities. The outcome of pending legal proceedings is inherently uncertain. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, the resolution of such a proceeding could result in penalties or sanctions, settlement costs and/or judgments, consent decrees, or orders requiring a change in our business practices, any of which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties, sanctions or costs may be insufficient. Judgments and estimates to determine accruals or the anticipated range of potential losses related to legal and other proceedings could change from one period to the next, and such changes could be material. +30 +The price of our common stock has been and may continue to be highly volatile, which may make it difficult for shareholders to sell our common stock when desired or at attractive prices. +The market price of our common stock is highly volatile, and we expect it to continue to be volatile for the foreseeable future. Adverse events could trigger declines in the price of our common stock, including, among others: +• +changes in production volumes, worldwide demand and prices for crude oil and natural gas; +• +changes in market prices of crude oil and natural gas; +• +inability to hedge future production at the same pricing level as our current hedges; +• +changes in securities analysts’ estimates of our financial performance; +• +fluctuations in stock market prices and volumes, particularly among securities of energy companies; +• +changes in market valuations and valuation multiples of similar companies; +• +changes in interest rates; +• +announcements regarding adverse timing or lack of success in discovering, acquiring, developing, and producing crude oil and natural gas resources; +• +announcements by us or our competitors of significant contracts, new acquisitions, discoveries, commercial relationships, joint ventures, or capital commitments; +• +decreases in the amount of capital available to us, including as a result of borrowing base reductions and/or lenders ceasing to participate in our revolving credit facility syndicate; +• +operating results that fall below market expectations or variations in our quarterly operating results; +• +loss of a major customer; +• +loss of a relationship with a partner; +• +the identification of and severity of environmental events and governmental and other third-party responses to the events; or +• +additions or departures of key personnel. +External events, such as news concerning economic conditions, counterparties to our natural gas or oil derivatives arrangements, changes in government regulations impacting the oil and natural gas exploration and production industries or the movement of capital into or out of our industry, are also likely to affect the price of our common stock, regardless of our operating performance. Similarly, our stock price could be adversely affected by changes in the way that analysts and investors assess the geological and economic characteristics of the basins in which we operate. For example, general market perceptions of the Permian Basin region have recently become highly favorable, and adverse changes in those perceptions could have a corresponding effect on the price of our stock. Furthermore, general market conditions, including the level of, and fluctuations in, the trading prices of stocks generally could affect the price of our common stock. Recently, the stock markets have experienced price and volume volatility that has affected many companies’ stock prices. Stock prices for many companies have experienced wide fluctuations that have often been unrelated to the operating performance of those companies. These fluctuations may affect the market price of our common stock. +In addition, a portion of the consideration we paid to the sellers in the Delaware Basin acquisitions was in the form our common stock. Those shares are currently subject to lock-up periods set forth in the applicable Investment Agreement. Upon the expiration of the lock-up period, the sellers will be entitled to sell their shares into the public markets, which could cause the market price of our common stock to decline. +Our business could be negatively impacted by security threats, including cybersecurity threats, and other disruptions. +We face various security threats, including attempts by third parties to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. There can be no assurance that the procedures and controls we use to monitor these threats and mitigate our exposure to them will be sufficient in preventing them from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial condition, results of operations, or cash flows. +In particular, the oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling activities, conduct reservoir modeling and reserves estimation, and to process and record financial and operating data. +We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to store, transmit, process, and record sensitive information (including trade secrets, employee information, and financial and operating data), communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil and gas reserves and for many other activities related to our business. The complexity of the technologies needed to explore for and develop oil, natural gas, and NGLs make certain information more attractive to thieves. +Our business partners, including vendors, service providers, operating partners, purchasers of our production, and financial institutions, are also dependent on digital technology. Some of these business partners may be provided limited access to our sensitive information or our information systems and related infrastructure. A vulnerability in the cybersecurity of one or more of our vendors could facilitate an attack on our systems. +As dependence on digital technologies has increased, cyber incidents, including deliberate attacks and unintentional events, have also increased. A cyber-attack could include an attempt to gain unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption. “Phishing” and other types of attempts to obtain unauthorized +31 +information or access are often sophisticated and difficult to detect or defeat. Certain countries are believed to possess cyber warfare capabilities and are credited with attacks on American companies and government agencies. +Our technologies, systems and networks, and those of our business partners, may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, theft of property or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Given the politically sensitive nature of hydraulic fracturing and the controversy generated by its opponents, our technologies, systems and networks may be of particular interest to certain groups with political agendas, which may seek to launch cyber-attacks as a method of promoting their message. A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations. Although to date we have not experienced any significant cyber-attacks, there can be no assurance that we will not be the target of such attacks in the future. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any security vulnerabilities. +Climate change legislation or regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the crude oil, natural gas, and NGLs that we produce while physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. +In December 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because emissions of such GHGs are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings provide the basis for the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. In June 2010, the EPA began regulating GHG emissions from stationary sources under the CAA’s Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. It was widely expected that facilities required to obtain PSD permits for their GHG emissions would be required to also reduce those emissions according to “best available control technology” (“BACT”) standards. In its permitting guidance for GHGs, issued in November 2010, the EPA recommended options for BACT from the largest sources, which include improved energy efficiency, among others. The EPA also issued a final rule in July 2013 retaining the “tailored” permitting thresholds, opting not to extend GHG permitting requirements to smaller stationary sources at that time. +In June 2012, the United States Court of Appeals for the District of Columbia Circuit issued an opinion and order in Coalition for Responsible Regulation v. Environmental Protection Agency, upholding the EPA’s GHG-related rules against challenges from various state and industry group petitioners. In October 2013, the United States Supreme Court in Utility Air Regulatory Group v. EPA , accepted a petition for certiorari to decide whether the EPA correctly determined that its regulation of GHGs from mobile sources triggered permitting requirements under the CAA for stationary sources that emit GHGs. In June 2014, the Supreme Court upheld a portion of the EPA’s GHG stationary source program, but invalidated a portion of it. The Court held that stationary sources already subject to the PSD or Title V program for non-GHG criteria pollutants remained subject to GHG BACT requirements, but ruled that sources subject to the PSD or Title V program only for GHGs could not be forced to comply with GHG BACT requirements. Upon remand, the D.C. Circuit issued an amended judgment, which, among other things, vacated the PSD and Title V regulations under review in that case to the extent they require a stationary source to obtain a PSD or Title V permit solely because the source emits or has the potential to emit GHGs above the applicable major source thresholds. In October 2016, the EPA issued a proposed rule to revise its PSD and Title V regulations applicable to GHGs in accordance with the decisions noted above, including proposing a de minimis level of GHG emissions below which BACT is not required. Depending on what the EPA does in a final rule, it is possible that any regulatory or permitting obligation that limits emissions of GHGs could extend to smaller stationary sources and require us to incur costs to reduce and monitor emissions of GHGs associated with our operations and also adversely affect demand for the crude oil and natural gas that we produce. +In the past, Congress has considered various pieces of legislation to reduce emissions of GHGs. Congress has not adopted any significant legislation in this respect to date, but could do so in the future. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such measures could include a carbon tax, which could result in additional direct costs to our operations. In the absence of such national legislation, many states and regions have taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. For example, in February 2014, Colorado adopted rules directly regulating methane emissions from the oil and gas sector. +President Obama indicated that climate change and GHG regulation was a significant priority for his second term. The President issued a Climate Action Plan in June 2013 that, among other things, calls for a reduction in methane emissions from the oil and gas sector. In November 2013, the President released an Executive Order charging various federal agencies, including the EPA, with devising and pursuing strategies to improve the country’s preparedness and resilience to climate change. In part through these executive actions, the direct regulation of methane emissions from the oil and gas sector continues to be a focus as reflected in both the EPA’s OOOOa and BLM’s venting and flaring regulations both finalized in 2016 as noted above. In addition, a lawsuit has been filed by several northeastern states that would require the EPA to more stringently regulate methane emissions from the oil and gas sector. Finally, the Obama administration reached an agreement during the December 2015 United Nations climate change conference in Paris pursuant to which the United States initially pledged to make a 26-28 percent reduction in its GHG emissions by 2025 against a 2005 baseline and committed to periodically update this pledge every five years starting in 2020. The passage of legislation or executive and other initiatives, including those made to implement the pledges made in Paris, that limit emissions of GHGs from our equipment and operations could require us to incur costs to reduce GHG emissions, and it could also adversely affect demand for the crude oil, natural gas, and NGLs that we produce. +Some have suggested that one consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. Flooding that occurred in Colorado in 2013 is an example of an extreme weather event that negatively impacted our +32 +operations. If such events were to continue to occur, or become more frequent, our operations could be adversely affected in various ways, including through damage to our facilities or from increased costs for insurance. +Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our fuels could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business. +Federal, state and local laws and regulations relating to hydraulic fracturing could result in increased costs, additional drilling and operating restrictions or delays in the production of crude oil, natural gas, and NGLs, and could prohibit hydraulic fracturing activities. +Substantially all of our drilling uses hydraulic fracturing. Hydraulic fracturing is an important and commonly used process in the completion of unconventional wells in shale, coalbed, and tight sand formations. Proposals have been introduced in the U.S. Congress to regulate hydraulic fracturing operations and related injection of fracturing fluids and propping agents used by the crude oil and natural gas industry in fracturing fluids under the SDWA, and to require the disclosure of chemicals used in the hydraulic fracturing process under the SDWA, the Emergency Planning and Community Right-to-Know Act (“EPCRA”), or other laws. Sponsors of these bills, which have been subject to various proceedings in the legislative process, including in the House Energy and Commerce Committee and the Senate Environmental and Public Works Committee, have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies and otherwise cause adverse environmental impacts. In March 2011, the EPA announced its intention to conduct a comprehensive research study on the potential adverse impacts that hydraulic fracturing may have on water quality and public health. In June 2015, the EPA released a draft assessment of the potential impacts to drinking water resources from hydraulic fracturing for public comment and peer review. The assessment concluded that while there are mechanisms by which hydraulic fracturing can impact drinking water resources, there was no evidence that these mechanisms have led to widespread, systemic impacts on drinking water resources in the United States. The EPA’s science advisory board subsequently questioned several elements and conclusions in the EPA’s draft assessment. In December 2016, the EPA released the final report on impacts from hydraulic fracturing activities on drinking water, concluding that hydraulic fracturing activities can impact drinking water resources under some circumstances and identified some factors that could influence these impacts. In addition, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. +The EPA has begun a Toxic Substances Control Act rulemaking which will collect expansive information on the chemicals used in hydraulic fracturing fluid, as well as other health-related data, from chemical manufacturers and processors. The EPA has not indicated when it intends to issue a proposed rule, but it issued an Advanced Notice of Proposed Rulemaking in May 2014, seeking public comment on a variety of issues related to the rulemaking. In October 2015, the EPA also granted, in part, a petition filed by several national environmental advocacy groups to add the oil and gas extraction industry to the list of industries required to report releases of certain “toxic chemicals” under the Toxics Release Inventory (“TRI”) program under EPCRA. The EPA determined that natural gas processing facilities may be appropriate for addition to the scope of TRI and will conduct a rulemaking process to propose such action. On January 6, 2017, the EPA issued a proposed rule to include natural gas processing facilities in the TRI program. +The EPA also finalized major new CAA standards (New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants) applicable to hydraulically fractured natural gas wells and certain storage vessels in August 2012. The standards require, among other things, use of reduced emission completions, or green completions, to reduce volatile organic compound emissions during well completions as well as new controls applicable to a wide variety of storage tanks and other equipment, including compressors, controllers, and dehydrators. Following administrative reconsideration of a portion of the 2012 rules, the EPA issued one set of final amendments to the rule in September 2013 related to storage tanks, and a second set of final amendments largely related to reduced emissions completion requirements in December 2014. Most key provisions in the new CAA standards became effective in 2015. +In January 2015, President Obama announced a comprehensive strategy to further reduce methane emissions from the oil and gas sector. As part of this strategy, in June 2016, the EPA finalized amendments to the 2012 NSPS Quad OOOO rules as well as new requirements focused on achieving additional methane and volatile organic compound reductions from the oil and natural gas industry. Known as NSPS OOOOa, the new rules impose, among other things, new requirements for leak detection and repair, control requirements at oil well completions, replacement of certain pneumatic pumps and controllers, and additional control requirements for gathering, boosting, and compressor stations. These additional methane reduction requirements are substantial and could increase future costs of our operations and require us to make modifications to our operations and install new equipment. In December 2016, the EPA began a process to regulate existing oil and natural gas facilities through a nationwide Information Collection Request (ICR). The ICR has two parts. First, the EPA is requesting general information about equipment at existing facilities from every operator throughout the country. Second, the EPA issued ICRs to a more targeted set of facilities, requesting more detailed information about these operations. During the fall of 2016, the EPA also issued final Control Techniques Guidelines (CTGs) for reducing volatile organic compound emissions from existing oil and natural gas equipment and processes in ozone non-attainment areas, including the Denver Front Range 8-hour ozone non-attainment area. The ICR and CTG processes could culminate in additional controls being required for our existing sources, which may increase the future costs of operations and require modifications or the installation of new equipment. +On the same day the EPA finalized the NSPS OOOOa rules, it also finalized a rule regarding source determination and permitting requirements for the onshore oil and gas industry under the CAA. The final rule defines the term “adjacent,” which is one of three factors used to determine whether stationary sources (including oil and gas equipment and activities) are considered part of a source that is subject to major source permitting requirements under the CAA. Under this final rule, the oil and gas industry and our operations could be subject to increased permitting costs and more stringent control requirements. +33 +The EPA has also issued permitting guidance under the SDWA for the underground injection of liquids from hydraulically fractured (and other) wells where diesel is used. Depending upon how it is implemented, this guidance may create duplicative requirements in certain areas, further slow the permitting process in certain areas, increase the costs of operations, and result in expanded regulation of hydraulic fracturing activities by the EPA and may therefore adversely affect even companies, such as PDC, that do not use diesel fuel in hydraulic fracturing activities. +Certain other federal agencies are analyzing, or have been requested to review, environmental issues associated with hydraulic fracturing. Most notably, in 2015 the U.S. Department of the Interior, through the Bureau of Land Management (the “BLM”), finalized regulations regarding chemical disclosure requirements and other regulations specific to well stimulation activities, including hydraulic fracturing on federal and tribal lands. Due to pending litigation, however, the effective date of the rule has been postponed. In November 2016, BLM finalized rules to further regulate venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. The rules require additional controls and impose new emissions and other standards on certain operations on applicable leases, including committed state or private tracts in a federally approved unit or communitized agreement that drain federal minerals. In October 2015, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA) proposed to expand its regulations in a number of ways, including increased regulation of gathering lines, even in rural areas, and proposed additional standards to revise safety regulations applicable to onshore gas transmission and gathering pipelines in 2016. In May 2015, the U.S. Department of Transportation also issued a final rule regarding the safe transportation of flammable liquids by rail. The final rule imposes certain requirements on “offerors” of crude oil, including sampling, testing, and certification requirements. +In addition, the governments of certain states, including Colorado, Texas, and Ohio, have adopted or are considering adopting laws and regulations that impose or could impose, among other requirements, stringent permitting or air emission control requirements, disclosure, wastewater disposal, baseline sampling, seismic monitoring, well construction and well location requirements on hydraulic fracturing operations, more stringent notification or consultation processes, or otherwise seek to ban underground injection of fracturing wastewater or fracturing activities altogether. For example, in January 2012, the Ohio Department of Natural Resources (“ODNR”) issued a temporary moratorium on the development of hydraulic fracturing disposal wells in northeast Ohio in order to study the relationship between these wells and earthquakes reported in the area. As a result, ODNR promulgated new and more stringent regulations for certain underground injection wells, including requirements for a complete suite of geophysical logs, analytical interpretation of the logs, and enhanced monitoring and recording. More recently, in April 2014, ODNR shut down a number of well sites after a series of small earthquakes in northeast Ohio. After investigating the earthquakes and determining that the connection to hydraulic fracturing was “probable,” ODNR implemented new permit conditions, requiring that operators of well sites within three miles of a known fault must install sensitive seismic-monitoring equipment. Operators must also halt drilling if a seismic event exceeds 1.0 magnitude. In January 2014, the Railroad Commission of Texas finalized a “well integrity rule,” which updates the requirements for drilling and cementing wells, and includes new testing and reporting requirements. In October 2014, the Railroad Commission published a new rule governing the permitting of disposal wells that requires the submission of detailed information related to seismicity. This rule grants the Railroad Commission the ability to deny, modify, suspend or terminate the permit application or existing operating permit. Similar initiatives could spread to other states in which we operate. In addition, oil and gas producers may be subject to lawsuits brought by landowners for earthquake-related damages. +At the local level, some municipalities and local governments have adopted or are considering bans on hydraulic fracturing. Beginning in 2012, voters in the cities of Fort Collins, Boulder, Longmont, Broomfield and Lafayette, Colorado approved bans of varying length on hydraulic fracturing within their respective city limits. In 2014, Boulder and Larimer county lower courts overturned the bans. The cities of Longmont and Fort Collins appealed the decisions. In August 2015, the Court of Appeals requested that the Colorado Supreme Court rule on the issue. The Colorado Supreme Court struck down the Fort Collins and Longmont bans in May 2016. Nonetheless, extended moratoria, like that put in place by Boulder County in December 2016, remain a threat to oil and gas operations in Colorado. +In Texas, voters in the City of Denton approved a local ordinance banning hydraulic fracturing in November 2014. In May 2015, the Texas legislature responded by enacting a statute preempting local government regulation of oil and gas activities. +In Ohio, several municipalities have passed hydraulic fracturing bans. In February 2015, the Ohio Supreme Court ruled that local governments cannot regulate hydraulic fracturing, finding that the State of Ohio has exclusive authority over regulating this activity under the State’s oil and gas preemption law, passed in 2004. In light of the recent Ohio Supreme Court decision, activists in Ohio are calling for the repeal of the oil and gas preemption law. +In addition, lawsuits have been filed against unrelated third parties in several states, including Colorado and Ohio, alleging contamination of drinking water by hydraulic fracturing. Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to crude oil, natural gas, and NGL production activities using hydraulic fracturing techniques. Additional legislation, regulation, litigation, or moratoria could also lead to operational delays or lead us to incur increased operating or capital costs in the production of crude oil, natural gas, and NGLs, including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing or other drilling activities. If these legislative, regulatory, litigation, and other initiatives cause a material decrease in the drilling of new wells or an increase in drilling costs, our profitability could be materially impacted. +Environmental and overall public scrutiny focused on the oil and gas industry is increasing. The current trend is to increase regulation of our operations and the industry. We are subject to complex federal, state, local, and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business. +Our exploration, development, production, and marketing operations are regulated extensively at the federal, state, and local levels. Environmental and other governmental laws and regulations have increased the costs of planning, designing, drilling, installing, operating, and abandoning crude oil and natural gas wells and associated facilities. Under these laws and regulations, we could also be liable for personal injuries, property damage, and natural resource or other damages. Similar to our competitors, we incur substantial operating and capital costs to comply with such laws and regulations. These compliance costs may put us at a competitive disadvantage compared to larger +34 +companies in the industry which can more easily capture economies of scale with respect to compliance. Failure to comply with these laws and regulations may result in various sanctions, including the suspension or termination of our operations or other operational impediments, and could subject us to administrative, civil, and criminal penalties. Moreover, public interest in environmental protection has increased in recent years-particularly with respect to hydraulic fracturing-and environmental organizations have opposed, with some success, certain drilling projects. These regulations also affect our operations, increase our costs of exploration and production, and limit the quantity of crude oil, natural gas, and NGLs that we can produce and market. +A major risk inherent in our drilling plans is the possibility that we will be unable to obtain needed drilling permits from relevant governmental authorities in a timely manner. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well, or the receipt of a permit with unreasonable or unexpected conditions or costs could have a material adverse effect on our ability to explore or develop our properties. Additionally, the crude oil and natural gas regulatory environment could change in ways that substantially increase our financial and managerial compliance costs, increase our exposure to potential damages or limit our activities. +The election of President Trump has resulted in uncertainty with respect to the future regulatory environment affecting the oil and natural gas industry. This uncertainty may affect how our industry is regulated as well as the level of public interest in environmental protection and may result in new or different pressures being exerted. For example, public interest groups may increase their use of litigation as a means to continue to exert pressure on the oil and natural gas industry. Accordingly, while we expect regulatory and enforcement pressures on our business to continue at federal, state, and local levels, the nature, level, and source of such pressures may change. +In August 2015, we received the Information Request from the EPA. The Information Request seeks, among other things, information related to the design, operation, and maintenance of our production facilities in the Denver-Julesburg Basin of Colorado. The Information Request focuses primarily on 46 of our production facilities and asks that we conduct certain sampling and analyses at the identified 46 facilities. We responded to the Information Request in January 2016. We cannot predict the outcome of this matter at this time. Certain other operators in the area have been assessed penalties following similar information requests. +In a related Clean Air Act development, on October 1, 2015, the EPA announced its final rule lowering the existing 75 part per billion (“ppb”) NAAQS for ozone under the CAA to 70 ppb. The lower ozone NAAQS could result in a significant expansion of ozone nonattainment areas across the United States, including areas in which we operate. Oil and natural gas operations in ozone nonattainment areas would likely be subject to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements, and increased permitting delays and costs. In addition, the state of Colorado’s non-attainment status was bumped up from “marginal” to “moderate” for the Denver Metro North Front Range Ozone 8-Hour Non-Attainment area. This increase in non-attainment status triggers significant additional obligations for the State under the CAA. In 2016, the state undertook rulemaking to address the new “moderate” status, culminating in, among others, the incorporation of two existing state-only requirements for oil and natural gas operations into the federally-enforceable State Implementation Plan ("SIP"). In 2017, as part of the federal Control Techniques Guideline (“CTG”) process for oil and natural gas, Colorado will begin a stakeholder and rulemaking effort to compare the CTGs to existing Colorado requirements to ensure they meet applicable federal requirements. This process could result in new or more stringent air quality control requirements applicable to our operations. +In addition, our activities are subject to regulations governing conservation practices, protection of wildlife and habitat, and protection of correlative rights by state governments. For example, the federal Endangered Species Act (“ESA”) and analogous state laws restrict activities that may adversely affect endangered and threatened species or their habitat. The designation of previously unidentified endangered or threatened species or their habitat in areas where we operate could cause us to incur additional costs or become subject to operating delays, restrictions or bans. For example, the U.S. Fish and Wildlife Service in May 2014 proposed a rule to alter how that agency designates critical habitat. That rule was finalized in 2016 and, depending on how it is implemented, could expand the reach of the ESA. +At the state level the COGCC issued a rule in 2013 governing mandatory minimum setbacks between oil and gas wells and occupied buildings and other areas. Also in 2013, the COGCC issued rules that require baseline sampling of certain ground and surface water in most areas of Colorado and impose stringent spill reporting and remediation requirements. These new sampling requirements could increase the costs of developing wells in certain locations. Other regulatory amendments and policies recently adopted or being proposed by the COGCC address wellbore integrity, hydraulic fracturing, well control, waste management, spill reporting, development of large scale facilities in urban mitigation areas, and certain local government notice requirements. In addition to increasing costs of operation and permitting times, some of these rules and policies, as well as litigation by public interest groups challenging application of these rules or policies, could prevent us from drilling wells on certain locations we plan to develop, thereby reducing our reserves as well as our future revenues. +In addition, during 2014, the Colorado Oil and Gas Conservation Act was amended to increase the potential sanctions for violating the Act or its implementing regulations, orders, or permits. These amendments increase the maximum penalty per violation per day from $1,000 to $15,000; eliminate a $10,000 maximum penalty for violations that do not result in significant waste of oil and gas resources, damage to correlative rights, or adverse impact to public health, safety, or welfare; require the COGCC to assess a penalty for each day there is evidence of a violation; and authorize the COGCC to prohibit the issuance of new permits and suspend certificates of clearance for egregious violations resulting from gross negligence or knowing and willful misconduct. In December 2014, the COGCC convened a hearing and adopted proposed amendments to its regulations to implement this new legislation and address certain other issues. Among other things, the amendments create a new process for calculating penalties, new standards for determining days of violation and penalty amounts, new restrictions on the use of informal enforcement procedures, and penalty reductions for voluntary disclosures. Following the adoption of this new penalty scheme, Colorado operators have experienced increased penalties for violations within COGCC’s jurisdiction. +In 2015, the COGCC convened hearings on regulations for large facilities located in urban mitigation areas. These new rules require best available technology and include required mitigations for emissions, flaring, fire, fluid leak detection, repair, reporting, automated well shut-in, storage tank pressure control, and proppant dust control. During these hearings, COGCC staff reported there would +35 +also be site-specific mitigation requirements for noise, ground and surface water protection, visual impacts, and remote stimulation. After debate, the rule did not include duration limits despite an opinion from the State Attorney General Office that the COGCC possessed authority to impose duration limits under current and existing statutes. +In February 2014, the Colorado Department of Public Health and Environment’s Air Quality Control Commission (“AQCC”) finalized regulations imposing stringent new requirements relating to air emissions from oil and gas facilities in Colorado. The new rules impose significantly more stringent control, monitoring, recordkeeping, and reporting requirements than those required under comparable new federal rules. In addition, as part of the rule, the AQCC approved the direct regulation of hydrocarbon (i.e., methane) emissions from the Colorado oil and gas sector. Such state-only, direct regulation of methane (a greenhouse gas) from a single industry sector affected federal regulations from the EPA and the BLM, and continues to have the potential to adversely affect operations in Colorado as well as in other parts of the country. Along the same lines, local governments are undertaking air quality studies to assess potential public health impacts from oil and gas operations. These studies, in combination with other air quality-related studies that are national in scope, may result in the imposition of additional regulatory requirements on oil and gas operations. +CERCLA (or the “Superfund law”) and some comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. This includes potential liability for activities on properties we may currently own or operate upon, but where previous owner/operators caused the release of a hazardous substance. In addition, we may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been or threaten to be released into the environment. From time to time, we are involved in remediation activities at such properties. +Regulatory focus on worker safety and health regulations involving operating hazards in oil and natural gas exploration and production activities is also increasing. One example is a recent investigation by the U.S. Occupational Safety and Health Administration (“OSHA”) and other governmental authorities regarding potential worker exposure to hydrocarbon vapors from certain fuel transfer and related tasks. Several recent worker fatalities at oil and gas facilities nationwide are being reviewed by OSHA and other governmental authorities for a potential link to hydrocarbon vapor exposure. Regulatory requirements generally relating to worker exposure to hydrocarbon vapors could be increased or receive heightened scrutiny going forward. For example, in December 2015, the Department of Labor and the Department of Justice, Environment and Natural Resources Division released a Memorandum of Understanding (“MOU”), announcing an inter-agency effort to increase the enforcement of workplace safety crimes that occur in conjunction with environmental crimes. Consistent with this MOU, DOJ will look for additional felony violations (such as false statements and willful violations of certain standards) when prosecuting safety crimes in order to heighten prospective penalties and strengthen enforcement. In October 2016, OSHA issued a Regional Emphasis Program (REP) notice for the purpose of conducting safety and hazard inspections at oil and gas industry facilities in Region III (Pennsylvania and West Virginia). Similar notices could result in increased OSHA activities in the areas in which we operate. +Other potential laws and regulations affecting us include new or increased severance taxes proposed in several states, including Ohio. This could adversely affect our existing operations in the state and the economic viability of future drilling. Additional laws, regulations, or other changes could significantly reduce our future growth, increase our costs of operations, and reduce our cash flows, in addition to undermining the demand for the crude oil, natural gas, and NGLs we produce. +Certain federal income tax deductions currently available with respect to crude oil and natural gas and exploration and development may be eliminated as a result of future legislation. +Potential legislation, if enacted into law, could make significant changes to U.S. federal and state income tax laws, including the elimination of certain key U.S. federal income tax preferences currently available with respect to crude oil and natural gas exploration and production. The changes could include, but are not limited to (i) the repeal of the percentage depletion deduction for crude oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is not possible at this time to predict how legislation or new regulations that may be adopted to address these proposals would impact our business, but any such future laws and regulations could result in higher federal income taxes, which could negatively affect our financial condition and results of operations. In addition, proposals are made from time to time in states where we operate to implement or increase severance or other taxes at the state level, and any such additional taxes would have similarly adverse effects on us. +Derivatives legislation and regulation could adversely affect our ability to hedge crude oil and natural gas prices and increase our costs and adversely affect our profitability. +In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was enacted into law. The Dodd-Frank Act regulates derivative transactions, including our commodity hedging swaps, and could have a number of adverse effects on us, including the following: +• +The Dodd-Frank Act may limit our ability to enter into hedging transactions, thus exposing us to additional risks related to commodity price volatility; commodity price decreases would then have an increased adverse effect on our profitability and revenues. Reduced hedging may also impair our ability to have certainty with respect to a portion of our cash flows, which could lead to decreases in capital spending and, therefore, decreases in future production and reserves. +• +If, as a result of the Dodd-Frank Act or its implementing regulations, we are required to post cash collateral in connection with our derivative positions, this would likely make it impracticable to implement our current hedging strategy. +• +Our derivatives counterparties are subject to significant requirements imposed as a result of the Dodd-Frank Act. We expect that these requirements will increase the cost to hedge because there will be fewer counterparties in the market and increased counterparty costs will be passed on to us. +36 +The above factors could also affect the pricing of derivatives and make it more difficult for us to enter into hedging transactions on favorable terms. The election of President Trump has resulted in uncertainty with respect to the future of the Dodd-Frank Act generally and derivative regulation specifically, and the future impact this may have on PDC is currently unknown. +ITEM 1B. UNRESOLVED STAFF COMMENTS +None. +ITEM 3. LEGAL PROCEEDINGS +From time to time, we are a party to various legal proceedings in the ordinary course of business. We are not currently a party to any litigation that we believe would have a materially adverse effect on our business, financial condition, results of operations, or liquidity. +Environmental +In August 2015, we received the Information Request from the EPA. The Information Request sought, among other things, information related to the design, operation, and maintenance of our Wattenberg Field production facilities in the Denver-Julesburg Basin of Colorado. The Information Request focused on historical operation and design information for 46 of our production facilities and asks that we conduct sampling and analyses at the identified 46 facilities. We responded to the Information Request in January 2016. Throughout 2016, we continued to meet with the EPA, Department of Justice, and Colorado Department of Public Health and Environment, and in December we received a draft consent decree from the EPA. +In addition, in December 2015, we received a Compliance Advisory pursuant to C.R.S. § 25-7-115(2) from the Colorado Department of Public Health and Environment's Air Quality Control Commission's Air Pollution Control Division alleging that we failed to design, operate, and maintain certain condensate collection, storage, processing, and handling operations to minimize leakage of volatile organic compounds at 65 facilities consistent with applicable standards under Colorado law. This matter has been combined with the matter discussed above. The ultimate outcome related to these combined actions has not been determined at this time. +In 2014, we experienced a loss of well control while drilling an oil and gas well in Morgan County, Ohio. The event resulted in a release of well fluids, including oil based drilling mud. We have completed the appropriate remediation to address the release. In August 2015, the EPA issued us a Notice of Intent seeking civil penalties. We and the EPA settled this matter for a civil fine of approximately $152,000 in November 2015. +Action Regarding Firm Transportation Contracts +A group of 42 independent West Virginia natural gas producers has filed a lawsuit in Marshall County, West Virginia, naming Dominion Transmission, Inc. ("Dominion"), certain entities affiliated with Dominion, and our subsidiary RNG as defendants, alleging various contractual, fiduciary and related claims against the defendants, all of which are associated with firm transportation contracts entered into by plaintiffs and relating to pipelines owned and operated by Dominion and its affiliates. RNG and Dominion have removed the case to the U.S. District Court for the Northern District of West Virginia and have filed pre-trial pleadings. At this time, the case has been remanded back to the state court. RNG is unable to estimate any potential damages associated with the claims, but believes the complaint is without merit and intends to vigorously pursue its defenses. +Class Action Regarding 2010 and 2011 Partnership Purchases +In December 2011, the Company and its wholly-owned merger subsidiary were served with an alleged class action on behalf of unit holders of 12 former limited partnerships, related to its repurchase of the 12 partnerships, which were formed beginning in late 2002 through 2005. The mergers were completed in 2010 and 2011. The action was filed in U.S. District Court for the Central District of California and was titled Schulein v. Petroleum Development Corp . The complaint primarily alleged that the disclosures in the proxy statements issued in connection with the mergers were inadequate, and a state law breach of fiduciary duty. In January 2014, the plaintiffs were certified as a class by the court. +In October 2014, the Company and plaintiffs’ counsel reached a settlement agreement in principle that was given final court approval in March 2015. Under this settlement agreement, the plaintiffs received a cash payment of $37.5 million in January 2015, of which the Company paid $31.5 million and insurers paid $6.0 million . In March 2015, the class action was dismissed with prejudice and all class claims were released. In 2014, the Company recorded an expense of $31.5 million related to this litigation, which was included in general and administrative expense in the consolidated statements of operations. +Further information regarding our legal proceedings can be found in the footnote titled Commitments and Contingencies – Litigation to our consolidated financial statements included elsewhere in this report. +ITEM 4. MINE SAFETY DISCLOSURES +Not applicable. +37 +PART II +ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES +Our common stock, par value $0.01 per share, is traded on the NASDAQ Global Select Market under the symbol PDCE. The following table sets forth the range of high and low sales prices for our common stock based on intra-day trading for each of the periods presented: +High +Low +January 1 - March 31, 2015 +$ +55.47 +$ +37.62 +April 1 - June 30, 2015 +61.41 +51.01 +July 1 - September 30, 2015 +61.55 +41.17 +October 1 - December 31, 2015 +64.99 +52.46 +January 1 - March 31, 2016 +60.56 +42.68 +April 1 - June 30, 2016 +65.86 +51.92 +July 1 - September 30, 2016 +71.00 +50.12 +October 1 - December 31, 2016 +84.88 +59.82 +As of February 15, 2017 , we had approximately 675 stockholders of record. Since inception, no cash dividends have been declared on our common stock. Cash dividends are restricted under the terms of our revolving credit facility as well as the indenture agreements governing our 2024 Senior Notes and our 7.75% senior notes due 2022 ("2022 Senior Notes"), and we presently intend to continue a policy of using retained earnings for expansion of our business. +The following table presents information about our purchases of our common stock during the three months ended December 31, 2016 : +Period +Total Number of Shares Purchased (1) +Average Price Paid per Share +October 1 - 31, 2016 +5,742 +$ +66.98 +November 1 - 30, 2016 +— +$ +— +December 1 - 31, 2016 +19,969 +$ +73.37 +Total fourth quarter 2016 purchases +25,711 +$ +71.94 +__________ +(1) +Purchases primarily represent shares purchased from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans. +38 +STOCKHOLDER PERFORMANCE GRAPH +The performance graph below compares the cumulative total return of our common stock over the five-year period ended December 31, 2016 , with the cumulative total returns for the same period for the Standard and Poor's ("S&P") 500 Index and the Standard Industrial Code ("SIC") Index. The SIC Index is a weighted composite of 211 crude petroleum and natural gas companies. The cumulative total stockholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on December 31, 2011 , and in the S&P 500 Index and the SIC Index on the same date. The results shown in the graph below are not necessarily indicative of future performance. +39 +ITEM 6. SELECTED FINANCIAL DATA +Year Ended/As of December 31, +2016 (1) +2015 +2014 +2013 +2012 +(in millions, except per share data and as noted) +Statement of Operations (From Continuing Operations) (2): +Crude oil, natural gas and NGLs sales +$ +497.4 +$ +378.7 +$ +471.4 +$ +340.8 +$ +228.0 +Commodity price risk management gain (loss), net of actual settlements and changes in mark-to-market valuation adjustments +(125.7 +) +$ +203.2 +310.3 +(23.9 +) +29.3 +Total revenues +382.9 +595.3 +856.2 +392.7 +307.1 +Income (loss) from continuing operations +(245.9 +) +(68.3 +) +107.3 +(21.1 +) +(19.4 +) +Earnings (loss) per share from continuing operations: +Basic +$ +(5.01 +) +$ +(1.74 +) +$ +3.00 +$ +(0.65 +) +$ +(0.70 +) +Diluted +(5.01 +) +(1.74 +) +2.93 +(0.65 +) +(0.70 +) +Statement of Cash Flows: +Net cash flows from: +Operating activities +$ +486.3 +$ +411.1 +$ +236.7 +$ +159.2 +$ +174.7 +Investing activities +(1,509.1 +) +(604.3 +) +(474.1 +) +(217.1 +) +(451.9 +) +Financing activities +1,266.1 +178.0 +60.3 +248.7 +271.4 +Capital expenditures from development and exploration activities (3) +436.9 +599.5 +623.8 +384.7 +344.2 +Acquisitions of crude oil and natural gas properties +1,073.7 +— +— +9.7 +312.2 +Balance Sheet: +Total assets +$ +4,485.8 +$ +2,370.5 +$ +2,331.1 +$ +1,991.7 +$ +1,777.9 +Working capital +129.2 +30.7 +89.5 +90.0 +(67.6 +) +Total debt, net of unamortized discount and debt issuance costs +1,044.0 +642.4 +655.5 +593.9 +637.5 +Total equity +2,622.8 +1,287.2 +1,137.4 +967.6 +703.2 +Pricing and Production Expenses From Continuing Operations (per Boe and as a percent of sales for Production Taxes): +Average sales price (excluding net settlements on derivatives) +$ +22.43 +$ +24.64 +$ +50.72 +$ +52.23 +$ +46.85 +Lease operating expenses +$ +2.70 +$ +3.71 +$ +4.56 +$ +5.18 +$ +5.54 +Transportation, gathering, and processing +$ +0.83 +$ +0.66 +$ +0.49 +$ +0.79 +$ +0.56 +Production taxes +$ +1.42 +$ +1.20 +$ +2.76 +$ +3.33 +$ +2.86 +Production taxes as a percent of sales +6.3 +% +4.9 +% +5.4 +% +6.4 +% +6.1 +% +Production (MBoe): +Production from continuing operations +22,175.9 +15,369.4 +9,294.4 +6,524.7 +4,866.5 +Production from discontinued operations +— +— +1,093.0 +2,032.6 +3,458.7 +Total production +22,175.9 +15,369.4 +10,387.4 +8,557.3 +8,325.2 +Total proved reserves (MMBoe) (4)(5) +341.4 +272.8 +250.1 +265.8 +192.8 +______________ +(1) +In 2016, we closed acquisitions in the Delaware Basin for aggregate consideration of approximately $1.76 billion . See footnotes titled Properties and Equipment - Delaware Basin Acreage Acquisition and Business Combination to our consolidated financial statements included elsewhere in this report for further information regarding these acquisitions. +(2) +In 2014, we completed the sale of our ownership interest in PDCM. Our proportionate share of PDCM's Marcellus Shale results of operations have been separately reported as discontinued operations. See footnote titled Divestiture and Discontinued Operations to our consolidated financial statements included elsewhere in this report for further information regarding this divestiture. +(3) +Includes impact of change in accounts payable related to capital expenditures. +(4) +Includes total proved reserves related to our Marcellus Shale and shallow Upper Devonian Appalachian Basin assets of 40 MMBoe and 30 MMBoe as of December 31, 2013 and 2012, respectively. The joint venture that owned these reserves was sold in late 2014. +(5) +Includes total proved reserves related to our Piceance Basin and North Eastern Colorado ("NECO") assets of 14 MMBoe as of December 31, 2012. These assets were sold in 2013. +40 +ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +The following discussion and analysis, as well as other sections in this report, should be read in conjunction with our consolidated financial statements and related notes to consolidated financial statements included elsewhere in this report. Further, we encourage you to revisit the Special Note Regarding Forward-Looking Statements in Part I of this report. +SUMMARY +2016 Financial Overview of Operations and Liquidity +Production volumes increased to 22.2 MMBoe in 2016 , including 0.2 MMBoe from our recent acquisitions in the Delaware Basin, compared to 15.4 MMBoe in 2015 , representing an increase of 44 percent . The increase in production volumes was primarily attributable to our successful horizontal Niobrara and Codell drilling program in the Wattenberg Field. Crude oil production increased 25 percent in 2016 , which comprised approximately 39 percent of total production. Natural gas production increased 55 percent and NGLs increased 70 percent in 2016 compared to 2015 . These increases were the result of our shift in focus to the higher rate of return drilling projects located in the higher gas to oil ratio inner and middle core areas of the Wattenberg Field during the first half of 2016. On a combined basis, total liquids production of crude oil and NGLs comprised 61 percent of production in 2016 compared to 64 percent of production in 2015, a decrease of four percent. For the month ended December 31, 2016 , we maintained an average production rate of 73 MBoe per day, up from 52 MBoe per day for the month ended December 31, 2015 . +Crude oil, natural gas, and NGLs sales increased to $497.4 million in 2016 compared to $378.7 million in 2015 , due to a 44 percent increase in production, offset in part by a nine percent decrease in the weighted-average realized prices of crude oil, natural gas, and NGLs, driven by lower commodity prices and changes in commodity mix. Crude oil, natural gas, and NGLs sales, coupled with the impact of positive net settlements of derivatives, also increased in 2016 as compared to 2015. When combining the physical commodity sales and the net settlements received on our commodity derivative instruments, the total net revenues increased 14 percent to $705.4 million in 2016 from $617.6 million in 2015. The low crude oil and natural gas index prices in 2016 and 2015 were the primary reason for the positive net settlements of $208.1 million and $238.9 million on commodity derivatives in 2016 and 2015 , respectively. +In 2016, we generated a net loss of $245.9 million , or $5.01 per diluted share. In the same period we generated $435.6 million of adjusted EBITDA, a non-U.S. GAAP financial measure, and invested $396.4 million in the development and exploration of our oil and natural gas properties, which is net of the change in accounts payable related to capital expenditures. Our cash flow from operations was $486.3 million and our adjusted cash flow from operations was $466.8 million in 2016. Adjusted EBITDA and adjusted cash flow from operations are non-U.S. GAAP financial measures as defined and more fully described later in this section. +Other significant changes impacting our 2016 results of operations include the following: +• +The net change in the fair value of unsettled derivative positions in 2016 was a loss of $333.8 million compared to a loss of $35.8 million in 2015 . The decrease in the fair value of unsettled derivative positions is largely driven by the normal monthly settlements of the commodity derivative instruments in 2016. Additionally, the change in fair value was attributable to hedging positions entered into in 2016 at lower strike prices and the upward shift in the crude oil and natural gas forward curves that occurred during 2016 versus a downward shift in 2015. +• +Production tax expense increased to $31.4 million in 2016 from $18.4 million in 2015 due to increased production of 44 percent and higher overall sales proceeds. Additionally, we had a higher effective production tax rate in 2016 primarily from a reduction in ad valorem credits from the prior year to offset current year severance taxes due. +• +Impairment of crude oil and natural gas properties was $10.0 million in 2016 compared to $161.6 million in 2015 . The 2016 impairments are a result of the write-off of certain leases that were no longer part of our development plan and to reflect the fair value of other land and buildings that are held for sale. The Utica Shale was the largest component of the 2015 write-down which included both producing and non-producing crude oil and natural gas properties. +• +General and administrative expense increased to $112.5 million in 2016 compared to $90.0 million in 2015 . The increase was attributable to professional and transaction fees related to the Delaware Basin acquisitions and increases in payroll and employee benefits, as we increased our staff by nine percent over the course of 2016. +• +Depreciation, depletion, and amortization expense increased to $416.9 million in 2016 compared to $303.3 million in 2015 , due to the increase in production volumes from year to year. +• +We recorded a provision for uncollectible notes receivable of $44.0 million in the first quarter of 2016 to impair a note receivable. +• +Interest expense increased to $62.0 million in 2016 from $47.6 million in 2015. The increase was primarily attributable to a $9.3 million charge for the bridge loan commitment related to our initial Delaware Basin acquisition, a $7.4 million increase in interest expense resulting from the issuance of our 2024 Senior Notes, and a $2.9 million increase in interest expense for the issuance of our 2021 Convertible Notes in September 2016. The increases were partially offset by a $5.1 million decrease in interest expense resulting from the net settlement of our 2016 Convertible Notes in May 2016. +Available liquidity as of December 31, 2016 was $932.4 million compared to $402.2 million as of December 31, 2015. Available liquidity as of December 31, 2016 is comprised of $244.1 million of cash and cash equivalents and $688.3 million available for borrowing under our revolving credit facility. In December 2016, pursuant to an amendment to our credit facility and in conjunction with the closing of +41 +the acquisitions of the Delaware Basin properties, we increased the aggregate commitment under our revolving credit facility from $450 million to $700 million. +In March 2016, we completed a public offering of 5.9 million shares of our common stock at a price to us of $50.11 per share. Net proceeds of the offering were $296.6 million, after deducting offering expenses and underwriting discounts. We used the net proceeds of the offering to repay all amounts then outstanding on our revolving credit facility, the principal and interest owed upon the maturity of the $115 million face value of 2016 Convertible Notes in May 2016 and for general corporate purposes. We settled the 2016 Convertible Notes with a combination of cash and stock, paying the aggregate principal amount, plus cash for fractional shares, totaling approximately $115 million. The conversion price for the 2016 Convertible Notes was $42.40 per share, resulting in the issuance of 792,406 shares of common stock for the excess conversion value. +In June 2016, we entered into definitive agreements with Noble Energy Inc. and certain of its subsidiaries ("Noble") to consolidate certain acreage positions in the core Wattenberg Field. In September 2016, we closed the acreage exchange transaction. Pursuant to the transaction, we exchanged leasehold acreage and, to a lesser extent, interests in certain development wells. Upon closing, we received approximately 13,500 net acres in exchange for approximately 11,700 net acres, with no cash exchanged between the parties. The difference in net acres was primarily due to variances in leasehold net revenue interests and third-party mid-stream contracts. This acreage trade has resulted in opportunities for longer length horizontal laterals with increased working interests, while minimizing potential surface impact. +In September 2016, we sold 9.1 million shares of common stock for net proceeds of $558.5 million, we issued the 2024 Senior Notes for net proceeds of $392.2 million , and we issued the 2021 Convertible Senior Notes convertible at 11.7113 shares of common stock per $1,000 principal amount for net proceeds of $193.9 million (collectively, the "Securities Issuances"). The total net proceeds of $1.1 billion from the Securities Issuances were used to fund a portion of the purchase price of the acquisitions of the Delaware Basin properties, pay related fees and expenses, and for general corporate purposes. +We intend to continue to manage our liquidity position by a variety of means, including through the generation of cash flow from our operations, investment in projects with attractive rates of return, protection of cash flows on a portion of our anticipated sales through the use of an active commodity derivative program, utilization of our borrowing capacity under our revolving credit facility, and the pursuit of capital markets transactions from time to time. +Delaware Basin Acquisitions +Through a deliberate and disciplined process of searching for, and evaluating, a large-scale acquisition in a U.S. onshore basin that diversifies our operations and is capable of creating material long-term value-added growth, we recently acquired proved and unproved leasehold in the Delaware Basin in Reeves and Culberson Counties in Texas. The acquisition criteria focused on four key attributes: +• +top-tier acreage in core geologic positions; +• +significant drilling inventory with additional expansion through down spacing; +• +portfolio optionality for capital allocation and diversification; and +• +the ability to deliver long-term corporate accretion. +We believe the Delaware Basin acquisitions met these criteria. +42 +We completed two acquisition transactions associated with the Delaware Basin. The first acquisition closed in early December 2016, and we acquired acreage, approximately 30 producing wells and related midstream infrastructure in Reeves and Culberson Counties, Texas, for an aggregate consideration to the sellers of approximately $1.64 billion , which was comprised of approximately $952.1 million in cash (including the repayment of $40.0 million of debt from the seller at closing) and 9.4 million shares of our common stock valued at approximately $690.7 million at the time the acquisition closed. The total purchase price remains subject to certain post-closing adjustments as of the date of this report and we expect that it may take into mid-2017 until all post-closing adjustments are settled. +The acquisitions were accounted for under the acquisition method. Accordingly, we conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. The details of the purchase price and the preliminary allocation of the purchase price for the first transaction are presented below (in thousands): +Acquisition costs: +Cash, net of cash acquired +$ +912,142 +Retirement of seller's debt +40,000 +Total cash consideration +952,142 +Common stock, 9.4 million shares +690,702 +Other purchase price adjustments +1,026 +Total acquisition costs +$ +1,643,870 +Recognized amounts of identifiable assets acquired and liabilities assumed: +Assets acquired: +Current assets +$ +8,201 +Crude oil and natural gas properties - proved +216,000 +Crude oil and natural gas properties - unproved +1,721,334 +Infrastructure, pipeline, and other +32,590 +Construction in progress +12,148 +Goodwill +62,041 +Total assets acquired +2,052,314 +Liabilities assumed: +Current liabilities +(24,844 +) +Asset retirement obligations +(3,705 +) +Deferred tax liabilities, net +(379,895 +) +Total liabilities assumed +(408,444 +) +Total identifiable net assets acquired +$ +1,643,870 +The 2016 results of operations of the acquired properties in the first transaction had a loss from operations of $1.7 million , which is included in our consolidated statements of operations for 2016. +The second transaction closed at the end of December 2016. In this transaction, we acquired primarily unproved acreage for cash consideration of $120.6 million. This acquisition is also subject to final settlement as there were some limited producing assets. The final settlement is not expected to be completed until mid-2017. +2016 Drilling Overview +During 2016 , we continued to execute our strategic plan to grow production while preserving our financial strength and liquidity. Through July 2016, we ran four automated drilling rigs in the Wattenberg Field. In August 2016, we decreased the number of automated drilling rigs to three in anticipation of higher working interests in wells drilled resulting from the acreage exchange. During 2016, we spud 128 gross horizontal, (109.4 net), wells and turned-in-line 140 gross, (109.7 net), horizontal wells in the Wattenberg Field. Also in the Wattenberg Field, we participated in 17 gross (3.6 net) horizontal non-operated wells that were spud and 24 gross (5.0 net) horizontal non-operated wells which were turned-in-line. In the Utica Shale, we completed five gross horizontal (4.5 net) wells, all of which were turned-in-line in 2016. Following the closing of our acquisitions in the Delaware Basin, we spud one well (0.9 net), and turned-in-line another well (1.0 net) prior to the end of 2016. +43 +The following table summarizes our 2016 drilling and completion activity: +Gross +Net +In-process as of December 31, 2015 +102 +63.4 +Wells spud during the period +144 +112.2 +Wells turned-in-line to sales +(170 +) +(120.2 +) +Acquired in-process +5 +4.9 +In-process as of December 31, 2016 +81 +60.3 +Our in-process wells represent wells that are in the process of being drilled and/or have been drilled and are waiting to be fractured and/or for gas pipeline connection. We do not have a practice of inventorying our drilled but uncompleted wells. The majority of these in-process wells at each year end are drilled, but not completed as we do not begin the completion process until the entire well pad is drilled. All costs incurred through the end of the period have been capitalized or accrued to capital, while the capital investment to complete the wells will be incurred in the following year. The cost of completing these wells is included in our 2017 capital forecast. +2017 Operational Outlook +We expect our production for 2017 to range between 30.0 MMBoe to 33.0 MMBoe and we estimate that our production rate will average approximately 82,200 to 90,400 Boe per day. We expect that 41 percent to 43 percent of our 2017 production will be comprised of crude oil and 20 percent to 22 percent will be NGLs, for total liquids of 61 percent to 65 percent of our total 2017 production. Our previously-announced 2017 capital forecast of between $725 million and $775 million is focused on continued development in the core Wattenberg Field and the integration of the core Delaware Basin assets. Due to recent cost escalation for services and the modification of our drilling schedule in the Delaware Basin, where we have accelerated the deployment of an additional drilling rig, we currently expect that our 2017 capital investment will be at or near the high end of the range. These changes to our capital investment outlook are not expected to impact our expected 2017 production as the incremental wells drilled are contemplated to be turned-in-line to sales late in the year. +Wattenberg Field. The 2017 investment outlook of approximately $470 million in the Wattenberg Field anticipates a three to four-rig drilling program based on our current commodity price outlook. Approximately $460 million of our 2017 capital investment program is expected to be allocated to development activities, comprised of approximately $440 million for our operated drilling program and approximately $20 million for wells drilled and operated by others. The remainder of the Wattenberg Field capital investment program is expected to be used for miscellaneous workover and capital projects. Wells in the Wattenberg Field typically have productive horizons at a depth of approximately 6,500 to 7,500 feet below the surface. In 2017, to help manage our priorities, we now anticipate spudding 137 and turning-in-line approximately 139 horizontal operated wells with lateral lengths of 5,000 to 10,000 feet. +Delaware Basin. Our 2017 investment outlook contemplates operating a two-rig to four-rig program in the Delaware Basin from time to time during the year. Total capital investment in the Delaware Basin is estimated to be $300 million, of which approximately $235 million is allocated to spud 31 and turn-in-line an estimated 26 wells. Of the the 26 planned turn-in-lines, 14 are expected to have laterals of approximately 10,000 horizontal feet with an estimated 70 to 75 completion stages per well. Similarly spaced completion stages are anticipated for the remaining 12 turn-in-lines. Wells in the Delaware Basin typically have productive horizons at a depth of approximately 9,000 to 11,000 feet below the surface. Based on the timing of our operations and the requirements to hold acreage, we may adapt our capital investment program to drill wells in addition to those currently anticipated, as we are continuing to analyze terms of the leaseholds related to our recent acquisitions of properties in the basin. We plan to invest approximately $35 million for leasing, seismic, and technical studies with an additional $30 million for midstream-related projects including gas connections, salt water disposal wells, and surface location infrastructure. +Utica Shale . At this time, we are currently evaluating all of our strategic alternatives with respect to our Utica Shale position. As a result of such evaluation, we are deferring our 2017 planned expenditure of $18 million to drill, complete, and turn-in-line two wells in Guernsey County. In 2017, our capital investment program for the Utica Shale is expected to include between $2 million to $3 million for additional leasing. Such leasing may be necessary to complete certain drilling operations if we decide to continue development of our existing position in the northern portion of our acreage. +44 +Results of Operations +Summary Operating Results +The following table presents selected information regarding our operating results from continuing operations: +Year Ended December 31, +Percent Change +2016 +2015 +2014 +2016-2015 +2015-2014 +(dollars in millions, except per unit data) +Production +Crude oil (MBbls) +8,728 +6,984 +4,322 +25.0 +% +61.6 +% +Natural gas (MMcf) +51,730 +33,302 +19,298 +55.3 +% +72.6 +% +NGLs (MBbls) +4,826 +2,835 +1,756 +70.2 +% +61.4 +% +Crude oil equivalent (MBoe) +22,176 +15,369 +9,294 +44.3 +% +65.4 +% +Average Boe per day +60,590 +42,108 +25,464 +43.9 +% +65.4 +% +Crude Oil, Natural Gas and NGLs Sales +Crude oil +$ +348.9 +$ +280.3 +$ +348.6 +24.5 +% +(19.6 +)% +Natural gas +91.6 +68.0 +74.7 +34.7 +% +(9.0 +)% +NGLs +56.9 +30.4 +48.1 +87.2 +% +(36.8 +)% +Total crude oil, natural gas, and NGLs sales +$ +497.4 +$ +378.7 +$ +471.4 +31.3 +% +(19.7 +)% +Net Settlements on Commodity Derivatives (1) +Crude oil +$ +165.2 +$ +208.9 +$ +2.3 +(20.9 +)% +* +Natural gas +42.9 +30.0 +(3.1 +) +43.0 +% +* +Total net settlements on derivatives +$ +208.1 +$ +238.9 +$ +(0.8 +) +(12.9 +)% +* +Average Sales Price (excluding net settlements on derivatives) +Crude oil (per Bbl) +$ +39.96 +$ +40.14 +$ +80.67 +(0.4 +)% +(50.2 +)% +Natural gas (per Mcf) +1.77 +2.04 +3.87 +(13.2 +)% +(47.3 +)% +NGLs (per Bbl) +11.80 +10.72 +27.39 +10.1 +% +(60.9 +)% +Crude oil equivalent (per Boe) +22.43 +24.64 +50.72 +(9.0 +)% +(51.4 +)% +Average Costs and Expenses (per Boe) +Lease operating expenses +$ +2.70 +$ +3.71 +$ +4.56 +(27.2 +)% +(18.6 +)% +Production taxes +1.42 +1.20 +2.76 +18.3 +% +(56.5 +)% +Transportation, gathering, and processing expenses +0.83 +0.66 +0.49 +25.8 +% +34.7 +% +General and administrative expense +5.07 +5.85 +13.29 +(13.3 +)% +(56.0 +)% +Depreciation, depletion, and amortization +18.80 +19.73 +20.71 +(4.7 +)% +(4.7 +)% +Other Costs and Expenses +Exploration expense +$ +4.7 +$ +1.1 +$ +0.9 +* +16.4 +% +Impairment of properties and equipment +10.0 +161.6 +166.8 +(93.8 +)% +(3.1 +)% +Interest expense +62.0 +47.6 +47.8 +30.3 +% +(0.6 +)% +Gas Marketing Contribution Margin (2) +$ +(1.5 +) +$ +(0.8 +) +$ +(0.4 +) +(87.5 +)% +(100.0 +)% +* +Percentage change is not meaningful or equal to or greater than 300% or not applicable. +Amounts may not recalculate due to rounding. +______________ +(1) +Represents net settlements on derivatives related to crude oil and natural gas sales, which do not include net settlements on derivatives related to gas marketing. +(2) +Represents sales from gas marketing, net of costs of gas marketing, including net settlements and net change in fair value of unsettled derivatives related to gas marketing activities. +45 +Crude Oil, Natural Gas and NGLs Sales +The following tables present crude oil, natural gas, and NGLs production and weighted-average sales price for continuing operations: +Year Ended December 31, +Change +Production by Operating Region +2016 +2015 +2014 +2016-2015 +2015-2014 +Crude oil (MBbls) +Wattenberg Field +8,229.7 +6,490.4 +4,026.7 +26.8 +% +61.2 +% +Delaware Basin (1) +79.5 +— +— +* +* +Utica Shale +419.1 +493.4 +295.2 +(15.1 +)% +67.1 +% +Total +8,728.3 +6,983.8 +4,321.9 +25.0 +% +61.6 +% +Natural gas (MMcf) +Wattenberg Field +48,889.1 +30,752.8 +17,108.9 +59.0 +% +79.7 +% +Delaware Basin (1) +373.3 +— +— +* +* +Utica Shale +2,467.8 +2,548.9 +2,189.1 +(3.2 +)% +16.4 +% +Total +51,730.2 +33,301.7 +19,298.0 +55.3 +% +72.6 +% +NGLs (MBbls) +Wattenberg Field +4,567.5 +2,615.9 +1,605.7 +74.6 +% +62.9 +% +Delaware Basin (1) +36.1 +— +— +* +* +Utica Shale +222.2 +219.4 +150.5 +1.3 +% +45.8 +% +Total +4,825.8 +2,835.3 +1,756.2 +70.2 +% +61.4 +% +Crude oil equivalent (MBoe) +Wattenberg Field +20,945.4 +14,231.7 +8,483.8 +47.2 +% +67.8 +% +Delaware Basin (1) +177.8 +— +— +* +* +Utica Shale +1,052.7 +1,137.7 +810.6 +(7.5 +)% +40.4 +% +Total +22,175.9 +15,369.4 +9,294.4 +44.3 +% +65.4 +% +(1) Reflects the Delaware Basin acquisitions that occurred in December 2016. +* +Percentage change is not meaningful or equal to or greater than 300%. +Amounts may not recalculate due to rounding. +46 +Year Ended December 31, +Weighted-Average Sales Price by Operating Region +Change +(excluding net settlements on derivatives) +2016 +2015 +2014 +2016-2015 +2015-2014 +Crude oil (per Bbl) +Wattenberg Field +$ +39.99 +$ +40.03 +$ +80.61 +(0.1 +)% +(50.3 +)% +Delaware Basin (1) +49.28 +— +— +* +* +Utica Shale +37.62 +41.59 +81.52 +(9.5 +)% +(49.0 +)% +Weighted-average price +39.96 +40.14 +80.67 +(0.4 +)% +(50.2 +)% +Natural gas (per Mcf) +Wattenberg Field +1.77 +2.06 +3.94 +(14.1 +)% +(47.7 +)% +Delaware Basin (1) +2.78 +— +— +* +* +Utica Shale +1.58 +1.85 +3.35 +(14.6 +)% +(44.8 +)% +Weighted-average price +1.77 +2.04 +3.87 +(13.2 +)% +(47.3 +)% +NGLs (per Bbl) +Wattenberg Field +11.59 +10.58 +25.95 +9.5 +% +(59.2 +)% +Delaware Basin (1) +17.87 +— +— +* +* +Utica Shale +15.11 +12.43 +42.76 +21.6 +% +(70.9 +)% +Weighted-average price +11.80 +10.72 +27.39 +10.1 +% +(60.9 +)% +Crude oil equivalent (per Boe) +Wattenberg Field +22.38 +24.64 +51.10 +(9.2 +)% +(51.8 +)% +Delaware Basin (1) +31.50 +— +— +* +* +Utica Shale +21.88 +24.59 +46.87 +(11.0 +)% +(47.5 +)% +Weighted-average price +22.43 +24.64 +50.72 +(9.0 +)% +(51.4 +)% +(1) Reflects the Delaware Basin acquisitions that occurred in December 2016. +* +Percentage change is not meaningful or equal to or greater than 300%. +Amounts may not recalculate due to rounding. +The year-over-year change in crude oil, natural gas, and NGLs sales revenue were primarily due to the following: +Year Ended December 31, +2016 +2015 +(in millions) +Increase in production from development of existing properties +$ +128.8 +$ +298.5 +Increase in production from acquisitions +0.2 +— +Decrease in average crude oil price +(1.6 +) +(283.1 +) +Decrease in average natural gas price +(14.0 +) +(60.9 +) +Increase (decrease) in average NGLs price +5.2 +(47.2 +) +Total increase (decrease) in crude oil, natural gas and NGLs sales revenue +$ +118.6 +$ +(92.7 +) +Production volumes increased 44 percent in 2016 compared to 2015. Crude oil production increased 25 percent in 2016, which comprised approximately 39 percent of total production. Natural gas production increased 55 percent and NGLs increased 70 percent in 2016 compared to 2015. The increases in crude oil are different from the comparative period because of our shift in focus to the higher rate of return drilling projects located in the higher gas to oil ratio inner and middle core areas of the Wattenberg Field during the first half of 2016. On a combined basis, total liquids production of crude oil and NGLs comprised 61 percent of production in 2016 compared to 64 percent of production in 2015, a decrease of four percent. Production volumes increased 65 percent in 2015 compared to 2014. Production of crude oil, natural gas and NGLs was relatively consistent across commodities at 62 percent, 73 percent, and 61 percent, respectively, as we focused our 2015 and 2014 drilling on the middle and outer core areas of the Wattenberg Field. We currently expect our 2017 individual commodity growth and overall production growth to be similar. +Crude oil, natural gas, and NGLs sales in 2016 increased 31 percent compared to 2015 . The increase was primarily attributable to higher volumes sold in 2016 of 22.2 MMBoe, up from 15.4 MMBoe in 2015 . This was offset in part by a decrease in commodity prices and modest changes in the commodity mix, which resulted in a nine percent decline in the average realized price on a barrel of oil equivalent basis in 2016 compared to 2015. The higher volumes were primarily contributed from turning in-line to sales 140 new gross wells in the Wattenberg Field that delivered significant production volumes. Included in the 22.2 MMBoe is production of 0.2 MMBoe from our acquisitions of producing properties in the Delaware Basin. Our average daily sales volumes increased to 60.6 MBoe per day in 2016 +47 +compared to 42.1 MBoe per day in 2015 as a result of continued drilling and completion activities. The average NYMEX crude oil and natural gas prices decreased by 11 percent and eight percent in 2016 compared to 2015. For crude oil the change was to $43.32 per barrel in 2016 from $48.80 per barrel in 2015, and we were able to offset the majority of the decrease in the NYMEX sales prices through actions that decreased our contractual deductions to $4.39 per barrel in 2016 from $9.95 per barrel in 2015. The natural gas realized sales price decreased more than the decrease in the NYMEX price because a portion of our deductions for natural gas are based on fixed price elements and have a more pronounced effect at lower prices. +Crude oil, natural gas, and NGLs sales in 2015 decreased 20 percent compared to 2014 . The decrease was primarily attributable to a significant decrease in commodity prices, resulting in a 51 percent decline in the price of a barrel of crude oil equivalent in 2015 compared to 2014. The decrease was offset in part by the higher volumes sold in 2015 of 15.4 MMBoe, up from 9.3 MMBoe in 2014. Our average daily sales volumes increased to 42.1 MMBoe per day in 2015 compared to 25.5 MMBoe per day in 2014 . The average NYMEX crude oil and natural gas prices decreased by 47 percent and 40 percent in 2015 and 2014, respectively. +During various times between 2012 and the summer of 2015, our production had been adversely affected by high line pressures in the natural gas gathering facilities in the Wattenberg Field. Such pressures did not materially affect our production during 2016 due to the investment in the midstream capabilities by our midstream providers and a decrease in development activity by certain producers in the Wattenberg Field resulting in more relative capacity being available to deliver our production. In 2016, approximately 90 percent of our production in the Wattenberg Field was delivered from horizontal wells, with the remaining 10 percent coming from vertical wells. The horizontal wells are less prone to issues than the vertical wells in that they are newer and have greater producing capacity and higher formation pressures and therefore tend to be more resilient from periodic gas system pressure issues. +We rely on our third-party midstream service providers to construct compression, gathering and processing facilities to keep pace with our, and the overall field's, production growth. We anticipate gathering system pressures to vary throughout the year, with increases coinciding with the warmer summer months. We, along with other operators in the Wattenberg Field, continue to work closely with our third-party midstream providers in an effort to ensure adequate system capacity going forward as evidenced by a recent commitment of DCP to build additional gathering and processing in the field. This expansion of gathering and processing facilities is expected to improve natural gas gathering pipelines and processing facilities and assist in the control of line pressures in the Wattenberg Field. However, the timing and availability of adequate infrastructure is not within our control and if our midstream provider's construction projects are delayed, we could experience higher line pressures that may negatively impact our ability to fulfill our growth plans. Total system infrastructure needs may also be affected by a number of factors, including potential increases in production from the Wattenberg Field and warmer than expected weather. +Crude Oil, Natural Gas, and NGLs Pricing. Our results of operations depend upon many factors, particularly the price of crude oil, natural gas, and NGLs, and our ability to market our production effectively. Crude oil, natural gas, and NGL prices have a high degree of volatility. While the price of crude oil decreased during the first half of 2016 compared to 2015, prices increased during the second half of 2016 as compared to the first half of the year as the number of U.S. crude oil rigs and inventories declined in the last half of 2015 and into early 2016. Natural gas prices decreased during 2016 compared to 2015, primarily due to domestic oversupply driven by a lack of a normal winter withdrawal cycle in the winter of 2015-2016. We experienced improved NGL pricing towards the end of 2016; however, due to an oversupply of nearly all domestic NGLs products, our average realized sales price for NGLs during most of 2016 reflected the same depressed levels seen during 2015. With the initiation of ethane exports and increased domestic demand for NGLs driven by the completion of petrochemical processing plants, the industry is beginning to see NGL prices trend upward, including in the near term forward market. +Crude Oil. Crude oil pricing is predominately driven by the physical market, supply and demand, the relative strength of the U.S. dollar, financial markets, and national and international politics. In the Wattenberg Field, our crude oil is sold under various purchase contracts with monthly and longer term transportation provisions based on NYMEX pricing, adjusted for differentials. We have entered into commitments ranging in term from one month to over three years to deliver crude oil to competitive markets, resulting in improved overall average deductions in 2016, as noted previously. We continue to pursue various alternatives with respect to oil transportation, particularly in the Wattenberg Field, with a view toward further improving pricing and limiting our use of trucking through delivering greater quantities of our crude oil via pipeline to liquid markets. We began delivering crude oil in accordance with our long term commitment to the White Cliffs pipeline in July 2015. The White Cliffs agreement is one of several we have entered into to facilitate deliveries of a portion of our crude oil to the Cushing, Oklahoma market. In addition, to the White Cliffs agreement described above, we have signed a long-term agreement with Saddle Butte Rockies Midstream, LLC for gathering of crude oil at the wellhead by pipeline from several of our producing pads in the Wattenberg Field, with a view toward minimizing truck traffic, increasing reliability, reducing the overall physical footprint of our well pads, and reducing emissions. We began delivering crude oil into this pipeline during the fourth quarter of 2015 and continued to grow these volumes during 2016. +In the Delaware Basin, our crude oil production is sold at the wellhead and transported via trucks to pipelines that deliver the oil to the Midland, Texas, crude oil market. Given the increased level of activity in the form of acquisitions, leasing, and the increases in rig count in the Delaware Basin over the last six months, we expect the balance between production and pipeline takeaway capacity to tighten during 2017. At the current time, there are pipeline, truck and rail pathways out of the basin, all of which are available to us. We are evaluating near-term and longer-term solutions that contemplate the increased activity levels we expect, as well as our anticipated future production. These may include longer-term sales agreements. +In the Utica Shale, crude oil and condensate is sold to local purchasers at each individual pad based on NYMEX pricing, adjusted for differentials, and is typically transported by the purchasers via truck to local refineries, rail facilities, or barge loading terminals on the Ohio River. To date, we have not experienced any issues with takeaway capacity in this region for our crude oil. +48 +Natural Gas. Natural gas prices vary quite significantly by region and locality, depending upon the distance to markets, availability of pipeline capacity, and supply and demand relationships in that region or locality. The price we receive for our natural gas produced in the Wattenberg Field is based on CIG pricing provisions or local distribution company monthly/daily pricing provisions, adjusted for certain deductions. Our natural gas from the Delaware Basin is sold into the Waha hub and El Paso index markets. Natural gas produced in the Utica Shale is sold based on TETCO M-2 pricing. +Natural Gas Liquids. Our NGL sales are priced based upon the components of the product and are correlated to the price of crude oil. Our price for NGLs produced in the Wattenberg Field is based on a combination of prices from the Conway hub in Kansas and Mt. Belvieu in Texas where this production is marketed. While NGL prices remained low during the majority of 2016, we realized improvements in NGL pricing during the fourth quarter of 2016 and are seeing this improvement continue in early 2017. Given the lack of liquidity in the forward markets, it is unclear if this trend will continue. Delaware Basin NGLs sales are indexed to NYMEX and sold into the Mt. Belvieu, Texas market. The NGLs produced in the Utica Shale are sold based on month-to-month pricing to various markets. +Our crude oil, natural gas, and NGLs sales are recorded under either the “net-back” or "gross" method of accounting, depending upon the related purchase agreement. We use the "net-back" method of accounting for natural gas and NGLs, as well as the majority of our crude oil production from the Wattenberg Field, for all commodities in the Delaware Basin, and for crude oil from the Utica Shale as the majority of the purchasers of these commodities also provide transportation, gathering, and processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds, or have fixed our sales price at index less a specified deduction. We sell our commodities at the wellhead or what is tantamount to the wellhead in situations where we gather multiple wells into larger pads, and collect a price and recognize revenues based on the wellhead sales price as transportation and processing costs downstream of the wellhead are incurred by the purchaser and therefore embedded in the wellhead price. The "net-back" method results in the recognition of a net sales price that is lower than the indices for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we earn. We use the "gross" method of accounting for Wattenberg Field crude oil delivered through the White Cliffs and Saddle Butte pipelines, and for natural gas and NGLs sales related to production from the Utica Shale as the purchasers do not provide transportation, gathering or processing services as a function of the price we earn. Rather, we contract separately with the midstream provider for the applicable transport and processing based on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering, and processing expenses. As a result of the White Cliffs and Saddle Butte agreements, during 2016 and 2015, our Wattenberg Field crude oil average sales price increased approximately $1.60 and $0.73, respectively, per barrel, relative to the benchmark price because we recognized the costs for transportation on the White Cliffs and Saddle Butte pipelines as an increase in revenues and transportation expense, rather than as a deduction from revenues. +Lease Operating Expenses +Lease operating expenses were $60.0 million in 2016 compared to $57.0 million in 2015 . Due to newer and more horizontal well completions that deliver larger volumes of production per well than older vertical wells, we are seeing the lease operating costs spread over more volume, resulting in lower lease operating cost per Boe. This is reflected in the fact that our per Boe lease operating expense decreased by 27 percent to $2.70 for 2016 from $3.71 for 2015. The $3.0 million increase in the total lease operating expenses in 2016 as compared to 2015 was primarily due to an increase of $3.7 million for increases in wages and employee benefits related to an increase in headcount, including costs for additional contract labor, $1.8 million for additional leased compressors to address line pressures, and an increase of $1.5 million related to lease operating expenses for the acquisitions in the Delaware Basin. These increases were partially offset by a decrease in environmental remediation and regulatory compliance projects of $3.2 million due to a reduction in new remediation projects, and a decrease of $1.4 million related to fewer workover and maintenance related projects. With our entry into the Delaware Basin, we anticipate that our per Boe lease operating cost will be higher initially as we have limited wells and production over which to apply our lease operating costs. With time, we expect that the lease operating costs per Boe in the Delaware Basin will improve. +Lease operating expenses were $57.0 million in 2015 compared to $42.4 million in 2014 . The $14.6 million increase in lease operating expenses in 2015 as compared to 2014 was primarily due to an increase of $4.2 million for environmental remediation and regulatory compliance projects due to increases in the number of projects and an increase in per project expenses, an increase of $3.4 million for additional wages and employee benefits primarily due to additional headcount, including costs for additional contract labor, $2.0 million for additional workover and maintenance related projects, $1.4 million for additional compressors to correct high line pressures in the Wattenberg Field, $1.0 million for the increasing number of non-operated wells in the Wattenberg Field, and $0.9 million for additional costs pertaining to water hauling and disposal. Lease operating expenses per Boe decreased significantly to $3.71 for 2015 from $4.56 in 2014 , as a result of increased production. +49 +Production Taxes +Production taxes are directly related to crude oil, natural gas, and NGLs sales. Production taxes are comprised of both statutory severance tax rates as well as ad valorem tax rates for the applicable production periods. There are a number of adjustments to the statutory rates based on certain credits that are determined based on activity levels and relative commodity prices from year-to-year. The $13.0 million , or 70 percent , increase in production taxes for 2016 compared to 2015 is primarily related to the 31 percent increase in crude oil, natural gas, and NGLs sales, higher ad valorem mill rates, and an overall higher effective tax rate resulting from a decrease in ad valorem tax credits available from the prior year to offset current year severance taxes, driven by the relatively depressed commodity pricing in 2015. These items resulted in effective production tax rates of 6.3 percent and 4.9 percent in 2016 and 2015, respectively. Similarly, the $7.2 million , or 28 percent , decrease in production taxes for 2015 compared to 2014 is primarily related to the 20 percent decrease in crude oil, natural gas, and NGLs sales. +On a per Boe basis, the increase in rates in 2016 impacted the production tax expense, which increased to $1.42 for 2016 compared to $1.20 for 2015 due to the higher effective tax rate noted above. With the decrease in commodity pricing for 2015, production taxes per Boe decreased to $1.20 for 2015 compared to $2.76 for 2014. These items resulted in effective production tax rates of 4.9 percent and 5.4 percent in 2015 and 2014, respectively. +Transportation, Gathering and Processing Expenses +The $8.3 million , or 81 percent , increase in transportation, gathering, and processing expenses for 2016 compared to 2015 was mainly attributable to the costs associated with the White Cliffs and Saddle Butte pipelines in the Wattenberg Field as we began delivering crude oil on these pipelines in July 2015 and December 2015, respectively. We expect to continue to incur these oil transportation costs pursuant to our long-term firm transportation agreement for 6,600 gross barrels per day. The $5.6 million , or 121 percent , increase in transportation, gathering, and processing expenses for 2015 compared to 2014 was mainly attributable to costs associated with the White Cliffs pipeline. Transportation, gathering, and processing expenses per Boe increased to $0.83 for 2016 compared to $0.66 for 2015 and $0.49 for 2014. By using these pipelines and having the pipelines be able to deliver product to the Cushing, Oklahoma market, we benefit from the liquidity associated with the purchasers’ delivery point. +Commodity Price Risk Management, Net +We use commodity derivative instruments to manage fluctuations in crude oil and natural gas prices. We have in place a variety of collars, fixed-price swaps, and basis swaps on a portion of our estimated crude oil and natural gas production. Because we sell all of our crude oil and natural gas production at prices related to the indexes inherent in our underlying derivative instruments, we ultimately realize value related to our collars of no less than the floor and no more than the ceiling and, for our commodity swaps, we ultimately realize the fixed price value related to our swaps. +Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments and the change in fair value of unsettled derivatives related to our crude oil and natural gas production. Commodity price risk management, net, does not include derivative transactions related to our gas marketing, which are included in sales from and cost of gas marketing. +Net settlements of commodity derivative instruments are based on the difference between the crude oil, natural gas and natural gas index prices at the settlement date of our commodity derivative instruments compared to the respective strike prices contracted for the settlement months that were established at the time we entered into the commodity derivative transaction. The net change in fair value of unsettled commodity derivatives is comprised of the net value increase or decrease in the beginning-of-period fair value of commodity derivative instruments that settled during the period, and the net change in fair value of unsettled commodity derivatives during the period or from inception of any new contracts entered into during the applicable period. The corresponding impact of settlement of the commodity derivative instruments during the period is included in net settlements for the period as discussed above. The net change in fair value of unsettled commodity derivatives during the period is primarily related to shifts in the crude oil and natural gas forward curves and changes in certain differentials. +50 +The following table presents net settlements and net change in fair value of unsettled commodity derivatives included in commodity price risk management, net: +Year Ended December 31, +2016 +2015 +2014 +(in millions) +Commodity price risk management gain (loss), net: +Net settlements of commodity derivative instruments: +Crude oil fixed price swaps and collars +$ +165.2 +$ +208.9 +$ +2.3 +Natural gas fixed price swaps and collars +41.9 +31.0 +(3.7 +) +Natural gas basis protection swaps +1.0 +(1.0 +) +0.6 +Total net settlements of commodity derivative instruments +208.1 +238.9 +(0.8 +) +Change in fair value of unsettled commodity derivative instruments: +Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments +(220.0 +) +(186.9 +) +13.3 +Crude oil fixed price swaps and collars +(78.6 +) +99.3 +256.1 +Natural gas fixed price swaps and collars +(37.1 +) +53.3 +41.7 +Natural gas basis swaps +1.9 +(1.4 +) +— +Net change in fair value of unsettled commodity derivative instruments +(333.8 +) +(35.7 +) +311.1 +Total commodity price risk management gain (loss), net +$ +(125.7 +) +$ +203.2 +$ +310.3 +Exploration Expense +The following table presents the major components of exploration expense: +Year Ended December 31, +2016 +2015 +2014 +(in millions) +Geological and geophysical costs, including seismic purchases +$ +3.5 +$ +— +$ +— +Operating, personnel and other +1.2 +1.1 +0.9 +Total exploration expense +$ +4.7 +$ +1.1 +$ +0.9 +Geological and geophysical costs. Geological and geophysical costs in 2016 were primarily related to the portion of the purchase of seismic data related to unproved acreage in the Delaware Basin. +Impairment of Properties and Equipment +The following table sets forth the major components of our impairments of properties and equipment expense: +Year Ended December 31, +2016 +2015 +2014 +(in millions) +Impairment of proved and unproved properties +$ +5.6 +$ +154.6 +$ +161.6 +Amortization of individually insignificant unproved properties +1.4 +7.0 +4.4 +Land and buildings +3.0 +— +0.8 +Total impairment of properties and equipment +$ +10.0 +$ +161.6 +$ +166.8 +Due to a significant decline in commodity prices and decreases in our net realized sales prices, we experienced triggering events during 2015 and 2014 that required us to assess our crude oil and natural gas properties for possible impairment. As a result of our assessments, we recorded impairment charges of $150.3 million and $158.3 million in 2015 and 2014, respectively, to write-down our Utica Shale proved and unproved properties. Of these impairment charges, $24.7 million and $112.6 million were recorded in 2015 and 2014, respectively, to write-down certain capitalized well costs on our Utica Shale proved producing properties. In 2015 and 2014, we also recorded +51 +impairment charges of $125.6 million and $45.7 million to write-down our Utica Shale lease acquisition costs. The impairment charges, which are included in the consolidated statements of operations line item impairment of properties and equipment, represented the amount by which the carrying value of these crude oil and natural gas properties exceeded the estimated fair values. We continued to monitor whether any further impairments were triggered and required measurement throughout 2016 given the continued volatility of commodity prices and the continued capital investment in the development and acquisition of oil and gas properties. No such triggering events occurred during 2016. Impairment charges in 2016 relate to the retirement of certain leases that were no longer part of our development plan and to reflect the fair value of other property and equipment that was held for sale as of December 31, 2016. Future deterioration of commodity prices or other operating circumstances could result in additional impairment charges to our properties and equipment. +Amortization of individually insignificant unproved properties. The decrease in 2016 as compared to 2015 is due to the impairment of leases in 2015, which significantly reduced total lease costs. The increase in 2015 as compared to 2014 was primarily related to a higher number of insignificant leases that were subject to amortization in 2015, primarily in the Utica Shale. +Land and buildings. The impairment charge for 2016 represents the excess of the carrying value over the estimated fair value, less the cost to sell, of a field operating facility in Greeley, Colorado, and 12 acres of land located adjacent to our Bridgeport, West Virginia, regional headquarters. The fair values of these assets were determined based upon estimated future cash flows from unrelated third-party bids. +General and Administrative Expense +General and administrative expense increased $22.5 million , or 25 percent , in 2016 compared to 2015. The increase in cash based general and administrative costs was primarily attributable to $12.2 million of legal and professional fees related to the acquisitions in the Delaware Basin, a $7.7 million increase in payroll and employee benefits due to per capita increases in wages and increases in headcount given the increase in our personnel by nine percent over the course of 2016. Stock-based compensation expense in 2016 and 2015 was $19.5 million and $20.1 million, respectively. +General and administrative expense decreased $33.6 million , or 27 percent , in 2015 compared to 2014. The decrease was primarily attributable to $40.3 million recorded in 2014 in connection with certain partnership-related class action litigation and estimates relating to litigation arising from bankruptcy proceedings of certain affiliated partnerships and a $1.8 million decrease in costs for legal and other professional services in 2015. The decreases were offset in part by an $8.2 million increase in payroll and employee benefits in 2015, of which $3.3 million was related to stock-based compensation. Stock-based compensation expense in 2015 and 2014 was $20.1 million and $17.5 million, respectively. +52 +Depreciation, Depletion, and Amortization +Crude oil and natural gas properties. During 2016, 2015, and 2014, we invested $396.4 million , $554.3 million and $663.4 million , which is net of the change in accounts payable related to capital expenditures, in the development of our oil and natural gas properties, respectively. We also incurred $1.76 billion to acquire proved reserves during 2016. We did not invest in any acquisitions of proved reserves in 2015 or 2014. DD&A expense related to crude oil and natural gas properties is directly related to proved reserves and production volumes. DD&A expense related to crude oil and natural gas properties was $413.1 million , $298.8 million , and $188.5 million in 2016 , 2015 , and 2014 , respectively. The year-over-year change in DD&A expense related to crude oil and natural gas properties were primarily due to the following: +Year Ended December 31, +2016 - 2015 +2015 - 2014 +(in millions) +Increase in production +$ +132.3 +$ +123.4 +Decrease in weighted-average depreciation, depletion and amortization rates +(18.0 +) +(13.1 +) +Total increase in DD&A expense related to crude oil and natural gas properties +$ +114.3 +$ +110.3 +The following table presents our DD&A expense rates for crude oil and natural gas properties: +Year Ended December 31, +Operating Region/Area +2016 +2015 +2014 +(per Boe) +Wattenberg Field +$ +19.11 +$ +20.13 +$ +19.26 +Delaware Basin +8.34 +— +— +Utica Shale +10.66 +10.74 +31.19 +Total weighted-average +18.63 +19.44 +20.28 +The 2016 rate for the Delaware Basin is related to our acquisitions in the Delaware Basin. The slight decrease in the Wattenberg Field rate for 2016 as compared to 2015 was primarily due to the impact of our 2016 year-end reserves. The decrease in the Utica Shale DD&A expense rates in 2015 relative to 2014 was primarily due to the effect of impairments recorded in 2015 and 2014 to write-down certain capitalized well costs on our Utica Shale proved producing properties. +Provision for Uncollectible Notes Receivable +In the first quarter of 2016, we recorded a provision for uncollectible notes receivable of $44.7 million to impair two third-party notes receivable whose collection was not reasonably assured. Later in 2016, we collected a $0.7 million promissory note and reversed the related provision and allowance for uncollectible notes receivable. +Accretion of Asset Retirement Obligations +Accretion of asset retirement obligations ("ARO") for 2016 increased by $0.8 million , or 13 percent , compared to 2015 , and increased by $2.9 million , or 84 percent , in 2015 compared to 2014. The increase in 2016 was due to adding new wells and the associated increase in amortization expense. The increase in 2015 was primarily attributable to decreases in the estimated useful life of certain vertical wells in the Wattenberg Field. +53 +Interest Expense +Interest expense increased by approximately $14.4 million in 2016 compared to 2015 . The increase is primarily attributable to a $9.3 million charge for the bridge loan commitment related to acquisitions of properties in the Delaware Basin, a $7.4 million increase in interest for the issuance of our 2024 Senior Notes, and a $2.9 million increase in interest expense for the issuance of our 2021 Convertible Notes in September 2016. The increases were partially offset by a $5.1 million decrease in interest expense resulting from the net settlement of our 2016 Convertible Notes in May 2016. The entire $9.3 million of interest expense attributed to the bridge loan facility was expensed in 2016 as the bridge loan was replaced with equity and longer term debt financing. +Interest expense decreased by approximately $0.3 million in 2015 compared to 2014 . The decrease is primarily comprised of a $1.6 million decrease attributable to an increase in capitalized interest, offset in part by a $0.9 million increase due to higher average borrowings on our revolving credit facility in 2015. +Interest costs capitalized in 2016 , 2015 , and 2014 were $4.5 million , $5.1 million , and $3.5 million , respectively. +Provision for Income Taxes +The current income tax benefit (expense) in 2016, 2015, and 2014 was $9.9 million, $(3.1) million, and $(0.5) million, respectively. Current income taxes generally relate to the cash that is paid or recovered for income taxes associated with the applicable period. The remaining portion of the total income tax expense is comprised of deferred income tax expense (benefit), which is a result of differences in the timing of deductions for our GAAP presentation of financial statements and the income tax regulations. +For 2016 , 2015 , and 2014 , the effective income tax rate (the "rate") of 37.4 percent , 35.9 percent , and 39.5 percent on income (loss) from operations differs from the federal statutory tax rate of 35 percent primarily due to state taxes and excess stock compensation benefits, offset by nondeductible expenses that consist primarily of officers' compensation cost and government lobbying expenses. +As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions. We continue to voluntarily participate in the Internal Revenue Service’s ("IRS") Compliance Assurance Program (the "CAP Program") for the 2015, 2016, and 2017 tax years. We have received a full acceptance notice from the IRS for our filed 2015 federal tax return and the IRS's post filing review is complete. +We acquired a net deferred tax liability of $379.9 million in 2016 associated with a lack of tax basis relative to the purchase price of one of the Delaware Basin acquisitions. This has resulted in a material increase in our deferred tax liability on the balance sheet as of December 31, 2016. +There has been increased discussion by the federal government of a potential reduction of the corporate income tax rate and corresponding changes to the tax code. In the event of a change in federal or state income tax rates, the impact of the rate change will be required to be recorded through deferred income tax expense. Should statutory income tax rates decrease, our deferred tax liability would decrease, resulting in deferred tax benefit for the period. If the statutory income tax rates increase, our deferred tax liability would increase resulting in a deferred tax expense. +Discontinued Operations +Appalachian Marcellus Shale Assets. In October 2014 , we completed the sale of our entire 50 percent ownership interest in PDCM to an unrelated third-party for aggregate consideration, after our share of PDCM's debt repayment and other working capital adjustments, of approximately $192.0 million , comprised of approximately $152.8 million in net cash proceeds and a promissory note due in 2020 of approximately $39.0 million . The transaction included the buyer's assumption of our share of the firm transportation commitment related to the assets owned by PDCM, as well as our share of PDCM's natural gas hedging positions in effect at the time. The divestiture resulted in a pre-tax gain of $76.3 million . The divestiture represented a strategic shift in our operations. Accordingly, our proportionate share of PDCM's Marcellus Shale results of operations have been separately reported as discontinued operations in the consolidated statements of operations for 2014 and prior periods in the Selected Financial Information disclosures. +Net Income (Loss)/Adjusted Net Income (Loss) +The factors resulting in changes in net loss in 2016 and 2015 compared to net income in 2014 are discussed above. These same reasons similarly impacted adjusted net income (loss), a non-U.S. GAAP financial measure, with the exception of the net change in fair value of unsettled derivatives, adjusted for taxes, of $208.9 million, $22.2 million, and $193.1 million in 2016, 2015, and 2014, respectively. Adjusted net loss, a non-U.S. GAAP financial measure, was $37.0 million, $46.1 million, and $37.7 million in 2016, 2015, and 2014 respectively. See Reconciliation of Non-U.S. GAAP Financial Measures , below, for a more detailed discussion of this non-U.S. GAAP financial measure. +54 +Financial Condition, Liquidity and Capital Resources +Historically, our primary sources of liquidity have been cash flows from operating activities, our revolving credit facility, proceeds raised in debt, and equity capital market transactions and asset sales. In 2016 , our primary sources of liquidity were net cash flows from operating activities of $486.3 million , the net proceeds received from the March 2016 public offering of our common stock of approximately $296.6 million , and the net proceeds from the Securities Issuances of approximately $1.1 billion. +We used a portion of the net proceeds from the March 2016 common stock offering to repay all amounts then outstanding on our revolving credit facility and the principal amount owed upon the maturity of the 2016 Convertible Notes in May 2016 and the remainder for general corporate purposes. The net proceeds from the Securities Issuances were used to fund a portion of the purchase price and related fees for acquisitions in the Delaware Basin and for general corporate purposes. +Our primary source of cash flows from operating activities is the sale of crude oil, natural gas, and NGLs. Fluctuations in our operating cash flows are substantially driven by commodity prices and changes in our production volumes. Commodity prices have historically been volatile and we partially manage this volatility through our use of commodity derivative instruments. In 2016 and 2015, net settled commodity derivatives comprised approximately 43 percent and 58 percent, respectively, of our cash flows from operating activities. Based upon our hedge position and assuming year-end forward strip pricing, in 2017 and thereafter our derivatives may not be a significant source of cash flow, and may result in cash outflows in 2017 and 2018. As of December 31, 2016, the fair value of our derivatives was a net liability of $70.0 million . Based on the forward pricing strip at December 31, 2016, we would expect negative net settlements totaling approximately $45 million during 2017. +The covenants under our revolving credit agreement limit the volume of our expected future production that we may hedge. However, we may enter into commodity derivative instruments with future settlement periods of up to sixty months from the date of issuance of the commodity derivative instrument. We do not have minimum hedging requirements associated with our revolving credit facility. +Our net working capital fluctuates for various reasons, including, but not limited to, changes in the fair value of our commodity derivative instruments and changes in our cash and cash equivalents due to our historical practice of utilizing excess cash to reduce the outstanding borrowings under our revolving credit facility when we have borrowings outstanding. At December 31, 2016 , we had a working capital surplus of $129.2 million compared to a surplus of $30.7 million at December 31, 2015 . The increase in working capital is primarily the result of an increase of $243.3 million in cash and cash equivalents, the $112.9 million reduction in the current portion of long-term debt due to the settlement of our 2016 Convertible Notes in May 2016, and no current amounts outstanding under our revolving credit facility as of December 31, 2016, partially offset by a negative change in the fair value of our commodity derivative instruments of $264.9 million from 2015 to 2016. The net cash position was a result of the Securities Issuances and our desire to have cash available to fund the portion of the 2017 capital investment program that is expected to exceed operating cash flows. +We ended 2016 with cash and cash equivalents of $244.1 million and availability under our revolving credit facility of $688.3 million , providing for a total liquidity position of $932.4 million , compared to $402.2 million at December 31, 2015 . The change in liquidity of $530.2 million , or 131.8 percent, was primarily attributable to: +• net cash flows from operating activities of $486.3 million ; +• net proceeds received from the March 2016 public offering of our common stock of approximately $296.6 million ; +• net proceeds from the Securities Issuances of approximately $1.1 billion; offset in part by, +• cash outflows for capital investments associated with development, exploration, and acquisition activity of +$1.76 billion during 2016; and +• cash payment of approximately $115 million upon the maturity of our Convertible Notes in May 2016. +Based on our expectations of cash flows from operations, our cash and cash equivalent balance and availability under our revolving credit facility, we believe that we have sufficient capital to fund our planned activities during 2017. +In March 2015, we filed an automatic shelf registration statement on Form S-3 with the SEC. Effective upon filing, the shelf provides for the potential sale of an unspecified amount of debt securities, common stock or preferred stock, either separately or represented by depository shares, warrants or purchase contracts, as well as units that may include any of these securities or securities of other entities. The shelf registration statement is intended to allow us to be proactive in our ability to raise capital and to have the flexibility to raise such funds in one or more offerings should we perceive market conditions to be favorable. We have utilized the shelf registration statement to raise capital from time to time, and we may utilize the facility in the future to raise additional capital. +Our revolving credit facility is a borrowing base facility and availability under the facility is subject to redetermination each May and November, based upon a quantification of our proved reserves at each June 30 and December 31, respectively. In September 2016, we entered into a Third Amendment to the Third Amended and Restated Credit Agreement. The amendment, among other things, amended the revolving credit facility to permit the completion of acquisitions in the Delaware Basin and, effective upon closing of the acquisitions, adjusted the interest rate payable on amounts borrowed under the facility, increased the aggregate commitments under the facility from $450 million to $700 million , and reduced our maximum leverage ratio to 4.00:1.00 times as described in more detail below. The maturity date of our revolving credit facility is May 2020. In October 2016, we entered into the Fourth Amendment to the Third Amended and Restated Credit Agreement. The amendment, among other things, reaffirmed our borrowing base at $700 million and, increased the percentage of our +55 +future production that we are permitted to hedge. Our borrowing base availability under the revolving credit facility is limited under our 2022 Senior Notes to the greater of $700 million or the calculated value under an Adjusted Consolidated Tangible Net Asset test, as defined. +Our borrowings bear interest at either the LIBOR or prime rate plus an applicable margin, depending on the percentage of the commitment that has been utilized as of December 31, 2016, the applicable margin is 1.25%, and the unused commitment fee is 0.50%. +We had no balance outstanding on our revolving credit facility as of December 31, 2016 . As of December 31, 2016 , RNG had issued an irrevocable standby letter of credit of approximately $11.7 million in favor of a third-party transportation service provider to secure firm transportation of the natural gas produced by third-party producers for whom we market production in the Appalachian Basin. The letter of credit expires in September 2017 and is automatically extended annually in accordance with the letter of credit's terms and conditions. The letter of credit reduces the amount of available funds under our revolving credit facility by an amount equal to the letter of credit. While we have added and expect to continue to add producing reserves through our drilling operations, the effect of any such reserve additions on our borrowing base could be offset by other factors including, among other things, a prolonged period of depressed commodity prices or regulatory pressure on lenders to reduce their exposure to exploration and production companies. +Our revolving credit facility contains financial maintenance covenants. The covenants require that we maintain: (i) total debt of less than 4.00 times the trailing 12 months earnings before interest, taxes, depreciation, depletion and amortization, change in fair value of unsettled commodity derivatives, exploration expense, gains (losses) on sales of assets and other non-cash, gains (losses) ("EBITDAX"), and (ii) an adjusted current ratio of at least 1.00:1.00. Our adjusted current ratio is adjusted by eliminating the impact on our current assets and liabilities of recording the fair value of crude oil and natural gas commodity derivative instruments. Additionally, available borrowings under our revolving credit facility are added to the current asset calculation and the current portion of our revolving credit facility debt is eliminated from the current liabilities calculation. At December 31, 2016 , we were in compliance with all debt covenants with a 2.10 times debt to EBITDAX ratio and a 5.00:1.00 current ratio. We expect to remain in compliance into the foreseeable future. +The indentures governing our 2024 Senior Notes and 2022 Senior Notes contain customary restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (a) incur additional debt including limitations as to availability under our revolving credit facility, (b) make certain investments or pay dividends or distributions on our capital stock or purchase, redeem, or retire capital stock, (c) sell assets, including capital stock of our restricted subsidiaries, (d) restrict the payment of dividends or other payments by restricted subsidiaries to us, (e) create liens that secure debt, (f) enter into transactions with affiliates, and (g) merge or consolidate with another company. At December 31, 2016 , we were in compliance with all covenants and expect to remain in compliance into the foreseeable future. +In January 2017, pursuant to the filing of the supplemental indentures for the 1.25% convertible senior notes due in 2021 ("2021 Convertible Senior Notes"), the 2024 Senior Notes, and the 2022 Senior Notes, our subsidiary PDC Permian, Inc., became a guarantor of the notes. +Cash Flows +Operating Activities. Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes, net settlements from our commodity derivative positions, operating costs, and general and administrative expenses. Cash flows provided by operating activities increased in 2016 compared to 2015 . The $75.2 million increase was primarily due to the increase in crude oil, natural gas, and NGLs sales of $118.7 million . We also realized an increase in the change of funds held for future distribution of $36.5 million , and an increase in the deferral of income taxes of $13.1 million. The increases were partially offset by a decrease in monthly derivative commodity settlements of $30.8 million , and increases in general and administrative expense of $22.5 million , interest expense of $14.4 million, production taxes of $13.0 million and transportation, gathering, and processing expenses of $8.3 million . +Cash flows provided by operating activities increased in 2015 compared to 2014. The $174.4 million increase was primarily due to the increase in normal monthly derivative commodity settlements of $241.0 million and a decrease in general and administrative expense of $33.6 million and production taxes of $7.2 million. The increase was offset by the decrease in crude oil, natural gas, and NGLs sales of $92.7 million and an increase in lease operating costs of $14.6 million. +Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased by $46.0 million in 2016 to $466.8 million , and $170.6 million to $420.8 million in 2015 , when compared to the respective prior years. These changes were primarily due to the same factors mentioned above for changes in cash flows provided by operating activities, without regard to timing of cash payments and/or receipts of our assets and liabilities of $19.5 million and $9.7 million in 2016 and 2015 , respectively. +Adjusted EBITDA, a non-U.S. GAAP financial measure, decreased by $7.6 million in 2016 to $435.6 million from $443.2 million in 2015 , primarily as a result of the provision for uncollectible notes receivable of $44.0 million, the decrease in net settlements from our monthly derivative commodity settlements of $30.8 million , an increase in general and administrative expense of $22.5 million , and a $27.8 million increase in production and exploration expense. The decrease was partially offset by the increase in crude oil, natural gas, and NGLs sales of $118.7 million . +Adjusted EBITDA increased by $78.9 million in 2015 from 2014 , primarily as a result of the increase in normal monthly derivative commodity settlements of $241.0 million and a decrease in general and administrative expense of $33.6 million. The increase was partially +56 +offset by the decrease in crude oil, natural gas, and NGLs sales of $92.7 million, and an $88.8 million decrease in contribution margins from discontinued operations and a $14.6 million increase in lease operating costs. +Investing Activities. Because crude oil and natural gas production from a well declines rapidly in the first few years of production, we need to continue to invest significant amounts of capital in order to maintain and grow our production and replace our reserves. If capital markets are not available in the future, we will be limited to our cash flows from operations and liquidity under our revolving credit facility as the sources for funding our capital investments. +Cash flows from investing activities primarily consist of the acquisition, exploration and development of crude oil and natural gas properties, net of dispositions of crude oil and natural gas properties. During 2016, our acquisitions in the Delaware Basin comprised the majority of our cash flows used in investing activities. Net cash used in the Delaware Basin acquisitions was $1.1 billion and we used cash of $436.9 million for our oil and gas operations. Our total cash used in investing activities during 2016 was approximately $1.5 billion. Through July 2016, we ran four automated drilling rigs in the Wattenberg Field. In August 2016, we decreased the number of automated drilling rigs to three in anticipation of higher working interests in wells drilled resulting from an acreage exchange. In the Utica Shale, we drilled and completed five gross (4.5 net) wells, all of which were turned-in-line to sales in 2016. With the closing of our acquisitions in the Delaware Basin, we completed the drilling of two wells that were in-process at closing, spud an additional well, and turned-in-line one well prior to the end of 2016. +Net cash used in investing activities of $604.3 million during 2015 was primarily related to cash utilized for our drilling operations. Net cash used in investing activities of $474.1 million during 2014 was primarily related to cash utilized for our drilling operations of $623.8 million, offset in part by the $152.8 million net cash proceeds received from the sale of our entire 50 percent ownership interest in PDCM. +Financing Activities. Net cash from financing activities in 2016 was primarily related to the $855.1 million of net proceeds received from the issuance of 9.4 million shares of our common stock, $392.2 million of net proceeds from issuance of the 2024 Senior Notes and $193.9 million of net proceeds from issuance of the 2021 Convertible Notes, partially offset by the $115 million payment owed upon the maturity of the 2016 Convertible Notes and net payments of approximately $37.0 million to pay down amounts borrowed under our revolving credit facility. +Net cash from financing activities in 2015 was primarily related to $202.9 million of net proceeds received from the issuance of our common stock in March 2015, partially offset by net payments of approximately $19.0 million to pay down amounts borrowed under our revolving credit facility. Net cash from financing activities in 2014 were primarily comprised of net borrowings under our revolving credit facility of $63.8 million to execute our capital budget. +Contractual Obligations and Contingent Commitments +The following table presents our contractual obligations and contingent commitments as of December 31, 2016 : +Payments due by period +Less than +1-3 +3-5 +More than +Contractual Obligations and Contingent Commitments +Total +1 year +years +years +5 years +(in millions) +Long-term liabilities reflected on the consolidated balance sheet (1) +Long-term debt (2) +$ +1,100 +$ +— +$ +— +$ +900 +$ +200 +Commodity derivative contracts (3) +81 +54 +27 +— +— +Capital leases (4) +2 +1 +1 +— +— +Production tax liability +53 +24 +29 +— +— +Asset retirement obligations +93 +10 +20 +22 +41 +Other liabilities (5) +7 +1 +1 +2 +3 +1,336 +90 +78 +924 +244 +Commitments, contingencies and other arrangements (6) +Interest on long-term debt (7) +537 +91 +181 +169 +96 +Operating leases +22 +3 +6 +6 +7 +Firm transportation and processing agreements (8) +187 +17 +52 +49 +69 +746 +111 +239 +224 +172 +Total +$ +2,082 +$ +201 +$ +317 +$ +1,148 +$ +416 +__________ +(1) +Table does not include deferred income tax liability to taxing authorities of $143.5 million , due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. +(2) +Amount presented does not agree with the consolidated balance sheets in that it excludes $37.5 million of unamortized debt discount and $18.6 million of unamortized debt issuance costs. +(3) +Represents our gross liability related to the fair value of derivative positions. +(4) +Short-term capital lease obligations are included in other accrued expenses on the consolidated balance sheets. Long-term capital lease obligations are included in other liabilities on the consolidated balance sheets. +(5) +Includes deferred compensation to former executive officers and deferred payments related to firm transportation agreements. +(6) +Table does not include an undrawn $11.7 million irrevocable standby letter of credit pending issuance to a transportation service provider. Additionally, the table does not include the annual repurchase obligations to investing partners or termination benefits related to employment agreements with our executive officers, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. +(7) +Amounts presented include $224.4 million to the holders of our 2022 Senior Notes, $188.7 million to the holders of our 2024 Senior Notes, and $115.2 million payable to the holders of our 2021 Convertible Notes. Amounts also include $11.0 million payable to the participating banks in our revolving credit facility, of which interest of $9.0 million is related to unutilized commitments at a rate of 0.38% per annum, and $0.2 million is related to our undrawn letters of credit. +(8) +Represents our gross commitment which includes volumes produced by us, purchased from third parties and produced by our affiliated partnerships and other third-party working, royalty and overriding royalty interest owners whose volumes we market on their behalf. This includes anticipated and estimated commitments associated with a new gas processing facility by our primary mid-stream provider. The timing of such payments has been estimated and is subject to change based on the completion of construction and the commencing of operations by the midstream provider. +As the managing general partner of affiliated partnerships, we have liability for potential casualty losses in excess of the partnership assets and insurance. We believe that the casualty insurance coverage we and our subcontractors carry is adequate to meet this potential liability. +From time to time, we are a party to various legal proceedings in the ordinary course of business. We are not currently a party to any litigation that we believe would have a materially adverse effect on our business, financial condition, results of operations, or liquidity. +Critical Accounting Policies and Estimates +We have identified the following policies as critical to business operations and the understanding of our results of operations. This is not a comprehensive list of all of the accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by U.S. GAAP, with no need for our judgment in the application. There are also areas in which our judgment in selecting available alternatives would not produce a materially different result. However, certain of our accounting policies are particularly important to the presentation of our financial position and results of operations and we may use significant judgment in the application. As a result, they are subject to an inherent degree of uncertainty. In applying those policies, we use our judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on historical experience, observation of trends in the industry and information available from other outside sources, as appropriate. For a more detailed discussion on the application of these and other accounting policies, see the footnote titled Summary of Significant Accounting Policies to our consolidated financial statements included elsewhere in this report. +Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. +Annually, we engage independent petroleum engineers to prepare reserve and economic evaluations of all our properties on a well-by-well basis as of December 31. We adjust our crude oil and natural gas reserves for major acquisitions, new drilling, and divestitures during the year as needed. The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering, and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. Although every reasonable effort is made to ensure that reserve estimates reported represent our most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect our DD&A expense, a change in our estimated reserves could have an effect on our net income (loss). +Exploration costs, including geological and geophysical expenses, the acquisition of seismic data covering unproved acreage, +and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but are charged to expense if the well is determined to be nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as the well has found a sufficient quantity of reserves to justify completion as a producing well and we are making sufficient progress assessing our reserves and economic and operating viability. If an in-progress exploratory well is found to be unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the well is classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time when we are able to make a final determination of a well’s productive status, the well is removed from the suspended well status and the proper accounting treatment is applied. +The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired, or amortized. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed, and any impairment in value is charged to impairment of crude oil and natural gas properties. The +57 +amount of impairment recognized on unproved properties which are not individually significant is determined by amortizing the costs of such properties within appropriate fields based on our historical experience, acquisition dates and average lease terms, with the amortization recognized in impairment of crude oil and natural gas properties. The valuation of unproved properties is subjective and requires us to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values. +We assess our crude oil and natural gas properties for possible impairment upon a triggering event or when circumstances warrant +by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. Any impairment in value is charged to impairment of properties and equipment. The estimates of future prices may differ from current market prices of crude oil and natural gas. Any downward revisions in estimates to our reserve quantities, expectations of falling commodity prices, or rising operating costs could result in a triggering event, and therefore, a reduction in undiscounted future net cash flows and an impairment of our crude oil and natural gas properties. Although our cash flow estimates are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. +Crude Oil, Natural Gas, and NGLs Sales Revenue Recognition. Crude oil, natural gas, and NGLs sales are recognized when production is sold to a purchaser at a determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas, and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes and prices received. We receive payment for sales from one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have been immaterial. If a sale is deemed uncollectible, an allowance for doubtful collection is recorded. +Fair Value of Financial Instruments. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. +Commodity Derivative Financial Instruments. We measure the fair value of our commodity derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas, and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of commodity derivative liabilities and the effect of our counterparties' credit standings on the fair value of commodity derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding commodity derivative position. +We validate our fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. While we believe our valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology, or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value. +Net settlements on our commodity derivative instruments are initially recorded to accounts receivable or payable, as applicable, and may not be received from or paid to counterparties to our commodity derivative contracts within the same accounting period. Such settlements typically occur the month following the maturity of the commodity derivative instrument. We have evaluated the credit risk of the counterparties holding our commodity derivative assets, which are primarily financial institutions who are also major lenders in our revolving credit facility, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding commodity derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our counterparties on the fair value of our commodity derivative instruments is not significant. +58 +Deferred Income Tax Asset Valuation Allowance. Deferred income tax assets are recognized for deductible temporary differences, net operating loss carry-forwards and credit carry-forwards if it is more likely than not that the tax benefits will be realized. To the extent a deferred tax asset is not expected to be realized under the preceding criteria, we establish a valuation allowance. The factors which we consider in assessing whether we will realize the value of deferred income tax assets involve judgments and estimates of both amount and timing. The judgments used in applying these policies are based on our evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results may differ from those estimates. +Accounting for Business Combinations. We utilize the purchase method to account for acquisitions of businesses and assets. The value of the purchase consideration takes into account the degree to which the consideration is objective and measurable such as cash consideration paid to a seller. With the issuance of equity, restrictions upon the sale of the issued stock are taken into consideration. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. The purchase price allocations are based on appraisals, discounted cash flows, quoted market prices, and estimates by management. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value as such sales represent the amount at which a willing buyer and seller would enter into an exchange for such properties. +In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped and unproved crude oil and natural gas properties, and other non-crude oil and natural gas properties. To estimate the fair values of these properties, we prepare estimates of crude oil and natural gas reserves. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. +We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. +Recent Accounting Standards +See the footnote titled Summary of Significant Accounting Policies - Recently Adopted Accounting Standards to our consolidated financial statements included elsewhere in this report. +Reconciliation of Non-U.S. GAAP Financial Measures +Adjusted cash flows from operations. We define adjusted cash flows from operations as the cash flows earned or incurred from operating activities, without regard to changes in operating assets and liabilities. We believe it is important to consider adjusted cash flows from operations, as well as cash flows from operations, as we believe it often provides more transparency into what drives the changes in our operating trends, such as production, prices, operating costs, and related operational factors, without regard to whether the related asset or liability was received or paid during the same period. We also use this measure because the timing of cash received from our assets, cash paid to obtain an asset or payment of our obligations has been only a timing issue from one period to the next as we have not had accounts receivable collection problems, nor been unable to purchase assets or pay our obligations. +Adjusted net income (loss). We define adjusted net income (loss) as net income (loss), plus loss on commodity derivatives, less gain on commodity derivatives and net settlements on commodity derivatives, each adjusted for tax effects. We believe it is important to consider adjusted net income (loss), as well as net income (loss). We believe this measure often provides more transparency into our operating trends, such as production, prices, operating costs, net settlements from derivatives and related factors, without regard to changes in our net income (loss) from mark-to-market adjustments resulting from net changes in the fair value of unsettled derivatives. Additionally, other items which we believe are not indicative of future results may be excluded to clearly identify operating trends. +Adjusted EBITDA. We define adjusted EBITDA as net income (loss), plus loss on commodity derivatives, interest expense, net of interest income, income taxes, impairment of properties and equipment, depreciation, depletion, and amortization and accretion of asset retirement obligations, less gain on commodity derivatives and net settlements on commodity derivatives. Adjusted EBITDA is not a measure of financial performance or liquidity under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss), nor as an indicator of cash flows reported in accordance with U.S. GAAP. Adjusted EBITDA includes certain non-cash costs incurred by us and does not take into account changes in operating assets and liabilities. Other companies in our industry may calculate adjusted EBITDA differently than we do, limiting its usefulness as a comparative measure. We believe adjusted EBITDA is relevant because it is a measure of our operational and financial performance, as well as a measure of our liquidity, and is used by our management, investors, commercial banks, research analysts, and others that utilize our financial statements to analyze such things as: +• +operating performance and return on capital as compared to our peers; +59 +• +financial performance of our assets and our valuation without regard to financing methods, capital structure, or historical cost basis; +• +ability to generate sufficient cash to service our debt obligations and commitments; and +• +viability of acquisition opportunities and capital investment projects, including the related rate of return. +PV-10. We define PV-10 as the estimated present value of the future net cash flows from our proved reserves before income taxes, discounted using a 10 percent discount rate. We believe that PV-10 provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. We believe that PV-10 is relevant and useful for evaluating the relative monetary significance of our reserves. Professional analysts, investors, and other users of our financial statements may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies' reserves. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable in evaluating us and our reserves. PV-10 is not intended to represent the current market value of our estimated reserves. +The following table presents a reconciliation of our non-U.S. GAAP financial measures to its most comparable U.S. GAAP measure: +Year Ended December 31, +2016 +2015 +2014 +(in millions) +Adjusted cash flows from operations: +Net cash from operating activities +$ +486.3 +$ +411.1 +$ +236.7 +Changes in assets and liabilities +(19.5 +) +9.7 +13.5 +Adjusted cash flows from operations +$ +466.8 +$ +420.8 +$ +250.2 +Adjusted net income (loss): +Net income (loss) +$ +(245.9 +) +$ +(68.3 +) +$ +155.4 +(Gain) loss on commodity derivative instruments +125.6 +(203.2 +) +(309.3 +) +Net settlements on commodity derivative instruments +208.2 +239.0 +(2.0 +) +Tax effect of above adjustments +(124.9 +) +(13.6 +) +118.2 +Adjusted net income (loss) +$ +(37.0 +) +$ +(46.1 +) +$ +(37.7 +) +Net income (loss) to adjusted EBITDA: +Net income (loss) +$ +(245.9 +) +$ +(68.3 +) +$ +155.4 +(Gain) loss on commodity derivative instruments, including net settlements +125.6 +(203.2 +) +(309.3 +) +Net settlement (gain) loss on commodity derivative instruments +208.2 +239.0 +(2.0 +) +Interest expense, net +61.0 +42.8 +48.6 +Income tax expense (benefit) +(147.2 +) +(38.3 +) +99.2 +Impairment of properties and equipment +10.0 +161.6 +167.3 +Depreciation, depletion and amortization +416.9 +303.3 +201.7 +Accretion of asset retirement obligations +7.0 +6.3 +3.4 +Adjusted EBITDA +$ +435.6 +$ +443.2 +$ +364.3 +Cash from operating activities to adjusted EBITDA: +Net cash from operating activities +$ +486.3 +$ +411.1 +$ +236.7 +Interest expense, net +61.0 +42.8 +48.6 +Stock-based compensation +(19.5 +) +(20.1 +) +(17.5 +) +Amortization of debt discount and issuance costs +(16.2 +) +(7.0 +) +(6.9 +) +Gain on sale of properties and equipment +— +0.4 +76.0 +Other +(56.5 +) +6.3 +13.9 +Changes in assets and liabilities +(19.5 +) +9.7 +13.5 +Adjusted EBITDA +$ +435.6 +$ +443.2 +$ +364.3 +PV-10: +PV-10 +$ +1,675.0 +$ +1,337.5 +$ +3,450.1 +Present value of estimated future income tax discounted at 10% +(254.4 +) +(240.6 +) +(1,143.6 +) +Standardized measure of discounted future net cash flows +$ +1,420.6 +$ +1,096.9 +$ +2,306.5 +Amounts above include results from continuing and discontinued operations. +60 +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK +Market-Sensitive Instruments and Risk Management +We are exposed to market risks associated with interest rate risks, commodity price risk, and credit risk. We have established risk management processes to monitor and manage these market risks. +Interest Rate Risk +Changes in interest rates affect the amount of interest we earn on our interest bearing cash and cash equivalents and the interest we pay on borrowings under our revolving credit facility. Our 2021 Convertible Notes, 2024 Senior Notes, and 2022 Senior Notes have fixed rates and, therefore, near-term changes in interest rates do not expose us to risk of earnings or cash flow loss; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt. +As of December 31, 2016 , our interest-bearing deposit accounts included money market accounts and checking accounts with various banks. The amount of our interest-bearing cash and cash equivalents as of December 31, 2016 was $208.8 million, with a weighted-average interest rate of 0.3 percent. Based on a sensitivity analysis of our interest bearing deposits as of December 31, 2016 and assuming we had $208.8 million outstanding throughout the period, we estimate that a one percent increase in interest rates would have increased interest income for the twelve months ended December 31, 2016 by approximately $2.1 million. +As of December 31, 2016 , we had no outstanding balance on our revolving credit facility. +Commodity Price Risk +We are exposed to the potential risk of loss from adverse changes in the market price of crude oil, natural gas, and NGLs. Pursuant to established policies and procedures, we manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. These instruments help us predict with greater certainty the effective crude oil and natural gas prices we will receive for our hedged production. We believe that our commodity derivative policies and procedures are effective in achieving our risk management objectives. +The following table presents our commodity derivative positions related to crude oil and natural gas sales in effect as of December 31, 2016 : +Collars +Fixed-Price Swaps +Basis Protection Swaps +Commodity/ Index/ +Maturity Period +Quantity (Gas - BBtu Oil - MBbls) +Weighted-Average +Contract Price +Quantity (Gas - BBtu Oil - MBbls) +Weighted- +Average +Contract +Price +Quantity +(BBtu) +Weighted- +Average +Contract +Price +Fair Value +December 31, +2016 (1) +(in millions) +Floors +Ceilings +Crude Oil +NYMEX +2017 +2,464 +$ +49.54 +$ +62.32 +6,002 +$ +49.14 +— +$ +— +$ +(44.3 +) +2018 +1,512 +41.85 +54.31 +3,364 +53.25 +— +— +(19.1 +) +Total Crude Oil +3,976 +9,366 +— +— +$ +(63.4 +) +Natural Gas +NYMEX +2017 +7,920 +$ +3.59 +$ +4.13 +27,290 +$ +3.55 +28,116 +$ +(0.29 +) +$ +(0.5 +) +2018 +1,230 +3.00 +3.67 +45,280 +2.94 +18,200 +(0.29 +) +(6.1 +) +Total Natural Gas +9,150 +72,570 +46,316 +$ +(6.6 +) +Total Crude Oil and Natural Gas +$ +(70.0 +) +_____________ +(1) +Approximately 44 percent of the fair value of our commodity derivative assets and 18 percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3). +61 +Our realized prices vary regionally based on local market differentials and our transportation agreements. The following table presents average market index prices for crude oil and natural gas for the periods identified, as well as the average sales prices we realized for our crude oil, natural gas, and NGLs production: +Year Ended December 31, +2016 +2015 +Average Index Price: +Crude oil (per Bbl) +NYMEX +$ +43.32 +$ +48.80 +Natural gas (per MMBtu) +NYMEX +$ +2.46 +$ +2.66 +Average Sales Price Realized: +Excluding net settlements on commodity derivatives +Crude oil (per Bbl) +$ +39.96 +$ +40.14 +Natural gas (per Mcf) +1.77 +2.04 +NGLs (per Bbl) +11.80 +10.72 +Based on a sensitivity analysis as of December 31, 2016 , it was estimated that a 10 percent increase in natural gas and crude oil prices, inclusive of basis, over the entire period for which we have commodity derivatives in place would have resulted in a decrease in the fair value of our derivative positions of $87.0 million, whereas a 10 percent decrease in prices would have resulted in an increase in fair value of $86.7 million. +Credit Risk +Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure and entering into transactions with high-quality counterparties. When exposed to significant credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We monitor the creditworthiness of significant counterparties through our credit committee, which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. While we believe that our credit risk analysis and monitoring procedures are reasonable, no amount of analysis can assure performance by our counterparties. +Our Oil and Gas Exploration and Production segment's crude oil, natural gas, and NGLs sales are concentrated with a few predominately large customers. This concentrates our credit risk exposure with a small number of large customers. +Amounts due to our Gas Marketing segment are from a diverse group of entities, including major upstream and midstream energy companies, financial institutions, and end-users in various industries. The underlying operations of these entities are however geographically concentrated in the same region, which increases the credit risk associated with this segment. As natural gas prices continue to remain depressed, certain third-party producers relating to our Gas Marketing segment are continuing to experience financial distress, which has led to certain contractual defaults and litigation; however, to date, we have had no material counterparty default losses. We have initiated several legal actions for breach of contract, collection and related claims against certain third-party producers that are delinquent in their payment obligations, which have to date resulted in two default judgments. We expect this trend to continue for this segment. +We primarily use financial institutions which are lenders in our revolving credit facility as counterparties for our derivative financial instruments. Disruption in the credit markets, changes in commodity prices and other factors may have a significant adverse impact on a number of financial institutions. To date, we have had no material counterparty default losses from our commodity derivative financial instruments. See the footnote titled Commodity Derivative Financial Instruments to our consolidated financial statements included elsewhere in this report for more detail on our commodity derivative financial instruments. +Disclosure of Limitations +Because the information above included only those exposures that existed at December 31, 2016 , it does not consider those exposures or positions which could arise after that date. Our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, our commodity price risk management strategies at the time and interest rates and commodity prices at the time. +62 +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Index to Consolidated Financial Statements, Financial Statement Schedule and Supplemental Information +Financial Statements: +Report of Independent Registered Public Accounting Firm +64 +Consolidated Balance Sheets - December 31, 201 6 and 2015 +65 +Consolidated Statements of Operations - Years Ended December 31, 2 016, 2015 and 2014 +66 +Consolidated Statements of Cash Flows - Years Ended December 31, 201 6, 2015 and 2014 +67 +Consolidated Statements of Equity - Years Ended December 31, 201 6, 2015 and 2014 +68 +Notes to Consolidated Financial Statements +69 +Supplemental Information - Unaudited: +Crude Oil and Natural Gas Information +97 +Quarterly Financial Information +103 +Financial Statement Schedule: +Schedule II - Valuation and Qualifying Accounts +104 +63 +Report of Independent Registered Public Accounting Firm +To the Board of Directors and Shareholders of PDC Energy, Inc.: +In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, cash flows, and equity present fairly, in all material respects, the financial position of PDC Energy, Inc. and its subsidiaries at December 31, 2016 and December 31, 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for each of the three years ended December 31, 2016, appearing under Item 8, presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +As described in Management’s Annual Report on Internal Control over Financial Reporting, management has excluded certain Delaware Basin acquisitions from their assessment of internal control over financial reporting as of December 31, 2016, because they were acquired by the Company in a purchase business combination during 2016. We have also excluded these acquisitions from our audit of internal control over financial reporting. The acquisitions are wholly owned subsidiaries whose total assets and total revenues represent 11% and 1%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2016. +/s/PricewaterhouseCoopers LLP +Denver, Colorado +February 28, 2017 +64 +PDC ENERGY, INC. +Consolidated Balance Sheets +(in thousands, except share and per share data) +As of December 31, +2016 +2015 +Assets +Current assets: +Cash and cash equivalents +$ +244,100 +$ +850 +Accounts receivable, net +143,392 +104,274 +Fair value of derivatives +8,791 +221,659 +Prepaid expenses and other current assets +3,542 +5,266 +Total current assets +399,825 +332,049 +Properties and equipment, net +4,008,266 +1,940,552 +Fair value of derivatives +2,386 +44,387 +Goodwill +62,041 +— +Other assets +13,324 +53,555 +Total Assets +$ +4,485,842 +$ +2,370,543 +Liabilities and Stockholders' Equity +Liabilities +Current liabilities: +Accounts payable +$ +66,322 +$ +92,613 +Production tax liability +24,767 +26,524 +Fair value of derivatives +53,595 +1,595 +Funds held for distribution +71,339 +29,894 +Current portion of long-term debt +— +112,940 +Accrued interest payable +15,930 +9,057 +Other accrued expenses +38,625 +28,709 +Total current liabilities +270,578 +301,332 +Long-term debt +1,043,954 +529,437 +Deferred income taxes +400,867 +143,452 +Asset retirement obligations +82,612 +84,032 +Fair value of derivatives +27,595 +695 +Other liabilities +37,482 +24,398 +Total liabilities +1,863,088 +1,083,346 +Commitments and contingent liabilities +Stockholders' equity +Common shares - par value $0.01 per share, 150,000,000 authorized, 65,704,568 and 40,174,776 issued as of December 31, 2016 and 2015, respectively +657 +402 +Additional paid-in capital +2,489,557 +907,382 +Retained earnings +134,208 +380,422 +Treasury shares - at cost, 28,763 and 20,220 as of December 31, 2016 and 2015, respectively +(1,668 +) +(1,009 +) +Total stockholders' equity +2,622,754 +1,287,197 +Total Liabilities and Stockholders' Equity +$ +4,485,842 +$ +2,370,543 +See accompanying Notes to Consolidated Financial Statements +65 +PDC ENERGY, INC. +Consolidated Statements of Operations +(in thousands, except per share data) +Year Ended December 31, +2016 +2015 +2014 +Revenues +Crude oil, natural gas, and NGLs sales +$ +497,353 +$ +378,713 +$ +471,413 +Sales from gas marketing +8,725 +10,920 +71,571 +Commodity price risk management gain (loss), net of settlements +(125,681 +) +203,183 +310,304 +Other income +2,518 +2,510 +2,919 +Total revenues +382,915 +595,326 +856,207 +Costs, expenses and other +Lease operating expenses +59,950 +56,992 +42,402 +Production taxes +31,410 +18,443 +25,615 +Transportation, gathering and processing expenses +18,415 +10,151 +4,592 +Cost of gas marketing +10,193 +11,717 +72,015 +Exploration expense +4,669 +1,102 +947 +Impairment of properties and equipment +9,973 +161,620 +166,847 +General and administrative expense +112,470 +89,959 +123,559 +Depreciation, depletion and amortization +416,874 +303,258 +192,528 +Provision for uncollectible notes receivable +44,038 +— +— +Accretion of asset retirement obligations +7,080 +6,293 +3,415 +(Gain) loss on sale of properties and equipment +(43 +) +(385 +) +507 +Total cost, expenses and other +715,029 +659,150 +632,427 +Income (loss) from operations +(332,114 +) +(63,824 +) +223,780 +Interest expense +(61,972 +) +(47,571 +) +(47,842 +) +Interest income +963 +4,807 +1,290 +Income (loss) before income taxes +(393,123 +) +(106,588 +) +177,228 +Income tax benefit (expense) +147,195 +38,308 +(69,967 +) +Income (loss) from continuing operations +(245,928 +) +(68,280 +) +107,261 +Income from discontinued operations, net of tax +— +— +48,174 +Net income (loss) +$ +(245,928 +) +$ +(68,280 +) +$ +155,435 +Earnings per share: +Basic +Income (loss) from continuing operations +$ +(5.01 +) +$ +(1.74 +) +$ +3.00 +Income from discontinued operations, net of tax +— +— +1.34 +Basic +$ +(5.01 +) +$ +(1.74 +) +$ +4.34 +Diluted +Income (loss) from continuing operations +$ +(5.01 +) +$ +(1.74 +) +$ +2.93 +Income from discontinued operations, net of tax +— +— +1.31 +Diluted +$ +(5.01 +) +$ +(1.74 +) +$ +4.24 +Weighted-average common shares outstanding: +Basic +49,052 +39,153 +35,784 +Diluted +49,052 +39,153 +36,678 +See accompanying Notes to Consolidated Financial Statements +66 +PDC ENERGY, INC. +Consolidated Statements of Cash Flows +(in thousands) +Year Ended December 31, +2016 +2015 +2014 +Cash flows from operating activities: +Net income (loss) +$ +(245,928 +) +$ +(68,280 +) +$ +155,435 +Adjustments to net income (loss) to reconcile to net cash from operating activities: +Net change in fair value of unsettled commodity derivatives +333,770 +35,791 +(311,281 +) +Depreciation, depletion and amortization +416,874 +303,258 +201,656 +Provision for uncollectible notes receivable +44,038 +— +— +Impairment of properties and equipment +9,973 +161,620 +167,280 +Accretion of asset retirement obligation +7,080 +6,293 +3,455 +Stock-based compensation +19,502 +20,068 +17,518 +Excess tax benefits from stock-based compensation +— +(1,361 +) +(1,999 +) +Gain from sale of properties and equipment +(43 +) +(385 +) +(75,972 +) +Amortization of debt discount and issuance costs +16,167 +7,040 +6,938 +Deferred income taxes +(137,249 +) +(41,415 +) +88,474 +Other +2,603 +(1,855 +) +(1,329 +) +Total adjustments to net income (loss) to reconcile to net cash from operating activities: +712,715 +489,054 +94,740 +Changes in assets and liabilities: +Accounts receivable +(32,627 +) +24,769 +(34,598 +) +Other assets +2,303 +(2,264 +) +(3,296 +) +Restricted cash +— +46 +2,214 +Production tax liability +9,223 +(1,629 +) +3,358 +Accounts payable and accrued expenses +(162 +) +(30,310 +) +21,453 +Funds held for future distribution +36,510 +2,699 +(4,372 +) +Other liabilities +4,229 +(3,012 +) +1,755 +Total changes in assets and liabilities +19,476 +(9,701 +) +(13,486 +) +Net cash from operating activities +486,263 +411,073 +236,689 +Cash flows from investing activities: +Capital expenditures for development of crude oil and natural gas properties +(436,884 +) +(599,546 +) +(623,750 +) +Capital expenditures for other properties and equipment +(3,464 +) +(5,122 +) +(4,842 +) +Acquisition of crude oil and natural gas properties, net of cash acquired +(1,073,723 +) +— +— +Proceeds from sale of properties and equipment, net +4,945 +405 +154,457 +Net cash from investing activities +(1,509,126 +) +(604,263 +) +(474,135 +) +Cash flows from financing activities: +Proceeds from sale of equity, net of issuance costs +855,074 +202,851 +— +Proceeds from senior notes, net of issuance costs +392,172 +— +— +Proceeds from convertible senior notes, net of issuance costs +193,935 +— +— +Proceeds from revolving credit facility +85,000 +397,000 +263,750 +Repayment of revolving credit facility +(122,000 +) +(416,000 +) +(200,000 +) +Redemption of convertible notes +(115,000 +) +— +— +Payment of debt issuance costs +(15,556 +) +(974 +) +(88 +) +Excess tax benefits from stock-based compensation +— +1,361 +1,999 +Purchase of treasury shares +(6,935 +) +(6,056 +) +(5,392 +) +Other +(577 +) +(208 +) +— +Net cash from financing activities +1,266,113 +177,974 +60,269 +Net change in cash and cash equivalents +243,250 +(15,216 +) +(177,177 +) +Cash and cash equivalents, beginning of year +850 +16,066 +193,243 +Cash and cash equivalents, end of year +$ +244,100 +$ +850 +$ +16,066 +Supplemental cash flow information: +Cash payments for: +Interest, net of capitalized interest +$ +43,406 +$ +45,642 +$ +46,809 +Income taxes, net of refunds +167 +10,049 +1,800 +Non-cash investing activities: +Issuance of common stock for acquisition of crude oil and natural gas properties related to Delaware Basin acquisition +690,702 +— +— +Change in accounts payable related to capital expenditures +(40,448 +) +(45,230 +) +39,667 +Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposal +4,894 +14,030 +33,250 +Change in other assets related to sale of properties and equipment +— +— +39,048 +Purchase of properties and equipment under capital leases +1,404 +1,601 +— +See footnote titled Business Combinations for non-cash transactions related to our acquisitions. +See accompanying Notes to Consolidated Financial Statements +67 +PDC ENERGY, INC. +Consolidated Statements of Equity +(in thousands, except share data) +Common Stock +Treasury Stock +Shares +Amount +Additional Paid-in Capital +Shares +Amount +Retained Earnings +Total Stockholders' Equity +Balances, January 1, 2014 +35,675,656 +$ +357 +$ +674,211 +(5,508 +) +$ +(241 +) +$ +293,267 +$ +967,594 +Net income +— +— +— +— +— +155,435 +155,435 +Purchase of treasury shares +— +— +— +(97,646 +) +(5,392 +) +— +(5,392 +) +Issuance of treasury shares +— +— +(4,817 +) +83,208 +4,817 +— +— +Retirement of treasury shares +(703 +) +— +(35 +) +703 +35 +— +— +Non-employee directors' deferred compensation plan +— +— +— +(2,400 +) +(130 +) +— +(130 +) +Issuance of stock awards, net of forfeitures +253,032 +2 +— +— +— +— +2 +Stock-based compensation expense, including tax impact +— +— +19,850 +— +— +— +19,850 +Balances, December 31, 2014 +35,927,985 +$ +359 +$ +689,209 +(21,643 +) +$ +(911 +) +$ +448,702 +$ +1,137,359 +Net loss +— +— +— +— +— +(68,280 +) +(68,280 +) +Issuance pursuant to sale of equity +4,002,000 +40 +202,811 +— +— +— +202,851 +Purchase of treasury shares +— +— +— +(120,864 +) +(6,055 +) +— +(6,055 +) +Issuance of treasury shares +— +(6,206 +) +127,159 +6,206 +— +— +Non-employee directors' deferred compensation plan +— +— +— +(4,872 +) +(249 +) +— +(249 +) +Issuance of stock awards, net of forfeitures +237,071 +3 +— +— +— +— +3 +Exercise of stock options +7,720 +— +— +— +— +— +— +Stock-based compensation expense, including tax impact +— +— +21,568 +— +— +— +21,568 +Balances, December 31, 2015 +40,174,776 +$ +402 +$ +907,382 +(20,220 +) +$ +(1,009 +) +$ +380,422 +$ +1,287,197 +Net loss +— +— +— +— +— +(245,928 +) +(245,928 +) +Issuance pursuant to acquisition +9,386,768 +94 +690,608 +— +— +— +690,702 +Issuance pursuant to sale of equity +15,007,500 +150 +854,933 +— +— +— +855,083 +Issuance pursuant to note conversion +792,406 +8 +(8 +) +— +— +— +— +Convertible debt discount, net of issuance costs and tax +— +— +23,518 +— +— +— +23,518 +Purchase of treasury shares +— +— +— +(116,085 +) +(6,935 +) +— +(6,935 +) +Issuance of treasury shares +(114,697 +) +— +(6,661 +) +114,697 +6,661 +— +— +Non-employee directors' deferred compensation plan +— +— +— +(7,155 +) +(385 +) +— +(385 +) +Issuance of stock awards, net of forfeitures +411,731 +3 +(3 +) +— +— +— +— +Exercise of stock options +46,084 +— +— +— +— +— +— +Stock-based compensation expense +— +— +19,502 +— +— +— +19,502 +Adoption of updated stock-based compensation accounting +— +— +286 +— +— +(286 +) +— +Balances, December 31, 2016 +65,704,568 +$ +657 +$ +2,489,557 +(28,763 +) +$ +(1,668 +) +$ +134,208 +$ +2,622,754 +See accompanying Notes to Consolidated Financial Statements +68 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION +PDC Energy, Inc. ("PDC", the "Company," "we," "us," or "our") is a domestic independent exploration and production company that acquires, produces, develops, and explores for crude oil, natural gas, and NGLs, with primary operations in the Wattenberg Field in Colorado, the Utica Shale in southeastern Ohio and, beginning in December 2016, the Delaware Basin in Reeves and Culberson Counties, Texas . Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays, our Delaware Basin operations are currently focused in the Wolfcamp zones, and our Ohio operations are focused in the Utica Shale play. As of December 31, 2016 , we owned an interest in approximately 2,900 productive gross wells. We are engaged in two business segments: The Oil and Gas Exploration and Production Segment and the Gas Marketing Segment. In October 2014 , we sold our entire 50 percent ownership interest in our joint venture, PDCM, to an unrelated third-party. +The audited consolidated financial statements include the accounts of PDC, our wholly-owned subsidiaries PDC Permian, Inc. and Riley Natural Gas ("RNG"), our proportionate share of our four affiliated partnerships and, for the information presented covering the year ended December 31, 2014, our proportionate share of PDCM. All material intercompany accounts and transactions have been eliminated in consolidation. +The preparation of our consolidated financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of crude oil, natural gas and NGLs sales revenue; crude oil, natural gas, and NGLs reserves; estimates of unpaid revenues and unbilled costs; future cash flows from crude oil and natural gas properties; valuation of commodity derivative instruments; impairment of proved and unproved properties; valuation and allocations of purchased businesses and assets; estimates of fair value of our fixed rate debt instruments; and valuation of deferred income tax assets. +NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Cash Equivalents. We consider all highly liquid investments with original maturities of three months or less to be cash equivalents. +Derivative Financial Instruments. We are exposed to the effect of market fluctuations in the prices of crude oil, natural gas, and NGLs. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy and our revolving credit facility prohibit the use of crude oil and natural gas derivative instruments for speculative purposes. +All derivative assets and liabilities are recorded on our consolidated balance sheets at fair value. We have elected not to designate any of our commodity derivative instruments as cash flow hedges. Accordingly, changes in the fair value of our commodity derivative instruments are recorded in the consolidated statements of operations. Classification of net settlements resulting from maturities and changes in fair value of unsettled commodity derivatives depends on the purpose for issuing or holding the derivative. Net settlements and changes in the fair value of commodity derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Net settlements and changes in the fair value of commodity derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of gas marketing. The consolidated statements of cash flows reflects the net settlement of commodity derivative instruments in operating cash flows. +The calculation of the commodity derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. +Properties and Equipment. Significant accounting polices related to our properties and equipment are discussed below. +Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. We have determined that we have three units-of-production fields which are the Wattenberg Field, the Delaware Basin, and the Utica Shale. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations, and common cost environments in these areas. We calculate quarterly depreciation, depletion, and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted to add back fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the consolidated statements of operations as a gain or loss. Upon the sale of individual wells or a portion of a field, the proceeds are credited to accumulated DD&A. +Exploration costs, including geological and geophysical expenses, seismic costs on unproved leasehold, and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but +69 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability, or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the proper accounting treatment is recorded. +Proved Property Impairment. Upon a triggering event and when general industry conditions warrant review, we assess our producing crude oil and natural gas properties for possible impairment by comparing net capitalized costs, or carrying value, to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity to be sold. The estimates of future prices may differ from current market prices of crude oil, natural gas, and NGLs. Certain events, including but not limited to downward revisions in estimates to our reserve quantities, expectations of falling commodity prices, or rising operating costs, could result in a triggering event and, therefore, a possible impairment of our proved crude oil and natural gas properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis and is measured by the amount by which the net capitalized costs exceed their fair value. Impairments are included in the consolidated statements of operations line item impairment of properties and equipment, with a corresponding impact on accumulated DD&A. +Unproved Property Impairment. The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired, or amortized. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized, by field, based on our historical experience, acquisition dates, and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statements of operations line item impairment of properties and equipment. +Other Property and Equipment. Other property and equipment is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of the asset exceeds our estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. Impairment and amortization charges related to other property and equipment are charged to the consolidated statements of operations line item impairment of properties and equipment. +The following table presents the estimated useful lives of our other property and equipment: +Transportation, pipeline, and other equipment +2 - 30 years +Buildings +20 - 40 years +Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed from the accounts, the proceeds are applied thereto and any resulting gain or loss is reflected in income. Total depreciation expense related to other property and equipment was $3.8 million , $4.5 million , and $4.1 million in 2016 , 2015 , and 2014 , respectively. +Capitalized Interest. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our debt outstanding by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $4.5 million , $5.1 million , and $3.5 million in 2016 , 2015 , and 2014 , respectively. +Goodwill. Goodwill represents the residual value of purchase price over net tangible and identifiable intangible assets of an acquired business and is stated at cost. Goodwill is not amortized; rather it is assessed annually for impairment, or more frequently if any event indicates that the carrying amount of goodwill may be impaired. +Assets Held for Sale and Discontinued Operations. Assets held for sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques such as a discounted cash flow model, valuations performed by +70 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +third parties, earnings multiples, or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets to be divested once they are classified as held for sale. Assets classified as held for sale are expected to be disposed of within one year. Assets to be divested are classified in the consolidated financial statements as held for sale and the activities of assets to be divested are classified either as discontinued operations or continuing operations. Assets held for sale of $5.3 million as of December 31, 2016 , represents the fair value of field office facilities and a parcel of land. Assets held for sale of $2.9 million as of December 31, 2015 , represents the fair value of a parcel of land. These amounts are included in properties and equipment, net on our consolidated balance sheets. +For assets classified as discontinued operations, the results of operations are reclassified from their historical presentation to discontinued operations on the consolidated statements of operations for all periods presented. The gains or losses associated with these divested assets are recorded in discontinued operations on the consolidated statements of operations. For businesses classified as held for sale that do not qualify for discontinued operations treatment, the results of operations continue to be reported in continuing operations. +Production Tax Liability. Production tax liability represents estimated taxes, primarily severance, ad valorem, and property taxes, to be paid to the states and counties in which we produce crude oil, natural gas, and NGLs, including the production of our affiliated partnerships. Our share of these taxes is expensed and included in the statement of operations line item production taxes. Affiliated partnerships' share, not owned by us, is recognized as a receivable in accounts receivable affiliates on the consolidated balance sheets. The long-term portion of the production tax liability is included in other liabilities on the consolidated balance sheets and was $29.0 million and $19.0 million in December 31, 2016 and 2015 , respectively. +Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable. As of December 31, 2016 and 2015 , we had no valuation allowance. +Debt Issuance Costs. Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs for the 2021 Convertible Notes, the 2024 Senior Notes, and the 2022 Senior Notes are included in long-term debt on the consolidated balance sheets and the debt issuance costs for the revolving credit facility are included in other accrued expenses on the consolidated balance sheets. +Asset Retirement Obligations. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from changes in retirement costs or the estimated timing of settling asset retirement obligations. +Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders’ equity in the consolidated balance sheets. When we retire treasury shares, we charge any excess of cost over the par value entirely to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings. +Revenue Recognition. Significant accounting polices related to our revenue recognition are discussed below. +Crude oil, natural gas, and NGLs sales. Crude oil, natural gas, and NGLs revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred, and collection of revenue is reasonably assured. Our crude oil, natural gas, and NGLs sales are recorded under either the "net-back" or "gross" method of accounting, depending upon the transportation, gathering or processing method used. We use the net-back method of accounting for a portion of our crude oil production in the Wattenberg Field and for substantially all crude oil production in the Delaware Basin and the Utica Shale, as well as natural gas and NGLs from the Delaware Basin and the Wattenberg Field as the majority of the purchasers of these commodities also provide transportation, gathering, and processing services. We sell our commodities at the wellhead and collect a price and recognize revenues based on the wellhead sales price as transportation and processing costs downstream of the wellhead are incurred by the purchaser and reflected in the wellhead price. The net-back method results in the recognition of a sales price that is below the indices for which the production is based. We use the gross method of accounting for Wattenberg Field crude oil delivered through the White Cliffs and Saddle Butte pipelines and for natural gas and NGLs sales related to production from the Utica Shale as the purchasers do not provide transportation, gathering, or processing services. Under this method, we recognize revenues based on the gross selling price. +Gas marketing. Gas marketing is reported on the gross method of accounting, based on the nature of the agreements between our gas marketing subsidiary, RNG, suppliers, and customers. RNG purchases gas from many small producers and bundles the gas together for a +71 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +price advantage to sell in larger amounts to purchasers of gas. RNG has latitude in establishing price and discretion in supplier and purchaser selection. Gas marketing revenues and expenses reflect the full cost and revenue of those transactions because RNG takes title to the gas it purchases from the various producers and bears the risks and rewards of that ownership. Both the net settlements and net change in fair value of unsettled commodity derivatives of the RNG commodity-based derivative transactions for gas marketing are included in sales from or cost of gas marketing, as applicable. +Accounting for Business Combinations. We utilize the purchase method to account for acquisitions of businesses and assets. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows, quoted market prices, and estimates by management, which are Level 3 inputs. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. +In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped, unproved crude oil and natural gas properties, and other non-crude oil and natural gas properties. To estimate the fair value of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of comparable purchased properties to determine an estimation of fair value. +We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. +Stock-Based Compensation. Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the vesting period for the entire award. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statements of operations. No amounts for stock-based compensation were capitalized in 2016 , 2015 , or 2014 . +Credit Risk and Allowance for Doubtful Accounts. Inherent to our industry is the concentration of crude oil, natural gas, and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices, or other conditions. We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs, and overall creditworthiness of our customers. Further, consideration is given to well production data for receivables related to well operations. +Recently Adopted Accounting Standards. +In August 2014, the FASB issued a new standard related to the disclosure of uncertainties about an entity's ability to continue as a going concern. The new standard requires management to assess an entity's ability to continue as a going concern at the end of every reporting period and to provide related footnote disclosures in certain circumstances. The new standard will be effective for all entities in the first annual period ending after December 15, 2016, with early adoption permitted. We early adopted this standard in the fourth quarter of 2016. Adoption of this standard did not have an impact on our consolidated financial statements or related disclosures. +In March 2016, the FASB issued an accounting update on stock-based compensation that is intended to simplify several aspects of the accounting for employee share-based payment award transactions. Areas of simplification include income tax consequences, classification of the awards as either equity or liabilities and the classification on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2016, and interim periods within those years, with early adoption permitted. We early adopted this standard in the fourth quarter of 2016. +• +The primary impact of the adoption was the recognition of excess tax benefits in our provision for income taxes rather than additional paid-in capital, as well as the adjustment in stock-based compensation expense as a result of our changes in forfeiture policy. The new guidance eliminates the requirement to delay the recognition of excess tax benefits until it reduces current taxes payable. We adopted this change on a prospective basis, and recorded unrecognized excess tax benefits amounting to $ 1.5 million , which increased retained earnings in the fourth quarter of 2016. +• +The new guidance also requires us to record, subsequent to the adoption, excess tax benefits and tax deficiencies in the period they occur. Prior to the adoption, the excess tax benefits would have been recorded as APIC. This change could create future volatility in our effective tax rate depending upon the amount of exercise or vesting activity from our stock awards. Under the new guidance, +72 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +we have elected to change our policy and have started to recognize forfeitures of awards as they occur. The change in forfeiture policy was adopted using a modified retrospective transition method. We recorded a cumulative-effect adjustment to decrease retained earnings by $0.3 million upon transition on January 1, 2016, and an increase of stock-based compensation of $0.1 million during the fourth quarter of 2016. Per the guidance in the accounting standard update, the adjustment to stock-based compensation should be recorded on a retrospective basis. Our adjustment was not material to our condensed consolidated financial statements, therefore, we recorded the entire adjustment in the fourth quarter of 2016. +• +The amendment to the minimum statutory withholding tax requirements was adopted on a modified retrospective basis. The adoption had no impact on retained earnings. +• +In addition, we adopted the presentation of taxes paid related to the net share settlement as a financing activity on the statement of cash flows on a retrospective basis. Adoption had no impact to any of the periods presented in our consolidated cash flows statements since such cash flows have historically been presented as a financing activity. +Recently Issued Accounting Standards. +In May 2014, the FASB and the International Accounting Standards Board issued their converged standard on revenue recognition that provides a single, comprehensive model that entities will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (1) identify the contract with the customer, (2) identify the separate performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to separate performance obligations and (5) recognize revenue when (or as) each performance obligation is satisfied. In March 2016, the FASB issued an update to the standard intended to improve the operability and understandability of the implementation guidance on principal versus agent considerations when recognizing revenue. In December 2016, the FASB issued technical corrections and improvements to the standard. The revenue standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The revenue standard can be adopted under the full retrospective method or simplified transition method. Entities are permitted to adopt the revenue standard early, beginning with annual reporting periods after December 15, 2016. We are in the process of assessing potential impacts of the new standard on our existing revenue recognition criteria, as well as on related revenue disclosures. +In February 2016, the FASB issued an accounting update aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements. For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. Both the lease asset and liability will initially be measured at the present value of the future minimum lease payments over the lease term. Subsequent measurement, including the presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those years, with early adoption permitted, and is to be applied as of the beginning of the earliest period presented using a modified retrospective approach. We are in the process of assessing the impact these changes may have on our consolidated financial statements. +In August 2016, the FASB issued an accounting update on statements of cash flows to address diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The update addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our consolidated financial statements. +In November 2016, the FASB issued an accounting update on statements of cash flows to address diversity in practice in the classification and presentation of changes in restricted cash. The accounting update requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash or restricted cash equivalents should be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period amounts shown on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. This is an expansive set of revisions to the cash flow presentation standards, but at this time we do not believe that these changes will impact our consolidated financial statements. +NOTE 3 - BUSINESS COMBINATION +Delaware Basin Acquisition completed December 6, 2016. On December 6, 2016, we closed on an acquisition which has been accounted for as a business combination. The transaction was for the purchase of approximately 57,900 net acres, approximately 30 wells and related midstream infrastructure in Reeves and Culberson Counties, Texas, for an aggregate consideration to the sellers of approximately $1.64 billion , comprised of approximately $952.1 million in cash, including the repayment of $40.0 million of debt from the seller at closing and other purchase price adjustments, and 9.4 million shares of our common stock valued at approximately $690.7 million at the time the acquisition closed. +. +73 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The details of the purchase price and the preliminary allocation of the purchase price for the first transaction are presented below (in thousands): +Year Ended December 31, 2016 +Acquisition costs: +Cash, net of cash acquired +$ +912,142 +Retirement of seller's debt +40,000 +Total cash consideration +952,142 +Common stock, 9.4 million shares +690,702 +Other purchase price adjustments +1,026 +Total acquisition costs +$ +1,643,870 +Recognized amounts of identifiable assets acquired and liabilities assumed: +Assets acquired: +Current assets +$ +8,201 +Crude oil and natural gas properties - proved +216,000 +Crude oil and natural gas properties - unproved +1,721,334 +Infrastructure, pipeline, and other +32,590 +Construction in progress +12,148 +Goodwill +62,041 +Total assets acquired +2,052,314 +Liabilities assumed: +Current liabilities +(24,844 +) +Asset retirement obligations +(3,705 +) +Deferred tax liabilities, net +(379,895 +) +Total liabilities assumed +(408,444 +) +Total identifiable net assets acquired +$ +1,643,870 +The estimated fair value of assets acquired and liabilities assumed in the acquisition presented above are preliminary and subject to post-closing adjustments as more detailed analysis associated with the acquired properties are completed. As of the date of this report, we expect that it may take into mid-2017 until all post-closing adjustments are finalized. +The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, and a market-based weighted-average cost of capital rate. These inputs require significant judgments and estimates by management at the time of the valuation and are the most sensitive and subject to change. +This acquisition was accounted for under the acquisition method. Accordingly, we conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. +Goodwill is calculated as the excess of the purchase price over the fair value of net assets acquired and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Among the factors that contributed to a purchase price in excess of the fair value of the net tangible and intangible assets acquired were the acquisition of an element of a workforce and the expected value from operations of the Delaware Basin acquisition to be derived in the future. Goodwill related to the Delaware Basin acquisition was recorded in our oil and gas exploration and production segment. Any value assigned to goodwill is not expected to be deductible for income tax purposes. +Pro Forma Information. The results of operations for the Delaware Basin acquisition have been included in our consolidated financial statements since the December 6, 2016 closing date, including approximately $5.6 million of total revenue and $1.7 million of loss from operations. The following unaudited pro forma financial information represents a summary of the consolidated results of operations for the years ended December 31, 2016 and December 31, 2015 , assuming the acquisition had been completed as of January 1, 2015. This pro forma financial information includes the Securities Issuances in September 2016, the shares issued to the sellers, and other acquisition costs. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the acquisition had been effective as of these dates, or of future results. +74 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Years Ended December 31, +2016 +2015 +(in thousands, except per share amounts) +Total revenue +$ +412,746 +$ +598,932 +Net loss +$ +(270,942 +) +$ +(138,904 +) +Earnings (loss) per share: +Basic and diluted +$ +(4.22 +) +$ +(2.41 +) +NOTE 4 - PROPERTIES AND EQUIPMENT +The following table presents the components of properties and equipment, net of accumulated DD&A: +As of December 31, +2016 +2015 +(in thousands) +Properties and equipment, net: +Crude oil and natural gas properties +Proved +$ +3,499,718 +$ +2,881,189 +Unproved +1,874,671 +60,498 +Total crude oil and natural gas properties +5,374,389 +2,941,687 +Infrastructure, pipeline, and other +62,093 +30,098 +Land and buildings +12,165 +12,667 +Construction in progress +122,591 +113,115 +Properties and equipment, at cost +5,571,238 +3,097,567 +Accumulated DD&A +(1,562,972 +) +(1,157,015 +) +Properties and equipment, net +$ +4,008,266 +$ +1,940,552 +Delaware Basin Acreage Acquisition. On December 30, 2016, we closed the purchase of approximately an additional 4,600 net bolt-on acres in Reeves and Culberson Counties, Texas, for consideration to the sellers of approximately $120.6 million , in cash, subject to post-closing adjustments. The transaction was accounted for as an acquisition of assets. +Acreage Exchange. In September 2016, we closed on an acreage exchange transaction with Noble Energy, Inc. and certain of its subsidiaries ("Noble") to consolidate certain acreage positions in the core area of the Wattenberg Field. Pursuant to the transaction, we exchanged leasehold acreage and, to a lesser extent, interests in certain development wells. Upon closing, we received approximately 13,500 net acres in exchange for approximately 11,700 net acres, with no cash exchanged between the parties. The assets exchanged were all in the same unit of production for property considerations, so it was concluded that this transaction was outside of the scope of the accounting requirements for recording the transaction at fair value and determining gain or loss on the non-monetary exchanges. The new acreage and underlying property costs were recorded at the previous historical cost of the assets we exchanged. +The following table presents impairment charges recorded for properties and equipment: +Year Ended December 31, +2016 +2015 +2014 +(in thousands) +Impairment of proved and unproved properties +$ +5,562 +$ +154,608 +$ +161,604 +Amortization of individually insignificant unproved properties +1,379 +7,012 +4,465 +Land and buildings +3,032 +— +778 +Impairment of properties and equipment +9,973 +161,620 +166,847 +Discontinued operations: +Impairment of proved and unproved properties +— +— +433 +Total discontinued operations +— +— +433 +Total impairment of properties and equipment +$ +9,973 +$ +161,620 +$ +167,280 +75 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Due to a significant decline in commodity prices and decreases in our net realized sales prices, we experienced triggering events during 2015 and 2014 that required us to assess our crude oil and natural gas properties for possible impairment. As a result of our assessments, we recorded impairment charges of $150.3 million and $158.3 million in 2015 and 2014, respectively, to write-down our Utica Shale proved and unproved properties. Of these impairment charges, $24.7 million and $112.6 million were recorded in 2015 and 2014, respectively, to write-down certain capitalized well costs on our Utica Shale proved producing properties. In 2015 and 2014, we also recorded impairment charges of $125.6 million and $45.7 million to write-down our Utica Shale lease acquisition costs. The impairment charges, which are included in the consolidated statements of operations line item impairment of properties and equipment, represented the amount by which the carrying value of these crude oil and natural gas properties exceeded the estimated fair values. We continued to monitor whether any further impairments were triggered and required measurement throughout 2016 given the continued volatility of commodity prices and the continued capital investment in the development and acquisition of oil and gas properties. No such triggering events occurred during 2016. Impairment charges in 2016 relate to the write-off of certain leases that were no longer part of our development plan and to reflect the fair value of other land and buildings that is held for sale as of December 31, 2016. +Suspended Well Costs +As of December 31, 2016 and 2015 , there were no suspended well costs or wells pending determination. +NOTE 5 - COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS +Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas, and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas, we utilize the following economic hedging strategies for each of our business segments. +• +For crude oil and natural gas sales, we enter into derivative contracts to protect against price declines in future periods. While we structure these commodity derivatives to reduce our exposure to changes in price associated with the derivative commodity, they also limit the benefit we might otherwise have received from price increases in the physical market; and +• +For gas marketing, we enter into fixed-price physical purchase and sale agreements that qualify as derivative contracts. In order to offset the fixed-price physical commodity derivatives in our gas marketing, we enter into financial derivative instruments that have the effect of locking in the prices we will receive or pay for the same volumes and period, offsetting the physical derivative. +We believe our commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of December 31, 2016 , we had derivative instruments, which were comprised of collars, fixed-price commodity swaps, basis protection swaps, and physical sales and purchases, in place for a portion of our anticipated production through 2018 for a total of 81,720 BBtu of natural gas and 13,342 MBbls of crude oil. The commodity derivative contracts were entered into at no cost to us as we hedge our anticipated production at the then-prevailing commodity market prices. +As of December 31, 2016 , our derivative instruments were comprised of collars, fixed-price commodity swaps, basis protection swaps, and physical sales and purchases. +• +Collars contain a fixed floor price (put) and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty; +• +Fixed-price commodity swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty; +• +Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For CIG-basis protection swaps, which had a negative differential to NYMEX for the majority of 2016 , we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. If the market price and contract price are the same, no payment is due to or from the counterparty; and +• +Physical sales and purchases are commodity derivatives for fixed-priced physical transactions where we sell or purchase third-party supply at fixed rates. These physical commodity derivatives are offset by financial swaps: for a physical sale the offset is a swap purchase and for a physical purchase the offset is a swap sale. +We have elected not to designate any of our derivative instruments as cash flow hedges, and therefore do not qualify for use of hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the statements of operations. Changes in the fair value of derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in +76 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +commodity price risk management, net. Changes in the fair value of derivative instruments related to our Gas Marketing segment are recorded in sales from and cost of gas marketing. +The following table presents the balance sheet location and fair value amounts of our derivative instruments on the consolidated balance sheets as of December 31, 2016 and 2015 : +Derivative instruments: +Consolidated Balance sheet line item +2016 +2015 +(in thousands) +Derivative assets: +Current +Commodity derivative contracts - +Related to crude oil and natural gas sales +Fair value of derivatives +$ +8,239 +$ +221,161 +Related to gas marketing +Fair value of derivatives +251 +441 +Basis protection derivative contracts - +Related to crude oil and natural gas sales +Fair value of derivatives +301 +57 +8,791 +221,659 +Non-current +Commodity derivative contracts - +Related to crude oil and natural gas sales +Fair value of derivatives +1,104 +44,292 +Related to gas marketing +Fair value of derivatives +19 +51 +Basis protection derivative contracts - +Related to crude oil and natural gas sales +Fair value of derivatives +1,263 +44 +2,386 +44,387 +Total derivative assets +$ +11,177 +$ +266,046 +Derivative liabilities: +Current +Commodity derivative contracts - +Related to crude oil and natural gas sales +Fair value of derivatives +$ +53,353 +$ +— +Related to gas marketing +Fair value of derivatives +212 +417 +Basis protection derivative contracts - +Related to crude oil and natural gas sales +Fair value of derivatives +30 +1,178 +53,595 +1,595 +Non-current +Commodity derivative contracts - +Related to crude oil and natural gas sales +Fair value of derivatives +27,581 +275 +Related to gas marketing +Fair value of derivatives +14 +46 +Basis protection derivative contracts - +Related to crude oil and natural gas sales +Fair value of derivatives +— +374 +27,595 +695 +Total derivative liabilities +$ +81,190 +$ +2,290 +77 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the impact of our derivative instruments on our consolidated statements of operations: +Year Ended December 31, +Consolidated statements of operations line item +2016 +2015 +2014 +(in thousands) +Commodity price risk management gain (loss), net - +Net settlements +$ +208,103 +$ +238,935 +$ +(837 +) +Net change in fair value of unsettled derivatives +(333,784 +) +(35,752 +) +311,141 +Total commodity price risk management gain (loss), net +$ +(125,681 +) +$ +203,183 +$ +310,304 +Sales from gas marketing - +Net settlements +$ +543 +$ +778 +$ +(208 +) +Net change in fair value of unsettled derivatives +(676 +) +(318 +) +364 +Total sales from gas marketing +$ +(133 +) +$ +460 +$ +156 +Cost of gas marketing - +Net settlements +$ +(483 +) +$ +(745 +) +$ +346 +Net change in fair value of unsettled derivatives +690 +279 +(451 +) +Total cost of gas marketing +$ +207 +$ +(466 +) +$ +(105 +) +All of our financial derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. Our fixed-price physical purchase and sale agreements that qualify as derivative contracts are not subject to master netting provisions and are not significant. We have elected not to offset the fair value positions recorded on our consolidated balance sheets. +The following table reflects the impact of netting agreements on gross derivative assets and liabilities: +As of December 31, 2016 +Derivative instruments, recorded in consolidated balance sheet, gross +Effect of master netting agreements +Derivative instruments, net +(in thousands) +Asset derivatives: +Derivative instruments, at fair value +$ +11,177 +$ +(10,930 +) +$ +247 +Liability derivatives: +Derivative instruments, at fair value +$ +81,190 +$ +(10,930 +) +$ +70,260 +As of December 31, 2015 +Derivative instruments, recorded in consolidated balance sheet, gross +Effect of master netting agreements +Derivative instruments, net +(in thousands) +Asset derivatives: +Derivative instruments, at fair value +$ +266,046 +$ +(1,921 +) +$ +264,125 +Liability derivatives: +Derivative instruments, at fair value +$ +2,290 +$ +(1,921 +) +$ +369 +NOTE 6 - FAIR VALUE OF FINANCIAL INSTRUMENTS +Derivative Financial Instruments +Determination of fair value. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +78 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. +Derivative Financial Instruments. We measure the fair value of our derivative instruments based on a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors, and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. +We validate our fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques and believe our valuation method is appropriate and consistent with those used by other market participants, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. +Our fixed-price swaps, basis swaps, and physical purchases are included in Level 2 and our collars and physical sales are included in Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis: +As of December 31, +2016 +2015 +Significant Other +Observable +Inputs +(Level 2) +Significant +Unobservable +Inputs +(Level 3) +Total +Significant Other +Observable +Inputs +(Level 2) +Significant +Unobservable +Inputs +(Level 3) +Total +(in thousands) +Total assets +$ +6,350 +$ +4,827 +$ +11,177 +$ +174,758 +$ +91,288 +$ +266,046 +Total liabilities +66,789 +14,401 +81,190 +2,290 +— +2,290 +Net asset (liability) +$ +(60,439 +) +$ +(9,574 +) +$ +(70,013 +) +$ +172,468 +$ +91,288 +$ +263,756 +The following table presents a reconciliation of our Level 3 commodity derivative instruments measured at fair value: +2016 +2015 +2014 +(in thousands) +Fair value of Level 3 instruments, net asset beginning of period +$ +91,288 +$ +62,356 +$ +1,111 +Changes in fair value included in consolidated statement of operations line item: +Commodity price risk management gain (loss), net +(28,530 +) +65,018 +62,003 +Sales from gas marketing +(20 +) +146 +(22 +) +Settlements included in statement of operations line items: +Commodity price risk management gain (loss), net +(72,242 +) +(36,169 +) +(737 +) +Sales from gas marketing +(70 +) +(63 +) +1 +Fair value of Level 3 instruments, net asset (liability) end of period +$ +(9,574 +) +$ +91,288 +$ +62,356 +Net change in fair value of Level 3 unsettled derivatives included in statement of operations line item: +Commodity price risk management gain (loss), net +$ +(12,905 +) +$ +43,540 +$ +15,632 +Sales from gas marketing +— +— +3 +Total +$ +(12,905 +) +$ +43,540 +$ +15,635 +79 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. There has been no change in the methodology we apply to measure the fair value of our Level 3 derivative contracts during the periods covered by the financial statements. +Non-Derivative Financial Assets and Liabilities +The carrying value of the financial instruments included in current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. +We utilize fair value on a nonrecurring basis to review our crude oil and natural gas properties for possible impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such properties. The fair value of the properties is determined based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil, natural gas and NGLs will be sold. +The portion of our long-term debt related to our revolving credit facility approximates fair value due to the variable nature of related interest rates. We have not elected to account for the portion of our debt related to our senior notes or convertible notes under the fair value option; however, we have determined an estimate of the fair values based on measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes and convertible notes as of December 31, 2016 : +Estimated Fair Value +% of Par +(in millions) +Senior notes: +2021 Convertible Notes +$ +220.2 +110.1 +% +2024 Senior Notes +408.0 +102.0 +% +2022 Senior Notes +535.0 +107.0 +% +The carrying value of our capital lease obligations approximates fair value due to the variable nature of the imputed interest rates and the duration of the vehicle lease. +NOTE 7 - CONCENTRATION OF RISK +Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts: +As of December 31, +2016 +2015 +(in thousands) +Crude oil, natural gas and NGLs sales +$ +97,520 +$ +41,873 +Joint interest billings +20,118 +35,017 +Derivative counterparties +10,266 +24,437 +Income tax receivable +11,505 +— +Insurance reimbursement +— +879 +Other +6,173 +4,077 +Allowance for doubtful accounts +(2,190 +) +(2,009 +) +Accounts receivable, net +$ +143,392 +$ +104,274 +Our accounts receivable primarily relate to sales of our crude oil, natural gas, and NGLs production, receivable balances from other third parties that own working interests in the properties we operate, and derivative counterparties. For the years ended December 31, 2016 and 2015 , amounts written off to allowance for doubtful accounts were not material. As of December 31, 2016 , we had no customers representing 10 percent or greater of our accounts receivable balance. As of December 31, 2015 , we had one customer representing 10 percent or greater of our accounts receivable balance. +80 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Major Customers. The following table presents the individual customers constituting 10 percent or more of total revenues: +Year Ended December 31, +Customer +2016 +2015 +2014 +Suncor Energy Marketing, Inc. +22.3 +% +14.3 +% +19.7 +% +DCP Midstream, LP +20.2 +% +13.2 +% +15.1 +% +Aka Energy Group, LLC +13.4 +% +— +% +— +% +Concord Energy, LLC +13.4 +% +23.2 +% +18.3 +% +Bridger Energy, LLC +11.5 +% +— +% +— +% +Shell Trading Company +— +% +13.8 +% +— +% +Teppco Crude Oil, LLC +— +% +— +% +12.9 +% +The concentration of revenue represented by the customers noted above relate to our oil and gas exploration and production segment. +Derivative Counterparties. A portion of our liquidity relates to commodity derivative instruments that enable us to manage a portion of our exposure to price volatility from producing crude oil and natural gas. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also major lenders under our revolving credit facility as counterparties to our commodity derivative contracts; however, an insignificant portion of our commodity derivative instruments may be with other counterparties. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our current counterparties on the fair value of our derivative instruments is not significant at December 31, 2016 , taking into account the estimated likelihood of nonperformance. +Note Receivable +The following table presents information regarding our note receivable outstanding: +As of December 31, +2016 +2015 +(in thousands) +Principal and PIK Interest outstanding at beginning of period +$ +43,069 +$ +39,707 +PIK Interest +969 +3,362 +Principal and PIK Interest outstanding at end of period +44,038 +43,069 +Allowance for uncollectible notes receivable +(44,038 +) +— +Note receivable, net +$ +— +$ +43,069 +In October 2014, we sold our entire 50 percent ownership interest in PDCM to an unrelated third-party as described in the footnote titled Divestiture and Discontinued Operations . As part of the consideration, we received a promissory note (the “Note”) for a principal sum of $39.0 million , bearing varying interest rates beginning at eight percent and increasing annually. Pursuant to the Note agreement, interest shall be paid quarterly, in arrears, commencing December 2014 and continuing on the last business day of each fiscal quarter thereafter. At the option of the issuer of the Note, an unrelated third-party, interest can be paid-in-kind (the “PIK Interest”) and any such PIK Interest will be added to the outstanding principal amount of the Note. Through December 31, 2016 , the issuer of the Note had elected the PIK Interest option for each quarterly period since inception. The principal and any unpaid interest shall be due and payable in full in September 2020 and can be prepaid in whole or in part at any time, and in certain circumstances must be repaid prior to maturity. Any such prepayment will be made without premium or penalty. Legally, the Note is secured by a pledge of stock in certain subsidiaries of the unrelated third-party, debt securities and other assets; however, we believe that the collection of the Note is not reasonably assured. +We examine the Note for evidence of collectability, evaluating factors such as the creditworthiness of the issuer of the Note and the value of the underlying assets that secure the Note. We performed our evaluation and cash flow analysis during the first quarter of 2016 and, based upon the year-end financial statements for 2015, the crude oil and natural gas reserve report of the issuer of the Note, and existing market conditions, determined that collection of the Note and PIK Interest was not reasonably assured. As a result, we recognized a provision and recorded an allowance for uncollectible notes receivable for the $44.0 million outstanding balance as of March 31, 2016, which was included in the consolidated balance sheet line item other assets. Commencing in the second quarter of 2016, we ceased recognizing interest income on the Note and began accounting for the interest on the Note under the cash basis method. To date, we have not received any interest payments. As of December 31, 2016 , there has been no change to our assessment of the collectibility of the Note or related interest, +81 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +and continue to believe collection is not reasonably assured. Under the effective interest method, we previously recognized $4.5 million of interest income for the year ended December 31, 2015, of which $3.4 million was PIK Interest. As of December 2015, the $43.1 million outstanding balance on the Note was included in the consolidated balance sheet line item other assets. +Other Accrued Expenses. The following table presents the components of other accrued expenses: +As of December 31, +2016 +2015 +(in thousands) +Employee benefits +$ +22,282 +$ +17,774 +Asset retirement obligations +9,775 +5,460 +Environmental expenses +3,238 +4,143 +Other +3,330 +1,332 +Other accrued expenses +$ +38,625 +$ +28,709 +NOTE 8 - INCOME TAXES +The table below presents the components of our provision for income taxes from continuing operations for the years presented: +Year Ended December 31, +2016 +2015 +2014 +(in thousands) +Current: +Federal +$ +9,646 +$ +(2,944 +) +$ +(1,514 +) +State +300 +(163 +) +966 +Total current income tax benefit (expense) +9,946 +(3,107 +) +(548 +) +Deferred: +Federal +118,427 +37,352 +(60,698 +) +State +18,822 +4,063 +(8,721 +) +Total deferred income tax benefit (expense) +137,249 +41,415 +(69,419 +) +Income tax benefit (expense) from continuing operations +$ +147,195 +$ +38,308 +$ +(69,967 +) +The following table presents a reconciliation of the statutory rate to the effective tax rate related to our provision for income taxes from continuing operations: +Year Ended December, 31, +2016 +2015 +2014 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income tax, net +2.6 +2.7 +2.8 +Effect of state income tax rate changes +0.6 +(0.3 +) +— +Percentage depletion +— +0.3 +(0.3 +) +Non-deductible compensation +(0.5 +) +(1.2 +) +0.7 +Excess tax benefits from stock-based compensation +0.4 +— +— +Other +(0.7 +) +(0.6 +) +1.3 +Effective tax rate +37.4 +% +35.9 +% +39.5 +% +82 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Amendments related to accounting for excess tax benefits of stock-based compensation have been adopted prospectively, resulting in recognition of excess tax benefits against income tax expenses rather than APIC of $1.5 million for the year ended December 31, 2016 . Excess tax benefits in the amount of $1.4 million were recognized as APIC during the year ended December 31, 2015 , resulting from the vesting of stock-based compensation. +The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities at December 31, 2016 and 2015 are presented below. Of note, the table includes the $403.7 million effect of including the deferred tax liability for the difference in the book and tax basis of the oil and gas properties acquired in the December 6, 2016, business combination and a $23.8 million of acquired deferred tax assets: +As of December 31, +2016 +2015 +(in thousands) +Deferred tax assets: +Deferred compensation +$ +9,338 +$ +13,104 +Asset retirement obligations +34,359 +34,101 +Federal NOL carryforward +29,988 +— +State NOL and tax credit carryforwards, net +5,189 +3,376 +Alternative minimum tax - credit carryforward +5,184 +2,812 +Allowance for note receivable +17,292 +— +Net change in fair value of unsettled derivatives +26,262 +— +Other +4,716 +3,412 +Total gross deferred tax assets +132,328 +56,805 +Deferred tax liabilities: +Properties and equipment +518,964 +99,191 +Net change in fair value of unsettled derivatives +— +100,369 +Convertible debt +14,231 +697 +Total gross deferred tax liabilities +533,195 +200,257 +Net deferred tax liability +$ +400,867 +$ +143,452 +Deferred tax assets increased in 2016, primarily due to the allowance for a note receivable, acquired federal NOL from the stock acquisition component of the Delaware Basin acquisition, current year generated NOL and the reduced fair value of unsettled derivatives. +Deferred tax liabilities increased in 2016, primarily due to the deferred tax liability arising from the excess book basis versus tax carryover basis of the properties and equipment relating to the stock acquisition component of the Delaware Basin acquisition. Deferred tax liabilities also increased due to the 2021 Convertible Notes and accelerated deductions on properties and equipment. These were partially offset by the settlement of commodity derivatives and the decrease in fair value of unsettled commodity derivatives. +During the year ending December 31, 2016 , we generated a federal NOL of $55.4 million of which $32.2 million will be utilized as a carryback leaving a federal NOL carryforward of $23.1 million that will begin to expire in 2036, and we have alternative minimum tax credits of $5.2 million that may be carried forward indefinitely. Also, we acquired a federal NOL of $62.5 million as a component of the Delaware Basin acquisition that will begin to expire in 2034 which is subject to an annual limitation of $15.1 million as a result of the acquisition, which constitutes a change of ownership as defined under IRS Code Section 382. +As of December 31, 2016 , we have state NOL carryforwards of $130.5 million that begin to expire in 2030 and state credit carryforwards of $1.8 million that begin to expire in 2022 . +Unrecognized tax benefits and related accrued interest and penalties were immaterial for the three-year period ended December 31, 2016 . The total amount of unrecognized tax benefits that would affect the effective tax rate decreased to zero in the current year due to a settlement with the IRS on a tax filing position related to our 2014 federal tax return. The statutes of limitations for most of our state tax jurisdictions are open from 2012 forward. +The IRS fully accepted our recently filed 2015 return, with minor agreed-upon adjustments, after the IRS CAP post-filing review process was completed in early January 2017. We are currently participating in the CAP Program for the review of our 2016 and 2017 tax years. Participation in the CAP Program has enabled us to have minimal uncertain tax benefits associated with our federal tax return filings. +There has been increased discussion by the federal government of a potential reduction of the corporate income tax rate and corresponding changes to the tax code. In the event of a change in federal or state income tax rates, the impact of the rate change will be required to be recorded through deferred income tax expense. Should statutory income tax rates decrease, our deferred tax liability will +83 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +decrease, resulting in deferred tax benefit for the period. If the statutory income tax rates increase, our deferred tax liability would increase resulting in a deferred tax expense. +As of December 31, 2016 , we were current with our income tax filings in all applicable state jurisdictions. +NOTE 9 - LONG-TERM DEBT +Long-term debt consists of the following: +As of December 31, +2016 +2015 +(in thousands) +Senior notes: +1.125% Convertible Notes due 2021: +Principal amount +$ +200,000 +$ +— +Unamortized discount +(37,475 +) +— +Unamortized debt issuance costs +(4,584 +) +— +1.125% Convertible Notes due 2021, net of unamortized discount and debt issuance costs +157,941 +— +6.125% Senior Notes due 2024: +Principal amount +400,000 +— +Unamortized debt issuance costs +(7,544 +) +— +6.125% Senior Notes due 2024, net of unamortized debt issuance costs +392,456 +— +7.75% Senior notes due 2022: +Principal amount +500,000 +500,000 +Unamortized debt issuance costs +(6,443 +) +(7,563 +) +7.75% Senior notes due 2022, net of unamortized debt issuance costs +493,557 +492,437 +3.25% Convertible senior notes due 2016: +Principal amount +— +115,000 +Unamortized discount +— +(1,852 +) +Unamortized debt issuance costs +— +(208 +) +3.25% Convertible senior notes due 2016, net of unamortized discount and debt issuance costs +— +112,940 +Total senior notes +1,043,954 +605,377 +Revolving credit facility +— +37,000 +Total debt, net of unamortized discount and debt issuance costs +1,043,954 +642,377 +Less current portion of long-term debt +— +112,940 +Long-term debt +$ +1,043,954 +$ +529,437 +Senior Notes +2021 Convertible Notes. In September 2016 , we issued $200.0 million of 1.125% convertible senior notes due 2021 in a public offering. The 2021 Convertible Notes are governed by an indenture dated September 14, 2016 between us and the U.S. Bank National Association, as trustee. The maturity for the payment of principal is September 15, 2021 . Interest at the rate of 1.125% per year is payable in cash semiannually in arrears on each March 15 and September 15 , commencing on March 15, 2017. The 2021 Convertible Notes are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the 2021 Convertible Notes; equal in right of payment to our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries. The proceeds from the issuance of the 2021 Convertible Notes, after deducting offering expenses and underwriting discounts, were used to fund a portion of the purchase price of acquisitions in the Delaware Basin, to pay related fees and expenses, and for general corporate purposes. +The 2021 Convertible Notes are convertible prior to March 15, 2021 only upon specified events and during specified periods and, thereafter, at any time, in each case at an initial conversion rate of 11.7113 shares of our common stock per $1,000 principal amount of the 2021 Convertible Notes, which is equal to an initial conversion price of approximately $85.39 per share. The conversion rate is subject to +84 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +adjustment upon certain events. Upon conversion, the 2021 Convertible Notes may be settled, at our sole election, in shares of our common stock, cash, or a combination of cash and shares of our common stock. We have initially elected a combination settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the 2021 Convertible Notes in cash and to settle the excess conversion value, if any, in shares, as well as cash in lieu of fractional shares. +We may not redeem the 2021 Convertible Notes prior to their maturity date. If we undergo a "fundamental change", as defined in the indenture for the 2021 Convertible Notes, subject to certain conditions, holders of the 2021 Convertible Notes may require us to repurchase all or part of the 2021 Convertible Notes for cash at a price equal to 100 percent of the principal amount of the 2021 Convertible Notes to be repurchased, plus any accrued and unpaid interest to, but excluding, the fundamental change repurchase date. The occurrence of a fundamental change will also result in the 2021 Convertible Notes becoming convertible. +We allocated the gross proceeds of the 2021 Convertible Notes between the liability and equity components of the debt. The initial $160.5 million liability component was determined based on the fair value of similar debt instruments excluding the conversion feature for similar terms and priced on the same day we issued the 2021 Convertible Notes. The initial $39.5 million equity component represents the debt discount and was calculated as the difference between the fair value of the debt and the gross proceeds of the 2021 Convertible Notes. Approximately $4.8 million in costs associated with the issuance of the 2021 Convertible Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. As of December 31, 2016 , the unamortized debt discount will be amortized over the remaining contractual term to maturity of the 2021 Convertible Notes using an effective interest rate of 5.8% . Based upon the December 31, 2016 stock price of $72.58 per share, the “if-converted” value of the 2021 Convertible Notes did not exceed the principal amount. +2024 Senior Notes. In September 2016 , we issued $400.0 million aggregate principal amount of 6.125% senior notes due September 2024 in a private placement to qualified institutional buyers. In connection with the issuance of the 2024 Senior Notes, we entered into a registration rights agreement with the initial purchasers in which we agreed to file a registration statement with the SEC relating to an offer to exchange the 2024 Senior Notes for registered notes with substantially identical terms. In addition, we have agreed, in certain circumstances, to file a shelf registration statement covering the resale of the 2024 Senior Notes by the holders. The proceeds from the issuance of the 2024 Senior Notes, after deducting offering expenses and underwriting discounts, were used to fund a portion of the purchase price of acquisitions in the Delaware Basin (see the footnotes titled Business Combination and Properties and Equipment) , to pay related fees and expenses, and for general corporate purposes. +The 2024 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually in arrears on March 15 and September 15 , commencing on March 15, 2017. Approximately $7.8 million in costs associated with the issuance of the 2024 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. The 2024 Senior Notes are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the notes; equal in right of payment to all our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the collateral securing such indebtedness, including borrowings under our revolving credit facility; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries. +The 2024 Senior Notes are redeemable after September 15, 2019, at fixed redemption prices beginning at 104.594 percent of the principal amount redeemed. At any time prior to September 15, 2019, we may redeem all or part of the 2024 Senior Notes at a make-whole price set forth in the indenture which generally approximates the present value of the redemption price at September 15, 2019, and remaining interest payments on the 2024 Senior Notes at the time of redemption. +At any time prior to September 15, 2019 , we may redeem up to 35 percent of the outstanding 2024 Senior Notes with proceeds from certain equity offerings at a redemption price of 106.125 percent of the principal amount of the notes redeemed, plus accrued and unpaid interest, if at least 65 percent of the aggregate principal amount of the 2024 Senior Notes remains outstanding after each such redemption and the redemption occurs within 180 days after the closing of the equity offering. +Upon the occurrence of a "change of control," as defined in the indenture for the 2024 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we may, under certain circumstances, be required to use the net cash proceeds of such asset sale to make an offer to purchase the notes at 100 percent of the principal amount, together with any accrued and unpaid interest to the date of purchase. +The indenture governing the 2024 Senior Notes contains covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make investments; create certain liens; enter into agreements that restrict distributions or other payments by restricted subsidiaries to us; enter into transactions with affiliates; sell assets; consolidate or merge with or into other companies or transfer all or substantially of our assets; and create unrestricted subsidiaries. +2022 Senior Notes. In October 2012 , we issued $500.0 million aggregate principal amount 7.75% senior notes due October 15, 2022 in a private placement to qualified institutional buyers. The 2022 Senior Notes have been registered. The 2022 Senior Notes accrue interest from the date of issuance and interest is payable semi-annually in arrears on April 15 and October 15 . Approximately $11.0 million +85 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +in costs associated with the issuance of the 2022 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. The 2022 Senior Notes are senior unsecured obligations and rank senior in right of payment to any of our future indebtedness that is expressly subordinated to the notes. The 2022 Senior Notes rank equally in right of payment with all our existing and future senior indebtedness and rank effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the collateral securing such indebtedness and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries. +At any time prior to October 15, 2017 , we may redeem all or part of the 2022 Senior Notes at a make-whole price set forth in the indenture. On or after October 15, 2017 , we may redeem the notes at fixed redemption prices, plus accrued and unpaid interest, if any, to the date of redemption. +Upon the occurrence of a "change of control" as defined in the indenture for the 2022 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we will be required to use the net cash proceeds of the asset sale to make an offer to purchase the notes at 100 percent of the principal amount, together with any accrued and unpaid interest to the date of purchase. +The indenture governing the 2022 Senior Notes contains covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make certain investments; create certain liens; restrict dividends or other payments by restricted subsidiaries; enter into transactions with affiliates; sell assets; and merge or consolidate with another company. +In January 2017, pursuant to the filing of the supplemental indentures for the 2021 Convertible Notes, 2024 Senior Notes, and the 2022 Senior Notes our subsidiary, PDC Permian, Inc., became a guarantor of our obligations under the notes. +As of December 31, 2016 , we were in compliance with all covenants related to the 2021 Convertible Notes, 2024 Convertible Notes and the 2022 Senior Notes, and expect to remain in compliance throughout the foreseeable future. +2016 Convertible Senior Notes. In November 2010 , we issued $115.0 million aggregate principal amount of 3.25% convertible senior notes due that were due in 2016 ("2016 Convertible Notes") in a private placement. The maturity for the payment of principal was May 15, 2016 , and we paid the aggregate principal amount of the 2016 Convertible Notes, plus cash for the fractional shares, totaling approximately $115.0 million . Additionally, we issued 792,406 shares of common stock for the $47.9 million excess conversion value. See the footnote titled Common Stock for more information. +Revolving Credit Facility +Revolving Credit Facility. Our revolving credit facility matures in May 2020 . The revolving credit facility is available for working capital requirements, capital investments, acquisitions, general corporate purposes and to support letters of credit. The revolving credit facility provides for a maximum of $1 billion in allowable borrowing capacity, subject to the borrowing base determination and subject to limitations under the 2022 Senior Notes. The amount available under the revolving credit facility is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests, excluding proved reserves attributable to our affiliated partnerships. The borrowing base is subject to a semi-annual size redetermination on November 1 and May 1 based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. The revolving credit facility is secured by a pledge of the stock of certain of our subsidiaries, mortgages of certain producing crude oil and natural gas properties and substantially all of our and such subsidiaries' other assets. Our affiliated partnerships are not guarantors of our obligations under the revolving credit facility. The current borrowing base and aggregate commitments under the facility are $700 million . +The weighted-average borrowing rate on our revolving credit facility, exclusive of fees on the unused commitment and the letter of credit noted below, was 2.7 percent and 2.6 percent per annum for the years ended December 31, 2016 and 2015 , respectively. We capitalized $8.8 million and $3.6 million of debt issuance costs as of December 31, 2016 and 2015 , respectively, related to our revolving credit facility which is included in other assets on the consolidated balance sheets. +We had no outstanding balance on our revolving credit facility as of December 31, 2016 compared to $37.0 million outstanding as of December 31, 2015 . The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greater of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus an applicable margin and the rate for dollar deposits in the London interbank market (“LIBOR”) for one month plus a premium), or at our election, a rate equal to LIBOR for certain time periods. Additionally, commitment fees, interest margin, and other bank fees, charged as a component of interest, vary with our utilization of the facility. As of December 31, 2016, the applicable margin is 1.25 percent, and the unused commitment fee is 0.50 percent. No principal payments are generally required until the credit agreement expires in May 2020 , or in the event that the borrowing base falls below the outstanding balance. +The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.00:1.00 and (b) not exceed a maximum leverage ratio of 4.00:1.00 . Our borrowing base availability under the +86 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +revolving credit facility is limited under our 2022 Senior Notes to the greater of $700 million or the calculated value under an Adjusted Consolidated Tangible Net Asset test, as defined in the applicable indenture. As of December 31, 2016 , we were in compliance with all the revolving credit facility covenants and expect to remain in compliance throughout the foreseeable future. As of December 31, 2016, our calculated debt to EBITDAX ratio was 2.10 and our current ratio was 5.00. +The revolving credit facility contains restrictions as to when we can directly or indirectly retire, redeem, repurchase, or prepay in cash any part of the principal of the 2021 Convertible Notes, 2022 Senior Notes, or 2024 Senior Notes. Among other things, the restriction on redemption of the 2021 Convertible Notes requires that immediately after giving effect to any such retirement, redemption, defeasance, repurchase, settlement, or prepayment, the aggregate commitment under the revolving credit facility must exceed the aggregate credit exposure under such facility by at least an amount equal to or greater than 20 percent of such aggregate commitment. +As of December 31, 2016 , RNG had issued an irrevocable standby letter of credit of approximately $11.7 million in favor of a third-party transportation service provider to secure firm transportation of the natural gas produced by third-party producers for whom we market production in the Appalachian Basin. The letter of credit currently expires in September 2017 and is automatically extended annually in accordance with the letter of credit's terms and conditions. The letter of credit reduces the amount of available funds under our revolving credit facility by an amount equal to the letter of credit. As of December 31, 2016 , the available funds under our revolving credit facility, including the reduction for the $11.7 million letter of credit, was $688.3 million . +NOTE 10 - CAPITAL LEASES +We periodically enter into non-cancelable lease agreements for vehicles utilized by our operations and field personnel. These leases are being accounted for as capital leases, as the present value of minimum monthly lease payments, including the residual value guarantee, exceeds 90 percent of the fair value of the leased vehicles at inception of the lease. +The following table presents leased vehicles under capital leases: +As of December 31, +2016 +2015 +(in thousands) +Vehicles +$ +2,975 +$ +1,601 +Accumulated depreciation +(776 +) +(211 +) +$ +2,199 +$ +1,390 +Future minimum lease payments by year and in the aggregate, under non-cancelable capital leases with terms of one year or more, consist of the following: +For the Twelve Months Ending December 31, +Amount +(in thousands) +2017 +$ +914 +2018 +1,099 +2019 +560 +2,573 +Less executory cost +(96 +) +Less amount representing interest +(263 +) +Present value of minimum lease payments +$ +2,214 +Short-term capital lease obligations +$ +699 +Long-term capital lease obligations +1,515 +$ +2,214 +Short-term capital lease obligations are included in other accrued expenses on the consolidated balance sheets. Long-term capital lease obligations are included in other liabilities on the consolidated balance sheets. +87 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 11 - ASSET RETIREMENT OBLIGATIONS +The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interest in crude oil and natural gas properties: +2016 +2015 +(in thousands) +Balance at beginning of period +$ +89,492 +$ +73,855 +Obligations incurred with development activities and assumed with acquisitions +4,894 +2,373 +Accretion expense +7,080 +6,293 +Revisions in estimated cash flows +— +11,658 +Obligations discharged with disposal of properties and asset retirements +(9,079 +) +(4,687 +) +Balance at end of period +92,387 +89,492 +Less current portion +(9,775 +) +(5,460 +) +Long-term portion +$ +82,612 +$ +84,032 +Our estimated asset retirement obligation liability is based on historical experience in plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment cost and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. In 2016, the credit-adjusted risk-free rates used to discount our plugging and abandonment liabilities ranged from 6.5 percent to 8.2 percent. In periods subsequent to initial measurement of the liability, we must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or changes in inflation factors, and changes to our credit-adjusted risk-free rate as market conditions warrant. +The increase in the current portion of asset retirement obligations in 2016 is attributable to an increase in the number of wells to be plugged and abandoned to allow for the drilling of nearby horizontal wells. The revisions in estimated cash flows during 2015 were due to changes in estimates of costs for materials and services related to the plugging and abandonment of certain vertical wells in the Wattenberg Field, as well as a decrease in the estimated useful life of these wells. +NOTE 12 - EMPLOYEE BENEFIT PLANS +We sponsor a qualified retirement plan covering substantially all of our employees. The plan consists of both a traditional and a Roth 401(k) component, as well as a profit sharing component. The 401(k) components enable eligible employees to contribute a portion of their compensation through payroll deductions in accordance with specific guidelines. We provide a discretionary matching contribution based on a percentage of the employees' contributions up to certain limits. Our contribution to the profit sharing component is discretionary. Our total combined expense for the plan was $4.8 million , $4.9 million , and $3.9 million for 2016 , 2015 , and 2014 , respectively. +NOTE 13 - COMMITMENTS AND CONTINGENCIES +Firm Transportation, Processing and Sales Agreements. We enter into contracts that provide firm transportation, sales, and processing agreements on pipeline systems through which we transport or sell crude oil and natural gas. Satisfaction of the volume requirements includes volumes produced by us, purchased from third parties and produced by our affiliated partnerships and other third-party working, royalty and overriding royalty interest owners whose volumes we market on their behalf. Our statements of operations reflect our share of these firm transportation costs. These contracts require us to pay these transportation and processing charges, whether or not the required volumes are delivered. As natural gas prices remain depressed, certain third-party producers under our Gas Marketing Segment have continued to experience financial distress, which has led to certain contractual defaults and litigation; however, to date, no counterparty default losses have been material to us. In 2016 and 2015 , we recorded an allowance for doubtful accounts of approximately $1.3 million and $0.5 million , respectively. We have initiated several legal actions for breach of contract, collection, and related claims against certain third-party producers that are delinquent in their payment obligations, which have to date resulted in two default judgments. +88 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents gross volume information related to our long-term firm transportation, sales and processing agreements for pipeline capacity: +Year Ending December 31, +Area +2017 +2018 +2019 +2020 +2021 and +Through +Expiration +Total +Expiration +Date +Natural gas (MMcf) +Wattenberg Field (1) +— +2,300 +17,125 +18,300 +86,700 +124,425 +September 30, 2025 +Gas Marketing segment +7,117 +7,117 +7,117 +7,136 +11,550 +40,037 +August 31, 2022 +Utica Shale +2,738 +2,738 +2,738 +2,745 +7,064 +18,023 +July 22, 2023 +Total +9,855 +12,155 +26,980 +28,181 +105,314 +182,485 +Crude oil (MBbls) +Wattenberg Field +2,413 +2,413 +2,413 +1,204 +— +8,443 +June 30, 2020 +Dollar commitment (in thousands) +$ +17,158 +$ +18,626 +$ +33,221 +$ +27,430 +$ +89,896 +$ +186,331 +__________ +(1) +In December 2016, in anticipation of our future drilling activities in the Wattenberg Field, we entered into a facilities expansion agreement with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities. The midstream provider is expected to construct a new 200 MMcfd cryogenic plant. We will be bound to the volume requirements in this agreement on the first day of the calendar month after the actual in-service date of the plant, which in the above table is estimated to be September 30, 2018. The agreement requires a baseline volume commitment of current sales volumes to this midstream provider and an incremental volume commitment of 50 MMcfd for seven years, of which we may be required to pay a shortfall fee for any volumes under the 50 MMcfd incremental commitment. Any shortfall of this volume commitment may be offset, in part, by additional third party producers’ volumes sold to the midstream provider when a certain total volume is achieved. We are also required for the first three years of the contract to guarantee a certain target profit margin to the midstream provider on these volumes sold. Under our current drilling plans, we expect to meet both the baseline and incremental volume commitments. Using the NYMEX forward pricing strip at December 31, 2016, the target profit margin would be achieved without an additional payment from us. +During 2016, 2015, and 2014, long-term firm transportation costs for our Gas Marketing segment as shown above were $3.4 million in each year and were recorded in cost of gas marketing in our consolidated statements of operations. For the years 2016, 2015, and 2014, commitments for long-term transportation volumes for Utica Shale natural gas and Wattenberg Field crude oil were $10.0 million , $4.7 million , and $0.3 million , respectively, and were recorded in transportation, gathering and processing expense in our consolidated statements of operations. +Litigation and Legal Items. The Company is involved in various legal proceedings. The Company reviews the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in the best interests of the Company. Management has provided the necessary estimated accruals in the accompanying balance sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations, or liquidity. +Class Action Regarding 2010 and 2011 Partnership Purchases +We finalized a settlement associated with the repurchase of certain partnership purchases in 2015. All required amounts associated with this settlement had been expensed in 2014. +Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. We are not aware of any environmental claims existing as of December 31, 2016 , which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown past non-compliance with environmental laws will not be discovered on our properties. Accrued environmental liabilities are recorded in other accrued expenses on the consolidated balance sheets. +In August 2015, we received the Information Request from the EPA. The Information Request sought, among other things, information related to the design, operation, and maintenance of our Wattenberg Field production facilities in the Denver-Julesburg Basin of Colorado. The Information Request focuses on historical operation and design information for 46 of our production facilities and asks that we conduct sampling and analyses at the identified 46 facilities. We responded to the the Information Request in January 2016. Throughout 2016, we continued to meet with the EPA, Department of Justice, and Colorado Department of Public Health and Environment, and in December we received a draft consent decree from the EPA. +89 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +In addition, in December 2015, we received a Compliance Advisory pursuant to C.R.S. 25-7-115(2) from the Colorado Department of Public Health and Environment's Air Quality Control Commission's Air Pollution Control Division alleging that we failed to design, operate, and maintain certain condensate collection, storage, processing, and handling operations to minimize leakage of volatile organic compounds at 65 facilities consistent with applicable standards under Colorado law. We are in the process of responding to the advisory, but cannot predict the outcome of this matter at this time. +Lease Agreements. We entered into operating leases, principally for the leasing of natural gas compressors, office space, and general office equipment. +The following table presents the minimum future lease payments under the non-cancelable operating leases as of December 31, 2016 : +Year Ending December 31, +2017 +2018 +2019 +2020 +2021 +Thereafter +Total +(in thousands) +Minimum Lease Payments +$ +3,056 +$ +3,041 +$ +3,033 +$ +3,093 +$ +3,154 +$ +6,786 +$ +22,163 +Operating lease expense for 2016 , 2015 , and 2014 was $10.2 million , $9.8 million , and $7.0 million , respectively. +NOTE 14 - COMMON STOCK +Sale of Equity Securities +We issued 9.4 million shares of common stock as partial consideration for 100 percent of the common stock of Arris Petroleum and for the acquisition of certain Delaware Basin properties on December 6, 2016. These shares are restricted for sale until June 6, 2017, due to previously-disclosed lock up agreements. Accordingly, the value of the shares was discounted from the market price on the date of issuance by 6 percent. +The following table provides a summary of our public offerings of common stock in 2016 and 2015: +Date +Shares Issued +Price per Share +Net Proceeds +(in millions) +September 2016 +9,085,000 +$ +61.51 +$ +558.5 +March 2016 +5,922,500 +50.11 +296.6 +March 2015 +4,002,000 +50.73 +202.9 +Stock-Based Compensation Plans +2010 Long-Term Equity Compensation Plan. In June 2010 , our stockholders approved a long-term equity compensation plan for our employees and non-employee directors (the "2010 Plan"). The plan was amended in June 2013. In accordance with the 2010 Plan, up to 3,000,000 new shares of our common stock are authorized for issuance. Shares issued may be either authorized but unissued shares, treasury shares, or any combination of these shares. Additionally, the 2010 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited or, in the case of stock appreciation rights ("SARs"), paid out in the form of cash. Awards may be issued to our employees in the form of SARs, restricted stock, restricted stock units ("RSUs"), performance shares, and performance units, and to our non-employee directors in the form of non-qualified stock options, SARs, restricted stock, and RSUs. Awards may vest over periods set at the discretion of the Compensation Committee of our Board of Directors (the "Compensation Committee") with certain minimum vesting periods. With regard to SARs, awards have a maximum exercisable period of ten years. In no event may an award be granted under the 2010 Plan on or after April 1, 2020. As of December 31, 2016 , 839,052 shares remain available for issuance pursuant to the 2010 Plan. +90 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented: +Year Ended December 31, +2016 +2015 +2014 +(in thousands) +Stock-based compensation expense +$ +19,502 +$ +20,068 +$ +17,518 +Income tax benefit +(7,296 +) +(7,636 +) +(5,955 +) +Net stock-based compensation expense +$ +12,206 +$ +12,432 +$ +11,563 +Stock Appreciation Rights ("SARs") +The SARs vest ratably over a three-year period and may be exercised at any point after vesting through ten years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance. +The Compensation Committee has awarded SARs to our executive officers in 2016, 2015, and 2014. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions: +Year Ended December 31, +2016 +2015 +2014 +Expected term of award +6.0 years +5.2 years +6.0 years +Risk-free interest rate +1.8 +% +1.4 +% +2.1 +% +Expected volatility +54.5 +% +58.0 +% +65.6 +% +Weighted-average grant date fair value per share +$ +26.96 +$ +22.23 +$ +29.96 +The expected term of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. We do not expect to pay or declare dividends in the foreseeable future. +The following table presents the changes in our SARs for all periods presented: +Year Ended December 31, +2016 +2015 +2014 +Number of +SARs +Weighted-Average +Exercise +Price +Average Remaining Contractual +Term (in years) +Aggregate Intrinsic +Value (in thousands) +Number of +SARs +Weighted-Average +Exercise +Price +Aggregate Intrinsic +Value (in thousands) +Number of +SARs +Weighted-Average +Exercise +Price +Aggregate Intrinsic +Value (in thousands) +Outstanding beginning of year, January 1, +326,453 +$ +38.99 +7.3 +$ +4,697 +279,011 +$ +38.77 +$ +1,472 +190,763 +$ +33.77 +$ +3,711 +Awarded +58,709 +51.63 +— +— +68,274 +39.63 +— +88,248 +49.57 +— +Exercised +(141,084 +) +40.16 +— +2,770 +(20,832 +) +38.05 +473 +— +— +— +Outstanding at December 31, +244,078 +41.36 +6.9 +7,620 +326,453 +38.99 +4,697 +279,011 +38.77 +1,472 +Exercisable at December 31, +174,919 +38.72 +6.3 +5,924 +222,489 +37.70 +3,489 +139,334 +36.27 +982 +Total compensation cost related to SARs granted and not yet recognized in our consolidated statements of operations as of December 31, 2016 , was $1.5 million . The cost is expected to be recognized over a weighted-average period of 1.7 years. +Restricted Stock Awards +Time-Based Awards. The fair value of the time-based restricted shares is amortized ratably over the requisite service period, primarily three years. The time-based shares generally vest ratably on each anniversary following the grant date that a participant is continuously employed. +91 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the changes in non-vested time-based awards during 2016 : +Shares +Weighted-Average +Grant Date +Fair Value +Non-vested at December 31, 2015 +525,081 +$ +50.23 +Granted +290,010 +58.52 +Vested +(317,034 +) +48.61 +Forfeited +(18,415 +) +56.10 +Non-vested at December 31, 2016 +479,642 +56.09 +The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: +As of/Year Ended December 31, +2016 +2015 +2014 +(in thousands, except per share data) +Total intrinsic value of time-based awards vested +$ +18,973 +$ +17,077 +$ +18,278 +Total intrinsic value of time-based awards non-vested +34,812 +28,029 +23,290 +Market price per common share as of December 31, +72.58 +53.38 +41.27 +Weighted-average grant date fair value per share +58.52 +48.88 +56.45 +Total compensation cost related to non-vested time-based awards and not yet recognized in our consolidated statements of operations as of December 31, 2016 was $17.5 million . This cost is expected to be recognized over a weighted-average period of 1.9 years. +Market-Based Awards. The fair value of the market-based restricted shares is amortized ratably over the requisite service period, primarily three years. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of three years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. +In January 2016 , the Compensation Committee awarded a total of 24,280 market-based restricted shares to our executive officers. In addition to continuous employment, the vesting of these shares is contingent on the Company's total stockholder return ("TSR"), which is essentially the Company’s stock price change including any dividends, as compared to the TSR of a group of peer companies. The shares are measured over a three-year period ending on December 31, 2018 and can result in a payout between 0 percent and 200 percent of the total shares awarded. As of December 31, 2016, we had approximately 48,000 non-vested market based restricted shares that could result in a payout between 0 and approximately 96,000 shares of our common stock. The weighted-average grant date fair value per market-based share for these awards granted was computed using the Monte Carlo pricing model using the following assumptions: +Year Ended December 31, +2016 +2015 +Expected term of award +3 years +3 years +Risk-free interest rate +1.2 +% +0.9 +% +Expected volatility +52.3 +% +53.0 +% +Weighted-average grant date fair value per share +$ +72.54 +$ +66.16 +The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our historical volatility. +92 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the change in non-vested market-based awards during 2016 : +Shares +Weighted-Average +Grant Date +Fair Value per Share +Non-vested at December 31, 2015 +71,549 +$ +63.60 +Granted +24,280 +72.54 +Vested +(47,409 +) +66.78 +Non-vested at December 31, 2016 +48,420 +64.97 +The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: +As of/Year Ended December 31, +2016 +2015 +2014 +(in thousands, except per share data) +Total intrinsic value of market-based awards vested +$ +6,562 +$ +4,293 +$ +1,260 +Total intrinsic value of market-based awards non-vested +3,514 +3,819 +3,455 +Market price per common share as of December 31, +72.58 +53.38 +41.27 +Weighted-average grant date fair value per share +72.54 +66.16 +56.87 +Total compensation cost related to non-vested market-based awards and not yet recognized in our consolidated statements of operations as of December 31, 2016 was $1.7 million . This cost is expected to be recognized over a weighted-average period of 1.7 years. +Treasury Share Purchases +In accordance with our stock-based compensation plans, employees and directors may surrender shares of the Company's common stock to pay tax withholding obligations upon the vesting and exercise of share-based awards. Shares acquired that had been issued pursuant to the 2010 Plan are reissued for new grants. For shares reissued for new grants under the 2010 Plan, shares are recorded at cost and upon reissuance we reduce the carrying value of shares acquired and held pursuant to the 2010 Plan by the weighted-average cost per share with an offsetting charge to APIC. As of December 3, 2015, we had 9,009 shares remaining available for reissuance pursuant to our 2010 plan. Additionally, as of December 31, 2016 and 2015, we had 18,366 and 11,211 , respectively, of shares of treasury stock related to a rabbi trust. During the year ended December 31, 2016 , we acquired 116,085 shares pursuant to our stock-based compensation plans for payment of tax liabilities, of which 114,697 shares were reissued and 10,397 shares are available for reissuance pursuant to our 2010 Plan. +Stockholders’ Rights Agreement +In 2007, we entered into a rights agreement designed to improve the ability of our Board to protect the interest of our stockholders in the event of an unsolicited takeover attempt. The rights agreement and all rights were set to expire in September 2017 . In June 2016, we entered into an amendment to the rights agreement, which accelerated the expiration date from September 2017 to June 2016 . Upon the expiration in June 2016, all of the rights distributed to holders of our common stock pursuant to the rights agreement expired. The amendment was entered into as a result of governance considerations and not in contemplation of any anticipated business combination or similar transaction. +Preferred stock +We are authorized, pursuant to stockholder approval in 2008, to issue 50,000,000 shares of preferred stock, par value $0.01, which may be issued in one or more series, with such rights, preferences, privileges, and restrictions as shall be fixed by our Board from time to time. As of December 31, 2016 , no preferred shares had been issued. +NOTE 15 - EARNINGS PER SHARE +Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, stock options, Convertible Notes, and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. +93 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents a reconciliation of the weighted-average diluted shares outstanding: +Year Ended December 31, +2016 +2015 +2014 +(in thousands) +Weighted-average common shares outstanding - basic +49,052 +39,153 +35,784 +Dilutive effect of: +Restricted stock +— +— +279 +Convertible notes +— +— +564 +Other equity-based awards +— +— +51 +Weighted-average common shares and equivalents outstanding - diluted +49,052 +39,153 +36,678 +For 2016 and 2015, we reported a net loss. As a result, our basic and diluted weighted-average common shares outstanding were the same because the effect of the common share equivalents was anti-dilutive. +The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect: +Year Ended December 31, +2016 +2015 +2014 +(in thousands) +Weighted-average common share equivalents excluded from diluted earnings +per share due to their anti-dilutive effect: +Restricted stock +689 +831 +8 +Convertible notes +292 +562 +— +Other equity-based awards +109 +101 +26 +Total anti-dilutive common share equivalents +1,090 +1,494 +34 +In September 2016 , we issued the 2021 Convertible Notes, which give the holders the right to convert the aggregate principal amount into 2.3 million shares of our common stock at a conversion price of $85.39 per share. The 2021 Convertible Notes would be included in the diluted earnings per share calculation using the treasury stock method if the average market share price exceeds the $85.39 conversion price during the periods presented. +In November 2010, we issued the 2016 Convertible Notes, which give the holders the right to convert the aggregate principal amount into 2.7 million shares of our common stock at a conversion price of $42.40 per share. The 2016 Convertible Notes matured and were redeemed in May 2016, as described more fully in the footnote titled Long Term Debt. Prior to maturity, the 2016 Convertible Notes were included in the diluted earnings per share calculation using the treasury stock method if the average market share price exceeded the $42.40 conversion price during the period presented. Shares issuable upon conversion of the Convertible Notes were excluded from the diluted earnings per share calculation for the year ended December 31, 2015 as the effect would have been anti-dilutive to our earnings per share. Shares issuable upon conversion of the 2016 Convertible Notes were included in the diluted earnings per share calculation for the year ended December 31, 2014 as the average market price during the period exceeded the conversion price. +NOTE 16 - DIVESTITURE AND DISCONTINUED OPERATIONS +In October 2014 , we completed the sale of our entire 50 percent ownership interest in PDCM to an unrelated third-party for aggregate consideration, after our share of PDCM's debt repayment and other working capital adjustments, of approximately $192 million , comprised of approximately $153 million in net cash proceeds and a promissory note due in 2020 of approximately $39 million . The transaction included the buyer's assumption of our share of the firm transportation commitment related to the assets owned by PDCM, as well as our share of PDCM's natural gas hedging positions for the years 2014 through 2017. The divestiture resulted in a pre-tax gain of $76.3 million . As the divestiture represented a strategic shift that had a major effect on our operations as our organization structure no longer has joint venture partners and we no longer have dry gas assets, our proportionate share of PDCM's Marcellus Shale results of operations have been separately reported as discontinued operations in the consolidated statements of operations for the year ended December 31, 2014. +94 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The tables below set forth selected financial information related to net assets divested and operating results related to discontinued operations. The following table presents consolidated statements of operations data related to our discontinued operations: +Consolidated statements of operations - discontinued operations +Year Ended December 31, 2014 +(in thousands) +Revenues +Crude oil, natural gas and NGLs sales +$ +24,149 +Commodity price risk management loss, net +(1,085 +) +Other income +48 +Total revenues +23,112 +Costs, expenses and other +Lease operating expenses +1,280 +Production taxes +1,579 +Transportation, gathering and processing expenses +3,536 +Impairment of properties and equipment +433 +Depreciation, depletion and amortization +9,128 +Other +4,170 +Gain on sale of properties and equipment +(76,479 +) +Total costs, expenses and other +(56,353 +) +Interest expense +(2,222 +) +Interest income +194 +Income from discontinued operations +77,437 +Provision for income taxes +(29,263 +) +Income from discontinued operations, net of tax +$ +48,174 +The following table presents supplemental cash flows information related to our 50 percent ownership interest in PDCM, which is classified as discontinued operations: +Supplemental cash flows information - discontinued operations +Year Ended December 31, 2014 +(in thousands) +Cash flows from investing activities: +Capital expenditures +$ +(17,253 +) +Significant non-cash investing items: +Change in accounts payable related to purchases of properties and equipment +(5,727 +) +NOTE 17 - TRANSACTIONS WITH AFFILIATES +PDCM. In 2014, o ur Gas Marketing segment marketed the natural gas produced by PDCM. Our cost of gas marketing includes $23.2 million in 2014 related to the marketing of this gas. +NOTE 18 - BUSINESS SEGMENTS +We separate our operating activities into two segments: Oil and Gas Exploration and Production and Gas Marketing. All material inter-company accounts and transactions between segments have been eliminated. +Oil and Gas Exploration and Production. Our Oil and Gas Exploration and Production segment includes all of our crude oil and natural gas properties. The segment represents revenues and expenses from the production and sale of crude oil, natural gas, and NGLs. Segment revenue includes crude oil, natural gas, and NGLs sales, commodity price risk management, net, and other income. Segment income (loss) consists of segment revenue less production cost, exploration expense, impairment of properties and equipment, direct general and administrative expense, and DD&A expense. Segment DD&A expense was $413.1 million , $298.8 million , and $188.5 million in 2016 , 2015 , and 2014 , respectively. +95 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Gas Marketing. Our Gas Marketing segment purchases, aggregates, and resells natural gas. Segment income (loss) primarily represents sales from gas marketing and direct interest income less costs of gas marketing, transportation and direct general and administrative expense. +Unallocated amounts. Unallocated income includes unallocated other revenue, less corporate general administrative expense, corporate DD&A expense, interest income, and interest expense. Unallocated assets include assets utilized for corporate, general and administrative purposes, as well as assets not specifically included in our two business segments. +The following tables present our segment information: +2016 +2015 +— +2014 +(in thousands) +Year Ended December 31, +Segment revenues: +Oil and gas exploration and production +$ +374,190 +$ +584,406 +$ +784,636 +Gas marketing +8,725 +10,920 +71,571 +Total revenues +$ +382,915 +$ +595,326 +$ +856,207 +Segment income (loss) before income taxes: +Oil and gas exploration and production +$ +(170,370 +) +$ +31,429 +$ +344,149 +Gas marketing +(1,468 +) +(797 +) +(445 +) +Unallocated +(221,285 +) +(137,220 +) +(166,476 +) +Income (loss) before income taxes +$ +(393,123 +) +$ +(106,588 +) +$ +177,228 +Expenditures for segment long-lived assets: +Oil and gas exploration and production +$ +436,884 +$ +599,617 +$ +623,912 +Acquisition of crude oil and natural gas properties, net of cash acquired +1,073,723 +— +— +Unallocated +3,464 +5,051 +4,680 +Total +$ +1,514,071 +$ +604,668 +$ +628,592 +As of December 31, +Segment assets: +Oil and gas exploration and production +$ +4,451,510 +$ +2,294,288 +Gas marketing +4,329 +4,217 +Unallocated +30,003 +72,038 +Total assets +$ +4,485,842 +$ +2,370,543 +96 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +SUPPLEMENTAL INFORMATION - UNAUDITED +CRUDE OIL AND NATURAL GAS INFORMATION - UNAUDITED +Net Proved Reserves +All of our crude oil, natural gas, and NGLs reserves are located in the U.S. We utilize the services of independent petroleum engineers to estimate our crude oil, natural gas, and NGL reserves. As of December 31, 2016 , 2015 , and 2014 , all of our estimates of proved reserves for the Wattenberg Field and the Utica Shale were based on reserve reports prepared by Ryder Scott and beginning in 2016, NSAI prepared the reserve reports for the Delaware Basin. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC. +Proved reserves are those quantities of crude oil, natural gas, and NGLs which can be estimated with reasonable certainty to be economically producible under existing economic conditions and operating methods. Proved developed reserves are the proved reserves that can be produced through existing wells with existing equipment and infrastructure and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for development. All of our proved undeveloped reserves conform to the SEC five-year rule requirement to be drilled within five years of each location’s initial booking date. +The indicated index prices for our reserves, by commodity, are presented below. +Average Benchmark Prices +As of December 31, +Crude Oil +(per Bbl) +Natural Gas +(per Mcf) +NGLs +(per Bbl) +2016 +$ +42.75 +$ +2.48 +$ +42.75 +2015 +50.28 +2.59 +50.28 +2014 +94.99 +4.35 +94.99 +The netted back price used to estimate our reserves, by commodity, are presented below. +Price Used to Estimate Reserves* +As of December 31, +Crude Oil +(per Bbl) +Natural Gas +(per Mcf) +NGLs +(per Bbl) +2016 +$ +38.67 +$ +1.85 +$ +11.97 +2015 +42.10 +2.05 +12.23 +2014 +84.65 +3.92 +32.27 +___________ +* +These prices are based on the index prices and are net of basin differentials, any transportation fees, contractual adjustments, and any Btu adjustments we experienced for the respective commodity. +97 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +The following tables present the changes in our estimated quantities of proved reserves: +Crude Oil, Condensate (MBbls) +Natural Gas +(MMcf) +NGLs +(MBbls) +Total +(MBoe) +Proved Reserves: +Proved reserves, January 1, 2014 (1) +93,830 +739,640 +48,671 +265,774 +Revisions of previous estimates +(29,777 +) +(149,064 +) +(10,204 +) +(64,825 +) +Extensions, discoveries and other additions, including infill reserves in an existing proved field +40,792 +202,957 +23,411 +98,029 +Acquisition of reserves +5 +43 +5 +17 +Dispositions +(13 +) +(237,306 +) +(8 +) +(39,572 +) +Production +(4,322 +) +(19,298 +) +(1,756 +) +(9,294 +) +Proved reserves, December 31, 2014 +100,515 +536,972 +60,119 +250,129 +Revisions of previous estimates +(43,268 +) +(154,775 +) +(24,407 +) +(93,471 +) +Extensions, discoveries and other additions, including infill reserves in an existing proved field +48,707 +311,709 +30,835 +131,494 +Acquisition of reserves +17 +215 +23 +76 +Dispositions +(12 +) +(82 +) +(8 +) +(34 +) +Production +(6,984 +) +(33,302 +) +(2,835 +) +(15,369 +) +Proved reserves, December 31, 2015 +98,975 +660,737 +63,727 +272,825 +Revisions of previous estimates +(22,097 +) +(80,426 +) +(7,130 +) +(42,631 +) +Extensions, discoveries and other additions +494 +4,094 +355 +1,531 +Acquisition of reserves +50,126 +305,224 +32,586 +133,583 +Dispositions +(601 +) +(4,202 +) +(424 +) +(1,725 +) +Production +(8,728 +) +(51,730 +) +(4,826 +) +(22,176 +) +Proved reserves, December 31, 2016 +118,169 +833,697 +84,288 +341,407 +Proved Developed Reserves, as of: +December 31, 2014 +26,798 +186,633 +17,002 +74,905 +December 31, 2015 +26,257 +175,367 +15,011 +70,496 +December 31, 2016 +30,013 +264,452 +24,196 +98,284 +Proved Undeveloped Reserves, as of: +December 31, 2014 +73,717 +350,339 +43,117 +175,224 +December 31, 2015 +72,718 +485,370 +48,716 +202,329 +December 31, 2016 +88,156 +569,245 +60,092 +243,122 +2016 Activity. During 2016, we increased proved reserves by 25 percent or 68.6 MMBoe, relative to December 31, 2015. This proved reserve increase was primarily a result of the development of longer lateral length well bores in the Wattenberg Field, which was driven by technology advancements, together with the ability to consolidate our leasehold position to drill longer length laterals with increased working interests. We also acquired proved developed reserves and undeveloped reserves in the Delaware Basin. +Extensions, discoveries and other additions for 2016 of 1.5 MMBoe includes the addition of five wells in the Utica Shale. +Acquisitions of reserves of 133.6 MMBoe includes proved developed producing properties and proved undeveloped (“PUD”) locations acquired in our Delaware Basin acquisitions, and new proved locations obtained from an acreage exchange transaction. Because of the preferential economics of the more concentrated acreage in the Wattenberg Field, we rescheduled the timing of anticipated development in the field. This resulted in a downward revision to our proved reserves. The net downward revisions were 42.6 MMBoe. The revision was most notably attributed to a 61.0 MMBoe decrease in reserves due to 2015 PUD locations being removed from our five year development plan and being replaced by PUD locations reflected in purchases of reserves. Infill reserve additions of 16.8 MMBoe in the Wattenberg Field were included as a positive revision of previous estimates. Infill reserve additions for years prior to 2016 for the Wattenberg Field were reported in extensions, discoveries and other additions, including infill reserves in an existing proved field. Revisions also include a 0.5 MMBoe decrease on production due to pricing. The remaining 2.1 MMBoe in positive revisions of previous estimates includes performance revisions and other items. +We had minimal dispositions of 1.7 MMBoe related to acreage traded in the acreage exchange. +98 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +At December 31, 2015, we projected a PUD reserve conversion rate of 19 percent for 2016. As a result of revisions to our drilling plan during the last two months of 2016, our actual reserve conversion rate was 16 percent, resulting in 32.2 MMBoe of reserves recorded as PUDs at December 31, 2015, being converted to proved developed reserves as of December 31, 2016. +Based on economic conditions on December 31, 2016, our approved development plan provides for the development of our remaining PUD locations within five years of the date such reserves were initially recorded. As of December 31, 2016, our 2017 PUD reserve conversion rate is expected to be approximately 26 percent. The balance of the PUD reserves are scheduled to be developed over the remaining four years in accordance with our current development plan. The level of capital spending necessary to achieve this drilling schedule is consistent with our recent performance and our outlook for future development activities. +2015 Activity. Overall, our proved reserves increased by 23 MMBoe as of December 31, 2015 as compared to December 31, 2014. In 2015, we produced 15.4 million MMBoe. At December 31, 2014, we projected a PUD conversion rate of 16 percent for 2015. Our actual conversion rate was 17 percent, resulting in 29 MMBoe of reserves booked as PUDs at December 31, 2014 being converted to proved developed reserves during 2015. As shown, we acquired and divested minimal volumes of proved reserves in 2015. +Extensions, discoveries, and other additions, including infill reserves, of approximately 131 MMBoe in 2015 were all added in the Wattenberg Field and primarily related to horizontal Niobrara projects being added to our development plan. The reserve additions associated with these projects are largely the result of data generated from our downspacing testing. This led to increased well density of our PUD locations year-over-year and extended the field by enabling us to book more reserves per section in the Niobrara. In general, at December 31, 2014, Niobrara PUD locations were booked at an equivalent of eight wells per section and at December 31, 2015, such locations were booked at an equivalent of 16 wells per section. Additionally, due to more efficient drilling leading to shorter spud-to-spud times, we have increased the number of wells drilled per drilling rig utilized during the course of the year. We have 791 gross PUD horizontal drilling locations at December 31, 2015, which is an increase from 774 locations at December 31, 2014. Approximately 9 MMBoe of the extensions, discoveries, and other additions to our developed reserves related to wells drilled that were not related to reserves booked as of prior year-end. +We recorded net downward revisions of previous estimates of proved reserves of approximately 93 MMBoe. The revision was a result of multiple factors, most notably a decrease of approximately 56 MMBoe for adjustments to our development plans in the Wattenberg Field resulting from the booking of further-downspaced PUD locations. This downspacing delayed the expected development date for many existing PUD locations beyond the limits of the SEC five-year rule. Also, contributing to the downward revision was a decrease of approximately 33 MMBoe due to the significant decrease in SEC commodity prices utilized in the December 31, 2015 reserve report, including approximately 11 MMBoe specifically related to the removal of vertical re-fracs and re-completions from the proved developed reserves which no longer fall within our economic parameters. There was an additional negative revision of approximately 22 MMBoe primarily related to geology findings and leasehold factors. Partially offsetting these decreases was an upward revision approximately 18 MMBoe related to well performance and forecast adjustments. +Based on the economic conditions on December 31, 2015, our approved development plan provides for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. The continued success of our increased well density tests in the Wattenberg Field in 2015 allowed for the additional increased well density of PUD locations as of December 31, 2015. Because we expect to continue to drill primarily proved Wattenberg Field locations in 2016 and as a result of additional newly-booked downspaced PUDs at December 31, 2015, our 2016 PUD conversion rate is expected to be approximately 19 percent. The balance of the locations are scheduled to be drilled over the remaining four years in accordance with our current development plan. The level of capital spending necessary to achieve this drilling schedule is consistent with our recent performance and our outlook for future development activities. +2014 Activity. Overall, our proved reserves decreased by 16 MMBoe as of December 31, 2014 as compared to December 31, 2013. In 2014, we produced 9.3 MMBoe. At December 31, 2013, we projected a PUD conversion rate of seven percent for 2014. Our actual conversion rate was seven percent, resulting in 13 MMBoe of reserves booked as PUDs at December 31, 2013 being converted to proved developed reserves during 2014. As shown, we acquired minimal proved reserves in 2014. We divested a total of 40 MMBoe in 2014, primarily from the sale of our Marcellus Shale assets. +Extensions, discoveries and other additions, including infill reserves, resulted in an increase of approximately 98 MMBoe in 2014, substantially all of which was added in the Wattenberg Field and primarily related to Niobrara and Codell projects. These reserve increases are primarily due to adding 78 MMBoe from new proved undeveloped reserves as a result of adjustments in well spacing, which extended the field by enabling us to book more reserves per section in the Niobrara and Codell formations. In addition, approximately 16 MMBoe of previously unbooked locations were developed in the current year and 2 MMBoe due to various other factors. Approximately 2 MMBoe was added in the Utica Shale. +We recorded a downward revision of our previous estimate of proved reserves of approximately 65 MMBoe. The revision was primarily related to decreases of approximately 55 MMBoe for adjustments to our development plans in the Wattenberg Field to focus on a more balanced commodity production mix and increased well density which delayed the expected development date for many existing PUD locations beyond the limits of the SEC five-year rule. In addition, 8 MMBoe of Utica Shale PUDs are no longer in our drilling plans as we directed more capital to higher-return projects in the Wattenberg Field and 2 MMBoe that were due to various other factors. +99 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Based on the economic conditions on December 31, 2014, our approved development plan provided for the development of our remaining PUD reserves within five years of the date such reserves were initially recorded. Our 2014 drilling program focused on testing increased well density in the Wattenberg Field. +Results of Operations for Crude Oil and Natural Gas Producing Activities +The results of operations for crude oil and natural gas producing activities are presented below. The results include activities related to both continuing and discontinued operations and exclude activities related to gas marketing and other income. +Year Ended December 31, +2016 +2015 +2014 +(in thousands) +Revenue: +Crude oil, natural gas and NGLs sales +$ +497,353 +$ +378,713 +$ +495,562 +Commodity price risk management gain (loss), net +(125,681 +) +203,183 +309,219 +371,672 +581,896 +804,781 +Expenses: +Lease operating expenses +59,950 +56,992 +43,682 +Production taxes +31,410 +18,443 +27,194 +Transportation, gathering and processing expenses +18,415 +10,151 +8,128 +Exploration expense +4,669 +1,102 +948 +Impairment of properties and equipment +9,973 +161,620 +167,280 +Depreciation, depletion, and amortization +413,105 +298,760 +201,656 +Accretion of asset retirement obligations +7,080 +6,293 +3,455 +Loss on sale of properties and equipment +(43 +) +(385 +) +(75,972 +) +544,559 +552,976 +376,371 +Results of operations for crude oil and natural gas producing +activities before provision for income taxes +(172,887 +) +28,920 +428,410 +Provision for income taxes +64,733 +(10,394 +) +(166,930 +) +Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs +$ +(108,154 +) +$ +18,526 +$ +261,480 +Production costs include those costs incurred to operate and maintain productive wells and related equipment, including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, production and severance taxes, and associated administrative expenses. DD&A expense includes those costs associated with capitalized acquisition, exploration, and development costs, but does not include the depreciation applicable to support equipment. The provision for income taxes is computed using effective tax rates. +100 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Costs Incurred in Crude Oil and Natural Gas Property Acquisition, Exploration, and Development Activities +Costs incurred in crude oil and natural gas property acquisition, exploration, and development are presented below. +Year Ended December 31, +2016 +2015 +2014 +(in thousands) +Acquisition of properties: (1) +Proved properties (2) +$ +268,567 +$ +3,561 +$ +11,973 +Unproved properties +1,843,985 +15 +45,999 +Development costs (3) +383,336 +552,104 +608,176 +Exploration costs: (4) +Exploratory drilling +— +— +— +Geological and geophysical +4,669 +— +1 +Total costs incurred +$ +2,500,557 +$ +555,680 +$ +666,149 +__________ +(1) +Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property. +(2) +Includes approximately $40.9 million of infrastructure and pipeline costs in 2016. +(3) +Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells, and provide facilities to extract, treat, gather, and store crude oil, natural gas, and NGLs. Of these costs incurred for the years ended December 31, 2016 , 2015 , and 2014 , $204.6 million , $207.8 million , and $125.2 million , respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. +(4) +Exploration costs - represents costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas, and NGLs. +Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities +Aggregate capitalized costs related to crude oil and natural gas exploration and production activities with applicable accumulated DD&A are presented below: +As of December 31, +2016 +2015 +(in thousands) +Proved crude oil and natural gas properties +$ +3,499,718 +$ +2,881,189 +Unproved crude oil and natural gas properties +1,874,671 +60,498 +Uncompleted wells, equipment and facilities +150,424 +109,385 +Capitalized costs +5,524,813 +3,051,072 +Less accumulated DD&A +(1,534,678 +) +(1,131,705 +) +Capitalized costs, net +$ +3,990,135 +$ +1,919,367 +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves +The standardized measure below has been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to our year-end estimated proved reserves. Prices for each of the three years were adjusted by field for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of our commodity derivatives. Production and development costs were based on prices as of December 31 for each of the respective years presented. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service or to depreciation, depletion, and amortization expense. Production and development costs include those cash flows associated with the expected ultimate settlement of our asset retirement obligations. Future estimated income tax expense is computed by applying the statutory rate in effect at the end of each year to the projected future pre-tax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits, and allowances related to the properties. +The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for crude oil, natural gas, and NGLs, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves. +101 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +As of December 31, +2016 +2015 +2014 +(in thousands) +Future estimated cash flows +$ +7,122,525 +$ +6,297,298 +$ +12,550,515 +Future estimated production costs* +(1,624,167 +) +(1,493,040 +) +(2,746,811 +) +Future estimated development costs +(2,219,914 +) +(2,036,685 +) +(2,528,755 +) +Future estimated income tax expense +(597,476 +) +(508,332 +) +(2,336,510 +) +Future net cash flows +2,680,968 +2,259,241 +4,938,439 +10% annual discount for estimated timing of cash flows +(1,260,339 +) +(1,162,377 +) +(2,631,974 +) +Standardized measure of discounted future estimated net cash flows +$ +1,420,629 +$ +1,096,864 +$ +2,306,465 +___________ +* +Represents future estimated lease operating expenses, production taxes, transportation, gathering and processing expenses. +The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows: +Year Ended December 31, +2016 +2015 +2014 +(in thousands) +Beginning of period +$ +1,096,864 +$ +2,306,465 +$ +1,782,163 +Sales of crude oil, natural gas and NGLs production, net of production costs +(387,576 +) +(293,127 +) +(387,789 +) +Net changes in prices and production costs (1) +(205,760 +) +(1,752,921 +) +129,213 +Extensions, discoveries, and improved recovery, less related costs +15,128 +489,178 +1,444,581 +Sales of reserves +(3,745 +) +(463 +) +(402,595 +) +Purchases of reserves +487,636 +374 +238 +Development costs incurred during the period +268,672 +368,840 +161,404 +Revisions of previous quantity estimates +(320,286 +) +(1,286,462 +) +(654,318 +) +Changes in estimated income taxes +(13,630 +) +902,994 +(221,874 +) +Net changes in future development costs +391,145 +112,958 +46,499 +Accretion of discount +133,747 +345,007 +270,389 +Timing and other +(41,566 +) +(95,979 +) +138,554 +End of period +$ +1,420,629 +$ +1,096,864 +$ +2,306,465 +__________ +(1) +Our weighted-average price, net of production costs per Boe, in our 2016 reserve report decreased to $15.73 as compared to $17.30 for 2015 and $37.78 for 2014. +The data presented should not be viewed as representing the expected cash flows from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the recent average prices and current costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein. +102 +PDC ENERGY, INC. +QUARTERLY FINANCIAL INFORMATION - UNAUDITED +Quarterly financial data for the years ended December 31, 2016 and 2015 is presented below. The quarterly consolidated statements of operations below reflect our revised presentation. The sum of the quarters may not equal the total of the year's net income or loss per share due to changes in the weighted-average shares outstanding throughout the year. +2016 +Quarter Ended +March 31 +June 30 +September 30 +December 31 +(in thousands, except per share data) +Total revenues +$ +90,831 +$ +20,097 +$ +163,890 +$ +108,097 +Total cost, expenses and other +193,864 +163,379 +179,178 +178,608 +Loss from operations +(103,033 +) +(143,282 +) +(15,288 +) +(70,511 +) +Loss before income taxes +(113,369 +) +(153,777 +) +(35,341 +) +(90,636 +) +Net loss +$ +(71,530 +) +$ +(95,450 +) +$ +(23,309 +) +$ +(55,639 +) +Earnings per share: +Basic +$ +(1.72 +) +$ +(2.04 +) +$ +(0.48 +) +$ +(0.94 +) +Diluted +(1.72 +) +(2.04 +) +(0.48 +) +(0.94 +) +2015 +Quarter Ended +March 31 +June 30 +September 30 +December 31 +(in thousands, except per share data) +Total revenues +$ +144,632 +$ +50,960 +$ +231,100 +$ +168,634 +Total costs, expenses and other +106,235 +117,514 +283,047 +152,354 +Income (loss) from operations +38,397 +(66,554 +) +(51,947 +) +16,280 +Income (loss) before income taxes +27,785 +(76,986 +) +(62,661 +) +5,274 +Net income (loss) +$ +17,062 +$ +(46,870 +) +$ +(41,494 +) +$ +3,022 +Earnings per share: +Basic +$ +0.47 +$ +(1.17 +) +$ +(1.04 +) +$ +0.08 +Diluted +0.46 +(1.17 +) +(1.04 +) +0.07 +103 +PDC ENERGY, INC. +FINANCIAL STATEMENT SCHEDULE +Schedule II -VALUATION AND QUALIFYING ACCOUNTS +Description +Beginning +Balance +January 1 +Charged to +Costs and +Expenses +Deductions (1) +Ending +Balance +December 31 +(in thousands) +2016: +Allowance for uncollectible notes +$ +— +$ +44,038 +$ +— +$ +44,038 +Allowance for doubtful accounts +2,009 +1,309 +1,128 +2,190 +Allowance for expirations of unproved crude oil and natural gas properties +144 +215 +— +359 +2015: +Allowance for doubtful accounts +486 +1,700 +177 +2,009 +Allowance for expirations of unproved crude oil and natural gas properties +9,293 +7,012 +16,161 +144 +2014: +Allowance for doubtful accounts +896 +78 +488 +486 +Allowance for expirations of unproved crude oil and natural gas properties +5,142 +4,465 +314 +9,293 +___ ____________ +(1) +For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For allowance for expirations of unproved crude oil and natural gas properties, deductions represent accumulated amortization of expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset. +104 +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +As of December 31, 2016 , we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). Based on the results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2016 . +Management's Report on Internal Control over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate. +In conducting our evaluation of the effectiveness of our internal control over financial reporting, we excluded the internal control over financial reporting and associated activities of the Delaware Basin acquisitions that were accounted for as a business combination, which were consolidated into our financial statements on December 6, 2016, due to the size of the acquisition and integration into our internal control structure which was in process as of December 31, 2016. These properties constituted 11 percent of total assets and one percent of total revenue of the consolidated financial statement amounts as of and for the year ended December 31, 2016. Such exclusion was in accordance with the SEC guidance that an assessment of a recently acquired business may be omitted in management’s report on internal controls over financial reporting, providing the acquisition took place within twelve months of management’s evaluation. +Management has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2016 , based upon the criteria established in "Internal Control – Integrated Framework (2013)" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2016 . +The effectiveness of the Company's internal control over financial reporting as of December 31, 2016 , has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. +Changes in Internal Control over Financial Reporting +During the fourth quarter of 2016 , we made no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. +ITEM 9B. OTHER INFORMATION +None. +105 +PART III +ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2017 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 11. EXECUTIVE COMPENSATION +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2017 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2017 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2017 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2017 Annual Stockholders' meeting and is incorporated by reference in this report. +PART IV +ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES +(a) +(1) +Exhibits: +See Exhibits Index on the following page. +106 +ITEM 16. FORM 10-K SUMMARY +None. +Exhibits Index +Incorporated by Reference +Exhibit Number +Exhibit Description +Form +SEC File Number +Exhibit +Filing Date +Filed Herewith +2.1 +Plan of Conversion, dated June 5, 2015, by PDC Energy, Inc. (the "Company"). +8-K12B +001-37419 +2.1 +6/8/2015 +2.2 +Stock Purchase and Sale Agreement, dated August 23, 2016, by and among the seller parties thereto, Kimmeridge Energy Management Company GP, LLC, Arris Petroleum Corporation, and PDC Energy, Inc. +8-K +001-37419 +2.1 +8/24/2016 +2.3 +Asset Purchase and Sale Agreement, dated August 23, 2016, by and among 299 Resources, LLC, 299 Production, LLC, 299 Pipeline, LLC, Kimmeridge Energy Management Company GP, LLC and PDC Energy, Inc. +8-K +001-37419 +2.2 +8/24/2016 +3.1 +Certificate of Incorporation of the Company. +8-K12B +001-37419 +3.1 +6/8/2015 +3.2 +By-laws of the Company. +8-K12B +001-37419 +3.2 +6/8/2015 +4.1 +Form of Common Stock Certificate of the Company. +X +4.2 +Indenture, dated as of October 3, 2012, by and between the Company and U.S. Bank Trust National Association, as Trustee, including the form of 7.75% Senior Notes due 2022. +8-K +000-07246 +4.1 +10/3/2012 +4.3 +Base Indenture, dated as of September 14, 2016, by and between the Company and U.S. Bank Trust National Association, as Trustee. +8-K +001-37419 +4.1 +9/14/2016 +4.4 +First Supplemental Indenture, dated as of September 14, 2016, by and between the Company and U.S. Bank Trust National Association, as Trustee, relating to the 1.125% Convertible Senior Notes due 2021. +8-K +001-37419 +4.2 +9/14/2016 +4.5 +Indenture, dated as of September 15, 2016, by and between PDC Energy, Inc. and U.S. Bank Trust National Association, as Trustee, relating to the 6.125% Senior Notes due 2024. +8-K +001-37419 +4.1 +9/15/2016 +10.1* +Form of Indemnification Agreement. +8-K +000-07246 +10.1 +6/8/2015 +10.2* +401(k) and Profit Sharing Plan, as amended on January 4, 2016. +X +10.3* +Amended and Restated Non-Employee Director Deferred Compensation Plan. +10-K +000-07246 +10.3 +2/21/2014 +10.4* +2004 Long-Term Equity Compensation Plan amended and restated as of March 8, 2008 ("2004 Plan"). +10-K +000-07246 +10.26 +2/27/2009 +10.4.1* +Summary of 2010 Stock Appreciation Rights and Restricted Stock Awards under the 2004 Plan. +8-K +000-07246 +4/23/2010 +10.5* +Amended and Restated 2010 Long-Term Equity Compensation Plan, as amended. +10-K +001-37419 +10.5 +2/22/2016 +10.6* +Executive Severance Compensation Plan, as amended. +10-K +001-37419 +10.6 +2/22/2016 +10.7* +Form of 2011 Restricted Stock/Stock Appreciation Rights Agreement. +10-K +000-07246 +10.5.2 +2/21/2014 +10.7.1* +Form of 2013 Performance Share Agreement. +10-K +000-07246 +10.9 +2/27/2013 +10.7.2* +Form of 2013 Restricted Stock/Stock Appreciation Rights Agreement. +10-K +000-07246 +10.10 +2/27/2013 +10.7.3* +Form of 2014 Performance Share Agreement. +10-K +000-07246 +10.5.4 +2/19/2015 +107 +Incorporated by Reference +Exhibit Number +Exhibit Description +Form +SEC File Number +Exhibit +Filing Date +Filed Herewith +10.7.4* +Form of 2014 Restricted Stock/Stock Appreciation Rights Agreement. +10-K +000-07246 +10.5.5 +2/19/2015 +10.7.5* +Form of 2015 Performance Share Agreement. +10-K +000-07246 +10.5.6 +2/19/2015 +10.7.6* +Form of 2015 Restricted Stock Unit Agreement. +10-K +000-07246 +10.5.7 +2/19/2015 +10.7.7* +Form of 2015 Stock Appreciation Rights Agreement. +10-K +000-07246 +10.5.8 +2/19/2015 +10.7.8* +Form of 2016 Performance Share Agreement. +10-K +001-37419 +10.7.8 +2/22/2016 +10.8* +Employment Agreement with Gysle R. Shellum, Chief Financial Officer, dated as of April 19, 2010. +8-K +000-07246 +10.2 +4/23/2010 +10.9* +Employment Agreement with Daniel W. Amidon, General Counsel and Corporate Secretary, dated as of April 19, 2010. +8-K +000-07246 +10.3 +4/23/2010 +10.10* +Employment Agreement with Lance A. Lauck, Senior Vice President of Business Development, dated as of April 19, 2010. +8-K +000-07246 +10.4 +4/23/2010 +10.11 +Third Amended and Restated Credit Agreement dated as of May 21, 2013, among PDC Energy, Inc. as Borrower, Riley Natural Gas Company, a Subsidiary of PDC Energy, Inc., as Guarantor, JP Morgan Chase Bank, N.A. as Administrative Agent, J.P. Morgan Securities LLC as Sole Bookrunner and Co-Lead Arranger, Wells Fargo Bank, N.A. as Syndication Agent, and Wells Fargo Securities, LLC as Co-Lead Arranger, and Certain Lenders. +8-K +000-07246 +10.1 +5/28/2013 +10.11.1 +First and Second Amendments to Third Amended and Restated Credit Agreement dated as of May 14, 2014 and September 30, 2015, respectively, among PDC Energy, Inc. as the Borrower, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders. +10-K +001-37419 +10.11.1 +2/22/2016 +10.11.2 +Third Amendment to the Third Amended and Restated Credit Agreement, dated as of September 6, 2016, among the Company, as Borrower, certain Subsidiaries of the Company, as Guarantors, the lenders from time to time party thereto (the “Lenders”) and JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders. +8-K +001-37419 +10.1 +9/8/2016 +10.11.3 +Fourth Amendment to the Third Amended and Restated Credit Agreement, dated as of October 14, 2016, among the Company, as Borrower, certain Subsidiaries of the Company, as Guarantors, the lenders from time to time party thereto (the “Lenders”) and JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders. +10-Q +001-37419 +99.1 +11/3/2016 +10.12* +Consulting Agreement with James M. Trimble, dated as of June 18, 2014. +10-Q +000-07246 +10.1 +8/8/2014 +10.13* +Retirement Agreement with Gysle R. Shellum, Chief Financial Officer, dated October 26, 2015. +8-K +001-37419 +10.1 +10/27/2015 +10.14* +Change of Control and Severance Plan. +X +10.14.1* +Amendment to the PDC Energy Change of Control and Severance Plan +10.14.1 +2/28/2017 +X +10.15 +Registration Rights Agreement, dated as of September 15, 2016, by and between PDC Energy, Inc. and J.P. Morgan Securities LLC, as representative of the initial purchasers, relating to the 6.125% Senior Notes due 2024. +8-K +001-37419 +10.2 +9/5/2016 +10.16 +Investment Agreement, dated December 6, 2016, by and among the Investor parties identified therein and PDC Energy, Inc. (relating to the Stock Purchase and Sale Agreement). +8-K +001-37419 +10.1 +12/7/2016 +10.17 +Investment Agreement, dated December 6, 2016, by and among the Investor parties identified therein and PDC Energy, Inc. (relating to the Asset Purchase and Sale Agreement). +8-K +001-37419 +10.2 +12/7/2016 +12.1 +Computation of Ratio of Earnings to Fixed Charges. +X +21.1 +Subsidiaries. +X +23.1 +Consent of PricewaterhouseCoopers LLP. +X +23.2 +Consent of Ryder Scott Company, L.P., Petroleum Consultants. +X +108 +Incorporated by Reference +Exhibit Number +Exhibit Description +Form +SEC File Number +Exhibit +Filing Date +Filed Herewith +23.3 +Consent of Netherland, Sewell & Associates, Inc., Petroleum Consultants. +X +31.1 +Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +31.2 +Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +32.1** +Certifications by Chief Executive Officer and Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. +99.1 +Report of Independent Petroleum Consultants - Ryder Scott Company, L.P. +X +99.2 +Report of Independent Petroleum Consultants - Netherland, Sewell & Associates, Inc. +X +101.INS +XBRL Instance Document +X +101.SCH +XBRL Taxonomy Extension Schema Document +X +101.CAL +XBRL Taxonomy Extension Calculation Linkbase Document +X +101.DEF +XBRL Taxonomy Extension Definition Linkbase Document +X +101.LAB +XBRL Taxonomy Extension Label Linkbase Document +X +101.PRE +XBRL Taxonomy Extension Presentation Linkbase Document +X +*Management contract or compensatory arrangement. +** Furnished herewith. +109 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +PDC ENERGY, INC. +By: /s/ Barton R. Brookman +Barton R. Brookman +President and Chief Executive Officer +February 28, 2017 +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated: +Signature +Title +Date +/s/ Barton R. Brookman +President, Chief Executive Officer and Director +February 28, 2017 +Barton R. Brookman +(principal executive officer) +/s/ David W. Honeyfield +Senior Vice President and Chief Financial Officer +February 28, 2017 +David W. Honeyfield +(principal financial officer) +/s/ R. Scott Meyers +Chief Accounting Officer +February 28, 2017 +R. Scott Meyers +(principal accounting officer) +/s/ Jeffrey C. Swoveland +Chairman and Director +February 28, 2017 +Jeffrey C. Swoveland +/s/ Joseph E. Casabona +Director +February 28, 2017 +Joseph E. Casabona +/s/ Anthony J. Crisafio +Director +February 28, 2017 +Anthony J. Crisafio +/s/ Larry F. Mazza +Director +February 28, 2017 +Larry F. Mazza +/s/ David C. Parke +Director +February 28, 2017 +David C. Parke +/s/ Kimberly Luff Wakim +Director +February 28, 2017 +Kimberly Luff Wakim +110 +GLOSSARY OF UNITS OF MEASUREMENT AND INDUSTRY TERMS +UNITS OF MEASUREMENT +The following presents a list of units of measurement used throughout the document. +Bbl – One barrel of crude oil or NGL or 42 gallons of liquid volume. +Bcf – One billion cubic feet of natural gas volume. +Boe – One barrel of crude oil equivalent. +Btu – British thermal unit. +BBtu – One billion British thermal units. +MBoe – One thousand barrels of crude oil equivalent. +MBbls – One thousand barrels of crude oil. +Mcf – One thousand cubic feet of natural gas volume. +MMBoe – One million barrels of crude oil equivalent. +MMBbls – One million barrels of crude oil. +MMBtu – One million British thermal units. +MMcf – One million cubic feet of natural gas volume. +GLOSSARY OF INDUSTRY TERMS +The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report: +CIG - Colorado Interstate Gas. +Completion - Refers to the installation of permanent equipment for the production of crude oil and natural gas from a recently drilled well or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned. +Developed acreage - Acreage assignable to productive wells. +Development well - A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. +Differentials - The difference between the crude oil and natural gas index spot price and the corresponding cash spot price in a specified location. +Dry gas or dry natural gas - Natural gas is considered dry when its composition is over 90 percent pure methane. +Dry well or dry hole - A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well. +Exploratory well - A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. +Extensions and discoveries - As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates. +Farm-out - Transfer of all or part of the operating rights from a working interest owner to an assignee, who assumes all or some of the burden of development in return for an interest in the property. The assignor usually retains an overriding royalty interest but may retain any type of interest. +Fracture or Fracturing - Procedure to stimulate production by forcing a mixture of fluid and proppant into the formation under high pressure. Fracturing creates artificial fractures in the reservoir rock to increase permeability and porosity, thereby allowing the release of trapped hydrocarbons. +Gross acres or wells - Refers to the total acres or wells in which we have a working interest. +Horizontal drilling - A drilling technique that permits the operator to drill a horizontal well shaft from the bottom of a vertical well and thereby to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons. +Joint interest billing - Process of billing/invoicing the costs related to well drilling, completions, and production operations among working interest partners. +Natural gas liquid(s) or NGL(s) - Hydrocarbons which can be extracted from natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs include ethane, propane, butane, and other natural gasolines. +111 +Net acres or wells - Refers to gross acres or wells we own multiplied, in each case, by our percentage working interest. References to net acres or wells include our proportionate share of PDCM's and our affiliated partnerships' net acres or wells. +Net production - Crude oil and natural gas production that we own, less royalties and production due to others. +Non-operated - A project in which we are not the operator. +NYMEX - New York Mercantile Exchange. +Operator - The individual or company responsible for the exploration, development and/or production of an oil or gas well or lease. +Overriding royalty - An interest which is created out of the operating or working interest. Its term is coextensive with that of the operating interest. +Possible reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability to exceed the sum of proved, probable, and possible reserves. When probabilistic methods are used, there must be at least a 10 percent probability that the actual quantities recovered will equal or exceed the sum of proved, probable and possible estimates. +Present value of future net revenues or (PV-10) - The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, of proved reserves calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using pricing and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10 percent. PV-10 is pre-tax and therefore a non-U.S. GAAP financial measure. +Probable reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Similarly, when probabilistic methods are used, there must be at least a 50 percent probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. +Productive well - An exploratory or developmental well that is not a dry well or dry hole, as defined above. +Proved developed non-producing reserves - Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and/or (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells. +Proved developed producing reserves or PDPs - Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods. +Proved developed reserves - The combination of proved developed producing and proved developed non-producing reserves. +Proved reserves - This term means "proved oil and gas reserves" as defined in SEC Regulation S-X Section 4-10(a) and refers to those quantities of crude oil and condensate, natural gas, and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +Proved undeveloped reserves or PUDs - Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. +Recomplete or Recompletion - The modification of an existing well for the purpose of producing crude oil and natural gas from a different producing formation. +Reserves - Estimated remaining quantities of crude oil, natural gas, NGLs and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering crude oil, natural gas, and NGLs or related substances to market, and all permits and financing required to implement the project. +Royalty - An interest in a crude oil and natural gas lease or mineral interest that gives the owner of the royalty the right to receive a portion of the production from the leased acreage or mineral interest (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +112 +Section - A square tract of land one mile by one mile, containing 640 acres. +Spud - To begin drilling; the act of beginning a hole. +Standardized measure of discounted future net cash flows or standardized measure - Future net cash flows discounted at a rate of 10 percent. Future net cash flows represent the estimated future revenues to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment and (ii) future income tax expense. +Stratigraphic test well - A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. +TETCO M2 - Texas Eastern Transmission Corporation M-2 receipts. +Undeveloped acreage - Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas, regardless of whether such acreage contains proved reserves. +Waha - Waha West Texas natural gas prices +Wet gas or wet natural gas - Natural gas that contains a larger quantity of hydrocarbon liquids than dry natural gas, such as NGLs, condensate and crude oil. +Working interest - An interest in a crude oil and natural gas lease that gives the owner of the interest the right to drill and produce crude oil and natural gas on the leased acreage. It requires the owner to pay its share of the costs of drilling and production operations. +Workover - Major remedial operations on a producing well to restore, maintain, or improve the well's production. +113 \ No newline at end of file diff --git a/raw/filings/0000077877/2016/0000077877-17-000006/filing_metadata.csv b/raw/filings/0000077877/2016/0000077877-17-000006/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..1588475a84e1d7d67b8d5d0c873e6a9902742e45 --- /dev/null +++ b/raw/filings/0000077877/2016/0000077877-17-000006/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000077877,PDCE,"PDC ENERGY, INC.",10-K,2017-02-28,2016-12-31,2017-02-28T13:41:08.000Z,0000077877-17-000006,pdce-10kxfy16.htm,PDCE ENERGY 2016 FORM 10-K,19286747,1,0,https://www.sec.gov/Archives/edgar/data/77877/000007787717000006/pdce-10kxfy16.htm,https://www.sec.gov/Archives/edgar/data/77877/000007787717000006/,2016,2016,1 diff --git a/raw/filings/0000077877/2016/0000077877-17-000006/item1.txt b/raw/filings/0000077877/2016/0000077877-17-000006/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2016/0000077877-17-000006/item13.txt b/raw/filings/0000077877/2016/0000077877-17-000006/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..0335b635f3755bca5be9066f13701ef17ced13d1 --- /dev/null +++ b/raw/filings/0000077877/2016/0000077877-17-000006/item13.txt @@ -0,0 +1,2 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2017 Annual Stockholders' meeting and is incorporated by reference in this report. \ No newline at end of file diff --git a/raw/filings/0000077877/2016/0000077877-17-000006/item9a.txt b/raw/filings/0000077877/2016/0000077877-17-000006/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..1f5e8babdaea7434131a060dc0eb1427bebbede5 --- /dev/null +++ b/raw/filings/0000077877/2016/0000077877-17-000006/item9a.txt @@ -0,0 +1,10 @@ +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +As of December 31, 2016 , we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). Based on the results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2016 . +Management's Report on Internal Control over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate. +In conducting our evaluation of the effectiveness of our internal control over financial reporting, we excluded the internal control over financial reporting and associated activities of the Delaware Basin acquisitions that were accounted for as a business combination, which were consolidated into our financial statements on December 6, 2016, due to the size of the acquisition and integration into our internal control structure which was in process as of December 31, 2016. These properties constituted 11 percent of total assets and one percent of total revenue of the consolidated financial statement amounts as of and for the year ended December 31, 2016. Such exclusion was in accordance with the SEC guidance that an assessment of a recently acquired business may be omitted in management’s report on internal controls over financial reporting, providing the acquisition took place within twelve months of management’s evaluation. +Management has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2016 , based upon the criteria established in "Internal Control – Integrated Framework (2013)" issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2016 . +The effectiveness of the Company's internal control over financial reporting as of December 31, 2016 , has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein. +Changes in Internal Control over Financial Reporting +During the fourth quarter of 2016 , we made no changes in our internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) that have materially affected or are reasonably likely to materially affect our internal control over financial reporting. \ No newline at end of file diff --git a/raw/filings/0000077877/2016/0000077877-17-000006/rp_note.txt b/raw/filings/0000077877/2016/0000077877-17-000006/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2016/0000077877-17-000006/rpt_disclosure.txt b/raw/filings/0000077877/2016/0000077877-17-000006/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..f83e59e5f9c2d2d7ee1c1f024673f6db0142d165 --- /dev/null +++ b/raw/filings/0000077877/2016/0000077877-17-000006/rpt_disclosure.txt @@ -0,0 +1,16 @@ +TRANSACTIONS WITH RELATED PERSONS +Related Transactions +During 2016, there +was no transaction or series of transactions, nor is there any currently proposed transaction, involving an amount exceeding $120,000 in which the Company is a participant and/or in which any Director, executive officer, known holder of more than +five percent of the Company’s voting securities, or any member of the immediate family of any of the foregoing persons, had or will have a direct or indirect material interest for which disclosure is required under Item 404 of Regulation S-K. +Policies and Procedures With Respect to Transactions with Related Persons +The Board has adopted a written policy for the review, approval and ratification of transactions that involve related parties and potential +conflicts of interest. The related party transaction policy applies to each Director and executive officer of the Company, any nominee for election as a Director, any security holder who is known to own more than five percent of the +Company’s voting securities, any immediate family member of any of the foregoing persons and any corporation, firm or association in which one or more of the Company’s Directors are directors or officers, or have a substantial financial +interest. +Under our related-party transaction policy, a related person transaction is a transaction or arrangement involving a related +person in which the Company is a participant or that would require disclosure in the Company’s filings with the SEC as a transaction with a related person. The related person must disclose to the Audit Committee any potential related +person transactions and must disclose all material facts with respect to such transaction and relationship. All related person transactions so disclosed will be reviewed by the Audit Committee. In determining whether to approve or ratify +a transaction, the Audit Committee will consider the relevant facts and circumstances of the transaction, which may include factors such as the relationship of the related person with the Company, the materiality or significance of the transaction +to the Company and the business purpose and reasonableness of the transaction, whether the transaction is comparable to a transaction that could be available to the Company from an unrelated party and the impact of the transaction on the +Company’s business and operations. \ No newline at end of file diff --git a/raw/filings/0000077877/2017/0000077877-18-000008/filing.txt b/raw/filings/0000077877/2017/0000077877-18-000008/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..d7bd6e54cf17ca42d42436b9484a18a7c0648598 --- /dev/null +++ b/raw/filings/0000077877/2017/0000077877-18-000008/filing.txt @@ -0,0 +1,8415 @@ +10-K +1 +pdce-10kxfy17.htm +10-K +Document +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +T ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2017 +or +£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from __________ to _________ +Commission File Number 001-37419 +PDC ENERGY, INC. +(Exact name of registrant as specified in its charter) +Delaware +95-2636730 +(State of incorporation) +(I.R.S. Employer Identification No.) +1775 Sherman Street, Suite 3000 +Denver, Colorado 80203 +(Address of principal executive offices) (Zip code) +Registrant's telephone number, including area code: (303) 860-5800 +Securities registered pursuant to Section 12(b) of the Act: +Title of each class +Name of each exchange on which registered +Common Stock, par value $0.01 per share +NASDAQ Global Select Market +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes T No £ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes £ No T +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes T No £ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes T No £ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. T +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. +Large accelerated filer x +Accelerated filer o +Non-accelerated filer £ +(Do not check if a smaller reporting company) +Smaller reporting company o +Emerging growth company o +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. £ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes £ No T +The aggregate market value of our common stock held by non-affiliates on June 30, 2017 was $2.8 billion (based on the closing price of $43.11 per share as of the last business day of the fiscal quarter ending June 30, 2017 ). +As of February 15, 2018 , there were 65,965,374 shares of our common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +We hereby incorporate by reference into this document the information required by Part III of this Form, which will appear in our definitive proxy statement to be filed pursuant to Regulation 14A for our 2018 Annual Meeting of Stockholders. +PDC ENERGY, INC. +2017 ANNUAL REPORT ON FORM 10-K +TABLE OF CONTENTS +PART I +Page +Items 1. and 2. +Business and Properties +2 +Item 1A. +Risk Factors +22 +Item 1B. +Unresolved Staff Comments +38 +Item 3. +Legal Proceedings +38 +Item 4. +Mine Safety Disclosures +38 +PART II +Item 5. +Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +39 +Item 6. +Selected Financial Data +41 +Item 7. +Management's Discussion and Analysis of Financial Condition and Results of Operations +42 +Item 7A. +Quantitative and Qualitative Disclosures About Market Risk +66 +Item 8. +Financial Statements and Supplementary Data +70 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +128 +Item 9A. +Controls and Procedures +128 +Item 9B. +Other Information +129 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +130 +Item 11. +Executive Compensation +130 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +130 +Item 13. +Certain Relationships and Related Transactions, and Director Independence +130 +Item 14. +Principal Accounting Fees and Services +130 +PART IV +Item15. +Exhibits, Financial Statement Schedules +130 +Item 16. +Form 10-K Summary +112 +Signatures +134 +Glossary of Units of Measurements and Industry Terms +135 +PART I +REFERENCES TO THE REGISTRANT +Unless the context otherwise requires, references in this report to "PDC," the "Company," "we," "us," "our," or "ours" refer to the registrant, PDC Energy, Inc., our wholly-owned subsidiaries consolidated for the purposes of its financial statements, including our proportionate share of the financial position, results of operations, cash flows and operating activities of our affiliated partnerships. +GLOSSARY OF UNITS OF MEASUREMENTS AND INDUSTRY TERMS +Units of measurements and industry terms are defined in the Glossary of Units of Measurements and Industry Terms, included at the end of this report. +SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS +This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding our business, financial condition, results of operations, and prospects. All statements other than statements of historical facts included in this report are "forward-looking statements" within the meaning of the safe harbor provisions of the United States ("U.S.") Private Securities Litigation Reform Act of 1995. Words such as expect, anticipate, intend, plan, believe, seek, estimate and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements include, among other things, statements regarding future: reserves, production, costs, cash flows and earnings; drilling locations and zones and growth opportunities; capital expenditures and projects, including expected lateral lengths of wells, drill times and number of rigs employed; rates of return; operational enhancements and efficiencies; management of lease expiration issues; financial ratios; our anticipated sale of our Utica Shale assets; certain accounting and tax change impacts; midstream capacity and related curtailments; and the closing of pending, and the nature of future, transactions. +The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this report or accompanying materials, we may use the term “projection” or similar terms or expressions, or indicate that we have “modeled” certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or the industry in periods beyond the current fiscal year. Because such statements relate to events or conditions further in the future, they are subject to increased levels of uncertainty. +Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to: +• +changes in worldwide production volumes and demand, including economic conditions that might impact demand and prices for products we produce; +• +volatility of commodity prices for crude oil, natural gas, and natural gas liquids ("NGLs") and the risk of an extended period of depressed prices; +• +reductions in the borrowing base under our revolving credit facility; +• +impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement related to those laws and regulations, liabilities arising thereunder, and the costs to comply with those laws and regulations; +• +declines in the value of our crude oil, natural gas, and NGLs properties resulting in further impairments; +• +changes in estimates of proved reserves; +• +inaccuracy of estimated reserves and production rates; +• +production decline rates from our wells being greater than expected; +• +timing and extent of our success in discovering, acquiring, developing, and producing reserves; +• +availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production and the impact of these facilities and regional capacity on the prices we receive for our production; +• +timing and receipt of necessary regulatory permits; +• +risks incidental to the drilling and operation of crude oil and natural gas wells; +• +losses from our gas marketing business exceeding our expectations; +1 +• +difficulties in integrating our operations as a result of any significant acquisitions and acreage exchanges; +• +increases or changes in expenses; +• +availability of supplies, materials, contractors, and services that may delay the drilling or completion of our wells; +• +potential losses of acreage or zones due to partial or complete lease expirations or otherwise; +• +increases or adverse changes in construction costs and procurement costs associated with future build out of mid-stream related assets; +• +future cash flows, liquidity, and financial condition; +• +possibility that the sale of the Utica Shale properties will not close as expected; +• +competition within the oil and gas industry; +• +availability and cost of capital; +• +our success in marketing crude oil, natural gas, and NGLs; +• +effect of crude oil and natural gas derivatives activities; +• +impact of environmental events, governmental and other third-party responses to such events, and our ability to insure adequately against such events; +• +cost of pending or future litigation; +• +effect that acquisitions we may pursue have on our capital requirements; +• +our ability to retain or attract senior management and key technical employees; and +• +success of strategic plans, expectations and objectives for our future operations. +Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under Item 1A, Risk Factors , made in this report and our other filings with the U.S. Securities and Exchange Commission ("SEC") for further information on risks and uncertainties that could affect our business, financial condition, results of operations and cash flows. We caution you not to place undue reliance on forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement. +ITEMS 1. AND 2. BUSINESS AND PROPERTIES +The Company +We are a domestic independent exploration and production company that acquires, explores, and develops properties for the production of crude oil, natural gas, and NGLs. Our primary operations are located in the Wattenberg Field in Colorado and the Delaware Basin in Texas. Our operations in the Wattenberg Field are focused on the Niobrara and Codell formations and our Delaware Basin operations are currently focused on the Wolfcamp zones. We also have operations in the Utica Shale in Southeastern Ohio; however, in February 2018, we entered into a definitive purchase and sale agreement ("PSA") for the sale of these properties for net cash proceeds of approximately $40.0 million , subject to certain customary closing adjustments. This transaction is expected to close in the first quarter of 2018. +As of December 31, 2017 , we own an interest in approximately 2,800 gross ( 2,300 net) productive wells, of which approximately 32 percent are horizontal. We operate 87 percent of the wells in which we have an interest. We produced 31.8 MMBoe in 2017, a 44 percent increase compared to 2016 , including 4.2 MMBoe from the Delaware Basin assets that we acquired in December 2016. For the month ended December 31, 2017 , we maintained an average production rate of 97 MBoe per day, representing a 33 percent increase from December 2016. We were able to achieve this strong growth rate while maintaining a robust liquidity position, comprised of cash and cash equivalents and available capacity under our revolving credit facility totaling $880.7 million as of December 31, 2017 . Our leverage ratio as of December 31, 2017 , as defined in our revolving credit facility agreement, was 1.9 to 1.0. As of December 31, 2017 , we had 452.9 MMBoe of proved reserves, 32 percent of which are proved developed reserves. Approximately 58 percent of our reserves at December 31, 2017 are liquids, which includes crude oil and NGLs. Our 452.9 MMBoe of total proved reserves as of December 31, 2017 , represented an increase of 111.5 MMBoe, or 33 percent , relative to December 31, 2016 . The additions to our proved reserves were primarily a result of extending the average lateral length of newly-drilled and expected future wells, combined with an increase in our working interest ownership in wells in areas with established reserves, and the addition of proved undeveloped locations in the Delaware Basin. +On January 5, 2018, we closed an acquisition of properties from Bayswater Exploration and Production, LLC and certain related parties in the core Wattenberg Field (the "Bayswater Acquisition") for approximately $186 million , subject to certain customary post-closing adjustments. In addition to the approximately $186 million of cash paid at closing, we invested approximately $15 million during 2017 to complete certain drilled uncompleted wells ("DUCs") acquired in the transaction. +2 +Our Strengths +• +Multi-year project inventory in premier crude oil, natural gas, and NGL plays. We have a significant operational presence in two premier U.S. onshore basins, the Wattenberg Field in Weld County, Colorado, and the Delaware Basin in Reeves and Culberson Counties, Texas. The company has identified a significant inventory of horizontal drilling locations in each basin which will allow us to continue to grow our proved reserves and production at attractive rates of return based on our current internal long-term commodity price projections and our current expected cost structure. Our 2018 drilling and completion operations are expected to focus on the Kersey area of the Wattenberg Field and in our oilier eastern and north central areas of the Delaware Basin, where we expect to deliver our strongest economic results. +In the Wattenberg Field, we have identified a gross operated inventory of approximately 1,500 horizontal drilling locations, including locations acquired in the Bayswater Acquisition, that consist of an average lateral length of approximately 6,300 feet per well. Our Wattenberg Field horizontal drilling locations have been substantially de-risked through multiple years of successful development from the field. In the Delaware Basin, we have identified a gross operated inventory of approximately 450 horizontal Wolfcamp drilling locations, primarily within our oilier eastern and north central focus areas, that consist of an average lateral length of approximately 7,500 feet per well. Some of these 450 locations are subject to a higher degree of uncertainty as they reflect assumptions primarily related to future downspacing that we are either in the process of testing, or have not yet tested. Our other Delaware Basin leaseholds that are not currently in our primary focus area contain an estimated 240 additional potential horizontal Wolfcamp drilling locations that typically have a higher gas to oil ratio, contain less contiguous acreage for long lateral development, or may require additional technical assessments. We believe that our inventory in the Delaware Basin may increase over time, depending upon, among other variables, successful trades to consolidate leaseholds, additional exploration and development activity in other potential zones, service cost efficiencies, and improved commodity and netback pricing. +• +Strong liquidity position. As of December 31, 2017 , we had a total liquidity position of $880.7 million , comprised of $180.7 million of cash and cash equivalents and $700.0 million available for borrowing under our revolving credit facility. In November 2017, we issued $600 million principal amount of 5.75 percent unsecured senior notes due in 2026 (the "2026 Senior Notes"). The net proceeds from the offering were used to redeem our $500 million 7.75 percent senior notes due in 2022 (the "2022 Senior Notes"), fund a portion of the Bayswater Acquisition, which closed in early January 2018, and for general corporate purposes. If the Bayswater Acquisition had closed in December 2017, our liquidity position as of December 31, 2017 would have been approximately $700 million . We intend to continue to manage our liquidity position through investment in projects with attractive rates of return, protection of cash flows on a portion of our anticipated sales through the use of an active commodity derivative program, and access to capital markets from time to time. +• +Balanced and diversified portfolio across two premier U.S. onshore basins. Having drilling opportunities in both the Wattenberg Field and the Delaware Basin allows us to allocate capital between the two basins to diversify our risk. We believe this will improve overall economic results and drive our future production and reserve growth. Additionally, we believe the geographical diversity of our portfolio aids in the mitigation of risks associated with a single dominant producing area, as each basin has its own operating and competitive dynamic in terms of commodity price markets, service costs, takeaway capacity, and regulatory and political considerations. +• +Significant operational control in our core areas. We have, and expect to continue to have, a substantial degree of operational control over our properties. As a result of successfully executing our strategy of acquiring and consolidating largely concentrated acreage positions with high working interests, we operate and manage approximately 87 percent of all wells in which we have an interest across all of our operating basins. Our control allows us to manage our drilling, production, operating and administrative costs, and to leverage our technical expertise in our core operating areas. Our leaseholds that are held by production further enhance our operational control by providing us flexibility in selecting drilling locations based upon various operational criteria. +In the Wattenberg Field, our operational control is attributable to our high working interest leasehold and large contiguous acreage blocks, which have been significantly enhanced as a result of our 2016 and 2017 acreage exchanges and the Bayswater Acquisition, and because substantially all of our Wattenberg Field acreage is held by production. We remain flexible in terms of rig activity and capital deployment due to short-term rig contracts and we are confident in our ability to manage our acreage in the Wattenberg Field in order to maintain our current level of operational control. As a result, we can adjust our drilling plans if commodity prices deteriorate in order to manage cash flows from operations relative to cash flows from investing activities. +3 +In the Delaware Basin, our average working interest in our properties that we operate is approximately 90 percent. We own and operate certain midstream assets in the Delaware Basin and believe this will allow for timely system expansion, well connections, fresh water supply for completion operations, and produced water disposal. Our leasehold in the Delaware Basin requires a more active drilling program and we have less flexibility than we do in the Wattenberg Field, in terms of managing lease expiration issues. In some cases, continuous operations will be required to maintain the underlying leasehold in the Delaware Basin. However, with our high percentage of operated leasehold in the area, we expect to have adequate control over the location and pace of our development to manage lease expirations and meet our drilling obligations in the central and eastern parts of the basin. See Item 1A. Risk Factors - Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities. +• +Utilizing technology to focus on efficiency. In the Wattenberg Field, we have a proven track record of continuing improvement in both costs and productivity of our existing operations. Our efficiencies have historically been driven by a focus on the use of multi-well pad drilling, extended-reach lateral well development, increased fracture stimulation stage density, enhanced fracture stimulation completion design, and improved drilling efficiencies. In 2017, approximately 65 percent of our horizontal well spuds were mid- or extended-reach laterals that ranged from approximately 6,000 to 10,000 horizontal feet in length. We also use a mono-bore drilling design to reduce drill times and well costs. Through the combination of these techniques, our drilling team has improved our drilling efficiencies with average drill results increasing to approximately 2,700 feet drilled per day in 2017 from approximately 2,200 feet drilled per day in 2016. +• +Strong environmental, health and safety compliance programs, and community outreach. We have focused on establishing effective environmental, health and safety programs that are intended to promote safe working practices for our employees and contractors and to help earn the trust and respect of land owners, regulatory agencies, and public officials. This is an important part of our strategy and in competing in today’s intensive regulatory and public debate climate. We are also dedicated to being an active and contributing member of the communities in which we operate. We share our success with these communities in various ways, including charitable giving and community event sponsorships. +• +Commodity derivative program. Our active use of commodity derivative instruments to protect our investment returns and cash flows was particularly important through the recent commodity price downturns. We have continued this program and entered into commodity derivative instruments to mitigate a portion of our short-term future exposure to commodity price fluctuations, including fixed-price swaps, crude oil and natural gas collars, basis swaps, and rollfactor swap contracts. While our commodity derivative program limits the upside benefits we may otherwise receive during periods of higher commodity prices, the program helps protect a portion of our cash flows, borrowing base, and liquidity during periods of depressed commodity prices. We strive to scale our overall hedging position to be appropriate relative to our current and expected level of indebtedness and consistent with our goals of preserving balance sheet strength and substantial liquidity, as well as our internal price view. +As of December 31, 2017 , we had commodity derivatives positions covering approximately 11.9 MMBbls and 6.6 MMBbls of crude oil production for 2018 and 2019, respectively. As of the same date, we had hedged approximately 56.5 Bcf of natural gas and 1.1 MMBbls of propane for 2018. The details of these transactions are described in Item 7a. - Quantitative and Qualitative Disclosures About Market Risk . +• +Strong management team and operational capabilities. We have strong and stable management, led by our executive management team. Each member of the team has between 10 and 30 years of experience in the energy and natural resource industry. This experience collectively spans expertise in land, reservoir analysis, operations, accounting, strategy, and general operations, and has helped us continue our growth through periods of commodity price pressure and cost inflation, and other challenging environments. +4 +Business Strategy +Our long-term business strategy focuses on generating stockholder value through the acquisition, exploration, and development of crude oil and natural gas properties. We are focused on the growth of our reserves, production, and cash flows through organic exploration and development of our existing and acquired leasehold through horizontal drilling. Our operational focus is concentrated within two basins. We pursue various midstream, marketing, and cost reduction initiatives designed to increase our per unit operating margins, while maintaining a disciplined financial strategy focused on providing sufficient liquidity and balance sheet strength to execute our business strategy. +We focus on horizontal development drilling programs in resource plays that offer repeatable results and the potential for attractive returns on investment in a range of commodity price environments. Our inventory of drilling locations supports our planned organic growth over the next several years. We expect our drilling and completion activity to drive increases in proved reserves, production, and cash flows. In addition to development drilling, we routinely review acquisition and acreage swap opportunities in our core areas of operations. We believe we can extract additional value from such transactions through production optimization opportunities and increases in our working interests in our development drilling locations afforded by more concentrated acreage positions. As a result, once we have established a significant presence in an area, the use of bolt-on acquisitions and acreage exchanges can potentially provide synergies that result in additional economies of scale. We also pursue a limited and disciplined exploration program with the goal of replenishing our portfolio with new exploration projects capable of positioning us for significant production and reserve growth in future years. +In 2017, we completed two significant acreage exchanges that consolidated certain acreage positions in the core area of the Wattenberg Field, creating two development areas that we refer to as Prairie and Plains. Both transactions involved the exchange of leasehold acreage with a limited number of wells that were in the process of being drilled and completed. Upon closing the transactions, we received an aggregate of approximately 15,900 net acres in exchange for an aggregate of approximately 16,200 net acres. The difference in net acres is primarily due to variances in working and net revenue interests and in midstream contracts. +As referenced above, we closed the Bayswater Acquisition in January 2018, acquiring approximately 7,400 net acres, 24 operated horizontal wells that were either DUCs or in-process wells at the time of closing and an estimated 220 gross drilling locations at the time of closing. +Development drilling +The following map presents the general locations of our development and production activities as of December 31, 2017 : +(1) In February 2018, we entered into a PSA to sell the Utica Shale properties. +5 +Our leasehold interests cover properties with developed and undeveloped crude oil, natural gas, and NGLs resources. We own approximately 2,800 gross ( 2,300 net) wells in our two primary operating basins. Our 2018 capital investment program, which contemplates expenditures of between $850 million and $920 million, is primarily focused on continued execution in the Wattenberg Field and Delaware Basin using three drilling rigs and one completion crew in each basin throughout the year. +Based on our current production forecast for 2018 and assuming an average $57.50 New York Mercantile Exchange ("NYMEX") crude oil price for the year and a $3.00 NYMEX natural gas price, we expect 2018 capital investments to exceed our 2018 cash flows from operations by approximately less than $90 million. We anticipate that the proceeds received from the sale of our Utica Shale assets and a midstream dedication agreement (see the footnote titled Subsequent Events to the consolidated financial statements included elsewhere in this report), will fund approximately two-thirds of this outspend. We expect this outspend to occur during the first half of 2018, with cash flows exceeding capital investment during the second half of the year. Our leverage ratio, as defined in our revolving credit facility agreement, is expected to decrease by the end of 2018 based on production and operational cash flow growth. However, a significant deterioration in commodity prices could negatively impact our results of operations, financial condition, and future development plans. We may increase or decrease our 2018 capital investment program during the year as a result of, among other things, changes in commodity prices or our internal long-term outlook for commodity prices, requirements to hold acreage, the cost of services for drilling and well completion activities, drilling results, changes in our borrowing capacity, a significant change in cash flows, regulatory issues, requirements to maintain continuous activity on leaseholds or acquisition and/or divestiture opportunities. If such changes result in our election to deploy additional capital, amounts invested may further exceed our cash flow from operations. +Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays in the core Wattenberg Field, which is further delineated between the Kersey, Prairie and Plains development areas. We plan to drill standard-reach lateral (“SRL”), mid-reach lateral (“MRL”), and extended-reach lateral (“XRL”) wells in 2018, the majority of which will be in the Kersey area of the field. Wells in the Wattenberg Field typically have productive horizons at depths of approximately 6,500 to 7,500 feet below the surface. In 2018, we anticipate spudding and turning-in-line between approximately 135 to 150 operated wells, as outlined below: +SRL +MRL +XRL +Estimated average lateral length (in feet) +4,200 +6,900 +9,500 +Expected drilling days (spud-to-spud) +6 +8 +10 +Estimated percentage of 2018 wells spud +25% +45% +30% +Estimated percentage of 2018 wells turned-in-line +50% +35% +15% +Estimated cost per well (in millions) +$2.6 +$3.5 +$4.4 +Our 2018 capital investment program for the Wattenberg Field is approximately $470 million to $500 million, of which approximately 90 percent is expected to be invested in operated drilling and completion activity. The remainder of the Wattenberg Field capital investment program is expected to be used for non-operated drilling, land, and miscellaneous workover and capital projects. +6 +The following map presents the general locations of our development areas in the Niobrara and Codell plays of the Wattenberg Field as of December 31, 2017 : +Delaware Basin. Our 2018 capital investment program for the Delaware Basin contemplates operating at a three-rig pace throughout the year. Total capital investment in the Delaware Basin for 2018 is expected to be approximately $380 million to $420 million, of which approximately 75 percent is allocated to both spud and turn-in-line approximately 25 to 30 operated wells. Based on the timing of our operations and requirements to hold acreage, we may elect to drill wells different from or in addition to those currently anticipated, as we are continuing to analyze the terms of the relevant leases. Our anticipated Delaware Basin drilling program is outlined below: +SRL +MRL +XRL +Estimated average lateral length (in feet) +5,000 +8,000 +10,000 +Expected drilling days (spud-to-rig release) +30 +31 +36 +Estimated percentage of 2018 wells spud +10% +40% +50% +Estimated percentage of 2018 wells turned-in-line +25% +45% +30% +Estimated cost per well (in millions) +$9.2 +$10.8 +$13.2 +Wells in the Delaware Basin typically have productive horizons at depths of approximately 8,000 to 11,000 feet below the surface. We plan to use approximately 10 percent of our budgeted capital for leasing, non-operated capital, seismic, and technical studies, with the remaining 15 percent for midstream-related projects, including oil and gas gathering systems and water supply and disposal systems. +7 +The following map presents the general locations of our Wolfcamp formation development areas in the Delaware Basin as of December 31, 2017 : +Utica Shale . In 2017, as part of our plan to divest the Utica Shale properties, we engaged an investment banking firm and began actively marketing the properties for sale; therefore, these properties are classified as held-for-sale as of December 31, 2017. In February 2018, we entered into a PSA to sell these properties for net cash proceeds of approximately $40.0 million , subject to certain customary closing adjustments. +Strategic acquisitions +As part of our overall growth strategy, we examine and evaluate acquisition opportunities as they present themselves and pursue those that meet our strategic plan and that we believe will increase stockholder value. We seek properties with large undeveloped drilling upside where we believe we can utilize our operational expertise to grow production and proved reserves. In addition, we may pursue opportunities to exchange acreage with other producers or complete small bolt-on acquisitions in order to optimize our portfolio by consolidating and concentrating on our core assets. The creation of large, contiguous acreage blocks through the trading of properties or bolt-on acquisitions provides the opportunity to optimize drilling activities and add more extended-reach lateral wells to our drilling program, while increasing our working interests in the related wells. We have an experienced team of management, engineering, geosciences, and commercial professionals who identify and evaluate acquisition opportunities. We believe the Bayswater Acquisition and the acreage exchanges executed in 2016 and 2017 met the criteria. Any acquisition activity we may pursue in 2018 is expected to be focused on the Wattenberg Field and Delaware Basin. +Selective exploration +Historically, we have pursued a disciplined exploration program intended to replenish our portfolio of potential drilling locations and position us for production and reserve growth in future years. When doing so, we attempt to accumulate significant leasehold positions prior to competitive forces driving up the cost of entry and to invest in leasehold positions that are near existing or emerging midstream infrastructure. Our recent exploration activity has been in the Delaware Basin as there are multiple zones that have not seen development sufficient to record proved reserves. We believe such zones could provide +8 +us with additional potential drilling locations and/or proved reserves, based upon the results of our exploratory wells. See the footnote titled Properties and Equipment - Suspended Well Costs to our consolidated financial statements included elsewhere in this report for additional details regarding our exploratory wells. +Business Segments +We are engaged in two operating segments: our oil and gas exploration and production segment and our gas marketing segment. Beginning in 2017, our gas marketing segment did not meet the quantitative thresholds to require disclosure as a separate reportable segment. All of our material operations are attributable to our exploration and production business; therefore, all of our operations are presented as a single segment for all periods presented. +The results of our Oil and Gas Exploration and Production segment primarily reflect revenues and expenses from the production and sale of crude oil, natural gas, and NGLs, commodity price risk management, and well operations. The exploration for and production of crude oil, natural gas, and NGLs involves the acquisition or leasing of mineral and related surface rights. Prior to development of these properties, we assess the economic viability of potential well development opportunities. We then develop the reserves through the permitting, drilling and completion of crude oil and natural gas wells, which are then turned-in-line to production. We operate and maintain the producing wells, while managing associated production, operating, and transportation costs. At the end of a well's economic life, the well is plugged and surface disturbances surrounding the well and producing facilities are remediated. The Oil and Gas Exploration and Production segment's most significant customers are Suncor Energy Marketing, Inc. and DCP Midstream, LP ("DCP"). Sales to each of these parties constituted more than 10 percent of our 2017 revenues. Given the liquidity in the market for the sale of hydrocarbons, we believe that the loss of any purchaser or the aggregate loss of several customers could be managed by selling to alternative purchasers. See Part II, Item 7,Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations, Summary Operating Results , for sales, pricing, production, and operating cost data. +9 +Properties +Productive Wells +The following table presents our productive wells: +Productive Wells +As of December 31, 2017 +Crude Oil +Natural Gas +Total +Operating Region/Area +Gross +Net +Gross +Net +Gross +Net +Wattenberg Field (1) +811 +551.6 +1,893 +1,660.7 +2,704 +2,212.3 +Delaware Basin (2) +47 +43.1 +4 +4.0 +51 +47.1 +Utica Shale (3) +27 +22.2 +3 +3.0 +30 +25.2 +Total productive wells +885 +616.9 +1,900 +1,667.7 +2,785 +2,284.6 +_________ +(1) Additionally, the Bayswater Acquisition, which closed in January 2018, included 56 gross (19.7 net) productive crude oil +wells and 164 gross (118.7 net) productive natural gas wells. +(2) During 2017, we submitted applications to the Railroad Commission of Texas ("RRC of Texas") requesting that the +designation for 20 wells in the Delaware Basin be changed from crude oil to natural gas per their GOR analysis. The +applications are currently pending review by the RRC of Texas. +(3) In February 2018, we entered into a PSA to sell the Utica Shale properties. +Proved Reserves +The following table presents our proved reserve estimates as of December 31, 2017 , based on reserve reports prepared by our independent petroleum engineering consulting firms, Ryder Scott Company, L.P. ("Ryder Scott"), and Netherland, Sewell & Associates, Inc. ("NSAI"), and related information: +Proved Reserves at December 31, 2017 +Proved Reserves (MMBoe) +% of Total Proved Reserves +% Proved Developed +% Liquids +Proved Reserves to Production Ratio (in years)(1) +2017 Production (MBoe) +Wattenberg Field +350.8 +77 +% +33 +% +55 +% +13.1 +26,815 +Delaware Basin +97.9 +22 +% +23 +% +67 +% +23.4 +4,184 +Utica Shale (2) +4.2 +1 +% +100 +% +51 +% +5.1 +831 +Total proved reserves +452.9 +100 +% +32 +% +58 +% +14.2 +31,830 +_________ +(1) Based on production during 2017. +(2) In February 2018, we entered into a PSA to sell the Utica Shale properties. +Our proved reserves are sensitive to future crude oil, natural gas, and NGLs sales prices and the related effect on the economic productive life of producing properties. Increases in commodity prices may result in a longer economic productive life of a property or result in recognition of more economically viable proved undeveloped reserves, while decreases in commodity prices may result in negative impacts of this nature. +All of our proved reserves are located onshore in the U.S. Our proved reserve estimates are prepared using the definitions for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a) and other applicable SEC rules. Our proved reserves in the Wattenberg Field and Utica Shale as of December 31, 2017 were estimated by Ryder Scott and our reserves in the Delaware Basin as of that date were estimated by NSAI. Both Ryder Scott and NSAI are independent professional engineering firms. +We have a comprehensive process that governs the determination and reporting of our proved reserves. As part of our internal control process, our reserves are reviewed annually by an internal team composed of reservoir engineers, geologists, land, and accounting personnel for adherence to SEC guidelines through a detailed review of land and accounting records, +10 +available geological and reservoir data, and production performance data. The internal team compiles the reviewed data and forwards the data to Ryder Scott and NSAI, as applicable. +When preparing our reserve estimates, neither Ryder Scott nor NSAI independently verifies the accuracy and completeness of information and data furnished by us with respect to ownership interests, production volumes, well test data, historical costs of operations and development, product prices or any agreements relating to current and future operations of properties, or sales of production. Ryder Scott and NSAI prepare estimates of our reserves in conjunction with an ongoing review by our engineers. A final comparison of data is performed to ensure that the reserve estimates are complete, determined pursuant to acceptable industry methods, and with a level of detail we deem appropriate. The final estimated reserve reports are prepared by Ryder Scott and NSAI and reviewed by our engineering staff and management prior to issuance by those firms. +The professional qualifications of our internal lead engineer primarily responsible for overseeing the preparation of our reserve estimates, as defined in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the Society of Petroleum Engineers, qualifies this individual as a Reserve Estimator. This person holds a Bachelor of Science degree in Petroleum and Chemical Refining Engineering with a minor in Petroleum Engineering, has over 40 years of experience in reservoir engineering, is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers, and is a registered Professional Engineer in the State of Colorado. +The SEC's reserve rules allow the use of techniques that have been proved effective by evaluation of actual production from projects in the same reservoir or an analogous reservoir or by other observational evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. We used a combination of performance methods, including decline curve analysis and other computational methods, offset analogies, and seismic data and interpretation to calculate our reserve estimates. All of our proved undeveloped reserves conform to the SEC five-year rule requirement as all proved undeveloped locations are scheduled, according to an adopted development plan, to be drilled within five years of the location’s initial booking date. Per SEC rules, the pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of the month prices for the preceding 12 months. The NYMEX prices used in preparing the reserves are then adjusted based on energy content, location and basis differentials and other marketing deductions to arrive at the net realized price. The SEC NYMEX prices used in the preparation of reserves are as follows: +As of December 31, +2017 +2016 +2015 +Crude oil (SEC NYMEX - $/Bbl) +$ +51.34 +$ +42.75 +$ +50.28 +Natural gas (SEC NYMEX - $/MMBtu) +$ +2.98 +$ +2.48 +$ +2.59 +Reserve estimates involve judgments and cannot be measured exactly. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geologic and geophysical data, and economic changes. Neither the estimated future net cash flows nor the standardized measure of discounted future net cash flows ("standardized measure") is intended to represent the current market value of our proved reserves. For additional information regarding both of these measures, as well as other information regarding our proved reserves, see the Supplemental Information Unaudited - Crude Oil and Natural Gas Information provided with our consolidated financial statements included elsewhere in this report. +11 +The following tables provide information regarding our estimated proved reserves: +As of December 31, +2017 +2016 +2015 +Proved reserves +Crude oil and condensate (MMBbls) +155 +118 +99 +Natural gas (Bcf) +1,154 +834 +661 +NGLs (MMBbls) +106 +84 +64 +Total proved reserves (MMBoe) +453 +341 +273 +Proved developed reserves (MMBoe) +143 +98 +70 +Estimated undiscounted future net cash flows (in millions) (1) +$ +5,453 +$ +2,681 +$ +2,259 +Standardized measure (in millions) +$ +2,880 +$ +1,421 +$ +1,097 +PV-10 ( in millions) (2) (3) +$ +3,212 +$ +1,675 +$ +1,338 +___________ +(1) +Amount represents aggregate undiscounted future net cash flows, before income taxes, estimated by Ryder Scott and NSAI, of approximately $6.2 billion , $3.3 billion , and $2.8 billion as of December 31, 2017 , 2016 , and 2015 , respectively, less an internally-estimated undiscounted future income tax expense of approximately $0.7 billion , $0.6 billion , and $0.5 billion , respectively. +(2) +PV-10 is a non-U.S. GAAP financial measure. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in accordance with U.S. GAAP, but rather should be considered in addition to the standardized measure. See Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10 and a reconciliation of our PV-10 value to the standardized measure. +(3) +Of the PV-10 amounts, $31.6 million, $21.6 million, and $26.6 million represent amounts attributable to our Utica Shale properties as of December 31, 2017, 2016, and 2015, respectively. In February 2018, we entered into a PSA to sell these properties. +The following table presents our estimated proved developed and undeveloped reserves by category and area: +As of December 31, 2017 +Operating Region/Area +Crude Oil and Condensate (MMBbls) +Natural Gas +(Bcf) +NGLs +(MMBbls) +Crude Oil +Equivalent +(MMBoe) +Percent +Proved developed +Wattenberg Field +36.3 +301.9 +29.2 +115.9 +26 +% +Delaware Basin +9.5 +50.6 +4.9 +22.9 +5 +% +Utica Shale (1) +1.0 +12.8 +1.1 +4.2 +1 +% +Total proved developed +46.8 +365.3 +35.2 +143.0 +32 +% +Proved undeveloped +Wattenberg Field +69.7 +644.5 +57.8 +234.9 +51 +% +Delaware Basin +38.3 +144.5 +12.7 +75.0 +17 +% +Total proved undeveloped +108.0 +789.0 +70.5 +309.9 +68 +% +Total proved reserves +Wattenberg Field +106.0 +946.4 +87.0 +350.8 +77 +% +Delaware Basin +47.8 +195.1 +17.6 +97.9 +22 +% +Utica Shale (1) +1.0 +12.8 +1.1 +4.2 +1 +% +Total proved reserves +154.8 +1,154.3 +105.7 +452.9 +100 +% +________ +(1) In February 2018, we entered into a PSA to sell the Utica Shale properties. +12 +We have performed an analysis of our proved reserve estimates as of December 31, 2017 to present sensitivity associated with a lower crude oil price as the value of crude oil influences the value of our proved reserves and PV-10 most significantly. Replacing the 2017 NYMEX price for crude oil used in estimating our reported proved reserves with $30.00 as shown on the table below, and leaving all other parameters unchanged, results in changes to our estimated proved reserves as shown. +Pricing Scenario - NYMEX +Crude Oil (per Bbl) +Natural Gas (per MMBtu) +Proved Reserves (MMBoe) +% Change from December 31, 2017 Estimated Reserves +PV-10 (in Millions) +PV-10 % Change from December 31, 2017 Estimate Reserves +2017 SEC Reserve Report (1) +$ +51.34 +$ +2.98 +452.9 +— +$ +3,212.0 +— +Alternate Price Scenario +$ +30.00 +$ +2.98 +424.9 +(6 +)% +$ +1,021.0 +(68 +)% +__________ +(1) +These prices are the SEC NYMEX prices applied to the calculation of the PV-10 value. Such prices have been applied consistently in the alternate pricing scenario to include the impact of adjusting for deductions for any basin differentials, transportation fees, contractual adjustments, and any Btu adjustments we experienced for the respective commodity. +Developed and Undeveloped Acreage +The following table presents our developed and undeveloped lease acreage: +As of December 31, 2017 +Developed +Undeveloped +Total +Operating Region/Area +Gross +Net +Gross +Net +Gross +Net +Wattenberg Field (1) (2) +114,200 +109,200 +8,800 +7,600 +123,000 +116,800 +Delaware Basin (3) +31,900 +29,500 +36,600 +30,400 +68,500 +59,900 +Utica Shale (4) +5,300 +4,500 +44,600 +41,100 +49,900 +45,600 +Total acreage +151,400 +143,200 +90,000 +79,100 +241,400 +222,300 +___________ +(1) Of the amounts shown, 91,600 gross (87,400 net) developed lease acres and 4,700 gross (3,900 net) undeveloped +lease acres are associated with our approximately 1,500 operated horizontal Wattenberg Field drilling locations targeting +the Niobrara or Codell plays. The remaining acres are associated with other zones within the field that we do not +currently estimate to be economic to develop; therefore, we have not currently identified any potential drilling +locations on these acres. +(2) The Bayswater Acquisition, which closed in January 2018, included 9,100 gross (7,200 net) developed lease acres and +200 gross and net undeveloped lease acres, providing us a total of 132,300 gross (124,200 net) total acres in the Wattenberg +Field. +(3) See below regarding Culberson County acreage expirations. +(4) In February 2018, we entered into a PSA to sell the Utica Shale properties. +13 +Substantially all of our undeveloped acreage in the Wattenberg Field is related to leaseholds that are held by production. In the Wattenberg Field, the leaseholds at risk to expire in 2018, 2019, and 2020 are not material. In the Delaware Basin, there are drilling obligations or continuous drilling clauses associated with the majority of our acreage. While we believe that our current Delaware Basin drilling plan should provide sufficient development to meet these obligations for the next few years, in the event that we do not meet the obligations for certain leases, we anticipate that, when development plans dictate or when our analysis of the acreage supports such a decision, we will make any necessary bonus extension payments, changes to drilling schedules, or will seek to renew or re-lease in order to retain the leases in the eastern and central areas. However, the payments necessary to extend or retain certain leases may be significant and we may not be successful in such efforts or may elect not to pursue them. We expect that approximately 3,200 gross and net Delaware Basin acres in our western area block located in Culberson County will expire during the first half of 2019 as a result of normal course lease expirations that we do not anticipate renewing due to an expected lack of economically recoverable production quantities. These acres were impaired to an immaterial value in 2017. In total for the Delaware Basin, approximately 12 percent, 35 percent, and two percent of the leaseholds are at risk to expire in 2018, 2019, and 2020, respectively. See Item 1A. Risk Factors - Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities. +14 +Drilling Activity. The following tables set forth a summary of our developmental and exploratory well drilling activity for the periods presented. There is no necessary correlation between the number of productive wells completed during any period and the aggregate reserves attributable to those wells. Productive wells consist of wells that were turned-in-line and commenced production during the period, regardless of when drilling was initiated. In-process wells represent wells that are in the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection as of the date shown. The in-process wells are a normal part of our activity. The Wattenberg Field activity is comprised of pad drilling operations where multiple wells are developed from the same well pad. Because we operate multiple drilling rigs in the area, we expect to have in-process wells at any given time. Wells may be in-process for anywhere from days to several months. This normal in-process inventory also exists in the development of our Delaware Basin leasehold. +Gross Development Well Drilling Activity +Year Ended December 31, +2017 +2016 +2015 +Operating Region/Area +Productive +In-Process +Non-Productive (1) +Productive +In-Process +Non-Productive (1) +Productive +In-Process +Non-Productive (1) +Wattenberg Field, operated wells +130 +87 +— +140 +64 +2 +136 +78 +4 +Wattenberg Field, non-operated wells +12 +14 +1 +24 +12 +— +58 +19 +— +Delaware Basin +11 +18 +— +1 +5 +— +— +— +— +Utica Shale (2) +— +— +— +5 +— +— +4 +5 +— +Total gross development wells +153 +119 +1 +170 +81 +2 +198 +102 +4 +__________ +(1) +Represents mechanical failures that resulted in the plugging and abandonment of the respective wells. +(2) +In February 2018, we entered into a PSA to sell the Utica Shale properties. +Net Development Well Drilling Activity +Year Ended December 31, +2017 +2016 +2015 +Operating Region/Area +Productive +In-Process +Non-Productive (1) +Productive +In-Process +Non-Productive (1) +Productive +In-Process +Non-Productive (1) +Wattenberg Field, operated wells +112.8 +80.1 +— +109.7 +52.7 +1.7 +110.8 +54.6 +2.7 +Wattenberg Field, non-operated wells +1.6 +2.6 +0.1 +5.0 +2.8 +— +9.3 +4.3 +— +Delaware Basin +10.5 +10.4 +— +1.0 +4.8 +— +— +— +— +Utica Shale (2) +— +— +— +4.5 +— +— +3.0 +4.5 +— +Total net development wells +124.9 +93.1 +0.1 +120.2 +60.3 +1.7 +123.1 +63.4 +2.7 +__________ +(1) +Represents mechanical failures that resulted in the plugging and abandonment of the respective wells. +(2) +In February 2018, we entered into a PSA to sell the Utica Shale properties. +15 +Gross Exploratory Well Drilling Activity +Year Ended December 31, +2017 +2016 +2015 +Operating Region/Area +Productive +In-Process +Non-Productive +Productive +In-Process +Non-Productive +Productive +In-Process +Non-Productive +Wattenberg Field, operated wells +— +— +— +— +— +— +— +— +— +Wattenberg Field, non-operated wells +— +— +— +— +— +— +— +— +— +Delaware Basin +5 +3 +2 +— +— +— +— +— +— +Utica Shale +— +— +— +— +— +— +— +— +— +Total gross development wells +5 +3 +2 +— +— +— +— +— +— +Net Exploratory Well Drilling Activity +Year Ended December 31, +2017 +2016 +2015 +Operating Region/Area +Productive +In-Process +Non-Productive +Productive +In-Process +Non-Productive +Productive +In-Process +Non-Productive +Wattenberg Field, operated wells +— +— +— +— +— +— +— +— +— +Wattenberg Field, non-operated wells +— +— +— +— +— +— +— +— +— +Delaware Basin +3.1 +2.8 +2.0 +— +— +— +— +— +— +Utica Shale +— +— +— +— +— +— +— +— +— +Total gross development wells +3.1 +2.8 +2.0 +— +— +— +— +— +— +Title to Properties +We believe that we hold good and defensible leasehold title to substantially all of our crude oil and natural gas properties in accordance with standards generally accepted in the industry. A preliminary title examination is typically conducted at the time the undeveloped properties are acquired. Prior to the commencement of drilling operations, a title examination is conducted and remedial curative work is performed, as necessary, with respect to discovered defects which we deem to be significant, in order to procure division order title opinions. Title examinations have been performed with respect to substantially all of our producing properties. +The properties we own are subject to royalty, overriding royalty, and other outstanding interests. The properties may also be subject to additional burdens, liens, or encumbrances customary in the industry, including items such as operating agreements, current taxes, development obligations under crude oil and natural gas leases, farm-out agreements, and other restrictions. We do not believe that any of these burdens will materially interfere with our use of the properties. +Substantially all of our crude oil and natural gas properties, excluding our share of properties held by the limited +partnerships that we sponsor, have been mortgaged or pledged as security for our revolving credit facility. See the footnote titled Long-Term Debt to our consolidated financial statements included elsewhere in this report. +Facilities +We lease 87,000 square feet of office space in Denver, Colorado, which serves as our corporate office, through February 2023 and 47,000 square feet of office space in Evans, Colorado through November 2025. We own a 32,000 square foot administrative office building located in Bridgeport, West Virginia. +We own or lease field operating facilities in or near Evans, Colorado and Midland, Texas. +Governmental Regulation +The U.S. crude oil and natural gas industry is extensively regulated at the federal, state and local levels. The following is a summary of certain laws, rules and regulations currently in force that apply to us. The regulatory environment in which we operate changes frequently and we cannot predict the timing or nature of such changes or their effects on us. +16 +Regulation of Crude Oil and Natural Gas Exploration and Production. Our exploration and production activities are subject to a variety of rules and regulations concerning drilling permits, the spacing and density of wells, rates of production, water discharge, prevention of waste, bonding requirements, surface use and restoration and well plugging and abandonment. The primary state-level regulatory authority regarding these matters is the Colorado Oil and Gas Conservation Commission (the “COGCC”). For example, prior to commencing drilling activities for a well, we must procure permits and/or approvals for the various stages of the drilling process from the relevant state and local agencies. Similarly, our operations must comply with rules governing the size of drilling and spacing units or proration units and the unitization or pooling of lands and leases. Some states, such as Colorado, allow the forced pooling or integration of tracts to facilitate exploration while other states, such as Texas, rely primarily or exclusively on voluntary pooling of lands and leases. In states, such as Texas, where pooling is primarily or exclusively voluntary, it may be more difficult to form units and therefore to drill and develop our leases in circumstances where we do not own all of the leases in the proposed unit. State laws may also establish maximum rates of production from crude oil and natural gas wells, prohibit the venting or flaring of natural gas, and impose requirements regarding the ratability of production. Leases covering state or federal lands often include additional regulations and conditions. These laws, regulations and conditions can limit the number of wells we can drill and the permissible production from successful wells and can increase our costs. +Regulation of Transportation of Natural Gas. We move natural gas through pipelines owned by other companies and sell natural gas to other companies that also utilize common carrier pipeline facilities. Natural gas pipeline interstate transmission and storage activities are subject to regulation by the Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act of 1938 ("NGA") and under the Natural Gas Policy Act of 1978. Rates and charges for the transportation of natural gas in interstate commerce, and the extension, enlargement or abandonment of jurisdictional facilities, among other things, are subject to regulation. Natural gas pipeline companies hold certificates of public convenience and necessity issued by FERC authorizing ownership and operation of certain pipelines, facilities and properties. Each natural gas pipeline company is also subject to the Natural Gas Pipeline Safety Act of 1968, as amended, which imposes safety requirements in the design, construction, operation, and maintenance of interstate natural gas transmission facilities. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. Interstate pipelines may not operate their pipeline systems to preferentially benefit their marketing affiliates. +Transportation and safety of natural gas is also subject to regulation by the United States Department of Transportation under the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2012. +The availability, terms, and cost of transportation affect our natural gas sales. Historically, producers were able to flow supplies into interstate pipelines on an interruptible basis; however, recently we have seen the increased need to acquire firm transportation on pipelines in order to avoid curtailments or shut-in gas, which could adversely affect cash flows from the affected area. Gathering is exempt from regulation under the NGA, thus allowing gatherers to charge negotiated rates. Gathering lines are subject to state regulation, however, which includes various safety, environmental, and in some circumstances, nondiscriminatory take requirements. +Environmental Matters +Our operations are subject to numerous laws and regulations relating to environmental protection. These laws and regulations change frequently, and the effect of these changes is often to impose additional costs or other restrictions on our operations. We cannot predict the occurrence, timing, nature or effect of these changes. +Hazardous Substances and Wastes +We generate wastes that may be subject to the Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. The U.S. Environmental Protection Agency (“EPA”) and various state agencies have adopted requirements that limit the approved disposal methods for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by our operations that are currently exempt from treatment as “hazardous wastes” may in the future be designated as hazardous wastes, and therefore may subject us to more rigorous and costly operating and disposal requirements. In December 2016, the U.S. District Court for the District of Columbia approved a consent decree between the EPA and a coalition of environmental groups. The consent decree requires the EPA to review and determine whether it will revise the RCRA regulations for exploration and production waste to treat such waste as hazardous waste. The EPA must complete its review and make its decision regarding revision by March 2019. If the EPA chooses to revise the applicable RCRA regulations, it must sign a notice taking final action related to the new regulation by July 2021. +17 +We currently own or lease numerous properties that have been used for the exploration and production of crude oil and natural gas for many years. If hydrocarbons or other wastes have been disposed of or released on or under the properties that we own or lease or on or under locations where such wastes have been taken for disposal by us or prior owners or operators of such properties, we could be subject to liability under the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), RCRA and analogous state laws, as well as state laws governing the management of crude oil and natural gas wastes. CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of, transported, or arranged for the disposal of the hazardous substances found at the site. Persons who are or were responsible for release of hazardous substances under CERCLA may be subject to full liability for the costs of cleaning up the hazardous substances that have been released into the environment or remediation to prevent future contamination and for damages to natural resources. Under state laws, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. +In October 2015, the EPA granted, in part, a petition filed by several national environmental advocacy groups to add the oil and gas extraction industry to the list of industries required to report releases of certain “toxic chemicals” under the Toxics Release Inventory (“TRI”) program under the Emergency Planning and Community Right-to-Know Act. +Hydraulic Fracturing +Hydraulic fracturing is commonly used to stimulate production of crude oil and/or natural gas from dense subsurface rock formations. We consistently utilize hydraulic fracturing in our crude oil and natural gas development programs. The process involves the injection of water, sand, and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations which are held open by the grains of sand, enabling the crude oil or natural gas to more easily flow to the wellbore. The process is generally subject to regulation by state oil and gas commissions, but is also the subject of various other regulatory initiatives at the federal, state and local levels. +Federal Regulation +Beginning in 2012, the EPA implemented Clean Air Act (“CAA”) standards (New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants) applicable to hydraulically fractured natural gas wells and certain storage vessels. The standards require, among other things, use of reduced emission completions, or “green” completions, to reduce volatile organic compound emissions during well completions as well as new controls applicable to a wide variety of storage tanks and other equipment, including compressors, controllers, and dehydrators. +In February 2014, the EPA issued permitting guidance under the Safe Drinking Water Act ("SDWA") for the underground injection of liquids from hydraulically fractured and other wells where diesel is used. Depending upon how it is implemented, this guidance may create duplicative requirements in certain areas, further slow the permitting process in certain areas, increase the costs of operations, and result in expanded regulation of hydraulic fracturing activities by the EPA, and may therefore adversely affect even companies, such as PDC, that do not use diesel fuel in hydraulic fracturing activities. +In May 2014, the EPA issued an advance notice of proposed rulemaking under the Toxic Substances Control Act pursuant to which it will collect extensive information on the chemicals used in hydraulic fracturing fluid, as well as other health-related data, from chemical manufacturers and processors. +The U.S. Department of the Interior, through the Bureau of Land Management (the “BLM”), finalized a rule in 2015 requiring the disclosure of chemicals used, mandating well integrity measures and imposing other requirements relating to hydraulic fracturing on federal lands. The BLM rescinded the rule in December 2017. +In June 2016, the EPA finalized pretreatment standards for indirect discharges of wastewater from the oil and gas extraction industry. The regulation prohibits sending wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned treatment works. +In December 2016, the EPA released a report titled “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources.” The report concluded that activities involved in hydraulic fracturing can have impacts on drinking water under certain circumstances. In addition, the U.S. Department of Energy has investigated practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. These +18 +and similar studies, depending on their degree of development and nature of results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. +State Regulation +Each of the states in which we currently operate, Colorado, Texas, and Ohio, have adopted or are considering adopting laws and regulations that impose or could impose, among other requirements, stringent permitting or air emission control requirements, disclosure, wastewater disposal, baseline sampling, seismic monitoring, well construction and well location requirements on hydraulic fracturing operations and/or more stringent notification or consultation processes. The Ohio Department of Natural Resources (“ODNR”) has required the suspension of certain activities relating to hydraulic fracturing in the past in response to earthquakes occurring near development operations. Similarly, the Railroad Commission of Texas has implemented rules requiring the submission of detailed information related to seismicity in connection with permit applications. In addition, some states have banned the treatment of fracturing wastewater at publicly owned treatment facilities. +Colorado and Texas require that all chemicals used in the hydraulic fracturing of a well be reported in a publicly searchable registry website developed and maintained by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission (“Frac Focus”). +Concerns about hydraulic fracturing have contributed to support for proposed ballot initiatives in Colorado that would dramatically limit the areas of the state in which drilling would be permitted to occur. See Item 1A. Risk Factors-Risks Relating to Our Business and the Industry-Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us. +Local Regulation +Various local and municipal bodies in each of the states in which we operate have purported to impose drilling moratoria and other restrictions on hydraulic fracturing activities. The cities purporting to ban hydraulic fracturing currently include Fort Collins, Boulder, Lafayette, Longmont and Brighton in Colorado and Denton in Texas. Ballot initiatives have been proposed in Colorado that would authorize local governmental authorities to implement hydraulic fracturing bans or other regulations. See Item 1A. Risk Factors-Risks Relating to Our Business and the Industry-Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us. +Private Lawsuits +Lawsuits have been filed against other operators in several states, including Colorado and Ohio, alleging contamination of drinking water as a result of hydraulic fracturing activities. +Greenhouse Gases +In December 2009, the EPA published its findings that emissions of carbon dioxide, methane, and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because such emissions are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings provide the basis for the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. In June 2010, the EPA began regulating GHG emissions from stationary sources. +In the past, Congress has considered proposed legislation to reduce emissions of GHGs. Congress has not adopted any significant legislation in this respect to date, but could do so in the future. In addition, many states and regions have taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. In February 2014 and November 2017, Colorado adopted rules regulating methane emissions from the oil and gas sector. +The Obama administration reached an agreement during the December 2015 United Nations climate change conference in Paris pursuant to which the United States initially pledged to make a 26-28 percent reduction in its GHG emissions by 2025 against a 2005 baseline and committed to periodically update this pledge every five years starting in 2020 (the Paris Agreement). In June 2017, President Trump announced that the United States would initiate the formal process to withdraw from the Paris Agreement. +19 +Air Quality +Our operations are subject to the CAA and comparable state and local requirements. The CAA contains provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and state governments continue to develop regulations to implement these requirements. We may be required to incur certain capital investments in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. See the footnote titled Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere in this report for further information regarding the Clean Air Act Section 114 Information Request that we received from the EPA in August 2015. +In June 2016, the EPA implemented new requirements focused on achieving additional methane and volatile organic compound reductions from the oil and natural gas industry. The rules imposed, among other things, new requirements for leak detection and repair, control requirements for oil well completions, replacement of certain pneumatic pumps and controllers, and additional control requirements for gathering, boosting, and compressor stations. The EPA has proposed a two-year stay of the effective dates of several requirements of the rules. Also in 2016, the EPA issued guidelines for reducing volatile organic compound emissions from existing oil and natural gas equipment and processes in ozone non-attainment areas, including the Denver Metro North Front Range Ozone 8-Hour Non-Attainment (“Denver Metro/North Front Range NAA”) area discussed below. +In November 2016, the BLM finalized rules to further regulate venting, flaring, and leaks during oil and natural gas production activities on onshore federal and Indian leases. The rules require additional controls and impose new emissions and other standards on certain operations on applicable leases, including committed state or private tracts in a federally approved unit or communitized agreement that drains federal minerals. The rules are the subject of litigation in federal court. In December 2017, the BLM published a rule to temporarily suspend or delay certain rule requirements until January 2019; that rule is also the subject of litigation in federal court. +In 2016, the EPA increased the state of Colorado’s non-attainment ozone classification for the Denver Metro/North Front Range NAA area from “marginal” to “moderate” under the 2008 national ambient air quality standard (“NAAQS”). This increase in non-attainment status triggered significant additional obligations for the state under the CAA and resulted in Colorado adopting new and more stringent air quality control requirements in November 2017 that are applicable to our operations. The Denver Metro/North Front Range NAA is at risk of being reclassified again to “serious” if it does not meet the 2008 NAAQS by 2018 or obtain an extension of the deadline from the EPA. A “serious” classification would trigger significant additional obligations for the state under the CAA and could result in new and more stringent air quality control requirements applicable to our operations and significant costs and delays in obtaining necessary permits. +State-level rules applicable to our operations include regulations imposed by the Colorado Department of Public Health and Environment’s Air Quality Control Commission, including stringent requirements relating to monitoring, recordkeeping, and reporting matters. +Water Quality +The federal Clean Water Act (“CWA”) and analogous state laws impose strict controls concerning the discharge of pollutants and fill material, including spills and leaks of crude oil and other substances. The CWA also requires approval and/or permits prior to construction, where construction will disturb wetlands or other waters of the United States. The scope of what areas constitute jurisdictional waters of the United States regulated under the CWA is currently the subject of ongoing litigation and related administrative matters that are not expected to be resolved for several years. In January 2017, the Army Corps of Engineers issued revised and renewed streamlined general nationwide permits that are available to satisfy permitting requirements for certain work in streams, wetlands and other waters of the United States under Section 404 of the CWA and the Rivers and Harbors Act. The new nationwide permits took effect in March 2017, or when certified by each state, whichever was later. The oil and gas industry broadly utilizes nationwide permits 12, 14, and 39 for the construction, maintenance and repairs of pipelines, roads, and drill pads, respectively, and related structures in waters of the United States that impact less than a half-acre of waters of the United States and meet the other criteria of each nationwide permit. +The CWA also regulates storm water run-off from crude oil and natural gas facilities and requires storm water discharge permits for certain activities. Spill Prevention, Control, and Countermeasure (“SPCC”) requirements of the CWA require appropriate secondary containment load out controls, piping controls, berms, and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture, or leak. +20 +Endangered Species +The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and bald and golden eagles under the Bald and Golden Eagle Protection Act. Some of our operations may be located in areas that are or may be designated as habitats for endangered or threatened species or that may attract migratory birds, bald eagles, or golden eagles. +Safety and Spill Prevention +In October 2015, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration proposed to expand its regulations in a number of ways, including increased regulation of gathering lines, even in rural areas, and proposed additional standards to revise safety regulations applicable to onshore gas transmission and gathering pipelines in 2016. +Crude oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of crude oil spills. In addition to SPCC requirements, the Oil Pollution Act of 1990 (“OPA”) subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from crude oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Historically, we have not experienced any significant crude oil discharge or crude oil spill problems. +In May 2015, the U.S. Department of Transportation issued a final rule regarding the safe transportation of flammable liquids by rail. The final rule imposes certain requirements on “offerors” of crude oil, including sampling, testing, and certification requirements. +We are also subject to rules regarding worker safety and similar matters promulgated by the U.S. Occupational Safety and Health Administration (“OSHA”) and other governmental authorities. OSHA has established workplace safety standards that provide guidelines for maintaining a safe workplace in light of potential hazards, such as employee exposure to hazardous substances. The COGCC has adopted or amended numerous rules in recent years, including rules relating to safety matters, and currently is pursuing a rulemaking process relating to flowline safety and leak detection. +WHERE YOU CAN FIND ADDITIONAL INFORMATION +We file annual, quarterly, and current reports, proxy statements and other information with the SEC. Our SEC filings are available free of charge from the SEC’s website at www.sec.gov or from our website at www.pdce.com. You may also read or copy any document we file at the SEC’s public reference room in Washington, D.C., located at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at (800) SEC-0330 for further information on the public reference room. We also make available free of charge any of our SEC filings by mail. For a mailed copy of a report, please contact PDC Energy, Inc., Investor Relations, 1775 Sherman Street, Suite 3000, Denver, CO 80203, or call (800) 624-3821. +We recommend that you view our website for additional information, as we routinely post information that we believe is important for investors. Our website can be used to access such information as our recent news releases, committee charters, code of business conduct and ethics, stockholder communication policy, director nomination procedures, and our whistle blower hotline. While we recommend that you view our website, the information available on our website is not part of this report and is not incorporated by reference. +21 +ITEM 1A. RISK FACTORS +You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results, and financial condition, as well as adversely affect the value of an investment in our common stock or other securities. +Risks Relating to Our Business and the Industry +Crude oil, natural gas, and NGL prices fluctuate and declines in these prices, or an extended period of low prices, can significantly affect the value of our assets and our financial results and may impede our growth. +Our revenue, profitability, cash flows and liquidity depend in large part upon the prices we receive for our crude oil, natural gas, and NGLs. Changes in prices affect many aspects of our business, including: +• +our revenue, profitability and cash flows; +• +our liquidity; +• +the quantity and present value of our reserves; +• +the borrowing base under our revolving credit facility and access to other sources of capital; and +• +the nature and scale of our operations. +The markets for crude oil, natural gas, and NGLs are often volatile, and prices may fluctuate in response to, among other things: +• +relatively minor changes in regional, national, or global supply and demand; +• +regional, national, or global economic conditions, and perceived trends in those conditions; +• +geopolitical factors, such as events that may reduce or increase production from particular oil-producing regions and/or from members of the Organization of Petroleum Exporting Countries, or ("OPEC"); and +• +regulatory changes. +The price of oil has been volatile since mid-2014, with a high over $100 per barrel in June 2014 to lows below $30 per barrel in 2016, in each case based on West Texas Intermediate (“WTI”) prices, due to a combination of factors including increased U.S. supply and global economic concerns. Prices for natural gas and NGLs have experienced similar volatility. If we reduce our capital expenditures due to low prices, natural declines in production from our wells will likely result in reduced production and therefore reduced cash flow from operations, which would in turn further limit our ability to make the capital expenditures necessary to replace our reserves and production. +In addition to factors affecting the price of crude oil, natural gas, and NGLs generally, the prices we receive for our production are affected by factors specific to us and to the local markets where the production occurs. The prices that we receive for our production are generally lower than the relevant benchmark prices that are used for calculating commodity derivative positions. These differences, or differentials, are difficult to predict and may widen or narrow in the future based on market forces. Differentials can be influenced by, among other things, local or regional supply and demand factors and the terms of our sales contracts. Over the longer term, differentials will be significantly affected by factors such as investment decisions made by providers of midstream facilities and services, refineries and other industry participants, and the overall regulatory and economic climate. For example, increases in U.S. domestic oil production generally, or in production from particular basins, may result in widening differentials. We may be materially and adversely impacted by widening differentials on our production and decreasing commodity prices. +The marketability of our production is dependent upon transportation and processing facilities the capacity and operation of which we do not control. Market conditions or operational impediments affecting midstream facilities and services could hinder our access to crude oil, natural gas, and NGL markets, increase our costs or delay production. Our efforts to address midstream issues may not be successful. +Our ability to market our production depends in substantial part on the availability, proximity and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. If adequate midstream facilities and services are not available to us on a timely basis and at acceptable costs, our production and results of operations will be adversely affected. For example, in recent periods, due to ongoing drilling activities by us and third parties and seasonal changes in temperatures, our principal third-party provider in the Wattenberg Field for midstream facilities and services has experienced significantly increased gathering system pressures. The resulting capacity constraints reduced the productivity of some of our older vertical wells and limited incremental production from some of our newer horizontal wells. This constrained our production volumes and reduced our revenue from the affected wells. Capacity constraints affecting natural gas production +22 +also impacted the associated NGLs. While this has not been a problem for us in the Delaware Basin to date, some operators in the Delaware Basin have also experienced similar issues from time to time, in part due to significant increases in production in the area. The use of alternative forms of transportation for oil production, such as trucks or rail, involve risks, including the risk that increased regulation could lead to increased costs or shortages of trucks or rail-cars. In addition to causing production curtailments, capacity constraints can also reduce the price we receive for the crude oil, natural gas, and NGLs we produce. +We rely on third parties to continue to construct additional midstream facilities and related infrastructure to accommodate our growth, and the ability and willingness of those parties to do so is subject to a variety of risks. For example: +• +Decreases in commodity prices in recent years have resulted in reduced investment in midstream facilities by some third parties; +• +Various interest groups have protested the construction of new pipelines, and particularly pipelines near water bodies, in various places throughout the country, and protests have at times physically interrupted pipeline construction activities; and +• +Some upstream energy companies have recently sought to reject volume commitment agreements with midstream providers in bankruptcy proceedings, and the risk that such efforts will succeed, or that upstream energy company counterparties will otherwise be unable or unwilling to satisfy their volume commitments, may have the effect of reducing investment in midstream infrastructure. +Like other producers, we from time to time enter into volume commitments with midstream providers in order to induce them to provide increased capacity. If our production falls below the level required under these agreements, we could be subject to substantial penalties. +In order to attempt to alleviate some of the risks associated with the midstream services and facilities upon which we rely, we have pursued various means of addressing our midstream needs, including by entering into facility expansion agreements with our primary midstream provider in the Wattenberg Field in 2017. We may pursue additional options with respect to midstream matters, possibly through one or more joint ventures or monetization transactions. There can be no assurance that we will be able to negotiate and complete the transactions contemplated by our chosen strategy or that such transactions will provide us with the benefits we expect to obtain. +Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in substantial lease renewal costs or, if renewal is not feasible, loss of our lease and prospective drilling opportunities. +Unless production is established within the spacing units covering our undeveloped acreage, our leases for such acreage will expire. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may differ materially from our current expectations, which could adversely affect our business. These risks are greater at times and in areas where the pace of our exploration and development activity slows. Our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. These risks are currently greater for us in the Delaware Basin area than in our other operating areas as approximately one-third of our Delaware Basin acreage is currently scheduled to expire by mid-2019 unless the relevant leases are extended or adequate production is established. +A substantial part of our crude oil, natural gas, and NGLs production is located in the Wattenberg Field, making us vulnerable to risks associated with operating primarily in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing formations. +Although we have significant leasehold positions in the Delaware Basin in Texas, our current production is primarily located in the Wattenberg Field in Colorado. Because our production is not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including: +• +fluctuations in prices of crude oil, natural gas, and NGLs produced from the wells in the area; +• +natural disasters such as the flooding that occurred in northern Colorado in September 2013; +• +restrictive governmental regulations; and +• +curtailment of production or interruption in the availability of gathering, processing, or transportation infrastructure and services, and any resulting delays or interruptions of production from existing or planned new wells. +23 +For example, bottlenecks in processing and transportation that have occurred in some recent periods in the Wattenberg Field have negatively affected our results of operations, and these adverse effects may be disproportionately severe to us compared to our more geographically diverse competitors. Similarly, the concentration of our producing assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules that could adversely affect development activities or production relating to those formations. Such an event could have a material adverse effect on our results of operations and financial condition. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the Wattenberg Field and the Delaware Basin, the demand for, and cost of, drilling rigs, equipment, supplies, chemicals, personnel, and oilfield services increase. Shortages or the high cost of drilling rigs, equipment, supplies, chemicals, personnel, or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital forecast, which could have a material adverse effect on our business, financial condition or results of operations. +Certain of our properties are subject to land use restrictions, which could limit the manner in which we conduct our business. +Certain of our properties are subject to land use restrictions, including city ordinances, which could limit the manner in which we conduct our business. Such restrictions could affect, among other things, our access to and the permissible uses of our facilities as well as the manner in which we produce oil and natural gas, and may restrict or prohibit drilling in general. The costs we incur to comply with such restrictions may be significant, and we may experience delays or curtailment in the pursuit of development activities and may be precluded from drilling wells in some areas. +We may incur losses as a result of title defects in the properties in which we invest or acquire. +It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform record title examinations before we acquire oil and gas leases and related interests. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property. +We are subject to complex federal, state, local, and other laws and regulations that adversely affect the cost and manner of doing business. +Our exploration, development, production, and marketing operations are regulated extensively at the federal, state, and local levels. Environmental and other governmental laws and regulations have increased the costs of planning, designing, drilling, installing, operating, and abandoning crude oil and natural gas wells and associated facilities. Under these laws and regulations, we could also be liable for personal injuries, property damage, and natural resource or other damages, and could be required to change, suspend or terminate operations. Similar to our competitors, we incur substantial operating and capital costs to comply with such laws and regulations. These costs may put us at a competitive disadvantage compared to larger companies in the industry which can more easily capture economies of scale with respect to compliance. A summary of certain laws and regulations that apply to us is set forth in Items 1 and 2 - Business and Properties - Governmental Regulation . +In June 2017, the U.S. Department of Justice, on behalf of the EPA and the State of Colorado, filed a complaint against us, claiming that we failed to operate and maintain certain condensate collection equipment at 65 facilities so as to minimize leakage of volatile organic compounds in compliance with applicable law. In October 2017, we entered into a consent decree to resolve the lawsuit. Pursuant to the consent decree, we agreed to implement a variety of operational enhancements and mitigation and similar projects, including vapor control system modifications and verification, increased inspection and monitoring, and installation of tank pressure monitors. If we fail to comply fully with the requirements of the consent decree with respect to those matters, we could be subject to additional liability. In addition, we could be the subject of other enforcement actions by regulatory authorities in the future relating to our past, present or future operations. See the footnote titled Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere in this report for further information regarding this litigation. +A major risk inherent in our drilling plans is the possibility that we will be unable to obtain needed drilling permits from relevant governmental authorities in a timely manner. Our ability to obtain the permits needed to pursue our development plans may be impacted by a variety of factors, including opposition by landowners or interest groups. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well, or the receipt of a permit with +24 +unreasonable or unexpected conditions or costs could have a material adverse effect on our ability to explore or develop our properties. +Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us. +The regulatory environment in which we operate changes frequently, often through the imposition of new or more stringent environmental and other requirements. We cannot predict the nature, timing or effect of such additional requirements, but they may have a variety of adverse effects on us. The types of regulatory changes that could impact our operations vary widely and include, but are not limited to, the following: +• +Substantially all of our drilling activities involve the use of hydraulic fracturing, and proposals are made from time to time at the federal, state and local levels to further regulate, or to ban, hydraulic fracturing practices. Additional laws or regulations regarding hydraulic fracturing could, among other things, increase our costs, reduce our inventory of economically viable drilling locations and reduce our reserves. +• +Federal and various state, local and regional governmental authorities have implemented, or considered implementing, regulations that seek to limit or discourage the emission of carbon, methane and other greenhouse gases ("GHGs"). For example, the EPA has made findings and issued regulations that require us to establish and report an inventory of greenhouse gas emissions, and the state of Colorado has adopted rules regulating methane emissions from oil and gas operations. In addition, the Obama administration reached an agreement during the December 2015 United Nations climate change conference in Paris pursuant to which the United States initially pledged to make a 26 percent to 28 percent reduction in its GHG emissions by 2025 against a 2005 baseline (although President Trump subsequently announced that the United States is withdrawing from the Paris Agreement). Additional laws or regulations intended to restrict the emission of GHGs could require us to incur additional operating costs and could adversely affect demand for the oil, natural gas and NGLs that we sell. These new laws or rules could, among other things, require us to install new emission controls on our equipment and facilities, acquire allowances to authorize our GHG emissions, pay taxes related to our emissions and administer and manage a GHG emissions program. +• +From time to time ballot initiatives have been proposed in Colorado that would adversely affect our operations. For example, during 2016, interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, advanced two initiatives: (i) a “local control” initiative that would have amended the state constitution to give city, town, and county governments the right to regulate, or to ban, oil and gas development and production within their boundaries, notwithstanding rules and approvals to the contrary at the state level, and (ii) a “setback” initiative that would have amended the state constitution to require all new oil and gas development facilities to be located at least 2,500 feet away from any occupied structure or broadly defined “area of special concern”. If implemented, the setback initiative would have effectively prohibited the vast majority of our planned future drilling activities in Colorado and would therefore have made it impossible to pursue our current development plans. The local control proposal would potentially have had a similar effect, depending on the nature and extent of regulations implemented by relevant local governmental authorities. These proposals ultimately did not appear on the November 2016 ballot but it is likely that similar proposals will be made in 2018 and in future years. Similar proposals may also be made in other states. +• +A recently-adopted ballot initiative that would make it more difficult to implement certain types of ballot initiatives in the future is currently the subject of a legal challenge and may be invalidated. +• +Proposals are made from time to time to amend U.S. federal and state income tax laws in ways that would be adverse to us, including by eliminating certain key U.S. federal income tax preferences currently available with respect to crude oil and natural gas exploration and production. The changes could include (i) the repeal of the percentage depletion deduction for crude oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Also, state severance taxes may increase in the states in which we operate. This could adversely affect our existing operations in the relevant state and the economic viability of future drilling. +• +The development of new environmental initiatives or regulations related to the acquisition, withdrawal, storage, and use of surface water or groundwater, or treatment and discharge of water waste, may limit our ability to use techniques such as hydraulic fracturing, increase our development and operating costs and cause delays, +25 +interruptions or termination of our operations, any of which could have an adverse effect on our operations and financial condition. +See Items 1 and 2, Business and Properties - Governmental Regulation for a summary of certain laws and regulations that currently apply to us. Any of such laws and regulations could be amended, and new laws or regulations could be implemented, in a way that adversely affects our operations. +In addition, the election of President Trump has resulted in uncertainty with respect to the future regulatory environment affecting the oil and natural gas industry. This uncertainty may affect how our industry is regulated as well as the level of public interest in environmental protection and may result in new or different pressures being exerted. For example, public interest groups may increase their use of litigation as a means of continuing to exert pressure on the oil and natural gas industry. Accordingly, while we expect regulatory and enforcement pressures on our business to continue at federal, state, and local levels, the nature, level, and source of such pressures may change. +Our ability to produce crude oil, natural gas, and NGLs economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of or recycle the water we use at a reasonable cost and within applicable environmental rules. +Drilling and development activities such as hydraulic fracturing require the use of water and result in the production of wastewater. Our operations could be adversely impacted if we are unable to locate sufficient amounts of water or dispose of or recycle water used in our exploration and production operations. The quantity of water required in certain completion operations, such as hydraulic fracturing, and changing regulations governing usage may lead to water constraints and supply concerns, particularly in relatively arid climates such as eastern Colorado and western Texas. +As we turn-in-line wells in the Delaware Basin, we are seeing a greater volume of water recovery and production than originally anticipated. Our operations depend on being able to reuse or dispose of wastewater in a timely and economic fashion. Wastewater from oil and gas operations is often disposed of through underground injection. An increased number of earthquakes have been detected in the Delaware Basin in recent years. Some studies have linked earthquakes, or induced seismicity, in certain areas to underground injection, which is leading to increased public and regulatory scrutiny of injection safety. +Reduced commodity prices could result in significant impairment charges and significant downward revisions of proved reserves. +Commodity prices are volatile. Significant and rapid declines in prices have occurred in the past and may occur in the future. Low commodity prices could result in, among other things, significant impairment charges. The cash flow model we use to assess properties for impairment includes numerous assumptions, such as management’s estimates of future oil and gas production and commodity prices, the outlook for forward commodity prices and operating and development costs. All inputs to the cash flow model must be evaluated at each date the estimate of future cash flows for each producing basin is calculated. However, a significant decrease in long-term forward prices alone could result in a significant impairment for our properties that are sensitive to declines in prices. We have incurred impairment charges in a number of recent periods, including charges of $251.6 million to write down assets and $ 75.1 million to impair goodwill associated with our acquisition in the Delaware Basin in 2017 and $150.3 million to write down our Utica Shale producing and non-producing crude oil and natural gas properties to their estimated fair value in 2015. Similar charges could occur in the future. +Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves. +Calculating reserves for crude oil, natural gas, and NGLs requires subjective estimates of remaining volumes of underground accumulations of hydrocarbons. Assumptions are also made concerning commodity prices, production levels, and operating and development costs over the economic life of the properties. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate. Independent petroleum engineers prepare our estimates of crude oil, natural gas, and NGLs reserves using pricing, production, cost, tax and other information that we provide. The reserve estimates are based on assumptions regarding commodity prices, production levels, and operating and development costs that may prove to be incorrect. Any significant variance from these assumptions to actual results could greatly affect: +• +the economically recoverable quantities of crude oil, natural gas, and NGLs attributable to any particular group of properties; +26 +• +future depreciation, depletion, and amortization (“DD&A”) rates and amounts; +• +impairments in the value of our assets; +• +the classifications of reserves based on risk of recovery; +• +estimates of future net cash flows; +• +timing of our capital expenditures; and +• +the amount of funds available for us to borrow under our revolving credit facility. +Some of our reserve estimates must be made with limited production histories, which renders these estimates less reliable than those based on longer production histories. Further, reserve estimates are based on the volumes of crude oil, natural gas, and NGLs that are anticipated to be economically recoverable from a given date forward based on economic conditions that exist at that date. The actual quantities of crude oil, natural gas, and NGLs recovered will be different than the reserve estimates since they will not be produced under the same economic conditions as are used for the reserve calculations. In addition, quantities of probable and possible reserves by definition are inherently more risky than proved reserves, in part because they have greater uncertainty associated with the recoverable quantities of hydrocarbons. +At December 31, 2017, approximately 68 percent of our estimated proved reserves were undeveloped. These reserve estimates reflect our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including approximately $2.8 billion during the five years ending December 31, 2022, as estimated in the calculation of the standardized measure of oil and gas activity. The estimated development costs may not be accurate, development may not occur as scheduled and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of initial booking, and we may therefore be required to downgrade any PUDs that are not developed within this five-year time frame. +The present value of the estimated future net cash flows from our proved reserves is not necessarily the same as the current market value of those reserves. Pursuant to SEC rules, the estimated discounted future net cash flows from our proved reserves, and the estimated quantity of those reserves, are based on the prior year’s first day of the month 12-month average crude oil and natural gas index prices. However, factors such as actual prices we receive for crude oil and natural gas and hedging instruments, the amount and timing of actual production, the amount and timing of future development costs, the supply of and demand for crude oil, natural gas, and NGLs, and changes in governmental regulations or taxation, also affect our actual future net cash flows from our properties. The timing of both our production and incurrence of expenses in connection with the development and production of crude oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10 percent discount factor we use when calculating discounted future net cash flows (the rate required by the SEC) may not be the most appropriate discount factor based on interest rates currently in effect and risks associated with our properties or the industry in general. +Unless reserves are replaced as they are produced, our reserves and production will decline, which would adversely affect our future business, financial condition and results of operations. We may not be able to develop our identified drilling locations as planned. +Producing crude oil, natural gas, and NGL reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline may change over time and may exceed our estimates. Our future reserves and production and, therefore, our cash flows and income, are highly dependent on our ability to efficiently develop and exploit our current reserves and to economically find or acquire additional recoverable reserves. We may not be able to develop, discover, or acquire additional reserves to replace our current and future production at acceptable costs. Our failure to do so would adversely affect our future operations, financial condition and results of operations. +We have identified a number of well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including: +• +crude oil, natural gas, and NGL prices; +• +the availability and cost of capital; +• +drilling and production costs; +• +availability of drilling services and equipment; +• +drilling results; +• +lease expirations or limitations as to depth; +• +midstream constraints; +27 +• +access to and availability of water sourcing and distribution systems; +• +regulatory approvals; and +• +other factors. +Because of these factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce crude oil, natural gas, or NGLs from these or any other potential well locations. In addition, the number of drilling locations available to us will depend in part on the spacing of wells in our operating areas. An increase in well density in an area could result in additional locations in that area, but a reduced production performance from the area on a per-well basis. Further, certain of the horizontal wells we intend to drill in the future may require pooling of our lease interests with the interests of third parties. Some states, including Colorado, allow the involuntary pooling of tracts in a relatively broad number of circumstances in order to facilitate exploration. Other states, including Texas, restrict involuntary pooling to a narrower set of circumstances and consequently these states rely primarily on voluntary pooling of lands and leases. In states where pooling is accomplished primarily on a voluntary basis, it may be more difficult to form units and, therefore, more difficult to fully develop a project if we own less than all the leasehold or one or more of our leases does not provide the necessary pooling authority. If third parties are unwilling to pool their interests with ours, we may be unable to require such pooling on a timely basis or at all, and this would limit the total locations we can drill. Further, the number of available locations will depend in part on the expected lateral lengths of the wells we drill. Because the intended lateral length of a well is subject to change for a variety of reasons, our estimated drilling locations will change over time. For this or numerous other reasons, our actual drilling activities may materially differ from those presently identified. +Our inventory of drilling projects includes locations in addition to those that we currently classify as proved, probable, and possible. The development of and results from these additional projects are more uncertain than those relating to probable and possible locations, and significantly more uncertain than those relating to proved locations. We have generally accelerated the pace of our development activities in the Wattenberg Field over the past several years, and this has reduced our related inventory of drilling locations. +The wells we drill may not yield crude oil, natural gas, or NGLs in commercially viable quantities and productive wells may be less successful than we expect. +A prospect is a property on which our geologists have identified what they believe, based on available information, to be indications of hydrocarbon-bearing rocks. However, given the limitations of available data and technology, our geologists cannot know conclusively prior to drilling and testing whether crude oil, natural gas, or NGLs will be present in sufficient quantities to repay drilling or completion costs and generate a profit. Furthermore, even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques do not enable our geologists to be certain as to the quantity of the hydrocarbons in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures, which may result in a reduction in our returns or losses. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline. If a well is determined to be dry or uneconomic, which can occur even though it contains some crude oil, natural gas, or NGLs, it is classified as a dry hole and must be plugged and abandoned in accordance with applicable regulations. This generally results in the loss of the entire cost of drilling and completion to that point, the cost of plugging, and lease costs associated with the prospect. Even wells that are completed and placed into production may not produce sufficient crude oil, natural gas, and NGLs to be profitable, or they may be less productive and/or profitable than we expected. In some recent periods we have been able to achieve reductions in drilling and completion costs in connection with lower commodity prices. However, as commodity prices have increased since mid-2016, many of these costs have increased, and further increases are expected. If we drill a dry hole or unprofitable well on a current or future prospect, or if drilling or completion costs increase, the profitability of our operations will decline and the value of our properties will likely be reduced. Exploratory drilling is typically subject to substantially greater risk than development drilling. In addition, initial results from a well are not necessarily indicative of its performance over a longer period. +Drilling for and producing crude oil, natural gas, and NGLs are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations. +28 +Drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling can be unprofitable, not only due to dry holes, but also due to curtailments, delays, or cancellations as a result of other factors, including: +• +unusual or unexpected geological formations; +• +pressures; +• +fires; +• +floods; +• +loss of well control; +• +loss of drilling fluid circulation; +• +title problems; +• +facility or equipment malfunctions; +• +unexpected operational events; +• +shortages or delays in the delivery of equipment and services; +• +unanticipated environmental liabilities; +• +compliance with environmental and other governmental requirements; and +• +adverse weather conditions. +Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells, and regulatory penalties. For example, a loss of containment of hydrocarbons during drilling activities could potentially subject us to civil and/or criminal liability and the possibility of substantial costs, including for environmental remediation. We maintain insurance against various losses and liabilities arising from our operations; however, insurance against certain operational risks may not be available or may be prohibitively expensive relative to the perceived risks presented. For example, we may not have coverage with respect to a pollution event if we are unaware of the event while it is occurring and are therefore unable to report the occurrence of the event to our insurance company within the time frame required under our insurance policy. Thus, losses could occur for uninsurable or uninsured risks or for amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance and/or governmental or third party responses to an event could have a material adverse effect on our business activities, financial condition and results of operations. We are currently involved in various remedial and investigatory activities at some of our wells and related sites. +Prior to 2012, most of the wells we drilled were vertical wells. Since 2012, however, we have devoted the majority of our capital to drilling horizontal wells. Drilling horizontal wells is technologically more difficult than drilling vertical wells - including as a result of risks relating to our ability to fracture stimulate the planned number of stages and to successfully run casing the length of the well bore - and the risk of failure is therefore greater than the risk involved in drilling vertical wells. Additionally, drilling a horizontal well is typically far costlier than drilling a vertical well. This means that the risks of our drilling program will be spread over a smaller number of wells, and that, in order to be economic, each horizontal well will need to produce at a higher level in order to cover the higher drilling costs. Similarly, the average lateral length of the horizontal wells we drill has generally been increasing. Longer-lateral wells are typically more expensive and require more time for preparation and permitting. In addition, we have transitioned to the use of multi-well pads instead of single-well sites. The use of multi-well pad drilling increases some operational risks because problems affecting the pad or a single well could adversely affect production from all of the wells on the pad. Pad drilling can also make our overall production, and therefore our revenue and cash flows, more volatile, because production from multiple wells on a pad will typically commence simultaneously. While we believe that we will be better served by drilling horizontal wells using multi-well pads, the risk component involved in such drilling will be increased in some respects, with the result that we might find it more difficult to achieve economic success in our drilling program. +The inability of one or more of our customers or other counterparties to meet their obligations may adversely affect our financial results. +Substantially all of our accounts receivable result from our crude oil, natural gas, and NGLs sales or joint interest billings to a small number of third parties in the energy industry. This concentration of customers and joint interest owners may affect our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our commodity derivatives expose us to credit risk in the event of nonperformance by counterparties. Nonperformance by our customers or derivative counterparties may adversely affect our financial condition and profitability. We face similar risks with respect to our other counterparties, including the lenders under our revolving credit facility and the providers of our insurance coverage. +Seasonal weather conditions and lease stipulations can adversely affect our operations. +29 +Seasonal weather conditions and lease stipulations designed to prohibit or limit operations during crop-growing seasons and to protect wildlife affect operations in some areas. In certain areas drilling and other activities may be restricted or prohibited by lease stipulations, or prevented by weather conditions, for significant periods of time. This limits our operations in those areas and can intensify competition during the active months for drilling rigs, equipment, supplies, chemicals, personnel, and oilfield services, which may lead to additional or increased costs or periodic shortages. These constraints, and the resulting high costs or shortages, could delay our operations and materially increase operating and capital costs and therefore adversely affect our profitability. Similarly, hot weather during some recent periods adversely impacted the operation of certain midstream facilities, and therefore our production. Similar events could occur in the future and could negatively impact our results of operations and cash flows. +We have limited control over activities on properties in which we own an interest but we do not operate, which could reduce our production and revenues. +We operate approximately 87 percent of the wells in which we own an interest. If we do not operate a property, we do not have control over normal operating procedures, expenditures or future development of the property. The success and timing of drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise (including safety and environmental compliance) and financial resources, inclusion of other participants in drilling wells, and use of technology. The failure by an operator to adequately perform operations, or an operator’s breach of the applicable agreements, could reduce production and revenues and adversely affect our profitability. These risks may be heightened during periods of depressed commodity prices as operators may propose operations that we believe to be economically unattractive, leading us to incur non-consent penalties. Our lack of control over non-operated properties also makes it more difficult for us to forecast capital expenditures, production and related matters +We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects. +We frequently own less than all of the working interest in the oil and gas leases on which we conduct operations. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities, arising from the actions of the other owners. In addition, declines in oil, natural gas, and NGL prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, may declare bankruptcy. In the event any of our project partners does not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover the costs from the partner. This could materially adversely affect our financial position. +We may not be able to keep pace with technological developments in our industry. +Our industry is characterized by rapid and significant technological advancements. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those or other new technologies at substantial cost. In addition, our competitors may have greater financial, technical, and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we were unable to use the most advanced technology, our business, financial condition and results of operations could be materially adversely affected. +Competition in our industry is intense, which may adversely affect our ability to succeed. +Our industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce crude oil, natural gas, and NGLs, but also carry on refining operations and market petroleum and other products on a regional, national, or worldwide basis. These companies may be able to pay more for productive properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, larger companies may have a greater ability to continue exploration activities during periods of low commodity prices. Larger competitors may also be able to absorb the burden of present and future federal, state, local, and other laws and regulations more easily than we can, which could adversely affect our competitive position. These factors could adversely affect our operations and our profitability. +30 +Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel. +Our future success depends to a large extent on the services of our key employees. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise. +A failure to complete successful acquisitions would limit our growth. +Because our crude oil and natural gas properties are depleting assets, our future reserves, production volumes, and cash flows depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. In addition, we continue to strive to achieve greater efficiencies in our drilling program, and our ability to do so is dependent in part on our ability to complete asset exchanges and other acquisitions that allow us to increase our working interests in particular properties. When attractive opportunities arise, acquiring additional crude oil and natural gas properties, or businesses that own or operate such properties, is a significant component of our strategy. We may not be able to identify attractive acquisition opportunities. If we do identify an appropriate acquisition candidate, we may be unable to negotiate mutually acceptable terms with the seller, finance the acquisition or obtain the necessary regulatory approvals. It may be difficult to agree on the economic terms of a transaction, as a potential seller may be unwilling to accept a price that we believe to be appropriately reflective of prevailing economic conditions. If we are unable to complete suitable acquisitions, it will be more difficult to replace our reserves, and an inability to replace our reserves would have a material adverse effect on our financial condition and results of operations. +Acquisitions of properties are subject to the uncertainties of evaluating recoverable reserves and potential liabilities, including environmental uncertainties. +Acquisitions of producing and undeveloped properties have been an important part of our growth over time. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, development potential, future commodity prices, operating costs, title issues, and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we generally perform engineering, environmental, geological, and geophysical reviews of the acquired properties that we believe are generally consistent with customary industry practices. However, such reviews are not likely to permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well prior to an acquisition and our ability to evaluate undeveloped acreage is inherently imprecise. Even when we inspect a well, we may not always discover structural, subsurface, and environmental problems that may exist or arise. In some cases, our review prior to signing a definitive purchase agreement may be even more limited. In addition, we often acquire acreage without any warranty of title except as to claims made by, through or under the transferor. +When we acquire properties, we will generally have potential exposure to liabilities and costs for environmental and other problems existing on the acquired properties, and these liabilities may exceed our estimates. We may not be entitled to contractual indemnification associated with acquired properties. We often acquire interests in properties on an “as is” basis with no or limited remedies for breaches of representations and warranties. Therefore, we could incur significant unknown liabilities, including environmental liabilities or losses due to title defects, in connection with acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, the acquisition of undeveloped acreage is subject to many inherent risks and we may not be able to realize efficiently, or at all, the assumed or expected economic benefits of acreage that we acquire. +Additionally, significant acquisitions can change the nature of our operations depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or may be in different geographic locations than our existing properties. These factors can increase the risks associated with an acquisition. Acquisitions also present risks associated with the additional indebtedness that may be required to finance the purchase price, and any related increase in interest expense or other related charges. +Some of our acquisitions are structured as asset trades or exchanges. These transactions may give rise to any or all of the foregoing risks. In addition, transactions of this type create a risk that we will undervalue the properties we transfer to the counterparty in the trade or exchange or overvalue the properties we receive. Such an undervaluation or overvaluation would result in the transaction being less favorable to us than we expected. +31 +We operate in a litigious environment. The cost of defending any suits brought against us, and any judgments or settlements resulting from such suits, could have an adverse effect on our results of operations and financial condition. +Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, employment litigation, regulatory compliance matters, and personal injury or property damage matters, in the ordinary course of our business. For example, in recent years, we have been subject to lawsuits regarding royalty practices and payments and matters relating to certain of our affiliated partnerships. As discussed in the footnote titled Commitments and Contingencies to our consolidated financial statements included elsewhere in this report, we are the subject of a recently filed lawsuit relating to our two remaining affiliated partnerships, and the strained financial condition of those partnerships makes additional litigation more likely. The outcome of legal proceedings is inherently uncertain. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management attention and other factors. In addition, the resolution of such a proceeding could result in penalties or sanctions, settlement costs and/or judgments, consent decrees, or orders requiring a change in our business practices, any of which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties, sanctions or costs may be insufficient. Judgments and estimates to determine accruals or the anticipated range of potential losses related to legal and other proceedings could change from one period to the next, and such changes could be material. Information regarding our legal proceedings can found in the footnote titled Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere in this report. +Our business could be negatively impacted by security threats, including cybersecurity threats, and other disruptions. +We face various security threats, including attempts by third parties to gain unauthorized access to competitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. There can be no assurance that the procedures and controls we use to monitor these threats and mitigate our exposure to them will be sufficient in preventing them from materializing. +Our industry has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain exploration, development, and production activities. We depend on digital technology, including information systems and related infrastructure, as well as cloud applications and services, to store, transmit, process, and record sensitive information (including but not limited to trade secrets, employee information, and financial and operating data), communicate with our employees and business partners, and for many other activities related to our business. The complexity of the technologies needed to explore for and develop crude oil, natural gas, and NGLs make certain information more attractive to thieves. +As dependence on digital technologies has increased in our industry, cyber incidents, including deliberate attacks and unintentional events, have also increased. A cyber-attack could include an attempt to gain unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption. “Phishing” and other types of attempts to obtain unauthorized information or access are often sophisticated and difficult to detect or defeat. +Our business partners, including vendors, service providers, operating partners, purchasers of our production, and financial institutions, are also dependent on digital technology. A vulnerability in the cybersecurity of one or more of our vendors could facilitate an attack on our systems. +Our technologies, systems and networks, and those of our business partners, may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, theft of property or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Although we have not suffered material losses related to cyber-attacks to date, if we were successfully attacked, we could incur substantial remediation and other costs or suffer other negative consequences, such as a loss of competitive information, critical infrastructure, personnel or capabilities essential to our operations. Events of this nature could have a material adverse effect on our reputation, financial condition, results of operations, or cash flows. Moreover, as the sophistication of cyber-attacks continues to evolve, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities. +The physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. +32 +Many scientists believe that increasing concentrations of carbon dioxide, methane, and other GHGs in the Earth's atmosphere are changing global climate patterns. One consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. Flooding that occurred in Colorado in 2013 is an example of an extreme weather event that negatively impacted our operations. If such events were to continue to occur, or become more frequent, our operations could be adversely affected in various ways, including through damage to our facilities or from increased costs for insurance. +Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our production could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business. +Risks Relating to Financial Matters +Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our production and reserves, and ultimately our profitability. +Our industry is capital intensive. We expect to continue to make substantial capital expenditures for the exploration, development, production and acquisition of crude oil, natural gas, and NGL reserves. To date, we have financed capital expenditures primarily with bank borrowings under our revolving credit facility, cash generated by operations and proceeds from capital markets transactions and the sale of properties. We intend to finance our future capital expenditures utilizing similar financing sources. Our cash flows from operations and access to capital are subject to a number of variables, including: +• +our proved reserves; +• +the amount of crude oil, natural gas, and NGLs we are able to produce from existing wells; +• +the prices at which crude oil, natural gas, and NGLs are sold; +• +the costs to produce crude oil, natural gas, and NGLs; and +• +our ability to acquire, locate and produce new reserves. +If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower commodity prices, operating difficulties or for any other reason, our need for capital from other sources could increase, and there can be no assurance that such other sources of capital would be available at that time on reasonable terms or at all. If we raise funds by issuing additional equity securities, this would have a dilutive effect on existing shareholders. If we raise funds through the incurrence of debt, the risks we face with respect to our indebtedness would increase and we would incur additional interest expense. Our inability to obtain sufficient financing on acceptable terms would adversely affect our financial condition and profitability. +We have a substantial amount of debt and the cost of servicing, and risks related to refinancing, that debt could adversely affect our business. Those risks could increase if we incur more debt. +We have a substantial amount of indebtedness outstanding. As a result, a significant portion of our cash flows will be required to pay interest and principal on our indebtedness, and we may not generate sufficient cash flows from operations, or have future borrowing capacity available, to enable us to repay our indebtedness or to fund other liquidity needs. +Servicing our indebtedness and satisfying our other obligations will require a significant amount of cash. Our cash flow from operating activities and other sources may not be sufficient to fund our liquidity needs. Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend on our future operating performance, our financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control. We cannot assure you that our business will generate sufficient cash flow from operations, or that sufficient future borrowings will be available to us under our revolving credit facility or otherwise, to fund our liquidity needs. +A substantial decrease in our operating cash flow or an increase in our expenses could make it difficult for us to meet debt service requirements and could require us to modify our operations, including by curtailing our exploration and drilling programs, selling assets, reducing our capital expenditures, refinancing all or a portion of our existing debt or obtaining +33 +additional financing. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. +In addition, the terms of our debt agreements could restrict us from implementing some of these alternatives. In the absence of adequate cash from operations and other available capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. We may not be able to consummate these dispositions for fair market value, in a timely manner or at all. Furthermore, any proceeds that we could realize from any dispositions may not be adequate to meet our debt service obligations then due. +Covenants in our debt agreements currently impose, and future financing agreements may impose, significant operating and financial restrictions. +Our current debt agreements contain restrictions, and future financing agreements may contain additional restrictions, on our activities, including covenants that restrict our and our restricted subsidiaries’ ability to: +• +incur additional debt; +• +pay dividends on, redeem or repurchase stock; +• +create liens; +• +make specified types of investments; +• +apply net proceeds from certain asset sales; +• +engage in transactions with our affiliates; +• +engage in sale and leaseback transactions; +• +merge or consolidate; +• +restrict dividends or other payments from restricted subsidiaries; +• +sell equity interests of restricted subsidiaries; and +• +sell, assign, transfer, lease, convey or dispose of assets. +Our revolving credit facility is secured by substantially all of our oil and gas properties as well as a pledge of all ownership interests in operating subsidiaries. The restrictions contained in our debt agreements may prevent us from taking actions that we believe would be in the best interest of our business, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. We may also incur future debt obligations that subject us to additional restrictive covenants. +Our revolving credit facility has substantial restrictions and financial covenants and our ability to comply with those restrictions and covenants is uncertain. Our lenders can unilaterally reduce our borrowing availability based on anticipated commodity prices. +We expect to depend on our revolving credit facility for part of our future capital needs. The terms of the credit agreement require us to comply with certain financial covenants. Our ability to comply with these covenants in the future is uncertain and will be affected by the levels of cash flows from operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the revolving credit facility or other debt agreements could result in a default under those agreements, which could cause all of our existing indebtedness to become immediately due and payable. +The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based upon projected revenues from the properties securing their loan. Decreases in the price of crude oil, natural gas, or NGLs can be expected to have an adverse effect on the borrowing base. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Outstanding borrowings in excess of the borrowing base must be repaid immediately unless we pledge other crude oil and natural gas properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility. Our inability to borrow additional funds under our revolving credit facility could adversely affect our operations and our financial results. +34 +If we are unable to comply with the restrictions and covenants in our debt agreements, the resulting default could lead to an acceleration of payment of funds that we have borrowed and we may not have or be able to obtain the funds necessary to repay those amounts. +Any default under the agreements governing our indebtedness, including a default under our revolving credit facility that is not waived by the required lenders, and the remedies sought by the holders of any such indebtedness, could make us unable to pay principal and interest on our indebtedness and satisfy our other obligations. If we are unable to generate sufficient cash flows and are otherwise unable to obtain the funds necessary to meet required payments of principal and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. In the event of such a default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our revolving credit facility could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation. In addition, the default could result in a cross-default under other debt agreements. If our operating performance declines, we may in the future need to seek waivers from the required lenders under our revolving credit facility to avoid being in default and we may not be able to obtain such a waiver. If this occurs and no waiver is obtained, we would be in default under our revolving credit facility, the lenders could exercise their rights as described above, and we could be forced into bankruptcy or liquidation. We cannot assure you that we will be granted waivers or amendments to our debt agreements if for any reason we are unable to comply with these agreements, or that we will be able to refinance our debt on terms acceptable to us, or at all. +Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly. +Borrowings under our revolving credit facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase although the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness and for other purposes would decrease. +Notwithstanding our current indebtedness levels and restrictive covenants, we may still be able to incur substantial additional debt, which could exacerbate the risks described above. +We may be able to incur additional debt in the future. Although our debt agreements contain restrictions on our ability to incur indebtedness, those restrictions are subject to a number of exceptions. In particular, we may borrow under the revolving credit facility. We may also consider investments in joint ventures or acquisitions that may increase our indebtedness. Adding new debt to current debt levels could intensify the related risks that we and our subsidiaries now face. +Under the “successful efforts” accounting method that we use, unsuccessful exploratory wells must be expensed in the period in which they are determined to be non-productive, which reduces our net income in such periods. +We conduct exploratory drilling in order to identify additional opportunities for future development. Under the “successful efforts” method of accounting that we use, the cost of unsuccessful exploratory wells must be charged to expense in the period in which the wells are determined to be unsuccessful. In addition, lease costs for acreage condemned by the unsuccessful well must also be expensed. In contrast, unsuccessful development wells are capitalized as a part of the investment in the field where they are located. The costs of unsuccessful exploratory wells could result in a significant reduction in our profitability in periods in which the costs are required to be expensed. +Our commodity derivative activities could result in financial losses or reduced income from failure to perform by our counterparties, could limit our potential gains from increases in prices and could result in volatility in our net income. +We use commodity derivatives for a portion of the production from our own wells and for natural gas purchases and sales by our marketing subsidiary to achieve more predictable cash flows, to reduce exposure to adverse fluctuations in commodity prices, and to allow our natural gas marketing company to offer pricing options to natural gas sellers and purchasers. These arrangements expose us to the risk of financial loss in some circumstances, including when purchases or sales are different than expected or the counterparty to the commodity derivative contract defaults on its contractual obligations. In addition, many of our commodity derivative contracts are based on WTI or another crude oil or natural gas index price. The risk that the differential between the index price and the price we receive for the relevant production may change unexpectedly makes it more difficult to hedge effectively and increases the risk of a hedging-related loss. Also, commodity derivative arrangements may limit the benefit we would otherwise receive from increases in the prices for the relevant commodity, and they may require the use of our resources to meet cash margin requirements. +35 +At December 31, 2017, we had hedged a total of 18,484 MBbls of crude oil and 56,510 BBtu of natural gas for 2018 and 2019. These hedges may be inadequate to protect us from continuing and prolonged declines in crude oil and natural gas prices, and our current hedge position is smaller, and its estimated fair value is lower, than our hedge position in some recent periods. +Since we do not designate our commodity derivatives as cash flow hedges, we do not currently qualify for use of hedge accounting; therefore, changes in the fair value of commodity derivatives are recorded in our income statements, and our net income is subject to greater volatility than it would be if our commodity derivative instruments qualified for hedge accounting. For instance, if commodity prices rise significantly, this could result in significant non-cash charges during the relevant period, which could have a material negative effect on our net income. +Our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur. +The occurrence of a significant accident or other event that is not fully covered by insurance, not properly or timely noticed to our carrier, or that is in excess of our insurance coverage could have a material adverse effect on our operations and financial condition. Insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. In addition, pollution and environmental risks are generally not fully insurable. +The price of our common stock has been and may continue to be highly volatile, which may make it difficult for shareholders to sell our common stock when desired or at attractive prices. +The market price of our common stock is highly volatile, and we expect it to continue to be volatile for the foreseeable future. Adverse events could trigger declines in the price of our common stock, including, among others: +• +changes in production volumes, worldwide demand and prices for crude oil and natural gas; +• +changes in market prices of crude oil and natural gas; +• +inability to hedge future production at the same pricing level as our current or prior hedges; +• +changes in securities analysts’ estimates of our financial performance; +• +fluctuations in stock market prices and volumes, particularly among securities of energy companies; +• +changes in market valuations and valuation multiples of similar companies; +• +changes in interest rates; +• +announcements regarding adverse timing or lack of success in discovering, acquiring, developing, and producing crude oil and natural gas resources; +• +announcements by us or our competitors of significant contracts, new acquisitions, discoveries, commercial relationships, joint ventures, or capital commitments; +• +decreases in the amount of capital available to us, including as a result of borrowing base reductions and/or lenders ceasing to participate in our revolving credit facility syndicate; +• +operating results that fall below market expectations or variations in our quarterly operating results; +• +loss of a major customer; +• +loss of a relationship with a partner; +• +the identification of and severity of environmental events and governmental and other third-party responses to the events; or +• +additions or departures of key personnel. +External events, such as news concerning economic conditions, counterparties to our natural gas or crude oil derivatives arrangements, changes in government regulations impacting the crude oil and natural gas exploration and production industry or the movement of capital into or out of our industry, are also likely to affect the price of our common stock, regardless of our operating performance. For example, there have been recent efforts by some investment advisers, sovereign wealth funds, public pension funds, universities, and other investment groups to divest themselves from investments in companies involved in fossil fuel extraction, and these efforts could reduce the trading prices of our securities. Similarly, our stock price could be adversely affected by changes in the way that analysts and investors assess the geological and economic characteristics of the basins in which we operate. Furthermore, general market conditions, including the level of, and fluctuations in, the trading prices of stocks generally could affect the price of our common stock. The stock markets regularly experience price and volume volatility that affects many companies’ stock prices without regard to the operating performance of those companies. Volatility of this type may affect the trading price of our common stock. Similar factors could also affect the trading prices of our senior notes. +36 +We have identified material weaknesses in our internal control over financial reporting which could, if not remediated, result in material misstatements in our financial statements. +As disclosed in Item 9A - Controls and Procedures , management identified certain material weaknesses in our internal control over precision of the review of supporting documentation regarding the completeness and accuracy of certain land administrative records. Because of these material weaknesses, our management concluded that we did not maintain effective internal control over financial reporting as of December 31, 2017. A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. +With the oversight of the audit committee, we have begun taking steps to remediate the underlying cause of these material weaknesses and improve the design of controls. We cannot assure you that we will adequately remediate the material weaknesses or that additional material weaknesses in our internal controls will not be identified in the future. Any failure to maintain or implement required new or improved controls, or any difficulties we encounter in their implementation, could result in additional material weaknesses, or could result in material misstatements in our financial statements. These misstatements could result in restatements of our financial statements, cause us to fail to meet our reporting obligations, or cause investors to lose confidence in our reported financial information. Further and continued determinations that there are material weaknesses in the effectiveness of our internal controls could reduce our ability to obtain financing or could increase the cost of any financing we obtain and require additional expenditures of resources to comply with applicable requirements. +Derivatives legislation and regulation could adversely affect our ability to hedge crude oil and natural gas prices and increase our costs and adversely affect our profitability. +In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was enacted into law. The Dodd-Frank Act regulates derivative transactions, including our commodity hedging swaps, and could have a number of adverse effects on us, including the following: +• +The Dodd-Frank Act may limit our ability to enter into hedging transactions, thus exposing us to additional risks related to commodity price volatility; commodity price decreases would then have an increased adverse effect on our profitability and revenues. Reduced hedging may also impair our ability to have certainty with respect to a portion of our cash flows, which could lead to decreases in capital spending and, therefore, decreases in future production and reserves. +• +If, as a result of the Dodd-Frank Act or its implementing regulations, we are required to post cash collateral in connection with our derivative positions, this would likely make it impracticable to implement our current hedging strategy. +• +Our derivatives counterparties are subject to significant requirements imposed as a result of the Dodd-Frank Act. We expect that these requirements will increase the cost to hedge because there will be fewer counterparties in the market and increased counterparty costs will be passed on to us. +The above factors could also affect the pricing of derivatives and make it more difficult for us to enter into hedging transactions on favorable terms. +37 +ITEM 1B. UNRESOLVED STAFF COMMENTS +None. +ITEM 3. LEGAL PROCEEDINGS +Information regarding our legal proceedings can found in the footnote titled Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere in this report. +ITEM 4. MINE SAFETY DISCLOSURES +Not applicable. +38 +PART II +ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES +Our common stock, par value $0.01 per share, is traded on the NASDAQ Global Select Market under the symbol PDCE. The following table sets forth the range of high and low sales prices for our common stock based on intra-day trading for each of the periods presented: +High +Low +January 1 - March 31, 2016 +$ +60.56 +$ +42.68 +April 1 - June 30, 2016 +65.86 +51.92 +July 1 - September 30, 2016 +71.00 +50.12 +October 1 - December 31, 2016 +84.88 +59.82 +January 1 - March 31, 2017 +78.61 +60.27 +April 1 - June 30, 2017 +65.99 +40.12 +July 1 - September 30, 2017 +50.51 +36.74 +October 1 - December 31, 2017 +53.41 +41.13 +As of February 15, 2018 , we had approximately 589 stockholders of record. Since inception, no cash dividends have been declared on our common stock. Cash dividends are restricted under the terms of our revolving credit facility as well as the indentures governing our 6.125% senior notes due September 15, 2024 (the "2024 Senior Notes") and our 2026 Senior Notes, and we presently intend to continue a policy of using retained earnings for the expansion of our business. +The following table presents information about our purchases of our common stock during the three months ended December 31, 2017 : +Period +Total Number of Shares Purchased (1) +Average Price Paid per Share +October 1 - 31, 2017 +5,636 +$ +48.88 +November 1 - 30, 2017 +— +— +December 1 - 31, 2017 +21,301 +50.68 +Total fourth quarter 2017 purchases +26,937 +50.30 +__________ +(1) +Purchases primarily represent shares purchased from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans. +39 +STOCKHOLDER PERFORMANCE GRAPH +The performance graph below compares the cumulative total return of our common stock over the five-year period ended December 31, 2017 with the cumulative total returns for the same period for the Standard and Poor's ("S&P") 500 Index and the Standard Industrial Code ("SIC") Index. The SIC Index is a weighted composite of 233 crude petroleum and natural gas companies. The cumulative total stockholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on December 31, 2012 , and in the S&P 500 Index and the SIC Index on the same date. The results shown in the graph below are not necessarily indicative of future performance. +40 +ITEM 6. SELECTED FINANCIAL DATA +Year Ended/As of December 31, +2017 +2016 (1) +2015 +2014 +2013 +(in millions, except per share data and as noted) +Statement of Operations (From Continuing Operations) (2): +Crude oil, natural gas, and NGLs sales +$ +913.1 +$ +497.4 +$ +378.7 +$ +471.4 +$ +340.8 +Commodity price risk management gain (loss), net +(3.9 +) +(125.7 +) +203.2 +310.3 +(23.9 +) +Total revenues +921.6 +382.9 +595.3 +856.2 +392.7 +Income (loss) from continuing operations +(127.5 +) +(245.9 +) +(68.3 +) +107.3 +(21.1 +) +Earnings per share from continuing operations: +Basic +$ +(1.94 +) +$ +(5.01 +) +$ +(1.74 +) +$ +3.00 +$ +(0.65 +) +Diluted +(1.94 +) +(5.01 +) +(1.74 +) +2.93 +(0.65 +) +Statement of Cash Flows: +Net cash flows from: +Operating activities +$ +588.6 +$ +486.3 +$ +411.1 +$ +236.7 +$ +159.2 +Investing activities +(717.0 +) +(1,509.1 +) +(604.3 +) +(474.1 +) +(217.1 +) +Financing activities +65.0 +1,266.1 +178.0 +60.3 +248.7 +Capital expenditures from development and exploration activities (3) +737.2 +436.9 +599.5 +623.8 +384.7 +Acquisitions of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition +15.6 +1,073.7 +— +— +9.7 +Balance Sheet: +Total assets +$ +4,419.9 +$ +4,485.8 +$ +2,370.5 +$ +2,331.1 +$ +1,991.7 +Working capital (deficit) +(16.4 +) +129.2 +30.7 +89.5 +90.0 +Total debt, net of unamortized discount and debt issuance costs +1,151.9 +1,044.0 +642.4 +655.5 +593.9 +Total equity +2,507.6 +2,622.8 +1,287.2 +1,137.4 +967.6 +Average Pricing and Production Expenses From Continuing Operations (per Boe and as a percent of sales for production taxes): +Sales price (excluding net settlements on derivatives) +$ +28.69 +$ +22.43 +$ +24.64 +$ +50.72 +$ +52.23 +Lease operating expenses +$ +2.82 +$ +2.70 +$ +3.71 +$ +4.56 +$ +5.18 +Transportation, gathering, and processing +$ +1.04 +$ +0.83 +$ +0.66 +$ +0.49 +$ +0.79 +Production taxes +$ +1.91 +$ +1.42 +$ +1.20 +$ +2.76 +$ +3.33 +Production taxes as a percent of sales +6.6 +% +6.3 +% +4.9 +% +5.4 +% +6.4 +% +Production (MBoe): +Production from continuing operations +31,830 +22,176 +15,369 +9,294 +6,525 +Production from discontinued operations +— +— +— +1,093 +2,032 +Total production +31,830 +22,176 +15,369 +10,387 +8,557 +Total proved reserves (MMBoe) (4) +452.9 +341.4 +272.8 +250.1 +265.8 +______________ +(1) +In 2016, we closed an acquisition in the Delaware Basin for aggregate consideration of approximately $1.76 billion . See footnotes titled Properties and Equipment - Delaware Basin Acreage Acquisition and Business Combination to our consolidated financial statements included elsewhere in this report for further information regarding this acquisition. +(2) +In 2014, we completed the sale of our ownership interest in PDC Mountaineer, LLC ("PDCM"). Our proportionate share of PDCM's Marcellus Shale results of operations have been separately reported as discontinued operations. +(3) +Includes impact of change in accounts payable related to capital expenditures. +(4) +Includes total proved reserves related to our Marcellus Shale and shallow Upper Devonian Appalachian Basin assets of 40 MMBoe as of December 31, 2013. PDCM, which owned these reserves, was sold in late 2014. +41 +ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes thereto included elsewhere in this report. Further, we encourage you to revisit the Special Note Regarding Forward-Looking Statements in Part I of this report. +SUMMARY +2017 Financial Overview of Operations and Liquidity +Production volumes increased 44 percent to 31.8 MMBoe in 2017 compared to 2016, including 4.2 MMBoe contributed from the Delaware Basin assets that we acquired in December 2016. The increase in production volumes was primarily attributable to the continued success of our horizontal Niobrara and Codell drilling program in the Wattenberg Field and growing production from our horizontal Wolfcamp drilling program in our Delaware Basin properties. Crude oil production increased 48 percent in 2017 , which comprised approximately 41 percent of our total production. Natural gas production increased 39 percent and NGLs increased 45 percent in 2017 compared to 2016 . On a combined basis, total liquids production of crude oil and NGLs comprised 62 percent of production in 2017. For the month ended December 31, 2017 , we maintained an average production rate of approximately 97,000 Boe per day, including approximately 18,000 Boe per day from the Delaware Basin, up from approximately 73,200 Boe per day, including approximately 6,000 Boe per day from the Delaware Basin, for the month ended December 31, 2016 . +Crude oil, natural gas, and NGLs sales increased to $913.1 million in 2017 compared to $497.4 million in 2016 , due to a 44 percent increase in production, combined with a 28 percent increase in the weighted average realized commodity prices. Crude oil, natural gas, and NGLs sales increased 31 percent in 2016 as compared to 2015 due to a 44 percent increase in production, partially offset by a nine percent decrease in average realized commodity prices. +We had positive net settlements from our commodity derivative contracts of $13.3 million for 2017 , $208.1 million for 2016 , and $238.9 million for 2015 . We entered into agreements for the derivative instruments that settled throughout 2016 and 2015 prior to commodity prices becoming depressed in late 2014. Substantially all of these higher-value derivatives settled by the end of 2016. Net settlements for 2017 reflect derivative instruments entered into since 2015, which more closely approximate recent realized prices. See Results of Operations - Commodity Price Risk Management, Net for further details of our settlements of derivatives and changes in the fair value of unsettled derivatives . +The combined revenue from crude oil, natural gas, and NGLs sales and net settlements received on our commodity derivative instruments increased 31 percent to $926.4 million in 2017 from $705.5 million in 2016 . Such combined revenue of $705.5 million in 2016 increased 14 percent from $617.6 million in 2015 . +During 2017 , we recorded exploratory dry hole well expense of $41.3 million and an unproved and proved property impairment charge of $285.5 million , and we impaired all of the goodwill associated with the assets acquired in the Delaware Basin, which resulted in an impairment charge of $75.1 million. The majority of these charges are a result of our western Culberson County acreage not meeting our performance expectations. In addition, we recorded a loss on extinguishment of debt of $24.7 million related to the redemption of our 2022 Senior Notes. For more information regarding these expenses and charges see Results of Operations - Exploration, Geologic, and Geophysical Expense, Results of Operations - Impairments of Properties, Results of Operations - Impairment of Goodwill, and Results of Operations - Loss on Extinguishment of Debt . +In December 2017, the President of the United States signed into law the 2017 Tax Cuts and Jobs Act (the "2017 Tax Act"). We recorded the effects of changes in tax law in the period of enactment. The 2017 Tax Act reduces the corporate tax rate from 35 percent to 21 percent effective January 1, 2018. Consequently, we have decreased our deferred tax assets and deferred tax liabilities as of December 31, 2017. Since we are in a net deferred liability position at 2017 year end, the tax rate change resulted in a deferred tax benefit and corresponding reduction of our net deferred tax liability of approximately $114 million in 2017. +42 +In 2017 , we generated a net loss of $127.5 million or $1.94 per diluted share. Our net income was negatively impacted by the aforementioned impairment charges, expensing of exploratory dry hole well costs, and extinguishment of debt. During the same period, our adjusted EBITDAX, a non-U.S. GAAP financial measure, was $682.1 million , up 48 percent relative to 2016. The increase in our 2017 adjusted EBITDAX as compared to 2016 was primarily the result of the increase in crude oil, natural gas, and NGLs sales of $415.7 million , as well as the recording of a provision for a note receivable in 2016 of $44.0 million and the subsequent sale of the note in 2017 to a third-party for $40.2 million. These increases were partially offset by a decrease in derivative commodity settlements of $194.8 million and increases in operating costs of $81.7 million and interest expense of $16.7 million. Beginning in 2017, we have included non-cash stock-based compensation and exploration, geologic, and geophysical expense in our reconciliation of adjusted EBITDAX. In prior periods, we reported adjusted EBITDA, a non-U.S. GAAP financial measure that did not include these adjustments. All prior periods have been conformed for comparability of this updated EBITDAX presentation. In 2016 and 2015 , our net loss per diluted share was $5.01 and $1.74 , respectively, and our adjusted EBITDAX was $459.8 million and $464.3 million , respectively. Our net cash flows from operating activities in 2017 , 2016 , and 2015 were $588.6 million , $486.3 million , and $411.1 million , respectively, and our adjusted cash flow from operations, a non-U.S. GAAP financial measure, were $582.1 million , $466.8 million , and $420.8 million , respectively. See Reconciliation of Non-U.S. GAAP Financial Measures , below, for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures. +Liquidity +Available liquidity as of December 31, 2017 was $880.7 million , which was comprised of $180.7 million of cash and cash equivalents and $700.0 million available for borrowing under our revolving credit facility at our current commitment level. In October 2017, we entered into a Sixth Amendment to the Third Amended and Restated Credit Agreement. The amendment allowed the borrowing base to be set above the $1.0 billion borrowing capacity of the facility. The borrowing base for our November 2017 redetermination was confirmed at $1.1 billion and we elected to maintain a $700 million commitment level. Assuming that the Bayswater Acquisition had closed in December 2017, our liquidity position as of December 31, 2017, would have been approximately $700 million . +In November 2017, we issued $600 million principal amount of our 2026 Senior Notes. The net proceeds from the offering were used to fund the redemption of our $500 million 2022 Senior Notes and a portion of the purchase price of the January 2018 Bayswater Acquisition, and for general corporate purposes. +We intend to continue to manage our liquidity position by a variety of means, including through the generation of cash flows from operations, investment in projects with attractive rates of return, protection of cash flows on a portion of our anticipated sales through the use of an active commodity derivative hedging program, potential utilization of our borrowing capacity under our revolving credit facility, and if warranted, capital markets transactions from time to time. +Acquisition +On January 5, 2018, we closed the Bayswater Acquisition for approximately $186 million , subject to certain customary post-closing adjustments. In addition to the approximately $186 million of cash paid at closing, we invested approximately $15 million during 2017 to complete certain DUCs acquired in the transaction. +Acreage Exchanges +In 2017, we completed two significant acreage exchanges that consolidated certain acreage positions in the core area of the Wattenberg Field. Both transactions involved the exchange of leasehold acreage with a limited number of wells that were in the process of being drilled and completed. Upon closing the transactions, we received an aggregate of approximately 15,900 net acres in exchange for an aggregate of approximately 16,200 net acres. The difference in net acres is primarily due to variances in working and net revenue interests and midstream contracts. +43 +2017 Drilling Overview +During the year ended December 31, 2017 , we continued to execute our strategic plan to grow production while preserving our financial strength and liquidity. Our drilling efficiency in the Wattenberg Field over the last year has resulted in shorter drill times; as a result, we decreased our rig count from four to three in the fourth quarter of 2017. Due to the decreased drill times, the impact of the reduced rig count on our expected turn-in-line count in the Wattenberg Field was minimal in 2017. During the three months ended December 31, 2017 , we briefly ran four rigs in the Delaware Basin as we swapped out rigs to focus on improving drill times. During the fourth quarter of 2017, we turned-in-line 19 wells in the Wattenberg Field and five wells in the Delaware Basin. We did not complete or turn-in-line any wells in the Utica Shale during 2017 . +The following tables summarizes our drilling and completion activity for the year ended December 31, 2017 : +Wells Operated by PDC +Wattenberg Field +Delaware Basin +Total +Gross +Net +Gross +Net +Gross +Net +In-process as of December 31, 2016 +64 +52.7 +5 +4.8 +69 +57.5 +Wells spud +153 +140.2 +26 +22.7 +179 +162.9 +Wells turned-in-line +(130 +) +(112.8 +) +(16 +) +(15.2 +) +(146 +) +(128.0 +) +Exploratory dry holes +— +— +(2 +) +(2.0 +) +(2 +) +(2.0 +) +In-process as of December 31, 2017 +87 +80.1 +13 +10.3 +100 +90.4 +Wells Operated by Others +Wattenberg Field +Delaware Basin +Total +Gross +Net +Gross +Net +Gross +Net +In-process as of December 31, 2016 +18 +3.4 +— +— +18 +3.4 +Wells spud +94 +13.1 +10 +1.5 +104 +14.5 +Wells turned-in-line +(12 +) +(1.6 +) +(2 +) +(0.4 +) +(14 +) +(2.0 +) +Wells interest exchanged +(85 +) +(12.2 +) +— +— +(85 +) +(12.2 +) +Exploratory dry holes +(1 +) +(0.1 +) +— +— +(1 +) +(0.1 +) +In-process as of December 31, 2017 +14 +2.6 +8 +1.1 +22 +3.6 +Our in-process wells represent wells that are in the process of being drilled and/or have been drilled and are waiting to be fractured and/or for gas pipeline connection. Our DUCs are generally completed and turned-in-line within three to nine months of drilling. The majority of the PDC-operated in-process wells at each period end are DUCs, as we do not begin the completion process until the entire well pad is drilled. All appropriate costs incurred through the end of the period have been capitalized, while the capital investment to complete the wells will be incurred in the period in which the wells are completed. +2018 Operational and Financial Outlook +We expect our production for 2018 to range between 38 MMBoe to 42 MMBoe, or approximately 104,000 Boe to 115,000 Boe per day for the year. We expect that approximately 42 to 45 percent of our 2018 production will be comprised of crude oil and approximately 19 to 22 percent will be NGLs, for total liquids of approximately 64 to 67 percent. Our 2018 capital forecast of between $850 million and $920 million is focused on continued execution in the Wattenberg Field and Delaware Basin with three drilling rigs and one completion crew in each basin throughout the year. +We believe that we maintain significant operational flexibility to control the pace of our capital spending. As we execute our capital investment program, we continually monitor, among other things, commodity prices, development costs, midstream capacity, and offset and continuous drilling obligations. Should commodity pricing or the operating environment deteriorate, we may determine that an adjustment to our development plan is appropriate. We believe we have ample opportunities to reduce capital spending in order to stay within the range of our capital investment plan, including but not limited to reducing the number of rigs being utilized in our drilling program and/or managing our completion schedule. This flexibility is more limited in the Delaware Basin given leasehold maintenance requirements. +44 +Wattenberg Field. We are drilling in the Niobrara and Codell plays within the field and anticipate spudding and turning-in-line between approximately 135 to 150 operated wells in 2018. Our 2018 capital investment program is estimated to be approximately $470 million to $500 million in the Wattenberg Field, of which approximately 90 percent is anticipated to be invested in operated drilling and completion activity. The remainder of the Wattenberg Field capital investment program is expected to be used for non-operated wells and miscellaneous workover and capital projects. +Delaware Basin. Total capital investment in the Delaware Basin in 2018 is estimated to be approximately $380 million to $420 million, of which approximately 75 percent is allocated to both spud and turn-in-line approximately 25 to 30 operated wells targeting the Wolfcamp formation. Based on the timing of our operations and requirements to hold acreage, we may adapt our capital investment program to drill wells different from or in addition to those currently anticipated, as we are continuing to analyze the terms of the relevant leases. We plan to invest approximately 10 percent of our capital in leasing, non-operated capital, seismic, and technical studies with an additional approximately 15 percent for midstream related projects including oil and gas gathering systems and water supply and disposal systems. +Utica Shale . In 2017, as part of plans to divest the Utica Shale properties, we engaged an investment banking firm and began actively marketing the properties for sale; therefore, these properties are classified as held-for-sale as of December 31, 2017. In February 2018, we entered into a definitive PSA to sell these properties for net cash proceeds of approximately $40.0 million . The transaction is expected to close in the first quarter of 2018, subject to certain customary closing conditions. +Financial Guidance. Based on our current production forecast for 2018 and assuming averages of approximately $57.50 NYMEX crude oil price for the year and a $3.00 NYMEX natural gas price, we expect 2018 capital investments to exceed our 2018 cash flows from operations by approximately less than $90 million. We anticipate that the proceeds received from the sale of our Utica Shale assets and a midstream dedication agreement (see the footnote titled Subsequent Events to the consolidated financial statements included elsewhere in this report), will fund approximately two-thirds of this outspend. We expect this capital investment outspend to occur during the first half of 2018, with cash flows exceeding capital investment during the second half of the year. Our leverage ratio, as defined in our revolving credit facility agreement, is expected to decrease in 2018 to 1.4 based on production and operational cash flow growth. +The following table provides projected financial guidance for 2018: +Low +High +Operating Expenses +Lease operating expenses ($/Boe) +$ +2.75 +$ +3.00 +Transportation, gathering, and processing expenses ("TGP") ($/Boe) +$ +0.60 +$ +0.80 +Production taxes (% of crude oil, natural gas, and NGL sales) +6 +% +8 +% +General and administrative expense ($/Boe) +$ +3.40 +$ +3.70 +Estimated Price Realizations (% of NYMEX, excludes TGP) +Crude oil +91% +95% +Natural gas +55% +60% +NGLs +30% +35% +45 +Results of Operations +Summary Operating Results +The following table presents selected information regarding our operating results from continuing operations: +Year Ended December 31, +Percent Change +2017 +2016 +2015 +2017-2016 +2016-2015 +(dollars in millions, except per unit data) +Production +Crude oil (MBbls) +12,902 +8,728 +6,984 +47.8 +% +25.0 +% +Natural gas (MMcf) +71,689 +51,730 +33,302 +38.6 +% +55.3 +% +NGLs (MBbls) +6,981 +4,826 +2,835 +44.7 +% +70.2 +% +Crude oil equivalent (MBoe) +31,830 +22,176 +15,369 +43.5 +% +44.3 +% +Average Boe per day (Boe) +87,206 +60,590 +42,108 +43.9 +% +43.9 +% +Crude Oil, Natural Gas and NGLs Sales +Crude oil +$ +625.0 +$ +348.9 +$ +280.3 +79.1 +% +24.5 +% +Natural gas +158.3 +91.6 +68.0 +72.8 +% +34.7 +% +NGLs +129.8 +56.9 +30.4 +128.1 +% +87.2 +% +Total crude oil, natural gas, and NGLs sales +$ +913.1 +$ +497.4 +$ +378.7 +83.6 +% +31.3 +% +Net Settlements on Commodity Derivatives +Crude oil +$ +(2.7 +) +$ +165.2 +$ +208.9 +(101.6 +)% +(20.9 +)% +Natural gas +23.3 +42.9 +30.0 +(45.7 +)% +43.0 +% +NGLs (propane portion) +(7.3 +) +— +— +* +* +Total net settlements on derivatives +$ +13.3 +$ +208.1 +$ +238.9 +(93.6 +)% +(12.9 +)% +Average Sales Price (excluding net settlements on derivatives) +Crude oil (per Bbl) +$ +48.45 +$ +39.96 +$ +40.14 +21.2 +% +(0.4 +)% +Natural gas (per Mcf) +2.21 +1.77 +2.04 +24.9 +% +(13.2 +)% +NGLs (per Bbl) +18.59 +11.80 +10.72 +57.5 +% +10.1 +% +Crude oil equivalent (per Boe) +28.69 +22.43 +24.64 +27.9 +% +(9.0 +)% +Average Costs and Expenses (per Boe) +Lease operating expenses +$ +2.82 +$ +2.70 +$ +3.71 +4.4 +% +(27.2 +)% +Production taxes +1.91 +1.42 +1.20 +34.5 +% +18.3 +% +Transportation, gathering, and processing expenses +1.04 +0.83 +0.66 +25.3 +% +25.8 +% +General and administrative expense +3.78 +5.07 +5.85 +(25.4 +)% +(13.3 +)% +Depreciation, depletion, and amortization +14.74 +18.80 +19.73 +(21.6 +)% +(4.7 +)% +Lease Operating Expenses by Operating Region (per Boe) +Wattenberg Field +$ +2.48 +$ +2.70 +$ +3.78 +(8.1 +)% +(28.6 +)% +Delaware Basin +5.16 +8.79 +* +(41.3 +)% +* +Utica Shale (1) +1.66 +1.75 +2.78 +(5.1 +)% +(37.1 +)% +* +Percentage change is not meaningful or equal to or greater than 300% or not applicable. +Amounts may not recalculate due to rounding. +______________ +(1) In February 2018, we entered into a PSA to sell the Utica Shale properties. +46 +Crude Oil, Natural Gas, and NGLs Sales +The year-over-year change in crude oil, natural gas, and NGLs sales revenue were primarily due to the following: +Year Ended December 31, +2017 +2016 +(in millions) +Increase in production +$ +227.5 +$ +129.0 +Increase (decrease) in average crude oil price +109.6 +(1.6 +) +Increase (decrease) in average natural gas price +31.2 +(14.0 +) +Increase in average NGLs price +47.4 +5.2 +Total increase in crude oil, natural gas and NGLs sales revenue +$ +415.7 +$ +118.6 +Crude Oil, Natural Gas, and NGLs Production +The following tables present crude oil, natural gas, and NGLs production. Our acquisition of assets in the Delaware Basin closed in December 2016; therefore, there is no comparative data for 2015. +Year Ended December 31, +Change +Production by Operating Region +2017 +2016 +2015 +2017-2016 +2016-2015 +Crude oil (MBbls) +Wattenberg Field +10,922 +8,230 +6,490 +32.7 +% +26.8 +% +Delaware Basin +1,699 +79 +— +* +* +Utica Shale (1) +281 +419 +494 +(32.9 +)% +(15.2 +)% +Total +12,902 +8,728 +6,984 +47.8 +% +25.0 +% +Natural gas (MMcf) +Wattenberg Field +60,106 +48,889 +30,753 +22.9 +% +59.0 +% +Delaware Basin +9,410 +373 +— +* +* +Utica Shale (1) +2,173 +2,468 +2,549 +(12.0 +)% +(3.2 +)% +Total +71,689 +51,730 +33,302 +38.6 +% +55.3 +% +NGLs (MBbls) +Wattenberg Field +5,876 +4,568 +2,616 +28.6 +% +74.6 +% +Delaware Basin +917 +36 +— +* +* +Utica Shale (1) +188 +222 +219 +(15.3 +)% +1.4 +% +Total +6,981 +4,826 +2,835 +44.7 +% +70.2 +% +Crude oil equivalent (MBoe) +Wattenberg Field +26,815 +20,945 +14,231 +28.0 +% +47.2 +% +Delaware Basin +4,184 +178 +— +* +* +Utica Shale (1) +831 +1,053 +1,138 +(21.1 +)% +(7.5 +)% +Total +31,830 +22,176 +15,369 +43.5 +% +44.3 +% +Average crude oil equivalent per day (Boe) +Wattenberg Field +73,466 +57,227 +38,990 +28.4 +% +46.8 +% +Delaware Basin +11,463 +486 +— +* +* +Utica Shale (1) +2,277 +2,877 +3,118 +(20.9 +)% +(7.7 +)% +Total +87,206 +60,590 +42,108 +43.9 +% +43.9 +% +*Percentage change is not meaningful or equal to or greater than 300%. +Amounts may not recalculate due to rounding. +______________ +(1) In February 2018, we entered into a PSA to sell the Utica Shale properties. +47 +In the Wattenberg Field, we rely on third-party midstream service providers to construct gathering, compression, and processing facilities to keep pace with our and the overall field's natural gas production growth. In 2017 and during 2018, our production has been adversely affected by high line pressures on the gas gathering facilities, primarily due to increases in field-wide production volumes. As a result, we experienced some production curtailments during the second half of 2017. The gathering system of our primary midstream service provider, DCP Midstream, LP ("DCP"), is currently at capacity. We believe that our 2018 production guidance range appropriately reflects the impact of anticipated gathering system line pressures and the resulting temporary limitations on the gathering system’s capacity, but curtailments may be greater than anticipated. For 2017 , 94 percent of our production in the Wattenberg Field was delivered from horizontal wells, with the remaining six percent coming from vertical wells. The horizontal wells are less prone to curtailments than the vertical wells because they are newer and have greater producing capacity and higher formation pressures and therefore tend to be more resilient to gas system pressure issues; however, all of our wells in the field are currently experiencing some impact. We expect to continue to operate in a constrained environment into the third quarter of 2018 , at which time additional processing capacity is scheduled to be brought into operation by DCP. +We continue to work closely with our third-party midstream providers in an effort to ensure that adequate midstream system capacity is available going forward in the Wattenberg Field. We, along with other operators, have made a commitment with DCP to support its construction of two additional processing facilities with associated gathering pipe and compression in the field. These expansions are expected to increase DCP's system capacity, assist in the control of line pressures on its natural gas gathering facilities, and reduce production curtailments in the field. We will be bound to the incremental volume requirements in these agreements on the first day of the calendar month after the actual in-service dates of the plants for a period of seven years, which are currently scheduled to occur in the third quarter of 2018 and in the second quarter of 2019, respectively. The agreements impose a baseline volume commitment and guarantee a certain target profit margin to DCP on those volumes during the initial three years of the contracts. Under our current drilling plans, we expect to meet both the baseline and incremental volume commitments, and we believe that the contractual target profit margin will be achieved without additional payment from us. See the footnote titled Commitments and Contingencies to our consolidated financial statements included elsewhere in this report for additional details regarding the agreements. In addition, we have begun early discussions with DCP with respect to further increasing its processing facilities in the Wattenberg Field. We also continue to work with all of our midstream service providers in the field in an effort to ensure all of the existing infrastructure is fully utilized and that all options for system expansions are evaluated and implemented, where possible. The ultimate timing and availability of adequate infrastructure is not within our control and if our midstream service providers' construction projects are delayed, we could experience higher gathering line pressures that would negatively impact our ability to meet our production targets. +48 +Crude Oil, Natural Gas, and NGLs Pricing +Our results of operations depend upon many factors. Key factors include the price of crude oil, natural gas, and NGLs and our ability to market our production effectively. Crude oil, natural gas, and NGL prices have a high degree of volatility and our realizations can change substantially. Our sales prices for crude oil, natural gas, and NGLs increased during 2017 compared to 2016 . NYMEX crude oil prices increased 18 percent and NYMEX natural gas prices increased 26 percent as compared to 2016 . Our sales prices for crude oil and natural gas decreased and prices for NGLs increased during 2016 compared to 2015 . NYMEX crude oil prices decreased 12 percent and NYMEX natural gas prices decreased 8 percent as compared to 2015 . The majority of our NGL prices in the Wattenberg Field are reflected in the tables below, net of the processing and transport costs that are embedded in the applicable percent-of-proceeds contracts. +The following tables present weighted-average sales prices of crude oil, natural gas, and NGLs for the periods presented. Our acquisition of assets in the Delaware Basin closed in December 2016; therefore, there is no comparative data for 2015 : +Year Ended December 31, +Weighted-Average Sales Price by Operating Region +Change +(excluding net settlements on derivatives) +2017 +2016 +2015 +2017-2016 +2016-2015 +Crude oil (per Bbl) +Wattenberg Field +$ +48.48 +$ +39.99 +$ +40.03 +21.2 +% +(0.1 +)% +Delaware Basin +48.68 +49.28 +— +(1.2 +)% +* +Utica Shale (1) +45.63 +37.62 +41.59 +21.3 +% +(9.5 +)% +Weighted-average price +48.45 +39.96 +40.14 +21.2 +% +(0.4 +)% +Natural gas (per Mcf) +Wattenberg Field +2.19 +1.77 +2.06 +23.7 +% +(14.1 +)% +Delaware Basin +2.26 +2.78 +— +(18.7 +)% +* +Utica Shale (1) +2.40 +1.58 +1.85 +51.9 +% +(14.6 +)% +Weighted-average price +2.21 +1.77 +2.04 +24.9 +% +(13.2 +)% +NGLs (per Bbl) +Wattenberg Field +17.75 +11.59 +10.58 +53.1 +% +9.5 +% +Delaware Basin +22.64 +17.87 +— +26.7 +% +* +Utica Shale (1) +25.06 +15.11 +12.43 +65.9 +% +21.6 +% +Weighted-average price +18.59 +11.80 +10.72 +57.5 +% +10.1 +% +Crude oil equivalent (per Boe) +Wattenberg Field +28.55 +22.38 +24.64 +27.6 +% +(9.2 +)% +Delaware Basin +29.80 +31.50 +— +(5.4 +)% +* +Utica Shale (1) +27.36 +21.88 +24.59 +25.0 +% +(11.0 +)% +Weighted-average price +28.69 +22.43 +24.64 +27.9 +% +(9.0 +)% +* +Percentage change is not meaningful or equal to or greater than 300%. +Amounts may not recalculate due to rounding. +______________ +(1) In February 2018, we entered into a PSA to sell the Utica Shale properties. +Our crude oil, natural gas, and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related purchase agreement. We use the net-back method when the purchasers of these commodities also provide transportation, gathering, or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the indices for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. +We use the gross method of accounting when the purchasers do not provide transportation, gathering, or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering, and processing expenses. +49 +The following table summarizes how we recognize revenue related to the sales of our crude oil, natural gas, and NGLs: +Years Ended December 31, 2015 through 2017 +Net-Back +Gross +Wattenberg Field +Crude oil +Yes +Yes +Natural gas +Yes +No +NGLs +Yes +No +Delaware Basin +Crude oil +Yes +Yes +Natural gas +Yes +Yes +NGLs +Yes +No +As discussed above, we enter into agreements for the sale, transportation, gathering, and processing of our production. The terms of these agreements can result in variances in the per unit realized prices that we receive for our crude oil, natural gas and NGLs. Information related to the components and classifications in the consolidated statements of operations is shown below. For crude oil, the average NYMEX prices shown below are based upon average daily prices throughout each month and our natural gas average NYMEX pricing is based upon first-of-the-month index prices as this is how the majority of each of these commodities are sold pursuant to terms of the respective sales agreements. For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. For NGLs, the average realized price both before and after transportation, gathering, and processing expenses shown in the table below represents our approximate composite per barrel price. +2017 +Average NYMEX Price +Average Realized Price Before Transportation, Gathering and Processing Expenses +Average Realization Percentage Before Transportation, Gathering and Processing Expenses +Average Transportation, Gathering and Processing Expenses +Average Realized Price After Transportation, Gathering and Processing Expenses +Average Realization Percentage After Transportation, Gathering and Processing Expenses +Crude oil (per Bbl) +$ +50.95 +$ +48.45 +95 +% +$ +1.41 +$ +47.04 +92 +% +Natural gas (per MMBtu) +3.11 +2.21 +71 +% +0.17 +2.04 +66 +% +NGLs (per Bbl) +50.95 +18.59 +36 +% +0.30 +18.29 +36 +% +Crude oil equivalent (per Boe) +38.83 +28.69 +74 +% +1.04 +27.65 +71 +% +We adopted a new revenue recognition accounting standard effective January 1, 2018. Under the guidance of the new revenue recognition standard, certain crude oil sales in the Wattenberg Field that were recognized using the gross method prior to the adoption of the new revenue standard will be recognized using the net-back method and in the Delaware Basin certain crude oil and natural gas sales that were recognized using the gross method prior to the adoption of the new revenue standard will be recognized using the net-back method. If we had adopted the standard on January 1, 2017, we estimate that the average realization percentage before transportation, gathering, and processing expenses would have been 94 percent, 70 percent, 36 percent, and 73 percent for crude oil, natural gas, NGLs, and crude oil equivalent, respectively, as $11.3 million in expenses currently recorded in transportation, gathering, and processing on our consolidated statements of operations would, in that case, have been reflected as a reduction to the sales price. However, the net realized price would remain unchanged. +50 +2016 +Average NYMEX Price +Average Realized Price Before Transportation, Gathering and Processing Expenses +Average Realization Percentage Before Transportation, Gathering and Processing Expenses +Average Transportation, Gathering and Processing Expenses +Average Realized Price After Transportation, Gathering and Processing Expenses +Average Realization Percentage After Transportation, Gathering and Processing Expenses +Crude oil (per Bbl) +$ +43.32 +$ +39.96 +92 +% +$ +1.51 +$ +38.45 +89 +% +Natural gas (per MMBtu) +2.46 +1.77 +72 +% +0.07 +1.70 +69 +% +NGLs (per Bbl) +43.32 +11.80 +27 +% +0.28 +11.52 +27 +% +Crude oil equivalent (per Boe) +32.22 +22.43 +70 +% +0.83 +21.60 +67 +% +2015 +Average NYMEX Price +Average Realized Price Before Transportation, Gathering and Processing Expenses +Average Realization Percentage Before Transportation, Gathering and Processing Expenses +Average Transportation, Gathering and Processing Expenses +Average Realized Price After Transportation, Gathering and Processing Expenses +Average Realization Percentage After Transportation, Gathering and Processing Expenses +Crude oil (per Bbl) +$ +48.80 +$ +40.14 +82 +% +$ +0.67 +$ +39.47 +81 +% +Natural gas (per MMBtu) +2.66 +2.04 +77 +% +0.12 +1.92 +72 +% +NGLs (per Bbl) +48.80 +10.72 +22 +% +0.55 +10.17 +21 +% +Crude oil equivalent (per Boe) +36.94 +24.64 +67 +% +0.66 +23.98 +65 +% +Commodity Price Risk Management, Net +We use commodity derivative instruments to manage fluctuations in crude oil and natural gas prices. We have in place a variety of collars, fixed-price swaps, and basis swaps on a portion of our estimated crude oil, natural gas, and propane production. Because we sell all of our crude oil, natural gas, and NGLs production at prices related to the indexes inherent in our underlying derivative instruments, we ultimately realize value related to our collars of no less than the floor and no more than the ceiling. For our commodity swaps, we ultimately realize the fixed price value related to our swaps. See the footnote titled Commodity Derivative Financial Instruments for a detailed presentation of our derivative positions as of December 31, 2017 . +Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments, as well as the change in fair value of unsettled commodity derivatives related to our crude oil, natural gas, and propane production. Commodity price risk management, net, does not include derivative transactions related to our gas marketing, which are included in other income and other expenses. +Net settlements of commodity derivative instruments are based on the difference between the crude oil, natural gas, and propane index prices at the settlement date of our commodity derivative instruments compared to the respective strike prices. The net change in fair value of unsettled commodity derivatives is comprised of the net value increase or decrease in the beginning-of-period fair value of commodity derivative instruments that settled during the period, and the net change in fair value of unsettled commodity derivatives during the period or from inception of any new contracts entered into during the applicable period. The net change in fair value of unsettled commodity derivatives during the period is primarily related to shifts in the crude oil, natural gas, and NGLs forward curves and changes in certain differentials. +51 +The following table presents net settlements and net change in fair value of unsettled commodity derivatives included in commodity price risk management, net: +Year Ended December 31, +2017 +2016 +2015 +(in millions) +Commodity price risk management gain (loss), net: +Net settlements of commodity derivative instruments: +Crude oil fixed price swaps and collars +$ +(2.7 +) +$ +165.2 +$ +208.9 +Natural gas fixed price swaps and collars +19.5 +41.9 +31.0 +Natural gas basis protection swaps +3.8 +1.0 +(1.0 +) +NGLs (propane portion) fixed price swaps +(7.3 +) +— +— +Total net settlements of commodity derivative instruments +13.3 +208.1 +238.9 +Change in fair value of unsettled commodity derivative instruments: +Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments +44.8 +(220.0 +) +(186.9 +) +Crude oil fixed price swaps, collars, and rollfactors +(77.9 +) +(78.6 +) +99.3 +Natural gas fixed price swaps and collars +14.7 +(37.1 +) +53.3 +Natural gas basis protection swaps +5.7 +1.9 +(1.4 +) +NGLs (propane portion) fixed price swaps +(4.6 +) +— +— +Net change in fair value of unsettled commodity derivative instruments +(17.3 +) +(333.8 +) +(35.7 +) +Total commodity price risk management gain (loss), net +$ +(4.0 +) +$ +(125.7 +) +$ +203.2 +Lease Operating Expenses +Lease operating expenses were $89.6 million in 2017 compared to $60.0 million in 2016 . Aggregate lease operating expenses during 2017 increased $29.6 million, of which $20.1 million related to our properties in the Delaware Basin. The $29.6 million increase in the total lease operating expenses in 2017 as compared to 2016 was primarily due to increases of $9.4 million for payroll and employee benefits related to increases in headcount, $5.6 million for produced water disposal, $5.6 million for increased workover projects, $3.9 million related to additional compressor rentals, and $2.2 million for equipment rentals. The increases were slightly offset by a $1.5 million decrease in environmental remediation costs. Lease operating expense per Boe increased by four percent to $2.82 for 2017 from $2.70 for 2016 , primarily due to expected higher per Boe costs in the Delaware Basin compared to our other areas of operation. +Lease operating expenses were $60.0 million in 2016 compared to $57.0 million in 2015 . The $3.0 million increase in lease operating expenses in 2016 as compared to 2015 was primarily due to an increase of $3.7 million for increases in wages and employee benefits related to an increase in headcount, including costs for additional contract labor, $1.8 million for additional leased compressors to address line pressures, and an increase of $1.5 million related to lease operating expenses for the acquisition in the Delaware Basin. These increases were partially offset by a decrease in environmental remediation and regulatory compliance projects of $3.2 million due to a reduction in new remediation projects, and a decrease of $1.4 million related to fewer workover and maintenance related projects. Lease operating expenses per Boe decreased significantly to $2.70 for 2016 from $3.71 in 2015 as a result of increased production. +Production Taxes +Production taxes were $60.7 million , $31.4 million , and $18.4 million in 2017 , 2016 , and 2015 , respectively. Production taxes are comprised mainly of severance tax and ad valorem tax and are directly related to crude oil, natural gas, and NGLs sales as the taxes are generally assessed as a percentage of net revenues. From time to time, there are adjustments to the statutory rates for these taxes based upon certain credits that are determined based upon activity levels and relative commodity prices from year to year. The $29.3 million and $13.0 million increases in production taxes during 2017 and 2016, respectively, were primarily related to the 84 percent and 31 percent increases in crude oil, natural gas, and NGLs sales in 2017 and 2016 , respectively, and to a lesser extent, an increase in tax rates. Our overall production tax rates were 6.6 percent , 6.3 percent , and 4.9 percent in 2017 , 2016 , and 2015 , respectively. +52 +Transportation, Gathering and Processing Expenses +Transportation expenses were $33.2 million in 2017 compared to $18.4 million in 2016 . The increase was mainly attributable to a $5.0 million increase in oil transportation costs due to additional volumes delivered through pipelines in the Wattenberg Field and an increase of $9.7 million related to natural gas gathering and transportation operations in the Delaware Basin. Transportation expenses were $18.4 million in 2016 compared to $10.2 million in 2015 . The increase was mainly attributable to the costs associated with certain pipelines in the Wattenberg Field as we began delivering crude oil on these pipelines in July and December 2015, respectively. Transportation, gathering, and processing expenses per Boe increased to $1.04 for 2017 compared to $0.83 for 2016 and $0.66 for 2015 . As discussed in — Crude Oil, Natural Gas, and NGLs Pricing , whether transportation, gathering, and processing costs are presented separately or are reflected as a reduction to net revenue is a function of the terms of the relevant marketing contract. The tables at the end of that section show our net realized prices for the periods shown after the relevant costs are deducted, regardless of where those costs appear on our income statement (see in particular the columns titled “Average Realized Price After Transportation, Gathering and Processing Expenses” and “Average Realization Percentage After Transportation, Gathering and Processing Expenses”). We expect that our transportation, gathering, and processing expenses will decrease beginning in 2018 with the adoption of a new revenue recognition standard as a portion of our current transportation, gathering, and processing expense will be recorded as a reduction to the sales price. +Exploration, Geologic, and Geophysical Expense +The following table presents the major components of exploration, geologic, and geophysical expense: +Year Ended December 31, +2017 +2016 +2015 +(in millions) +Exploratory dry hole costs +$ +41.3 +$ +— +$ +— +Geological and geophysical costs +3.9 +3.5 +— +Operating, personnel and other +2.1 +1.2 +1.1 +Total exploration expense +$ +47.3 +$ +4.7 +$ +1.1 +Exploratory dry hole costs. During 2017 , two exploratory dry hole wells, associated lease costs, and related infrastructure assets in the Delaware Basin were expensed at a cost of $41.3 million . The conclusion to expense these items was based on our determination that the acreage on which these wells were drilled was exploratory in nature and, following drilling, that the hydrocarbon production was insufficient for the wells to be deemed economically viable. +Geological and geophysical costs. Geological and geophysical costs in 2017 and 2016 were primarily related to the portion of the purchase of seismic data related to unproved acreage in the Delaware Basin. +53 +Impairment of Properties and Equipment +The following table sets forth the major components of our impairments of properties and equipment expense: +Year Ended December 31, +2017 +2016 +2015 +(in millions) +Impairment of proved and unproved properties +$ +285.5 +$ +5.6 +$ +154.6 +Amortization of individually insignificant unproved properties +0.4 +1.4 +7.0 +Land and buildings +— +3.0 +— +Total impairment of properties and equipment +$ +285.9 +$ +10.0 +$ +161.6 +Impairment of proved and unproved properties. Amounts represent the retirement or expiration of certain leases that are no longer part of our development plan or that we do not plan to extend and will allow to expire. Deterioration of commodity prices or other operating circumstances could result in additional impairment charges. +During 2017, we recorded a charge related to two exploratory dry holes we had drilled in the western area of our Culberson County acreage in the Delaware Basin, as referenced previously. We then assessed the impact of the dry holes and various factors related thereto, including (i) the operational and geologic data obtained, (ii) the current increased cost environment for drilling and completion services in the Delaware Basin, (iii) our future commodity price outlook, and (iv) the terms of the related lease agreements. Based on the results of this assessment, we concluded that the underlying geologic risk and the challenged economics of future capital expenditures reduced the likelihood that we would perform future development in this area over the remaining lease term for this acreage. Accordingly, we recorded an impairment of $251.6 million covering approximately 13,400 acres during 2017. The amount of the impairment was based on the value assigned to individual lease acres in the final purchase price allocation of our Delaware Basin acquisition. This allocation included the consideration paid to the sellers, including the effect of the non-cash impact from the deferred tax liability created at the time of the acquisition. We recorded approximately $29 million of additional lease impairments in the Delaware Basin and an impairment charge of $2.1 million related to the Utica Shale properties that are classified as held-for-sale during 2017. Due to the aforementioned events and circumstances, we also evaluated our proved property for possible impairment and concluded that no further impairments were necessary at this time. +During 2015, due to a significant decline in commodity prices and decreases in our net realized sales prices, we experienced triggering events that required us to assess our crude oil and natural gas properties for possible impairment. As a result of our assessments, we recorded impairment charges of $150.3 million in 2015 to write-down our Utica Shale proved and unproved properties. Of these impairment charges, $24.7 million were recorded in 2015 to write-down certain capitalized well costs on our Utica Shale proved producing properties. In 2015, we also recorded impairment charges of $125.6 million to write-down our Utica Shale lease acquisition costs. The impairment charges, which are included in the consolidated statements of operations line item impairment of properties and equipment, represented the amount by which the carrying value of these crude oil and natural gas properties exceeded the estimated fair values. +Amortization of individually insignificant unproved properties. The decrease in 2016 as compared to 2015 is due to the impairment of leases in the Utica Shale in 2015. +Impairment of Goodwill +The final goodwill that resulted from the purchase price allocation of the assets acquired in the Delaware Basin was determined to be $75.1 million . With the creation of goodwill from this transaction, we expected to perform our evaluation of goodwill for impairment annually in the fourth quarter. However, primarily due to a combination of increases in per well development and operational costs and our drilling of two exploratory dry holes in the Delaware Basin subsequent to the acquisition, in conjunction with our lower future commodity price outlook, we determined that a triggering event had occurred in the quarter ended September 30, 2017. In addition to the factors mentioned above, we also considered our recent impairments of certain unproven leasehold costs and the impact of these items on our internal expectations for acceptable rates of return. We evaluated goodwill for impairment by performing a quantitative test, which involves comparing the estimated fair value of the goodwill reporting unit, which we define as the Delaware Basin, to the carrying value. We determined the fair +54 +value of the goodwill at September 30, 2017 by using an estimated after-tax future discounted cash flow analysis, along with a combination of market-based pricing factors for similar acreage, reserve valuation techniques, and other fair value considerations. The discounted cash flow analysis used to estimate fair value was based on known or knowable information at the interim measurement date. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. The quantitative test resulted in a determination that a full impairment charge of $75.1 million was required; therefore, the charge was recorded in third quarter of 2017. +General and Administrative Expense +General and administrative expense increased $7.9 million , or seven percent , in 2017 compared to 2016. The increase was primarily attributable to an $8.1 million increase in payroll and employee benefits due to an increase in headcount in 2017 as compared to 2016, $4.4 million related to professional services, $4.2 million related to legal expenses, $1.4 million related to software license and maintenance agreements, and $1.3 million for the rental of additional office space. The increases were partially offset by the $12.2 million of legal and professional fees related to the acquisition in the Delaware Basin that were incurred in 2016. +General and administrative expense increased $22.5 million , or 25 percent , in 2016 compared to 2015. The increase in cash based general and administrative costs was primarily attributable to $12.2 million of legal and professional fees related to the acquisition in the Delaware Basin and a $7.7 million increase in payroll and employee benefits due to increases in wages and increases in headcount. +Depreciation, Depletion, and Amortization +Crude oil and natural gas properties. During 2017 , 2016 , and 2015 , we invested $788.0 million , $396.4 million , and $554.3 million , net of changes in accounts payable related to capital expenditures, in the development of our crude oil and natural gas properties, respectively. We also incurred $1.76 billion to acquire reserves during 2016 in the Delaware Basin. We did not invest in any acquisitions of proved reserves in 2015. DD&A expense related to crude oil and natural gas properties is directly related to proved reserves and production volumes. DD&A expense related to crude oil and natural gas properties was $462.5 million , $413.1 million , and $298.8 million in 2017 , 2016 , and 2015 , respectively. The year-over-year changes in DD&A expense related to crude oil and natural gas properties were primarily due to the following: +Year Ended December 31, +2017 - 2016 +2016 - 2015 +(in millions) +Increase in production +$ +144.7 +$ +132.3 +Decrease in weighted-average depreciation, depletion and amortization rates +(95.3 +) +(18.0 +) +Total increase in DD&A expense related to crude oil and natural gas properties +$ +49.4 +$ +114.3 +The following table presents our DD&A expense rates for crude oil and natural gas properties: +Year Ended December 31, +Operating Region/Area +2017 +2016 +2015 +(per Boe) +Wattenberg Field +$ +14.67 +$ +19.11 +$ +20.13 +Delaware Basin (1) +14.89 +8.34 +— +Utica Shale (2) +8.09 +10.66 +10.74 +Total weighted-average +14.53 +18.63 +19.44 +____________ +(1) The 2016 Delaware Basin rate represents one month of DD&A expense. Accordingly, the comparison of the 2017 rate +to the 2016 rate is not meaningful. +(2) In February 2018, we entered into a PSA to sell the Utica Shale properties. +55 +The 2017 rate in the Wattenberg Field decreased as compared to the 2016 rate due to a decrease in per well development costs, and an increase in 2017 year-end reserves. The slight decrease in the Wattenberg Field rate for 2016 as compared to 2015 was primarily due to the impact of our 2016 year-end reserves. +Provision for Uncollectible Notes Receivable +In 2016, we recorded a provision for uncollectible notes receivable of $44.0 million to impair two third-party notes receivable whose collection was not reasonably assured. As described in the footnote titled Note Receivable included elsewhere in this report, in April 2017, we signed a definitive agreement and simultaneously closed on the sale of one of the associated notes receivable to an unrelated third-party for $40.2 million . Accordingly, we reversed $40.2 million of the provision for uncollectible notes receivable during 2017. +Accretion of Asset Retirement Obligations +Accretion of asset retirement obligations for 2017 decreased by $0.8 million , or 11 percent , compared to 2016 , and increased by $0.8 million , or 13 percent , in 2016 compared to 2015. The decrease in 2017 was due to the replacement of vertical wells that have been plugged and abandoned with horizontal wells, which have a longer expected life. The increase in 2016 was due to adding new wells and the associated increase in amortization expense. +Interest Expense +Interest expense increased by $16.7 million in 2017 compared to 2016 . The increase is primarily attributable to an $18.0 million increase in interest for the issuance of our 2024 Senior Notes, a $7.4 million increase in interest expense for the issuance of $200 million principal amount of our 1.125% convertible notes due 2021 (the "2021 Convertible Notes") in September 2016, a $3.1 million increase in interest expense for the issuance of our 2026 Notes in November 2017, and a $3.0 million increase in the utilization fee of our revolving credit facility. The increases were partially offset by a $9.3 million charge for a bridge loan commitment related to the 2016 acquisition of properties in the Delaware Basin, a $3.5 million decrease in interest expense resulting from the net settlement of our 2016 Convertible Notes in May 2016, and a $1.8 million decrease in interest expense resulting from the net settlement of our 2022 Notes in December 2017. +Interest expense increased by approximately $14.4 million in 2016 compared to 2015 . The increase is primarily attributable to a $9.3 million charge for the bridge loan commitment related to the acquisition of properties in the Delaware Basin, a $7.4 million increase in interest for the issuance of our 2024 Senior Notes, and a $2.9 million increase in interest expense for the issuance of our 2021 Convertible Notes in September 2016. The increases were partially offset by a $5.1 million decrease in interest expense resulting from the net settlement of our 2016 Convertible Notes in May 2016. The entire $9.3 million of interest expense attributed to the bridge loan facility was expensed in 2016 as the bridge loan was not used. +Interest costs capitalized in 2017 , 2016 , and 2015 were $5.0 million , $4.5 million , and $5.1 million , respectively. +Loss on Extinguishment of Debt +The $24.7 million pre-tax loss on extinguishment of debt relates to the redemption of the 2022 Senior Notes during the fourth quarter of 2017. The pretax loss consists of a $19.4 million make-whole premium and the write-off of unamortized debt issuance costs of $5.4 million . +Provision for Income Taxes +Current income tax (expense) benefit in 2017, 2016, and 2015 was $8.2 million, $9.9 million, and $(3.1) million, respectively. Current income taxes generally relate to the cash that is paid or recovered for income taxes associated with the applicable period. The remaining portion of the total income tax provision is comprised of deferred income taxes, which are a result of differences in the timing of deductions from our U.S. GAAP presentation of financial statements and the income tax regulations. +Our effective income tax rates for 2017, 2016, and 2015 were 62.4 percent, 37.4 percent, and 35.9 percent, respectively, on income (loss) from operations. The 2017 rate differs from the statutory rate of 35 percent primarily due to the reduction in the federal corporate income tax rate resulting from the 2017 Tax Act increasing the tax rate on our 2017 loss from operations by 33.7 percent. Additionally, the nondeductible goodwill impairment charge in 2017 reduced the 2017 rate by 7.7 percent. The 2017 rate was also impacted by state taxes. The 2016 and 2015 rates differ from the federal statutory tax rate +56 +primarily due to state taxes and excess stock compensation benefits, offset by nondeductible expenses that consist primarily of officers' compensation cost and government lobbying expenses. +In 2016, we recorded a net deferred tax liability of $379.9 million due to book versus tax accounting basis differences of assets acquired and deferred tax liabilities assumed from the acquisition in the Delaware Basin, resulting in a material increase in our deferred tax liability on the balance sheet as of December 31, 2016. In 2017, the deferred tax liability was reduced by $94.1 million as a result of recording an impairment charge related to a portion of these Delaware Basin assets. +As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions. We continue to voluntarily participate in the Internal Revenue Service’s ("IRS") Compliance Assurance Program (the "CAP Program") for the 2016 through 2018 tax years. We have received a partial acceptance notice from the IRS for our filed 2016 federal tax return and the IRS's post filing review is currently ongoing. +Net Income (Loss)/Adjusted Net Income (Loss) +The factors resulting in changes in net loss in 2017, 2016, and 2015 are discussed above. These same reasons similarly impacted adjusted net income (loss), a non-U.S. GAAP financial measure, with the exception of the net change in fair value of unsettled derivatives, adjusted for taxes, of $13.1 million, $208.9 million, and $22.2 million in 2017, 2016, and 2015, respectively. Adjusted net loss, a non-U.S. GAAP financial measure, was $114.4 million , $37.0 million , and $46.2 million in 2017, 2016, and 2015 respectively. See Reconciliation of Non-U.S. GAAP Financial Measures , below, for a more detailed discussion of this non-U.S. GAAP financial measure. +Financial Condition, Liquidity and Capital Resources +Historically, our primary sources of liquidity have been cash flows from operating activities, our revolving credit facility, proceeds from debt and equity capital market transactions, and asset sales. In 2017 , our primary sources of liquidity were net cash flows from operating activities of $588.6 million , net proceeds from issuance of the 2026 Senior Notes of approximately $592.4 million, and $40.2 million of proceeds from the sale of a promissory note. +We used a portion of the net proceeds from the 2026 Senior Notes to fund the redemption our 2022 Senior Notes and a portion of the purchase price of the Bayswater Acquisition in early 2018, and for general corporate purposes. +Our primary source of cash flows from operating activities is the sale of crude oil, natural gas, and NGLs. Fluctuations in our operating cash flows are principally driven by commodity prices and changes in our production volumes. Commodity prices have historically been volatile and we manage a portion of this volatility through our use of derivative instruments. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the instrument. Our revolving credit facility imposes limits on the amount of our production we can hedge, and we may choose not to hedge the maximum amounts permitted. Therefore, we may still have fluctuations in our cash flows from operating activities due to the remaining non-hedged portion of our future production. Based upon our hedge position and assuming forward strip pricing as of December 31, 2017 , our derivatives are not expected to be a significant source of cash flow in the near term. +Our working capital fluctuates for various reasons, including, but not limited to, changes in the fair value of our commodity derivative instruments and changes in our cash and cash equivalents due to our practice of utilizing excess cash to reduce the outstanding borrowings under our revolving credit facility. At December 31, 2017 , we had a working capital deficit of $16.4 million compared to working capital of $129.2 million at December 31, 2016 . The decrease in working capital as of December 31, 2017 is primarily the result of a decrease in cash and cash equivalents of $63.4 million related to capital investment exceeding operating cash flows, an increase in accounts payable of $83.7 million related to increased development and exploration activity, and a decrease in the net fair value of our unsettled commodity derivatives of $20.2 million, which was partially offset by an increase in our net accounts receivable balance of $54.2 million. +Our cash and cash equivalents were $180.7 million at December 31, 2017 and availability under our revolving credit facility was $700.0 million , providing for total liquidity of $880.7 million as of December 31, 2017 . Our liquidity was augmented in 2017 by the net proceeds from the 2026 Senior Notes and the proceeds from the sale of a promissory note, described previously. +57 +Based on our expectations of cash flows from operations, our cash and cash equivalent balance and availability under our revolving credit facility, we believe that we have sufficient capital to fund our planned activities through the 12-month period following the filing of this report. +Our revolving credit facility is a borrowing base facility and availability under the facility is subject to redetermination generally each May and November, based upon a quantification of our proved reserves at each December 31 and June 30, respectively. The maturity date of our revolving credit facility is May 2020. +In May and October 2017, we entered into the Fifth and Sixth Amendments, respectively, to the Third Amended and Restated Credit Agreement to amend the revolving credit facility to reflect increases in the borrowing base. The Fifth amendment reflected an increase of the borrowing base from $700 million to $950 million and the Sixth Amendment amended the revolving credit facility to allow the borrowing base to increase above the borrowing capacity of $1.0 billion . In addition, the Fifth Amendment made changes to certain of the covenants in the existing agreement as well as other administrative changes. We elected to increase the borrowing base to $1.1 billion for our November 2017 borrowing base redetermination and have elected to maintain a $700 million commitment level as of the date of this report. +Amounts borrowed under the revolving credit facility bear interest at either an alternate base rate option or a LIBOR option as defined in the revolving credit facility plus an applicable margin, depending on the percentage of the commitment that has been utilized. As of December 31, 2017 , the applicable margin is 1.25 percent for the alternate base rate option or 2.25 percent for the LIBOR option, and the unused commitment fee is 0.5 percent. +We had no amounts outstanding under our revolving credit facility as of December 31, 2017 . In May 2017, we replaced our $11.7 million irrevocable standby letter of credit that we held in favor of a third-party transportation service provider to secure a firm transportation obligation with a $9.3 million deposit, which is classified as restricted cash and is included in other assets on the consolidated balance sheet. As of December 31, 2017 , the available funds under our revolving credit facility were $700 million based on our elected commitment level. +Our revolving credit facility contains financial maintenance covenants. The covenants require that we maintain (i) a leverage ratio defined as total debt of less than 4.0 times the trailing 12 months earnings before interest, taxes, depreciation, depletion and amortization, change in fair value of unsettled commodity derivatives, exploration expense, gains (losses) on sales of assets and other non-cash gains (losses) and (ii) an adjusted current ratio of at least 1.0:1.0. Our adjusted current ratio is adjusted by eliminating the impact on our current assets and liabilities of recording the fair value of crude oil and natural gas commodity derivative instruments. Additionally, available borrowings under our revolving credit facility are added to the current asset calculation and the current portion of our revolving credit facility debt is eliminated from the current liabilities calculation. At December 31, 2017 , we were in compliance with all debt covenants, as defined by the revolving credit agreement, with a leverage ratio of 1.9 and a current ratio of 3.2 . We expect to remain in compliance throughout the 12-month period following the filing of this report. +The indentures governing our 2024 Senior Notes and 2026 Senior Notes contain customary restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (a) incur additional debt including under our revolving credit facility, (b) make certain investments or pay dividends or distributions on our capital stock or purchase, redeem, or retire capital stock, (c) sell assets, including capital stock of our restricted subsidiaries, (d) restrict the payment of dividends or other payments by restricted subsidiaries to us, (e) create liens that secure debt, (f) enter into transactions with affiliates, and (g) merge or consolidate with another company. At December 31, 2017 , we were in compliance with all covenants and expect to remain in compliance throughout the next 12-month period. +In January 2017, pursuant to the filing of the supplemental indentures for the 2021 Convertible Senior Notes and the 2024 Senior Notes, our subsidiary PDC Permian, Inc. became a guarantor of the notes. PDC Permian, Inc. is also the guarantor of our 2026 Senior Notes issued in November 2017. +58 +Cash Flows +Operating Activities. Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes, net settlements from our commodity derivative positions, operating costs, and general and administrative expenses. Cash flows provided by operating activities increased in 2017 as compared to 2016 . The $102.3 million increase was primarily due to the increase in crude oil, natural gas, and NGLs sales of $415.7 million . The increase was partially offset by a decrease in derivative commodity settlements of $194.8 million and increases in lease operating expenses of $29.7 million, production taxes of $29.3 million , interest expense of $16.7 million, transportation, gathering, and processing expenses of $14.8 million , and increases in general and administrative expense of $7.9 million as well as a decrease in the changes in assets and liabilities of $13.0 million. +Cash flows provided by operating activities increased in 2016 compared to 2015. The $75.2 million increase was primarily due to the increase in crude oil, natural gas, and NGLs sales of $118.7 million. We also realized an increase in the change of funds held for distribution of $36.5 million, and an increase in the deferral of income taxes of $13.1 million. The increases were partially offset by a decrease in derivative commodity settlements of $30.8 million, and increases in general and administrative expense of $22.5 million, interest expense of $14.4 million, production taxes of $13.0 million and transportation, gathering, and processing expenses of $8.3 million. +Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased by $115.3 million in 2017 to $582.1 million , and $46.0 million to $466.8 million in 2016 , when compared to the respective prior years. These changes were primarily due to the same factors mentioned above for changes in cash flows provided by operating activities, without regard to changes in assets and liabilities. +Adjusted EBITDAX, a non-U.S. GAAP financial measure, increased by $222.3 million in 2017 to $682.1 million from $459.8 million in 2016 , primarily as the result of the increase in crude oil, natural gas, and NGLs sales of $415.7 million , as well as the recording of a provision for a note receivable in 2016 of $44.0 million, and the subsequent sale of the note in 2017 to a third-party for $40.2 million . The increase was partially offset by a decrease in derivative commodity settlements of $194.8 million , and increases in lease operating expenses of $29.7 million, production taxes of $29.3 million , interest expense of $16.7 million, transportation, gathering, and processing expenses of $14.8 million , and general and administrative expense of $7.9 million . +Adjusted EBITDAX, a non-U.S. GAAP financial measure, decreased by $4.5 million in 2016 to $459.8 million from $464.3 million in 2015, primarily as a result of the provision for uncollectible notes receivable of $44.0 million, the decrease in net settlements from our monthly derivative commodity settlements of $30.8 million, an increase in general and administrative expense of $22.5 million, and a $13.0 million increase in production taxes. The decrease was partially offset by the increase in crude oil, natural gas, and NGLs sales of $118.7 million. +See Item 7. Reconciliation of Non-U.S. GAAP Financial Measures for a reconciliation of our U.S. GAAP to non-U.S. GAAP financial measures. +Investing Activities. Because crude oil and natural gas production from a well declines rapidly in the first few years of production, we continue to invest significant amounts of capital in order to maintain and grow our production and replace our reserves. If capital markets are not available in the future, we will be limited to our cash flows from operations and liquidity under our revolving credit facility as the sources for funding our capital investments. +Cash flows from investing activities primarily consist of the acquisition, exploration, and development of crude oil and natural gas properties, net of dispositions of crude oil and natural gas properties. Net cash used in investing activities of $717.0 million during 2017 was primarily related to cash utilized for our drilling operations, including completion activities of $737.2 million , a $21.0 million deposit toward the Bayswater Acquisition, purchases of short-term investments of $49.9 million, and a $9.3 million deposit with a third-party transportation service provider for surety of an existing firm transportation obligation. Partially offsetting these investments was the receipt of approximately $49.9 million related to the sale of short-term investments, $40.2 million from the sale of a promissory note, and $5.4 million related to post-closing settlements of properties acquired in 2016. During 2016, our acquisition in the Delaware Basin comprised the majority of our cash flows used in investing activities. Net cash used in the Delaware Basin acquisition was $1.1 billion and we used cash of $436.9 million for our crude oil and gas operations. Our total cash used in investing activities during 2016 was approximately $1.5 billion. +Financing Activities. Net cash from financing activities in 2017 was primarily related to $592.4 million of net proceeds from issuance of the 2026 Senior Notes, partially offset by the $519.4 million used to redeem our 2022 Senior Notes. +59 +Net cash from financing activities in 2016 was primarily related to the $855.1 million of net proceeds received from the issuance of 9.4 million shares of our common stock, $392.2 million of net proceeds from issuance of the 2024 Senior Notes, and $193.9 million of net proceeds from issuance of the 2021 Convertible Notes, partially offset by the $115.0 million payment upon the maturity of the 2016 Convertible Notes and net payments of approximately $37.0 million to pay down amounts borrowed under our revolving credit facility. +Contractual Obligations and Contingent Commitments +The following table presents our contractual obligations and contingent commitments as of December 31, 2017 : +Payments due by period +Less than +1-3 +3-5 +More than +Contractual Obligations and Contingent Commitments +Total +1 year +years +years +5 years +(in millions) +Long-term liabilities reflected on the consolidated balance sheet (1) +Long-term debt (2) +$ +1,200 +$ +— +$ +— +$ +200 +$ +1,000 +Commodity derivative contracts (3) +101 +79 +22 +— +— +Capital leases (4) +4 +1 +3 +— +— +Production tax liability +85 +38 +47 +— +— +Asset retirement obligations +87 +16 +32 +32 +7 +Other liabilities (5) +8 +2 +2 +2 +2 +1,485 +136 +106 +234 +1,009 +Commitments, contingencies and other arrangements (6) +Interest on long-term debt (7) +552 +87 +172 +135 +158 +Operating leases +23 +4 +8 +8 +3 +Firm transportation and processing agreements (8) +262 +23 +86 +66 +87 +837 +114 +266 +209 +248 +Total +$ +2,322 +$ +250 +$ +372 +$ +443 +$ +1,257 +__________ +(1) +Table does not include deferred income tax liability to taxing authorities of $192.0 million due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. +(2) +Amount presented does not agree with the consolidated balance sheets in that it excludes $30.3 million of unamortized debt discount and $17.7 million of unamortized debt issuance costs. +(3) +Represents our gross liability related to the fair value of derivative positions. +(4) +Short-term capital lease obligations are included in other accrued expenses on the consolidated balance sheets. Long-term capital lease obligations are included in other liabilities on the consolidated balance sheets. +(5) +Includes deferred compensation to former executive officers and deferred payments related to firm transportation agreements. +(6) +The table does not include termination benefits related to employment agreements with our executive officers, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. +(7) +Amounts presented include $288.9 million to the holders of our 2026 Senior Notes, $164.2 million to the holders of our 2024 Senior Notes, and $90.7 million payable to the holders of our 2021 Convertible Notes. Amounts also include interest of $8.4 million related to unutilized commitments at a rate of 0.50 percent per annum. +(8) +Represents our gross commitment which includes volumes produced by us, purchased from third parties and produced by our affiliated partnerships and other third-party working, royalty and overriding royalty interest owners whose volumes we market on their behalf. This includes anticipated and estimated commitments associated with two new gas processing facilities by our primary mid-stream provider. The timing of such payments has been estimated and is subject to change based on the completion of construction and the commencement of operations by the midstream provider. +From time to time, we are a party to various legal proceedings in the ordinary course of business. We are not currently a party to any litigation that we believe would have a materially adverse effect on our business, financial condition, results of operations, or liquidity. Information regarding our legal proceedings can found in the footnote titled Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere in this report. +Critical Accounting Policies and Estimates +We have identified the following policies as critical to business operations and the understanding of our results of operations. This is not a comprehensive list of all of the accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by U.S. GAAP, with no need for our judgment in the application. There are also +60 +areas in which our judgment in selecting available alternatives would not produce a materially different result. However, certain of our accounting policies are particularly important to the presentation of our financial position and results of operations and we may use significant judgment in their application. As a result, they are subject to an inherent degree of uncertainty. In applying those policies, we use our judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on historical experience, observation of trends in the industry and information available from other outside sources, as appropriate. For a more detailed discussion on the application of these and other accounting policies, see the footnote titled Summary of Significant Accounting Policies to our consolidated financial statements included elsewhere in this report. +Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. +Annually, we engage independent petroleum engineers to prepare reserve and economic evaluations of all our properties on a well-by-well basis as of December 31. We adjust our crude oil and natural gas reserves for major acquisitions, new drilling, and divestitures during the year as needed. The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering, and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. Although every reasonable effort is made to ensure that reserve estimates reported represent our most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect our DD&A expense, a change in our estimated reserves could have an effect on our net income (loss). +Exploration costs, including geological and geophysical expenses, the acquisition of seismic data covering unproved acreage, and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but are charged to expense if the well is determined to be nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as the well has found a sufficient quantity of reserves to justify completion as a producing well and we are making sufficient progress assessing our reserves and economic and operating viability. If an in-progress exploratory well is found to be unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the well is classified as a "suspended well" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time when we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the proper accounting treatment is applied. +The acquisition costs of unproved properties are capitalized when incurred until such properties are transferred to proved properties or charged to expense when expired, impaired, or amortized. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed, and any impairment in value is charged to impairment of crude oil and natural gas properties. The amount of impairment recognized on unproved properties which are not individually significant is determined by amortizing the costs of such properties within appropriate fields based on our historical experience, acquisition dates and average lease terms, with the amortization recognized in impairment of crude oil and natural gas properties. The valuation of unproved properties is subjective and requires us to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values. +We assess our crude oil and natural gas properties for possible impairment upon a triggering event, including when general industry conditions warrant, by comparing net capitalized costs to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity will be sold. Any impairment in value is charged to impairment of properties and equipment. The estimates of future prices may differ from current market prices of crude oil and natural gas. Any downward revisions in estimates to our reserve quantities, expectations of falling commodity prices, or rising operating costs could result in a triggering event, and therefore, a reduction in undiscounted future net cash flows and an impairment of our crude oil and natural gas properties. Although our cash flow estimates are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. +61 +Crude Oil, Natural Gas, and NGLs Sales Revenue Recognition. Crude oil, natural gas, and NGLs sales are recognized when production is sold to a purchaser at a determinable price, delivery has occurred, rights and responsibility of ownership have transferred and collection of revenue is reasonably assured. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas, and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes and prices received. We receive payment for sales from one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have been immaterial. If a sale is deemed uncollectible, an allowance for doubtful collection is recorded. There is a new revenue standard effective for annual reporting periods beginning after December 15, 2017. See the footnote titled Summary of Significant Accounting Policies - Recently Issued Accounting Standards . +Fair Value of Financial Instruments. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. +Commodity Derivative Financial Instruments. We measure the fair value of our commodity derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, natural gas, and crude oil forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of commodity derivative liabilities and the effect of our counterparties' credit standings on the fair value of commodity derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding commodity derivative position. +We validate our fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. While we believe our valuation method is appropriate and consistent with those used by other market participants, the use of a different methodology, or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value. +Net settlements on our commodity derivative instruments are initially recorded to accounts receivable or payable, as applicable, and may not be received from or paid to counterparties to our commodity derivative contracts within the same accounting period. Such settlements typically occur the month following the maturity of the commodity derivative instrument. We have evaluated the credit risk of the counterparties holding our commodity derivative assets, which are primarily financial institutions who are also major lenders in our revolving credit facility, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding commodity derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our counterparties on the fair value of our commodity derivative instruments is not significant. +Deferred Income Tax Asset Valuation Allowance. Deferred income tax assets are recognized for deductible temporary differences, net operating loss carry-forwards and credit carry-forwards if it is more likely than not that the tax +62 +benefits will be realized. To the extent a deferred tax asset is not expected to be realized under the preceding criteria, we establish a valuation allowance. The factors which we consider in assessing whether we will realize the value of deferred income tax assets involve judgments and estimates of both amount and timing. The judgments used in applying these policies are based on our evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results may differ from those estimates. +Accounting for Business Combinations. We utilize the purchase method to account for acquisitions of businesses and assets. The value of the purchase consideration takes into account the degree to which the consideration is objective and measurable such as cash consideration paid to a seller. With the issuance of equity, restrictions upon the sale of the issued stock are taken into consideration. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. The purchase price allocations are based on appraisals, discounted cash flows, quoted market prices, and estimates by management. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value as such sales represent the amount at which a willing buyer and seller would enter into an exchange for such properties. +In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped and unproved crude oil and natural gas properties, and other non-crude oil and natural gas properties. To estimate the fair values of these properties, we prepare estimates of crude oil and natural gas reserves. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. +We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. +Recent Accounting Standards +See the footnote titled Summary of Significant Accounting Policies - Recently Adopted Accounting Standards to our consolidated financial statements included elsewhere in this report. +Reconciliation of Non-U.S. GAAP Financial Measures +We use "adjusted cash flows from operations," "adjusted net income (loss)" and "adjusted EBITDAX," non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and, in some cases, providing public guidance on possible future results. Beginning in 2017, we have included non-cash stock-based compensation and exploration, geologic and geophysical expense in our reconciliation of adjusted EBITDAX calculation. In prior periods, we disclosed adjusted EBITDA, a non-U.S. GAAP financial measure that did not include these adjustments. We have elected to disclose Adjusted EBITDAX rather than Adjusted EBITDA in this report and other public disclosures because we believe it is more comparable to similar metrics presented by others in the industry. All prior periods have been conformed for comparability of this information. These measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss) or cash flows from operations, investing or financing activities, and should not be viewed as liquidity measures or indicators of cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. Also, in the future, we may disclose different non-U.S. GAAP financial measures in order to help our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and not rely on any single financial measure. +Adjusted cash flows from operations. We define adjusted cash flows from operations as the cash flows earned or incurred from operating activities, without regard to changes in operating assets and liabilities. We believe it is important to consider adjusted cash flows from operations, as well as cash flows from operations, as we believe it often provides more +63 +transparency into what drives the changes in our operating trends, such as production, prices, operating costs, and related operational factors, without regard to whether the related asset or liability was received or paid during the same period. We also use this measure because the timing of cash received from our assets, cash paid to obtain an asset or payment of our obligations has generally been a timing issue from one period to the next as we have not had significant accounts receivable collection problems, nor been unable to purchase assets or pay our obligations. +Adjusted net income (loss). We define adjusted net income (loss) as net income (loss), plus loss on commodity derivatives, less gain on commodity derivatives, and net settlements on commodity derivatives, each adjusted for tax effect. We believe it is important to consider adjusted net income (loss), as well as net income (loss). We believe this measure often provides more transparency into our operating trends, such as production, prices, operating costs, net settlements from derivatives, and related factors, without regard to changes in our net income (loss) from our mark-to-market adjustments resulting from net changes in the fair value of unsettled derivatives. Additionally, other items which are not indicative of future results may be excluded to clearly identify operating trends. +Adjusted EBITDAX. We define adjusted EBITDAX as net income (loss), plus loss on commodity derivatives, interest expense, net of interest income, income taxes, impairment of properties and equipment, exploration, geologic, and geophysical expense, depreciation, depletion and amortization expense, accretion of asset retirement obligations, and non-cash stock-based compensation, less gain on commodity derivatives and net settlements on commodity derivatives. Adjusted EBITDAX is not a measure of financial performance or liquidity under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss), and should not be considered an indicator of cash flows reported in accordance with U.S. GAAP. Adjusted EBITDAX includes certain non-cash costs incurred by us and does not take into account changes in operating assets and liabilities. Other companies in our industry may calculate adjusted EBITDAX differently than we do, limiting its usefulness as a comparative measure. We believe adjusted EBITDAX is relevant because it is a measure of our operational and financial performance, as well as a measure of our liquidity, and is used by our management, investors, commercial banks, research analysts, and others to analyze such things as: +• +operating performance and return on capital as compared to our peers; +• +financial performance of our assets and our valuation without regard to financing methods, capital structure, or historical cost basis; +• +our ability to generate sufficient cash to service our debt obligations; and +• +the viability of acquisition opportunities and capital expenditure projects, including the related rate of return. +PV-10. We define PV-10 as the estimated present value of the future net cash flows from our proved reserves before income taxes, discounted using a 10 percent discount rate. We believe that PV-10 provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. We believe that PV-10 is relevant and useful for evaluating the relative monetary significance of our reserves. Professional analysts, investors, and other users of our financial statements may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies' reserves. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable in evaluating us and our reserves. PV-10 is not intended to represent the current market value of our estimated reserves. +64 +The following table presents a reconciliation of our non-U.S. GAAP financial measures to its most comparable U.S. GAAP measure: +Year Ended December 31, +2017 +2016 +2015 +(in millions) +Adjusted cash flows from operations: +Net cash from operating activities +$ +588.6 +$ +486.3 +$ +411.1 +Changes in assets and liabilities +(6.5 +) +(19.5 +) +9.7 +Adjusted cash flows from operations +$ +582.1 +$ +466.8 +$ +420.8 +Adjusted net loss: +Net loss +$ +(127.5 +) +$ +(245.9 +) +$ +(68.3 +) +(Gain) loss on commodity derivative instruments +3.9 +125.7 +(203.2 +) +Net settlements on commodity derivative instruments +13.3 +208.1 +238.9 +Tax effect of above adjustments +(4.1 +) +(124.9 +) +(13.6 +) +Adjusted net loss +$ +(114.4 +) +$ +(37.0 +) +$ +(46.2 +) +Net loss to adjusted EBITDAX: +Net loss +$ +(127.5 +) +$ +(245.9 +) +$ +(68.3 +) +(Gain) loss on commodity derivative instruments +3.9 +125.7 +(203.2 +) +Net settlements on commodity derivative instruments +13.3 +208.1 +238.9 +Non-cash stock-based compensation +19.4 +19.5 +20.1 +Interest expense, net +76.4 +61.0 +42.8 +Income tax benefit +(211.9 +) +(147.2 +) +(38.3 +) +Impairment of properties and equipment +285.9 +10.0 +161.6 +Impairment of goodwill +75.1 +— +— +Exploration, geologic, and geophysical expense +47.3 +4.7 +1.1 +Depreciation, depletion, and amortization +469.1 +416.9 +303.3 +Accretion of asset retirement obligations +6.4 +7.0 +6.3 +Loss on extinguishment of debt +24.7 +— +— +Adjusted EBITDAX +$ +682.1 +$ +459.8 +$ +464.3 +Cash from operating activities to adjusted EBITDAX: +Net cash from operating activities +$ +588.6 +$ +486.3 +$ +411.1 +Interest expense, net +76.4 +61.0 +42.8 +Amortization of debt discount and issuance costs +(12.9 +) +(16.2 +) +(7.0 +) +Gain on sale of properties and equipment +0.7 +— +0.4 +Exploration, geologic, and geophysical expense +47.3 +4.7 +1.1 +Exploratory dry hole expense +(41.3 +) +— +— +Other +29.8 +(56.5 +) +6.2 +Changes in assets and liabilities +(6.5 +) +(19.5 +) +9.7 +Adjusted EBITDAX +$ +682.1 +$ +459.8 +$ +464.3 +PV-10: +PV-10 +$ +3,212.0 +$ +1,675.0 +$ +1,337.5 +Present value of estimated future income tax discounted at 10% +(331.9 +) +(254.4 +) +(240.6 +) +Standardized measure of discounted future net cash flows +$ +2,880.1 +$ +1,420.6 +$ +1,096.9 +Amounts above include results from continuing and discontinued operations. +65 +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Market-Sensitive Instruments and Risk Management +We are exposed to market risks associated with interest rate risks, commodity price risk, and credit risk. We have established risk management processes to monitor and manage these market risks. +Interest Rate Risk +Changes in interest rates affect the amount of interest we earn on our interest bearing cash and cash equivalents and the interest we pay on borrowings under our revolving credit facility. Our 2021 Convertible Notes, 2024 Senior Notes, and 2026 Senior Notes have fixed rates and, therefore, near-term changes in interest rates do not expose us to risk of earnings or cash flow loss; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt. +As of December 31, 2017 , our interest-bearing deposit accounts included money market accounts and checking accounts with various banks. The amount of our interest-bearing cash and cash equivalents as of December 31, 2017 was $ 179.6 million , with a weighted-average interest rate of one percent. Based on a sensitivity analysis of our interest bearing deposits as of December 31, 2017 and assuming we had $ 179.6 million outstanding throughout the period, we estimate that a one percent increase in interest rates would have increased interest income for the twelve months ended December 31, 2017 by approximately $ 1.8 million . +As of December 31, 2017 , we had no outstanding balance on our revolving credit facility. +Commodity Price Risk +We are exposed to the potential risk of loss from adverse changes in the market price of crude oil, natural gas, and NGLs. Pursuant to established policies and procedures, we manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. These instruments help us predict with greater certainty the effective crude oil, natural gas, and propane prices we will receive for our hedged production. We believe that our commodity derivative policies and procedures are effective in achieving our risk management objectives. +66 +The following table presents our commodity derivative positions related to crude oil, natural gas, and NGLs in effect as of December 31, 2017 : +Collars +Fixed-Price Swaps +Commodity/ Index/ +Maturity Period +Quantity +(Gas - +BBtu +Oil - MBbls) +Weighted-Average +Contract Price +Quantity (Oil - MBbls +Gas and Basis- +BBtu +Propane - MBbls) +Weighted- +Average +Contract +Price +Fair Value +December 31, +2017 (1) +(in millions) +Floors +Ceilings +Crude Oil +NYMEX +2018 +1,512.0 +$ +41.85 +$ +54.31 +10,372.0 +$ +52.93 +$ +(73.4 +) +2019 +— +— +— +6,600.0 +52.47 +(22.3 +) +Total Crude Oil +1,512.0 +16,972.0 +$ +(95.7 +) +Natural Gas +NYMEX +2018 +5,230.0 +$ +3.00 +$ +3.54 +51,280.0 +$ +2.95 +$ +7.3 +Total Natural Gas +5,230.0 +51,280.0 +$ +7.3 +Basis Protection - Crude Oil +Midland Cushing +2018 +— +— +— +1,809.9 +(0.10 +) +$ +(0.2 +) +Total Basis Protection - Crude Oil +— +1,809.9 +(0.2 +) +Basis Protection - Natural Gas +CIG +2018 +— +— +— +35,200.0 +$ +(0.36 +) +$ +5.2 +Waha +2018 +— +— +— +6,000.0 +(0.50 +) +1.3 +El Paso +2018 +— +— +— +3,000.0 +(0.62 +) +$ +0.5 +Total Basis Protection - Natural Gas +— +44,200.0 +$ +7.0 +Propane +Mont Belvieu +2018 +— +— +— +1,095.3 +$ +32.08 +$ +(4.6 +) +Total Propane +— +1,095.3 +$ +(4.6 +) +Rollfactor (2) +Crude Oil CMA +2018 +— +— +— +5,333.9 +0.12 +$ +(1.1 +) +Total Rollfactor +— +5,333.9 +(1.1 +) +Commodity Derivatives Fair Value +$ +(87.3 +) +_____________ +(1) +Approximately ten percent of the fair value of our commodity derivative assets and 11 percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3). +(2) +These positions hedge the timing risk associated with our physical sales. We generally sell crude oil for the delivery month at a sales price based on the average NYMEX West Texas Intermediate price during that month, plus an adjustment calculated as a spread between the weighted average prices of the delivery month, the next month and the following month during the period when the delivery month is the first month (the "trade month roll"). +67 +Our realized prices vary regionally based on local market differentials and our transportation agreements. The following table presents average market index prices for crude oil and natural gas for the periods identified, as well as the average sales prices we realized for our crude oil, natural gas, and NGLs production: +Year Ended December 31, +2017 +2016 +Average NYMEX Index Price: +Crude oil (per Bbl) +NYMEX +$ +50.95 +$ +43.32 +Natural gas (per MMBtu) +NYMEX +$ +3.11 +$ +2.46 +Average Sales Price Realized: +Excluding net settlements on commodity derivatives +Crude oil (per Bbl) +$ +48.45 +$ +39.96 +Natural gas (per Mcf) +2.21 +1.77 +NGLs (per Bbl) +18.59 +11.80 +Based on a sensitivity analysis as of December 31, 2017 , it was estimated that a 10 percent increase in natural gas, crude oil prices, and the propane portion of NGLs prices, inclusive of basis, over the entire period for which we have commodity derivatives in place would have resulted in a decrease in the fair value of our derivative positions of $119.3 million, whereas a 10 percent decrease in prices would have resulted in an increase in fair value of $118.0 million. +Credit Risk +Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure and entering into transactions with high-quality counterparties. When exposed to significant credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We monitor the creditworthiness of significant counterparties through our credit committee, which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. While we believe that our credit risk analysis and monitoring procedures are reasonable, no amount of analysis can assure financial performance by our counterparties. +Our oil and gas exploration and production business's crude oil, natural gas, and NGLs sales are concentrated with a few predominately large customers. This concentrates our credit risk exposure with a small number of large customers. +Amounts due to our gas marketing business are from a diverse group of entities. The underlying operations of these entities are geographically concentrated in the same region, which increases the credit risk associated with this business. As natural gas prices continue to remain depressed, certain third-party producers committed to providing natural gas to our gas marketing business continue to experience financial distress, which has led to certain contractual defaults and litigation; however, to date, we have had no material counterparty default losses. We have initiated several legal actions for breach of contract and collection claims against certain third-party producers that are delinquent in their payment obligations. We expect this trend to continue for this business segment. +We primarily use financial institutions which are lenders in our revolving credit facility as counterparties for our derivative financial instruments. Disruption in the credit markets, changes in commodity prices and other factors may have a significant adverse impact on a number of financial institutions. To date, we have had no material counterparty default losses from our commodity derivative financial instruments. See the footnote titled Commodity Derivative Financial Instruments to our consolidated financial statements included elsewhere in this report for more detail on our commodity derivative financial instruments. +Disclosure of Limitations +Because the information above included only those exposures that existed at December 31, 2017 , it does not consider those exposures or positions which could arise after that date. Our ultimate realized gain or loss with respect to interest rate +68 +and commodity price fluctuations will depend on the exposures that arise during the period, our commodity price risk management strategies at the time and interest rates and commodity prices at the time. +69 +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Index to Consolidated Financial Statements, Financial Statement Schedule and Supplemental Information +Financial Statements: +Report of Independent Registered Public Accounting Firm +71 +Consolidated Balance Sheets - December 31, 201 7 and 2016 +73 +Consolidated Statements of Operations - Years Ended December 31, 2 017, 2016, and 2015 +74 +Consolidated Statements of Cash Flows - Years Ended December 31, 201 7, 2016, and 2015 +75 +Consolidated Statements of Equity - Years Ended December 31, 201 7, 2016, and 2015 +77 +Notes to Consolidated Financial Statements +78 +Supplemental Information - Unaudited: +Crude Oil and Natural Gas Information +119 +Quarterly Financial Information +126 +Financial Statement Schedule: +Schedule II - Valuation and Qualifying Accounts - Years Ended December 31, 2017, 2016, and 2015 +127 +70 +Report of Independent Registered Public Accounting Firm +To the Board of Directors and Shareholders of PDC Energy, Inc. +Opinions on the Financial Statements and Internal Control over Financial Reporting +We have audited the accompanying consolidated balance sheets of PDC Energy, Inc. and its subsidiaries as of December 31, 2017 and 2016, and the related consolidated statements of operations, equity and cash flows for each of the three years in the period ended December 31, 2017, including the related notes and financial statement schedule listed in the accompanying index (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016 , and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2017 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2017 based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO because material weaknesses in internal control over financial reporting existed as of that date related to not maintaining a sufficient complement of personnel within the Land Department as a result of increased volume of leases, which contributed to the ineffective design and maintenance of controls to verify the completeness and accuracy of land administrative records associated with unproved leases. +A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. The material weaknesses referred to above are described in Management's Report on Internal Control over Financial Reporting appearing under Item 9A. We considered these material weaknesses in determining the nature, timing, and extent of audit tests applied in our audit of the 2017 consolidated financial statements, and our opinion regarding the effectiveness of the Company’s internal control over financial reporting does not affect our opinion on those consolidated financial statements. +Basis for Opinions +The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in management's report referred to above. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. +Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. +71 +Definition and Limitations of Internal Control over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/PricewaterhouseCoopers LLP +Denver, Colorado +February 26, 2018 +We have served as the Company’s auditor since 2007. +72 +PDC ENERGY, INC. +Consolidated Balance Sheets +(in thousands, except share and per share data) +As of December 31, +2017 +2016 +Assets +Current assets: +Cash and cash equivalents +$ +180,675 +$ +244,100 +Accounts receivable, net +197,598 +143,392 +Fair value of derivatives +14,338 +8,791 +Prepaid expenses and other current assets +8,613 +3,542 +Total current assets +401,224 +399,825 +Properties and equipment, net +3,933,467 +4,002,994 +Assets held-for-sale, net +40,084 +5,272 +Fair value of derivatives +— +2,386 +Goodwill +— +62,041 +Other assets +45,116 +13,324 +Total Assets +$ +4,419,891 +$ +4,485,842 +Liabilities and Stockholders' Equity +Liabilities +Current liabilities: +Accounts payable +$ +150,067 +$ +66,322 +Production tax liability +37,654 +24,767 +Fair value of derivatives +79,302 +53,595 +Funds held for distribution +95,811 +71,339 +Accrued interest payable +11,815 +15,930 +Other accrued expenses +42,987 +38,625 +Total current liabilities +417,636 +270,578 +Long-term debt +1,151,932 +1,043,954 +Deferred income taxes +191,992 +400,867 +Asset retirement obligations +71,006 +82,612 +Fair value of derivatives +22,343 +27,595 +Other liabilities +57,333 +37,482 +Total liabilities +1,912,242 +1,863,088 +Commitments and contingent liabilities +Stockholders' equity +Common shares - par value $0.01 per share, 150,000,000 authorized, 65,955,080 and 65,704,568 issued as of December 31, 2017 and 2016, respectively +659 +657 +Additional paid-in capital +2,503,294 +2,489,557 +Retained earnings +6,704 +134,208 +Treasury shares - at cost, 55,927 and 28,763 as of December 31, 2017 and 2016, respectively +(3,008 +) +(1,668 +) +Total stockholders' equity +2,507,649 +2,622,754 +Total Liabilities and Stockholders' Equity +$ +4,419,891 +$ +4,485,842 +See accompanying Notes to Consolidated Financial Statements +73 +PDC ENERGY, INC. +Consolidated Statements of Operations +(in thousands, except per share data) +Year Ended December 31, +2017 +2016 +2015 +Revenues +Crude oil, natural gas, and NGLs sales +$ +913,084 +$ +497,353 +$ +378,713 +Commodity price risk management gain (loss), net +(3,936 +) +(125,681 +) +203,183 +Other income +12,468 +11,243 +13,430 +Total revenues +921,616 +382,915 +595,326 +Costs, expenses and other +Lease operating expenses +89,641 +59,950 +56,992 +Production taxes +60,717 +31,410 +18,443 +Transportation, gathering, and processing expenses +33,220 +18,415 +10,151 +Exploration, geologic, and geophysical expense +47,334 +4,669 +1,102 +Impairment of properties and equipment +285,887 +9,973 +161,620 +Impairment of goodwill +75,121 +— +— +General and administrative expense +120,370 +112,470 +89,959 +Depreciation, depletion and amortization +469,084 +416,874 +303,258 +Provision for uncollectible notes receivable +(40,203 +) +44,038 +— +Accretion of asset retirement obligations +6,306 +7,080 +6,293 +Gain on sale of properties and equipment +(766 +) +(43 +) +(385 +) +Other expenses +13,157 +10,193 +11,717 +Total costs, expenses and other +1,159,868 +715,029 +659,150 +Loss from operations +(238,252 +) +(332,114 +) +(63,824 +) +Loss on extinguishment of debt +(24,747 +) +— +— +Interest expense +(78,694 +) +(61,972 +) +(47,571 +) +Interest income +2,261 +963 +4,807 +Loss before income taxes +(339,432 +) +(393,123 +) +(106,588 +) +Income tax benefit +211,928 +147,195 +38,308 +Net loss +$ +(127,504 +) +$ +(245,928 +) +$ +(68,280 +) +Earnings per share: +Basic +$ +(1.94 +) +$ +(5.01 +) +$ +(1.74 +) +Diluted +$ +(1.94 +) +$ +(5.01 +) +$ +(1.74 +) +Weighted-average common shares outstanding: +Basic +65,837 +49,052 +39,153 +Diluted +65,837 +49,052 +39,153 +See accompanying Notes to Consolidated Financial Statements +74 +PDC ENERGY, INC. +Consolidated Statements of Cash Flows +(in thousands) +Year Ended December 31, +2017 +2016 +2015 +Cash flows from operating activities: +Net loss +$ +(127,504 +) +$ +(245,928 +) +$ +(68,280 +) +Adjustments to net loss to reconcile to net cash from operating activities: +Net change in fair value of unsettled commodity derivatives +17,260 +333,770 +35,791 +Depreciation, depletion and amortization +469,084 +416,874 +303,258 +Provision for uncollectible notes receivable +(40,203 +) +44,038 +— +Impairment of properties and equipment +285,887 +9,973 +161,620 +Impairment of goodwill +75,121 +— +— +Exploratory dry hole costs +41,297 +— +— +Loss on extinguishment of debt +24,747 +— +— +Accretion of asset retirement obligations +6,306 +7,080 +6,293 +Non-cash stock-based compensation +19,353 +19,502 +20,068 +Gain on sale of properties and equipment +(766 +) +(43 +) +(385 +) +Amortization of debt discount and issuance costs +12,907 +16,167 +7,040 +Deferred income taxes +(203,685 +) +(137,249 +) +(41,415 +) +Other +2,265 +2,603 +(3,216 +) +Total adjustments to net loss to reconcile to net cash from operating activities: +709,573 +712,715 +489,054 +Changes in assets and liabilities: +Accounts receivable +(60,546 +) +(32,627 +) +24,815 +Other assets +(5,886 +) +2,303 +(2,264 +) +Production tax liability +31,316 +9,223 +(1,629 +) +Accounts payable and accrued expenses +31,378 +(162 +) +(30,310 +) +Funds held for future distribution +24,472 +36,510 +2,699 +Asset retirement obligations +(10,176 +) +(4,109 +) +(4,458 +) +Other liabilities +(4,064 +) +8,338 +1,446 +Total changes in assets and liabilities +6,494 +19,476 +(9,701 +) +Net cash from operating activities +588,563 +486,263 +411,073 +Cash flows from investing activities: +Capital expenditures for development of crude oil and natural gas properties +(737,208 +) +(436,884 +) +(599,546 +) +Capital expenditures for other properties and equipment +(5,094 +) +(3,464 +) +(5,122 +) +Acquisition of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition +(15,628 +) +(1,073,723 +) +— +Proceeds from sale of properties and equipment +9,991 +4,945 +405 +Sale of promissory note +40,203 +— +— +Restricted cash +(9,250 +) +— +— +Sale of short-term investments +49,890 +— +— +Purchase of short-term investments +(49,890 +) +— +— +Net cash from investing activities +(716,986 +) +(1,509,126 +) +(604,263 +) +Cash flows from financing activities: +Proceeds from issuance of equity, net of issuance costs +— +855,074 +202,851 +Proceeds from issuance of senior notes +592,366 +392,172 +— +Proceeds from issuance of convertible senior notes +— +193,935 +— +Proceeds from revolving credit facility +— +85,000 +397,000 +Repayment of revolving credit facility +— +(122,000 +) +(416,000 +) +Redemption of senior notes +(519,375 +) +— +— +Redemption of convertible notes +— +(115,000 +) +— +Payment of debt issuance costs +(50 +) +(15,556 +) +(974 +) +Purchase of treasury shares +(6,672 +) +(6,935 +) +(6,055 +) +Other +(1,271 +) +(577 +) +1,152 +Net cash from financing activities +64,998 +1,266,113 +177,974 +Net change in cash and cash equivalents +(63,425 +) +243,250 +(15,216 +) +Cash and cash equivalents, beginning of year +244,100 +850 +16,066 +Cash and cash equivalents, end of year +$ +180,675 +$ +244,100 +$ +850 +See accompanying Notes to Consolidated Financial Statements +75 +Supplemental cash flow information: +Cash payments (receipts) for: +Interest, net of capitalized interest +$ +69,880 +$ +43,406 +$ +45,642 +Income taxes +(13,925 +) +167 +10,049 +Non-cash investing activities: +Issuance of common stock for acquisition of crude oil and natural gas properties +— +690,702 +— +Change in accounts payable related to capital expenditures +50,761 +(40,448 +) +(45,230 +) +Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposal +839 +4,894 +14,030 +Purchase of properties and equipment under capital leases +3,497 +1,404 +1,601 +See footnote titled Business Combinations for non-cash transactions related to our acquisitions. +See accompanying Notes to Consolidated Financial Statements +76 +PDC ENERGY, INC. +Consolidated Statements of Equity +(in thousands, except share data) +Common Stock +Treasury Stock +Shares +Amount +Additional Paid-in Capital +Shares +Amount +Retained Earnings +Total Stockholders' Equity +Balances, January 1, 2015 +35,927,985 +$ +359 +$ +689,209 +(21,643 +) +$ +(911 +) +$ +448,702 +$ +1,137,359 +Net loss +— +— +— +— +— +(68,280 +) +(68,280 +) +Issuance pursuant to sale of equity +4,002,000 +40 +202,811 +— +— +— +202,851 +Purchase of treasury shares +— +— +— +(120,864 +) +(6,055 +) +— +(6,055 +) +Issuance of treasury shares +— +— +(6,206 +) +127,159 +6,206 +— +— +Non-employee directors' deferred compensation plan +— +— +— +(4,872 +) +(249 +) +— +(249 +) +Issuance of stock awards, net of forfeitures +244,791 +3 +— +— +— +— +3 +Stock-based compensation expense, including tax impact +— +— +21,568 +— +— +— +21,568 +Balances, December 31, 2015 +40,174,776 +$ +402 +$ +907,382 +(20,220 +) +$ +(1,009 +) +$ +380,422 +$ +1,287,197 +Net loss +— +— +— +— +— +(245,928 +) +(245,928 +) +Issuance pursuant to acquisition +9,386,768 +94 +690,608 +— +— +— +690,702 +Issuance pursuant to sale of equity +15,007,500 +150 +854,933 +— +— +— +855,083 +Convertible debt discount, net of issuance costs and tax +— +— +23,518 +— +— +— +23,518 +Purchase of treasury shares +— +— +— +(116,085 +) +(6,935 +) +— +(6,935 +) +Issuance pursuant to note conversion +792,406 +8 +(8 +) +— +— +— +— +Issuance of treasury shares +(114,697 +) +(6,661 +) +114,697 +6,661 +— +— +Non-employee directors' deferred compensation plan +— +— +— +(7,155 +) +(385 +) +— +(385 +) +Issuance of stock awards, net of forfeitures +411,731 +3 +(3 +) +— +— +— +— +Exercise of stock options +46,084 +— +— +— +— +— +— +Stock-based compensation expense +— +— +19,502 +— +— +— +19,502 +Other +— +— +286 +— +— +(286 +) +— +Balances, December 31, 2016 +65,704,568 +$ +657 +$ +2,489,557 +(28,763 +) +$ +(1,668 +) +$ +134,208 +$ +2,622,754 +Net loss +— +— +— +— +— +(127,504 +) +(127,504 +) +Purchase of treasury shares +— +— +— +(107,357 +) +(6,672 +) +— +(6,672 +) +Issuance of treasury shares +— +— +(5,517 +) +83,228 +5,517 +— +— +Non-employee directors' deferred compensation plan +— +— +— +(3,035 +) +(185 +) +— +(185 +) +Issuance of stock awards, net of forfeitures +250,512 +2 +(2 +) +— +— +— +— +Stock-based compensation expense +— +— +19,353 +— +— +— +19,353 +Other +— +— +(97 +) +— +— +— +(97 +) +Balance, December 31, 2017 +65,955,080 +$ +659 +$ +2,503,294 +(55,927 +) +$ +(3,008 +) +$ +6,704 +$ +2,507,649 +See accompanying Notes to Consolidated Financial Statements +77 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION +PDC Energy, Inc. ("PDC", the "Company," "we," "us," or "our") is a domestic independent exploration and production company that acquires, explores and develops properties for the production of crude oil, natural gas, and NGLs, with primary operations in the Wattenberg Field in Colorado and the Delaware Basin in Texas . Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are currently focused in the Wolfcamp zones. We also have operations in the Utica Shale in Southeastern Ohio; however, in 2017, we began actively marketing the Utica Shale properties for sale; therefore, these properties are classified as held-for-sale as they met the criteria for such classification during the third quarter of 2017. In February 2018, we entered into a PSA for the sale of these properties for net cash proceeds of approximately $40.0 million , subject to the terms and conditions of the agreement. As of December 31, 2017 , we owned an interest in approximately 2,800 productive gross wells. We are engaged in two operating segments: our oil and gas exploration and production segment and our gas marketing segment. Beginning in 2017, our gas marketing segment does not meet the quantitative thresholds to require disclosure as a separate reportable segment. All of our material operations are attributable to our exploration and production business; therefore, all of our operations are presented as a single segment for all periods presented. +The audited consolidated financial statements include the accounts of PDC, our wholly-owned subsidiaries, and our proportionate share of our two affiliated partnerships. All intercompany accounts and transactions have been eliminated in consolidation. +The preparation of our consolidated financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of crude oil, natural gas and NGLs sales revenue; crude oil, natural gas, and NGLs reserves; estimates of unpaid revenues and unbilled costs; future cash flows from crude oil and natural gas properties; valuation of commodity derivative instruments; exploratory dry hole costs; impairment of proved and unproved properties; impairment of goodwill; valuation and allocations of purchased businesses and assets; estimates of fair value of our fixed rate debt instruments; and valuation of deferred income tax assets. +Certain immaterial reclassifications have been made to our prior period balance sheet and statement of operations to conform to the current period presentation. The reclassifications had no impact on previously reported cash flows, net earnings, earnings per share, or stockholders' equity. +NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Cash Equivalents. We consider all highly liquid investments with original maturities of three months or less to be cash equivalents. +Commodity Derivative Financial Instruments. We are exposed to the effect of market fluctuations in the prices of crude oil, natural gas, and NGLs. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy and our revolving credit facility prohibit the use of crude oil and natural gas derivative instruments for speculative purposes. +All derivative assets and liabilities are recorded on our consolidated balance sheets at fair value. We have elected not to designate any of our commodity derivative instruments as cash flow hedges. Accordingly, changes in the fair value of our commodity derivative instruments are recorded in the consolidated statements of operations. We use the normal purchase, normal sale exception for our crude oil and natural gas contracts. Classification of net settlements resulting from maturities and changes in fair value of unsettled commodity derivatives depends on the purpose for issuing or holding the derivative. Net settlements and changes in the fair value of commodity derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Net settlements and changes in the fair value of commodity derivative instruments related to our Gas Marketing segment are recorded in other income and other expenses. The consolidated statements of cash flows reflects the net settlement of commodity derivative instruments in operating cash flows. +The calculation of the commodity derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. +78 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Properties and Equipment. Significant accounting polices related to our properties and equipment are discussed below. +Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells, and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method, based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. We have determined that we have three units-of-production fields: the Wattenberg Field, the Delaware Basin, and the Utica Shale. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations, and common cost environments in these areas. We calculate quarterly depreciation, depletion, and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted to add back fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the consolidated statement of operations as a gain or loss. Upon the sale of individual wells or a portion of a field, the proceeds are credited to accumulated DD&A. +Exploration costs, including geologic and geophysical expenses, seismic costs on unproved leasehold, and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability, or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as "suspended well costs" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the proper accounting treatment is recorded. +Proved Property Impairment. Upon a triggering event, including when general industry conditions warrant review, we assess our producing crude oil and natural gas properties for possible impairment by comparing net capitalized costs, or carrying value, to estimated undiscounted future net cash flows on a field-by-field basis using estimated production based upon prices at which we reasonably estimate the commodity will be sold. The estimates of future prices may differ from current market prices of crude oil, natural gas, and NGLs. Certain events, including but not limited to downward revisions in estimates of our reserve quantities, expectations of falling commodity prices, or rising operating costs, could result in a triggering event, and therefore a possible impairment of our proved crude oil and natural gas properties. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis. The impairment recorded is the amount by which the net capitalized costs exceed fair value. Impairments are included in the consolidated statements of operations line item impairment of properties and equipment, with a corresponding impact on accumulated DD&A. +Unproved Property Impairment. The acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense when expired, impaired, or amortized. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized, by field, based on our historical experience, acquisition dates, and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statements of operations line item impairment of properties and equipment. +79 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Other Property and Equipment. Other property and equipment is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives. We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of the asset exceeds our estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. Impairment and amortization charges related to other property and equipment are charged to the consolidated statements of operations line item impairment of properties and equipment. +The following table presents the estimated useful lives of our other property and equipment: +Transportation, pipeline, and other equipment +2 - 30 years +Buildings +20 - 40 years +Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed from the accounts, the proceeds are applied thereto, and any resulting gain or loss is reflected in income. Total depreciation expense related to other property and equipment was $6.6 million , $3.8 million , and $4.5 million in 2017 , 2016 , and 2015 , respectively. +Capitalized Interest. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A expense is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our outstanding debt by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $5.0 million , $4.5 million , and $5.1 million in 2017 , 2016 , and 2015 , respectively. +Goodwill. Goodwill represents the excess of the purchase price over the fair value of net assets acquired, including the additional value resulting from the creation of the deferred tax liability, and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Among the factors that could contribute to a purchase price in excess of the fair value of the net tangible and intangible assets acquired is the acquisition of an element of a workforce and the expected value from operations of the acquisition to be derived in the future, such as production from future development of additional producing zones. +We evaluate goodwill for impairment by performing a quantitative test, which involves comparing the estimated fair value of the goodwill reporting unit to the carrying value. We determine the fair value of the goodwill at the impairment evaluation date by using an estimated after-tax future discounted cash flow analysis, along with a combination of market-based pricing factors for similar acreage, reserve valuation techniques, and other fair value considerations. The discounted cash flow analysis used to estimate fair value is based on known or knowable information at the interim measurement date. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. +Assets Held-for-Sale. Assets held-for-sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, valuations performed by third parties, earnings multiples, or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets to be divested once they are classified as held-for-sale. Assets classified as held-for-sale are expected to be disposed of within one year. Assets to be divested are classified in the consolidated financial statements as held-for-sale. +Production Tax Liability. Production tax liability represents estimated taxes, primarily severance, ad valorem, and property taxes, to be paid to the states and counties in which we produce crude oil, natural gas, and NGLs. These taxes are expensed and included in the statements of operations line item production taxes. The long-term portion of the production tax liability is included in other liabilities on the consolidated balance sheets and was $50.5 million and $29.0 million in December 31, 2017 and 2016 , respectively. +80 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable. As of December 31, 2017 and 2016 , we had no valuation allowance. +Debt Issuance Costs. Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs for the 2021 Convertible Notes, the 2024 Senior Notes, and the 2026 Senior Notes are included in long-term debt on the consolidated balance sheets and the debt issuance costs for the revolving credit facility are included in other assets on the consolidated balance sheets. +Asset Retirement Obligations. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from, among other things, changes in retirement costs or the estimated timing of settling asset retirement obligations. +Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders’ equity in the consolidated balance sheets. When we retire treasury shares, we charge any excess of cost over the par value to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings. +Revenue Recognition. Significant accounting polices related to our revenue recognition are discussed below. +Crude oil, natural gas, and NGLs sales. Crude oil, natural gas, and NGLs revenues are recognized when production is sold to a purchaser at a fixed or determinable price, delivery has occurred, rights and responsibility of ownership have transferred, and collection of revenue is reasonably assured. Our crude oil, natural gas, and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related purchase agreement. We use the net-back method when the purchasers of these commodities also provide transportation, gathering, or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the indices for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. +We use the gross method of accounting when the purchasers do not provide transportation, gathering, or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering, and processing expenses. +There is a new revenue standard effective for annual reporting periods beginning after December 15, 2017. See Recently Issued Accounting Standards below. +Accounting for Business Combinations. We utilize the purchase method to account for acquisitions of businesses. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows, quoted market prices, and estimates by management, which are Level 3 inputs. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. +In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non- +81 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +producing, proved undeveloped, unproved crude oil and natural gas properties, and other non-crude oil and natural gas properties. To estimate the fair value of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs, to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of comparable purchased properties to determine an estimation of fair value. +We record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities, except goodwill. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. +Stock-Based Compensation. Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the vesting period for the entire award. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statements of operations. No amounts for stock-based compensation were capitalized in 2017 , 2016 , or 2015 . +Credit Risk and Allowance for Doubtful Accounts. Inherent to our industry is the concentration of crude oil, natural gas, and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices, or other conditions. We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs and the overall creditworthiness of our customers. Further, consideration is given to well production data for receivables related to well operations. +Recently Adopted Accounting Standards. +In January 2017, the FASB issued an accounting update to simplify the measurement of goodwill. The update eliminates the two-step process that required identification of potential impairment and a separate measure of actual impairment. The annual and/or interim assessments are still required to be completed. The guidance is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with early adoption permitted. We elected to early adopt this standard in the second quarter of 2017. Our annual evaluation of goodwill for impairment was expected to occur in the fourth quarter of 2017; however, we experienced an impairment triggering event as of September 30, 2017 and implemented the new guidance as part of the impairment evaluation. See the footnote titled Goodwill for a detailed description of the results of our impairment testing. +In August 2016, the FASB issued an accounting update on statements of cash flows to address diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. The update addresses eight specific cash flow issues with the objective of reducing the existing diversity in practice. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We elected to early adopt this standard in the fourth quarter of 2017. Adoption of this standard did not have an impact on our consolidated financial statements or related disclosures. +In January 2017, the FASB issued an accounting update clarifying the definition of a business, with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. This guidance is to be applied using a prospective method and is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We elected to early adopt this standard in the fourth quarter of 2017. Adoption of this standard did not have an impact on our consolidated financial statements or related disclosures. +82 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +In May 2017, the FASB issued an accounting update clarifying when to account for a change to the terms or conditions of a share-based payment award as a modification. The guidance is effective for fiscal years beginning on or after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We elected to early adopt this standard in the fourth quarter of 2017. Adoption of this standard did not have an impact on our consolidated financial statements or related disclosures. +Recently Issued Accounting Standards +In May 2014, the FASB and the International Accounting Standards Board issued their converged standard on revenue recognition that provides a single, comprehensive model that entities will apply to determine the measurement of revenue and timing of when it is recognized. The standard has been updated and now includes technical corrections. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (1) identify the contract with the customer, (2) identify the separate performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to separate performance obligations, and (5) recognize revenue when or as each performance obligation is satisfied. The revenue standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period; we are adopting the standard effective January 1, 2018. The revenue standard can be adopted under the full retrospective method or modified retrospective method. In order to evaluate the impact that the adoption of the revenue standard will have on our consolidated financial statements, we have performed a comprehensive review of our significant revenue streams. The focus of this review included, among other things, the identification of the significant contracts and other arrangements we have with our customers to identify performance obligations and principal versus agent considerations, and factors affecting the determination of the transaction price. We are also reviewing our current accounting policies, procedures, and controls with respect to these contracts and arrangements to determine what changes, if any, may be required by the adoption of the revenue standard. We have determined that we will adopt the standard under the modified retrospective method. Based upon our review, we currently estimate that adoption of the standard would have reduced our crude oil, natural gas, and NGLs sales by approximately $11.3 million in 2017 with corresponding decreases in transportation, gathering, and processing expenses and no impact on net earnings. Upon adoption, no adjustment to our opening balance of retained earnings was deemed necessary. +In February 2016, the FASB issued an accounting update aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements. For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. Both the lease asset and liability will initially be measured at the present value of the future minimum lease payments over the lease term. Subsequent measurement, including the presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those years, with early adoption permitted, and is to be applied as of the beginning of the earliest period presented using a modified retrospective approach. The update does not apply to leases of mineral rights to explore for or use crude oil and natural gas. We are currently evaluating the impact these changes may have on our consolidated financial statements. +In November 2016, the FASB issued an accounting update on statements of cash flows to address diversity in practice in the classification and presentation of changes in restricted cash. The accounting update requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash or restricted cash equivalents should be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period amounts shown on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our consolidated financial statements. +In August 2017, the FASB issued an accounting update to provide guidance for various components of hedge accounting, including hedge ineffectiveness, the expansion of types of permissible hedging strategies, reduced complexity in the application of the long-haul method for fair value hedges and reduced complexity in assessment of effectiveness. The guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. We are currently evaluating the impact these changes may have on our consolidated financial statements. +83 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 3 - BUSINESS COMBINATIONS +Delaware Basin Acquisition. On December 6, 2016, we closed on an acquisition which was accounted for as a business combination. The acquisition consisted of the purchase of stock of an entity and assets of other entities under common control. The transaction was for the purchase of approximately 57,900 net acres, approximately 30 completed and producing wells and related midstream infrastructure in Reeves and Culberson Counties, Texas, for an aggregate consideration to the sellers of approximately $1.64 billion , after preliminary post-closing adjustments. The total consideration to sellers was comprised of approximately $ 946.0 million in cash, including the payment of $ 40.0 million of debt of the sellers at closing and other purchase price adjustments, and 9.4 million shares of our common stock valued at approximately $ 690.7 million at the time the acquisition closed. The purchase accounting for the entity, the stock of which we acquired, reflected oil and gas assets for which we did not receive a fair value step-up of the tax basis. As a result, a significant deferred income tax liability was calculated based on the acquired allocated fair value of the assets in excess of the tax basis of assets inside the entity. This calculation resulted in approximately $ 375.0 million of non-cash basis needing to be allocated to the acquired assets. No deferred tax liability was established for the calculated goodwill as it did not qualify as tax goodwill. +The final fair value allocation of the assets acquired and liabilities assumed in the acquisition are presented below and include customary post-closing adjustments. The most significant item to be completed during the final purchase price allocation in the third quarter of 2017 was the final allocation of value to the unproved oil and gas properties associated with the acquired acreage. Adjustments to the preliminary purchase price primarily stem from additional information we obtained about facts and circumstances that existed at the acquisition date that impact the underlying value of certain assets acquired and liabilities assumed, including detailed lease terms, location of the acreage, and intent to develop the acreage as of the date of closing. There were a significant number of leases acquired with complex lease terms and evaluation of these terms and the timing of the lease expirations impacted the manner in which the final purchase price was allocated. Our final determination of the value of goodwill has been adjusted for all post-closing adjustments. +The details of the final purchase price and the allocation of the purchase price for the transaction, are presented below (in thousands): +Year Ended December 31, 2016 +Acquisition costs: +Cash, net of cash acquired +$ +905,962 +Retirement of seller's debt +40,000 +Total cash consideration +945,962 +Common stock +690,702 +Other purchase price adjustments +426 +Total acquisition costs +$ +1,637,090 +Recognized amounts of identifiable assets acquired and liabilities assumed: +Assets acquired: +Current Assets +$ +6,401 +Crude oil and natural gas properties - proved +216,000 +Crude oil and natural gas properties - unproved +1,697,000 +Infrastructure, pipeline, and other +33,153 +Construction in progress +12,323 +Goodwill +75,121 +Total assets acquired +2,039,998 +Liabilities assumed: +Current liabilities +(24,496 +) +Asset retirement obligations +(3,705 +) +Deferred tax liabilities, net +(374,707 +) +Total liabilities assumed +(402,908 +) +Total identifiable net assets acquired +$ +1,637,090 +84 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, lease terms and expirations, and a market-based weighted-average cost of capital rate. Within the unproven properties, the allocation of the value to the underlying leases also required significant judgment and was based on a combination of comparable market transactions, the terms and conditions associated with the individual leases, our ability and intent to develop specific leases, and our initial assessment of the underlying relative value of the leases given our knowledge of the geology at the time of closing. These inputs require significant judgments and estimates by management at the time of the valuation and were the most sensitive and subject to change. +This acquisition was accounted for under the acquisition method. Accordingly, we conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. +Pro Forma Information. The results of operations for the Delaware Basin acquisition have been included in our consolidated financial statements since the December 6, 2016 closing date, including approximately $5.6 million of total revenue and $1.7 million of loss from operations in our statements of operations for the year ended December 31, 2016. The following unaudited pro forma financial information represents a summary of the consolidated results of operations for the years ended December 31, 2016 and December 31, 2015, assuming the acquisition had been completed as of January 1, 2015. This pro forma financial information includes proceeds from the sale of 9,085,000 shares of our common stock, the 2021 Convertible Notes, and the 2024 Senior Notes in September 2016, the shares issued to the sellers, and other acquisition costs. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the acquisition had been effective as of these dates, or of future results. +Years Ended December 31, +2016 +2015 +(in thousands, except per share amounts) +Total revenue +$ +412,746 +$ +598,932 +Net loss +$ +(270,942 +) +$ +(138,904 +) +Earnings per share: +Basic and diluted +$ +(4.22 +) +$ +(2.41 +) +Goodwill. Goodwill was calculated as the excess of the purchase price over the fair value of net assets acquired, including the additional value resulting from the creation of the deferred tax liability, and represents the future economic benefits arising from other assets acquired that could not be individually identified and separately recognized. Among the factors that contributed to a purchase price in excess of the fair value of the net tangible and intangible assets acquired were the acquisition of an element of a workforce and the expected value from operations of the Delaware Basin acquisition to be derived in the future, such as production from future development of additional producing zones. The amount of the final goodwill that was recorded in the third quarter of 2017 related to the Delaware Basin acquisition was $75.1 million , which was higher than the initial estimated amount recorded as of December 31, 2016. The increase primarily related to finalization of the aggregate acreage position acquired and the related lease terms and a final settlement with the sellers in connection with a revised valuation of certain acquired leases and the retirement of estimated environmental remediation liabilities. Any value assigned to goodwill was not expected to be deductible for income tax purposes. +The following table presents the changes in goodwill from the preliminary allocation at December 31, 2016, and the final allocation determined during the third quarter of 2017: +Amount +(in thousands) +Preliminary purchase price allocation +$ +62,041 +Adjustments +13,080 +Final purchase price allocation +$ +75,121 +85 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +See the footnote titled Goodwill for the details regarding the impairment of goodwill related to the Delaware Basin acquisition. +86 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 4 - FAIR VALUE OF FINANCIAL INSTRUMENTS +Commodity Derivative Financial Instruments +Determination of fair value. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. +Commodity Derivative Financial Instruments. We measure the fair value of our commodity derivative instruments based on a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors, and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. +We validate our fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. While we use common industry practices to develop our valuation techniques and believe our valuation method is appropriate and consistent with those used by other market participants, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. +Our crude oil and natural gas fixed-price swaps are included in Level 2. Our collars and propane fixed-price swaps are included in Level 3. Our basis swaps are included in Level 2 and Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis: +As of December 31, +2017 +2016 +Significant Other +Observable +Inputs +(Level 2) +Significant +Unobservable +Inputs +(Level 3) +Total +Significant Other +Observable +Inputs +(Level 2) +Significant +Unobservable +Inputs +(Level 3) +Total +(in thousands) +Total assets +$ +12,949 +$ +1,389 +$ +14,338 +$ +6,350 +$ +4,827 +$ +11,177 +Total liabilities +90,569 +11,076 +101,645 +66,789 +14,401 +81,190 +Net liability +$ +(77,620 +) +$ +(9,687 +) +$ +(87,307 +) +$ +(60,439 +) +$ +(9,574 +) +$ +(70,013 +) +87 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents a reconciliation of our Level 3 commodity derivative instruments measured at fair value: +2017 +2016 +2015 +(in thousands) +Fair value of Level 3 instruments, net asset (liability) beginning of period +$ +(9,574 +) +$ +91,288 +$ +62,356 +Changes in fair value included in consolidated statements of operations line item: +Commodity price risk management gain (loss), net +6,241 +(28,550 +) +65,164 +Settlements included in consolidated statements of operations line items: +Commodity price risk management ( loss) , net +(6,354 +) +(72,312 +) +(36,232 +) +Fair value of Level 3 instruments, net asset (liability) end of period +$ +(9,687 +) +$ +(9,574 +) +$ +91,288 +Net change in fair value of Level 3 unsettled derivatives included in consolidated statements of operations line item: +Commodity price risk management gain (loss), net +$ +(866 +) +$ +(12,905 +) +$ +43,540 +Total +$ +(866 +) +$ +(12,905 +) +$ +43,540 +The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. There has been no change in the methodology we apply to measure the fair value of our Level 3 derivative contracts during the periods covered by the financial statements. +Non-Derivative Financial Assets and Liabilities +The carrying value of the financial instruments included in current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. +We utilize fair value on a nonrecurring basis to review our crude oil and natural gas properties and goodwill for possible impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such assets. The fair value of the properties is determined based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. The fair value of the goodwill is determined using either a qualitative method or a quantitative method, both of which utilize market data, a Level 3 input, in the derivation of the value estimation. +The portion of our long-term debt related to our revolving credit facility approximates fair value due to the variable nature of related interest rates. We have not elected to account for the portion of our debt related to our senior notes under the fair value option; however, we have determined an estimate of the fair values based on measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes and convertible notes as of December 31, 2017 : +Estimated Fair Value +% of Par +(in millions) +Senior notes: +2021 Convertible Notes +$ +195.6 +97.8 +% +2024 Senior Notes +416.0 +104.0 +% +2026 Senior Notes +616.5 +102.8 +% +The carrying value of our capital lease obligations approximates fair value due to the variable nature of the imputed interest rates and the duration of the related vehicle lease. +88 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 5 - COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS +Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas, and NGLs. To manage a portion of our exposure to price volatility from producing crude oil, natural gas, and propane, which is an element of our NGLs, we enter into commodity derivative contracts to protect against price declines in future periods. While we structure these commodity derivatives to reduce our exposure to decreases in commodity prices, they also limit the benefit we might otherwise receive from price increases. +We believe our commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of December 31, 2017 , we had commodity derivatives positions covering approximately 11.9 MMBbls and 6.6 MMBbls of crude oil production for 2018 and 2019, respectively. As of the same date, we had hedged approximately 56.5 Bcf of natural gas and 1.1 MMBbls of propane for 2018. Our commodity derivative contracts have been entered into at no cost to us as we hedge our anticipated production at the then-prevailing commodity market prices, without adjustment for premium or discount. +As of December 31, 2017 , our derivative instruments were comprised of collars, fixed-price commodity swaps, and basis protection swaps. +• +Collars contain a fixed floor price (put) and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty; +• +Fixed-price commodity swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty; +• +Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For basis protection swaps, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. If the market price and contract price are the same, no payment is due to or from the counterparty. See Item 7a. - Quantitative and Qualitative Disclosures About Market Risk - Derivative Positions Table found elsewhere in this report for a detailed list of our basis protection swaps. +We have elected not to designate any of our derivative instruments as cash flow hedges, and therefore do not qualify for the use of hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the statements of operations. +89 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the balance sheet location and fair value amounts of our commodity derivative instruments on the consolidated balance sheets as of December 31, 2017 and 2016 : +Derivative instruments: +Consolidated balance sheet line item +2017 +2016 +(in thousands) +Derivative assets: +Current +Commodity derivative contracts +Fair value of derivatives +$ +7,340 +$ +8,490 +Basis protection derivative contracts +Fair value of derivatives +6,998 +301 +14,338 +8,791 +Non-current +Commodity derivative contracts +Fair value of derivatives +— +1,123 +Basis protection derivative contracts +Fair value of derivatives +— +1,263 +— +2,386 +Total derivative assets +$ +14,338 +$ +11,177 +Derivative liabilities: +Current +Commodity derivative contracts +Fair value of derivatives +$ +77,999 +53,565 +Basis protection derivative contracts +Fair value of derivatives +234 +30 +Rollfactor derivative contracts +Fair value of derivatives +1,069 +— +79,302 +53,595 +Non-current +Commodity derivative contracts +Fair value of derivatives +22,343 +27,595 +Total derivative liabilities +$ +101,645 +$ +81,190 +90 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the impact of our derivative instruments on our consolidated statements of operations: +Year Ended December 31, +Consolidated statements of operations line item +2017 +2016 +2015 +(in thousands) +Commodity price risk management gain (loss), net +Net settlements +$ +13,324 +$ +208,103 +$ +238,935 +Net change in fair value of unsettled derivatives +(17,260 +) +(333,784 +) +(35,752 +) +Total commodity price risk management gain (loss), net +$ +(3,936 +) +$ +(125,681 +) +$ +203,183 +All of our financial derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. We have elected not to offset the fair value positions recorded on our consolidated balance sheets. +The following table reflects the impact of netting agreements on gross derivative assets and liabilities: +As of December 31, 2017 +Derivative instruments, gross +Effect of master netting agreements +Derivative instruments, net +(in thousands) +Asset derivatives: +Derivative instruments, at fair value +$ +14,338 +$ +(14,173 +) +$ +165 +Liability derivatives: +Derivative instruments, at fair value +$ +101,645 +$ +(14,173 +) +$ +87,472 +As of December 31, 2016 +Derivative instruments, gross +Effect of master netting agreements +Derivative instruments, net +(in thousands) +Asset derivatives: +Derivative instruments, at fair value +$ +11,177 +$ +(10,930 +) +$ +247 +Liability derivatives: +Derivative instruments, at fair value +$ +81,190 +$ +(10,930 +) +$ +70,260 +91 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 6 - CONCENTRATION OF RISK +Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts: +As of December 31, +2017 +2016 +(in thousands) +Crude oil, natural gas, and NGLs sales +$ +154,260 +$ +97,520 +Joint interest billings (1) +34,576 +20,118 +Derivative counterparties +(18 +) +10,266 +Income tax receivable +6,015 +11,505 +Other +5,893 +6,173 +Allowance for doubtful accounts +(3,128 +) +(2,190 +) +Accounts receivable, net +$ +197,598 +$ +143,392 +_________ +(1) The December 31, 2017 amount includes $13.9 million of pre-closing contracted completion costs of wells associated +with the Bayswater Acquisition, which closed in January 2018. Upon closing, the $13.9 million was capitalized and +included in properties and equipment, net on the consolidated balance sheet. +Our accounts receivable primarily relate to sales of our crude oil, natural gas, and NGLs production, receivable balances from other third parties that own working interests in the properties we operate, and derivative counterparties. For the years ended December 31, 2017 and 2016 , amounts written off to allowance for doubtful accounts were not material. As of December 31, 2017 and 2016, none of our customers represented 10 percent or greater of our accounts receivable balance. +Major Customers. The following table presents the individual customers constituting 10 percent or more of total revenues: +Year Ended December 31, +Customer +2017 +2016 +2015 +DCP Midstream, LP +19.6 +% +20.2 +% +13.2 +% +Suncor Energy Marketing, Inc. +16.4 +% +22.3 +% +14.3 +% +Aka Energy Group, LLC +— +% +13.4 +% +— +% +Concord Energy, LLC +— +% +13.4 +% +23.2 +% +Bridger Energy, LLC +— +% +11.5 +% +— +% +Shell Trading Company +— +% +— +% +13.8 +% +Derivative Counterparties. A portion of our liquidity relates to commodity derivative instruments that enable us to manage a portion of our exposure to price volatility from producing crude oil, natural gas, and NGLs. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also major lenders under our revolving credit facility as counterparties to our commodity derivative contracts; however, an insignificant portion of our commodity derivative instruments may be with other counterparties. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our current counterparties on the fair value of our derivative instruments is not significant at December 31, 2017 , taking into account the estimated likelihood of nonperformance. +Note Receivable. In October 2014, we sold our entire 50 percent ownership interest in PDC Mountaineer, LLC to an unrelated third-party. As part of the consideration, we received a promissory note (the “Promissory Note”) for a principal sum of $ 39.0 million , bearing variable interest rates. The interest was to be paid quarterly, in arrears and at the option of the issuer could be paid-in-kind (“PIK Interest”). Any such PIK Interest would be subject to the then current interest rate. +We regularly analyzed the Promissory Note for evidence of collectibility, evaluating factors such as the creditworthiness of the issuer of the Promissory Note and the value of the issuer's assets. Based upon this analysis, during the quarter ended March 31, 2016, we recognized a provision and recorded an allowance for uncollectible notes receivable for the +92 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +$ 44.0 million accumulated outstanding balance, including interest. Commencing in the second quarter of 2016, we ceased recognizing interest income on the Promissory Note and began accounting for the interest on the Promissory Note under the cash basis method. +We performed this analysis as of March 31, 2017 and evaluated preliminary 2016 year-end financial statements of the note issuer which were available at such time, related information about the operations of the issuer, and existing market conditions for natural gas. Based upon this evaluation, it was determined that collection of the Promissory Note and the PIK Interest continued to be doubtful and the full valuation allowance on the Promissory Note remained appropriate as of that date. This evaluation assumed that repayment of the Promissory Note would be made exclusively from the existing operations of the issuer of the Promissory Note based on the latest available information. +In April 2017, we sold the Promissory Note to an unrelated third-party buyer for approximately $ 40.2 million in cash. The sales agreement transferred all of our legal rights to collect from the issuer of the Promissory Note. Accordingly, we reversed $ 40.2 million of the provision for uncollectible notes receivable during the second quarter of 2017. +Other Accrued Expenses. The following table presents the components of other accrued expenses: +As of December 31, +2017 +2016 +(in thousands) +Employee benefits +$ +22,383 +$ +22,282 +Asset retirement obligations +15,801 +9,775 +Environmental expenses +1,374 +3,238 +Other +3,429 +3,330 +Other accrued expenses +$ +42,987 +$ +38,625 +NOTE 7 - PROPERTIES AND EQUIPMENT +The following table presents the components of properties and equipment, net of accumulated DD&A: +As of December 31, +2017 +2016 +(in thousands) +Properties and equipment, net: +Crude oil and natural gas properties +Proved +$ +4,356,922 +$ +3,499,718 +Unproved +1,097,317 +1,874,671 +Total crude oil and natural gas properties +5,454,239 +5,374,389 +Infrastructure, pipeline, and other +109,359 +62,093 +Land and buildings +10,960 +6,392 +Construction in progress +196,024 +122,591 +Properties and equipment, at cost +5,770,582 +5,565,465 +Accumulated DD&A +(1,837,115 +) +(1,562,471 +) +Properties and equipment, net +$ +3,933,467 +$ +4,002,994 +Acreage Exchanges. In the fourth quarter of 2017, we completed two significant acreage exchanges that consolidated certain acreage positions in the core area of the Wattenberg Field. Pursuant to the transactions, we exchanged leasehold acreage with a limited number of wells that were in the process of being drilled and completed. Upon closing, we received an aggregate of approximately 15,900 net acres in exchange for an aggregate of approximately 16,200 net acres with minimal cash exchanged between the parties. The differences in net acres are primarily due to variances in working and net revenue interests and in midstream contracts. The assets exchanged were all in the same unit-of-production for property considerations, so it was concluded that this transaction was outside of the scope of the accounting requirements for recording the transaction at fair +93 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +value and determining gain or loss on the non-monetary exchanges. The new acreage and underlying property costs were recorded at the previous historical cost of the assets we exchanged. +In September 2016, we closed on an acreage exchange transaction with Noble Energy, Inc. and certain of its subsidiaries ("Noble") to consolidate certain acreage positions in the core area of the Wattenberg Field. Pursuant to the transaction, we exchanged leasehold acreage and, to a lesser extent, interests in certain development wells. Upon closing, we received approximately 13,500 net acres in exchange for approximately 11,700 net acres, with no cash exchanged between the parties. The assets exchanged were all in the same unit of production for property considerations, so it was concluded that this transaction was outside of the scope of the accounting requirements for recording the transaction at fair value and determining gain or loss on the non-monetary exchanges. The new acreage and underlying property costs were recorded at the previous historical cost of the assets we exchanged. +Delaware Basin Acreage Acquisition. On December 30, 2016, we closed the purchase of approximately 4,600 net bolt-on acres in Reeves and Culberson Counties, Texas, for consideration to the sellers of approximately $120.6 million in cash, subject to post-closing adjustments. The transaction was accounted for as an acquisition of assets. +Classification of Assets as Held-for-Sale. During the third quarter of 2017, as part of our plan to divest the Utica Shale properties, we engaged an investment banking firm and began actively marketing the properties for sale; therefore, these properties are classified as held-for-sale as they met the criteria for such classification beginning in the third quarter of 2017. In February 2018, we entered into a PSA for the sale of these properties for net cash proceeds of approximately $40.0 million , subject to certain customary closing adjustments. Based upon multiple offers received for the sale of our Utica Shale properties, we recorded an impairment charge of $2.1 million in 2017 to reflect their fair value. Assets held-for-sale as of December 31, 2017 included $ 36.8 million and $3.3 million , representing of our Utica Shale properties and field office facilities and a parcel of land, respectively. Assets held-for-sale as of December 31, 2016 of $5.3 million represented field office facilities and a parcel of land at that time. +The following table presents balance sheet data related to assets held-for-sale, which include the Utica Shale properties, field office facilities, and a parcel of land that are being marketed for sale. Assets held-for-sale represents the assets that are expected to be sold, net of liabilities that are expected to be assumed by the purchasers: +December 31, 2017 +December 31, 2016 +(in thousands) +Assets +Properties and equipment, net +$ +40,583 +$ +5,272 +Total assets +$ +40,583 +$ +5,272 +Liabilities +Asset retirement obligation +$ +499 +$ +— +Total liabilities +$ +499 +$ +— +Net assets +$ +40,084 +$ +5,272 +Impairment of Properties and Equipment +The following table presents impairment charges recorded for properties and equipment: +Year Ended December 31, +2017 +2016 +2015 +(in thousands) +Impairment of proved and unproved properties +$ +285,465 +$ +5,562 +$ +154,608 +Amortization of individually insignificant unproved properties +422 +1,379 +7,012 +Land and buildings +— +3,032 +— +Total impairment of properties and equipment +$ +285,887 +$ +9,973 +$ +161,620 +During the third quarter of 2017, we recorded a charge related to two exploratory dry holes we had drilled in the western area of our Culberson County acreage in the Delaware Basin. We then assessed the impact of the dry holes and various factors related thereto, including (i) the operational and geologic data obtained, (ii) the current increased cost environment for +94 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +drilling and completion services in the Delaware Basin, (iii) our decreased future commodity price outlook, and (iv) the terms of the related lease agreements. Based on the results of this assessment, we concluded that the underlying geologic risk and the challenged economics of future capital expenditures reduced the likelihood that we would perform future development in this area over the remaining lease term for this acreage. Accordingly, we recorded an impairment of $251.6 million covering approximately 13,400 acres during the third quarter of 2017. The amount of the impairment was based on the value assigned to individual lease acres in the final purchase price allocation of the Delaware Basin acquisition. This allocation had included the consideration paid to the sellers, including the effect of the non-cash impact from the deferred tax liability created at the time of the acquisition. We recorded approximately $29 million of additional lease impairments in the Delaware Basin and an impairment charge of $2.1 million related to the Utica Shale properties that are classified as held-for-sale during 2017. Due to the aforementioned events and circumstances, we also evaluated our proved property for possible impairment and concluded that no further impairments were necessary. Future deterioration of commodity prices or other operating circumstances could result in additional impairment charges to our properties and equipment. +During 2015, due to a significant decline in commodity prices and decreases in our net realized sales prices, we experienced triggering events that required us to assess our crude oil and natural gas properties for possible impairment. As a result of our assessments, we recorded impairment charges of $150.3 million in 2015 to write-down our Utica Shale proved and unproved properties. Of these impairment charges, $24.7 million were recorded in 2015 to write-down certain capitalized well costs on our Utica Shale proved producing properties. We also recorded impairment charges of $125.6 million to write-down our Utica Shale lease acquisition costs. The impairment charges, which are included in the consolidated statements of operations line item impairment of properties and equipment, represented the amount by which the carrying value of these crude oil and natural gas properties exceeded the estimated fair values. +Suspended Well Costs. We have spud three wells in the Delaware Basin for which we are unable to make a final determination regarding whether proved reserves can be associated with the wells as of December 31, 2017 as the wells had not been completed as of that date. Therefore, we have classified the capitalized costs of the wells as suspended well costs as of December 31, 2017 while we continue to conduct completion and testing operations to determine the existence of proved reserves. +The following table presents the capitalized exploratory well cost pending determination of proved reserves and included in properties and equipment, net on the consolidated balance sheet: +2017 +(in thousands, except for number of wells) +Beginning balance +$ +— +Additions to capitalized exploratory well costs pending the determination of proved reserves +51,776 +Reclassifications to proved properties +(36,328 +) +Balance at December 31, +$ +15,448 +Number of wells pending determination at December 31, +3 +We did not have any suspended well costs as of December 31, 2016 or 2015. +Exploration Expenses. The following table presents the major components of exploration, geologic, and geophysical expense: +95 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Year Ended December 31, +2017 +2016 +2015 +(in thousands) +Exploratory dry hole costs +$ +41,297 +$ +— +$ +— +Geological and geophysical costs, including seismic purchases +3,881 +3,472 +— +Operating, personnel and other +2,156 +1,197 +1,102 +Total exploration, geologic, and geophysical expense +$ +47,334 +$ +4,669 +$ +1,102 +Exploratory dry hole costs. During the third quarter of 2017 , two exploratory dry hole wells, associated lease costs, and related infrastructure assets in the Delaware Basin were expensed at a cost of $41.3 million . The conclusion to expense these items was based on our determination that the acreage on which these wells were drilled was exploratory in nature and, following drilling, that the hydrocarbon production was insufficient for the wells to be deemed economically viable. +NOTE 8 - GOODWILL +The final goodwill that resulted from the purchase price allocation of the business combination in the Delaware Basin in December 2016 was determined to be $ 75.1 million . With the creation of goodwill from this transaction, we expected to perform our evaluation of goodwill for impairment annually in the fourth quarter. However, primarily due to a combination of increases in per well development and operational costs and our drilling of two exploratory dry holes in the Delaware Basin subsequent to the acquisition, in conjunction with the then current lower future commodity price outlook, we determined that a triggering event had occurred in the third quarter of 2017. In addition to the factors mentioned above, we also considered our impairments of certain unproven leasehold costs during the third quarter of 2017 and the impact of these items on our internal expectations for acceptable rates of return. We evaluated goodwill for impairment by performing a quantitative test, which involves comparing the estimated fair value of the goodwill reporting unit, which we define as the Delaware Basin, to the carrying value. We determined the fair value of the goodwill at September 30, 2017 by using an estimated after-tax future discounted cash flow analysis, along with a combination of market-based pricing factors for similar acreage, reserve valuation techniques, and other fair value considerations. The discounted cash flow analysis used to estimate fair value was based on known or knowable information at the interim measurement date. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. The quantitative test resulted in a determination that a full impairment charge of $ 75.1 million was required; therefore, the charge was recorded in the third quarter of 2017. +96 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 9 - LONG-TERM DEBT +Long-term debt consists of the following: +As of December 31, +2017 +2016 +(in thousands) +Senior notes: +1.125% Convertible Notes due 2021: +Principal amount +$ +200,000 +$ +200,000 +Unamortized discount +(30,328 +) +(37,475 +) +Unamortized debt issuance costs +(3,615 +) +(4,584 +) +1.125% Convertible Notes due 2021, net of unamortized discount and debt issuance costs +166,057 +157,941 +6.125% Senior Notes due 2024: +Principal amount +400,000 +400,000 +Unamortized debt issuance costs +(6,570 +) +(7,544 +) +6.125% Senior Notes due 2024, net of unamortized debt issuance costs +393,430 +392,456 +5.75% Senior Notes due 2026: +Principal amount +600,000 +— +Unamortized debt issuance costs +(7,555 +) +— +5.75% Senior Notes due 2026, net of unamortized debt issuance costs +592,445 +— +7.75% Senior notes redeemed 2017: +Principal amount +— +500,000 +Unamortized debt issuance costs +— +(6,443 +) +7.75% Senior notes redeemed 2017, net of unamortized debt issuance costs +— +493,557 +Total senior notes +1,151,932 +1,043,954 +Revolving credit facility +— +— +Total long-term debt, net of unamortized discount and debt issuance costs +1,151,932 +1,043,954 +Less current portion of long-term debt +— +— +Long-term debt +$ +1,151,932 +$ +1,043,954 +Senior Notes +2026 Senior Notes. In November 2017, we issued $600.0 million aggregate principal amount 5.75% senior notes due May 15, 2026, in a private placement to qualified institutional buyers. The 2026 Senior Notes are governed by an indenture dated November 29, 2017 between us and the U.S. Bank National Association, as trustee. The maturity for the payment of principal is May 15, 2026 . Interest at the rate of 5.75% per year is payable in cash semiannually in arrears on each May 15 and November 15 , commencing on May 15, 2018. Approximately $7.6 million in costs associated with the issuance of the 2026 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. The 2026 Senior Notes are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the notes; equal in right of payment to all our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the collateral securing such indebtedness, including borrowings under our revolving credit facility; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries. +The 2026 Senior Notes are redeemable after May 15, 2021 , at fixed redemption prices beginning at 104.313 percent of the principal amount redeemed. At any time prior to May 15, 2021 , we may redeem all or part of the 2026 Senior Notes at a +97 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +make-whole price set forth in the indenture which generally approximates the present value of the redemption price at May 15, 2021 and remaining interest payments on the 2026 Senior Notes at the time of redemption. +At any time prior to May 15, 2021 we may redeem up to 35 percent of the outstanding 2026 Senior Notes with proceeds from certain equity offerings at a redemption price of 105.75 percent of the principal amount of the notes redeemed, plus accrued and unpaid interest, if at least 65 percent of the aggregate principal amount of the 2026 Senior Notes remains outstanding after each such redemption and the redemption occurs within 180 days after the closing of the equity offering. +Upon the occurrence of a "change of control," as defined in the indenture for the 2026 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we may, under certain circumstances, be required to use the net cash proceeds of such asset sale to make an offer to purchase the notes at 100 percent of the principal amount, together with any accrued and unpaid interest to the date of purchase. +The indenture governing the 2026 Senior Notes contains covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make investments; create certain liens; enter into agreements that restrict distributions or other payments by restricted subsidiaries to us; enter into transactions with affiliates; sell assets; consolidate or merge with or into other companies or transfer all or substantially of our assets; and create unrestricted subsidiaries. +2021 Convertible Notes. In September 2016 , we issued $200.0 million of 1.125% convertible senior notes due 2021 in a public offering. The 2021 Convertible Notes are governed by an indenture dated September 14, 2016 between us and the U.S. Bank National Association, as trustee. The maturity for the payment of principal is September 15, 2021 . Interest at the rate of 1.125% per year is payable in cash semiannually in arrears on each March 15 and September 15 , commencing on March 15, 2017. The 2021 Convertible Notes are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the 2021 Convertible Notes; equal in right of payment to our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries. The proceeds from the issuance of the 2021 Convertible Notes, after deducting offering expenses and underwriting discounts, were used to fund a portion of the purchase price of acquisitions in the Delaware Basin, to pay related fees and expenses, and for general corporate purposes. +The 2021 Convertible Notes are convertible prior to March 15, 2021 only upon specified events and during specified periods and, thereafter, at any time, in each case at an initial conversion rate of 11.7113 shares of our common stock per $1,000 principal amount of the 2021 Convertible Notes, which is equal to an initial conversion price of approximately $85.39 per share. The conversion rate is subject to adjustment upon certain events. Upon conversion, the 2021 Convertible Notes may be settled, at our sole election, in shares of our common stock, cash, or a combination of cash and shares of our common stock. We have initially elected a combination settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the 2021 Convertible Notes in cash and to settle the excess conversion value, if any, in shares, as well as cash in lieu of fractional shares. +We may not redeem the 2021 Convertible Notes prior to their maturity date. If we undergo a "fundamental change", as defined in the indenture for the 2021 Convertible Notes, subject to certain conditions, holders of the 2021 Convertible Notes may require us to repurchase all or part of the 2021 Convertible Notes for cash at a price equal to 100 percent of the principal amount of the 2021 Convertible Notes to be repurchased, plus any accrued and unpaid interest to, but excluding, the fundamental change repurchase date. The occurrence of a fundamental change will also result in the 2021 Convertible Notes becoming convertible. +We allocated the gross proceeds of the 2021 Convertible Notes between the liability and equity components of the debt. The initial $160.5 million liability component was determined based on the fair value of similar debt instruments excluding the conversion feature for similar terms and priced on the same day we issued the 2021 Convertible Notes. The initial $39.5 million equity component represents the debt discount and was calculated as the difference between the fair value of the debt and the gross proceeds of the 2021 Convertible Notes. Approximately $4.8 million in costs associated with the issuance of the 2021 Convertible Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. As of December 31, 2017 , the unamortized debt discount will be amortized over the remaining contractual term to maturity of the 2021 Convertible Notes using an effective interest rate of +98 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +5.8% . Based upon the December 31, 2017 stock price of $51.54 per share, the “if-converted” value of the 2021 Convertible Notes did not exceed the principal amount. +2024 Senior Notes. In September 2016 , we issued $400.0 million aggregate principal amount of 6.125% senior notes due September 2024 in a private placement to qualified institutional buyers. In May 2017, in accordance with the registration rights agreement that we entered into with the initial purchasers when we issued the 2024 Senior Notes, we filed a registration statement with the SEC relating to an offer to exchange the 2024 Senior Notes for registered notes with substantially identical terms, and we completed the exchange offer in September 2017. The proceeds from the issuance of the 2024 Senior Notes, after deducting offering expenses and underwriting discounts, were used to fund a portion of the purchase price of acquisitions in the Delaware Basin (see the footnotes titled Business Combination and Properties and Equipment) , to pay related fees and expenses, and for general corporate purposes. +The 2024 Senior Notes began accruing interest from the date of issuance and interest is payable semi-annually in arrears on March 15 and September 15 . Approximately $7.8 million in costs associated with the issuance of the 2024 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. The 2024 Senior Notes are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the notes; equal in right of payment to all our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the collateral securing such indebtedness, including borrowings under our revolving credit facility; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries. +The 2024 Senior Notes are redeemable after September 15, 2019, at fixed redemption prices beginning at 104.594 percent of the principal amount redeemed. At any time prior to September 15, 2019, we may redeem all or part of the 2024 Senior Notes at a make-whole price set forth in the indenture which generally approximates the present value of the redemption price at September 15, 2019 and remaining interest payments on the 2024 Senior Notes at the time of redemption. +At any time prior to September 15, 2019 , we may redeem up to 35 percent of the outstanding 2024 Senior Notes with proceeds from certain equity offerings at a redemption price of 106.125 percent of the principal amount of the notes redeemed, plus accrued and unpaid interest, if at least 65 percent of the aggregate principal amount of the 2024 Senior Notes remains outstanding after each such redemption and the redemption occurs within 180 days after the closing of the equity offering. +Upon the occurrence of a "change of control," as defined in the indenture for the 2024 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we may, under certain circumstances, be required to use the net cash proceeds of such asset sale to make an offer to purchase the notes at 100 percent of the principal amount, together with any accrued and unpaid interest to the date of purchase. +The indenture governing the 2024 Senior Notes contains covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make investments; create certain liens; enter into agreements that restrict distributions or other payments by restricted subsidiaries to us; enter into transactions with affiliates; sell assets; consolidate or merge with or into other companies or transfer all or substantially of our assets; and create unrestricted subsidiaries. +2022 Senior Notes. In October 2012 , we issued $500 million aggregate principal amount of 7.75% senior notes due October 15, 2022 (the "2022 Senior Notes") in a private placement to qualified institutional buyers. On November 14, 2017, we issued a notice to redeem the notes on December 13, 2017 for a total redemption price of $519.4 million , including a $19.4 million make-whole premium. The make-whole provision was based upon terms set forth in the related indenture. On December 14, 2017, upon the redemption of the 2022 Senior Notes, the $19.4 million make-whole premium and the remaining unamortized debt issuance costs of $5.4 million were recognized as a $24.7 million pre-tax loss on debt extinguishment in the consolidated statements of operations. The amount paid to bond holders for the make-whole premium has been included as a financing activity in our statement of cash flows. +Our wholly-owned subsidiary PDC Permian, Inc. has been a guarantor of our obligations under the 2026 Senior Notes since the issuance of those notes. In January 2017, pursuant to the filing of the supplemental indentures for the 2021 Convertible Notes, 2024 Senior Notes, and the 2022 Senior Notes, PDC Permian, Inc. became a guarantor of our obligations under each of those notes. +99 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +As of December 31, 2017 , we were in compliance with all covenants related to the 2021 Convertible Notes, 2024 Convertible Notes, and the 2026 Senior Notes, and expect to remain in compliance throughout the foreseeable future. +Revolving Credit Facility +Our revolving credit facility matures in May 2020 . The revolving credit facility is available for working capital requirements, capital investments, acquisitions, general corporate purposes and to support letters of credit. The revolving credit facility provides for a maximum of $1 billion in allowable borrowing capacity, but allows the borrowing base to exceed this capacity. The amount available under the revolving credit facility is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests, excluding proved reserves attributable to our affiliated partnerships. The borrowing base is subject to a semi-annual size redetermination on November 1 and May 1 based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. The revolving credit facility is secured by a pledge of the stock of certain of our subsidiaries, mortgages of certain producing crude oil and natural gas properties and substantially all of our and such subsidiaries' other assets. Our affiliated partnerships are not guarantors of our obligations under the revolving credit facility. +In May and October 2017, we entered into the Fifth and Sixth Amendments, respectively, to the Third Amended and Restated Credit Agreement to amend the revolving credit facility to reflect increases in the borrowing base. The Fifth amendment reflected an increase of the borrowing base from $700 million to $950 million and the Sixth Amendment amended the revolving credit facility to allow the borrowing base to increase above the borrowing capacity of $1.0 billion . In addition, the Fifth Amendment made changes to certain of the covenants in the existing agreement as well as other administrative changes. We elected to increase the borrowing base to $1.1 billion for our November 2017 borrowing base redetermination and have elected to maintain a $700 million commitment level as of the date of this report. +The weighted-average borrowing rate on our revolving credit facility, exclusive of fees on the unused commitment and the letter of credit noted below, was 2.7 percent per annum for the year ended December 31, 2016 . We did not borrow any amounts under our revolving credit facility during 2017. We capitalized $6.2 million and $8.8 million of debt issuance costs as of December 31, 2017 and 2016 , respectively, related to our revolving credit facility which is included in other assets on the consolidated balance sheets. +We had no outstanding balance on our revolving credit facility as of December 31, 2017 or 2016 . The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greater of JPMorgan Chase Bank, N.A.'s prime rate, the federal funds rate plus an applicable margin and the rate for dollar deposits in the London interbank market (“LIBOR”) for one month plus a premium), or at our election, a rate equal to LIBOR for certain time periods. Additionally, commitment fees, interest margin, and other bank fees, charged as a component of interest, vary with our utilization of the facility. As of December 31, 2017, the applicable margin is 1.25 percent and the unused commitment fee is 0.50 percent. No principal payments are generally required until the credit agreement expires in May 2020 , or in the event that the borrowing base falls below the outstanding balance. +The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.0:1.0 and (b) not exceed a maximum leverage ratio of 4.0:1.0. As of December 31, 2017 , we were in compliance with all the revolving credit facility covenants and expect to remain in compliance throughout the next 12-month period. As defined by the revolving credit facility, our leverage ratio was 1.9 and our current ratio was 3.2 as of December 31, 2017 . +In May 2017, we replaced our $11.7 million irrevocable standby letter of credit that we held in favor of a third-party transportation service provider to secure a firm transportation obligation with a $9.3 million deposit, which is classified as restricted cash and is included in other assets on the consolidated balance sheets. As of December 31, 2017 , the available funds under our revolving credit facility were $700 million based on our elected commitment level. +NOTE 10 - CAPITAL LEASES +We periodically enter into non-cancelable lease agreements for vehicles utilized by our operations and field personnel. These leases are being accounted for as capital leases, as the present value of minimum monthly lease payments, including the residual value guarantee, exceeds 90 percent of the fair value of the leased vehicles at inception of the lease. +100 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents leased vehicles under capital leases: +As of December 31, +2017 +2016 +(in thousands) +Vehicles +$ +6,249 +$ +2,975 +Accumulated depreciation +(1,882 +) +(776 +) +$ +4,367 +$ +2,199 +Future minimum lease payments by year and in the aggregate, under non-cancelable capital leases with terms of one year or more, consist of the following: +For the Twelve Months Ending December 31, +Amount +(in thousands) +2018 +$ +2,075 +2019 +1,623 +2020 +1,507 +5,205 +Less executory cost +(235 +) +Less amount representing interest +(537 +) +Present value of minimum lease payments +$ +4,433 +Short-term capital lease obligations +$ +1,672 +Long-term capital lease obligations +2,761 +$ +4,433 +Short-term capital lease obligations are included in other accrued expenses on the consolidated balance sheets. Long-term capital lease obligations are included in other liabilities on the consolidated balance sheets. +NOTE 11 - INCOME TAXES +The table below presents the components of our provision for income taxes from continuing operations for the years presented: +Year Ended December 31, +2017 +2016 +2015 +(in thousands) +Current: +Federal +$ +8,443 +$ +9,646 +$ +(2,944 +) +State +(200 +) +300 +(163 +) +Total current income tax (expense) benefit +8,243 +9,946 +(3,107 +) +Deferred: +Federal +193,809 +118,427 +37,352 +State +9,876 +18,822 +4,063 +Total deferred income tax benefit +203,685 +137,249 +41,415 +Income tax benefit from continuing operations +$ +211,928 +$ +147,195 +$ +38,308 +101 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents a reconciliation of the statutory rate to the effective tax rate related to our benefit for income taxes from continuing operations: +Year Ended December, 31, +2017 +2016 +2015 +Statutory tax rate +35.0 +% +35.0 +% +35.0 +% +State income tax, net +1.8 +2.6 +2.7 +Effect of state income tax rate changes +— +0.6 +(0.3 +) +Percentage depletion +— +— +0.3 +Non-deductible compensation +(0.3 +) +(0.5 +) +(1.2 +) +Federal tax reform rate reduction +33.7 +— +— +Non-deductible goodwill impairment +(7.7 +) +— +— +Other +(0.1 +) +(0.3 +) +(0.6 +) +Effective tax rate +62.4 +% +37.4 +% +35.9 +% +Tax effects of temporary differences that give rise to significant portions of deferred tax assets and deferred tax liabilities at December 31, 2017 and 2016 are presented below. The 2017 amounts include the reduction of our deferred tax assets and liabilities to a projected combined federal and state deferred tax rate of 23.9 percent as a result of the 2017 Tax Act. Also in 2017, deferred tax liability for properties and equipment was reduced by $94.1 million as a result of recording an impairment charge related to a portion of the Delaware Basin assets. The 2016 amounts include the $403.7 million effect of including the deferred tax liability for the difference in the book and tax basis of the oil and gas properties acquired in a 2016 business combination and $23.8 million of acquired deferred tax assets: +As of December 31, +2017 +2016 +(in thousands) +Deferred tax assets: +Deferred compensation +$ +6,059 +$ +9,338 +Asset retirement obligations +21,760 +34,359 +Federal NOL carryforward +19,386 +29,988 +State NOL and tax credit carryforwards, net +7,815 +5,189 +Federal tax - credit carryforwards +4,366 +5,184 +Allowance for note receivable +— +17,292 +Net change in fair value of unsettled derivatives +20,929 +26,262 +Other +2,453 +4,716 +Total gross deferred tax assets +82,768 +132,328 +Deferred tax liabilities: +Properties and equipment +267,498 +518,964 +Convertible debt +7,262 +14,231 +Total gross deferred tax liabilities +274,760 +533,195 +Net deferred tax liability +$ +191,992 +$ +400,867 +The 2017 Tax Act, enacted into law in December 2017, reduces the corporate income tax rate to 21 percent , effective January 1, 2018. Consequently, we have decreased our deferred tax assets and deferred tax liabilities by $43.8 million and $158.2 million , respectively, with a corresponding income tax benefit of $114.4 million . Our accounting for the deferred income tax effects of the 2017 Tax Act is complete. +Prior to the decrease of deferred tax assets for the federal rate change noted above, the deferred tax assets would have decreased primarily due to the utilization of the deferred tax benefit of an allowance for note receivable, partially offset by a decrease in the value of unsettled derivatives and an increase in federal and state net operating loss (“NOL”) and tax credit carryforwards. +In addition to the decrease of deferred tax liabilities for the tax rate change and our impairment in the Delaware Basin, deferred tax liabilities also decreased for the amortization of the discount and debt issuance costs for the 2021 Convertible +102 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Notes, which were issued in 2016. These decreases were partially offset by accelerated deductions on properties and equipment and deductions for lease expirations. +During the year ending December 31, 2017 , we generated a federal NOL of $28 million , of which $10.1 million will be utilized as a carryback leaving a federal NOL carryforward of $17.9 million that will begin to expire in 2037. We have a marginal gas well credit of $ 1.2 million that can be carried forward five years and we have alternative minimum tax credits of $3.2 million that may be carried forward, and pursuant to the new tax law will be refunded over the next four years. Also, we acquired a federal NOL of $60.1 million as a component of our 2016 acquisition in the Delaware Basin that will begin to expire in 2034 and is subject to an annual limitation of $15.1 million as a result of the acquisition, which constitutes a change of ownership as defined under IRS Code Section 382. +As of December 31, 2017 , we have state NOL carryforwards of $158.0 million that begin to expire in 2030 and state credit carryforwards of $2.4 million that begin to expire in 2022 . +Unrecognized tax benefits and related accrued interest and penalties were immaterial for the three-year period ended December 31, 2017 . The statutes of limitations for most of our state tax jurisdictions are open from 2013 forward. +The IRS partially accepted our recently-filed 2016 tax return. The 2016 tax return is currently going through the IRS CAP post-filing review process, with no significant tax adjustments currently proposed. We are currently participating in the CAP Program for the review of our 2017 and 2018 tax years. Participation in the CAP Program has enabled us to have minimal uncertain tax benefits associated with our federal tax return filings. +As of December 31, 2017 , we were current with our income tax filings in all applicable state jurisdictions. +NOTE 12 - ASSET RETIREMENT OBLIGATIONS +The following table presents the changes in carrying amounts of the asset retirement obligations associated with our crude oil and natural gas properties and midstream assets: +2017 +2016 +(in thousands) +Beginning balance +$ +92,387 +$ +89,492 +Obligations incurred with development activities +3,638 +4,894 +Accretion expense +6,306 +7,080 +Revisions in estimated cash flows +(2,860 +) +— +Obligations discharged with asset retirements +(12,165 +) +(9,079 +) +Balance at December 31 +87,306 +92,387 +Less liabilities held-for-sale +(499 +) +— +Less current portion +(15,801 +) +(9,775 +) +Long-term portion +$ +71,006 +$ +82,612 +Our estimated asset retirement obligations liability is based on historical experience in plugging and abandoning wells, estimated economic lives, estimated plugging and abandonment cost and federal and state regulatory requirements. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. In 2017, the credit-adjusted risk-free rates used to discount our plugging and abandonment liabilities ranged from 6.5 percent to 7.5 percent. In periods subsequent to initial measurement of the liability, we must recognize period-to-period changes in the liability resulting from the passage of time, revisions to either the amount of the original estimate of undiscounted cash flows or changes in inflation factors, and changes to our credit-adjusted risk-free rate as market conditions warrant. +The revisions in estimated cash flows during 2017 were primarily due to changes in estimates of costs for materials and services related to the plugging and abandonment of vertical and horizontal wells and the shortening of the estimated expected lives of vertical wells in the Wattenberg Field. +NOTE 13 - EMPLOYEE BENEFIT PLANS +We sponsor a qualified retirement plan covering substantially all of our employees. The plan consists of both a traditional and a Roth 401(k) component, as well as a profit sharing component. The 401(k) components enable eligible employees to contribute a portion of their compensation through payroll deductions in accordance with specific guidelines. We provide a discretionary matching contribution based on a percentage of the employees' contributions up to certain limits. Additionally, our contribution to the profit sharing component is discretionary. Our total combined expense for the plan was $6.2 million , $4.8 million , and $4.9 million for 2017 , 2016 , and 2015 , respectively. +NOTE 14 - COMMITMENTS AND CONTINGENCIES +Firm Transportation and Processing Agreements. We enter into contracts that provide firm transportation and processing on pipeline systems through which we transport or sell crude oil and natural gas. Satisfaction of the volume requirements includes volumes produced by us, purchased from third parties, and produced by our affiliated partnerships and other third-party working, royalty, and overriding royalty interest owners, whose volumes we market on their behalf. Our consolidated statements of operations reflect our share of these firm transportation and processing costs. These contracts require us to pay these transportation and processing charges whether or not the required volumes are delivered. +103 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents gross volume information related to our long-term firm transportation, sales, and processing agreements for pipeline capacity: +Year Ending December 31, +Area +2018 +2019 +2020 +2021 +2022 and +Through +Expiration +Total +Expiration +Date +Natural gas (MMcf) +Wattenberg Field +3,541 +23,934 +31,110 +31,025 +121,922 +211,532 +April 30, 2026 +Delaware Basin +14,600 +14,600 +14,640 +— +— +43,840 +December 31, 2020 +Gas Marketing +7,117 +7,117 +7,136 +7,056 +4,495 +32,921 +August 31, 2022 +Utica Shale (1) +2,738 +2,738 +2,745 +2,738 +4,326 +15,285 +July 31, 2023 +Total +27,996 +48,389 +55,631 +40,819 +130,743 +303,578 +Crude oil (MBbls) +Wattenberg Field +3,638 +4,239 +1,808 +— +— +9,685 +June 30, 2020 +Dollar commitment (in thousands) +$ +23,176 +$ +43,855 +$ +42,496 +$ +33,226 +$ +118,927 +$ +261,680 +(1) In February 2018, we entered into a PSA to sell the Utica Shale properties. This commitment would be assumed by the purchaser of the +Utica Shale properties. +In anticipation of our future drilling activities in the Wattenberg Field, we entered into two facilities expansion agreements in 2016 and 2017 with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities. The midstream provider is expected to construct two new 200 MMcfd cryogenic plants. We will be bound to the volume requirements in these agreements on the first day of the calendar month following after the actual in-service date of the plants, which in the above table is scheduled to be in the third quarter of 2018 for the first plant and the second quarter of 2019 for the second plant. Both agreements require baseline volume commitments, consisting of our gross wellhead volume delivered in November 2016, to this midstream provider, and incremental wellhead volume commitments of 51.5 MMcfd and 33.5 MMcfd for the first and second agreements, respectively, for seven years. We may be required to pay shortfall fees for any volumes under the 51.5 MMcfd and 33.5 MMcfd incremental commitments. Any shortfall of these volume commitments may be offset by additional third party producers’ volumes sold to the midstream provider that are greater than a certain total baseline volume. We are also required for the first three years of the contracts to guarantee a certain target profit margin to the midstream provider on these incremental volumes. We currently expect that our future development plans will meet both baseline and incremental volumes, and we believe that the contractual target profit margin will be achieved without additional payment from us. +In April 2017, we entered into a transportation service agreement for delivery of 40,000 dekatherms per day of our Delaware Basin natural gas production to the Waha market hub in West Texas. +For the years 2017, 2016, and 2015, commitments for long-term transportation volumes for Wattenberg Field crude oil, Delaware Basin natural gas, and Utica Shale natural gas were $10.0 million , $10.0 million , and $4.7 million , respectively, and were recorded in transportation, gathering and processing expense in our consolidated statements of operations. +Litigation and Legal Items. We are involved in various legal proceedings. We review the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in our best interests. We have provided the necessary estimated accruals in the accompanying balance sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations, or liquidity. +Action Regarding Partnerships. In December 2017, we received an action entitled Dufresne, et al. v. PDC Energy, et al ., filed in the United States District Court for the District of Colorado. The complaint states that it is a derivative action brought by a number of limited partner investors seeking to assert claims on behalf of our two affiliated partnerships, Rockies Region 2006 LP and Rockies Region 2007 LP, against PDC and alleging claims for breach of fiduciary duty and breach of contract. The plaintiffs also included claims against two of our senior officers for alleged breach of fiduciary duty. The lawsuit accuses PDC, as the managing general partner of the two partnerships, of, among other things, failing to maximize the +104 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +productivity of the partnerships’ crude oil and natural gas wells. We filed a motion to dismiss the lawsuit on February 1, 2018, on the grounds that the complaint is deficient, including because the plaintiffs failed to allege that PDC refused a demand to take action on their claims. That motion is still pending. We are unable to estimate any potential damages as a result of this recent lawsuit. +Action Regarding Firm Transportation Contracts. In June 2016, a group of 42 independent West Virginia natural gas producers filed a lawsuit in Marshall County, West Virginia, naming Dominion Transmission, Inc. (“Dominion”), certain entities affiliated with Dominion, and our subsidiary Riley Natural Gas ("RNG") as defendants, alleging various contractual, fiduciary and related claims against the defendants, all of which are associated with firm transportation contracts entered into by plaintiffs and relating to pipelines owned and operated by Dominion and its affiliates. The case has been transferred to the Business Court Division of the Circuit Court of Marshall County, West Virginia. RNG is unable to estimate any potential damages associated with the claims, but believes the complaint is without merit and intends to vigorously pursue its defenses. +Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures designed to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as discussed herein, we are not aware of any material environmental claims existing as of December 31, 2017 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws or other environmental liabilities will not be discovered on our properties. Accrued environmental liabilities are recorded in other accrued expenses on the condensed consolidated balance sheets. The liability ultimately incurred with respect to a matter may exceed the related accrual. +Clean Air Act Agreement and Related Consent Decree. In August 2015, we received a Clean Air Act Section 114 Information Request (the “Information Request”) from the U.S. Environmental Protection Agency (“EPA”). The Information Request sought, among other things, information related to the design, operation, and maintenance of our Wattenberg Field production facilities in the Denver-Julesburg Basin of Colorado (“DJ Basin”). The Information Request focused on historical operation and design information for 46 of our production facilities and requested sampling and analyses at the identified 46 facilities. We responded to the Information Request with the requested data in January 2016. +In addition, in December 2015, we received a Compliance Advisory pursuant to C.R.S. 25-7-115(2) from the Colorado Department of Public Health and Environment’s Air Quality Control Commission’s Air Pollution Control Division alleging that we failed to design, operate, and maintain certain condensate collection, storage, processing, and handling operations to minimize leakage of volatile organic compounds at 65 facilities consistent with applicable standards under Colorado law. +In June 2017, the U.S. Department of Justice, on behalf of the EPA and the state of Colorado, filed a complaint against us in the U.S. District Court for the District of Colorado, claiming that we failed to operate and maintain certain condensate collection facilities at 65 facilities so as to minimize leakage of volatile organic compounds in compliance with applicable law. In October 2017, we entered into a consent decree to resolve the lawsuit. Pursuant to the consent decree, we agreed to implement a variety of operational enhancements and mitigation and similar projects, including vapor control system modifications and verification, increased inspection and monitoring, and installation of tank pressure monitors. The three primary elements of the consent decree are: (i) fine/supplemental environmental projects ($1.5 million cash fine, plus $1 million in supplemental environmental projects) which have been accrued in other accrued expenses on our consolidated balance sheet as of December 31, 2017 ; (ii) injunctive relief with an estimated cost of approximately $18 million, primarily representing capital enhancements to our operations; and (iii) mitigation with an estimated cost of $1.7 million. We continue to incur costs associated with these activities. If we fail to comply fully with the requirements of the consent decree with respect to those matters, we could be subject to additional liability. In addition, we could be the subject of other enforcement actions by regulatory authorities in the future relating to our past, present or future operations. We do not believe that the expenditures resulting from the settlement will have a material adverse effect on our consolidated financial statements. +Lease Agreements. We entered into operating leases, principally for the leasing of natural gas compressors, office space, and general office equipment. +105 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the minimum future lease payments under the non-cancelable operating leases as of December 31, 2017 : +Year Ending December 31, +2018 +2019 +2020 +2021 +2022 +Thereafter +Total +(in thousands) +Minimum Lease Payments +$ +3,865 +$ +3,865 +$ +3,932 +$ +3,998 +$ +4,078 +$ +3,515 +$ +23,253 +Operating lease expense for 2017 , 2016 , and 2015 was $17.2 million , $10.2 million , and $9.8 million , respectively. +106 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 15 - COMMON STOCK +Issuance of Equity Securities +In December 2016, we issued 9.4 million shares of our common stock as partial consideration for 100 percent of the common stock of Arris Petroleum and for the acquisition of certain Delaware Basin properties. Pursuant to the terms of previously disclosed lock-up agreements, the resale of these shares was restricted. The lock-up period ended in June 2017. We have registered the 9.4 million shares of our common stock for resale under the Securities Act of 1933. +Sales of Equity Securities +The following table provides a summary of our public offerings of common stock in 2016 and 2015: +Date +Shares Issued +Price per Share +Net Proceeds +(in millions) +September 2016 +9,085,000 +$ +61.51 +$ +558.5 +March 2016 +5,922,500 +50.11 +296.6 +March 2015 +4,002,000 +50.73 +202.9 +Stock-Based Compensation Plans +2010 Long-Term Equity Compensation Plan. In June 2010 , our stockholders approved a long-term equity compensation plan for our employees and non-employee directors (the "2010 Plan"). The plan was amended in June 2013. In accordance with the 2010 Plan, up to 3,000,000 new shares of our common stock are authorized for issuance. Shares issued may be either authorized but unissued shares, treasury shares, or any combination. Additionally, the 2010 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited, paid out in the form of cash, or withheld for the payment of taxes. Awards may be issued to our employees in the form of stock appreciation rights ("SARs"), restricted stock, restricted stock units ("RSUs"), performance shares, and performance units ("PSUs"), and to our non-employee directors in the form of non-qualified stock options, SARs, restricted stock, and RSUs. Awards may vest over periods set at the discretion of the Compensation Committee of our Board of Directors (the "Compensation Committee") with certain minimum vesting periods. With regard to SARs, awards have a maximum exercisable period of ten years. In no event may an award be granted under the 2010 Plan on or after June 5, 2023. As of December 31, 2017 , 689,206 shares remain available for issuance pursuant to the 2010 Plan. +The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented: +Year Ended December 31, +2017 +2016 +2015 +(in thousands) +Stock-based compensation expense +$ +19,353 +$ +19,502 +$ +20,068 +Income tax benefit +(7,372 +) +(7,296 +) +(7,636 +) +Net stock-based compensation expense +$ +11,981 +$ +12,206 +$ +12,432 +SARs +The SARs vest ratably over a three-year period and may be exercised at any point after vesting through ten years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the holders of the SARs will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance. +107 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The Compensation Committee has awarded SARs to our executive officers in 2017, 2016, and 2015. The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions: +Year Ended December 31, +2017 +2016 +2015 +Expected term of award (in years) +6.0 years +6.0 years +5.2 years +Risk-free interest rate +2.0 +% +1.8 +% +1.4 +% +Expected volatility +53.3 +% +54.5 +% +58.0 +% +Weighted-average grant date fair value per share +$ +38.58 +$ +26.96 +$ +22.23 +The expected term of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. We do not expect to pay or declare dividends in the foreseeable future. +The following table presents the changes in our SARs for all periods presented (in thousands, except per share data): +Year Ended December 31, +2017 +2016 +2015 +Number of +SARs +Weighted-Average +Exercise +Price +Average Remaining Contractual +Term (in years) +Aggregate Intrinsic +Value +Number of +SARs +Weighted-Average +Exercise +Price +Aggregate Intrinsic +Value +Number of +SARs +Weighted-Average +Exercise +Price +Aggregate Intrinsic +Value +Outstanding at January 1, +244,078 +$ +41.36 +6.9 +$ +7,620 +326,453 +$ +38.99 +$ +4,697 +279,011 +$ +38.77 +$ +1,472 +Awarded +54,142 +74.57 +— +— +58,709 +51.63 +— +68,274 +39.63 +— +Exercised +— +— +— +— +(141,084 +) +40.16 +2,770 +(20,832 +) +38.05 +473 +Outstanding at December 31 +298,220 +47.39 +6.5 +2,490 +244,078 +41.36 +7,620 +326,453 +38.99 +4,697 +Exercisable at December 31 +223,865 +43.28 +5.9 +2,267 +174,919 +38.72 +5,924 +222,489 +37.70 +3,489 +We expect all SARs outstanding as of December 31, 2017 to vest. Total compensation cost related to SARs granted and not yet recognized in our consolidated statements of operations as of December 31, 2017 was $1.9 million . The cost is expected to be recognized over a weighted-average period of 1.8 years. +Restricted Stock Unit Awards +Time-Based Awards. The fair value of the time-based RSUs is amortized ratably over the requisite service period, primarily three years. The time-based RSUs generally vest ratably on each anniversary following the grant date that a participant is continuously employed. +The following table presents the changes in non-vested time-based RSUs during 2017 : +Shares +Weighted-Average +Grant Date +Fair Value per Share +Non-vested at December 31, 2016 +479,642 +$ +56.09 +Granted +273,941 +65.14 +Vested +(266,809 +) +57.67 +Forfeited +(14,642 +) +62.92 +Non-vested at December 31, 2017 +472,132 +60.23 +108 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: +As of/Year Ended December 31, +2017 +2016 +2015 +(in thousands, except per share data) +Total intrinsic value of time-based awards vested +$ +16,303 +$ +18,973 +$ +17,077 +Total intrinsic value of time-based awards non-vested +24,334 +34,812 +28,029 +Market price per common share as of December 31, +51.54 +72.58 +53.38 +Weighted-average grant date fair value per share +65.14 +58.52 +48.88 +Total compensation cost related to non-vested time-based awards and not yet recognized in our consolidated statements of operations as of December 31, 2017 was $18.5 million . This cost is expected to be recognized over a weighted-average period of 1.8 years. +Market-Based Awards. The fair value of the market-based PSUs is amortized ratably over the requisite service period, primarily three years. The market-based PSUs vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of three years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. +In January 2017, the Compensation Committee awarded a total of 28,069 market-based PSUs to our executive officers. In addition to continuous employment, the vesting of these PSUs is contingent on our total stockholder return ("TSR"), which is essentially our stock price change including any dividends, as compared to the TSR of a group of peer companies. The shares are measured over a three-year period ending on December 31, 2019 and can result in a payout between 0 percent and 200 percent of the target PSUs awarded. As of December 31, 2017, we had approximately 52,000 non-vested market based PSUs that could result in a payout between 0 and approximately 105,000 shares of our common stock. The weighted-average grant date fair value per PSU granted was computed using the Monte Carlo pricing model using the following assumptions: +Year Ended December 31, +2017 +2016 +2015 +Expected term of award (in years) +3 years +3 years +3 years +Risk-free interest rate +1.4 +% +1.2 +% +0.9 +% +Expected volatility +51.4 +% +52.3 +% +53.0 +% +Weighted-average grant date fair value per share +$ +94.02 +$ +72.54 +$ +66.16 +The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our historical volatility. +The following table presents the change in non-vested market-based awards during 2017 : +Shares +Weighted-Average +Grant Date +Fair Value per Share +Non-vested at December 31, 2016 +48,420 +$ +64.97 +Granted +28,069 +94.02 +Vested +(24,140 +) +57.35 +Non-vested at December 31, 2017 +52,349 +84.06 +109 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: +As of/Year Ended December 31, +2017 +2016 +2015 +(in thousands, except per share data) +Total intrinsic value of market-based awards vested +$ +2,687 +$ +6,562 +$ +4,293 +Total intrinsic value of market-based awards non-vested +2,698 +3,514 +3,819 +Market price per common share as of December 31, +51.54 +72.58 +53.38 +Weighted-average grant date fair value per share +94.02 +72.54 +66.16 +Total compensation cost related to non-vested market-based awards and not yet recognized in our consolidated statements of operations as of December 31, 2017 was $2.4 million . This cost is expected to be recognized over a weighted-average period of 1.8 years. +Treasury Share Purchases +In accordance with our stock-based compensation plans, employees may surrender shares of our common stock to pay tax withholding obligations upon the vesting and exercise of share-based awards. Shares acquired that had been issued pursuant to the 2010 Plan are withheld for reissuance for new grants. For shares reissued for new grants under the 2010 Plan, shares are recorded at cost and upon reissuance we reduce the carrying value of shares acquired and held pursuant to the 2010 Plan by the weighted-average cost per share with an offsetting charge to APIC. During the year ended December 31, 2017 , we acquired 107,357 shares pursuant to our stock-based compensation plans for payment of tax liabilities, of which 83,228 shares were reissued and 34,526 are available for reissuance pursuant to our 2010 Plan. During the year ended December 31, 2016 , we acquired 116,085 shares pursuant to our stock-based compensation plans for payment of tax liabilities, of which 114,697 were reissued and 10,397 are available for reissuance pursuant to our 2010 Plan. As of December 31, 2017 and 2016 , we had 21,401 and 18,366 , respectively, shares of treasury stock related to a rabbi trust. +Preferred stock +We are authorized to issue 50,000,000 shares of preferred stock, par value $0.01, in one or more series, with such rights, preferences, privileges, and restrictions as shall be fixed by our Board of Directors at the time of issuance. As of December 31, 2017 , no preferred shares had been issued. +NOTE 16 - EARNINGS PER SHARE +Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, stock options, convertible notes, and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. +The following table presents a reconciliation of the weighted-average diluted shares outstanding: +Year Ended December 31, +2017 +2016 +2015 +(in thousands) +Weighted-average common shares outstanding - basic +65,837 +49,052 +39,153 +Weighted-average common shares and equivalents outstanding - diluted +65,837 +49,052 +39,153 +For 2017, 2016, and 2015, we reported a net loss. As a result, our basic and diluted weighted-average common shares outstanding were the same because the effect of the common share equivalents was anti-dilutive. +110 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect: +Year Ended December 31, +2017 +2016 +2015 +(in thousands) +Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: +Restricted stock +590 +689 +831 +Convertible notes +— +292 +562 +Other equity-based awards +75 +109 +101 +Total anti-dilutive common share equivalents +665 +1,090 +1,494 +In September 2016 , we issued the 2021 Convertible Notes, which gave the holders the right to convert the aggregate principal amount into 2.3 million shares of our common stock at a conversion price of $85.39 per share. The 2021 Convertible Notes would be included in the diluted earnings per share calculation using the treasury stock method if the average market share price had exceeded the $85.39 conversion price during the periods presented. +In November 2010, we issued the 2016 Convertible Notes, which give the holders the right to convert the aggregate principal amount into 2.7 million shares of our common stock at a conversion price of $42.40 per share. The 2016 Convertible Notes matured and were redeemed in May 2016 . Prior to maturity, the 2016 Convertible Notes were included in the diluted earnings per share calculation using the treasury stock method when the average market share price exceeded the $42.40 conversion price during the period presented. Shares issuable upon conversion of the Convertible Notes were excluded from the diluted earnings per share calculation for the years ended December 31, 2016 and 2015 as the effect would have been anti-dilutive to our earnings per share. +NOTE 17 - SUBSIDIARY GUARANTOR +PDC Permian, Inc., our wholly-owned subsidiary, guarantees our obligations under our publicly-registered senior notes. The following presents the condensed consolidating financial information separately for: +(i) +PDC Energy, Inc. ("Parent"), the issuer of the guaranteed obligations, including non-material subsidiaries; +(ii) +PDC Permian, Inc., the guarantor subsidiary ("Guarantor"), as specified in the indentures related to our senior notes; +(iii) +Eliminations representing adjustments to (a) eliminate intercompany transactions between or among Parent, Guarantor, and our other subsidiaries and (b) eliminate the investments in our subsidiaries; and +(iv) +Parent and subsidiaries on a consolidated basis ("Consolidated"). +The Guarantor was 100 percent owned by the Parent beginning in December 2016. The senior notes are fully and unconditionally guaranteed on a joint and several basis by the Guarantor. The guarantee is subject to release in limited circumstances only upon the occurrence of certain customary conditions. Each entity in the consolidating financial information follows the same accounting policies as described in the notes to the consolidated financial statements. +The following consolidating financial statements have been prepared on the same basis of accounting as our consolidated financial statements. Investments in subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Parent and Guarantor are reflected in the eliminations column. +111 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Consolidating Balance Sheets +December 31, 2017 +Parent +Guarantor +Eliminations +Consolidated +(in thousands) +Assets +Current assets: +Cash and cash equivalents +$ +180,675 +$ +— +$ +— +$ +180,675 +Accounts receivable, net +160,490 +37,108 +— +197,598 +Fair value of derivatives +14,338 +— +— +14,338 +Prepaid expenses and other current assets +8,284 +329 +— +8,613 +Total current assets +363,787 +37,437 +— +401,224 +Properties and equipment, net +1,891,314 +2,042,153 +— +3,933,467 +Assets held-for-sale, net +40,084 +— +— +40,084 +Intercompany receivable +250,279 +— +(250,279 +) +— +Investment in subsidiaries +1,617,537 +— +(1,617,537 +) +— +Other assets +42,547 +2,569 +— +45,116 +Total Assets +$ +4,205,548 +$ +2,082,159 +$ +(1,867,816 +) +$ +4,419,891 +Liabilities and Stockholders' Equity +Liabilities +Current liabilities: +Accounts payable +$ +85,000 +$ +65,067 +$ +— +$ +150,067 +Production tax liability +35,902 +1,752 +— +37,654 +Fair value of derivatives +79,302 +— +— +79,302 +Funds held for distribution +83,898 +11,913 +— +95,811 +Accrued interest payable +11,812 +3 +— +11,815 +Other accrued expenses +42,543 +444 +— +42,987 +Total current liabilities +338,457 +79,179 +— +417,636 +Intercompany payable +— +250,279 +(250,279 +) +— +Long-term debt +1,151,932 +— +— +1,151,932 +Deferred income taxes +62,857 +129,135 +— +191,992 +Asset retirement obligations +65,301 +5,705 +— +71,006 +Fair value of derivatives +22,343 +— +— +22,343 +Other liabilities +57,009 +324 +— +57,333 +Total liabilities +1,697,899 +464,622 +(250,279 +) +1,912,242 +Stockholders' equity +Common shares +659 +— +— +659 +Additional paid-in capital +2,503,294 +1,766,775 +(1,766,775 +) +2,503,294 +Retained earnings +6,704 +(149,238 +) +149,238 +6,704 +Treasury shares +(3,008 +) +— +— +(3,008 +) +Total stockholders' equity +2,507,649 +1,617,537 +(1,617,537 +) +2,507,649 +Total Liabilities and Stockholders' Equity +$ +4,205,548 +$ +2,082,159 +$ +(1,867,816 +) +$ +4,419,891 +112 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Consolidating Balance Sheets +December 31, 2016 +Parent +Guarantor +Eliminations +Consolidated +(in thousands) +Assets +Current assets: +Cash and cash equivalents +$ +240,487 +$ +3,613 +$ +— +$ +244,100 +Accounts receivable, net +134,589 +8,803 +— +143,392 +Fair value of derivatives +8,791 +— +— +8,791 +Prepaid expenses and other current assets +3,442 +100 +— +3,542 +Total current assets +387,309 +12,516 +— +399,825 +Properties and equipment, net +1,884,147 +2,118,847 +— +4,002,994 +Assets held-for-sale, net +5,272 +— +— +5,272 +Intercompany receivable +9,415 +— +(9,415 +) +— +Investment in subsidiaries +1,765,092 +— +(1,765,092 +) +— +Fair value of derivatives +2,386 +— +— +2,386 +Goodwill +— +62,041 +— +62,041 +Other assets +13,153 +171 +— +13,324 +Total Assets +$ +4,066,774 +$ +2,193,575 +$ +(1,774,507 +) +$ +4,485,842 +Liabilities and Stockholders' Equity +Liabilities +Current liabilities: +Accounts payable +$ +38,748 +$ +27,574 +$ +— +$ +66,322 +Production tax liability +24,401 +366 +— +24,767 +Fair value of derivatives +53,595 +— +— +53,595 +Funds held for distribution +65,022 +6,317 +— +71,339 +Accrued interest payable +15,930 +— +— +15,930 +Other accrued expenses +37,425 +1,200 +— +38,625 +Total current liabilities +235,121 +35,457 +— +270,578 +Intercompany payable +— +9,415 +(9,415 +) +— +Long-term debt +1,043,954 +— +— +1,043,954 +Deferred income taxes +20,971 +379,896 +— +400,867 +Asset retirement obligations +78,897 +3,715 +— +82,612 +Fair value of derivatives +27,595 +— +— +27,595 +Other liabilities +37,482 +— +— +37,482 +Total liabilities +1,444,020 +428,483 +(9,415 +) +1,863,088 +Stockholders' equity +Common shares +657 +— +— +657 +Additional paid-in capital +2,489,557 +1,766,775 +(1,766,775 +) +2,489,557 +Retained earnings +134,208 +(1,683 +) +1,683 +134,208 +Treasury shares +(1,668 +) +— +— +(1,668 +) +Total stockholders' equity +2,622,754 +1,765,092 +(1,765,092 +) +2,622,754 +Total Liabilities and Stockholders' Equity +$ +4,066,774 +$ +2,193,575 +$ +(1,774,507 +) +$ +4,485,842 +113 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Consolidating Statements of Operations +Year Ended December 31, 2017 +Parent +Guarantor +Eliminations +Consolidated +(in thousands) +Revenues +Crude oil, natural gas, and NGLs sales +$ +788,400 +$ +124,684 +$ +— +$ +913,084 +Commodity price risk management gain (loss), net +(3,936 +) +— +— +(3,936 +) +Other income +11,901 +567 +— +12,468 +Total revenues +796,365 +125,251 +— +921,616 +Costs, expenses and other +Lease operating expenses +68,031 +21,610 +— +89,641 +Production taxes +53,236 +7,481 +— +60,717 +Transportation, gathering, and processing expenses +23,301 +9,919 +— +33,220 +Exploration, geologic, and geophysical expense +1,092 +46,242 +— +47,334 +Impairment of properties and equipment +4,951 +280,936 +— +285,887 +Impairment of goodwill +— +75,121 +— +75,121 +General and administrative expense +107,518 +12,852 +— +120,370 +Depreciation, depletion and amortization +403,984 +65,100 +— +469,084 +Provision for uncollectible notes receivable +(40,203 +) +— +— +(40,203 +) +Accretion of asset retirement obligations +5,965 +341 +— +6,306 +Gain on sale of properties and equipment +(766 +) +— +— +(766 +) +Other expenses +13,157 +— +— +13,157 +Total costs, expenses and other +640,266 +519,602 +— +1,159,868 +Income (loss) from operations +156,099 +(394,351 +) +— +(238,252 +) +Loss on extinguishment of debt +(24,747 +) +— +— +(24,747 +) +Interest expense +(79,919 +) +1,225 +— +(78,694 +) +Interest income +2,261 +— +— +2,261 +Income (loss) before income taxes +53,694 +(393,126 +) +— +(339,432 +) +Income tax (expense) benefit +(33,643 +) +245,571 +— +211,928 +Equity in loss of subsidiary +(147,555 +) +— +147,555 +— +Net loss +$ +(127,504 +) +$ +(147,555 +) +$ +147,555 +$ +(127,504 +) +Net losses of the Guarantor for the year ended 2017 are primarily the result of the exploratory dry hole expense, impairment of certain unproved Delaware Basin leasehold positions, and the impairment of goodwill. +114 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Consolidating Statements of Operations +Year Ended December 31, 2016 +Parent +Guarantor +Eliminations +Consolidated +(in thousands) +Revenues +Crude oil, natural gas, and NGLs sales +$ +491,750 +$ +5,603 +$ +— +$ +497,353 +Commodity price risk management gain (loss), net +(125,681 +) +— +— +(125,681 +) +Other income +11,241 +2 +— +11,243 +Total revenues +377,310 +5,605 +— +382,915 +Costs, expenses and other +Lease operating expenses +58,401 +1,549 +— +59,950 +Production taxes +31,132 +278 +— +31,410 +Transportation, gathering, and processing expenses +18,263 +152 +— +18,415 +Exploration, geologic, and geophysical expense +1,197 +3,472 +— +4,669 +Impairment of properties and equipment +9,973 +— +— +9,973 +General and administrative expense +112,166 +304 +— +112,470 +Depreciation, depletion and amortization +415,321 +1,553 +— +416,874 +Provision for uncollectible notes receivable +44,038 +— +— +44,038 +Accretion of asset retirement obligations +7,070 +10 +— +7,080 +Gain on sale of properties and equipment +(43 +) +— +— +(43 +) +Other expenses +10,193 +— +— +10,193 +Total costs, expenses and other +707,711 +7,318 +— +715,029 +Loss from operations +(330,401 +) +(1,713 +) +— +(332,114 +) +Interest expense +(62,002 +) +30 +— +(61,972 +) +Interest income +963 +— +— +963 +Loss before income taxes +(391,440 +) +(1,683 +) +— +(393,123 +) +Income tax benefit +147,195 +— +— +147,195 +Equity in loss of subsidiary +(1,683 +) +— +1,683 +— +Net loss +$ +(245,928 +) +$ +(1,683 +) +$ +1,683 +$ +(245,928 +) +115 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Condensed Consolidating Statements of Cash Flows +Year Ended December 31, 2017 +Parent +Guarantor +Eliminations +Consolidated +(in thousands) +Cash flows from operating activities +$ +537,704 +$ +50,859 +$ +— +$ +588,563 +Cash flows from investing activities: +Capital expenditures for development of crude oil and natural properties +(439,897 +) +(297,311 +) +— +(737,208 +) +Capital expenditures for other properties and equipment +(3,539 +) +(1,555 +) +— +(5,094 +) +Acquisition of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition +(21,000 +) +5,372 +— +(15,628 +) +Proceeds from sale of properties and equipment +10,084 +(93 +) +— +9,991 +Sale of promissory note +40,203 +— +— +40,203 +Restricted cash +(9,250 +) +— +— +(9,250 +) +Sale of short-term investments +49,890 +— +— +49,890 +Purchase of short-term investments +(49,890 +) +— +— +(49,890 +) +Intercompany transfers +(239,191 +) +— +239,191 +— +Net cash from investing activities +(662,590 +) +(293,587 +) +239,191 +(716,986 +) +Cash flows from financing activities: +Proceeds from issuance of senior notes +592,366 +— +— +592,366 +Redemption of senior notes +(519,375 +) +— +— +(519,375 +) +Purchase of treasury stock +(6,672 +) +— +— +(6,672 +) +Payment of debt issuance costs +(50 +) +— +— +(50 +) +Other +(1,195 +) +(76 +) +— +(1,271 +) +Intercompany transfers +— +239,191 +(239,191 +) +— +Net cash from financing activities +65,074 +239,115 +(239,191 +) +64,998 +Net change in cash and cash equivalents +(59,812 +) +(3,613 +) +— +(63,425 +) +Cash and cash equivalents, beginning of period +240,487 +3,613 +— +244,100 +Cash and cash equivalents, end of period +$ +180,675 +$ +— +$ +— +$ +180,675 +116 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Condensed Consolidating Statements of Cash Flows +Year Ended December 31, 2016 +Parent +Guarantor +Eliminations +Consolidated +(in thousands) +Cash flows from operating activities +$ +492,893 +$ +(6,630 +) +$ +— +$ +486,263 +Cash flows from investing activities: +Capital expenditures for development of crude oil and natural properties +(436,361 +) +(523 +) +— +(436,884 +) +Capital expenditures for other properties and equipment +(2,282 +) +(1,182 +) +— +(3,464 +) +Acquisition of crude oil and natural gas properties, including settlement adjustments and deposit for pending acquisition +(1,076,256 +) +2,533 +— +(1,073,723 +) +Proceeds from sale of properties and equipment +4,945 +— +— +4,945 +Intercompany transfers +(9,415 +) +— +9,415 +— +Net cash from investing activities +(1,519,369 +) +828 +9,415 +(1,509,126 +) +Cash flows from financing activities: +Proceeds from issuance of equity, net of issuance costs +855,074 +— +— +855,074 +Proceeds from issuance of senior notes +392,172 +— +— +392,172 +Proceeds from issuance of convertible senior notes +193,935 +— +— +193,935 +Proceeds from revolving credit facility +85,000 +— +— +85,000 +Repayment of revolving credit facility +(122,000 +) +— +— +(122,000 +) +Redemption of convertible notes +(115,000 +) +— +— +(115,000 +) +Payment of debt issuance costs +(15,556 +) +— +— +(15,556 +) +Purchase of treasury shares +(6,935 +) +— +— +(6,935 +) +Other +(577 +) +— +— +(577 +) +Intercompany transfers +— +9,415 +(9,415 +) +— +Net cash from financing activities +1,266,113 +9,415 +(9,415 +) +1,266,113 +Net change in cash and cash equivalents +239,637 +3,613 +— +243,250 +Cash and cash equivalents, beginning of period +850 +— +— +850 +Cash and cash equivalents, end of period +$ +240,487 +$ +3,613 +$ +— +$ +244,100 +The condensed consolidating financial statements for the year ended December 31, 2016 represent one month of activity for the Guarantor as the Delaware Basin acquisition occurred in December 2016. +117 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 18 - SUBSEQUENT EVENTS +Bayswater Acquisition. On January 5, 2018, we closed the Bayswater Acquisition for approximately $186 million , subject to certain customary post-closing adjustments. After adjustments, we acquired approximately 7,400 net acres, approximately 220 gross drilling locations, and 24 operated horizontal wells that were either drilled uncompleted wells or in-process wells at the time of closing, for approximately $186 million , subject to certain customary post-closing adjustments. In addition to the approximately $186 million of cash paid at closing, we invested approximately $15 million during December 2017 to complete 12 of the 24 wells. Upon executing the PSA, we paid a $21.0 million deposit toward the purchase price into an escrow account, which is included in other assets on our December 31, 2017 consolidated balance sheet. +Utica Shale Divestiture. In February 2018, we entered into a PSA for the sale of the Utica Shale properties for net cash proceeds of approximately $40.0 million , subject to certain customary closing adjustments. These properties were classified as held-for-sale as they met the criteria for such classification beginning in the third quarter of 2017. See the footnote titled Properties and Equipment for further details regarding the assets held-for-sale. +Saddle Butte Rockies Midstream Amendment Payment. On January 31, 2018, we received a payment of approximately $24 million from Saddle Butte for the execution of an Amendment to an existing crude oil purchase and sale agreement, signed in December 2017. The Amendment was effective contingent upon certain events which occurred in late January 2018. The Amendment, among other things, dedicates the majority of our Wattenberg Field acreage for crude oil production to be gathered by Saddle Butte's gathering lines and extends the term through December 2029. +118 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +SUPPLEMENTAL INFORMATION - UNAUDITED +CRUDE OIL AND NATURAL GAS INFORMATION - UNAUDITED +Net Proved Reserves +All of our crude oil, natural gas, and NGLs reserves are located in the U.S. We utilize the services of independent petroleum engineers to estimate our crude oil, natural gas, and NGL reserves. As of December 31, 2017 , 2016 , and 2015 , all of our estimates of proved reserves for the Wattenberg Field and the Utica Shale were based on reserve reports prepared by Ryder Scott Company, L.P. and beginning in 2016, Netherland, Sewell & Associates, Inc. prepared the reserve reports for the Delaware Basin. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC. +Proved reserves are those quantities of crude oil, natural gas, and NGLs which can be estimated with reasonable certainty to be economically producible under existing economic conditions and operating methods. Proved developed reserves are the proved reserves that can be produced through existing wells with existing equipment and infrastructure and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for development. All of our proved undeveloped reserves conform to the SEC five-year rule requirement to be drilled within five years of each location’s initial booking date. +The indicated index prices for our reserves, by commodity, are presented below. +Average Benchmark Prices (1) +As of December 31, +Crude Oil +(per Bbl) +Natural Gas +(per Mcf) +NGLs +(per Bbl) (2) +2017 +$ +51.34 +$ +2.98 +$ +51.34 +2016 +42.75 +2.48 +42.75 +2015 +50.28 +2.59 +50.28 +The netted back price used to estimate our reserves, by commodity, are presented below. +Price Used to Estimate Reserves (3) +As of December 31, +Crude Oil +(per Bbl) +Natural Gas +(per Mcf) +NGLs +(per Bbl) (2) +2017 +$ +48.68 +$ +2.31 +$ +20.21 +2016 +38.67 +1.85 +11.97 +2015 +42.10 +2.05 +12.23 +___________ +(1) +Per SEC rules, the pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of the month prices for the preceding 12 months. +(2) +For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. +(3) +These prices are based on the index prices and are net of basin differentials, any transportation fees, contractual adjustments, and any Btu adjustments we experienced for the respective commodity. +119 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +The following tables present the changes in our estimated quantities of proved reserves: +Crude Oil, Condensate (MBbls) +Natural Gas +(MMcf) +NGLs +(MBbls) +Total +(MBoe) +Proved Reserves: +Proved reserves, January 1, 2015 +100,515 +536,972 +60,119 +250,129 +Revisions of previous estimates +(43,268 +) +(154,775 +) +(24,407 +) +(93,471 +) +Extensions, discoveries, and other additions +48,707 +311,709 +30,835 +131,494 +Acquisition of reserves +17 +215 +23 +76 +Dispositions +(12 +) +(82 +) +(8 +) +(34 +) +Production +(6,984 +) +(33,302 +) +(2,835 +) +(15,369 +) +Proved reserves, December 31, 2015 +98,975 +660,737 +63,727 +272,825 +Revisions of previous estimates +(22,097 +) +(80,426 +) +(7,130 +) +(42,631 +) +Extensions, discoveries, and other additions +494 +4,094 +355 +1,531 +Acquisition of reserves +50,126 +305,224 +32,586 +133,583 +Dispositions +(601 +) +(4,202 +) +(424 +) +(1,725 +) +Production +(8,728 +) +(51,730 +) +(4,826 +) +(22,176 +) +Proved reserves, December 31, 2016 +118,169 +833,697 +84,288 +341,407 +Revisions of previous estimates +28,334 +96,119 +8,104 +52,457 +Extensions, discoveries, and other additions +2,923 +11,541 +1,158 +6,005 +Acquisition of reserves +18,971 +289,223 +19,604 +86,778 +Dispositions +(653 +) +(4,597 +) +(481 +) +(1,900 +) +Production +(12,902 +) +(71,689 +) +(6,981 +) +(31,830 +) +Proved reserves, December 31, 2017 +154,842 +1,154,294 +105,692 +452,917 +Proved Developed Reserves, as of: +December 31, 2015 +26,257 +175,367 +15,011 +70,496 +December 31, 2016 +30,013 +264,452 +24,196 +98,284 +December 31, 2017 +46,862 +365,332 +35,220 +142,971 +Proved Undeveloped Reserves, as of: +December 31, 2015 +72,718 +485,370 +48,716 +202,329 +December 31, 2016 +88,156 +569,245 +60,092 +243,122 +December 31, 2017 +107,980 +788,962 +70,472 +309,946 +120 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Developed +Undeveloped +Total +(MBoe) +Proved reserves, January 1, 2015 +74,905 +175,224 +250,129 +Undeveloped reserves converted to developed +29,090 +(29,090 +) +— +Revisions of previous estimates +(26,875 +) +(66,596 +) +(93,471 +) +Extensions, discoveries, and other additions +8,703 +122,791 +131,494 +Acquisition of reserves +76 +— +76 +Dispositions +(34 +) +— +(34 +) +Production +(15,369 +) +— +(15,369 +) +Proved reserves, December 31, 2015 +70,496 +202,329 +272,825 +Undeveloped reserves converted to developed +32,192 +(32,192 +) +— +Revisions of previous estimates +6,112 +(48,743 +) +(42,631 +) +Extensions, discoveries, and other additions +1,531 +— +1,531 +Acquisition of reserves +10,229 +123,354 +133,583 +Dispositions +(99 +) +(1,626 +) +(1,725 +) +Production +(22,176 +) +— +(22,176 +) +Proved reserves, December 31, 2016 +98,285 +243,122 +341,407 +Undeveloped reserves converted to developed +54,648 +(54,648 +) +— +Revisions of previous estimates +18,291 +34,166 +52,457 +Extensions, discoveries, and other additions +2,292 +3,713 +6,005 +Acquisition of reserves +1,305 +85,473 +86,778 +Dispositions +(20 +) +(1,880 +) +(1,900 +) +Production +(31,830 +) +— +(31,830 +) +Proved reserves, December 31, 2017 +142,971 +309,946 +452,917 +2017 Activity. During 2017, we increased proved reserves by 33 percent or 111.5 MMBoe, relative to December 31, 2016. This proved reserve increase was primarily a result of an increase in acquisitions and reserve additions on proved acreage in our Delaware Basin properties from our 2017 development plan. In 2017, we produced 31.8 MMboe. +Extensions, discoveries, and other additions for 2017 of 6.0 MMBoe includes the addition of five newly drilled wells and seven proved undeveloped ("PUD") locations in the Delaware Basin. +Acquisitions of reserves of 86.8 MMBoe includes proved developed producing properties and PUD locations obtained in our Wattenberg Field from acreage exchange transactions. We had minimal dispositions of 1.9 MMBoe related to the acreage disposed of in an acreage exchange. In relation to our acreage exchange transactions, we primarily divested proved acreage with future locations that were not in our proved five-year development plan as of December 31, 2016, as we do not add non-operated PUD locations to our proved five-year development plan until drilling has started as our certainty threshold is not achieved until such time. +We estimated 52.5 MMBoe in upward revisions from the following changes: +• +Negative revisions of 57.7 MMBoe were due to Wattenberg Field PUD locations being dropped from our proved five- year development plan and being replaced by PUD locations on newly-acquired properties. +• +Positive revisions of 93.9 MMBoe for infill drilling within a proven area, with 37.3 MMBoe in our Wattenberg Field and 56.6 MMBoe in our Delaware Basin. +• +Net negative revisions of 2.2 MMBoe were due to an increase in operating costs, partially offset by an increase in prices for crude oil, natural gas, and NGLs. +• +Negative revisions of 0.7 MMBoe were due to locations being removed due to the SEC five-year development rule. +• +Net positive revisions of 19.2 MMBoe includes performance revisions and other items. +At December 31, 2016, we projected a PUD reserve conversion rate of 26 percent for 2017. As a result of drilling plans being extended in our Delaware Basin in the first half of 2017, our actual reserve conversion rate was 23 percent, resulting in 54.6 MMBoe of reserves recorded as PUDs at December 31, 2016, being converted to proved developed reserves as of December 31, 2017. +121 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Based on economic conditions on December 31, 2017, our approved development plan provides for the development of our remaining PUD locations within five years of the date such reserves were initially recorded. As of December 31, 2017, our 2018 PUD reserve conversion rate is expected to be approximately 16 percent . Our lower 2018 PUD conversion rate is a result of our Bayswater Acquisition that closed on January 5, 2018. We anticipate drilling acquired Bayswater locations in 2018 that are not included within our December 31, 2017 reserves. The Bayswater Acquisition is more fully described in the footnote titled Subsequent Events to the consolidated financial statements included elsewhere in this report. The balance of the PUD reserves are scheduled to be developed over the remaining four years in accordance with our current development plan. The level of capital spending necessary to achieve this drilling schedule is consistent with our recent performance and our outlook for future development activities. +2016 Activity. During 2016, we increased proved reserves by 25 percent or 68.6 MMBoe, relative to December 31, 2015. This proved reserve increase was primarily a result of the development of longer lateral length well bores in the Wattenberg Field, which was driven by technology advancements, together with the ability to consolidate our leasehold position to drill longer length laterals with increased working interests. We also acquired proved developed reserves and undeveloped reserves in the Delaware Basin. Extensions, discoveries, and other additions for 2016 of 1.5 MMBoe includes the addition of five wells in the Utica Shale. +Acquisitions of reserves of 133.6 MMBoe includes proved developed producing properties and PUD locations acquired in our Delaware Basin acquisitions, and new proved locations obtained from an acreage exchange transaction. Because of the preferential economics of the more concentrated acreage in the Wattenberg Field, we rescheduled the timing of anticipated development in the field. This resulted in a downward revision to our proved reserves in the revisions of previous estimates category. The net downward revisions were 42.6 MMBoe. The revision was most notably attributed to a 61.0 MMBoe decrease in reserves due to 2015 PUD locations being removed from our five year development plan and being replaced by PUD locations reflected in purchases of reserves. Infill reserve additions of 16.8 MMBoe in the Wattenberg Field were included as a positive revision of previous estimates. Infill reserve additions for years prior to 2016 for the Wattenberg Field were reported in extensions, discoveries, and other additions, including infill reserves in an existing proved field. Revisions also include a 0.5 MMBoe decrease on production due to pricing. The remaining 2.1 MMBoe in positive revisions of previous estimates includes performance revisions and other items. +We had minimal dispositions of 1.7 MMBoe related to the acreage we traded in the acreage exchange. +At December 31, 2015, we projected a PUD reserve conversion rate of 19 percent for 2016. As a result of revisions to our drilling plan during the last two months of 2016, our actual reserve conversion rate was 16 percent , resulting in 32.2 MMBoe of reserves recorded as PUDs at December 31, 2015, being converted to proved developed reserves as of December 31, 2016. +Based on economic conditions on December 31, 2016, our then-current development plan provided for the development of our remaining PUD locations within five years of the date such reserves were initially recorded. As of December 31, 2016, our 2017 PUD reserve conversion rate was expected to be approximately 26 percent. +2015 Activity. Overall, our proved reserves increased by 23 MMBoe as of December 31, 2015 as compared to December 31, 2014. In 2015, we produced 15.4 MMBoe. At December 31, 2014, we projected a PUD conversion rate of 16 percent for 2015. Our actual conversion rate was 17 percent, resulting in 29 MMBoe of reserves booked as PUDs at December 31, 2014 being converted to proved developed reserves during 2015. As shown, we acquired and divested minimal volumes of proved reserves in 2015. +Extensions, discoveries, and other additions, including infill reserves, of approximately 131 MMBoe in 2015 were all added in the Wattenberg Field and primarily related to horizontal Niobrara projects being added to our development plan. The reserve additions associated with these projects were largely the result of data generated from our downspacing testing. This led to increased well density of our PUD locations year-over-year and extended the field by enabling us to book more reserves per section in the Niobrara. In general, at December 31, 2014, Niobrara PUD locations were booked at an equivalent of eight wells per section and at December 31, 2015, such locations were booked at an equivalent of 16 wells per section. Additionally, due to more efficient drilling leading to shorter spud-to-spud times, we have increased the number of wells drilled per drilling rig utilized during the course of the year. We had 791 gross PUD horizontal drilling locations at December 31, 2015, which was an increase from 774 locations at December 31, 2014. Approximately 9 MMBoe of the extensions, discoveries, and other additions to our developed reserves related to wells drilled that were not related to reserves booked as of the prior year-end. +122 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +We recorded net downward revisions of previous estimates of proved reserves of approximately 93 MMBoe. The revision was a result of multiple factors, most notably a decrease of approximately 56 MMBoe for adjustments to our development plans in the Wattenberg Field resulting from the booking of further-downspaced PUD locations. This downspacing delayed the expected development date for many existing PUD locations beyond the limits of the SEC five-year rule. Also contributing to the downward revision was a decrease of approximately 33 MMBoe due to the significant decrease in SEC commodity prices utilized in the December 31, 2015 reserve report, including approximately 11 MMBoe specifically related to the removal of vertical re-fracs and re-completions from the proved developed reserves which no longer fall within our economic parameters. There was an additional negative revision of approximately 22 MMBoe primarily related to geology findings and leasehold factors. Partially offsetting these decreases was an upward revision approximately 18 MMBoe related to well performance and forecast adjustments. +Results of Operations for Crude Oil and Natural Gas Producing Activities +The results of operations for crude oil and natural gas producing activities are presented below. The results include activities related to both continuing and discontinued operations and exclude activities related to gas marketing and other income. Comprehensive income (loss) includes net income (loss), as well as other changes in stockholders' equity that result from transactions and economic events other than those with shareholders. There was no difference between our net income (loss) and comprehensive income (loss) for any of the periods presented in the results of operations for crude oil and natural gas producing activities shown. +Year Ended December 31, +2017 +2016 +2015 +(in thousands) +Revenue: +Crude oil, natural gas and NGLs sales +$ +913,084 +$ +497,353 +$ +378,713 +Commodity price risk management gain (loss), net +(3,936 +) +(125,681 +) +203,183 +909,148 +371,672 +581,896 +Expenses: +Lease operating expenses +89,641 +59,950 +56,992 +Production taxes +60,717 +31,410 +18,443 +Transportation, gathering and processing expenses +33,220 +18,415 +10,151 +Exploration expense +47,334 +4,669 +1,102 +Impairment of properties and equipment +285,887 +9,973 +161,620 +Depreciation, depletion, and amortization +462,482 +413,105 +298,760 +Accretion of asset retirement obligations +6,306 +7,080 +6,293 +Gain on sale of properties and equipment +(766 +) +(43 +) +(385 +) +984,821 +544,559 +552,976 +Results of operations for crude oil and natural gas producing +activities before provision for income taxes +(75,673 +) +(172,887 +) +28,920 +Provision for income taxes +47,247 +64,733 +(10,394 +) +Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs +$ +(28,426 +) +$ +(108,154 +) +$ +18,526 +Production costs include those costs incurred to operate and maintain productive wells and related equipment, including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, production and severance taxes, and associated administrative expenses. DD&A expense includes those costs associated with capitalized acquisition, exploration, and development costs, but does not include the depreciation applicable to support equipment. The provision for income taxes is computed using effective tax rates. +123 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Costs Incurred in Crude Oil and Natural Gas Property Acquisition, Exploration, and Development Activities +Costs incurred in crude oil and natural gas property acquisition, exploration, and development are presented below. +Year Ended December 31, +2017 +2016 +2015 +(in thousands) +Acquisition of properties: (1) +Proved properties +$ +172 +$ +268,567 +$ +3,561 +Unproved properties +18,914 +1,843,985 +15 +Development costs (2) +688,165 +383,336 +552,104 +Exploration costs: (3) +Exploratory drilling +80,103 +— +— +Geological and geophysical +3,881 +4,669 +— +Total costs incurred (4) +$ +791,235 +$ +2,500,557 +$ +555,680 +__________ +(1) +Property acquisition costs represent costs incurred to purchase, lease, or otherwise acquire a property. Proved properties +include approximately $40.9 million of infrastructure and pipeline costs in 2016. +(2) +Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells, and provide facilities to extract, treat, gather, and store crude oil, natural gas, and NGLs. Of these costs incurred for the years ended December 31, 2017 , 2016 , and 2015 , $463.4 million , $204.6 million , and $207.8 million , respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. These costs also include approximately $32.8 million of infrastructure and pipeline costs in 2017. +(3) +Exploration costs represent costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas, and NGLs. These costs include, but are not limited to, dry hole contributions and costs of drilling and equipping exploratory wells. +(4) +During the year ended 2017, we finalized our purchase price allocation for the 2016 Delaware Basin acquisition within the one year measurement period. The finalization included a reduction to our proved, undeveloped and development costs of $24.6 million. We excluded this reduction from our 2017 costs incurred as it did not relate to any cash acquisitions in 2017. +Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities +Aggregate capitalized costs related to crude oil and natural gas exploration and production activities with applicable accumulated DD&A are presented below: +As of December 31, +2017 +2016 +(in thousands) +Proved crude oil and natural gas properties +$ +4,356,922 +$ +3,499,718 +Unproved crude oil and natural gas properties +1,097,317 +1,874,671 +Uncompleted wells, equipment and facilities +265,526 +150,424 +Capitalized costs +5,719,765 +5,524,813 +Less accumulated DD&A +(1,803,847 +) +(1,534,678 +) +Capitalized costs, net +$ +3,915,918 +$ +3,990,135 +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves +The standardized measure below has been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to our year-end estimated proved reserves. Prices for each of the three years were adjusted by field for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of our commodity derivatives. Production and development costs were based on prices as of December 31 for each of the respective years presented. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service or to depreciation, depletion, and amortization expense. Production and development costs include those cash flows associated with the expected ultimate settlement of our asset retirement obligations. Future +124 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +estimated income tax expense is computed by applying the statutory rate in effect at the end of each year to the projected future pre-tax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits, and allowances related to the properties. +The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for crude oil, natural gas, and NGLs, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves. +As of December 31, +2017 +2016 +2015 +(in thousands) +Future estimated cash flows +$ +12,340,407 +$ +7,122,525 +$ +6,297,298 +Future estimated production costs* +(3,245,627 +) +(1,624,167 +) +(1,493,040 +) +Future estimated development costs +(2,893,335 +) +(2,219,914 +) +(2,036,685 +) +Future estimated income tax expense +(748,494 +) +(597,476 +) +(508,332 +) +Future net cash flows +5,452,951 +2,680,968 +2,259,241 +10% annual discount for estimated timing of cash flows +(2,572,846 +) +(1,260,339 +) +(1,162,377 +) +Standardized measure of discounted future estimated net cash flows +$ +2,880,105 +$ +1,420,629 +$ +1,096,864 +___________ +* +Represents future estimated lease operating expenses, production taxes, transportation, gathering, and processing expenses. +The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows: +Year Ended December 31, +2017 +2016 +2015 +(in thousands) +Beginning of period +$ +1,420,629 +$ +1,096,864 +$ +2,306,465 +Sales of crude oil, natural gas and NGLs production, net of production costs +(729,506 +) +(387,576 +) +(293,127 +) +Net changes in prices and production costs (1) +841,713 +(205,760 +) +(1,752,921 +) +Extensions, discoveries, and improved recovery, less related costs +47,240 +15,128 +489,178 +Sales of reserves +(2,613 +) +(3,745 +) +(463 +) +Purchases of reserves +224,483 +487,636 +374 +Development costs incurred during the period +419,047 +268,672 +368,840 +Revisions of previous quantity estimates +484,431 +(320,286 +) +(1,286,462 +) +Changes in estimated income taxes +(138,560 +) +(13,630 +) +902,994 +Net changes in future development costs +25,183 +391,145 +112,958 +Accretion of discount +167,487 +133,747 +345,007 +Timing and other +120,571 +(41,566 +) +(95,979 +) +End of period +$ +2,880,105 +$ +1,420,629 +$ +1,096,864 +__________ +(1) +Our weighted-average price, net of production costs per Boe, in our 2017 reserve report increased to $20.08 as compared to $15.73 for 2016 and $17.30 for 2015. +The data presented should not be viewed as representing the expected cash flows from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the recent average prices and current costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein. +125 +PDC ENERGY, INC. +QUARTERLY FINANCIAL INFORMATION - UNAUDITED +Quarterly financial data for the years ended December 31, 2017 and 2016 is presented below. The quarterly consolidated statements of operations below reflect our revised presentation. The sum of the quarters may not equal the total of the year's net income or loss per share due to changes in the weighted-average shares outstanding throughout the year. +2017 +Quarter Ended +March 31 +June 30 +September 30 +December 31 +(in thousands, except per share data) +Total revenues +$ +273,707 +$ +275,158 +$ +183,235 +$ +189,516 +Total costs, expenses and other +182,004 +190,522 +579,326 +208,016 +Income (loss) from operations +91,703 +84,636 +(396,091 +) +(18,500 +) +Income (loss) before income taxes +72,476 +65,787 +(414,887 +) +(62,808 +) +Net income (loss) (1) +$ +46,146 +$ +41,250 +$ +(292,537 +) +$ +77,637 +Earnings per share: +Basic +$ +0.70 +$ +0.63 +$ +(4.44 +) +$ +1.18 +Diluted +0.70 +0.62 +(4.44 +) +1.17 +________ +(1) Net income of $77.6 million for the quarter ended December 31, 2017 is primarily due to an income tax benefit of +$114.4 million resulting from a decrease in deferred tax assets and liabilities related to the 2017 Tax Act. +2016 +Quarter Ended +March 31 +June 30 +September 30 +December 31 +(in thousands, except per share data) +Total revenues +$ +90,831 +$ +20,097 +$ +163,890 +$ +108,097 +Total costs, expenses and other +193,864 +163,379 +179,178 +178,608 +Loss from operations +(103,033 +) +(143,282 +) +(15,288 +) +(70,511 +) +Loss before income taxes +(113,369 +) +(153,777 +) +(35,341 +) +(90,636 +) +Net loss +$ +(71,530 +) +$ +(95,450 +) +$ +(23,309 +) +$ +(55,639 +) +Earnings per share: +Basic +$ +(1.72 +) +$ +(2.04 +) +$ +(0.48 +) +$ +(0.94 +) +Diluted +(1.72 +) +(2.04 +) +(0.48 +) +(0.94 +) +126 +PDC ENERGY, INC. +FINANCIAL STATEMENT SCHEDULE +Schedule II -VALUATION AND QUALIFYING ACCOUNTS +Description +Beginning +Balance +January 1, +Charged to +Costs and +Expenses +Deductions (1) +Ending +Balance +December 31, +(in thousands) +2017: +Allowance for uncollectible notes +$ +44,038 +$ +— +$ +44,038 +$ +— +Allowance for doubtful accounts +2,190 +1,108 +170 +3,128 +Allowance for expirations of unproved crude oil and natural gas properties +359 +263,817 +13,017 +251,159 +2016: +Allowance for uncollectible notes +— +44,038 +— +44,038 +Allowance for doubtful accounts +2,009 +1,309 +1,128 +2,190 +Allowance for expirations of unproved crude oil and natural gas properties +144 +215 +— +359 +2015: +Allowance for doubtful accounts +486 +1,700 +177 +2,009 +Allowance for expirations of unproved crude oil and natural gas properties +9,293 +7,012 +16,161 +144 +____________ +(1) +For allowance for uncollectible notes, deductions represent reversals of allowances due to the collection of amounts owed. For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For allowance for expirations of unproved crude oil and natural gas properties, deductions represent either actual expired or abandoned unproved crude oil and natural gas properties or an accumulated amortization of expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset. +127 +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +As of December 31, 2017 , we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). Based on the results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were not effective as of December 31, 2017 because of the material weaknesses in our internal control over financial reporting described below. +Management's Report on Internal Control over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Internal control over financial reporting is a process designed by, or under the supervision of, our CEO and CFO, or persons performing similar functions, and effected by our board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate. +Management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2017 , based upon the criteria established in "Internal Control – Integrated Framework (2013)" issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). +A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. +We did not maintain a sufficient complement of personnel within the Land Department as a result of increased volume of leases, which contributed to the ineffective design and maintenance of controls to verify the completeness and accuracy of land administrative records associated with unproved leases, which are used in verifying the completeness, accuracy, valuation, rights and obligations over the accounting of properties and equipment, sales and accounts receivable, and costs and expenses. These control deficiencies resulted in immaterial adjustments of our unproved properties, impairment of unproved properties, sales, accounts receivable, and depletion expense accounts and related disclosures during 2017. +Additionally, these control deficiencies could result in misstatements of substantially all accounts and disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. Accordingly, our management has determined that these control deficiencies constitute material weaknesses. +The effectiveness of our internal control over financial reporting as of December 31, 2017 , has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears under Item 8. +Remediation Plan for Material Weaknesses +In response to the identified material weaknesses, our management, with the oversight of the Audit Committee of our board of directors, has begun the process of assessing a number of different remediation initiatives to improve our internal control over financial reporting for the year ended December 31, 2018. We are currently in the process of evaluating the material weaknesses and are developing a plan of remediation to strengthen our overall controls over the sufficient complement of personnel within the Land Department and the completeness and accuracy of land administration records. We are committed to continuing to improve our internal control processes and will continue to review, optimize, and enhance our internal control +128 +environment. These material weaknesses will not be considered remediated until the applicable remedial controls operate for a sufficient period of time and management has concluded, through testing, that these controls are operating effectively. +Changes in Internal Control over Financial Reporting +There were no changes in our internal control over financial reporting during the quarter ended December 31, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. +ITEM 9B. OTHER INFORMATION +None. +129 +PART III +ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2018 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 11. EXECUTIVE COMPENSATION +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2018 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2018 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2018 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2018 Annual Stockholders' meeting and is incorporated by reference in this report. +PART IV +ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES +(a) +(1) +Exhibits: +See Exhibits Index on the following page. +130 +ITEM 16. FORM 10-K SUMMARY +None. +Exhibits Index +Incorporated by Reference +Exhibit Number +Exhibit Description +Form +SEC File Number +Exhibit +Filing Date +Filed Herewith +2.1 +Plan of Conversion, dated June 5, 2015, by PDC Energy, Inc. (the "Company"). +8-K12B +001-37419 +2.1 +6/8/2015 +2.2 +Stock Purchase and Sale Agreement, dated August 23, 2016, by and among the seller parties thereto, Kimmeridge Energy Management Company GP, LLC, Arris Petroleum Corporation, and PDC Energy, Inc. +8-K +001-37419 +2.1 +8/24/2016 +2.3 +Asset Purchase and Sale Agreement, dated August 23, 2016, by and among 299 Resources, LLC, 299 Production, LLC, 299 Pipeline, LLC, Kimmeridge Energy Management Company GP, LLC and PDC Energy, Inc. +8-K +001-37419 +2.2 +8/24/2016 +3.1 +Certificate of Incorporation of the Company. +8-K12B +001-37419 +3.1 +6/8/2015 +3.2 +By-laws of the Company. +8-K12B +001-37419 +3.2 +6/8/2015 +4.1 +Form of Common Stock Certificate of the Company. +10-K +001-37419 +4.1 +2/28/2017 +4.2 +Indenture, dated as of November 29, 2017, by and between PDC Energy, Inc., PDC Permian, Inc., a subsidiary guarantor of the Company, and U.S. Bank Trust National Association, as Trustee, relating to the 5.750% Senior Notes due 2026. +8-K +001-37419 +4.1 +11/29/2017 +4.3 +Base Indenture, dated as of September 14, 2016, by and between the Company and U.S. Bank Trust National Association, as Trustee. +8-K +001-37419 +4.1 +9/14/2016 +4.4 +First Supplemental Indenture, dated as of September 14, 2016, by and between the Company and U.S. Bank Trust National Association, as Trustee, relating to the 1.125% Convertible Senior Notes due 2021. +8-K +001-37419 +4.2 +9/14/2016 +4.5 +Indenture, dated as of September 15, 2016, by and between PDC Energy, Inc. and U.S. Bank Trust National Association, as Trustee, relating to the 6.125% Senior Notes due 2024. +8-K +001-37419 +4.1 +9/15/2016 +10.1 +Form of Indemnification Agreement. +8-K +000-07246 +10.1 +6/8/2015 +10.2 +401(k) and Profit Sharing Plan, as amended on January 4, 2016. +10-K +001-37419 +10.2 +2/28/2017 +10.3 +Amended and Restated Non-Employee Director Deferred Compensation Plan. +10-K +10.3 +X +10.4 +2004 Long-Term Equity Compensation Plan amended and restated as of March 8, 2008 ("2004 Plan"). +10-K +000-07246 +10.26 +2/27/2009 +10.4.1 +Summary of 2010 Stock Appreciation Rights and Restricted Stock Awards under the 2004 Plan. +8-K +000-07246 +4/23/2010 +10.5 +Amended and Restated 2010 Long-Term Equity Compensation Plan, as amended. +10-K +001-37419 +10.5 +2/22/2016 +10.6 +Executive Severance Compensation Plan, as amended. +10-K +001-37419 +10.6 +2/22/2016 +10.7 +Form of 2011 Restricted Stock/Stock Appreciation Rights Agreement. +10-K +000-07246 +10.5.2 +2/21/2014 +10.7.1 +Form of 2013 Performance Share Agreement. +10-K +000-07246 +10.9 +2/27/2013 +10.7.2 +Form of 2013 Restricted Stock/Stock Appreciation Rights Agreement. +10-K +000-07246 +10.10 +2/27/2013 +10.7.3 +Form of 2014 Performance Share Agreement. +10-K +000-07246 +10.5.4 +2/19/2015 +10.7.4 +Form of 2014 Restricted Stock/Stock Appreciation Rights Agreement. +10-K +000-07246 +10.5.5 +2/19/2015 +131 +Incorporated by Reference +Exhibit Number +Exhibit Description +Form +SEC File Number +Exhibit +Filing Date +Filed Herewith +10.7.5 +Form of 2015 Performance Share Agreement. +10-K +000-07246 +10.5.6 +2/19/2015 +10.7.6 +Form of 2015 Restricted Stock Unit Agreement. +10-K +000-07246 +10.5.7 +2/19/2015 +10.7.7 +Form of 2015 Stock Appreciation Rights Agreement. +10-K +000-07246 +10.5.8 +2/19/2015 +10.7.8 +Form of 2016 Performance Share Agreement. +10-K +001-37419 +10.7.8 +2/22/2016 +10.9 +Employment Agreement with Daniel W. Amidon, General Counsel and Corporate Secretary, dated as of April 19, 2010. +8-K +000-07246 +10.3 +4/23/2010 +10.10 +Employment Agreement with Lance A. Lauck, Senior Vice President of Business Development, dated as of April 19, 2010. +8-K +000-07246 +10.4 +4/23/2010 +10.11 +Third Amended and Restated Credit Agreement dated as of May 21, 2013, among PDC Energy, Inc. as Borrower, Riley Natural Gas Company, a Subsidiary of PDC Energy, Inc., as Guarantor, JP Morgan Chase Bank, N.A. as Administrative Agent, J.P. Morgan Securities LLC as Sole Bookrunner and Co-Lead Arranger, Wells Fargo Bank, N.A. as Syndication Agent, and Wells Fargo Securities, LLC as Co-Lead Arranger, and Certain Lenders. +8-K +000-07246 +10.1 +5/28/2013 +10.11.1 +First and Second Amendments to Third Amended and Restated Credit Agreement dated as of May 14, 2014 and September 30, 2015, respectively, among PDC Energy, Inc. as the Borrower, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders. +10-K +001-37419 +10.11.1 +2/22/2016 +10.11.2 +Third Amendment to the Third Amended and Restated Credit Agreement, dated as of September 6, 2016, among the Company, as Borrower, certain Subsidiaries of the Company, as Guarantors, the lenders from time to time party thereto (the “Lenders”) and JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders. +8-K +001-37419 +10.1 +9/8/2016 +10.11.3 +Fourth Amendment to the Third Amended and Restated Credit Agreement, dated as of October 14, 2016, among the Company, as Borrower, certain Subsidiaries of the Company, as Guarantors, the lenders from time to time party thereto (the “Lenders”) and JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders. +10-Q +001-37419 +99.1 +11/3/2016 +10.11.4 +Fifth Amendment to Third Amended and Restated Credit Agreement, dated as of May 10, 2017, among the Company, as Borrower, certain Subsidiaries of the Company, as Guarantors, JPMorgan Chase Bank, N.A., as administrative agent, and the other lenders party thereto. +8-K +001-37419 +10.1 +5/16/2017 +10.11.5 +Sixth Amendment to the Third Amended and Restated Credit Agreement, dated as of October 6, 2017, among the Company, as Borrower, certain Subsidiaries of the Company, as Guarantors, the lenders from time to time party thereto (the “Lenders”) and JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders. +10-Q +001-37419 +10.1 +11/7/2017 +10.12* +Change of Control and Severance Plan. +10-K +001-37419 +10.14 +2/28/2017 +10.12.1* +Amendment to the PDC Energy Change of Control and Severance Plan. +10-K +001-37419 +10.14.1 +2/28/2017 +10.13 +Registration Rights Agreement, dated as of September 15, 2016, by and between PDC Energy, Inc. and J.P. Morgan Securities LLC, as representative of the initial purchasers, relating to the 6.125% Senior Notes due 2024. +8-K +001-37419 +10.2 +9/15/2016 +10.14 +Investment Agreement, dated December 6, 2016, by and among the Investor parties identified therein and PDC Energy, Inc. (relating to the Stock Purchase and Sale Agreement). +8-K +001-37419 +10.1 +12/7/2016 +10.15 +Investment Agreement, dated December 6, 2016, by and among the Investor parties identified therein and PDC Energy, Inc. (relating to the Asset Purchase and Sale Agreement). +8-K +001-37419 +10.2 +12/7/2016 +10.16 +Purchase Agreement, dated as of November 14, 2017, by and between 10.PDC Energy, Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the initial purchasers named therein, and PDC Permian, Inc., a subsidiary guarantor of the Company, relating to the 5.750% Senior Notes due 2026. +8-K +001-37419 +10.1 +11/17/2017 +10.17 +Registration Rights Agreement, dated as of November 29, 2017, by and between PDC Energy, Inc., PDC Permian, Inc., a subsidiary guarantor of the Company, and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the initial purchasers, relating to the 5.750% Senior Notes due 2026. +8-K +001-37419 +10.1 +11/29/2017 +132 +Incorporated by Reference +Exhibit Number +Exhibit Description +Form +SEC File Number +Exhibit +Filing Date +Filed Herewith +12.1 +Computation of Ratio of Earnings to Fixed Charges. +X +21.1 +Subsidiaries. +X +23.1 +Consent of PricewaterhouseCoopers LLP. +X +23.2 +Consent of Ryder Scott Company, L.P., Petroleum Consultants. +X +23.3 +Consent of Netherland, Sewell & Associates, Inc., Petroleum Consultants. +X +31.1 +Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +31.2 +Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +32.1 +Certifications by Chief Executive Officer and Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. +X +99.1 +Report of Independent Petroleum Consultants - Ryder Scott Company, L.P. +X +99.2 +Report of Independent Petroleum Consultants - Netherland, Sewell & Associates, Inc. +X +101.INS +XBRL Instance Document +X +101.SCH +XBRL Taxonomy Extension Schema Document +X +101.CAL +XBRL Taxonomy Extension Calculation Linkbase Document +X +101.DEF +XBRL Taxonomy Extension Definition Linkbase Document +X +101.LAB +XBRL Taxonomy Extension Label Linkbase Document +X +101.PRE +XBRL Taxonomy Extension Presentation Linkbase Document +X +133 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +PDC ENERGY, INC. +By: /s/ Barton R. Brookman +Barton R. Brookman +President and Chief Executive Officer +February 26, 2018 +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated: +Signature +Title +Date +/s/ Barton R. Brookman +President, Chief Executive Officer and Director +February 26, 2018 +Barton R. Brookman +(principal executive officer) +/s/ R. Scott Meyers +Senior Vice President and Chief Financial Officer +February 26, 2018 +R. Scott Meyers +(principal financial officer and principal accounting officer) +/s/ Jeffrey C. Swoveland +Chairman and Director +February 26, 2018 +Jeffrey C. Swoveland +/s/ Anthony J. Crisafio +Director +February 26, 2018 +Anthony J. Crisafio +/s/ Larry F. Mazza +Director +February 26, 2018 +Larry F. Mazza +/s/ David C. Parke +Director +February 26, 2018 +David C. Parke +/s/ Randy S. Nickerson +Director +February 26, 2018 +Randy S. Nickerson +/s/ Mark E. Ellis +Director +February 26, 2018 +Mark E. Ellis +/s/ Christina M. Ibrahim +Director +February 26, 2018 +Christina M. Ibrahim +134 +GLOSSARY OF UNITS OF MEASUREMENT AND INDUSTRY TERMS +UNITS OF MEASUREMENT +The following presents a list of units of measurement used throughout the document. +Bbl – One barrel of crude oil or NGL or 42 gallons of liquid volume. +Bcf – One billion cubic feet of natural gas volume. +Boe – One barrel of crude oil equivalent. +Btu – British thermal unit. +BBtu – One billion British thermal units. +MBoe – One thousand barrels of crude oil equivalent. +MBbls – One thousand barrels of crude oil. +Mcf – One thousand cubic feet of natural gas volume. +MMBoe – One million barrels of crude oil equivalent. +MMBbls – One million barrels of crude oil. +MMBtu – One million British thermal units. +MMcf – One million cubic feet of natural gas volume. +GLOSSARY OF INDUSTRY TERMS +The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report: +CIG - Colorado Interstate Gas. +Completion - Refers to the installation of permanent equipment for the production of crude oil and natural gas from a recently drilled well or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned. +Developed acreage - Acreage assignable to productive wells. +Development well - A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. +Differentials - The difference between the crude oil and natural gas index spot price and the corresponding cash spot price in a specified location. +Dry well or dry hole - A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well. +Exploratory well - A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. +Extensions, discoveries, and other additions - As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates. +Farm-out - Transfer of all or part of the operating rights from a working interest owner to an assignee, who assumes all or some of the burden of development in return for an interest in the property. The assignor usually retains an overriding royalty interest but may retain any type of interest. +Fracture or Fracturing - Procedure to stimulate production by forcing a mixture of fluid and proppant into the formation under high pressure. Fracturing creates artificial fractures in the reservoir rock to increase permeability and porosity, thereby allowing the release of trapped hydrocarbons. +Gross acres or wells - Refers to the total acres or wells in which we have a working interest. +Horizontal drilling - A drilling technique that permits the operator to drill a horizontal well shaft from the bottom of a vertical well and thereby to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons. +135 +Joint interest billing - Process of billing/invoicing the costs related to well drilling, completions, and production operations among working interest partners. +Natural gas liquid(s) or NGL(s) - Hydrocarbons which can be extracted from natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs include ethane, propane, butane, and other natural gasolines. +Net acres or wells - Refers to gross acres or wells we own multiplied, in each case, by our percentage working interest. References to net acres or wells include our proportionate share of PDCM's and our affiliated partnerships' net acres or wells. +Net production - Crude oil and natural gas production that we own, less royalties and production due to others. +Non-operated - A project in which we are not the operator. +NYMEX - New York Mercantile Exchange. +Operator - The individual or company responsible for the exploration, development and/or production of an oil or gas well or lease. +Overriding royalty - An interest which is created out of the operating or working interest. Its term is coextensive with that of the operating interest. +Possible reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability to exceed the sum of proved, probable, and possible reserves. When probabilistic methods are used, there must be at least a 10 percent probability that the actual quantities recovered will equal or exceed the sum of proved, probable and possible estimates. +Present value of future net revenues or (PV-10) - The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, of proved reserves calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using pricing and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization, and discounted using an annual discount rate of 10 percent. PV-10 is pre-tax and therefore a non-U.S. GAAP financial measure. +Probable reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Similarly, when probabilistic methods are used, there must be at least a 50 percent probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. +Productive well - An exploratory or developmental well that is not a dry well or dry hole, as defined above. +Proved developed non-producing reserves - Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and/or (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells. +Proved developed producing reserves or PDPs - Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods. +Proved developed reserves - The combination of proved developed producing and proved developed non-producing reserves. +Proved reserves - This term means "proved oil and gas reserves" as defined in SEC Regulation S-X Section 4-10(a) and refers to those quantities of crude oil and condensate, natural gas, and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing conditions, operating methods, and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +136 +Proved undeveloped reserves or PUDs - Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. +Recomplete or Recompletion - The modification of an existing well for the purpose of producing crude oil and natural gas from a different producing formation. +Reserves - Estimated remaining quantities of crude oil, natural gas, NGLs and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering crude oil, natural gas, and NGLs or related substances to market, and all permits and financing required to implement the project. +Royalty - An interest in a crude oil and natural gas lease or mineral interest that gives the owner of the royalty the right to receive a portion of the production from the leased acreage or mineral interest (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +Section - A square tract of land one mile by one mile, containing 640 acres. +Spud - To begin drilling; the act of beginning a hole. +Standardized measure of discounted future net cash flows or standardized measure - Future net cash flows discounted at a rate of 10 percent. Future net cash flows represent the estimated future revenues to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment and (ii) future income tax expense. +Stratigraphic test well - A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. +Undeveloped acreage - Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas, regardless of whether such acreage contains proved reserves. +Waha - Waha West Texas natural gas prices +Working interest - An interest in a crude oil and natural gas lease that gives the owner of the interest the right to drill and produce crude oil and natural gas on the leased acreage. It requires the owner to pay its share of the costs of drilling and production operations. +Workover - Major remedial operations on a producing well to restore, maintain, or improve the well's production. +137 \ No newline at end of file diff --git a/raw/filings/0000077877/2017/0000077877-18-000008/filing_metadata.csv b/raw/filings/0000077877/2017/0000077877-18-000008/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..f9dda1c7baefbe4b364f97f2b57f9f44ea3beb39 --- /dev/null +++ b/raw/filings/0000077877/2017/0000077877-18-000008/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000077877,PDCE,"PDC ENERGY, INC.",10-K,2018-02-27,2017-12-31,2018-02-26T22:53:06.000Z,0000077877-18-000008,pdce-10kxfy17.htm,10-K,22573091,1,0,https://www.sec.gov/Archives/edgar/data/77877/000007787718000008/pdce-10kxfy17.htm,https://www.sec.gov/Archives/edgar/data/77877/000007787718000008/,2017,2017,1 diff --git a/raw/filings/0000077877/2017/0000077877-18-000008/item1.txt b/raw/filings/0000077877/2017/0000077877-18-000008/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2017/0000077877-18-000008/item13.txt b/raw/filings/0000077877/2017/0000077877-18-000008/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..73dad74a281185c7e9b901baddab6addc14edfdb --- /dev/null +++ b/raw/filings/0000077877/2017/0000077877-18-000008/item13.txt @@ -0,0 +1,2 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2018 Annual Stockholders' meeting and is incorporated by reference in this report. \ No newline at end of file diff --git a/raw/filings/0000077877/2017/0000077877-18-000008/item9a.txt b/raw/filings/0000077877/2017/0000077877-18-000008/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..adfe595d2177410ea5b10aed1469762dbeffd4a3 --- /dev/null +++ b/raw/filings/0000077877/2017/0000077877-18-000008/item9a.txt @@ -0,0 +1,17 @@ +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +As of December 31, 2017 , we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(e) and 15d-15(e). Based on the results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were not effective as of December 31, 2017 because of the material weaknesses in our internal control over financial reporting described below. +Management's Report on Internal Control over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Internal control over financial reporting is a process designed by, or under the supervision of, our CEO and CFO, or persons performing similar functions, and effected by our board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate. +Management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2017 , based upon the criteria established in "Internal Control – Integrated Framework (2013)" issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). +A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. +We did not maintain a sufficient complement of personnel within the Land Department as a result of increased volume of leases, which contributed to the ineffective design and maintenance of controls to verify the completeness and accuracy of land administrative records associated with unproved leases, which are used in verifying the completeness, accuracy, valuation, rights and obligations over the accounting of properties and equipment, sales and accounts receivable, and costs and expenses. These control deficiencies resulted in immaterial adjustments of our unproved properties, impairment of unproved properties, sales, accounts receivable, and depletion expense accounts and related disclosures during 2017. +Additionally, these control deficiencies could result in misstatements of substantially all accounts and disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. Accordingly, our management has determined that these control deficiencies constitute material weaknesses. +The effectiveness of our internal control over financial reporting as of December 31, 2017 , has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears under Item 8. +Remediation Plan for Material Weaknesses +In response to the identified material weaknesses, our management, with the oversight of the Audit Committee of our board of directors, has begun the process of assessing a number of different remediation initiatives to improve our internal control over financial reporting for the year ended December 31, 2018. We are currently in the process of evaluating the material weaknesses and are developing a plan of remediation to strengthen our overall controls over the sufficient complement of personnel within the Land Department and the completeness and accuracy of land administration records. We are committed to continuing to improve our internal control processes and will continue to review, optimize, and enhance our internal control +128 +environment. These material weaknesses will not be considered remediated until the applicable remedial controls operate for a sufficient period of time and management has concluded, through testing, that these controls are operating effectively. +Changes in Internal Control over Financial Reporting +There were no changes in our internal control over financial reporting during the quarter ended December 31, 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. \ No newline at end of file diff --git a/raw/filings/0000077877/2017/0000077877-18-000008/rp_note.txt b/raw/filings/0000077877/2017/0000077877-18-000008/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2017/0000077877-18-000008/rpt_disclosure.txt b/raw/filings/0000077877/2017/0000077877-18-000008/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..d8d39f95424ab921dcdb4f9fcf8ac023f787a212 --- /dev/null +++ b/raw/filings/0000077877/2017/0000077877-18-000008/rpt_disclosure.txt @@ -0,0 +1,19 @@ +TRANSACTIONS WITH RELATED PARTIES +Related Transactions +During 2017, there was no transaction or series of transactions, nor is there any currently proposed transaction, involving an amount exceeding +$120,000 in which the Company is or was a participant and in which any Director, executive officer, known holder of more than five percent of the Company's voting securities, or any member of the +immediate family of any of the foregoing persons, had or has a direct or indirect material interest for which disclosure is required under Item 404 of Regulation S-K. +34 +Table of Contents +Policies and Procedures With Respect to Transactions with Related Parties +The Board has adopted a written policy for the review, approval and ratification of transactions that involve related parties and potential +conflicts of interest. The related-party transaction policy applies to each Director and executive officer of the Company, any nominee for election as a Director, any security holder who is known to +own more than five percent of the Company's voting securities, any immediate family member of any of the foregoing persons and any corporation, firm or association in which one or more of the +Company's Directors or executive officers have a substantial interest. +Under +our related-party transaction policy, a related-party transaction is a transaction or arrangement involving a related party in which the Company is a participant or that would +require disclosure in the Company's filings with the SEC as a transaction with a related party. The related party must disclose to +the Audit Committee any potential related-party transactions and must disclose all material facts with respect to such transaction and relationship. All related-party transactions so disclosed will be +reviewed by the Audit Committee. In determining whether to approve or ratify a transaction, the Audit Committee will consider the relevant facts and circumstances of the transaction, which may include +factors such as the relationship of the related party to the Company, the materiality or significance of the transaction to the Company and the business purpose and reasonableness of the transaction, +whether the transaction is comparable to a transaction that could be available to the Company from an unrelated party and the impact of the transaction on the Company's business and operations. \ No newline at end of file diff --git a/raw/filings/0000077877/2018/0000077877-19-000009/filing.txt b/raw/filings/0000077877/2018/0000077877-19-000009/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..5ece64d0ab24aac22b87a0e9e6f8d525240ba070 --- /dev/null +++ b/raw/filings/0000077877/2018/0000077877-19-000009/filing.txt @@ -0,0 +1,8894 @@ +10-K +1 +pdce-201810xk.htm +PDCE ENERGY 2018 FORM 10-K +Document +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +T ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2018 +or +£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from __________ to _________ +Commission File Number 001-37419 +PDC ENERGY, INC. +(Exact name of registrant as specified in its charter) +Delaware +95-2636730 +(State of incorporation) +(I.R.S. Employer Identification No.) +1775 Sherman Street, Suite 3000 +Denver, Colorado 80203 +(Address of principal executive offices) (Zip code) +Registrant's telephone number, including area code: (303) 860-5800 +Securities registered pursuant to Section 12(b) of the Act: +Title of each class +Name of each exchange on which registered +Common Stock, par value $0.01 per share +NASDAQ Global Select Market +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes T No £ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes £ No T +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes T No £ +Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes T No £ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. T +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act. +Large accelerated filer x +Accelerated filer o +Non-accelerated filer £ +Smaller reporting company o +Emerging growth company o +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. £ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes £ No T +The aggregate market value of our common stock held by non-affiliates on June 30, 2018 was $4.0 billion (based on the closing price of $60.45 per share as of the last business day of the fiscal quarter ending June 30, 2018 ). +As of February 15, 2019 , there were 66,148,128 shares of our common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +We hereby incorporate by reference into this document the information required by Part III of this Form, which will appear in our definitive proxy statement filed pursuant to Regulation 14A for our 2019 Annual Meeting of Stockholders. +PDC ENERGY, INC. +2018 ANNUAL REPORT ON FORM 10-K +TABLE OF CONTENTS +PART I +Page +Items 1. and 2. +Business and Properties +3 +Item 1A. +Risk Factors +20 +Item 1B. +Unresolved Staff Comments +35 +Item 3. +Legal Proceedings +36 +Item 4. +Mine Safety Disclosures +36 +PART II +Item 5. +Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +36 +Item 6. +Selected Financial Data +38 +Item 7. +Management's Discussion and Analysis of Financial Condition and Results of Operations +39 +Item 7A. +Quantitative and Qualitative Disclosures About Market Risk +65 +Item 8. +Financial Statements and Supplementary Data +67 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +125 +Item 9A. +Controls and Procedures +125 +Item 9B. +Other Information +126 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +127 +Item 11. +Executive Compensation +127 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +127 +Item 13. +Certain Relationships and Related Transactions and Director Independence +127 +Item 14. +Principal Accounting Fees and Services +127 +PART IV +Item15. +Exhibits, Financial Statement Schedules +127 +Item 16. +Form 10-K Summary +112 +Signatures +131 +Glossary of Units of Measurements and Industry Terms +132 +PART I +REFERENCES TO THE REGISTRANT +Unless the context otherwise requires, references in this report to "PDC," the "Company," "we," "us," "our" or "ours" refer to the registrant, PDC Energy, Inc., our wholly-owned subsidiaries consolidated for the purposes of its financial statements, including our proportionate share of the financial position, results of operations, cash flows and operating activities of our affiliated partnerships. PDC Energy, Inc. is a Delaware corporation, having reincorporated from Nevada in 2015. +GLOSSARY OF UNITS OF MEASUREMENTS AND INDUSTRY TERMS +Units of measurements and industry terms are defined in the Glossary of Units of Measurements and Industry Terms, included at the end of this report. +SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS +This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical fact included in and incorporated by reference into this report are "forward-looking statements." Words such as expect, anticipate, intend, plan, believe, seek, estimate, schedule and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements include, among other things, statements regarding future: production, costs and cash flows; drilling locations, zones and growth opportunities; commodity prices and differentials; capital expenditures and projects, including the number of rigs employed, and that cash flows from operations will exceed expected capital investments in crude oil and natural gas properties for 2019 and 2020; management of lease expiration issues; financial ratios and compliance with covenants in our revolving credit facility and other debt instruments; impacts of certain accounting and tax changes; anticipated sale of our Delaware Basin midstream assets and the timing of those sales; midstream capacity and related curtailments; fractionation capacity; impacts of Colorado political matters; ability to meet our volume commitments to midstream providers; ongoing compliance with our consent decree; reclassification of the Denver Metro/North Front Range NAA ozone classification to serious; and timing and adequacy of infrastructure projects of our midstream providers. +The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this report or accompanying materials, we may use the term “projection” or similar terms or expressions, or indicate that we have “modeled” certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or the industry in periods beyond the current fiscal year. Because such statements relate to events or conditions further in the future, they are subject to increased levels of uncertainty. +Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to: +• +changes in global production volumes and demand, including economic conditions that might impact demand and prices for products we produce; +• +volatility of commodity prices for crude oil, natural gas and natural gas liquids ("NGLs") and the risk of extended periods of depressed prices; +• +volatility and widening of differentials; +• +reductions in the borrowing base under our revolving credit facility; +• +impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement related to those laws and regulations, liabilities arising thereunder and the costs to comply with those laws and regulations; +• +declines in the value of our crude oil, natural gas and NGLs properties resulting in impairments; +• +changes in estimates of proved reserves; +• +inaccuracy of estimated reserves and production rates; +• +potential for production decline rates from our wells being greater than expected; +• +timing and extent of our success in discovering, acquiring, developing and producing reserves; +1 +• +availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production and the impact of these facilities and regional capacity on the prices we receive for our production; +• +timing and receipt of necessary regulatory permits; +• +risks incidental to the drilling and operation of crude oil and natural gas wells; +• +difficulties in integrating our operations as a result of any significant acquisitions and acreage exchanges; +• +availability of supplies, materials, contractors and services that may delay the drilling or completion of our wells; +• +potential losses of acreage due to lease expirations or otherwise; +• +increases or changes in costs and expenses; +• +future cash flows, liquidity and financial condition; +• +possibility that one or more sales of our Delaware Basin midstream assets will not close as expected; +• +competition within the oil and gas industry; +• +availability and cost of capital; +• +our success in marketing crude oil, natural gas and NGLs; +• +effect of crude oil, natural gas and NGLs derivatives activities; +• +impact of environmental events, governmental and other third-party responses to such events and our ability to insure adequately against such events; +• +cost of pending or future litigation; +• +effect that acquisitions we may pursue have on our capital requirements; +• +our ability to retain or attract senior management and key technical employees; and +• +success of strategic plans, expectations and objectives for our future operations. +Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under Item 1A, Risk Factors , made in this report and our other filings with the U.S. Securities and Exchange Commission ("SEC") for further information on risks and uncertainties that could affect our business, financial condition, results of operations and cash flows. We caution you not to place undue reliance on forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement. +2 +ITEMS 1. AND 2. BUSINESS AND PROPERTIES +The Company +We are a domestic independent exploration and production company that acquires, explores and develops properties for the production of crude oil, natural gas and NGLs, with operations in the Wattenberg Field in Colorado and the Delaware Basin in Texas. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are primarily focused in the Wolfcamp zones. We previously operated properties in the Utica Shale in Southeastern Ohio; however, we divested these properties (the "Utica Shale Divestiture") during the first quarter of 2018. +The following map presents the general locations of our development and production activities as of December 31, 2018 : +The following table presents selected information regarding our results of operations for the periods presented: +Year Ended/As of +December 31, +Percent Change +2018 +2017 +2018-2017 +(production and reserves in MMBoe, dollars in millions) +Wells: +Gross productive wells +2,876 +2,785 +3.3 +% +Net productive wells +2,284 +2,285 +— +% +Horizontal percentage +39.0 +% +32.0 +% +21.9 +% +Operated percentage +84.3 +% +87.0 +% +(3.1 +)% +Gross operated wells turned-in-line +165 +146 +13.0 +% +Net operated wells turned-in-line +151 +128 +18.0 +% +Production: +Wattenberg Field +30.7 +26.8 +14.3 +% +Delaware Basin +9.4 +4.2 +123.7 +% +Utica Shale (1) +0.1 +0.8 +(82.1 +)% +Total +40.2 +31.8 +26.2 +% +Reserves: +Proved reserves +544.9 +452.9 +20.3 +% +Proved developed reserves percentage +32.9 +% +31.6 +% +4.1 +% +Liquidity +$ +1,268.9 +$ +880.7 +44.1 +% +Leverage ratio +1.4 +1.9 +(26.3 +)% +(1) In March 2018, we completed the disposition of our Utica Shale properties. +3 +Our Strengths +• +Significant project inventory in premier crude oil, natural gas and NGL plays. We have a considerable operational presence in two premier U.S. onshore basins, the Wattenberg Field in Weld County, Colorado, and the Delaware Basin in Reeves and Culberson Counties, Texas. We have identified an inventory of horizontal drilling locations in each basin which we believe will allow us to continue to grow our proved reserves and production at attractive rates of return. Such expected returns can vary well by well and are based upon many factors, including, but not limited to commodity prices, drilling rig pace and well development and operating costs. Our 2019 drilling and completion operations are expected to continue to focus on the areas in which we expect to deliver our strongest economic results, which include the Kersey area of the Wattenberg Field and in the oilier eastern and north central areas of the Delaware Basin. +• +Strong financial position. We expect to maintain a disciplined financial strategy, consisting of strong liquidity, low leverage ratios and an active commodity derivative program to help mitigate a portion of the risk associated with commod ity price fluctuations. As of December 31, 2018 , we had a total liquidity position of $1.3 billion , comprised of $1.4 million of cash and cash equivalents and $1.3 billion available for borrowing under our revolving credit facility, a leverage ratio, as defined in our revolving line of credit facility agreement, of 1.4 , and c ommodity derivative positions coverin g 11.0 MMBbls and 8.6 MMBbls of crude oil production for 2019 and 2020, respectively. As of the same date, we had hedged approximately 26.4 Bc f of natural gas for 2019. +• +Balanced and diversified portfolio across two premier U.S. onshore basins. Having drilling opportunities in both the Wattenberg Field and the Delaware Basin allows us to allocate capital between the two areas to diversify our risk. We believe this will improve our overall financial results and drive our future production and reserve growth. Additionally, we believe the geographical diversity of our portfolio aids in the mitigation of risks associated with a single dominant producing area, as each basin has its own operating and competitive dynamic in terms of commodity price markets, service costs, takeaway capacity and regulatory and political considerations. +• +Significant operational control in our core areas. We have, and expect to continue to have, a substantial degree of operational control over our properties. As a result of successfully executing our strategy of acquiring and consolidating largely concentrated acreage positions with high working interests, we operate and manage approximately 84 percent of all wells in which we have an interest across all of our operating basins. Our control allows us to manage our drilling, production, operating and administrative costs and to leverage our technical expertise in our core operating areas. Our leaseholds that are held by production further enhance our operational control by providing us flexibility in selecting drilling locations based upon various operational criteria. +• +Efficiency through technology and consolidation. Technological innovation has led to continued improvement in our Wattenberg Field and Delaware Basin drilling times. These improvements in drilling efficiency have resulted from a combination of highly technical drilling services and equipment and continuity within our operations team. After several years of drilling horizontal wells, our drilling operations in the Wattenberg Field have shown strong results. We are in the process of applying our extensive experience in drilling highly-successful wells in the Wattenberg Field to our growing Delaware Basin operations. +The technology associated with our completions process is also improving as wellbore placement and stage spacing continue to advance. In addition, completion equipment, perforation clusters, fluid and sand type and concentration decisions continue to result in increased estimated ultimate recoveries of crude oil and natural gas reserves. As with our drilling operations, we are currently working toward using the expertise we have developed in the Wattenberg Field to increase the efficiency of our Delaware Basin completions activities. +Also key to our efficiency, we occasionally enter into acquisitions and exchanges that provide acreage consolidation, particularly in the Wattenberg Field, where we continue to drill longer length lateral wells. Longer length lateral wells are more cost effective and reduce the impact on the surface through fewer wells and reduced truck traffic, both of which also provide enhanced efficiencies and are beneficial to the communities in which we operate. +• +Strong environmental, health and safety compliance programs and community outreach. We have focused on establishing effective environmental, health and safety programs that are intended to promote safe working practices for our employees and contractors and to help earn the trust and respect of land owners, regulatory agencies and public officials. This is an important part of our strategy in effectively operating in today’s intensive regulatory and public debate climate. We are also dedicated to being an active and contributing member of the communities in which we +4 +operate. We share our success with these communities in various ways, including charitable giving and community event sponsorships. +• +Strong management team and operational capabilities. We have strong and stable management, led by our executive management team. Each member of the team has between 10 and 30 years of experience in the energy and natural resource industry. This experience collectively spans land, reservoir analysis, operations, accounting, strategy and general operations, and has helped us continue our growth through periods of commodity price pressure and cost inflation and other challenging environments. +Long-Term Business Strategy +Our long-term business strategy focuses on being a responsible and respected provider of energy while generating stockholder value through the exploration and development of crude oil and natural gas properties. We leverage technology and innovation to increase operational efficiencies while prioritizing health, safety and the environment and are focused on the growth of our cash flows, production and reserves, primarily through organic exploration and development of our existing leasehold. We focus on horizontal development drilling programs in resource plays that offer repeatable results and the potential for attractive returns on investment in a range of commodity price environments. Our creation and maintenance of a high-value inventory of drilling locations supports our planned organic growth over the next several years. +In addition to development drilling, we routinely review acquisition and acreage swap opportunities in our core areas of operations and pursue those that meet our strategic plan and that we believe will increase stockholder value. We believe we can extract additional value from such transactions through the addition of more extended reach lateral wells, related production optimization opportunities and increases in our working interests in our development drilling locations afforded by more concentrated acreage positions. Once we have established a significant presence in an area, the use of bolt-on acquisitions and acreage exchanges provides synergies that result in additional economies of scale. +We also maintain a limited and disciplined exploration program with the goal of replenishing our portfolio with new potential drilling locations capable of positioning us for significant production and reserve growth in future years. When doing so, we attempt to accumulate significant leasehold positions before competitive forces drive up the cost of entry and to invest in leasehold positions that are near existing or emerging midstream infrastructure. Our recent exploration activity has been in the Delaware Basin as there are multiple zones that have not seen development sufficient to record proved reserves, such as the Bone Spring and Wolfcamp C zones. +We pursue various midstream, marketing and cost reduction initiatives designed to increase our operating margins, while maintaining a disciplined financial strategy focused on providing a strong financial foundation for the execution of our business strategy. +Operating Areas +Wattenberg Field. In the Wattenberg Field, we have identified a gross operated inventory of approximately 920 horizontal drilling locations with an average lateral length of approximately 8,300 feet. In addition to these drilling locations, we entered 2019 with approximately 135 gross operated drilled uncompleted wells ("DUCs"). Our inventory of Wattenberg Field locations declined in 2018 as a result of our 2018 drilling program and two significant acreage exchanges. Although these acreage exchanges reduced our inventory of gross drilling locations, they increased both our working interest ownership in, and the average lateral length of, the remaining locations. Our average working interest in our Wattenberg Field properties that we operate is approximately 79 percent. Our Wattenberg Field horizontal drilling locations have been substantially de-risked through multiple years of successful development from the field. Substantially all of our Wattenberg Field acreage is held by production. Wells in the Wattenberg Field typically have productive horizons at depths of approximately 6,500 to 7,500 feet below the surface. +Delaware Basin. In the Delaware Basin, we have identified a gross operated inventory of approximately 365 horizontal drilling locations, primarily targeting the Wolfcamp A and Wolfcamp B zones within our oilier eastern and north central areas. The average lateral length of these locations is approximately 7,900 feet. Some of these locations are within untested target zones that may be subject to a higher degree of uncertainty or may depend upon additional delineation and testing. In addition to these drilling locations, we entered 2019 with approximately 20 gross operated DUCs. Wells in the Delaware Basin typically have productive horizons at depths of approximately 8,000 to 11,500 feet below the surface. +Our average working interest in our Delaware Basin properties that we operate is approximately 83 percent. Our leasehold in the Delaware Basin requires a more active drilling program than the Wattenberg Field in terms of managing lease +5 +expirations. In some cases, continuous operations will be required to maintain the underlying leasehold in the Delaware Basin. However, with our high percentage of operated leasehold in the area, we expect to have adequate control over the location and pace of our development to manage lease expirations and meet our drilling obligations in the central and eastern parts of our acreage position. +We are in the process of actively marketing our Delaware Basin crude oil gathering, natural gas gathering and produced water gathering and disposal assets for sale and currently expect to execute agreements for the sales of these assets in the first half of 2019. +2019 Strategic Focus +Our planned 2019 capital investments in crude oil and natural gas properties, which we expect to be between $810 million and $870 million , are focused on continued execution of our development plans in the Wattenberg Field and Delaware Basin. In allocating our planned expenditures, we consider, among other things, expected rates of return, the political environment and our remaining inventory in order to best meet our short- and long-term corporate goals. +As a result of this disciplined approach, we expect that cash flows from operations in 2019 will exceed our capital investments in crude oil and natural gas properties, which exclude investments in corporate capital, by approximately $65.0 million . This expectation is based on our current production forecast for 2019 and our average 2019 price assumptions of $55.00 for New York Mercantile Exchange ("NYMEX") crude oil and $3.00 for NYMEX natural gas. Assuming a NYMEX crude oil price of $50.00 , we expect cash flows from operations to exceed our capital investments in crude oil and natural gas properties by approximately $25.0 million . We anticipate that capital investments will exceed cash flows from operations during the first half of 2019 and expect cash flows from operations to exceed capital investment during the remainder of the year. Our leverage ratio, as defined in our revolving credit facility agreement, is expected to decrease from 1.4 as of the end of 2018 to approximately 1.3 by the end of 2019 based on our anticipated production and $50.00 to $55.00 NYMEX crude oil prices. +Assuming a NYMEX crude oil price of $45.00 , we expect cash flows from operations to approximate our capital investments in crude oil and natural gas properties. A significant decline in NYMEX crude oil prices below approximately $45.00 per barrel would negatively impact our results of operations, financial condition and future development plans. We may revise our 2019 capital investment program during the year as a result of, among other things, changes in commodity prices or our internal long-term outlook for commodity prices, the cost of services for drilling and well completion activities, requirements to hold acreage, drilling results, changes in our borrowing capacity, a significant change in cash flows, regulatory issues, requirements to maintain continuous activity on leaseholds or acquisition and/or divestiture opportunities. +In 2019, we also expect to spend approximately $20 million for corporate capital, the majority of which is related to the implementation of an enterprise resource planning (“ERP”) system to replace our existing operating and financial systems. This long-planned investment is being made to enhance maintenance of our financial records, improve operational functionality and provide timely information to our management team related to the operation of the business. +Recent Strategic Developments +We closed an acquisition of properties from Bayswater Exploration and Production LLC (the "Bayswater Asset Acquisition") in January 2018, acquiring approximately 7,400 net acres, 24 operated horizontal wells that were either DUCs or in-process wells at the time of closing and approximately 220 gross drilling locations. +During 2018, we completed two acreage exchanges that consolidated our position in the core area of the Wattenberg Field, resulting in us acquiring approximately 14,800 net acres in exchange for 15,500 net acres. +Business Segments +We are engaged in two operating segments: our oil and gas exploration and production segment and our gas marketing segment. All of our material operations are attributable to our exploration and production business; therefore, our operations are presented as a single segment for all periods presented. Our most significant customer is DCP Midstream, LP ("DCP"). Sales to this party constituted more than 10 percent of our 2018 revenues. Given the liquidity in the market for the sale of hydrocarbons, however, we believe that the loss of any purchaser or the aggregate loss of several customers could be managed by selling to alternative purchasers. +6 +Properties +Productive Wells +The following table presents our productive wells: +Productive Wells +As of December 31, 2018 +Crude Oil +Natural Gas +Total +Operating Region/Area +Gross +Net +Gross +Net +Gross +Net +Wattenberg Field +1,044 +706.0 +1,746 +1,506.7 +2,790 +2,212.7 +Delaware Basin +43 +29.8 +43 +41.2 +86 +71.0 +Total productive wells +1,087 +735.8 +1,789 +1,547.9 +2,876 +2,283.7 +Proved Reserves +The following table presents our proved reserve estimates as of December 31, 2018 , based on reserve reports prepared by our independent petroleum engineering consulting firms, Ryder Scott Company, L.P. ("Ryder Scott") and Netherland, Sewell & Associates, Inc. ("NSAI") and related information: +Proved Reserves at December 31, 2018 +Proved Reserves (MMBoe) +% of Total Proved Reserves +% Proved Developed +% Liquids +Proved Reserves to Production Ratio (in years)(1) +2018 Production (MBoe) +Wattenberg Field +425.4 +78 +% +33 +% +57 +% +13.9 +30,652 +Delaware Basin +119.5 +22 +% +34 +% +68 +% +12.8 +9,359 +Utica Shale (2) +— +— +% +— +% +— +% +— +149 +Total +544.9 +100 +% +33 +% +59 +% +13.6 +40,160 +_________ +(1) Based on 2018 production. +(2) In March 2018, we completed the disposition of our Utica Shale properties. +Our proved reserves are sensitive to future crude oil, natural gas and NGLs sales prices and the related effect on the economic productive life of producing properties. Increases in commodity prices may result in a longer economic productive life of a property or result in recognition of more economically viable proved undeveloped ("PUD") reserves, while decreases in commodity prices may result in negative impacts of this nature. All of our proved reserves are located in the U.S. +Controls Over Reserve Report Preparation . Our proved reserve estimates are prepared using the definitions for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a) and other applicable SEC rules. Inputs and major assumptions related to our proved reserves are reviewed annually by an internal team composed of reservoir engineers, geologists, land and management for adherence to SEC guidelines through a detailed review of land and accounting records, available geological and reservoir data and production performance data. The internal team compiles the reviewed data and forwards the applicable data to Ryder Scott or NSAI. Our proved reserves in the Wattenberg Field as of December 31, 2018 were estimated by Ryder Scott and our proved reserves in the Delaware Basin as of that date were estimated by NSAI. +When preparing our reserve estimates, neither Ryder Scott nor NSAI independently verifies the accuracy and completeness of information and data furnished by us with respect to ownership interests, production volumes, well test data, historical costs of operations and development, product prices or any agreements relating to current and future operations of properties or sales of production. Ryder Scott and NSAI prepare estimates of our reserves in conjunction with an ongoing review by our engineers. A final comparison of data is performed to ensure that the reserve estimates are complete, determined pursuant to acceptable industry methods, and with a level of detail we deem appropriate. The final estimated reserve reports are prepared by Ryder Scott and NSAI and reviewed by our engineering staff and management prior to issuance by those firms. +Letters which identify the professional qualifications of the individuals at Ryder Scott and NSAI who are responsible for overseeing the preparation of our reserve estimates as of December 31, 2018 have been filed as Exhibits 99.1 and 99.2 to this report. +7 +Internally, the professional qualifications of our lead engineer primarily responsible for overseeing the preparation of our reserve estimates, as defined in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the Society of Petroleum Engineers, qualifies this individual as a Reserve Estimator. This person holds a Masters of Petroleum Engineering from the Colorado School of Mines and a Bachelors of Geology from the University of Colorado and has over 18 years of oil and gas experience. +In determining our proved reserves estimates, we used a combination of performance methods, including decline curve analysis and other computational methods, offset analogies and seismic data and interpretation. All of our proved undeveloped reserves conform to the SEC five-year rule requirement as all proved undeveloped locations are scheduled, according to an adopted development plan, to be drilled within five years of the location’s initial booking date. +Commodity Pricing . Per SEC rules, the pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of the month prices for the preceding 12 months. The NYMEX prices used in preparing the reserves are then adjusted based on energy content, location and basis differentials and other marketing deductions to arrive at the net realized price. +The indicated index prices for our reserves, by commodity, are presented below. +Average Benchmark Prices (1) +As of December 31, +Crude Oil +(per Bbl) (2) +Natural Gas +(per Mcf) (2) +NGLs +(per Bbl) (3) +2018 +$ +65.56 +$ +3.10 +$ +65.56 +2017 +51.34 +2.98 +51.34 +2016 +42.75 +2.48 +42.75 +The netted back price used to estimate our reserves, by commodity, are presented below. +Price Used to Estimate Reserves (4) +As of December 31, +Crude Oil +(per Bbl) +Natural Gas +(per Mcf) +NGLs +(per Bbl) +2018 +$ +61.14 +$ +2.15 +$ +23.04 +2017 +48.68 +2.31 +20.21 +2016 +38.67 +1.85 +11.97 +___________ +(1) +Per SEC rules, the pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of the month prices for the preceding 12 months. +(2) Our benchmark prices for crude oil and natural gas are West Texas Intermediate ("WTI") and Henry Hub, respectively. +(3) +For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. +(4) +These prices are based on the index prices and are net of basin differentials, transportation fees, contractual adjustments and Btu adjustments we experienced for the respective commodity. +Commodities and Standardized Measure . Reserve estimates involve judgments and reserves cannot be measured exactly. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geologic and geophysical data and economic changes. Neither the estimated future net cash flows nor the standardized measure of discounted future net cash flows ("standardized measure") is intended to represent the current market value of our proved reserves. For additional information regarding both of these measures, as well as other information regarding our proved reserves, see the Supplemental Information Unaudited - Crude Oil and Natural Gas Information provided with our consolidated financial statements included elsewhere in this report. +8 +The following tables provide information regarding our estimated proved reserves: +As of December 31, +2018 +2017 +2016 +Proved reserves +Crude oil and condensate (MMBbls) +190 +155 +118 +Natural gas (Bcf) +1,336 +1,154 +834 +NGLs (MMBbls) +132 +106 +84 +Total proved reserves (MMBoe) +545 +453 +341 +Proved developed reserves (MMBoe) +180 +143 +98 +Estimated undiscounted future net cash flows (in millions) (1) +$ +7,735 +$ +5,453 +$ +2,681 +Standardized measure (in millions) +$ +4,448 +$ +2,880 +$ +1,421 +PV-10 ( in millions) (2) +$ +5,321 +$ +3,212 +$ +1,675 +___________ +(1) +Amount represents aggregate undiscounted future net cash flows, before income taxes, estimated by Ryder Scott and NSAI, of approximately $9.1 billion , $6.2 billion and $3.3 billion as of December 31, 2018 , 2017 and 2016 , respectively, less an internally-estimated undiscounted future income tax expense of approximately $1.4 billion , $0.7 billion and $0.6 billion , respectively. +(2) +PV-10 is a non-U.S. GAAP financial measure. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in accordance with U.S. GAAP, but rather should be considered in addition to the standardized measure. See Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10 and a reconciliation of our PV-10 value to the standardized measure. +The additions to our proved reserves at December 31, 2018 as compared to December 31, 2017 were primarily a result of extending the average lateral length of newly-drilled and expected future wells, combined with an increase in our working interest ownership in wells in areas with established reserves largely resulting from recently-completed acreage exchanges and the addition of proved undeveloped locations in the Delaware Basin. +The following table presents our estimated proved developed and undeveloped reserves by category and area: +As of December 31, 2018 +Operating Region/Area +Crude Oil and Condensate (MMBbls) +Natural Gas +(Bcf) +NGLs +(MMBbls) +Crude Oil +Equivalent +(MMBoe) +Percent +Proved developed +Wattenberg Field +46.3 +357.4 +33.2 +139.0 +26 +% +Delaware Basin +15.6 +85.7 +10.7 +40.5 +7 +% +Total proved developed +61.9 +443.1 +43.9 +179.5 +33 +% +Proved undeveloped +Wattenberg Field +90.5 +749.2 +71.0 +286.4 +52 +% +Delaware Basin +38.0 +143.4 +17.1 +79.0 +15 +% +Total proved undeveloped +128.5 +892.6 +88.1 +365.4 +67 +% +Total proved reserves +Wattenberg Field +136.8 +1,106.6 +104.2 +425.4 +78 +% +Delaware Basin +53.6 +229.1 +27.8 +119.5 +22 +% +Total proved reserves +190.4 +1,335.7 +132.0 +544.9 +100 +% +9 +Proved Reserves Sensitivity Analysis . We have performed an analysis of our proved reserve estimates as of December 31, 2018 to present sensitivity associated with a lower crude oil price as the value of crude oil influences the value of our proved reserves and PV-10 most significantly. Replacing the 2018 NYMEX price for crude oil used in estimating our reported proved reserves with $50.00 as shown on the table below, and leaving all other parameters unchanged, results in changes to our estimated proved reserves as shown. +Pricing Scenario - NYMEX +Crude Oil (per Bbl) +Natural Gas (per MMBtu) +Proved Reserves (MMBoe) +% Change from December 31, 2018 Estimated Reserves +PV-10 (in Millions) +PV-10 % Change from December 31, 2018 Estimated Reserves +2018 SEC Reserve Report (1) +$ +65.56 +$ +3.10 +544.9 +— +$ +5,321.3 +— +Alternate Price Scenario +$ +50.00 +$ +3.10 +529.3 +(3 +)% +$ +3,659.0 +(31 +)% +__________ +(1) +These prices are the SEC NYMEX prices applied to the calculation of the PV-10 value. Such prices have been applied consistently in the alternate pricing scenario to include the impact of adjusting for deductions for any basin differentials, transportation fees, contractual adjustments and Btu adjustments we experienced for the relevant commodity. +Developed and Undeveloped Acreage +The following table presents our developed and undeveloped lease acreage: +As of December 31, 2018 +Developed +Undeveloped +Total +Operating Region/Area +Gross +Net +Gross +Net +Gross +Net +Wattenberg Field (1) +115,600 +109,300 +16,000 +14,700 +131,600 +124,000 +Delaware Basin (2) +36,100 +32,300 +22,300 +19,100 +58,400 +51,400 +Total acreage +151,700 +141,600 +38,300 +33,800 +190,000 +175,400 +_______________ +(1) +Of the amounts shown, 91,500 gross (86,100 net) developed lease acres and 11,100 gross (10,200 net) undeveloped lease acres are associated with our approximately 920 operated horizontal Wattenberg Field drilling locations targeting the Niobrara or Codell plays. The remaining acres are associated with other zones within the field that we do not currently estimate to be economic to develop; therefore, we have not currently identified any potential drilling locations on these acres. +(2) +See below regarding Culberson County acreage expirations. +Substantially all of our undeveloped acreage in the Wattenberg Field is related to leaseholds that are held by production. Our Wattenberg Field leaseholds at risk to expire in 2019 and 2020 are not material. +In the Delaware Basin, there are drilling obligations or continuous drilling clauses associated with the majority of our acreage. We believe that our current Delaware Basin drilling plan should provide sufficient development to meet these obligations in our core areas over the next few years. In the event that we do not meet the obligations for certain leases, we plan to make any necessary bonus extension payments or changes to drilling schedules, or seek to renew or re-lease in order to retain the leases. However, the payments necessary to extend or retain certain leases may be significant and we may not be successful in such efforts or we may elect not to pursue them. +During 2017 and 2018, we recorded impairment charges totaling $285.9 million and $458.4 million , respectively, as we identified current and anticipated leasehold expirations within the Western Culberson County area of the Delaware Basin and made the determination that we would no longer pursue plans to develop these properties. The impaired non-focus leaseholds typically have a higher gas to oil ratio and a greater degree of geologic complexity than our other Delaware Basin properties. In 2019, we expect that we will allow approximately 18,300 gross (17,900 net) acres of our leaseholds in the Delaware Basin to expire. Of these leaseholds, we expect that approximately 9,500 gross and net acres and 8,600 gross (8,000 net) acres will expire in the first and third quarters, respectively, of 2019. Taking all expected 2019 expirations into account, we anticipate ending 2019 with approximately 40,100 gross (33,500 net) acres in the Delaware Basin. In 2020, we expect that we will allow approximately 3,400 gross (1,800 net) acres of our leaseholds in the Delaware Basin to expire. We are currently exploring strategic alternatives with respect to the acres expected to expire in 2019 and 2020 and believe that we may be able to monetize a portion of this acreage. See Item 1A. Risk Factors - Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold +10 +acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities. +Drilling Activity. The following tables set forth a summary of our developmental and exploratory well drilling activity for the periods presented. Productive wells consist of wells that were turned-in-line and commenced production during the period, regardless of when drilling was initiated. In-process wells represent wells that are in the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection as of the date shown. We utilize pad drilling operations where multiple wells are developed from the same well pad in both the Wattenberg Field and Delaware Basin. Because we operate multiple drilling rigs in each operating area, we expect to have in-process wells at any given time. Wells may be in-process for up to a year. +Gross Development Well Drilling Activity +Year Ended December 31, +2018 +2017 +2016 +Operating Region/Area +Productive +In-Process +Non-Productive +Productive +In-Process +Non-Productive (1) +Productive +In-Process +Non-Productive (1) +Wattenberg Field, operated wells +139 +133 +— +130 +87 +— +140 +64 +2 +Wattenberg Field, non-operated wells +20 +5 +— +12 +14 +1 +24 +12 +— +Delaware Basin, operated wells +26 +22 +1 +9 +10 +— +1 +5 +— +Delaware Basin, non-operated wells +11 +— +— +2 +8 +— +— +— +— +Utica Shale (2) +— +— +— +— +— +— +5 +— +— +Total gross development wells +196 +160 +1 +153 +119 +1 +170 +81 +2 +__________ +(1) Represents mechanical failures that resulted in the plugging and abandonment of the respective well(s). +(2) In March 2018, we completed the disposition of our Utica Shale properties. +Net Development Well Drilling Activity +Year Ended December 31, +2018 +2017 +2016 +Operating Region/Area +Productive +In-Process +Non-Productive +Productive +In-Process +Non-Productive (1) +Productive +In-Process +Non-Productive (1) +Wattenberg Field, operated wells +126.8 +122.4 +— +112.8 +80.1 +— +109.7 +52.7 +1.7 +Wattenberg Field, non-operated wells +2.5 +0.9 +— +1.6 +2.6 +0.1 +5.0 +2.8 +— +Delaware Basin, operated wells +24.5 +16.3 +1.0 +10.1 +9.4 +— +1.0 +4.8 +— +Delaware Basin, non-operated wells +1.2 +— +— +0.4 +1.0 +— +— +— +— +Utica Shale (2) +— +— +— +— +— +— +4.5 +— +— +Total net development wells +155.0 +139.6 +1.0 +124.9 +93.1 +0.1 +120.2 +60.3 +1.7 +_________ +(1) Represents mechanical failures that resulted in the plugging and abandonment of the respective well(s). +(2) In March 2018, we completed the disposition of our Utica Shale properties. +11 +Gross Exploratory Well Drilling Activity +Year Ended December 31, +2018 +2017 +2016 +Operating Region/Area +Productive +In-Process +Non-Productive +Productive +In-Process +Non-Productive +Productive +In-Process +Non-Productive +Wattenberg Field, operated wells +— +— +— +— +— +— +— +— +— +Wattenberg Field, non-operated wells +— +— +— +— +— +— +— +— +— +Delaware Basin +3 +2 +— +5 +3 +2 +— +— +— +Total gross development wells +3 +2 +— +5 +3 +2 +— +— +— +Net Exploratory Well Drilling Activity +Year Ended December 31, +2018 +2017 +2016 +Operating Region/Area +Productive +In-Process +Non-Productive +Productive +In-Process +Non-Productive +Productive +In-Process +Non-Productive +Wattenberg Field, operated wells +— +— +— +— +— +— +— +— +— +Wattenberg Field, non-operated wells +— +— +— +— +— +— +— +— +— +Delaware Basin +2.8 +2.0 +— +3.1 +2.8 +2.0 +— +— +— +Total gross development wells +2.8 +2.0 +— +3.1 +2.8 +2.0 +— +— +— +Title to Properties +We believe that we hold good and defensible leasehold title to substantially all of our crude oil and natural gas properties, in accordance with standards generally accepted in the industry. A preliminary title examination is typically conducted at the time the undeveloped properties are acquired. Prior to the commencement of drilling operations, a title examination is conducted and remedial curative work is performed, as necessary, with respect to discovered defects which we deem to be significant, in order to procure division order title opinions. Title examinations have been performed with respect to substantially all of our producing properties. +The properties we own are subject to royalty, overriding royalty and other outstanding interests. The properties may also be subject to additional burdens, liens or encumbrances customary in the industry, including items such as operating agreements, current taxes, development obligations under crude oil and natural gas leases, farm-out agreements and other restrictions. We do not believe that any of these burdens will materially interfere with our use of the properties. +Substantially all of our crude oil and natural gas properties, excluding our share of properties held by the limited partnerships that we sponsor, have been mortgaged or pledged as security for our revolving credit facility. +Facilities +We lease 109,000 square feet of office space in Denver, Colorado, which serves as our corporate office, through February 2023. We own a 32,000 square foot administrative office building located in Bridgeport, West Virginia. +We also lease field operating facilities in or near Evans, Colorado, and Midland, Texas. +Governmental Regulation +The U.S. crude oil and natural gas industry is extensively regulated at the federal, state and local levels. The following is a summary of certain laws, rules and regulations currently in force that apply to us. The regulatory environment in which we operate changes frequently and we cannot predict the timing or nature of such changes or their effects on us. +Regulation of Crude Oil and Natural Gas Exploration and Production. Our exploration and production activities are subject to a variety of rules and regulations concerning drilling permits, location, spacing and density of wells, water discharge +12 +and disposal, prevention of waste, bonding requirements, surface use and restoration and well plugging and abandonment. The primary state-level regulatory authority regarding these matters is the Colorado Oil and Gas Conservation Commission (the “COGCC”) in Colorado and the Texas Railroad Commission in Texas. For example, prior to preparing a surface location and commencing drilling operations on a well, we must procure permits and/or approvals for the various stages of the drilling process from the relevant state and local agencies. Similarly, our operations must comply with rules governing the size of drilling and spacing units or proration units and the unitization or pooling of lands and leases. Some states, such as Colorado, allow the forced pooling or integration of tracts to facilitate exploration while other states, such as Texas, rely primarily or exclusively on voluntary pooling of lands and leases. +In states such as Texas, where pooling is primarily or exclusively voluntary, it may be more difficult to form units and therefore to drill and develop our leases in circumstances where we do not own all of the leases in the proposed unit. State laws may also prohibit the venting or flaring of natural gas, which may impact rates of production of crude oil and natural gas from our wells. Leases covering state or federal lands often include additional laws, regulations and conditions which can limit the location, timing and number of wells we can drill and impose other requirements on our operations, all of which can increase our costs. +Regulation of Transportation of Commodities. We move natural gas through pipelines owned by other entities and sell natural gas to other entities that also utilize common carrier pipeline facilities. Natural gas pipeline interstate transmission and storage activities are subject to regulation by the Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act of 1938 ("NGA") and under the Natural Gas Policy Act of 1978 ("NGPA"). Rates and charges for the transportation of natural gas in interstate commerce, and the extension, enlargement or abandonment of jurisdictional facilities, among other things, are subject to regulation. Natural gas pipeline companies hold certificates of public convenience and necessity issued by FERC authorizing ownership and operation of certain pipelines, facilities and properties. +In addition to regulation of natural gas pipeline interstate transmission and storage activities, under the Energy Policy Act of 2005 (the “EPAct 2005”), it is unlawful for “any entity” to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of gas or the purchase or sale of transportation services subject to regulation by FERC. The EPAct 2005 provides FERC with substantial enforcement authority to prohibit such manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. +In December 2007, FERC issued Order 704 (as amended by subsequent orders on rehearing, “Order 704”), which requires that any market participant, including natural gas producers, gatherers and marketers, that engaged in wholesale sales or purchases of natural gas that equaled or exceeded 2.2 MMBtus of physical natural gas in the previous calendar year to report to FERC the aggregate volumes of natural gas produced or sold at wholesale in such calendar year. Order 704 applies only to those transactions that utilize, contribute to or may contribute to the formation of price indices. It is the responsibility of the market participant to determine which individual transactions are to be reported under the guidance of Order 704. Additional information that must be reported includes whether the price in the relevant transaction was reported to any index publisher, and if so, whether such reporting complied with FERC’s policy statement on price reporting. To the extent that we engage in wholesale sales or purchases of natural gas that equal or exceed 2.2 MMBtus of physical natural gas in the a calendar year pursuant to transactions utilizing, contributing or having the potential to contribute to the formation of price indices, we may be subject to the reporting requirements of Order 704. +Gathering is exempt from regulation under the NGA, thus allowing gatherers to charge negotiated rates. Gathering lines are, however, subject to state regulation, which includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and rate regulation on a complaint basis. We own certain pipeline facilities in the Delaware Basin that we believe are exempt from regulation under the NGA as “gathering facilities,” but which may in some cases be subject to state regulation. +Although FERC has set forth a general test to determine whether facilities are exempt from regulation under the NGA as “gathering” facilities, FERC’s determinations as to the classification of facilities are performed on a case-by-case basis. With respect to facilities owned by third parties and on which we move natural gas, to the extent that FERC subsequently issues an order reclassifying facilities previously thought to be subject to FERC jurisdiction as non-jurisdictional gathering facilities, and depending on the scope of that decision, our costs of moving natural gas to the point of sale may be increased. Further, to the extent that FERC issues an order reclassifying facilities that we own that were previously thought to be non-jurisdictional gathering facilities as subject to FERC jurisdiction, we could be subject to additional regulatory requirements under the NGA and the NGPA. +Transportation and safety of natural gas is also subject to regulation by the U.S. Department of Transportation, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), under the Natural Gas Pipeline Safety Act of 1968, as +13 +amended, which imposes safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities, the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (the “PIPES Act 2006”), and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (the “PIPES Act 2011”). We own certain pipeline facilities in the Delaware Basin that are subject to such regulation by PHMSA. +In addition to natural gas, we move crude oil, condensate and natural gas liquids (collectively, “liquids”) through pipelines owned by other entities and sell such liquids to other entities that also utilize pipeline facilities that may be subject to regulation by FERC. FERC regulates the rates and terms and conditions of service for the interstate transportation of liquids under the Interstate Commerce Act, as it existed on October 1, 1977 (the “ICA”), and the rules and regulations promulgated thereunder. This includes movements of liquids through any pipelines, including those located solely within one state, that are providing part of the continuous movement of such liquids in interstate commerce for a shipper. The ICA requires that pipelines providing jurisdictional movements maintain a tariff on file with FERC, setting forth established rates and the rules and regulations governing transportation service, which must be “just and reasonable.” The ICA also requires that services be provided in a manner that is not unduly discriminatory or unduly preferential; in some cases, this may result in the proration of capacity among shippers in an equitable manner. +The intrastate transportation of crude oil and NGLs is subject to regulation by state regulatory commissions, which in some cases require the provision of intrastate transportation on a nondiscriminatory basis and the prorationing of capacity on such pipelines under policies set forth in published tariffs. These state-level regulations may also impose certain limitations on the rates that the pipeline owner may charge for transportation. +Transportation and safety of liquids by pipeline is subject to regulation by PHMSA pursuant to the Hazardous Liquids Pipeline Safety Act of 1979, as well as the PIPES Act 2006 and the PIPES Act 2011, which govern the design, installation, testing, construction, operation, replacement and management of liquids pipeline facilities. Liquids that are transported by rail may also be subject to additional regulation by PHMSA. +The availability, terms and cost of transportation affect the amounts we receive for our commodities. Historically, producers were able to flow supplies into interstate pipelines on an interruptible basis; however, recently we have seen the increased need to acquire firm transportation on pipelines in order to avoid curtailments or shut-in gas, which could adversely affect cash flows from the affected area. +Environmental Matters +Our operations are subject to numerous laws and regulations relating to environmental protection. These laws and regulations change frequently, and the effect of these changes is often to impose additional costs or other restrictions on our operations. We cannot predict the occurrence, timing, nature or effect of these changes. +Hazardous Substances and Wastes +We generate wastes that may be subject to the Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. The U.S. Environmental Protection Agency (“EPA”) and various state agencies have adopted requirements that limit the approved disposal methods for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by our operations that are currently exempt from treatment as “hazardous wastes” may in the future be designated as hazardous wastes, and therefore may subject us to more rigorous and costly operating and disposal requirements. In December 2016, the U.S. District Court for the District of Columbia approved a consent decree between the EPA and a coalition of environmental groups. The consent decree requires the EPA to review and determine whether it will revise the RCRA regulations for exploration and production waste to treat such waste as hazardous waste. The EPA must complete its review and make its decision regarding revision by March 2019. If the EPA chooses to revise the applicable RCRA regulations, it must sign a notice taking final action related to the new regulation by July 2021. +We currently own or lease numerous properties that have been used for the exploration and production of crude oil and natural gas for many years. If hydrocarbons or other wastes have been disposed of or released on or under the properties that we own or lease or on or under locations where such wastes have been taken for disposal by us or prior owners or operators of such properties, we could be subject to liability under the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), RCRA and analogous state laws, as well as state laws governing the management of crude oil and natural gas wastes. CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of, transported or arranged for the disposal of the hazardous substances found at the site. Individuals who are or +14 +were responsible for release of hazardous substances under CERCLA may be subject to full liability for the costs of cleaning up the hazardous substances that have been released into the environment or remediation to prevent future contamination and for damages to natural resources. Under state laws, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. +Hydraulic Fracturing +Hydraulic fracturing is commonly used to stimulate production of crude oil and/or natural gas from dense subsurface rock formations. We consistently utilize hydraulic fracturing in our crude oil and natural gas development programs. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations which are held open by the grains of sand, enabling the crude oil or natural gas to more easily flow to the wellbore. The process is generally subject to regulation by state oil and gas commissions, but is also the subject of various other regulatory initiatives at the federal, state and local levels. +Federal Regulation +Beginning in 2012, the EPA implemented Clean Air Act (“CAA”) standards (New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants) applicable to hydraulically fractured natural gas wells and certain storage vessels. The standards require, among other things, use of reduced emission completions, or “green” completions, to reduce volatile organic compound emissions during well completions as well as new controls applicable to a wide variety of storage tanks and other equipment, including compressors, controllers and dehydrators. +In February 2014, the EPA issued permitting guidance under the Safe Drinking Water Act ("SDWA") for the underground injection of liquids from hydraulically fractured and other wells where diesel is used. Depending upon how it is implemented, this guidance may create duplicative requirements in certain areas, further slow the permitting process in certain areas, increase the costs of operations and result in expanded regulation of hydraulic fracturing activities by the EPA, and may therefore adversely affect even companies, such as us, that do not use diesel fuel in hydraulic fracturing activities. +In May 2014, the EPA issued an advance notice of proposed rulemaking under the Toxic Substances Control Act pursuant to which it will collect extensive information on the chemicals used in hydraulic fracturing fluid, as well as other health-related data, from chemical manufacturers and processors. +The U.S. Department of the Interior, through the Bureau of Land Management (the “BLM”), finalized a rule in 2015 requiring the disclosure of chemicals used, mandating well integrity measures and imposing other requirements relating to hydraulic fracturing on federal lands. The BLM rescinded the rule in December 2017; however, the BLM’s rescission of the rule has been challenged in the United States District Court for the Northern District of California. +In June 2016, the EPA finalized pretreatment standards for indirect discharges of wastewater from the oil and gas extraction industry. The regulation prohibits sending wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned treatment works. +In December 2016, the EPA released a report titled “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources.” The report concluded that activities involved in hydraulic fracturing can have impacts on drinking water under certain circumstances. These and similar studies, depending on their degree of development and nature of results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. +In November 2018, the EPA and the non-profit organization known as the State Review of Oil and Natural Gas Environmental Regulations (“STRONGER”) entered into a Memorandum of Understanding pursuant to which the EPA has affirmed its commitment to meaningful participation in STRONGER’s efforts to develop guidelines for state oil and natural gas environmental regulatory programs, conduct reviews of such programs and publish reports of those reviews. +15 +State Regulation +The states in which we currently operate have adopted or are considering adopting laws and regulations that impose or could impose, among other requirements, stringent permitting or air emission control, chemical disclosure, wastewater disposal, baseline sampling, seismic monitoring, well monitoring and materials handling requirements on hydraulic fracturing and/or well construction and well location requirements and more stringent notification or consultation processes that relate to hydraulic fracturing. Similarly, some states, including Texas, have implemented rules requiring the submission of detailed information related to seismicity in connection with injection well permit applications for the disposal of wastewater. +Colorado and Texas require that chemicals used in the hydraulic fracturing of a well be reported in a publicly searchable registry website developed and maintained by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission. +Concerns about hydraulic fracturing have contributed to support for ballot initiatives in Colorado that would dramatically limit the areas of the state in which drilling would be permitted to occur. See Item 1A. Risk Factors-Risks Relating to Our Business and the Industry-Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us. +Local Regulation +Various local and municipal bodies in each of the states in which we operate have sought to impose prohibitions, moratoria and other restrictions on hydraulic fracturing activities. In Colorado, the Colorado Supreme Court ruled in 2016 that the cities of Fort Collins and Longmont did not have the authority to prohibit or impose five-year moratoria on hydraulic fracturing. Ballot initiatives and legislation have previously been proposed but not enacted in Colorado that would vest local governmental authorities with greater control over oil and gas development. If similar proposals are enacted in the future, they could conceivably undo the Colorado Supreme Court’s 2016 rulings and enable local authorities to implement hydraulic fracturing bans or other restrictions. We primarily operate in the rural areas of the core Wattenberg Field in Weld County. In Texas, legislation enacted in 2015 generally prohibits political subdivisions from banning, limiting or otherwise regulating oil and gas operations. See Item 1A. Risk Factors-Risks Relating to Our Business and the Industry-Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us. +Private Lawsuits +Lawsuits have been filed against other operators in several states, including Colorado, alleging contamination of drinking water as a result of hydraulic fracturing activities. +Greenhouse Gases +In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because such emissions are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings provide the basis for the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. In June 2010, the EPA began regulating GHG emissions from stationary sources. +In the past, Congress has considered proposed legislation to reduce emissions of GHGs. To date, Congress has not adopted any such significant legislation, but could do so in the future. In addition, many states and regions have taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. In February 2014 and November 2017, Colorado adopted rules regulating methane emissions from the oil and gas sector. +The Obama administration reached an agreement during the December 2015 United Nations climate change conference in Paris pursuant to which the U.S. initially pledged to make a 26 to 28 percent reduction in its GHG emissions by 2025 against a 2005 baseline and committed to periodically update this pledge every five years starting in 2020 (the "Paris Agreement"). In June 2017, President Trump announced that the U.S. would initiate the formal process to withdraw from the Paris Agreement. +Regulation of methane and other GHG emissions associated with oil and natural gas production could impose significant requirements and costs on our operations. +16 +Air Quality +Our operations are subject to the CAA and comparable state and local requirements. The CAA contains provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and state governments continue to develop regulations to implement these requirements. We may be required to incur certain capital investments in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. See the footnote titled Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere in this report for further information regarding the Clean Air Act Section 114 Information Request that we received from the EPA. +In June 2016, the EPA implemented new requirements focused on achieving additional methane and volatile organic compound reductions from the oil and natural gas industry. The rules imposed, among other things, new requirements for leak detection and repair, control requirements for oil well completions, replacement of certain pneumatic pumps and controllers and additional control requirements for gathering, boosting and compressor stations. In September 2018, the EPA proposed revisions to the 2016 rules. The proposed amendments address certain technical issues raised in administrative petitions and include proposed changes to, among other things, the frequency of monitoring for fugitive emissions at well sites and compressor stations. Also in 2016, the EPA issued guidelines for reducing volatile organic compound emissions from existing oil and natural gas equipment and processes in ozone non-attainment areas, including the Denver Metro North Front Range Ozone 8-Hour Non-Attainment (“Denver Metro/North Front Range NAA”) area discussed below. +In November 2016, the BLM finalized rules to further regulate venting, flaring and leaks during oil and natural gas production activities on onshore federal and Indian leases. The rules require additional controls and impose new emissions and other standards on certain operations on applicable leases, including committed state or private tracts in a federally approved unit or communitized agreement that drains federal minerals. In September 2018, the BLM published a final rule that revises the 2016 rules. The new rule, among other things, rescinds the 2016 rule requirements related to waste-minimization plans, gas-capture percentages, well drilling, well completion and related operations, pneumatic controllers, pneumatic diaphragm pumps, storage vessels and leak detection and repair. The new rule also revised provisions related to venting and flaring. Environmental groups and the States of California and New Mexico have filed challenges to the 2018 rule in the United States District Court for the Northern District of California. +In 2016, the EPA increased the state of Colorado’s non-attainment ozone classification for the Denver Metro/North Front Range NAA area from “marginal” to “moderate” under the 2008 national ambient air quality standards (“NAAQS”). This increase in non-attainment status triggered significant additional obligations for the state under the CAA and resulted in Colorado adopting new and more stringent air quality control requirements in November 2017 that are applicable to our operations. Ozone measurements in the Denver Metro/North Front Range NAA exceeded the NAAQS during 2018, subjecting it to a further reclassification to “serious.” While the Colorado Department of Public Health and Environment (“CDPHE”) may request an exception or other relief from the reclassification, it appears very likely that the Denver Metro/North Front Range NAA will be reclassified as “serious” by early 2020. A “serious” classification will trigger significant additional obligations for the state under the CAA and could result in new and more stringent air quality control requirements, which may in turn result in significant costs and delays in obtaining necessary permits applicable to our operations. +State-level rules applicable to our operations include regulations imposed by the CDPHE's Air Quality Control Commission, including stringent requirements relating to monitoring, recordkeeping and reporting matters. +Water Quality +The federal Clean Water Act (“CWA”) and analogous state laws impose strict controls concerning the discharge of pollutants and fill material, including spills and leaks of crude oil and other substances. The CWA also requires approval and/or permits prior to construction, where construction will disturb wetlands or other waters of the U.S. In June 2015, the EPA and the Army Corps of Engineers (the “Corps”) issued a new rule known as the Clean Water Rule clarifying the scope of the EPA’s and the Corps’ jurisdiction under the Clean Water Act with respect to certain types of waterbodies and classifying these waterbodies as regulated. In February 2018, the EPA issued a rule that delays the applicability of the new definition of the waters of the U.S. until 2020. In August 2018, the U.S. District Court for South Carolina found that the EPA and the Corps failed to comply with the Administrative Procedure Act and struck the 2018 rule that attempted to delay the applicability date of the 2015 Clean Water Rule. Other district courts, however, have issued rulings temporarily enjoining the applicability of the 2015 Clean Water Rule itself. Taken together, the 2015 Clean Water Rule is currently in effect in 23 states, and temporarily stayed in the remaining states, including Colorado and Texas. In those remaining states, the 1986 rule and guidance remain in effect. In December 2018, the EPA and the Corps issued a proposed new rule that would differently revise the definition of +17 +“waters of the United States” and essentially replace both the 1986 rule and the 2015 Clean Water Rule. According to the agencies, the proposed new rule is “intended to increase CWA program predictability and consistency by increasing clarity as to the scope of ‘waters of the United States’ federally regulated under the Act.” If finalized, this new definition of “waters of the United States” will likely be challenged and sought to be enjoined in federal court. +In January 2017, the Corps issued revised and renewed streamlined general nationwide permits that are available to satisfy permitting requirements for certain work in streams, wetlands and other waters of the U.S. under Section 404 of the CWA and the Rivers and Harbors Act. The new nationwide permits took effect in March 2017, or when certified by each state, whichever was later. The oil and gas industry broadly utilizes nationwide permits 12, 14 and 39 for the construction, maintenance and repairs of pipelines, roads and drill pads, respectively, and related structures in waters of the U.S. that impact less than a half-acre of waters of the U.S. and meet the other criteria of each nationwide permit. +The CWA also regulates storm water run-off from crude oil and natural gas facilities and requires storm water discharge permits for certain activities. Spill Prevention, Control and Countermeasure (“SPCC”) requirements of the CWA require appropriate secondary containment load out controls, piping controls, berms and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture or leak. +Endangered Species +The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and bald and golden eagles under the Bald and Golden Eagle Protection Act. Some of our operations may be located in areas that are or may be designated as habitats for endangered or threatened species or that may attract migratory birds, bald eagles or golden eagles. +Safety and Spill Prevention +In October 2015, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration proposed to expand its regulations in a number of ways, including increased regulation of gathering lines, even in rural areas, and proposed additional standards to revise safety regulations applicable to onshore gas transmission and gathering pipelines in 2016. +Crude oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of crude oil spills. In addition to SPCC requirements, the Oil Pollution Act of 1990 (“OPA”) subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from crude oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Historically, we have not experienced any significant crude oil discharge or crude oil spill problems. +In May 2015, the U.S. Department of Transportation issued a final rule regarding the safe transportation of flammable liquids by rail. The final rule imposes certain requirements on “offerors” of crude oil, including sampling, testing and certification requirements. +In February 2018, the COGCC comprehensively amended its regulations for oil, gas, and water flowlines to expand requirements addressing flowline registration and safety, integrity management, leak detection, and other matters. The COGCC has also adopted or amended numerous other rules in recent years, including rules relating to safety, flood protection and spill reporting. +We are also subject to rules regarding worker safety and similar matters promulgated by the U.S. Occupational Safety and Health Administration (“OSHA”) and other governmental authorities. OSHA has established workplace safety standards that provide guidelines for maintaining a safe workplace in light of potential hazards, such as employee exposure to hazardous substances. To this end, OSHA adopted a new rule governing employee exposure to silica, including during hydraulic fracturing activities, in March 2016. +Employees +As of December 31, 2018 , we had approximately 600 full-time employees. Our employees are not covered by collective bargaining agreements. We consider relations with our employees to be good. +18 +WHERE YOU CAN FIND ADDITIONAL INFORMATION +We file annual, quarterly and current reports, proxy statements and other information with the SEC. Our SEC filings are available free of charge from our website at www.pdce.com as soon as reasonably practicable after such material is filed with, or furnished to, the SEC. We also make available free of charge any of our SEC filings by mail. For a mailed copy of a report, please contact PDC Energy, Inc., Investor Relations, 1775 Sherman Street, Suite 3000, Denver, CO 80203, or call (303) 860-5800. +We recommend that you view our website for additional information, as we routinely post information that we believe is important for investors. Our website can be used to access such information as our recent news releases, committee charters, code of business conduct and ethics, stockholder communication policy, director nomination procedures and our whistle blower hotline. While we recommend that you view our website, the information available on our website is not part of this report and is not incorporated by reference. +19 +ITEM 1A. RISK FACTORS +You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock or other securities. +Risks Relating to Our Business and the Industry +Crude oil, natural gas and NGL prices fluctuate and declines in these prices, or an extended period of low prices, can significantly affect the value of our assets and our financial results and may impede our growth. +Our revenue, profitability, cash flows and liquidity depend in large part upon the prices we receive for our crude oil, natural gas and NGLs. Changes in prices affect many aspects of our business, including: +• +our revenue, profitability and cash flows; +• +our liquidity; +• +the quantity and present value of our reserves; +• +the borrowing base under our revolving credit facility and access to other sources of capital; and +• +the nature and scale of our operations. +The markets for crude oil, natural gas and NGLs are often volatile, and prices may fluctuate in response to, among other things: +• +relatively minor changes in regional, national or global supply and demand; +• +regional, national or global economic conditions, and perceived trends in those conditions; +• +geopolitical factors, such as events that may reduce or increase production from particular oil-producing regions and/or from members of the Organization of Petroleum Exporting Countries ("OPEC"); and +• +regulatory changes. +The price of oil has been volatile since mid-2014, with a high over $100 per barrel in June 2014 to lows below $30 per barrel in 2016, in each case based on WTI prices, due to a combination of factors including increased U.S. supply and global economic concerns. In 2018, oil prices ranged from highs of over $70 per barrel to lows of less than $50 per barrel. Prices for natural gas and NGLs have also experienced substantial volatility. If we reduce our capital expenditures due to low prices, natural declines in production from our wells will likely result in reduced production and therefore reduced cash flow from operations, which would in turn further limit our ability to make the capital expenditures necessary to replace our reserves and production. +In addition to factors affecting the price of crude oil, natural gas and NGLs generally, the prices we receive for our production are affected by factors specific to us and to the local markets where the production occurs. The prices that we receive for our production are generally lower than the relevant benchmark prices that are used for calculating commodity derivative positions. These differences, or differentials, are difficult to predict and may widen or narrow in the future based on market forces. Differentials can be influenced by, among other things, local or regional supply and demand factors and the terms of our sales contracts. Over the longer term, differentials will be significantly affected by factors such as investment decisions made by providers of midstream facilities and services, refineries and other industry participants and the overall regulatory and economic climate. For example, increases in U.S. domestic oil production generally, or in production from particular basins, may result in widening differentials. We may be materially and adversely impacted by widening differentials on our production and decreasing commodity prices. +The marketability of our production is dependent upon transportation and processing facilities, the capacity and operation of which we do not control. Market conditions or operational impediments affecting midstream facilities and services could hinder our access to crude oil, natural gas and NGL markets, increase our costs or delay production. Our efforts to address midstream issues may not be successful. +Our ability to market our production depends in substantial part on the availability, proximity and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. If adequate midstream facilities and services are not available to us on a timely basis and at acceptable costs, our production and results of operations will be adversely affected. For example, in recent periods, due to ongoing drilling activities by us and third parties and seasonal changes in temperatures, our principal third-party provider in the Wattenberg Field for midstream facilities and services has experienced significantly increased gathering system pressures. The resulting capacity constraints have restricted our production in the area and reduced our revenue. Similarly, rapid production growth in the Permian Basin has strained the +20 +available midstream infrastructure there with adverse effects on our operations. The use of alternative forms of transportation for oil production, such as trucks or rail, involves risks, including the risk that increased regulation could lead to increased costs or shortages of trucks or rail-cars. In addition to causing production curtailments, capacity constraints can also reduce the price we receive for the crude oil, natural gas and NGLs we produce. +We rely on third parties to continue to construct additional midstream facilities and related infrastructure to accommodate our growth, and the ability and willingness of those parties to do so is subject to a variety of risks. For example: +• +Decreases in commodity prices in recent years have resulted in reduced investment in midstream facilities by some third parties; +• +Various interest groups have protested the construction of new pipelines, and particularly pipelines near water bodies, in various places throughout the country, and protests have at times physically interrupted pipeline construction activities; +• +Some upstream energy companies have sought to reject volume commitment agreements with midstream providers in bankruptcy proceedings, and the risk that such efforts will succeed, or that upstream energy company counterparties will otherwise be unable or unwilling to satisfy their volume commitments, may have the effect of reducing investment in midstream infrastructure; and +• +The possibility that new or amended regulations, including regulations that increase mandatory setbacks or enhance local control of oil and gas development, could result in severely curtailed drilling activities in Colorado may discourage investment in midstream facilities. +Like other producers, we from time to time enter into volume commitments with midstream providers in order to induce them to provide increased capacity. If our production falls below the level required under these agreements, we could be subject to substantial penalties. We are currently not producing sufficient volumes to satisfy a volume commitment in the Delaware Basin; although at current commodity prices we have been able to profitably satisfy our obligations under the agreement with volumes purchased from third parties, this may not continue to be the case. +We have pursued a variety of strategies to alleviate some of the risks associated with the midstream services and facilities upon which we rely, including entering into facility expansion agreements with our primary midstream provider in the Wattenberg Field in 2017 and 2018. There can be no assurance that the strategies we pursue will be successful or adequate to meet our needs. For example, while we expect the midstream provider to commence operation of a new facility in the second quarter of 2019, it is not obligated to do so and it may delay or cancel the project entirely. In addition, the benefits to us of that facility may be less than we expect. +Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us. +The regulatory environment in which we operate changes frequently, often through the imposition of new or more stringent environmental and other requirements. We cannot predict the nature, timing or effect of such additional requirements, but they may have a variety of adverse effects on us. The types of regulatory changes that could impact our operations vary widely and include, but are not limited to, the following: +• +From time to time ballot initiatives have been proposed in Colorado that would adversely affect our operations. For example, Proposition 112, which was included on the ballot for the November 2018 election in Colorado but was defeated at the polls, would have amended the Colorado Oil and Gas Conservation Act to, among other things, require all new oil and gas development not on federal land to be located at least 2,500 feet away from any occupied structure or broadly defined “vulnerable area”. If enacted, Proposition 112 would have effectively prohibited the vast majority of our planned future drilling activities in Colorado and would therefore have made it impossible to pursue our current development plans. Despite the defeat of Proposition 112, it is likely that similar proposals to increase setbacks, or other proposals to enhance local control of oil and gas development or otherwise restrict our ability to operate or increase our costs, will be made in future years, either by ballot initiative or by legislation. Similar proposals may also be made in other states. +• +Substantially all of our drilling activities involve the use of hydraulic fracturing, and proposals are made from time to time at the federal, state and local levels to further regulate, or to ban, hydraulic fracturing practices. Additional laws or regulations regarding hydraulic fracturing could, among other things, increase our costs, reduce our inventory of economically viable drilling locations and reduce our reserves. +• +Federal and various state, local and regional governmental authorities have implemented, or considered implementing, regulations that seek to limit or discourage the emission of carbon, methane and other greenhouse gases ("GHGs"). For example, the EPA has made findings and issued regulations that require us to establish and +21 +report an inventory of greenhouse gas emissions, and the state of Colorado has adopted rules regulating methane emissions from oil and gas operations. In addition, the Obama administration reached an agreement during the December 2015 United Nations climate change conference in Paris pursuant to which the U.S. initially pledged to make a 26 percent to 28 percent reduction in its GHG emissions by 2025 against a 2005 baseline (although President Trump subsequently announced that the U.S. is withdrawing from the Paris Agreement). Additional laws or regulations intended to restrict the emission of GHGs could require us to incur additional operating costs and could adversely affect demand for the oil, natural gas and NGLs that we sell. These new laws or rules could, among other things, require us to install new emission controls on our equipment and facilities, acquire allowances to authorize our GHG emissions, pay taxes related to our emissions and administer and manage a GHG emissions program. In addition, like other energy companies, we could be named as a defendant in GHG-related lawsuits. +• +Proposals are made from time to time to amend U.S. federal and state tax laws in ways that would be adverse to us, including by eliminating certain key U.S. federal income tax preferences currently available with respect to crude oil and natural gas exploration and production. The changes could include (i) the repeal of the percentage depletion deduction for crude oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Also, state severance taxes may increase in the states in which we operate. This could adversely affect our existing operations in the relevant state and the economic viability of future drilling. +• +The development of new environmental initiatives or regulations related to the acquisition, withdrawal, storage and use of surface water or groundwater or treatment and discharge of water waste, may limit our ability to use techniques such as hydraulic fracturing, increase our development and operating costs and cause delays, interruptions or termination of our operations, any of which could have an adverse effect on our operations and financial condition. +See Items 1 and 2, Business and Properties - Governmental Regulation for a summary of certain laws and regulations that currently apply to us. Any of such laws and regulations could be amended, and new laws or regulations could be implemented, in a way that adversely affects our operations. +Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in substantial lease renewal costs or, if renewal is not feasible, loss of our lease and prospective drilling opportunities. +Unless production is established within the spacing units covering our undeveloped acreage, our leases for such acreage will expire. The cost to renew such leases may increase significantly and we may not be able to renew such leases on commercially reasonable terms or at all. In 2019, we expect that we will allow 35 percent of our net leaseholds in the Delaware Basin to expire based on our current drilling plan, and we incurred an impairment charge in the fourth quarter of 2018 relating to these anticipated expirations. Unexpected lease expirations could also occur if our actual drilling activities differ materially from our current expectations, and this could result in further impairment charges. The risk of lease expiration is greater at times and in areas where the pace of our exploration and development activity slows. Our ability to drill and develop the locations necessary to maintain our leases depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. +A substantial part of our crude oil, natural gas and NGLs production is located in the Wattenberg Field, making us vulnerable to risks associated with operating primarily in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing formations. +Although we have significant leasehold positions in the Delaware Basin in Texas, our current production is primarily located in the Wattenberg Field in Colorado. Because our production is not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including: +• +fluctuations in prices of crude oil, natural gas and NGLs produced from the wells in the area; +• +natural disasters such as the flooding that occurred in northern Colorado in September 2013; +• +restrictive governmental regulations; and +• +curtailment of production or interruption in the availability of gathering, processing or transportation infrastructure and services and any resulting delays or interruptions of production from existing or planned new wells. +22 +For example, bottlenecks in processing and transportation that have occurred in some recent periods in the Wattenberg Field have negatively affected our results of operations, and these adverse effects may be disproportionately severe to us compared to our more geographically diverse competitors. Similarly, the concentration of our producing assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules that could adversely affect development activities or production relating to those formations. Such an event could have a material adverse effect on our results of operations and financial condition. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the Wattenberg Field and the Delaware Basin, the demand for, and cost of, drilling rigs, equipment, supplies, chemicals, personnel and oilfield services often increase as well. Shortages or the high cost of drilling rigs, equipment, supplies, chemicals, personnel or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital forecast, which could have a material adverse effect on our business, financial condition or results of operations. +Certain of our properties are subject to land use restrictions, which could limit the manner in which we conduct our business. +Certain of our properties are subject to land use restrictions, including city ordinances, which could limit the manner in which we conduct our business. Such restrictions could affect, among other things, our access to and the permissible uses of our facilities as well as the manner in which we produce oil and natural gas, and may restrict or prohibit drilling in general. The costs we incur to comply with such restrictions may be significant, and we may experience delays or curtailment in the pursuit of development activities and may be precluded from drilling wells in some areas. +We may incur losses as a result of title defects in the properties in which we invest or acquire. +It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform record title examinations before we acquire oil and gas leases and related interests. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property. +We are subject to complex federal, state, local and other laws and regulations that adversely affect the cost and manner of doing business. +Our exploration, development, production and marketing operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning crude oil and natural gas wells and associated facilities. Under these laws and regulations, we could also be liable for personal injuries, property damage and natural resource or other damages, and could be required to change, suspend or terminate operations. Similar to our competitors, we incur substantial operating and capital costs to comply with such laws and regulations. These costs may put us at a competitive disadvantage compared to larger companies in the industry which can more easily capture economies of scale with respect to compliance. A summary of certain laws and regulations that apply to us is set forth in Items 1 and 2 - Business and Properties - Governmental Regulation . +In June 2017, the U.S. Department of Justice, on behalf of the EPA and the State of Colorado, filed a complaint against us, claiming that we failed to operate and maintain certain condensate collection equipment at 65 facilities so as to minimize leakage of volatile organic compounds in compliance with applicable law. In October 2017, we entered into a consent decree to resolve the lawsuit. Pursuant to the consent decree, we agreed to implement a variety of operational enhancements and mitigation and similar projects, including vapor control system modifications and verification, increased inspection and monitoring and installation of tank pressure monitors. If we materially fail to comply with the requirements of the consent decree with respect to those matters, we could be subject to additional liability. See the footnote titled Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere in this report for further information regarding this litigation. +A major risk inherent in our drilling plans is the possibility that we will be unable to obtain needed drilling permits from relevant governmental authorities in a timely manner. Our ability to obtain the permits needed to pursue our development plans may be impacted by a variety of factors, including opposition by landowners or interest groups. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well or the receipt of a permit with unreasonable or unexpected conditions or costs could have a material adverse effect on our ability to explore or develop our properties. +23 +Our ability to produce crude oil, natural gas and NGLs economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of or recycle the water we use at a reasonable cost, in a timely manner and within applicable environmental rules. +Drilling and development activities such as hydraulic fracturing require the use of water and result in the production of wastewater. Our operations could be adversely impacted if we are unable to locate sufficient amounts of water or dispose of or recycle water used in our exploration and production operations. The quantity of water required in certain completion operations, such as hydraulic fracturing, and changing regulations governing usage may lead to water constraints, supply concerns and regulatory issues, particularly in relatively arid climates such as eastern Colorado and western Texas. For example, increased drilling activity in the Delaware Basin in recent years has led to heightened concerns about water supply issues in the area and this may lead to regulatory actions, including rules providing local governments greater authority over water use, that adversely impact our operations. +Our operations depend on being able to reuse or dispose of wastewater in a timely and economic fashion. Wastewater from oil and gas operations is often disposed of through underground injection. Wells in the Delaware Basin typically produce relatively large amounts of water that require disposal and an increased number of earthquakes have been detected in the Delaware Basin in recent years. Some studies have linked earthquakes, or induced seismicity, in certain areas to underground injection, which is leading to increased public and regulatory scrutiny of injection safety. +Reduced commodity prices could result in significant impairment charges and significant downward revisions of proved reserves. +Commodity prices are volatile. Significant and rapid declines in prices have occurred in the past and may occur in the future. Low commodity prices could result in, among other things, significant impairment charges. The cash flow model we use to assess properties for impairment includes numerous assumptions, such as management’s estimates of future oil and gas production and commodity prices, the outlook for forward commodity prices and operating and development costs. All inputs to the cash flow model must be evaluated at each date the estimate of future cash flows for each producing basin is calculated. However, a significant decrease in long-term forward prices alone could result in a significant impairment for our properties that are sensitive to declines in prices. We have incurred impairment charges in a number of recent periods, including charges of $458.4 million and $285.9 million in 2018 and 2017, respectively, to write down assets and $ 75.1 million to impair goodwill associated with our acquisition in the Delaware Basin in 2017. Similar charges could occur in the future. +Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves. +Calculating reserves for crude oil, natural gas and NGLs requires subjective estimates of remaining volumes of underground accumulations of hydrocarbons. Assumptions are also made concerning commodity prices, production levels and operating and development costs over the economic life of the properties. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate. Independent petroleum engineers prepare our estimates of crude oil, natural gas and NGLs reserves using pricing, production, cost, tax and other information that we provide. The reserve estimates are based on assumptions regarding commodity prices, production levels and operating and development costs that may prove to be incorrect. Any significant variance from these assumptions to actual results could greatly affect: +• +the economically recoverable quantities of crude oil, natural gas and NGLs attributable to any particular group of properties; +• +future depreciation, depletion and amortization (“DD&A”) rates and amounts; +• +impairments in the value of our assets; +• +the classifications of reserves based on risk of recovery; +• +estimates of future net cash flows; +• +timing of our capital expenditures; and +• +the amount of funds available for us to borrow under our revolving credit facility. +Some of our reserve estimates must be made with limited production histories, which renders these estimates less reliable than those based on longer production histories. Further, reserve estimates are based on the volumes of crude oil, natural gas and NGLs that are anticipated to be economically recoverable from a given date forward based on economic conditions that exist at that date. The actual quantities of crude oil, natural gas and NGLs recovered will be different than the reserve estimates since they will not be produced under the same economic conditions as are used for the reserve calculations. +24 +In addition, quantities of probable and possible reserves by definition are inherently more risky than proved reserves, in part because they have greater uncertainty associated with the recoverable quantities of hydrocarbons. +At December 31, 2018 , approximately 67 percent of our estimated proved reserves were undeveloped. These reserve estimates reflect our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including approximately $4.4 billion during the five years ending December 31, 2023, as estimated in the calculation of the standardized measure of oil and gas activity. The estimated development costs may not be accurate, development may not occur as scheduled and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of initial booking, and we may therefore be required to downgrade any PUDs that are not developed within this five-year time frame. +The present value of the estimated future net cash flows from our proved reserves is not necessarily the same as the current market value of those reserves. Pursuant to SEC rules, the estimated discounted future net cash flows from our proved reserves, and the estimated quantity of those reserves, are based on the prior year’s first day of the month 12-month average crude oil and natural gas index prices. However, factors such as actual prices we receive for crude oil and natural gas and hedging instruments, the amount and timing of actual production, the amount and timing of future development costs, the supply of and demand for crude oil, natural gas and NGLs and changes in governmental regulations or taxation, also affect our actual future net cash flows from our properties. The timing of both our production and incurrence of expenses in connection with the development and production of crude oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10 percent discount factor we use when calculating discounted future net cash flows (the rate required by the SEC) may not be the most appropriate discount factor based on interest rates currently in effect and risks associated with our properties or the industry in general. +Unless reserves are replaced as they are produced, our reserves and production will decline, which would adversely affect our future business, financial condition and results of operations. We may not be able to develop our identified drilling locations as planned. +Producing crude oil, natural gas and NGL reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline may change over time and may exceed our estimates. Our future reserves and production and, therefore, our cash flows and income, are highly dependent on our ability to efficiently develop and exploit our current reserves and to economically find or acquire additional recoverable reserves. We may not be able to develop, discover, or acquire additional reserves to replace our current and future production at acceptable costs. Our failure to do so would adversely affect our future operations, financial condition and results of operations. +We have identified a number of well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including: +• +crude oil, natural gas and NGL prices; +• +the availability and cost of capital; +• +drilling and production costs; +• +availability of drilling services and equipment; +• +drilling results; +• +lease expirations or limitations as to depth; +• +midstream constraints; +• +access to and availability of water sourcing and distribution systems; +• +regulatory approvals; and +• +other factors. +Because of these factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce crude oil, natural gas or NGLs from these or any other potential well locations. In addition, the number of drilling locations available to us will depend in part on the spacing of wells in our operating areas. An increase in well density in an area could result in additional locations in that area, but a reduced production performance from the area on a per-well basis. Further, certain of the horizontal wells we intend to drill in the future may require pooling of our lease interests with the interests of third parties. Some states, including Colorado, allow the involuntary pooling of tracts in a relatively broad number of circumstances in order to facilitate exploration. Other states, notably Texas, restrict involuntary pooling to a much narrower set of circumstances and consequently these states rely primarily on voluntary pooling of lands and +25 +leases. In states such as Texas where pooling is accomplished primarily on a voluntary basis, it may be more difficult to form units and, therefore, more difficult to fully develop a project if we own less than all the leasehold in the proposed units or one or more of our leases in the proposed units does not provide the necessary pooling authority. If third parties in the proposed units are unwilling to pool their interests with ours, we may be unable to require such pooling on a timely basis or at all, which would limit the total horizontal wells we can drill. Further, the number of available locations will depend in part on the expected lateral lengths of the horizontal wells we drill. Because the intended lateral length of a horizontal well is subject to change for a variety of reasons, our estimated drilling locations will change over time. For this or numerous other reasons, our actual drilling activities may materially differ from those presently identified. +Our inventory of drilling projects includes locations in addition to those that we currently classify as proved, probable and possible. The development of and results from these additional projects are more uncertain than those relating to probable and possible locations, and significantly more uncertain than those relating to proved locations. We have generally accelerated the pace of our development activities in the Wattenberg Field over the past several years, and this has reduced our related inventory of drilling locations. In addition, our Wattenberg Field inventory was further reduced by recent acreage exchange transactions in which we received, among other things, increased working interests in certain locations in exchange for our right to develop other locations. We anticipate that our remaining locations in the field will not, on average, be as productive as economic as many those we have drilled in recent years, due to lower anticipated overall production or higher gas-to-oil ratios. In the Delaware Basin, our inventory is subject to, among other things, lease expiration issues and our continued analysis of geologic issues in certain areas. +The wells we drill may not yield crude oil, natural gas or NGLs in commercially viable quantities and productive wells may be less successful than we expect. +A prospect is a property on which our geologists have identified what they believe, based on available information, to be indications of hydrocarbon-bearing rocks. However, given the limitations of available data and technology, our geologists cannot know conclusively prior to drilling and testing whether crude oil, natural gas or NGLs will be present in sufficient quantities to repay drilling or completion costs and generate a profit. Furthermore, even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques do not enable our geologists to be certain as to the quantity of the hydrocarbons in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures, which may result in a reduction in our returns or losses. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline. If a well is determined to be dry or uneconomic, which can occur even though it contains some crude oil, natural gas or NGLs, it is classified as a dry hole and must be plugged and abandoned in accordance with applicable regulations. This generally results in the loss of the entire cost of drilling and completion to that point, the cost of plugging and lease costs associated with the prospect. Even wells that are completed and placed into production may not produce sufficient crude oil, natural gas and NGLs to be profitable, or they may be less productive and/or profitable than we expected. For example, the data we use to model anticipated results from wells in a particular area may prove to be not representative of actual results from typical wells in the area, and this could result in production that falls short of estimates reflected in our internal business plans and/or guidance, "type curve" or other disclosures we make to the public. This risk is higher for us in certain areas in the Delaware Basin that have relatively complex geological characteristics and correspondingly greater variability in well results. If we drill a dry hole or unprofitable well on a current or future prospect, or if drilling or completion costs increase, the profitability of our operations will decline and the value of our properties will likely be reduced. Exploratory drilling is typically subject to substantially greater risk than development drilling. In addition, initial results from a well are not necessarily indicative of its performance over a longer period. +26 +Drilling for and producing crude oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations. +Drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling can be unprofitable, not only due to dry holes, but also due to curtailments, delays or cancellations as a result of other factors, including: +• +unusual or unexpected geological formations; +• +pressures; +• +fires; +• +floods; +• +loss of well control; +• +loss of drilling fluid circulation; +• +title problems; +• +facility or equipment malfunctions; +• +unexpected operational events; +• +shortages or delays in the delivery of equipment and services; +• +unanticipated environmental liabilities; +• +compliance with environmental and other governmental requirements; and +• +adverse weather conditions. +Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and regulatory penalties. For example, a loss of containment of hydrocarbons during drilling activities could potentially subject us to civil and/or criminal liability and the possibility of substantial costs, including for environmental remediation. We maintain insurance against various losses and liabilities arising from our operations; however, insurance against certain operational risks may not be available or may be prohibitively expensive relative to the perceived risks presented. For example, we may not have coverage with respect to a pollution event if we are unaware of the event while it is occurring and are therefore unable to report the occurrence of the event to our insurance company within the time frame required under our insurance policy. Thus, losses could occur for uninsurable or uninsured risks or for amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance and/or governmental or third party responses to an event could have a material adverse effect on our business activities, financial condition and results of operations. We are currently involved in various remedial and investigatory activities at some of our wells and related sites. +In addition, certain technical risks relating to the drilling of horizontal wells - including those relating to our ability to fracture stimulate the planned number of stages and to successfully run casing the length of the well bore - have increased in recent years because we have increased the average lateral length of the horizontal wells we drill. Longer-lateral wells are also typically more expensive and require more time for preparation. In addition, we have transitioned to the use of multi-well pads instead of single-well sites. The use of multi-well pad drilling increases some operational risks because problems affecting the pad or a single well could adversely affect production from all of the wells on the pad. Pad drilling can also make our overall production, and therefore our revenue and cash flows, more volatile, because production from multiple wells on a pad will typically commence simultaneously. While we believe that we will be better served by using multi-well pads with longer lateral wells, the risk component involved in such drilling will be increased in some respects, with the result that we might find it more difficult to achieve economic success in our drilling program. +The inability of one or more of our customers or other counterparties to meet their obligations may adversely affect our financial results. +Substantially all of our accounts receivable result from our crude oil, natural gas and NGLs sales or joint interest billings to a small number of third parties in the energy industry. This concentration of customers and joint interest owners may affect our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our commodity derivatives expose us to credit risk in the event of nonperformance by counterparties. Nonperformance by our customers or derivative counterparties may adversely affect our financial condition and profitability. We face similar risks with respect to our other counterparties, including the lenders under our revolving credit facility and the providers of our insurance coverage. +Seasonal weather conditions and lease stipulations can adversely affect our operations. +Seasonal weather conditions and lease stipulations designed to prohibit or limit operations during crop-growing seasons and to protect wildlife affect operations in some areas. In certain areas drilling and other activities may be restricted or +27 +prohibited by lease stipulations, or prevented by weather conditions, for significant periods of time. This limits our operations in those areas and can intensify competition during the active months for drilling rigs, equipment, supplies, chemicals, personnel, and oilfield services, which may lead to additional or increased costs or periodic shortages. These constraints, and the resulting high costs or shortages, could delay our operations and materially increase operating and capital costs and therefore adversely affect our profitability. Similarly, extreme temperatures during some recent periods adversely impacted the operation of certain midstream facilities, and therefore our production. Similar events could occur in the future and could negatively impact our results of operations and cash flows. +We have limited control over activities on properties in which we own an interest but we do not operate, which could reduce our production and revenues. +We operate approximately 84 percent of the wells in which we own an interest. If we do not operate a property, we do not have control over normal operating procedures, expenditures or future development of the property. The success and timing of drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise (including safety and environmental compliance) and financial resources, inclusion of other participants in drilling wells and use of technology. The failure of an operator to conduct drilling activities properly, or its breach of the applicable agreements, could reduce production and revenues and adversely affect our profitability. These risks may be heightened during periods of depressed commodity prices as operators may propose activities that we believe to be economically unattractive, leading us to incur non-consent penalties. Our lack of control over non-operated properties also makes it more difficult for us to forecast capital expenditures, production and related matters. +We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects. +We frequently own less than all of the working interest in the oil and gas leases on which we conduct operations. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities, arising from the actions of the other owners. In addition, declines in oil, natural gas and NGL prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, may declare bankruptcy. In the event any of our project partners does not pay its share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover the costs from the partner. This could materially adversely affect our financial position. +We may not be able to keep pace with technological developments in our industry. +Our industry is characterized by rapid and significant technological advancements. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those or other new technologies at substantial cost. In addition, our competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we were unable to use the most advanced technology, our business, financial condition and results of operations could be materially adversely affected. +Competition in our industry is intense, which may adversely affect our ability to succeed. +Our industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce crude oil, natural gas and NGLs, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, larger companies may have a greater ability to continue exploration activities during periods of low commodity prices. Larger competitors may also be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which could adversely affect our competitive position. These factors could adversely affect our operations and our profitability. +28 +Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel. +Our future success depends to a large extent on the services of our key employees. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise. +A failure to complete successful acquisitions would limit our growth. +Because our crude oil and natural gas properties are depleting assets, our future reserves, production volumes and cash flows depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. In addition, we continue to strive to achieve greater efficiencies in our drilling program, and our ability to do so is dependent in part on our ability to complete asset exchanges and other acquisitions that allow us to increase our working interests in particular properties. When attractive opportunities arise, acquiring additional crude oil and natural gas properties, or businesses that own or operate such properties, is a significant component of our strategy. We may not be able to identify attractive acquisition opportunities. If we do identify an appropriate acquisition candidate, we may be unable to negotiate mutually acceptable terms with the seller, finance the acquisition or obtain the necessary regulatory approvals. It may be difficult to agree on the economic terms of a transaction, as a potential seller may be unwilling to accept a price that we believe to be appropriately reflective of prevailing economic conditions. If we are unable to complete suitable acquisitions, it will be more difficult to replace our reserves, and an inability to replace our reserves would have a material adverse effect on our financial condition and results of operations. +Acquisitions of properties are subject to the uncertainties of evaluating recoverable reserves and potential liabilities, including environmental uncertainties. +Acquisitions of producing and undeveloped properties have been an important part of our growth over time. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, development potential, future commodity prices, operating costs, title issues and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we generally perform engineering, environmental, geological and geophysical reviews of the acquired properties that we believe are generally consistent with customary industry practices. However, such reviews are not likely to permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well prior to an acquisition and our ability to evaluate undeveloped acreage is inherently imprecise. Even when we inspect a well, we may not always discover structural, subsurface and environmental problems that may exist or arise. In some cases, our review prior to signing a definitive purchase agreement may be even more limited. In addition, we often acquire acreage without any warranty of title except as to claims made by, through or under the transferor. +When we acquire properties, we will generally have potential exposure to liabilities and costs for environmental and other problems existing on the acquired properties, and these liabilities may exceed our estimates. We may not be entitled to contractual indemnification associated with acquired properties. We often acquire interests in properties on an “as is” basis with no or limited remedies for breaches of representations and warranties. Therefore, we could incur significant unknown liabilities, including environmental liabilities or losses due to title defects, in connection with acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, the acquisition of undeveloped acreage is subject to many inherent risks and we may not be able to realize efficiently, or at all, the assumed or expected economic benefits of acreage that we acquire. +Additionally, significant acquisitions can change the nature of our operations depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or may be in different geographic locations than our existing properties. These factors can increase the risks associated with an acquisition. Acquisitions also present risks associated with the additional indebtedness that may be required to finance the purchase price and any related increase in interest expense or other related charges. +Some of our acquisitions are structured as asset trades or exchanges. These transactions may give rise to any or all of the foregoing risks. In addition, transactions of this type create a risk that we will undervalue the properties we transfer to the counterparty in the trade or exchange or overvalue the properties we receive. Such an undervaluation or overvaluation would result in the transaction being less favorable to us than we expected. +29 +Complications with the design or implementation of our new enterprise resource planning system could adversely impact our business and operations. +We rely extensively on information systems and technology to manage our business and summarize operating results. We are in the process of implementing a new ERP system. This ERP system will replace our existing operating and financial systems. The ERP system is designed to enhance the maintenance of our financial records, improve operational functionality and provide timely information to our management team related to the operation of the business. The ERP system implementation process has required, and will continue to require, the investment of significant personnel and financial resources. We may not be able to successfully implement the ERP system without experiencing delays, increased costs and other difficulties. If we are unable to successfully design and implement the new ERP system as planned, our financial position, results of operations and cash flows could be negatively impacted. Additionally, if we do not effectively implement the ERP system as planned or the ERP system does not operate as intended, the effectiveness of our internal control over financial reporting could be adversely affected or our ability to assess those controls adequately could be delayed. +We operate in a litigious environment. The cost of defending any suits brought against us, and any judgments or settlements resulting from such suits, could have an adverse effect on our results of operations and financial condition. +Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, employment litigation, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. For example, in recent years, we have been subject to lawsuits regarding royalty practices and payments and matters relating to certain of our affiliated partnerships. As discussed in the footnote titled Commitments and Contingencies to our consolidated financial statements included elsewhere in this report, we are the subject of a recently filed lawsuit relating to our two remaining affiliated partnerships and are currently involved in a fiduciary duty lawsuit regarding our environmental compliance programs. The outcome of legal proceedings is inherently uncertain. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management attention and other factors. In addition, the resolution of such a proceeding could result in penalties or sanctions, settlement costs and/or judgments, consent decrees or orders requiring a change in our business practices, any of which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties, sanctions or costs may be insufficient. Judgments and estimates to determine accruals or the anticipated range of potential losses related to legal and other proceedings could change from one period to the next, and such changes could be material. Information regarding our legal proceedings can found in the footnote titled Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere in this report. +Our business could be negatively impacted by security threats, including cybersecurity threats and other disruptions. +We face various security threats, including attempts by third parties to gain unauthorized access to competitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. There can be no assurance that the procedures and controls we use to monitor these threats and mitigate our exposure to them will be sufficient to prevent them from materializing. +Our industry has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain exploration, development and production activities. We depend on digital technology, including information systems and related infrastructure, as well as cloud applications and services, to store, transmit, process and record sensitive information (including but not limited to trade secrets, employee information and financial and operating data), communicate with our employees and business partners, and for many other activities related to our business. In addition, computer systems control the oil and gas production and processing equipment that are necessary to deliver our production to market. A disruption or failure of these systems, or of the networks and infrastructure on which they rely, may cause damage to critical production, distribution and/or storage assets, delay or prevent delivery to markets, or make it difficult to accurately account for production and settle transactions. +As dependence on digital technologies has increased in our industry, cyber incidents, including deliberate attacks and unintentional events, have also increased. Our systems and infrastructure are subject to damage or interruption from a number of potential sources including natural disasters, software viruses or other malware, power failures, cyber-attacks and other events. We also face various other cyber-security threats from criminal hackers, state-sponsored intrusion, industrial espionage and employee malfeasance, including threats to gain access to sensitive information or to render data or systems unusable. +30 +Our business partners, including vendors, service providers, operating partners, purchasers of our production and financial institutions, are also dependent on digital technology. A vulnerability in the cybersecurity of one or more of our vendors could facilitate an attack on our systems. +Our technologies, systems and networks, and those of our business partners, may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, theft of property or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Although we have not suffered material losses related to cyber-attacks to date, if we were successfully attacked, we could incur substantial remediation and other costs or suffer other negative consequences, such as a loss of competitive information, critical infrastructure, personnel or capabilities essential to our operations. Events of this nature could have a material adverse effect on our reputation, financial condition, results of operations or cash flows. Moreover, as the sophistication of cyber-attacks continues to evolve, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities. +The physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. +Many scientists believe that increasing concentrations of carbon dioxide, methane and other GHGs in the Earth's atmosphere are changing global climate patterns. One consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. Flooding that occurred in Colorado in 2013 is an example of an extreme weather event that negatively impacted our operations. If such events were to continue to occur, or become more frequent, our operations could be adversely affected in various ways, including through damage to our facilities or from increased costs for insurance. +Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our production could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business. +Risks Relating to Financial Matters +Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our production and reserves, and ultimately our profitability. +Our industry is capital intensive. We expect to continue to make substantial capital expenditures for the exploration, development, production and acquisition of crude oil, natural gas and NGL reserves. To date, we have financed capital expenditures primarily with bank borrowings under our revolving credit facility, cash generated by operations and proceeds from capital markets transactions and the sale of properties. We intend to finance our future capital expenditures utilizing similar financing sources. Our cash flows from operations and access to capital are subject to a number of variables, including: +• +our proved reserves; +• +the amount of crude oil, natural gas and NGLs we are able to produce from existing wells; +• +the prices at which crude oil, natural gas and NGLs are sold; +• +the costs to produce crude oil, natural gas and NGLs; and +• +our ability to acquire, locate and produce new reserves. +If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower commodity prices, operating difficulties or for any other reason, our need for capital from other sources could increase, and there can be no assurance that such other sources of capital would be available at that time on reasonable terms or at all. If we raise funds by issuing additional equity securities, this would have a dilutive effect on existing shareholders. If we raise funds through the incurrence of debt, the risks we face with respect to our indebtedness would increase and we would incur additional interest expense. Our inability to obtain sufficient financing on acceptable terms would adversely affect our financial condition and profitability. +31 +We have a substantial amount of debt and the cost of servicing, and risks related to refinancing, that debt could adversely affect our business. Those risks could increase if we incur more debt. +We have a substantial amount of indebtedness outstanding. As a result, a significant portion of our cash flows will be required to pay interest and principal on our indebtedness, and we may not generate sufficient cash flows from operations, or have future borrowing capacity available, to enable us to repay our indebtedness or to fund other liquidity needs. +Servicing our indebtedness and satisfying our other obligations will require a significant amount of cash. Our cash flow from operating activities and other sources may not be sufficient to fund our liquidity needs. Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend on our future operating performance, our financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control. We cannot assure you that our business will generate sufficient cash flow from operations, or that sufficient future borrowings will be available to us under our revolving credit facility or otherwise, to fund our liquidity needs. +A substantial decrease in our operating cash flow or an increase in our expenses could make it difficult for us to meet debt service requirements and could require us to modify our operations, including by curtailing our exploration and drilling programs, selling assets, reducing our capital expenditures, refinancing all or a portion of our existing debt or obtaining additional financing. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. In addition, the terms of our debt agreements could restrict us from implementing some of these alternatives. +In the absence of adequate cash from operations and other available capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. We may not be able to consummate these dispositions for fair market value, in a timely manner or at all. Furthermore, any proceeds that we could realize from any dispositions may not be adequate to meet our debt service obligations then due. +Covenants in our debt agreements currently impose, and future financing agreements may impose, significant operating and financial restrictions. +Our current debt agreements contain restrictions, and future financing agreements may contain additional restrictions, on our activities, including covenants that restrict our and our restricted subsidiaries’ ability to: +• +incur additional debt; +• +pay dividends on, redeem or repurchase stock; +• +create liens; +• +make specified types of investments; +• +apply net proceeds from certain asset sales; +• +engage in transactions with our affiliates; +• +engage in sale and leaseback transactions; +• +merge or consolidate; +• +restrict dividends or other payments from restricted subsidiaries; +• +sell equity interests of restricted subsidiaries; and +• +sell, assign, transfer, lease, convey or dispose of assets. +Our revolving credit facility is secured by substantially all of our oil and gas properties as well as a pledge of all ownership interests in our operating subsidiaries. The restrictions contained in our debt agreements may prevent us from taking actions that we believe would be in the best interest of our business, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. We may also incur future debt obligations that subject us to additional restrictive covenants. +Our revolving credit facility has substantial restrictions and financial covenants and our ability to comply with those restrictions and covenants is uncertain. Our lenders can unilaterally reduce our borrowing availability based on anticipated commodity prices. +We expect to depend on our revolving credit facility for part of our future capital needs. The terms of the credit agreement require us to comply with certain financial covenants. Our ability to comply with these covenants in the future is +32 +uncertain and will be affected by the levels of cash flows from operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the revolving credit facility or other debt agreements could result in a default under those agreements, which could cause all of our existing indebtedness to become immediately due and payable. +The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based upon projected revenues from the properties securing their loan. Decreases in the price of crude oil, natural gas or NGLs can be expected to have an adverse effect on the borrowing base. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Outstanding borrowings in excess of the borrowing base must be repaid immediately unless we pledge other crude oil and natural gas properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility. Our inability to borrow additional funds under our revolving credit facility could adversely affect our operations and our financial results. +If we are unable to comply with the restrictions and covenants in our debt agreements, the resulting default could lead to an acceleration of payment of funds that we have borrowed and we may not have or be able to obtain the funds necessary to repay those amounts. +Any default under the agreements governing our indebtedness, including a default under our revolving credit facility that is not waived by the required lenders, and the remedies sought by the holders of any such indebtedness, could make us unable to pay principal and interest on our indebtedness and satisfy our other obligations. If we are unable to generate sufficient cash flows and are otherwise unable to obtain the funds necessary to meet required payments of principal and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. In the event of such a default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our revolving credit facility could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation. In addition, the default could result in a cross-default under other debt agreements. If our operating performance declines, we may in the future need to seek waivers from the required lenders under our revolving credit facility to avoid being in default and we may not be able to obtain such a waiver. If this occurs and no waiver is obtained, we would be in default under our revolving credit facility, the lenders could exercise their rights as described above, and we could be forced into bankruptcy or liquidation. We cannot assure you that we will be granted waivers or amendments to our debt agreements if for any reason we are unable to comply with these agreements, or that we will be able to refinance our debt on terms acceptable to us, or at all. +Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly. +Borrowings under our revolving credit facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase although the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness and for other purposes would decrease. +Notwithstanding our current indebtedness levels and restrictive covenants, we may still be able to incur substantial additional debt, which could exacerbate the risks described above. +We may be able to incur additional debt in the future. Although our debt agreements contain restrictions on our ability to incur indebtedness, those restrictions are subject to a number of exceptions. In particular, we may borrow under the revolving credit facility. We may also consider investments in joint ventures or acquisitions that may increase our indebtedness. Adding new debt to current debt levels could intensify the related risks that we and our subsidiaries now face. +Under the “successful efforts” accounting method that we use, unsuccessful exploratory wells must be expensed in the period in which they are determined to be non-productive, which reduces our net income in such periods. +We conduct exploratory drilling in order to identify additional opportunities for future development. Under the “successful efforts” method of accounting that we use, the cost of unsuccessful exploratory wells must be charged to expense in the period in which the wells are determined to be unsuccessful. In addition, lease costs for acreage condemned by the unsuccessful well must also be expensed. In contrast, unsuccessful development wells are capitalized as a part of the investment in the field where they are located. The costs of unsuccessful exploratory wells could result in a significant reduction in our profitability in periods in which the costs are required to be expensed. +33 +Our commodity derivative activities could result in financial losses or reduced income from failure to perform by our counterparties, could limit our potential gains from increases in prices and could result in volatility in our net income. +We use commodity derivatives for a portion of the production from our own wells and for natural gas purchases and sales by our marketing subsidiary to achieve more predictable cash flows, to reduce exposure to adverse fluctuations in commodity prices, and to allow our natural gas marketing company to offer pricing options to natural gas sellers and purchasers. These arrangements expose us to the risk of financial loss in some circumstances, including when purchases or sales are different than expected or the counterparty to the commodity derivative contract defaults on its contractual obligations. In addition, many of our commodity derivative contracts are based on WTI or another crude oil or natural gas index price. The risk that the differential between the index price and the price we receive for the relevant production may change unexpectedly makes it more difficult to hedge effectively and increases the risk of a hedging-related loss. Also, commodity derivative arrangements may limit the benefit we would otherwise receive from increases in the prices for the relevant commodity. +At December 31, 2018 , we had hedged a total of 19.6 MMBbls of crude oil and 26.4 Bcf of natural gas through 2020. These hedges may be inadequate to protect us from continuing and prolonged declines in crude oil and natural gas prices. +Since we do not designate our commodity derivatives as cash flow hedges, we do not currently qualify for use of hedge accounting; therefore, changes in the fair value of commodity derivatives are recorded in our income statements and our net income is subject to greater volatility than it would be if our commodity derivative instruments qualified for hedge accounting. For instance, if commodity prices rise significantly, this could result in significant non-cash charges during the relevant period, which could have a material negative effect on our net income. +Our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur. +The occurrence of a significant accident or other event that is not fully covered by insurance, not properly or timely noticed to our carrier, or that is in excess of our insurance coverage, could have a material adverse effect on our operations and financial condition. Insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. In addition, pollution and environmental risks are generally not fully insurable. +The price of our common stock has been and may continue to be highly volatile, which may make it difficult for shareholders to sell our common stock when desired or at attractive prices. +The market price of our common stock is highly volatile and we expect it to continue to be volatile for the foreseeable future. Adverse events could trigger declines in the price of our common stock, including, among others: +• +changes in production volumes, worldwide demand and prices for crude oil and natural gas; +• +inability to hedge future production at the same pricing level as our current or prior hedges; +• +changes in securities analysts’ estimates of our financial performance; +• +fluctuations in stock market prices and volumes, particularly among securities of energy companies; +• +changes in market valuations and valuation multiples of similar companies; +• +changes in interest rates; +• +announcements regarding adverse timing or lack of success in discovering, acquiring, developing and producing crude oil and natural gas resources; +• +announcements by us or our competitors of significant contracts, new acquisitions, discoveries, commercial relationships, joint ventures or capital commitments; +• +decreases in the amount of capital available to us, including as a result of borrowing base reductions and/or lenders ceasing to participate in our revolving credit facility syndicate; +• +operating results that fall below market expectations or variations in our quarterly operating results; +• +loss of a major customer; +• +loss of a relationship with a partner; +• +the occurrence and severity of environmental events and governmental and other third-party responses to the events; or +• +additions or departures of key personnel. +External events, such as news concerning economic conditions, counterparties to our natural gas or crude oil derivatives arrangements, changes in government regulations impacting the crude oil and natural gas exploration and production industry or the movement of capital into or out of our industry, are also likely to affect the price of our common stock, regardless of our operating performance. For example, there have been recent efforts by some investment advisers, sovereign wealth funds, public pension funds, universities and other investment groups to divest themselves from investments +34 +in companies involved in fossil fuel extraction, and these efforts could reduce the trading prices of our securities. Similarly, our stock price could be adversely affected by changes in the way that analysts and investors assess the geological and economic characteristics of the basins in which we operate. Furthermore, general market conditions, including the level of, and fluctuations in, the trading prices of stocks generally could affect the price of our common stock. The stock markets regularly experience price and volume volatility that affects many companies’ stock prices without regard to the operating performance of those companies. Volatility of this type may affect the trading price of our common stock. Similar factors could also affect the trading prices of our senior notes. +Our certificate of incorporation, bylaws and Delaware law contain provisions that may have an anti-takeover effect and may delay, defer or prevent a tender offer or takeover attempt, which may adversely affect the market price of our common stock. +Our certificate of incorporation and bylaws, and certain provisions of Delaware law, may have anti-takeover effects. +For example, our certificate of incorporation authorizes our board of directors to issue preferred stock without shareholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us, including in circumstances where the acquisition is supported by the holders of a majority of our stock. In addition, other provisions of our certificate of incorporation, bylaws and Delaware law could make it more difficult for a third party to acquire control of us against the wishes of our board of directors, including: +• +the organization of our board of directors as a classified board, which provides that approximately one-third of our directors are subject to election each year; +• +bylaw provisions that require advance notice of some types of shareholder proposals; and +• +Delaware law provisions which prohibit us from engaging in any business combination with any "interested stockholder," meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met. +In addition, shareholder activism in our industry has been increasing. If we are unable to work productively with activist or other shareholders, any resulting disagreements or disputes could require substantial management time and attention and could adversely affect our results of operations. +Derivatives legislation and regulation could adversely affect our ability to hedge crude oil and natural gas prices and increase our costs and adversely affect our profitability. +In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was enacted into law. The Dodd-Frank Act regulates derivative transactions, including our commodity hedging swaps, and could have a number of adverse effects on us, including the following: +• +The Dodd-Frank Act may limit our ability to enter into hedging transactions, thus exposing us to additional risks related to commodity price volatility; commodity price decreases would then have an increased adverse effect on our profitability and revenues. Reduced hedging may also impair our ability to have certainty with respect to a portion of our cash flows, which could lead to decreases in capital spending and, therefore, decreases in future production and reserves. +• +If, as a result of the Dodd-Frank Act or its implementing regulations, we are required to post cash collateral in connection with our derivative positions, this would likely make it impracticable to implement our current hedging strategy. +• +Our derivatives counterparties are subject to significant requirements imposed as a result of the Dodd-Frank Act. We expect that these requirements will increase the cost to hedge because there will be fewer counterparties in the market and increased counterparty costs will be passed on to us. +The above factors could also affect the pricing of derivatives and make it more difficult for us to enter into hedging transactions on favorable terms. +ITEM 1B. UNRESOLVED STAFF COMMENTS +None. +35 +ITEM 3. LEGAL PROCEEDINGS +Information regarding our legal proceedings can found in the footnote titled Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere in this report. +ITEM 4. MINE SAFETY DISCLOSURES +Not applicable. +PART II +ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Our common stock, par value $0.01 per share, is traded on the NASDAQ Global Select Market under the symbol PDCE. +As of February 15, 2019 , we had approximately 476 stockholders of record. Since inception, no cash dividends have been declared on our common stock. Cash dividends are restricted under the terms of our revolving credit facility, as well as the indentures governing our 6.125% senior notes due September 15, 2024 (the "2024 Senior Notes") and our 5.75% senior notes due May 15, 2026 (the "2026 Senior Notes"), and we presently intend to continue a policy of using retained earnings for the expansion of our business. +The following table presents information about our purchases of our common stock during the three months ended December 31, 2018 : +Period +Total Number of Shares Purchased (1) +Average Price Paid per Share +October 1 - 31, 2018 +5,160 +$ +47.20 +November 1 - 30, 2018 +— +— +December 1 - 31, 2018 +7,022 +29.00 +Total fourth quarter 2018 purchases +12,182 +36.71 +__________ +(1) +Purchases primarily represent shares purchased from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans. +36 +STOCKHOLDER PERFORMANCE GRAPH +The performance graph below compares the cumulative total return of our common stock over the five-year period ended December 31, 2018 with the cumulative total returns for the same period for the Standard and Poor's ("S&P") 500 Index and the Standard Industrial Code ("SIC") Index. The SIC Index is a weighted composite of 233 crude petroleum and natural gas companies. The cumulative total stockholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on December 31, 2013 , and in the S&P 500 Index and the SIC Index on the same date. The results shown in the graph below are not necessarily indicative of future performance. +37 +ITEM 6. SELECTED FINANCIAL DATA +Year Ended/As of December 31, +2018 +2017 +2016 (1) +2015 +2014 (2) +(in millions, except per share data and as noted) +Statement of Operations (From Continuing Operations): +Crude oil, natural gas and NGLs sales +$ +1,390.0 +$ +913.1 +$ +497.4 +$ +378.7 +$ +471.4 +Commodity price risk management gain (loss), net +145.2 +(3.9 +) +(125.7 +) +203.2 +310.3 +Total revenues +1,548.7 +921.6 +382.9 +595.3 +856.2 +Income (loss) from continuing operations +2.0 +(127.5 +) +(245.9 +) +(68.3 +) +107.3 +Earnings per share from continuing operations: +Basic +$ +0.03 +$ +(1.94 +) +$ +(5.01 +) +$ +(1.74 +) +$ +3.00 +Diluted +0.03 +(1.94 +) +(5.01 +) +(1.74 +) +2.93 +Statement of Cash Flows: +Net cash flows from: +Operating activities +$ +889.3 +$ +597.8 +$ +486.3 +$ +411.1 +$ +236.7 +Investing activities +(1,087.9 +) +(717.0 +) +(1,509.1 +) +(604.3 +) +(474.1 +) +Financing activities +18.1 +65.0 +1,266.1 +178.0 +60.3 +Capital expenditures from development of crude oil and natural gas properties (3) +(946.4 +) +(737.2 +) +(436.9 +) +(599.5 +) +(623.8 +) +Acquisition of crude oil and natural gas properties +(180.0 +) +(15.6 +) +(1,073.7 +) +— +— +Balance Sheet: +Total assets +$ +4,544.1 +$ +4,420.4 +$ +4,485.8 +$ +2,370.5 +$ +2,331.1 +Working capital (deficit) +(166.6 +) +(16.4 +) +129.2 +30.7 +89.5 +Total debt, net of unamortized discount and debt issuance costs +1,194.9 +1,151.9 +1,044.0 +642.4 +655.5 +Total equity +2,526.7 +2,507.6 +2,622.8 +1,287.2 +1,137.4 +Average Pricing and Production Expenses From Continuing Operations (per Boe and as a percent of sales for production taxes): +Sales price (excluding net settlements on derivatives) +$ +34.61 +$ +28.69 +$ +22.43 +$ +24.64 +$ +50.72 +Lease operating expenses +3.26 +2.82 +2.70 +3.71 +4.56 +Transportation, gathering and processing +0.93 +1.04 +0.83 +0.66 +0.49 +Production taxes +2.25 +1.91 +1.42 +1.20 +2.76 +Production taxes (as a percent of sales) +6.5 +% +6.6 +% +6.3 +% +4.9 +% +5.4 +% +Production (MBoe): +Production from continuing operations +40,160 +31,830 +22,176 +15,369 +9,294 +Production from discontinued operations +— +— +— +— +1,093 +Total production +40,160 +31,830 +22,176 +15,369 +10,387 +Total proved reserves (MMBoe) +544.9 +452.9 +341.4 +272.8 +250.1 +______________ +(1) +In 2016, we closed an acquisition in the Delaware Basin for aggregate consideration of approximately $1.76 billion. +(2) +In 2014, we completed the sale of our ownership interest in PDC Mountaineer, LLC ("PDCM"). Our proportionate share of PDCM's Marcellus Shale results of operations have been separately reported as discontinued operations. +(3) +Includes impact of change in accounts payable related to capital expenditures. +38 +ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes thereto included elsewhere in this report. Further, we encourage you to revisit the Special Note Regarding Forward-Looking Statements in Part I of this report. +SUMMARY +2018 Financial Overview of Operations and Liquidity +Production volumes increased 26 percent to 40.2 MMBoe in 2018 compared to 2017 . The increase in production volumes was primarily attributable to the continued success of our horizontal Niobrara and Codell drilling program in the Wattenberg Field and growing production from our horizontal Wolfcamp drilling program in our Delaware Basin properties. Crude oil production increased 32 percent in 2018 and comprised approximately 42 percent of our total production. Natural gas production increased 23 percent and NGLs production increased 22 percent in 2018 compared to 2017 . On a combined basis, total liquids production of crude oil and NGLs comprised 63 percent of production in 2018 . For the month ended December 31, 2018 , we maintained an average production rate of approximately 129,000 Boe per day, up from approximately 97,000 Boe per day for the month ended December 31, 2017 . +Crude oil, natural gas and NGLs sales increased to $1.4 billion in 2018 compared to $913.1 million in 2017 , due to a 26 percent increase in production, combined with a 21 percent increase in weighted average realized commodity prices. Crude oil, natural gas and NGLs sales increased 84 percent in 2017 as compared to 2016 due to a 44 percent increase in production, combined with a 28 percent increase in average realized commodity prices. +We had negative net settlements from our commodity derivative contracts of $115.5 million for 2018 as compared to positive net settlements of $13.3 million and $208.1 million for 2017 and 2016 , respectively. See Results of Operations - Commodity Price Risk Management, Net for further details of our settlements of derivatives and changes in the fair value of unsettled derivatives . +The combined revenue from crude oil, natural gas and NGLs sales and net settlements received on our commodity derivative instruments increased 38 percent to $1.3 billion in 2018 from $926.4 million in 2017 . Such combined revenue of $926.4 million in 2017 represented an increase of 31 percent from $705.5 million in 2016 . +During 2018 , we recorded unproved and proved property impairment charges of $458.4 million , primarily resulting from identified current and anticipated near-term leasehold expirations within our non-focus areas of the Delaware Basin and our determination that we would no longer pursue plans to develop these properties. For more information regarding these charges see Results of Operations - Impairments of Properties. +In 2018 , we generated a net income of $2.0 million or $0.03 per diluted share. Our net income was most negatively impacted by the aforementioned impairment charges. +During the same period, our adjusted EBITDAX, a non-U.S. GAAP financial measure, was $868.3 million , up 27 percent relative to 2017 . See Reconciliation of Non-U.S. GAAP Financial Measures , below, for a more detailed discussion of adjusted EBITDAX and a reconciliation of adjusted EBITDAX to net income and cash from operating activities. The increase in our 2018 adjusted EBITDAX as compared to 2017 was primarily the result of the increase in crude oil, natural gas and NGLs sales of $476.9 million . This increase was partially offset by a decrease in derivative commodity settlements of $128.9 million , an increase in operating costs of $125.3 million and the reversal of a provision for uncollectible notes receivable of $40.2 million in 2017 . In 2017 and 2016 , our net loss per diluted share was $1.94 and $5.01 , respectively, and our adjusted EBITDAX was $682.1 million and $459.8 million , respectively. +Our net cash flows from operating activities in 2018 , 2017 and 2016 were $889.3 million , $597.8 million and $486.3 million , respectively, and our adjusted cash flows from operations, a non-U.S. GAAP financial measure, were $808.4 million , $582.1 million and $466.8 million , respectively. +39 +Liquidity +Available liquidity as of December 31, 2018 was $1.3 billion , which was comprised of $1.4 million of cash and cash equivalents and $1.3 billion available for borrowing under our revolving credit facility at our current commitment level. We increased the commitment level on our revolving credit facility to $1.3 billion in October 2018. +We maintain a significant capital investment program to execute our development plans, which requires capital expenditures to be made in periods prior to initial production from newly-developed wells. Further, we use our available liquidity for other working capital requirements, acquisitions, support for letters of credit and for general corporate purposes. From time to time, these activities may result in a working capital deficit; however, we do not believe that our working capital deficit as of December 31, 2018 is an indication of a lack of liquidity. We intend to continue to manage our liquidity position by a variety of means, including through the generation of cash flows from operations, investment in projects with attractive rates of return, protection of cash flows on a portion of our anticipated sales through the use of an active commodity derivative hedging program, utilization of our borrowing capacity under our revolving credit facility and, if warranted, capital markets transactions from time to time. +Acquisitions +We closed the Bayswater Asset Acquisition in January 2018, acquiring approximately 7,400 net acres, 24 operated horizontal wells that were either DUCs or in-process wells at the time of closing and approximately 220 gross drilling locations. See the footnote titled Business Combination to our consolidated financial statements included elsewhere in this report for further details. +Acreage Exchanges +During 2018, we completed two acreage exchanges that consolidated our position in the core area of the Wattenberg Field, resulting in us acquiring approximately 14,800 net acres in exchange for 15,500 net acres. +40 +2018 Drilling Overview +During the year ended December 31, 2018 , we continued to execute our strategic plan to grow production while preserving our financial strength and liquidity. During 2018 , we ran three drilling rigs in each of the Wattenberg Field and Delaware Basin. +The following tables summarizes our drilling and completion activity for the year ended December 31, 2018 : +Wells Operated by PDC +Wattenberg Field +Delaware Basin +Total +Gross +Net +Gross +Net +Gross +Net +In-process as of December 31, 2017 +87 +80.1 +13 +12.2 +100 +92.3 +Wells spud +161 +150.9 +31 +29.7 +192 +180.6 +Acquired in-process (1) +24 +18.2 +— +— +24 +18.2 +Wells turned-in-line +(139 +) +(126.8 +) +(26 +) +(24.5 +) +(165 +) +(151.3 +) +In-process as of December 31, 2018 +133 +122.4 +18 +17.4 +151 +139.8 +Wells Operated by Others +Wattenberg Field +Delaware Basin +Total +Gross +Net +Gross +Net +Gross +Net +In-process as of December 31, 2017 +14 +2.6 +8 +1.0 +22 +3.6 +Wells spud +25 +3.4 +9 +1.1 +34 +4.5 +Acquired DUCs (operated at December 31, 2018) (1) +(3 +) +(1.5 +) +— +— +(3 +) +(1.5 +) +Wells turned-in-line +(31 +) +(2.5 +) +(11 +) +(1.2 +) +(42 +) +(3.7 +) +In-process as of December 31, 2018 +5 +2.0 +6 +0.9 +11 +2.9 +_______________ +(1) +Represents DUCs and completed wells that had not been turned-in-line that we acquired with the Bayswater Asset Acquisition in January 2018. +Our in-process wells represent wells that are in the process of being drilled and/or have been drilled and are waiting to be fractured and/or for gas pipeline connection. Our DUCs are generally completed and turned-in-line within a year of drilling. +2019 Operational and Financial Outlook +We anticipate that our production for 2019 will range between 46 MMBoe to 50 MMBoe, or approximately 126,000 Boe to 137,000 Boe per day for the year. We expect that approximately 41 to 45 percent of our 2019 production will be comprised of crude oil and approximately 21 to 23 percent will be NGLs, for total liquids of approximately 62 to 68 percent. Our planned 2019 capital investments in crude oil and natural gas properties, which we expect to be between $810 million and $870 million , are focused on continued execution of our development plans in the Wattenberg Field and Delaware Basin. +In 2019, we also expect to spend approximately $20 million for corporate capital, the majority of which is related to the implementation of an ERP system to replace our existing operating and financial systems. This long-planned investment is being made to enhance maintenance of our financial records, improve operational functionality and provide timely information to our management team related to the operation of the business. +We believe that we maintain a degree of operational flexibility to control the pace of our capital spending. As we execute our capital investment program, we continually monitor, among other things, expected rates of return, the political environment and our remaining inventory in order to best meet our short- and long-term corporate strategy. Should commodity pricing or the operating environment deteriorate, we may determine that an adjustment to our development plan is appropriate. +Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays in the rural areas of the core Wattenberg Field, which is further delineated between the Kersey, Prairie and Plains development areas. Our 2019 capital investment program for the Wattenberg Field is approximately 60 percent of our total capital investments in crude oil and natural gas properties, of which approximately 90 percent is expected to be invested in operated drilling and completion activity. We plan to drill standard-reach lateral (“SRL”), mid-reach lateral (“MRL”) and extended-reach lateral (“XRL”) wells in 2019 , the +41 +majority of which will be in the Kersey area of the field. In 2019 , we anticipate spudding approximately 135 to 150 operated wells and turning-in-line approximately 110 to 125 operated wells. We expect to drill at a three-rig pace in 2019 with an average development cost per well of between $3 million and $5 million, depending upon the lateral length of the well. The remainder of the Wattenberg Field capital investment program is expected to be used for non-operated drilling, land, capital workovers and facilities projects. +Delaware Basin. Our 2019 capital investment program for the Delaware Basin contemplates operating between a two- and three-rig pace throughout the year. Total capital investments in crude oil and natural gas properties in the Delaware Basin for 2019 are expected to be approximately 40 percent of our total capital investments in crude oil and natural gas properties, of which approximately 80 percent is allocated to spud approximately 25 to 30 operated wells and turn-in-line approximately 20 to 25 operated wells. We plan to drill MRL and XRL wells in 2019 with an expected average development cost per well of between $11.5 million and $13 million, depending upon the lateral length of the well. We do not plan to drill any SRL wells in the Delaware Basin in 2019. Based on the timing of our operations and requirements to hold acreage, we may elect to drill wells different from or in addition to those currently anticipated as we are continuing to analyze the terms of the relevant leases. We plan to use approximately 20 percent of our budgeted capital for midstream assets, leasing, non-operated capital, seismic and technical studies and facilities. +We are in the process of actively marketing our Delaware Basin crude oil gathering, natural gas gathering and produced water gathering and disposal assets for sale and currently expect to execute agreements for the sales of these assets in the first half of 2019. We anticipate making capital investments for midstream assets of approximately $40 million in 2019, a portion of which would be made prior to such sales depending on the timing of the divestitures. Such expenditures are included in the Delaware Basin capital investment amounts noted above. We expect that we would recover a portion of these expenditures upon settlement of the final sale prices. +Financial Guidance. We are committed to our disciplined approach to managing our development plans and expect that cash flows from operations in 2019 will exceed our capital investments in crude oil and natural gas properties assuming an average NYMEX crude oil price of at least $50.00. Based on our current production forecast for 2019 and our average 2019 price assumptions of $55.00 for NYMEX crude oil and $3.00 for NYMEX natural gas, we expect 2019 cash flows from operations to exceed our capital investments in crude oil and natural gas properties by approximately $65.0 million . Assuming a NYMEX crude oil price of $50.00 , we expect cash flows from operations to exceed our capital investments in crude oil and natural gas properties by approximately $25.0 million . We anticipate that capital investments will exceed cash flows from operations during the first half of 2019 and expect cash flows from operations to exceed capital investment during the remainder of the year. +Assuming a NYMEX crude oil price of $45.00 , we expect cash flows from operations to approximate our capital investments in crude oil and natural gas properties. A significant decline in NYMEX crude oil prices below approximately $45.00 per barrel would negatively impact our results of operations, financial condition and future development plans. Our leverage ratio, as defined in our revolving credit facility agreement, is expected to decrease from 1.4 as of the end of 2018 to approximately 1.3 by the end of 2019 based on anticipated production and $50.00 to $55.00 NYMEX crude oil prices. We may revise our 2019 capital investment program during the year as a result of, among other things, changes in commodity prices or our internal long-term outlook for commodity prices, requirements to hold acreage, the cost of services for drilling and well completion activities, drilling results, changes in our borrowing capacity, a significant change in cash flows, regulatory issues, requirements to maintain continuous activity on leaseholds or acquisition and/or divestiture opportunities. +We currently expect similar levels of financial performance and growth in 2020 as we anticipate experiencing in 2019. Based upon similar pricing assumptions used in our 2019 outlook and our focus on capital investment discipline, we currently anticipate increasing free cash flow in 2020. +42 +The following table provides projected financial guidance for 2019 : +Low +High +Operating Expenses +Lease operating expenses ($/Boe) +$ +2.85 +$ +3.15 +Transportation, gathering and processing expenses ("TGP") ($/Boe) +$ +0.80 +$ +1.00 +Production taxes (% of crude oil, natural gas and NGL sales) +6 +% +7 +% +General and administrative expense ($/Boe) +$ +3.00 +$ +3.40 +Estimated Price Realizations (% of NYMEX, excludes TGP) +Crude oil +90 +% +95 +% +Natural gas +50 +% +55 +% +NGLs +30 +% +35 +% +43 +Results of Operations +Summary Operating Results +The following table presents selected information regarding our operating results: +Year Ended December 31, +Percent Change +2018 +2017 +2016 +2018-2017 +2017-2016 +(dollars in millions, except per unit data) +Production: +Crude oil (MBbls) +16,963 +12,902 +8,728 +31.5 +% +47.8 +% +Natural gas (MMcf) +88,017 +71,689 +51,730 +22.8 +% +38.6 +% +NGLs (MBbls) +8,527 +6,981 +4,826 +22.1 +% +44.7 +% +Crude oil equivalent (MBoe) +40,160 +31,830 +22,176 +26.2 +% +43.5 +% +Average Boe per day (Boe) +110,027 +87,206 +60,590 +26.2 +% +43.9 +% +Crude Oil, Natural Gas and NGLs Sales: +Crude oil +$ +1,038.0 +$ +625.0 +$ +348.9 +66.1 +% +79.1 +% +Natural gas +163.2 +158.3 +91.6 +3.1 +% +72.8 +% +NGLs +188.8 +129.8 +56.9 +45.5 +% +128.1 +% +Total crude oil, natural gas and NGLs sales +$ +1,390.0 +$ +913.1 +$ +497.4 +52.2 +% +83.6 +% +Net Settlements on Commodity Derivatives: +Crude oil +$ +(124.4 +) +$ +(2.7 +) +$ +165.2 +* +(101.6 +)% +Natural gas +13.9 +23.3 +42.9 +(40.3 +)% +(45.7 +)% +NGLs (propane portion) +(5.0 +) +(7.3 +) +— +(31.5 +)% +* +Total net settlements on derivatives +$ +(115.5 +) +$ +13.3 +$ +208.1 +* +(93.6 +)% +Average Sales Price (excluding net settlements on derivatives): +Crude oil (per Bbl) +$ +61.19 +$ +48.45 +$ +39.96 +26.3 +% +21.2 +% +Natural gas (per Mcf) +1.85 +2.21 +1.77 +(16.3 +)% +24.9 +% +NGLs (per Bbl) +22.14 +18.59 +11.80 +19.1 +% +57.5 +% +Crude oil equivalent (per Boe) +34.61 +28.69 +22.43 +20.6 +% +27.9 +% +Average Costs and Expenses (per Boe): +Lease operating expenses +$ +3.26 +$ +2.82 +$ +2.70 +15.6 +% +4.4 +% +Production taxes +2.25 +1.91 +1.42 +17.8 +% +34.5 +% +Transportation, gathering and processing expenses +0.93 +1.04 +0.83 +(10.6 +)% +25.3 +% +General and administrative expense +4.25 +3.78 +5.07 +12.4 +% +(25.4 +)% +Depreciation, depletion and amortization +13.94 +14.74 +18.80 +(5.4 +)% +(21.6 +)% +Lease Operating Expenses by Operating Region (per Boe): +Wattenberg Field +$ +2.99 +$ +2.48 +$ +2.70 +20.6 +% +(8.1 +)% +Delaware Basin +4.14 +5.16 +8.79 +(19.8 +)% +(41.3 +)% +Utica Shale (1) +3.46 +1.66 +1.75 +108.4 +% +(5.1 +)% +* +Percentage change is not meaningful or equal to or greater than 300% or not applicable. +Amounts may not recalculate due to rounding. +______________ +(1) In March 2018, we completed the disposition of our Utica Shale properties. +44 +Crude Oil, Natural Gas and NGLs Sales +The year-over-year change in crude oil, natural gas and NGLs sales revenue were primarily due to the following: +Year Ended December 31, +2018 +2017 +(in millions) +Increase in production +$ +261.6 +$ +227.5 +Increase in average crude oil price +216.1 +109.6 +Increase (decrease) in average natural gas price +(31.1 +) +31.2 +Increase in average NGLs price +30.3 +47.4 +Total increase in crude oil, natural gas and NGLs sales revenue +$ +476.9 +$ +415.7 +Crude Oil, Natural Gas and NGLs Production +The following table presents crude oil, natural gas and NGLs production. +Year Ended December 31, +Change +Production by Operating Region +2018 +2017 +2016 +2018-2017 +2017-2016 +Crude oil (MBbls) +Wattenberg Field +12,809 +10,922 +8,230 +17.3 +% +32.7 +% +Delaware Basin +4,108 +1,699 +79 +141.8 +% +* +Utica Shale (1) +46 +281 +419 +(83.6 +)% +(32.9 +)% +Total +16,963 +12,902 +8,728 +31.5 +% +47.8 +% +Natural gas (MMcf) +Wattenberg Field +68,326 +60,106 +48,889 +13.7 +% +22.9 +% +Delaware Basin +19,277 +9,410 +373 +104.9 +% +* +Utica Shale (1) +414 +2,173 +2,468 +(80.9 +)% +(12.0 +)% +Total +88,017 +71,689 +51,730 +22.8 +% +38.6 +% +NGLs (MBbls) +Wattenberg Field +6,455 +5,876 +4,568 +9.9 +% +28.6 +% +Delaware Basin +2,038 +917 +36 +122.2 +% +* +Utica Shale (1) +34 +188 +222 +(81.9 +)% +(15.3 +)% +Total +8,527 +6,981 +4,826 +22.1 +% +44.7 +% +Crude oil equivalent (MBoe) +Wattenberg Field +30,652 +26,815 +20,945 +14.3 +% +28.0 +% +Delaware Basin +9,359 +4,184 +178 +123.7 +% +* +Utica Shale (1) +149 +831 +1,053 +(82.1 +)% +(21.1 +)% +Total +40,160 +31,830 +22,176 +26.2 +% +43.5 +% +Average crude oil equivalent per day (Boe) +Wattenberg Field +83,978 +73,466 +57,227 +14.3 +% +28.4 +% +Delaware Basin +25,641 +11,463 +486 +123.7 +% +* +Utica Shale (1) +408 +2,277 +2,877 +(82.1 +)% +(20.9 +)% +Total +110,027 +87,206 +60,590 +26.2 +% +43.9 +% +* +Percentage change is not meaningful or equal to or greater than 300 percent. +Amounts may not recalculate due to rounding. +(1) +In March 2018, we completed the disposition of our Utica Shale properties. +45 +The following table presents our crude oil, natural gas and NGLs production ratio by operating region: +Year Ended December 31, +Production Ratio by Operating Region +2018 +2017 +2016 +Wattenberg Field +Crude oil +42 +% +41 +% +39 +% +Natural gas +37 +% +37 +% +39 +% +NGLs +21 +% +22 +% +22 +% +Total +100 +% +100 +% +100 +% +Delaware Basin +Crude oil +44 +% +41 +% +45 +% +Natural gas +34 +% +37 +% +35 +% +NGLs +22 +% +22 +% +20 +% +Total +100 +% +100 +% +100 +% +Utica Shale (1) +Crude oil +31 +% +34 +% +40 +% +Natural gas +46 +% +43 +% +39 +% +NGLs +23 +% +23 +% +21 +% +Total +100 +% +100 +% +100 +% +______________ +(1) In March 2018, we completed the disposition of our Utica Shale properties. +Midstream Capacity +Our ability to market our production depends substantially on the availability, proximity and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. If adequate midstream facilities and services are not available to us on a timely basis and at acceptable costs, our production and results of operations could be adversely affected. Both of our current areas of operation have seen substantial development in recent years, and this has made it more difficult for providers of midstream infrastructure and services to keep pace with the corresponding increases in field-wide production. The ultimate timing and availability of adequate infrastructure is not within our control and we could experience capacity constraints for extended periods of time that would negatively impact our ability to meet our production targets. Weather, regulatory developments and other factors also affect the adequacy of midstream infrastructure. +Wattenberg Field. Elevated line pressures on gas gathering facilities have adversely affected production from the Wattenberg Field from time to time, most recently beginning in mid-2017 and continuing into the fourth quarter of 2018. DCP completed its Mewbourn 3 Plant in August of 2018. This project, along with associated new compression, resulted in significant incremental capacity being added to the DCP system. System pressures began to decrease as these projects were started and reached full capacity during the third and fourth quarters of 2018. Concurrently, additional residue pipeline capacity became available as pipeline expansion projects were completed and commissioned in November 2018. As a result, system pressures have recently been maintained at a lower level than during the latter part of 2017. These lower pressures, along with the system improvements implemented by DCP to prevent freezes, combined with relatively mild weather in late 2018, resulted in a significant reduction in line freezes compared to those experienced during late 2017. +DCP continues to make progress on construction of its O’Conner 2 Plant, which we expect to be completed by the end of the second quarter of 2019. We expect that the start-up of the O’Conner 2 Plant will further reduce the line pressures on the system, while providing additional processing capacity for incremental production associated with our ongoing drilling program. This is the second plant that includes baseline volume commitments for us and the other operators and guarantees a specified profit margin to DCP for a three-year period, beginning on the initial start-up date of the plant. Under our current drilling plans and in the current commodity pricing environment, we currently expect to satisfy the volume commitment and profit margin requirements with minimal payment from us. See the footnote titled Commitments and Contingencies to our consolidated financial statements included elsewhere in this report for additional details regarding these agreements. +We have been engaged with DCP in planning for further incremental increases to the processing capacity in the field and it is currently our expectation that an additional plant will be constructed and commissioned on DCP’s system in mid-2020. We also continue to work with our other midstream service providers in the field in an effort to ensure all of the existing infrastructure is fully utilized and that all options for system expansion are evaluated and implemented to the extent possible. +46 +Additional residue and NGL takeaway pipeline expansions/conversions are expected to be completed in the third and fourth quarters of 2019 to help ensure that all products associated with additional processing capacity will be transported to market. +NGL fractionation on the Gulf Coast and Conway is running at full capacity and this could potentially impact the operation of gas plants in the Wattenberg Field. While our Wattenberg Field operations are not currently being impacted by NGL fractionation capacity constraints, the limitation on NGL fractionation capacity did limit the throughput of some gas processing plants in the field for a portion of the fourth quarter of 2018. Limitations on downstream fractionation capacity could limit the ability of our service providers to adjust ethane and propane recoveries to optimize the plant product mix to maximize revenue. Additional fractionation capacity is scheduled to come online later in 2019 and in 2020. +Delaware Basin. Like other producers, we from time to time enter into volume commitments with midstream providers in order to induce them to provide increased capacity. If our production falls below the level required under these agreements, we could be subject to substantial penalties. In the second quarter of 2018, we entered into firm sales and pipeline agreements for portions of our Delaware Basin crude oil and natural gas production, respectively. The crude oil agreement runs through December 2023 and provides for firm physical takeaway for all of our forecasted 2019 Delaware Basin crude oil volumes. This agreement provides us with price diversification through realization of export market pricing that includes access to a Corpus Christi terminal and exposure to Brent-weighted prices. As a result of this agreement, we expect to realize approximately 94 percent of West Texas Intermediate ("WTI") crude oil pricing for our total Delaware Basin production in 2019, after deducting transportation and other related marketing expenses. Our actual realization for Delaware Basin production for 2018 was 95 percent of WTI crude oil pricing. We are currently not producing sufficient volumes to satisfy this volume commitment in the Delaware Basin; although at current commodity prices we have been able to profitably satisfy our obligations under the agreement with volumes purchased from third parties, this may not continue to be the case. +Our Delaware Basin natural gas sales agreements run through December 2021 and provide for firm physical takeaway of amounts that vary between 50,000 MMbtu and 115,000 MMbtu per day of our natural gas volumes from the basin during the term of the agreements. We installed additional compression in the Central area of the basin during the third quarter of 2018, which allowed us to move our Central area natural gas volumes with minimal flaring. +Our production from the Delaware Basin was not materially affected by midstream or downstream capacity constraints during 2018. However, natural gas takeaway capacity downstream of in-field gathering and processing facilities in the basin is operating close to capacity, and near-term production constraints are possible. +As discussed above, NGL fractionation on the Gulf Coast and Conway is running at full capacity, and this could potentially impact the operation of gas plants in the Delaware Basin. In addition, residue pipeline and downstream crude oil pipelines in the Delaware Basin are operating at high utilization rates. We expect additional residue gas and crude oil pipelines to be available in early 2020, and additional NGL fractionation infrastructure to be available starting in mid-2019, with more projects scheduled to be completed in 2020. +See Item 1A. Risk Factors - The marketability of our production is dependent upon transportation and processing facilities, the capacity and operation of which we do not control. Market conditions or operational impediments affecting midstream facilities and services could hinder our access to crude oil, natural gas and NGL markets, increase our costs or delay production. Our efforts to address midstream issues may not be successful. +47 +Crude Oil, Natural Gas and NGLs Pricing +Our results of operations depend upon many factors. Key factors include the price of crude oil, natural gas and NGLs and our ability to market our production effectively. Crude oil, natural gas and NGL prices have a high degree of volatility and our realizations can change substantially. Our realized sales prices for crude oil and NGLs increased and our realized prices for natural gas decreased during 2018 as compared to 2017 . NYMEX average daily crude oil prices increased 27 percent and NYMEX first-of-the-month natural gas prices decreased slightly as compared to 2017 . Our realized sales prices for crude oil, natural gas and NGLs increased during 2017 compared to 2016 . NYMEX crude oil prices increased 18 percent and NYMEX natural gas prices increased 26 percent as compared to 2016 . +The following tables present weighted-average sales prices of crude oil, natural gas and NGLs for the periods presented. +Year Ended December 31, +Weighted-Average Sales Price by Operating Region +Change +(excluding net settlements on derivatives) +2018 +2017 +2016 +2018-2017 +2017-2016 +Crude oil (per Bbl) +Wattenberg Field +$ +61.14 +$ +48.48 +$ +39.99 +26.1 +% +21.2 +% +Delaware Basin +61.37 +48.68 +49.28 +26.1 +% +(1.2 +)% +Utica Shale (1) +58.10 +45.63 +37.62 +27.3 +% +21.3 +% +Weighted-average price +61.19 +48.45 +39.96 +26.3 +% +21.2 +% +Natural gas (per Mcf) +Wattenberg Field +1.90 +2.19 +1.77 +(13.2 +)% +23.7 +% +Delaware Basin +1.66 +2.26 +2.78 +(26.5 +)% +(18.7 +)% +Utica Shale (1) +2.68 +2.40 +1.58 +11.7 +% +51.9 +% +Weighted-average price +1.85 +2.21 +1.77 +(16.3 +)% +24.9 +% +NGLs (per Bbl) +Wattenberg Field +20.58 +17.75 +11.59 +15.9 +% +53.1 +% +Delaware Basin +27.06 +22.64 +17.87 +19.5 +% +26.7 +% +Utica Shale (1) +24.29 +25.06 +15.11 +(3.1 +)% +65.9 +% +Weighted-average price +22.14 +18.59 +11.80 +19.1 +% +57.5 +% +Crude oil equivalent (per Boe) +Wattenberg Field +34.13 +28.55 +22.38 +19.5 +% +27.6 +% +Delaware Basin +36.25 +29.80 +31.50 +21.6 +% +(5.4 +)% +Utica Shale (1) +30.98 +27.36 +21.88 +13.2 +% +25.0 +% +Weighted-average price +34.61 +28.69 +22.43 +20.6 +% +27.9 +% +* +Percentage change is not meaningful or equal to or greater than 300 percent. +Amounts may not recalculate due to rounding. +(1) +In March 2018, we completed the disposition of our Utica Shale properties. +Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of crude oil, natural gas or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and actual prices received. +Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related purchase agreement. We use the net-back method when control of the crude oil, natural gas or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the indices for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. +48 +We use the gross method of accounting when control of the crude oil, natural gas or NGLs is not transferred to the purchasers and the purchaser does not provide transportation, gathering or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses. +Under the New Revenue Standard, certain crude oil and natural gas sales that were recognized using the gross method prior to the adoption of the New Revenue Standard are recognized using the net-back method. If we had adopted the New Revenue Standard on January 1, 2017, we estimate that the average realization percentages before transportation, gathering and processing expenses for 2017 would not have differed materially from the average realization percentages shown for the periods shown below. Further, the net realized price after transportation, gathering and processing expenses would not have changed. See the footnote titled Revenue Recognition to our consolidated financial statements included elsewhere in this report for a more detailed discussion. +As discussed above, we enter into agreements for the sale and transportation, gathering and processing of our production, the terms of which can result in variances in the per unit realized prices that we receive for our crude oil, natural gas and NGLs. Information related to the components and classifications in the consolidated statements of operations is shown below. For crude oil, the average NYMEX prices shown below are based upon average daily prices throughout each month and, for natural gas, the average NYMEX pricing is based upon first-of-the-month index prices, as in each case this is the method used to sell the majority of these commodities pursuant to terms of the respective sales agreements. For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. The average realized price both before and after transportation, gathering and processing expenses shown in the table below represents our approximate composite per barrel price for NGLs. +2018 +Average NYMEX Price +Average Realized Price Before Transportation, Gathering and Processing Expenses +Average Realization Percentage Before Transportation, Gathering and Processing Expenses +Average Transportation, Gathering and Processing Expenses +Average Realized Price After Transportation, Gathering and Processing Expenses +Average Realization Percentage After Transportation, Gathering and Processing Expenses +Crude oil (per Bbl) +$ +64.77 +$ +61.19 +94 +% +$ +0.94 +$ +60.25 +93 +% +Natural gas (per MMBtu) +3.09 +1.85 +60 +% +0.22 +1.63 +53 +% +NGLs (per Bbl) +64.77 +22.14 +34 +% +0.21 +21.93 +34 +% +Crude oil equivalent (per Boe) +47.87 +34.61 +72 +% +0.93 +33.68 +70 +% +2017 +Average NYMEX Price +Average Realized Price Before Transportation, Gathering and Processing Expenses +Average Realization Percentage Before Transportation, Gathering and Processing Expenses +Average Transportation, Gathering and Processing Expenses +Average Realized Price After Transportation, Gathering and Processing Expenses +Average Realization Percentage After Transportation, Gathering and Processing Expenses +Crude oil (per Bbl) +$ +50.95 +$ +48.45 +95 +% +$ +1.41 +$ +47.04 +92 +% +Natural gas (per MMBtu) +3.11 +2.21 +71 +% +0.17 +2.04 +66 +% +NGLs (per Bbl) +50.95 +18.59 +36 +% +0.30 +18.29 +36 +% +Crude oil equivalent (per Boe) +38.83 +28.69 +74 +% +1.04 +27.65 +71 +% +49 +2016 +Average NYMEX Price +Average Realized Price Before Transportation, Gathering and Processing Expenses +Average Realization Percentage Before Transportation, Gathering and Processing Expenses +Average Transportation, Gathering and Processing Expenses +Average Realized Price After Transportation, Gathering and Processing Expenses +Average Realization Percentage After Transportation, Gathering and Processing Expenses +Crude oil (per Bbl) +$ +43.32 +$ +39.96 +92 +% +$ +1.51 +$ +38.45 +89 +% +Natural gas (per MMBtu) +2.46 +1.77 +72 +% +0.07 +1.70 +69 +% +NGLs (per Bbl) +43.32 +11.80 +27 +% +0.28 +11.52 +27 +% +Crude oil equivalent (per Boe) +32.22 +22.43 +70 +% +0.83 +21.60 +67 +% +Our average realization percentages for crude oil and NGLs for 2018 are consistent with those for 2017 . The realization percentage for our natural gas sales has decreased as compared to 2017 , primarily due to the widening of the basis between NYMEX and the indices upon which we sell our natural gas production. +Commodity Price Risk Management, Net +We use commodity derivative instruments to manage fluctuations in crude oil, natural gas and NGLs prices, including collars, fixed-price swaps and basis swaps on a portion of our estimated crude oil, natural gas and propane production. For our commodity swaps, we ultimately realize the fixed price value related to the swaps. See the footnote titled Commodity Derivative Financial Instruments to our consolidated financial statements included elsewhere in this report for a detailed presentation of our derivative positions as of December 31, 2018 . +Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments, as well as the change in the fair value of unsettled commodity derivatives related to our crude oil, natural gas and propane production. Commodity price risk management, net, does not include derivative transactions related to our gas marketing, which are included in other income and other expenses. +Net settlements of commodity derivative instruments are based on the difference between the crude oil, natural gas and propane index prices at the settlement date of our commodity derivative instruments compared to the respective strike prices contracted for the settlements months that were established at the time we entered into the commodity derivative transaction. The net change in fair value of unsettled commodity derivatives is comprised of the net value increase or decrease in the beginning-of-period fair value of commodity derivative instruments that settled during the period, and the net change in fair value of unsettled commodity derivatives during the period or from inception of any new contracts entered into during the applicable period. The net change in fair value of unsettled commodity derivatives during the period is primarily related to shifts in the crude oil, natural gas and NGLs forward curves and changes in certain differentials. +50 +The following table presents net settlements and net change in fair value of unsettled commodity derivatives included in commodity price risk management, net: +Year Ended December 31, +2018 +2017 +2016 +(in millions) +Commodity price risk management gain (loss), net: +Net settlements of commodity derivative instruments: +Crude oil fixed price swaps and collars +$ +(139.7 +) +$ +(2.7 +) +$ +165.2 +Crude oil basis protection swaps +15.2 +— +— +Natural gas fixed price swaps and collars +(7.0 +) +19.5 +41.9 +Natural gas basis protection swaps +21.0 +3.8 +1.0 +NGLs (propane portion) fixed price swaps +(5.0 +) +(7.3 +) +— +Total net settlements of commodity derivative instruments +(115.5 +) +13.3 +208.1 +Change in fair value of unsettled commodity derivative instruments: +Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments +64.9 +44.8 +(220.0 +) +Crude oil fixed price swaps, collars and rollfactors +197.0 +(77.9 +) +(78.6 +) +Natural gas fixed price swaps and collars +1.4 +14.7 +(37.1 +) +Natural gas basis protection swaps +(2.6 +) +5.7 +1.9 +NGLs (propane portion) fixed price swaps +— +(4.6 +) +— +Net change in fair value of unsettled commodity derivative instruments +260.7 +(17.3 +) +(333.8 +) +Total commodity price risk management gain (loss), net +$ +145.2 +$ +(4.0 +) +$ +(125.7 +) +Lease Operating Expenses +Lease operating expenses increased 46 percent to $131.0 million in 2018 compared to $89.6 million in 2017 . The increase was primarily due to increases of $8.3 million for workover projects related to increased costs to plug and abandon wells in the Wattenberg Field, $5.7 million related to additional compressor and equipment rentals to combat high line pressures, $5.4 million in environmental remediation expense, $4.9 million related to midstream expense in the Delaware Basin, $4.9 million for payroll and employee benefits related to increases in headcount, $2.6 million related to produced water disposal expense and $1.2 million related to expense for non-operated wells. Lease operating expense per Boe increased by 16 percent to $3.26 for 2018 from $2.82 for 2017 . +Lease operating expenses were $89.6 million in 2017 compared to $60.0 million in 2016 . The $29.6 million increase in lease operating expenses in 2017 as compared to 2016 was primarily due to increases of $9.4 million for payroll and employee benefits related to increases in headcount, $5.6 million for produced water disposal, $5.6 million for increased workover projects, $3.9 million related to additional compressor rentals and $2.2 million for equipment rentals. The increases were slightly offset by a $1.5 million decrease in environmental remediation costs. Lease operating expense per Boe increased by four percent to $2.82 for 2017 from $2.70 for 2016 . +Production Taxes +Production taxes are comprised mainly of severance tax and ad valorem tax, are directly related to crude oil, natural gas and NGLs sales and are generally assessed as a percentage of net revenues. From time to time, there are adjustments to the statutory rates for these taxes based upon activity levels and relative commodity prices from year-to-year. +Production taxes increased 49 percent to $90.4 million in 2018 compared to $60.7 million in 2017 , primarily due to the 52 percent increase in crude oil, natural gas and NGLs sales for 2018 compared to 2017 , as well as an increase in the ad valorem tax rate in the Delaware Basin related to an increase in assessed property values. +Production taxes increased 93 percent to $60.7 million in 2017 compared to $31.4 million in 2016 , primarily due to the 84 percent increase in crude oil, natural gas and NGLs sales for 2017 compared to 2016 , as well as an increase in tax rates. +51 +Transportation, Gathering and Processing Expenses +Transportation, gathering and processing expenses increased 13 percent to $37.4 million in 2018 compared to 2017 and increased 80 percent in 2017 to $33.2 million compared to 2016 . Transportation, gathering and processing expenses are primarily impacted by the volumes delivered through pipelines and for natural gas gathering and transportation operations. The change in 2018 as compared to 2017 is further impacted by decreases resulting from the adoption of the New Revenue Standard and the disposition of the Utica Shale properties. As discussed in Crude Oil, Natural Gas and NGLs Pricing , whether transportation, gathering and processing costs are presented separately or are reflected as a reduction to net revenue is a function of the terms of the relevant marketing contract. +Exploration, Geologic and Geophysical Expense +The following table presents the major components of exploration, geologic and geophysical expense: +Year Ended December 31, +2018 +2017 +2016 +(in millions) +Exploratory dry hole costs +$ +0.1 +$ +41.3 +$ +— +Geological and geophysical costs +3.4 +3.9 +3.5 +Operating, personnel and other +2.7 +2.1 +1.2 +Total exploration expense +$ +6.2 +$ +47.3 +$ +4.7 +Exploratory dry hole costs. During 2017, two exploratory dry holes, associated lease costs and related infrastructure assets in the Delaware Basin were expensed at a cost of $41.3 million . The conclusion to expense these items was based on our determination that the acreage on which these wells was drilled was exploratory in nature and, following drilling, that the hydrocarbon production was insufficient for the wells to be deemed economically viable. +Geological and geophysical costs. Geological and geophysical costs in 2018, 2017 and 2016 were primarily related to the portion of the purchase of seismic data related to unproved acreage in the Delaware Basin. +Impairment of Properties and Equipment +The following table sets forth the major components of our impairments of properties and equipment expense: +Year Ended December 31, +2018 +2017 +2016 +(in millions) +Impairment of proved and unproved properties +$ +458.4 +$ +285.5 +$ +5.6 +Amortization of individually insignificant unproved properties +— +0.4 +1.4 +Land and buildings +— +— +3.0 +Total impairment of properties and equipment +$ +458.4 +$ +285.9 +$ +10.0 +Impairment of proved and unproved properties. Amounts represent the retirement or expiration of certain leases that are no longer part of our development plan or that we do not plan to extend and will allow to expire. Deterioration of commodity prices or other operating circumstances could result in additional impairment charges. +During 2018 , we recorded impairment charges totaling $458.4 million as we identified current and anticipated leasehold expirations within the Western Culberson County area of the Delaware Basin and made the determination that we would no longer pursue plans to develop these properties. The impaired non-focus leaseholds typically have a higher gas to oil ratio and a greater degree of geologic complexity than our other Delaware Basin properties. In 2019, we expect that we will allow approximately 18,300 gross (17,900 net) acres of our leaseholds in the Delaware Basin to expire. Of these leaseholds, we expect that approximately 9,500 gross and net acres and 8,600 gross (8,000 net) acres will expire in the first and third quarters, respectively, of 2019. Taking all expected 2019 expirations into account, we anticipate ending 2019 with approximately 40,100 gross (33,500 net) acres in the Delaware Basin. In 2020, we expect that we will allow approximately 3,400 gross (1,800 net) +52 +acres of our leaseholds in the Delaware Basin to expire. We are currently exploring strategic alternatives with respect to the acres expected to expire in 2019 and 2020 and believe that we may be able to monetize a portion of this acreage. +During 2017, we recorded a charge related to two exploratory dry holes we had drilled in the western area of our Culberson County acreage in the Delaware Basin, as referenced previously. We then assessed the impact of the dry holes and various factors related thereto, including the operational and geologic data obtained, the current increased cost environment for drilling and completion services in the Delaware Basin, our future commodity price outlook and the terms of the related lease agreements. Based on the results of this assessment, we concluded that the underlying geologic risk and the challenged economics of future capital expenditures reduced the likelihood that we would perform future development in this area over the remaining lease term for this acreage. Accordingly, we recorded an impairment of $251.6 million covering approximately 13,400 acres during 2017. The amount of the impairment was based on the value assigned to individual lease acres in the final purchase price allocation of our Delaware Basin acquisition. This allocation included the consideration paid to the sellers, including the effect of the non-cash impact from the deferred tax liability created at the time of the acquisition. We recorded approximately $29 million of additional lease impairments in the Delaware Basin and an impairment charge of $2.1 million related to the Utica Shale Divestiture. Due to the aforementioned events and circumstances, we also evaluated our proved property for possible impairment and concluded that no further impairments were necessary at that time. +Impairment of Goodwill +During 2017 , we recorded goodwill impairment charges of $75.1 million resulting from the purchase price allocation of the assets acquired in the Delaware Basin. The impairment was primarily due to a combination of increases in per well development and operational costs and our drilling of two exploratory dry holes in the Delaware Basin subsequent to the acquisition. In conjunction with our then-current lower future commodity price outlook, we determined that a triggering event had occurred in the quarter ended September 30, 2017. +General and Administrative Expense +General and administrative expense increased 42 percent to $170.5 million in 2018 compared to 2017 . The increase was primarily attributable to a $16.1 million increase in payroll and employee benefits, a $14.0 million increase in legal related costs, a $9.2 million increase in government relations expenses and a $6.3 million increase related to professional services. These increases were partially offset by a $0.9 million decrease related to environmental matters. +General and administrative expense increased seven percent to $120.4 million in 2017 compared to 2016 . The increase was primarily attributable to an $8.1 million increase in payroll and employee benefits, a $4.4 million increase related to professional services, a $4.2 million increase in legal related costs, a $1.4 million increase in software licenses and subscriptions and a $1.3 million increase for the rental of additional office space. The increases were partially offset by the $12.2 million of legal and professional fees related to the acquisition in the Delaware Basin that were incurred in 2016. +53 +Depreciation, Depletion and Amortization +Crude oil and natural gas properties. During 2018 , 2017 and 2016 , we invested $982.7 million, $788.0 million and $396.4 million , net of changes in accounts payable related to capital expenditures, in the development of our crude oil and natural gas properties, respectively. DD&A expense related to crude oil and natural gas properties is directly related to proved reserves and production volumes. DD&A expense related to crude oil and natural gas properties was $551.3 million , $462.5 million and $413.1 million in 2018 , 2017 and 2016 , respectively. The year-over-year changes in DD&A expense related to crude oil and natural gas properties were primarily due to the following: +Year Ended December 31, +2018 - 2017 +2017 - 2016 +(in millions) +Increase in production +$ +127.9 +$ +144.7 +Decrease in weighted-average depreciation, depletion and amortization rates +(39.1 +) +(95.3 +) +Total increase in DD&A expense related to crude oil and natural gas properties +$ +88.8 +$ +49.4 +The following table presents our DD&A expense rates for crude oil and natural gas properties: +Year Ended December 31, +Operating Region/Area +2018 +2017 +2016 +(per Boe) +Wattenberg Field +$ +12.58 +$ +14.67 +$ +19.11 +Delaware Basin (1) +17.70 +14.89 +8.34 +Utica Shale (2) +— +8.09 +10.66 +Total weighted-average +13.73 +14.53 +18.63 +____________ +(1) The 2016 Delaware Basin rate represents one month of DD&A expense. Accordingly, the comparisons of the 2018 and 2017 +rates to the 2016 rate are not meaningful. +(2) The Utica Shale properties were classified as held-for-sale during the third quarter of 2017; therefore, we did not record +DD&A expense on these properties in 2018. In March 2018, we completed the disposition of our Utica Shale properties. +Provision for Uncollectible Notes Receivable +In 2016, we recorded a provision for uncollectible notes receivable of $44.0 million to impair two third-party notes receivable whose collection was not reasonably assured. In April 2017, we signed a definitive agreement and simultaneously closed on the sale of one of the associated notes receivable to an unrelated third-party for $40.2 million . Accordingly, we reversed $40.2 million of the provision for uncollectible notes receivable during 2017. +Accretion of Asset Retirement Obligations +Accretion of asset retirement obligations for 2018 decreased 20 percent to $5.1 million compared to 2017 , and decreased 11 percent in 2017 to $6.3 million compared to 2016 . The decreases in 2018 and 2017 were due to the replacement of vertical wells that have been plugged and abandoned with horizontal wells, which have a longer expected life. +54 +Interest Expense +Interest expense decreased by $8.0 million to $70.7 million in 2018 compared to $78.7 million in 2017 . The decrease was primarily related to a $38.1 million decrease in interest expense relating to the net settlement of previously outstanding senior notes in December 2017 and a $4.2 million increase in capitalized interest. The decreases were partially offset by a $32.2 million increase in interest expense related to the issuance of our 2026 Senior Notes in November 2017 and a $1.7 million increase in interest related to our revolving credit facility. +Interest expense increased by approximately $16.7 million to $78.7 million in 2017 compared to $62.0 million in 2016 . The increase is primarily attributable to an $18.0 million increase in interest for the issuance of our 2024 Senior Notes, a $7.4 million increase in interest expense for the issuance of $200 million principal amount of our 1.125% convertible notes due 2021 (the "2021 Convertible Notes") in September 2016, a $3.1 million increase in interest expense for the issuance of our 2026 Notes in November 2017 and a $3.0 million increase in the utilization fee of our revolving credit facility. The increases were partially offset by a $9.3 million charge for a bridge loan commitment related to the 2016 acquisition of properties in the Delaware Basin, a $3.5 million decrease in interest expense resulting from the net settlement of our 2016 Convertible Notes in May 2016 and a $1.8 million decrease in interest expense resulting from the net settlement of our 2022 Notes in December 2017. +Interest costs capitalized in 2018 , 2017 and 2016 were $9.2 million , $5.0 million and $4.5 million , respectively. +Loss on Extinguishment of Debt +The $24.7 million loss on extinguishment of debt relates to the redemption of the 2022 Senior Notes during the fourth quarter of 2017. The loss consists of a $19.4 million make-whole premium and the write-off of unamortized debt issuance costs of $5.4 million . +Provision for Income Taxes +Current income tax (expense) benefit in 2018, 2017 and 2016 was $0.7 million, $8.2 million and $9.9 million, respectively. Current income taxes generally relate to the cash that is paid or recovered for income taxes associated with the applicable period. The remaining portion of the total income tax provision is comprised of deferred income taxes, which are a result of differences in the timing of deductions from our U.S. GAAP presentation of financial statements and the income tax regulations. +Our effective income tax rates for 2018, 2017 and 2016 were 72.8 percent , 62.4 percent and 37.4 percent , respectively, on income (loss) from operations. +The 2018 rate differs from the federal statutory tax rate primarily due to state taxes, federal tax credits, valuation allowance for state tax attributes and nondeductible expenses that consist primarily of officers' compensation cost and government lobbying expenses. +The 2017 rate differs from the federal statutory rate primarily due to the reduction in the federal corporate income tax rate resulting from the 2017 Tax Cuts & Jobs Act ("The 2017 Act"), which increased the tax benefit rate by 33.7 percent. Additionally, the nondeductible goodwill impairment charge in 2017 reduced the 2017 tax rate by 7.7 percent. The 2017 tax rate was also impacted by state taxes. +The 2016 rate differs from the federal statutory tax rate, primarily due to state taxes and excess tax benefit from stock compensation, offset by nondeductible expenses that consist primarily of officers' compensation and government lobbying expenses. +As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions. We continue to voluntarily participate in the Internal Revenue Service’s ("IRS") Compliance Assurance Program (the "CAP Program") for the 2018 and 2019 tax years. We have received a partial acceptance notice from the IRS for our filed 2017 federal tax return and the IRS's post filing review is currently ongoing. +Net Income (Loss)/Adjusted Net Income (Loss) +The factors resulting in changes in net income in 2018 and net loss in 2017 and 2016 are discussed above. These same reasons similarly impacted adjusted net income (loss), a non-U.S. GAAP financial measure, with the exception of the net +55 +change in fair value of unsettled derivatives, adjusted for taxes, of $198.3 million , $13.1 million and $208.9 million in 2018 , 2017 and 2016 , respectively. Adjusted net loss, a non-U.S. GAAP financial measure, was $196.3 million , $114.4 million and $37.0 million in 2018 , 2017 and 2016 respectively. See Reconciliation of Non-U.S. GAAP Financial Measures , below, for a more detailed discussion of this non-U.S. GAAP financial measure. +Financial Condition, Liquidity and Capital Resources +Our primary sources of liquidity are cash flows from operating activities, our revolving credit facility, proceeds from debt and equity capital market transactions and asset sales. In 2018 , our net cash flows from operating activities were $889.3 million . +Our primary source of cash flows from operating activities is the sale of crude oil, natural gas and NGLs. Fluctuations in our operating cash flows are principally driven by commodity prices and changes in our production volumes. Commodity prices have historically been volatile and we manage a portion of this volatility through our use of derivative instruments. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the instrument. Our revolving credit facility imposes limits on the amount of our production we can hedge, and we may choose not to hedge the maximum amounts permitted. Therefore, we may still have fluctuations in our cash flows from operating activities due to the remaining non-hedged portion of our future production. Due to a decreasing leverage ratio that we have recently experienced, the percentage of our expected future production that we currently have hedged is lower than we have historically maintained and we anticipate that this may remain the case in the near future. +Our working capital fluctuates for various reasons, including, but not limited to, changes in the fair value of our commodity derivative instruments and changes in our cash and cash equivalents due to our practice of utilizing excess cash to reduce the outstanding borrowings under our revolving credit facility. At December 31, 2018 , we had a working capital deficit of $166.6 million compared to a working capital deficit of $16.4 million at December 31, 2017 . The decrease in working capital as of December 31, 2018 is primarily the result of a decrease in cash and cash equivalents of $ 179.3 million related to the Bayswater Asset Acquisition, partially offset by an increase in accounts payable of $ 31.8 million related to increased development and exploration activity. +Our cash and cash equivalents were $1.4 million at December 31, 2018 and availability under our revolving credit facility was $1.3 billion , providing for total liquidity of $1.3 billion as of December 31, 2018 . Assuming a NYMEX crude oil price of $50.00 , we expect cash flows from operations to exceed our capital investments in crude oil and natural gas properties in 2019 by approximately $25.0 million . We anticipate that capital investments will exceed cash flows from operations during the first half of 2019 and expect cash flows from operations to exceed capital investment during the remainder of the year. Our leverage ratio, as defined in our revolving credit facility agreement, is currently expected to decrease to approximately 1.3 by the end of 2019 based on anticipated production and $50.00 to $55.00 NYMEX crude oil prices. +We are in the process of actively marketing our Delaware Basin crude oil gathering, natural gas gathering and produced water gathering and disposal assets for sale and currently expect to execute agreements for the sales of these assets in the first half of 2019. We anticipate making capital investments for midstream assets during 2019, a portion of which would be made prior to such anticipated sales depending on the timing of the divestitures. We expect that we would recover a portion of these expenditures upon settlement of the final sale prices. +Based on our expected cash flows from operations, our cash and cash equivalents and availability under our revolving credit facility, we believe that we will have sufficient capital available to fund our planned activities through the 12-month period following the filing of this report. +Our revolving credit facility is available for working capital requirements, capital investments, acquisitions, to support letters of credit and for general corporate purposes. The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.0:1.0 and (b) not exceed a maximum leverage ratio of 4.0:1.0. At December 31, 2018 , we were in compliance with all covenants in the revolving credit facility with a current ratio of 3.3 :1.0 and a leverage ratio of 1.4 :1.0. We expect to remain in compliance throughout the 12-month period following the filing of this report. +56 +The indentures governing our 2024 Senior Notes and 2026 Senior Notes contain customary restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (a) incur additional debt including under our revolving credit facility, (b) make certain investments or pay dividends or distributions on our capital stock or purchase, redeem or retire capital stock, (c) sell assets, including capital stock of our restricted subsidiaries, (d) restrict the payment of dividends or other payments by restricted subsidiaries to us, (e) create liens that secure debt, (f) enter into transactions with affiliates and (g) merge or consolidate with another company. See the footnote titled Long-Term Debt to the accompanying consolidated financial statements included elsewhere in this report for more information regarding our revolving credit facility. +Cash Flows +Operating Activities. Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes, net settlements from our commodity derivative positions, operating costs and general and administrative expenses. Cash flows provided by operating activities increased by $291.5 million to $889.3 million in 2018 as compared to 2017 , primarily due to the increase in crude oil, natural gas and NGLs sales of $476.9 million and an increase in changes in assets and liabilities of $ 65.1 million . The increases were partially offset by a decrease in derivative commodity settlements of $128.9 million and increases in general and administrative expense of $50.1 million , lease operating expenses of $41.3 million and production taxes of $29.6 million . +Cash flows provided by operating activities increased by $111.6 million to $597.8 million in 2017 as compared to 2016 , primarily due to the increase in crude oil, natural gas, and NGLs sales of $415.7 million. The increase was partially offset +by a decrease in derivative commodity settlements of $194.8 million and increases in lease operating expenses of $29.7 million, +production taxes of $29.3 million, interest expense of $16.7 million, transportation, gathering, and processing expenses of +$14.8 million, and increases in general and administrative expense of $7.9 million as well as a decrease in changes in assets +and liabilities of $13.0 million. +Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased by $226.3 million in 2018 to $808.4 million , and increased by $115.3 million in 2017 to $582.1 million , when compared to the respective prior years. These changes were primarily due to the same factors mentioned above for changes in cash flows provided by operating activities, without regard to changes in assets and liabilities. +Adjusted EBITDAX, a non-U.S. GAAP financial measure, increased by $186.2 million in 2018 to $868.3 million from $682.1 million in 2017 , primarily as the result of the increase in crude oil, natural gas and NGLs sales of $476.9 million . This increase was partially offset by a decrease in derivative commodity settlements of $128.9 million , an increase in general and administrative expense of $50.1 million , an increase in lease operating expenses of $41.3 million , the sale of the note described below in 2017 to a third-party for $40.2 million, and an increase in production taxes of $29.6 million . +Adjusted EBITDAX, a non-U.S. GAAP financial measure, increased by $222.3 million in 2017 to $682.1 million +from $459.8 million in 2016, primarily as the result of the increase in crude oil, natural gas, and NGLs sales of $415.7 million, +as well as the recording of a provision for a note receivable in 2016 of $44.0 million and the subsequent sale of the note in +2017 to a third-party for $40.2 million. The increase was partially offset by a decrease in derivative commodity settlements of +$194.8 million, and increases in lease operating expenses of $29.7 million, production taxes of $29.3 million, interest expense +of $16.7 million, transportation, gathering, and processing expenses of $14.8 million, and general and administrative expense +of $7.9 million. +See Item 7. Reconciliation of Non-U.S. GAAP Financial Measures for a reconciliation of our U.S. GAAP to non-U.S. GAAP financial measures. +Investing Activities. Because crude oil and natural gas production from a well declines rapidly in the first few years of production, we continue to invest significant amounts of capital in order to maintain and grow our production and replace our reserves. If capital markets are not available in the future, we will be limited to our cash flows from operations and liquidity under our revolving credit facility as the sources for funding our capital investments. +Cash flows from investing activities primarily consist of the acquisition, exploration and development of crude oil and natural gas properties, net of dispositions of crude oil and natural gas properties. Net cash used in investing activities of $1.1 billion during 2018 was primarily related to the purchase price of the Bayswater Asset Acquisition of $179.0 million and our drilling operations, including completion activities, of $946.4 million . Partially offsetting these investments was the receipt of approximately $39.0 million related to the divestiture of our Utica Shale properties. +57 +Net cash used in investing activities during 2017 of $717.0 million was primarily related to cash utilized for our drilling operations, including completion activities of $737.2 million , a $21.0 million deposit toward the Bayswater Asset Acquisition, purchases of short-term investments of $49.9 million and a $9.3 million deposit with a third-party transportation service provider for surety of an existing firm transportation obligation. Partially offsetting these investments was the receipt of approximately $49.9 million related to the sale of short-term investments, $40.2 million from the sale of a promissory note and $5.4 million related to post-closing settlements of properties acquired in 2016. +Net cash used in investing activities during 2016 of $1.5 billion was primarily related to cash utilized for our acquisition in the Delaware Basin of $1.1 billion and $436.9 million for our drilling operations. +Financing Activities. Net cash from financing activities in 2018 of $18.1 million was comprised of net borrowings from our credit facility of $32.5 million, partially offset by $7.7 million of debt issuance costs and $5.1 million related to purchases of our stock. +Net cash from financing activities in 2017 of $65.0 million was primarily related to $592.4 million of net proceeds from issuance of the 2026 Senior Notes, partially offset by the $519.4 million used to redeem our 2022 Senior Notes. +Net cash from financing activities in 2016 of $1.3 billion was primarily related to the $855.1 million of net proceeds received from the issuance of 9.4 million shares of our common stock, $392.2 million of net proceeds from issuance of the 2024 Senior Notes and $193.9 million of net proceeds from issuance of the 2021 Convertible Notes, partially offset by the $115.0 million payment upon the maturity of the 2016 Convertible Notes and net payments of approximately $37.0 million to pay down amounts borrowed under our revolving credit facility. +58 +Contractual Obligations and Contingent Commitments +The following table presents our contractual obligations and contingent commitments as of December 31, 2018 : +Payments due by period +Less than +1-3 +3-5 +More than +Contractual Obligations and Contingent Commitments +Total +1 year +years +years +5 years +(in millions) +Long-term liabilities reflected on the consolidated balance sheet (1) +Long-term debt (2) +$ +1,233 +$ +— +$ +200 +$ +33 +$ +1,000 +Commodity derivative contracts (3) +5 +3 +2 +— +— +Production tax liability +122 +61 +61 +— +— +Deferred oil gathering credit +24 +2 +5 +5 +12 +Asset retirement obligations +111 +26 +39 +39 +7 +Other liabilities (4) +10 +3 +5 +1 +1 +1,505 +95 +312 +78 +1,020 +Commitments, contingencies and other arrangements (5) +Interest on long-term debt (6) +457 +67 +135 +127 +128 +Operating leases +28 +6 +13 +7 +2 +Firm transportation and processing agreements (7) +430 +107 +152 +124 +47 +915 +180 +300 +258 +177 +Total +$ +2,420 +$ +275 +$ +612 +$ +336 +$ +1,197 +__________ +(1) +Table does not include deferred income tax liability to taxing authorities of $198.1 million due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. +(2) +Amount presented does not agree with the consolidated balance sheets in that it excludes $22.8 million of unamortized debt discount and $14.9 million of unamortized debt issuance costs. +(3) +Represents our gross liability related to the fair value of derivative positions. +(4) +Includes deferred compensation to former executive officers, deferred payments related to firm transportation agreements and capital leases. +(5) +The table does not include termination benefits related to employment agreements with our executive officers, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. +(6) +Amounts presented include $276.0 million to the holders of our 2026 Senior Notes, $147.0 million to the holders of our 2024 Senior Notes and $6.8 million payable to the holders of our 2021 Convertible Notes. Amounts also include interest of $21.0 million related to unutilized commitments at a rate of 0.375 percent per annum. +(7) +Represents our gross commitment which includes volumes produced by us, purchased from third parties and produced by our affiliated partnerships and other third-party working, royalty and overriding royalty interest owners whose volumes we market on their behalf. This includes anticipated and estimated commitments associated with two new gas processing facilities by our primary mid-stream provider. The timing of such payments has been estimated and is subject to change based on the completion of construction and the commencement of operations by the midstream provider. +From time to time, we are a party to various legal proceedings in the ordinary course of business. We are not currently a party to any litigation that we believe would have a materially adverse effect on our business, financial condition, results of operations or liquidity. Information regarding our legal proceedings can be found in the footnote titled Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere in this report. +Critical Accounting Policies and Estimates +We have identified the following policies as critical to business operations and the understanding of our results of operations. This is not a comprehensive list of all of the accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by U.S. GAAP, with no need for our judgment in the application. There are also areas in which our judgment in selecting available alternatives would not produce a materially different result. However, certain of our accounting policies are particularly important to the presentation of our financial position and results of operations and we may use significant judgment in their application. As a result, they are subject to an inherent degree of uncertainty. In applying those policies, we use our judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on historical experience, observation of trends in the industry and information available from other outside sources, as appropriate. For a more detailed discussion on the application of these and other +59 +accounting policies, see the footnote titled Summary of Significant Accounting Policies to our consolidated financial statements included elsewhere in this report. +Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. +Annually, we engage independent petroleum engineers to prepare reserve and economic evaluations of all our properties on a well-by-well basis as of December 31. We adjust our crude oil and natural gas reserves for major acquisitions, new drilling and divestitures during the year as needed. The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. Although every reasonable effort is made to ensure that reserve estimates reported represent our most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect our DD&A expense, a change in our estimated reserves could have an effect on our net income (loss). +Exploration costs, including geological and geophysical expenses, the acquisition of seismic data covering unproved acreage and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but are charged to expense if the well is determined to be nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as the well has found a sufficient quantity of reserves to justify completion as a producing well and we are making sufficient progress assessing our reserves and economic and operating viability. If an in-progress exploratory well is found to be unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the well is classified as a "suspended well" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time when we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the proper accounting treatment is applied. +Acquisition costs of unproved properties are capitalized when incurred until such properties are transferred to proved properties or charged to expense. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed, and any impairment in value is charged to impairment of crude oil and natural gas properties. The amount of impairment recognized on unproved properties which are not individually significant is determined by amortizing the costs of such properties within appropriate fields based on our historical experience, acquisition dates and average lease terms, with the amortization recognized in impairment of properties and equipment. The valuation of unproved properties is subjective and requires us to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values. +We assess our crude oil and natural gas properties for possible impairment annually, or upon a triggering event, by comparing carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production and prices at which we reasonably estimate the commodities will be sold. Any impairment in value is charged to impairment of properties and equipment. The estimates of future prices may differ from current market prices of crude oil and natural gas. Any downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs could result in a triggering event, and therefore, a reduction in undiscounted future net cash flows and an impairment of our crude oil and natural gas properties. Although our cash flow estimates are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. +Crude Oil, Natural Gas and NGLs Sales Revenue Recognition. Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of crude oil, natural gas, or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on +60 +the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. If a sale is deemed uncollectible, an allowance for doubtful collection is recorded. +Fair Value of Financial Instruments. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. +Commodity Derivative Financial Instruments. We measure the fair value of our commodity derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of commodity derivative liabilities and the effect of our counterparties' credit standings on the fair value of commodity derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding commodity derivative position. +We validate our fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. +Net settlements on our commodity derivative instruments are initially recorded to accounts receivable or payable, as applicable, and may not be received from or paid to counterparties to our commodity derivative contracts within the same accounting period. Such settlements typically occur the month following the maturity of the commodity derivative instrument. We have evaluated the credit risk of the counterparties holding our commodity derivative assets, which are primarily financial institutions who are also major lenders in our revolving credit facility, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding commodity derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our counterparties on the fair value of our commodity derivative instruments is not significant. +Deferred Income Tax Asset Valuation Allowance. Deferred income tax assets are recognized for deductible temporary differences, net operating loss carry-forwards and credit carry-forwards if it is more likely than not that the tax benefits will be realized. To the extent a deferred tax asset is not expected to be realized under the preceding criteria, we establish a valuation allowance. The factors which we consider in assessing whether we will realize the value of deferred income tax assets involve judgments and estimates of both amount and timing. The judgments used in applying these policies are based on our evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results may differ from those estimates. +Accounting for Business Combinations. We utilize the purchase method to account for acquisitions of businesses and assets. The value of the purchase consideration takes into account the degree to which the consideration is objective and measurable such as cash consideration paid to a seller. With the issuance of equity, restrictions upon the sale of the issued stock are taken into consideration. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. The purchase price allocations are based on appraisals, discounted cash flows, quoted market prices and estimates by management. When appropriate, we review comparable +61 +purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value as such sales represent the amount at which a willing buyer and seller would enter into an exchange for such properties. +In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped and unproved crude oil and natural gas properties and other non-crude oil and natural gas properties. To estimate the fair values of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of comparable purchased properties to determine an estimation of fair value. +If applicable, we record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. +Acreage Exchanges . From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and providing us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges of non-producing interests and unproved mineral leases in accordance with the guidance prescribed by Accounting Standards Codification 845, Nonmonetary Transactions . For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized in earnings, in accordance with Accounting Standards Codification 820, Fair Value Measurement . +Recent Accounting Standards +See the footnote titled Summary of Significant Accounting Policies - Recently Adopted Accounting Standards to our consolidated financial statements included elsewhere in this report. +Reconciliation of Non-U.S. GAAP Financial Measures +We use "adjusted cash flows from operations," "adjusted net income (loss)" and "adjusted EBITDAX," non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and, in some cases, providing public guidance on possible future results. These measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss) or cash flows from operations, investing or financing activities and should not be viewed as liquidity measures or indicators of cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. Also, in the future, we may disclose different non-U.S. GAAP financial measures in order to help our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and not rely on any single financial measure. +Adjusted cash flows from operations. We define adjusted cash flows from operations as the cash flows earned or incurred from operating activities, without regard to changes in operating assets and liabilities. We believe it is important to consider adjusted cash flows from operations, as well as cash flows from operations, as we believe it often provides more transparency into what drives the changes in our operating trends, such as production, prices, operating costs and related operational factors, without regard to whether the related asset or liability was received or paid during the same period. We also use this measure because the timing of cash received from our assets, cash paid to obtain an asset or payment of our obligations has generally been a timing issue from one period to the next as we have not had significant accounts receivable collection problems, nor been unable to purchase assets or pay our obligations. +Adjusted net income (loss). We define adjusted net income (loss) as net income (loss), plus loss on commodity derivatives, less gain on commodity derivatives and net settlements on commodity derivatives, each adjusted for tax effect. We +62 +believe it is important to consider adjusted net income (loss), as well as net income (loss). We believe this measure often provides more transparency into our operating trends, such as production, prices, operating costs, net settlements from derivatives and related factors, without regard to changes in our net income (loss) from our mark-to-market adjustments resulting from net changes in the fair value of unsettled derivatives. Additionally, other items which are not indicative of future results may be excluded to clearly identify operating trends. +Adjusted EBITDAX. We define adjusted EBITDAX as net income (loss), plus loss on commodity derivatives, interest expense, net of interest income, income taxes, impairment of properties and equipment, exploration, geologic and geophysical expense, depreciation, depletion and amortization expense, accretion of asset retirement obligations and non-cash stock-based compensation, less gain on commodity derivatives and net settlements on commodity derivatives. Adjusted EBITDAX is not a measure of financial performance or liquidity under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss), and should not be considered an indicator of cash flows reported in accordance with U.S. GAAP. Adjusted EBITDAX includes certain non-cash costs incurred by us and does not take into account changes in operating assets and liabilities. Other companies in our industry may calculate adjusted EBITDAX differently than we do, limiting its usefulness as a comparative measure. We believe adjusted EBITDAX is relevant because it is a measure of our operational and financial performance, as well as a measure of our liquidity, and is used by our management, investors, commercial banks, research analysts, and others to analyze such things as: +• +operating performance and return on capital as compared to our peers; +• +financial performance of our assets and our valuation without regard to financing methods, capital structure or historical cost basis; +• +our ability to generate sufficient cash to service our debt obligations; and +• +the viability of acquisition opportunities and capital expenditure projects, including the related rate of return. +PV-10. We define PV-10 as the estimated present value of the future net cash flows from our proved reserves before income taxes, discounted using a 10 percent discount rate. We believe that PV-10 provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. We believe that PV-10 is relevant and useful for evaluating the relative monetary significance of our reserves. Professional analysts, investors and other users of our financial statements may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies' reserves. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable in evaluating us and our reserves. PV-10 is not intended to represent the current market value of our estimated reserves. +63 +The following table presents a reconciliation of our non-U.S. GAAP financial measures to its most comparable U.S. GAAP measure: +Year Ended December 31, +2018 +2017 +2016 +(in millions) +Adjusted cash flows from operations: +Net cash from operating activities +$ +889.3 +$ +597.8 +$ +486.3 +Changes in assets and liabilities +(80.9 +) +(15.7 +) +(19.5 +) +Adjusted cash flows from operations +$ +808.4 +$ +582.1 +$ +466.8 +Adjusted net loss: +Net income (loss) +$ +2.0 +$ +(127.5 +) +$ +(245.9 +) +(Gain) loss on commodity derivative instruments +(145.2 +) +3.9 +125.7 +Net settlements on commodity derivative instruments +(115.5 +) +13.3 +208.1 +Tax effect of above adjustments +62.4 +(4.1 +) +(124.9 +) +Adjusted net loss +$ +(196.3 +) +$ +(114.4 +) +$ +(37.0 +) +Net income (loss) to adjusted EBITDAX: +Net income (loss) +$ +2.0 +$ +(127.5 +) +$ +(245.9 +) +(Gain) loss on commodity derivative instruments +(145.2 +) +3.9 +125.7 +Net settlements on commodity derivative instruments +(115.5 +) +13.3 +208.1 +Non-cash stock-based compensation +21.8 +19.4 +19.5 +Interest expense, net +70.3 +76.4 +61.0 +Income tax expense (benefit) +5.4 +(211.9 +) +(147.2 +) +Impairment of properties and equipment +458.4 +285.9 +10.0 +Impairment of goodwill +— +75.1 +— +Exploration, geologic and geophysical expense +6.2 +47.3 +4.7 +Depreciation, depletion and amortization +559.8 +469.1 +416.9 +Accretion of asset retirement obligations +5.1 +6.4 +7.0 +Loss on extinguishment of debt +— +24.7 +— +Adjusted EBITDAX +$ +868.3 +$ +682.1 +$ +459.8 +Cash from operating activities to adjusted EBITDAX: +Net cash from operating activities +$ +889.3 +$ +597.8 +$ +486.3 +Interest expense, net +70.3 +76.4 +61.0 +Amortization of debt discount and issuance costs +(12.8 +) +(12.9 +) +(16.2 +) +Gain (loss) on sale of properties and equipment +(0.4 +) +0.7 +— +Exploration, geologic and geophysical expense +6.2 +47.3 +4.7 +Exploratory dry hole expense +(0.1 +) +(41.3 +) +— +Other +(3.3 +) +29.8 +(56.5 +) +Changes in assets and liabilities +(80.9 +) +(15.7 +) +(19.5 +) +Adjusted EBITDAX +$ +868.3 +$ +682.1 +$ +459.8 +PV-10: +PV-10 +$ +5,321.3 +$ +3,212.0 +$ +1,675.0 +Present value of estimated future income tax discounted at 10% +(873.6 +) +(331.9 +) +(254.4 +) +Standardized measure of discounted future net cash flows +$ +4,447.7 +$ +2,880.1 +$ +1,420.6 +64 +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Market-Sensitive Instruments and Risk Management +We are exposed to market risks associated with interest rate risks, commodity price risk and credit risk. We have established risk management processes to monitor and manage these market risks. +Interest Rate Risk +Changes in interest rates affect the amount of interest we earn on our interest bearing cash and cash equivalents and the interest we pay on borrowings under our revolving credit facility. Our 2021 Convertible Notes, 2024 Senior Notes and 2026 Senior Notes have fixed rates and, therefore, near-term changes in interest rates do not expose us to risk of earnings or cash flow loss; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt. +As of December 31, 2018 , our interest-bearing deposit accounts included money market accounts and checking accounts with various banks. The amount of our interest-bearing cash and cash equivalents as of December 31, 2018 was $ 0.6 million , with a weighted-average interest rate of one percent. Based on a sensitivity analysis of our interest bearing deposits as of December 31, 2018 and assuming we had $ 0.6 million outstanding throughout the period, we estimate that a one percent increase in interest rates would not have a material impact on interest income for the twelve months ended December 31, 2018 . +As of December 31, 2018 , we had $ 32.5 million outstanding balance on our revolving credit facility. If market interest rates would have decreased by one percent, our interest expense for the twelve months ended December 31, 2018 would have decreased by approximately $ 0.3 million . If market interest rates would have increased by one percent, our interest expense for the twelve months ended December 31, 2018 would have increased by approximately $ 0.2 million . +Commodity Price Risk +We are exposed to the potential risk of loss from adverse changes in the market price of crude oil, natural gas and NGLs. Pursuant to established policies and procedures, we manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. These instruments help us predict with greater certainty the effective crude oil, natural gas and propane prices we will receive for our hedged production. We believe that our commodity derivative policies and procedures are effective in achieving our risk management objectives. +Our realized prices vary regionally based on local market differentials and our transportation agreements. The following table presents average market index prices for crude oil and natural gas for the periods identified, as well as the average sales prices we realized for our crude oil, natural gas and NGLs production: +Year Ended December 31, +2018 +2017 +Average NYMEX Index Price: +Crude oil (per Bbl) +NYMEX +$ +64.77 +$ +50.95 +Natural gas (per MMBtu) +NYMEX +$ +3.09 +$ +3.11 +Average Sales Price Realized: +Excluding net settlements on commodity derivatives +Crude oil (per Bbl) +$ +61.19 +$ +48.45 +Natural gas (per Mcf) +1.85 +2.21 +NGLs (per Bbl) +22.14 +18.59 +Based on a sensitivity analysis as of December 31, 2018 , we estimate that a 10 percent increase in natural gas, crude oil prices and the propane portion of NGLs prices, inclusive of basis, over the entire period for which we have commodity derivatives in place would have resulted in a decrease in the fair value of our derivative positions of $63.1 million, whereas a 10 percent decrease in prices would have resulted in an increase in fair value of $63.9 million. +65 +Credit Risk +Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure and entering into transactions with high-quality counterparties. When exposed to significant credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We monitor the creditworthiness of significant counterparties through our credit committee, which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. While we believe that our credit risk analysis and monitoring procedures are reasonable, no amount of analysis can assure financial performance by our counterparties. +Our oil and gas exploration and production business's crude oil, natural gas and NGLs sales are concentrated with a few predominately large customers. This concentrates our credit risk exposure with a small number of large customers. +Amounts due to our gas marketing business are from a diverse group of entities. The underlying operations of these entities are geographically concentrated in the same region, which increases the credit risk associated with this business. As natural gas prices continue to remain depressed, certain third-party producers committed to providing natural gas to our gas marketing business continue to experience financial distress, which has led to certain contractual defaults and litigation; however, to date, we have had no material counterparty default losses. We have initiated several legal actions for breach of contract and collection claims against certain third-party producers that are delinquent in their payment obligations. We expect this trend to continue for this business segment. +We primarily use financial institutions which are lenders in our revolving credit facility as counterparties for our derivative financial instruments. Disruption in the credit markets, changes in commodity prices and other factors may have a significant adverse impact on a number of financial institutions. To date, we have had no material counterparty default losses from our commodity derivative financial instruments. See the footnote titled Commodity Derivative Financial Instruments to our consolidated financial statements included elsewhere in this report for more detail on our commodity derivative financial instruments. +Disclosure of Limitations +Because the information above included only those exposures that existed at December 31, 2018 , it does not consider those exposures or positions which could arise after that date. Our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, our commodity price risk management strategies at the time and interest rates and commodity prices at the time. +66 +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Index to Consolidated Financial Statements, Financial Statement Schedule and Supplemental Information +Financial Statements: +Report of Independent Registered Public Accounting Firm +68 +Consolidated Balance Sheets - December 31, 2018 and 2017 +70 +Consolidated Statements of Operations - Years Ended December 31, 2018, 2017 and 2016 +71 +Consolidated Statements of Cash Flows - Years Ended December 31, 2018, 2017 and 2016 +72 +Consolidated Statements of Equity - Years Ended December 31, 2018, 2017 and 2016 +73 +Notes to Consolidated Financial Statements +74 +Supplemental Information - Unaudited: +Crude Oil and Natural Gas Information +115 +Quarterly Financial Information +123 +Financial Statement Schedule: +Schedule II - Valuation and Qualifying Accounts - Years Ended December 31, 2018, 2017 and 2016 +124 +67 +Report of Independent Registered Public Accounting Firm +To the Board of Directors and Shareholders of PDC Energy, Inc. +Opinions on the Financial Statements and Internal Control over Financial Reporting +We have audited the accompanying consolidated balance sheets of PDC Energy, Inc. and its subsidiaries (the “Company”) as of December 31, 2018 and 2017 , and the related consolidated statements of operations, equity and cash flows for each of the three years in the period ended December 31, 2018 , including the related notes and financial statement schedule listed in the accompanying index (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2018 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2018 and 2017 , and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2018 based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO because material weaknesses in internal control over financial reporting existed as of that date related to not maintaining a sufficient complement of personnel within the Land Department as a result of an increased volume of leases, which contributed to the ineffective design and maintenance of controls to verify the completeness and accuracy of land administrative records associated with unproved leases. +A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. The material weaknesses referred to above are described in Management's Report on Internal Control over Financial Reporting appearing under Item 9A. We considered these material weaknesses in determining the nature, timing, and extent of audit tests applied in our audit of the 2018 consolidated financial statements, and our opinion regarding the effectiveness of the Company’s internal control over financial reporting does not affect our opinion on those consolidated financial statements. +Change in Accounting Principle +As discussed in Note 2 to the consolidated financial statements, the Company changed the manner in which it accounts for revenues from contracts with customers in 2018 . +Basis for Opinions +The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in management's report referred to above. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. +Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, +68 +assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. +Definition and Limitations of Internal Control over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/PricewaterhouseCoopers LLP +Denver, Colorado +February 27, 2019 +We have served as the Company’s auditor since 2007. +69 +PDC ENERGY, INC. +Consolidated Balance Sheets +(in thousands, except share and per share data) +As of December 31, +2018 +2017 +Assets +Current assets: +Cash and cash equivalents +$ +1,398 +$ +180,675 +Accounts receivable, net +181,434 +197,598 +Fair value of derivatives +84,492 +14,338 +Prepaid expenses and other current assets +7,136 +8,613 +Total current assets +274,460 +401,224 +Properties and equipment, net +4,002,862 +3,933,467 +Assets held-for-sale +140,705 +40,583 +Fair value of derivatives +93,722 +— +Other assets +32,396 +45,116 +Total Assets +$ +4,544,145 +$ +4,420,390 +Liabilities and Stockholders' Equity +Liabilities +Current liabilities: +Accounts payable +$ +181,864 +$ +150,067 +Production tax liability +60,719 +37,654 +Fair value of derivatives +3,364 +79,302 +Funds held for distribution +105,784 +95,811 +Accrued interest payable +14,150 +11,815 +Other accrued expenses +75,133 +42,987 +Total current liabilities +441,014 +417,636 +Long-term debt +1,194,876 +1,151,932 +Deferred income taxes +198,096 +191,992 +Asset retirement obligations +85,312 +71,006 +Liabilities held-for-sale +4,111 +499 +Fair value of derivatives +1,364 +22,343 +Other liabilities +92,664 +57,333 +Total liabilities +2,017,437 +1,912,741 +Commitments and contingent liabilities +Stockholders' equity +Common shares - par value $0.01 per share, 150,000,000 authorized, 66,148,609 and 65,955,080 issued as of December 31, 2018 and 2017, respectively +661 +659 +Additional paid-in capital +2,519,423 +2,503,294 +Retained earnings +8,727 +6,704 +Treasury shares - at cost, 45,220 and 55,927 as of December 31, 2018 and 2017, respectively +(2,103 +) +(3,008 +) +Total stockholders' equity +2,526,708 +2,507,649 +Total Liabilities and Stockholders' Equity +$ +4,544,145 +$ +4,420,390 +See accompanying Notes to Consolidated Financial Statements +70 +PDC ENERGY, INC. +Consolidated Statements of Operations +(in thousands, except per share data) +Year Ended December 31, +2018 +2017 +2016 +Revenues +Crude oil, natural gas and NGLs sales +$ +1,389,961 +$ +913,084 +$ +497,353 +Commodity price risk management gain (loss), net +145,237 +(3,936 +) +(125,681 +) +Other income +13,461 +12,468 +11,243 +Total revenues +1,548,659 +921,616 +382,915 +Costs, expenses and other +Lease operating expenses +130,957 +89,641 +59,950 +Production taxes +90,357 +60,717 +31,410 +Transportation, gathering and processing expenses +37,403 +33,220 +18,415 +Exploration, geologic and geophysical expense +6,204 +47,334 +4,669 +Impairment of properties and equipment +458,397 +285,887 +9,973 +Impairment of goodwill +— +75,121 +— +General and administrative expense +170,504 +120,370 +112,470 +Depreciation, depletion and amortization +559,793 +469,084 +416,874 +Accretion of asset retirement obligations +5,075 +6,306 +7,080 +(Gain) loss on sale of properties and equipment +394 +(766 +) +(43 +) +Provision for uncollectible notes receivable +— +(40,203 +) +44,038 +Other expenses +11,829 +13,157 +10,193 +Total costs, expenses and other +1,470,913 +1,159,868 +715,029 +Income (loss) from operations +77,746 +(238,252 +) +(332,114 +) +Loss on extinguishment of debt +— +(24,747 +) +— +Interest expense +(70,730 +) +(78,694 +) +(61,972 +) +Interest income +413 +2,261 +963 +Income (loss) before income taxes +7,429 +(339,432 +) +(393,123 +) +Income tax (expense) benefit +(5,406 +) +211,928 +147,195 +Net income (loss) +$ +2,023 +$ +(127,504 +) +$ +(245,928 +) +Earnings per share: +Basic +$ +0.03 +$ +(1.94 +) +$ +(5.01 +) +Diluted +$ +0.03 +$ +(1.94 +) +$ +(5.01 +) +Weighted-average common shares outstanding: +Basic +66,059 +65,837 +49,052 +Diluted +66,303 +65,837 +49,052 +See accompanying Notes to Consolidated Financial Statements +71 +PDC ENERGY, INC. +Consolidated Statements of Cash Flows +(in thousands) +Year Ended December 31, +2018 +2017 +2016 +Cash flows from operating activities: +Net income (loss) +$ +2,023 +$ +(127,504 +) +$ +(245,928 +) +Adjustments to net income (loss) to reconcile to net cash from operating activities: +Net change in fair value of unsettled commodity derivatives +(260,775 +) +17,260 +333,770 +Depreciation, depletion and amortization +559,793 +469,084 +416,874 +Impairment of properties and equipment +458,397 +285,887 +9,973 +Impairment of goodwill +— +75,121 +— +Exploratory dry hole costs +113 +41,297 +— +Provision for uncollectible notes receivable +— +(40,203 +) +44,038 +Loss on extinguishment of debt +— +24,747 +— +Accretion of asset retirement obligations +5,075 +6,306 +7,080 +Non-cash stock-based compensation +21,782 +19,353 +19,502 +(Gain) loss on sale of properties and equipment +394 +(766 +) +(43 +) +Amortization of debt discount and issuance costs +12,769 +12,907 +16,167 +Deferred income taxes +6,105 +(203,685 +) +(137,249 +) +Other +2,763 +2,265 +2,603 +Total adjustments to net income (loss) to reconcile to net cash from operating activities: +806,416 +709,573 +712,715 +Changes in assets and liabilities: +Accounts receivable +12,025 +(60,546 +) +(32,627 +) +Other assets +(81 +) +3,364 +2,303 +Production tax liability +35,225 +31,316 +9,223 +Accounts payable and accrued expenses +16,261 +31,378 +(162 +) +Funds held for future distribution +9,973 +24,472 +36,510 +Asset retirement obligations +(13,341 +) +(10,176 +) +(4,109 +) +Other liabilities +20,801 +(4,064 +) +8,338 +Total changes in assets and liabilities +80,863 +15,744 +19,476 +Net cash from operating activities +889,302 +597,813 +486,263 +Cash flows from investing activities: +Capital expenditures for development of crude oil and natural gas properties +(946,350 +) +(737,208 +) +(436,884 +) +Capital expenditures for other properties and equipment +(11,055 +) +(5,094 +) +(3,464 +) +Acquisition of crude oil and natural gas properties +(180,026 +) +(15,628 +) +(1,073,723 +) +Proceeds from sale of properties and equipment +3,562 +9,991 +4,945 +Proceeds from divestiture +44,693 +— +— +Sale of promissory note +— +40,203 +— +Restricted cash +1,249 +(9,250 +) +— +Sale of short-term investments +— +49,890 +— +Purchase of short-term investments +— +(49,890 +) +— +Net cash from investing activities +(1,087,927 +) +(716,986 +) +(1,509,126 +) +Cash flows from financing activities: +Proceeds from revolving credit facility +1,072,500 +— +85,000 +Repayment of revolving credit facility +(1,040,000 +) +— +(122,000 +) +Proceeds from issuance of equity, net of issuance costs +— +— +855,074 +Proceeds from issuance of senior notes +— +592,366 +392,172 +Proceeds from issuance of convertible senior notes +— +— +193,935 +Redemption of senior notes +— +(519,375 +) +— +Redemption of convertible notes +— +— +(115,000 +) +Payment of debt issuance costs +(7,704 +) +(50 +) +(15,556 +) +Purchase of treasury shares +(5,147 +) +(6,672 +) +(6,935 +) +Other +(1,550 +) +(1,271 +) +(577 +) +Net cash from financing activities +18,099 +64,998 +1,266,113 +Net change in cash, cash equivalents and restricted cash +(180,526 +) +(54,175 +) +243,250 +Cash, cash equivalents and restricted cash, beginning of year +189,925 +244,100 +850 +Cash, cash equivalents and restricted cash, end of year +$ +9,399 +$ +189,925 +$ +244,100 +See accompanying Notes to Consolidated Financial Statements +72 +PDC ENERGY, INC. +Consolidated Statements of Equity +(in thousands, except share data) +Common Stock +Treasury Stock +Shares +Amount +Additional Paid-in Capital +Shares +Amount +Retained Earnings +Total Stockholders' Equity +Balances, January 1, 2016 +40,174,776 +$ +402 +$ +907,382 +(20,220 +) +$ +(1,009 +) +$ +380,422 +$ +1,287,197 +Net loss +— +— +— +— +— +(245,928 +) +(245,928 +) +Issuance pursuant to acquisition +9,386,768 +94 +690,608 +— +— +— +690,702 +Issuance pursuant to sale of equity +15,007,500 +150 +854,933 +— +— +— +855,083 +Convertible debt discount, net of issuance costs and tax +— +— +23,518 +— +— +— +23,518 +Purchase of treasury shares +— +— +— +(116,085 +) +(6,935 +) +— +(6,935 +) +Issuance pursuant to note conversion +792,406 +8 +(8 +) +— +— +— +— +Issuance of treasury shares +(114,697 +) +— +(6,661 +) +114,697 +6,661 +— +— +Non-employee directors' deferred compensation plan +— +— +— +(7,155 +) +(385 +) +— +(385 +) +Issuance of stock awards, net of forfeitures +411,731 +3 +(3 +) +— +— +— +— +Exercise of stock options +46,084 +— +— +— +— +— +— +Stock-based compensation expense +— +— +19,502 +— +— +— +19,502 +Other +— +— +286 +— +— +(286 +) +— +Balances, December 31, 2016 +65,704,568 +$ +657 +$ +2,489,557 +(28,763 +) +$ +(1,668 +) +$ +134,208 +$ +2,622,754 +Net loss +— +— +— +— +— +(127,504 +) +(127,504 +) +Purchase of treasury shares +— +— +— +(107,357 +) +(6,672 +) +— +(6,672 +) +Issuance of treasury shares +— +(5,517 +) +83,228 +5,517 +— +— +Non-employee directors' deferred compensation plan +— +— +— +(3,035 +) +(185 +) +— +(185 +) +Issuance of stock awards, net of forfeitures +250,512 +2 +(2 +) +— +— +— +— +Stock-based compensation expense +— +— +19,353 +— +— +— +19,353 +Other +— +— +(97 +) +— +— +— +(97 +) +Balances, December 31, 2017 +65,955,080 +$ +659 +$ +2,503,294 +(55,927 +) +$ +(3,008 +) +$ +6,704 +$ +2,507,649 +Net income +— +— +— +— +— +2,023 +2,023 +Purchase of treasury shares +— +— +— +(102,647 +) +(5,147 +) +— +(5,147 +) +Issuance of treasury shares +— +— +(5,561 +) +104,068 +5,561 +— +— +Non-employee directors' deferred compensation plan +— +— +— +9,286 +491 +— +491 +Issuance of stock awards, net of forfeitures +193,529 +2 +(2 +) +— +— +— +— +Stock-based compensation expense +— +— +21,782 +— +— +— +21,782 +Other +— +— +(90 +) +— +— +— +(90 +) +Balance, December 31, 2018 +66,148,609 +$ +661 +$ +2,519,423 +(45,220 +) +$ +(2,103 +) +$ +8,727 +$ +2,526,708 +See accompanying Notes to Consolidated Financial Statements +73 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION +PDC Energy, Inc. ("PDC", the "Company," "we," "us," or "our") is a domestic independent exploration and production company that acquires, explores and develops properties for the production of crude oil, natural gas and NGLs, with operations in the Wattenberg Field in Colorado and the Delaware Basin in Texas. Our operations in the Wattenberg Field are focused in the rural areas of the horizontal Niobrara and Codell plays and our Delaware Basin operations are primarily focused in the Wolfcamp zones. We previously operated properties in the Utica Shale in Southeastern Ohio; however, we divested these properties during the first quarter of 2018. As of December 31, 2018 , we owned an interest in approximately 2,900 productive gross wells. We are engaged in two operating segments: our oil and gas exploration and production segment and our gas marketing segment. Our gas marketing segment does not meet the quantitative thresholds to require disclosure as a separate reportable segment. All of our material operations are attributable to our exploration and production business; therefore, all of our operations are presented as a single segment for all periods presented. +The audited consolidated financial statements include the accounts of PDC, our wholly-owned subsidiaries and our proportionate share of our affiliated partnerships. All intercompany accounts and transactions have been eliminated in consolidation. +The preparation of our consolidated financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of crude oil, natural gas and NGLs sales revenue; crude oil, natural gas and NGLs reserves; estimates of unpaid revenues and unbilled costs; future cash flows from crude oil and natural gas properties; valuation of commodity derivative instruments; exploratory dry hole costs; impairment of proved and unproved properties; impairment of goodwill; valuation and allocations of purchased and exchanged businesses and assets; estimates of fair value of our fixed rate debt instruments; and valuation of deferred income tax assets. +Certain immaterial reclassifications have been made to our prior period balance sheet to conform to the current period presentation. The reclassifications had no impact on previously reported results. +NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Cash Equivalents. We consider all highly liquid investments with original maturities of three months or less to be cash equivalents. +Commodity Derivative Financial Instruments. We are exposed to the effect of market fluctuations in the prices of crude oil, natural gas and NGLs. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy and our revolving credit facility prohibit the use of crude oil and natural gas derivative instruments for speculative purposes. +Derivative assets and liabilities are recorded on our consolidated balance sheets at fair value. We have elected not to designate any of our commodity derivative instruments as cash flow hedges. Accordingly, changes in the fair value of our commodity derivative instruments are recorded in the consolidated statements of operations. We have elected the normal purchase, normal sale exception for our crude oil and natural gas contracts; therefore, the effects of these contracts are not included in our derivative assets and liabilities. Classification of net settlements resulting from maturities and changes in fair value of unsettled commodity derivatives depends on the purpose of issuing or holding the derivative. Net settlements and changes in the fair value of commodity derivative instruments related to our Oil and Gas Exploration and Production segment are recorded in commodity price risk management, net. Net settlements and changes in the fair value of commodity derivative instruments related to our Gas Marketing segment are recorded in other income and other expenses. The consolidated statements of cash flows reflects the net settlement of commodity derivative instruments in operating cash flows. +The calculation of the commodity derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. +74 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Properties and Equipment. Significant accounting polices related to our properties and equipment are discussed below. +Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depreciated or depleted by the unit-of-production method, based on estimated proved developed producing reserves. Property acquisition costs are depreciated or depleted on the unit-of-production method based on estimated proved reserves. We have determined that we have two unit-of-production fields: the Wattenberg Field and the Delaware Basin. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations and common cost environments in these areas. We calculate quarterly depreciation, depletion and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted for fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized in the consolidated statement of operations as a gain or loss. Upon the sale of individual wells or an insignificant portion of a field, the proceeds are credited to accumulated DD&A. +Exploration costs, including geologic and geophysical expenses, seismic costs on unproved leaseholds and delay rentals are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as suspended well costs until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the resulting accounting treatment is recorded. +Proved Property Impairment. Annually, or upon a triggering event, we assess our producing crude oil and natural gas properties for possible impairment by comparing carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production and prices at which we reasonably estimate the commodities will be sold. The estimates of future prices may differ from current market prices of crude oil, natural gas and NGLs. Certain events, including but not limited to downward revisions in estimates of our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event, and therefore a possible impairment of our proved crude oil and natural gas properties. If carrying values exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a discounted future cash flows analysis. The impairment recorded is the amount by which the carrying values exceed fair value. Impairments are included in the consolidated statements of operations line item impairment of properties and equipment, with a corresponding impact on accumulated DD&A. +Unproved Property Impairment. Acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized by field, based on our historical experience, acquisition dates and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statements of operations line item impairment of properties and equipment. +Other Property and Equipment. Other property and equipment such as pipelines, vehicles, facilities, office furniture and equipment, buildings and computer hardware and software is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives, which range from two to 35 years . We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying value of the asset exceeds the estimated future cash flows, an impairment charge is recognized in the amount by which the carrying value of the asset exceeds the fair value of the asset. Impairment and amortization charges related to other property and equipment are charged to the consolidated statements of operations line item impairment of properties and equipment. +75 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed, the proceeds are applied and any resulting gain or loss is reflected in income. Total depreciation expense related to other property and equipment was $8.5 million , $6.6 million and $3.8 million in 2018 , 2017 and 2016 , respectively. +Internal-Use Software. Certain internal-use software costs incurred during the development stage are capitalized. The development stage generally includes software design, configuration, testing and installation activities. Training and maintenance costs are expenses as incurred, while upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Capitalized internal-use software costs are depreciated over the estimated useful life of the underlying project on a straight-line basis upon completion of the project. As of December 31, 2018 , capitalized costs for internal-use software were not material. We did not have any capitalized internal-use software costs at December 31, 2017 . +Capitalized Interest. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A expense is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our outstanding debt by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $9.2 million , $5.0 million and $4.5 million in 2018 , 2017 and 2016 , respectively. +Assets Held-for-Sale. Assets held-for-sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, earnings multiples or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets once they are classified as held-for-sale. Assets classified as held-for-sale are expected to be disposed of within one year. +Production Tax Liability. Production tax liability represents estimated taxes, primarily severance, ad valorem and property taxes, to be paid to the states and counties in which we produce crude oil, natural gas and NGLs. These taxes are expensed and included in the statements of operations line item production taxes. The long-term portion of the production tax liability is included in other liabilities on the consolidated balance sheets and was $61.3 million and $50.5 million in December 31, 2018 and 2017 , respectively. +Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable. +Debt Issuance Costs. Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs for the 2021 Convertible Notes, the 2024 Senior Notes and the 2026 Senior Notes are included in long-term debt on the consolidated balance sheets and the debt issuance costs for the revolving credit facility are included in other assets on the consolidated balance sheets. +Asset Retirement Obligations. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from, among other things, changes in retirement costs or the estimated timing of settling asset retirement obligations. +76 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders’ equity in the consolidated balance sheets. When we retire treasury shares, we charge any excess of cost over the par value to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings. +Revenue Recognition. Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of crude oil, natural gas, or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For 2018 , 2017 and 2016 , the impact of any natural gas imbalances was not significant. If a sale is deemed uncollectible, an allowance for doubtful collection is recorded. +Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related agreement. We use the net-back method when control of the crude oil, natural gas, or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. +We use the gross method of accounting when control of the crude oil, natural gas, or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering, or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses. +Credit Risk and Allowance for Doubtful Accounts. Inherent to our industry is the concentration of crude oil, natural gas and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs and the overall creditworthiness of our customers. Further, consideration is given to well production data for receivables related to well operations. +Accounting for Business Combinations. We utilize the purchase method to account for acquisitions of businesses. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows, quoted market prices and estimates by management, which are Level 3 inputs. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. +In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped, unproved crude oil and natural gas properties and other non-crude oil and natural gas properties. To estimate the fair value of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired and estimates of future operating and development costs to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of comparable purchased properties to determine an estimation of fair value. +77 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +If applicable, we record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities, except goodwill. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. +Acreage Exchanges . From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and providing us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges of non-producing interests and unproved mineral leases in accordance with the guidance prescribed by Accounting Standards Codification 845, Nonmonetary Transactions . For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized in earnings, in accordance with Accounting Standards Codification 820, Fair Value Measurement . +Stock-Based Compensation. Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the vesting period for the entire award and we account for forfeitures of stock-based compensation awards as they occur. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities or the development of internal-use software, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statements of operations. +Recently Adopted Accounting Standards. +In May 2014, the Financial Accounting Standards Board ("FASB") and the International Accounting Standards Board issued their converged standard on revenue recognition that provides a single, comprehensive model that entities will apply to determine the measurement of revenue and timing of when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The standard outlines a five-step approach to apply the underlying principle: (1) identify the contract with the customer, (2) identify the separate performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to separate performance obligations and (5) recognize revenue when or as each performance obligation is satisfied. We adopted the standard effective January 1, 2018 under the modified retrospective method. In order to evaluate the impact that the adoption of the revenue standard had on our consolidated financial statements, we performed a comprehensive review of our significant revenue streams. The focus of this review included, among other things, the identification of the significant contracts and other arrangements we have with our customers to identify performance obligations and principal versus agent considerations and factors affecting the determination of the transaction price. We also reviewed our current accounting policies, procedures and controls with respect to these contracts and arrangements to determine what changes, if any, would be required by the adoption of the revenue standard. Upon adoption, no adjustment to our opening balance of retained earnings was deemed necessary. See the footnote below titled Revenue Recognition for further details regarding the changes in our revenue recognition resulting from the adoption of this standard. +In November 2016, the FASB issued an accounting update on statements of cash flows to address diversity in practice in the classification and presentation of changes in restricted cash. The accounting update requires that the statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash or restricted cash equivalents should be included with cash and cash equivalents when reconciling beginning-of-period and end-of-period amounts shown on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. Adoption of this standard impacted our consolidated statements of cash flows. The following table provides a reconciliation of cash and cash equivalents and restricted cash reported on the consolidated balance sheets at December 31, 2018 and 2017 , which sum to the total of cash, cash equivalents and restricted cash in the consolidated statements of cash flows: +78 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +December 31, 2018 +December 31, 2017 +(in thousands) +Cash and cash equivalents +$ +1,398 +$ +180,675 +Restricted cash +8,001 +9,250 +Cash, cash equivalents and restricted cash shown in the consolidated statements of cash flows +$ +9,399 +$ +189,925 +Restricted cash is included in other assets on the consolidated balance sheets at December 31, 2018 and December 31, 2017 . We did not have any cash classified as restricted cash at December 31, 2016 . +In August 2018, the FASB issued an accounting update to align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software and hosting arrangements that include an internal-use software license. The guidance is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with early adoption permitted. We elected to early adopt this standard in the third quarter of 2018. As of December 31, 2018 , capitalized costs for internal-use software were not material. +In November 2018, the FASB issued an accounting update and amendments to clarify the interaction between collaborative contractual arrangements and the revenue recognition standard. The amendments in this update specify that transactions between participants in a collaborative arrangement should be accounted for under the revenue recognition standard when the counterparty is a customer and the guidance precludes entities from presenting consideration from a transaction in a collaborative arrangement as revenue from contracts with customers if the counterparty is not a customer for that transaction. The guidance is effective for fiscal years beginning after December 15, 2019 and interim periods within those fiscal periods, with early adoption permitted. We have elected to early adopt this standard in the fourth quarter of 2018. Upon adoption, no adjustment to our opening balance of retained earnings was deemed necessary as adoption of this standard did not have an impact on our consolidated financial statements. +Recently Issued Accounting Standards +In February 2016, the FASB issued an accounting update and subsequent amendments aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements (the “New Lease Standard”). For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use ("ROU") asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. Both the ROU asset and corresponding liability will initially be measured at the present value of the future minimum lease payments over the lease term. Subsequent measurement, as well as presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. We will make accounting policy elections to not recognize ROU assets and lease liabilities that arise from short-term leases and to not separate lease and non-lease components for any class of underlying asset, as provided by practical expedients. In January 2018, the FASB also issued an accounting update which provides an optional transition practical expedient for the adoption of the New Lease Standard that if elected, would not require an organization to reconsider accounting for existing land easements that are not accounted for under the previous lease accounting standard. We will elect this practical expedient and accordingly, existing land easements will not be assessed. All new or modified land easements entered into after January 1, 2019 will be evaluated under the New Lease Standard. The New Lease Standard does not apply to leases of mineral rights to explore for or use crude oil and natural gas. We will adopt the New Lease standard and subsequent amendments effective January 1, 2019 under the modified retrospective approach for all active contracts as of December 31, 2018 . Based upon our implementation progress to date, we expect the adoption of the New Lease Standard to result in increases to total assets and total liabilities of approximately $20.0 million at January 1, 2019, with no adjustment to the opening balance of retained earnings. +79 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 3 - BUSINESS COMBINATIONS +In January 2018, we closed the acquisition of properties from Bayswater Exploration and Production LLC (the "Bayswater Asset Acquisition") for approximately $200.0 million in cash, after post-closing adjustments, including $21.0 million deposited into an escrow account in 2017. The $21.0 million deposit was included in other assets on our December 31, 2017 consolidated balance sheet. We acquired approximately 7,400 net acres, approximately 220 gross drilling locations and 24 operated horizontal wells that were either DUCs or in-process wells at the time of closing. +The final purchase price and allocation of the assets acquired and the liabilities assumed in the acquisition are presented below. Adjustments made subsequent to the preliminary purchase price stem from final settlement of the proceeds from operating activities and additional information we obtained about facts and circumstances that existed at the acquisition date that impact the underlying value of certain assets acquired and liabilities assumed. Such adjustments primarily relate to sales, operating expenses and capital costs from the effective date through closing. +The details of the final purchase price and allocation of the purchase price for the transaction, are presented below (in thousands): +December 31, 2018 +Acquisition costs: +Cash +$ +168,560 +Deposit made in prior period +21,000 +Total cash consideration +189,560 +Other purchase price adjustments +10,422 +Total acquisition costs +$ +199,982 +Recognized amounts of identifiable assets acquired and liabilities assumed: +Assets acquired: +Current assets +$ +468 +Crude oil and natural gas properties - proved +205,834 +Other assets +2,796 +Total assets acquired +209,098 +Liabilities assumed: +Current liabilities +(4,429 +) +Asset retirement obligations +(4,687 +) +Total liabilities assumed +(9,116 +) +Total identifiable net assets acquired +$ +199,982 +This transaction was accounted for under the acquisition method. Accordingly, we conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of crude oil and natural gas properties include estimates of reserves, future operating and development costs, future commodity prices, estimated future cash flows, lease terms and expirations and a market-based weighted-average cost of capital rate. The allocation of the value to the underlying leases also requires significant judgment and is based on a combination of comparable market transactions, the term and conditions associated with the individual leases, our ability and intent to develop specific leases and our initial assessment of the underlying relative value of the leases given our knowledge of the geology at the time of closing. These inputs require significant judgments and estimates by management at the time of the valuation. +The results of operations for the Bayswater Asset Acquisition for the year ended December 31, 2018 have been included in our consolidated financial statements, including approximately $70.8 million of total revenue, $39.3 million of income from operations and $0.59 of diluted earnings per share. Pro forma results of operations for the Bayswater Asset Acquisition showing results as if the acquisition had been completed as of January 1, 2017 would not have been material to our consolidated financial statements for the year ended December 31, 2017 . +80 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 4 - REVENUE RECOGNITION +On January 1, 2018, we adopted the new accounting standard that was issued by the FASB to provide a single, comprehensive model to determine the measurement of revenue and timing of when it is recognized and all related amendments (the “New Revenue Standard”) using the modified retrospective method. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Based upon our review, we determined that the adoption of the New Revenue Standard would have reduced our crude oil, natural gas and NGLs sales by approximately $11.3 million in 2017 with a corresponding decrease in transportation, gathering and processing expenses and no impact on net earnings. To determine the impact on our crude oil, natural gas and NGLs sales and our transportation, processing and gathering expenses for 2018 , we applied the new guidance to contracts that were not completed as of December 31, 2017. We do not expect adoption of the New Revenue Standard to have a significant impact on our net income going forward. +Based on our evaluation of when control of crude oil and natural gas sales are transferred to the customer under the guidance of the New Revenue Standard, certain crude oil sales in the Wattenberg Field that were recognized using the gross method prior to the adoption of the New Revenue Standard will be recognized using the net-back method. In the Delaware Basin, certain crude oil and natural gas sales that were recognized using the gross method prior to the adoption of the New Revenue Standard will be recognized using the net-back method. +As discussed above, we enter into agreements for the sale, transportation, gathering and processing of our production. The terms of these agreements can result in variances in the per unit realized prices that we receive for our crude oil, natural gas and NGLs. For crude oil, the average NYMEX prices are based upon average daily prices throughout each month and, for natural gas, the average NYMEX pricing is based upon first-of-the-month index prices, as in each case this is how the majority of each of these commodities is sold pursuant to terms of the respective sales agreements. For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. +Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for 2018 , 2017 and 2016 (in thousands): +Year Ended December 31, +Revenue by Commodity and Operating Region +2018 +2017 (1) +2016 (1) +Crude oil +Wattenberg Field +$ +783,158 +$ +529,562 +$ +329,168 +Delaware Basin +252,107 +82,677 +3,918 +Utica Shale (2) +2,696 +12,814 +15,769 +Total +$ +1,037,961 +$ +625,053 +$ +348,855 +Natural gas +Wattenberg Field +$ +130,073 +$ +131,792 +$ +86,633 +Delaware Basin +32,010 +21,251 +1,039 +Utica Shale (2) +1,109 +5,216 +3,904 +Total +$ +163,192 +$ +158,259 +$ +91,576 +NGLs +Wattenberg Field +$ +132,820 +$ +104,298 +$ +52,919 +Delaware Basin +55,148 +20,756 +645 +Utica Shale (2) +840 +4,718 +3,358 +Total +$ +188,808 +$ +129,772 +$ +56,922 +Revenue by Operating Region +Wattenberg Field +$ +1,046,051 +$ +765,652 +$ +468,720 +Delaware Basin +339,265 +124,684 +5,602 +Utica Shale (2) +4,645 +22,748 +23,031 +Total +$ +1,389,961 +$ +913,084 +$ +497,353 +________________________________________ +(1) +As we have elected the modified retrospective method of adoption for the New Revenue Standard, revenues for 2017 +and 2016 have not been restated. Such changes would not have been material. +(2) +In March 2018, we completed the disposition of our Utica Shale properties. +81 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Contract Assets. Contract assets include material contributions in aid of construction, which are common in purchase and processing agreements with midstream service providers that are our customers. Generally, the intent of the payments is to reimburse the customer for actual costs incurred related to the construction of its gathering and processing infrastructure. Contract assets are classified as long-term assets and included in other assets on our consolidated balance sheet. The contract assets will be amortized as a reduction to crude oil, natural gas and NGLs sales revenue during the periods in which the related production is transferred to the customer. +The following table presents the changes in carrying amounts of the contract assets associated with our crude oil, natural gas and NGLs sales revenue for year ended December 31, 2018 : +Amount +(in thousands) +Beginning balance, January 1, 2018 +$ +3,746 +Additions +2,884 +Amortized as a reduction to crude oil, natural gas and NGLs sales +(3,096 +) +Ending balance, December 31, 2018 +$ +3,534 +Customer Accounts Receivable. Our accounts receivable include amounts billed and currently due from sales of our crude oil, natural gas and NGLs production. Our gross accounts receivable balance from crude oil, natural gas and NGLs sales at December 31, 2018 and 2017 was $155.8 million and $154.3 million , respectively. We did not record an allowance for doubtful accounts for these receivables at December 31, 2018 or 2017. +NOTE 5 - FAIR VALUE OF FINANCIAL INSTRUMENTS +Determination of Fair Value +Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. +Derivative Financial Instruments +We measure the fair value of our commodity derivative instruments based on a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. +We validate our fair value measurement through the review of counterparty statements and other supporting documentation, the determination that the source of the inputs is valid, the corroboration of the original source of inputs through access to multiple quotes, if available, or other information and monitoring changes in valuation methods and assumptions. +82 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Our crude oil and natural gas fixed-price swaps are included in Level 2. Our collars and propane fixed-price swaps are included in Level 3. Our basis swaps are included in Level 2 and Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis: +As of December 31, +2018 +2017 +Significant Other +Observable +Inputs +(Level 2) +Significant +Unobservable +Inputs +(Level 3) +Total +Significant Other +Observable +Inputs +(Level 2) +Significant +Unobservable +Inputs +(Level 3) +Total +(in thousands) +Total assets +$ +118,521 +$ +59,693 +$ +178,214 +$ +12,949 +$ +1,389 +$ +14,338 +Total liabilities +(3,364 +) +(1,364 +) +(4,728 +) +(90,569 +) +(11,076 +) +(101,645 +) +Net asset (liability) +$ +115,157 +$ +58,329 +$ +173,486 +$ +(77,620 +) +$ +(9,687 +) +$ +(87,307 +) +The following table presents a reconciliation of our Level 3 commodity derivative instruments measured at fair value: +Year Ended December 31, +2018 +2017 +2016 +(in thousands) +Fair value of Level 3 instruments, net asset (liability) beginning of period +$ +(9,687 +) +$ +(9,574 +) +$ +91,288 +Changes in fair value included in consolidated statements of operations line item: +Commodity price risk management gain (loss), net +63,257 +6,241 +(28,550 +) +Settlements included in consolidated statements of operations line items: +Commodity price risk management ( loss) , net +4,759 +(6,354 +) +(72,312 +) +Fair value of Level 3 instruments, net asset (liability) end of period +$ +58,329 +$ +(9,687 +) +$ +(9,574 +) +Net change in fair value of Level 3 unsettled derivatives included in consolidated statements of operations line item: +Commodity price risk management gain (loss), net +$ +— +$ +(866 +) +$ +(12,905 +) +Total +$ +— +$ +(866 +) +$ +(12,905 +) +The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. There has been no change in the methodology we apply to measure the fair value of our Level 3 derivative contracts during the periods covered by the financial statements. +Non-Derivative Financial Assets and Liabilities +The carrying value of the financial instruments included in current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. +We utilize fair value on a nonrecurring basis to review our crude oil and natural gas properties and goodwill for possible impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such assets. The fair value of the properties is determined based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. The fair value of the goodwill is determined using either a qualitative method or a quantitative method, both of which utilize market data, a Level 3 input, in the derivation of the value estimation. +The portion of our long-term debt related to our revolving credit facility approximates fair value due to the variable nature of related interest rates. We have not elected to account for the portion of our debt related to our senior notes under the +83 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +fair value option; however, we have determined an estimate of the fair values based on measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes and convertible notes as of December 31, 2018 and 2017: +As of December 31, +2018 +2017 +Estimated Fair Value +Percent of Par +Estimated Fair Value +Percent of Par +(in millions) +Senior notes: +2021 Convertible Notes +$ +175.4 +87.7 +% +$ +195.6 +97.8 +% +2024 Senior Notes +370.2 +92.5 +% +416.0 +104.0 +% +2026 Senior Notes +532.4 +88.7 +% +616.5 +102.8 +% +The carrying value of our capital lease obligations approximates fair value due to the variable nature of the imputed interest rates and the duration of the related vehicle lease. +NOTE 6 - COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS +Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil, natural gas and propane, which is an element of our NGLs, we enter into commodity derivative contracts to protect against price declines in future periods. While we structure these commodity derivatives to reduce our exposure to decreases in commodity prices, they also limit the benefit we might otherwise receive from price increases. +We believe our commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of December 31, 2018 , we had commodity derivatives positions covering approximately 11.0 MMBbls and 8.6 MMBbls of crude oil production for 2019 and 2020, respectively. As of the same date, we had hedged approximately 26.4 Bcf of natural gas for 2019. Our commodity derivative contracts have been entered into at no cost to us as we hedge our anticipated production at the then-prevailing commodity market prices, without adjustment for premium or discount. +As of December 31, 2018 , our derivative instruments were comprised of collars, fixed-price commodity swaps and basis protection swaps. +• +Collars contain a fixed floor price (put) and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty; +• +Fixed-price commodity swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty. If the index price and contract price are the same, no payment is due to or from the counterparty; +• +Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For basis protection swaps, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. If the market price and contract price are the same, no payment is due to or from the counterparty. +84 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +As of December 31, 2018 , we had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed. +Collars +Fixed-Price Swaps +Commodity/ Index/ +Maturity Period +Quantity +(Crude oil - +MBls +Natural Gas - BBtu) +Weighted-Average +Contract Price +Quantity (Crude Oil - MBbls +Gas and Basis- +BBtu) +Weighted- +Average +Contract +Price +Fair Value +December 31, +2018 (1) +(in thousands) +Floors +Ceilings +Crude Oil +NYMEX +2019 +2,600 +$ +56.54 +$ +68.13 +8,400 +$ +53.86 +$ +82,305 +2020 +3,600 +55.00 +71.68 +5,000 +62.07 +92,359 +Total Crude Oil +6,200 +13,400 +$ +174,664 +Natural Gas +NYMEX +2019 +— +— +— +26,008 +2.91 +1,408 +Dominion South +2019 +— +— +— +372 +3.13 +30 +Columbia +2019 +— +— +— +3 +2.40 +— +Total Natural Gas +— +26,383 +$ +1,438 +Basis Protection - Natural Gas +CIG +2019 +— +— +— +25,924 +(0.78 +) +(2,616 +) +Total Basis Protection - Natural Gas +— +25,924 +$ +(2,616 +) +Commodity Derivatives Fair Value +$ +173,486 +(1) +Approximately 33.5 percent of the fair value of our commodity derivative assets and 28.9 percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3). +The following table presents the balance sheet location and fair value amounts of our commodity derivative instruments on the consolidated balance sheets as of December 31, 2018 and 2017 : +Derivative instruments: +Consolidated balance sheet line item +2018 +2017 +(in thousands) +Derivative assets: +Current +Commodity derivative contracts +Fair value of derivatives +$ +84,492 +$ +7,340 +Basis protection derivative contracts +Fair value of derivatives +— +6,998 +84,492 +14,338 +Non-current +Commodity derivative contracts +Fair value of derivatives +93,722 +— +93,722 +— +Total derivative assets +$ +178,214 +$ +14,338 +Derivative liabilities: +Current +Commodity derivative contracts +Fair value of derivatives +$ +748 +77,999 +Basis protection derivative contracts +Fair value of derivatives +2,616 +234 +Rollfactor derivative contracts +Fair value of derivatives +— +1,069 +3,364 +79,302 +Non-current +Commodity derivative contracts +Fair value of derivatives +1,364 +22,343 +Total derivative liabilities +$ +4,728 +$ +101,645 +85 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the impact of our derivative instruments on our consolidated statements of operations: +Year Ended December 31, +Consolidated statements of operations line item +2018 +2017 +2016 +(in thousands) +Commodity price risk management gain (loss), net +Net settlements +$ +(115,538 +) +$ +13,324 +$ +208,103 +Net change in fair value of unsettled derivatives +260,775 +(17,260 +) +(333,784 +) +Total commodity price risk management gain (loss), net +$ +145,237 +$ +(3,936 +) +$ +(125,681 +) +All of our financial derivative agreements contain master netting provisions that provide for the net settlement of all contracts through a single payment in the event of early termination. We have elected not to offset the fair value positions recorded on our consolidated balance sheets. +The following table reflects the impact of netting agreements on gross derivative assets and liabilities: +As of December 31, 2018 +Derivative instruments, gross +Effect of master netting agreements +Derivative instruments, net +(in thousands) +Asset derivatives: +Derivative instruments, at fair value +$ +178,214 +$ +(3,985 +) +$ +174,229 +Liability derivatives: +Derivative instruments, at fair value +$ +4,728 +$ +(3,985 +) +$ +743 +As of December 31, 2017 +Derivative instruments, gross +Effect of master netting agreements +Derivative instruments, net +(in thousands) +Asset derivatives: +Derivative instruments, at fair value +$ +14,338 +$ +(14,173 +) +$ +165 +Liability derivatives: +Derivative instruments, at fair value +$ +101,645 +$ +(14,173 +) +$ +87,472 +86 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 7 - CONCENTRATION OF RISK +Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts: +As of December 31, +2018 +2017 +(in thousands) +Crude oil, natural gas and NGLs sales +$ +155,756 +$ +154,260 +Joint interest billings +19,580 +34,576 +Derivative counterparties +3,937 +(18 +) +Income tax receivable +— +6,015 +Other +6,542 +5,893 +Allowance for doubtful accounts +(4,381 +) +(3,128 +) +Accounts receivable, net +$ +181,434 +$ +197,598 +Our accounts receivable primarily relate to sales of our crude oil, natural gas and NGLs production, receivable balances from other third parties that own working interests in the properties we operate, and derivative counterparties. For the years ended December 31, 2018 and 2017 , amounts written off to allowance for doubtful accounts were not material. As of December 31, 2018 , two of our customers represent 10 percent or greater of our accounts receivable balance. As of December 31, 2017 , none of our customers represented 10 percent or greater of our accounts receivable balance. +Major Customers. The following table presents the individual customers constituting 10 percent or more of total revenues: +Year Ended December 31, +Customer +2018 +2017 +2016 +DCP Midstream, LP +12.5 +% +19.6 +% +20.2 +% +Suncor Energy Marketing, Inc. +— +% +16.4 +% +22.3 +% +Aka Energy Group, LLC +— +% +— +% +13.4 +% +Concord Energy, LLC +— +% +— +% +13.4 +% +Bridger Energy, LLC +— +% +— +% +11.5 +% +Derivative Counterparties. A portion of our liquidity relates to commodity derivative instruments that enable us to manage a portion of our exposure to price volatility from producing crude oil, natural gas and NGLs. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also major lenders under our revolving credit facility as counterparties to our commodity derivative contracts. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our current counterparties on the fair value of our derivative instruments is not significant at December 31, 2018 . +Note Receivable. Note Receivable. In 2014, we sold our entire 50 percent ownership interest in PDC Mountaineer, LLC to an unrelated third-party. As part of the consideration, we received a promissory note (the “Promissory Note”) for a principal sum of $39.0 million . We regularly analyzed the Promissory Note for evidence of collectibility, evaluating factors such as the creditworthiness of the issuer of the Promissory Note and the value of the issuer's assets. Based upon this analysis, during the quarter ended March 31, 2016, we recognized a provision and recorded an allowance for uncollectible notes receivable for the $44.0 million accumulated outstanding balance, including interest. In April 2017, we sold the Promissory Note to an unrelated third-party buyer for approximately $40.2 million in cash. Accordingly, we reversed $40.2 million of the provision for uncollectible notes receivable during the second quarter of 2017. +87 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Other Accrued Expenses. The following table presents the components of other accrued expenses: +As of December 31, +2018 +2017 +(in thousands) +Employee benefits +$ +25,811 +$ +22,383 +Asset retirement obligations +25,598 +15,801 +Environmental expenses +3,038 +1,374 +Other +20,686 +3,429 +Other accrued expenses +$ +75,133 +$ +42,987 +Other Liabilities. The following table presents the components of other liabilities as of: +As of December 31, +2018 +2017 +(in thousands) +Production taxes +$ +61,310 +$ +50,476 +Deferred oil gathering credit +22,710 +— +Other +8,644 +6,857 +Other liabilities +$ +92,664 +$ +57,333 +Deferred Oil Gathering Credit. In January 2018, we received a payment of $24.1 million from a midstream service provider for the execution of an amendment to an existing crude oil purchase and sale agreement signed in December 2017. The amendment was effective contingent upon certain events which occurred in late January 2018. The amendment, among other things, dedicates crude oil from the majority of our Wattenberg Field acreage to the midstream provider's gathering lines and extends the term of the agreement through December 2029. The payment will be amortized using the straight-line method over the life of the amendment. Amortization charges totaling approximately $1.4 million for 2018 related to the deferred oil gathering credit are included as a reduction to transportation, gathering and processing expenses in our consolidated statements of operations. +NOTE 8 - PROPERTIES AND EQUIPMENT +The following table presents the components of properties and equipment, net of accumulated DD&A: +As of December 31, +2018 +2017 +(in thousands) +Properties and equipment, net: +Crude oil and natural gas properties +Proved +$ +5,452,613 +$ +4,356,922 +Unproved +492,594 +1,097,317 +Total crude oil and natural gas properties +5,945,207 +5,454,239 +Infrastructure and other +60,612 +109,359 +Land and buildings +11,243 +10,960 +Construction in progress +356,095 +196,024 +Properties and equipment, at cost +6,373,157 +5,770,582 +Accumulated DD&A +(2,370,295 +) +(1,837,115 +) +Properties and equipment, net +$ +4,002,862 +$ +3,933,467 +Acreage Exchanges. In November 2018, we completed a nonmonetary acreage exchange that resulted in our acquisition of approximately 12,300 net acres that consolidated our position in the core area of the Wattenberg Field. We recognized a gain of approximately $6.0 million related to the exchange based on the fair value of the assets surrendered. +88 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Also during 2018, we completed another nonmonetary acreage exchange in the Wattenberg Field, resulting in us acquiring approximately 2,500 net acres and $3.7 million in cash. It was concluded that this transaction lacked commercial substance, and accordingly, the trade was recorded at the previous historical cost of the assets exchanged, less cash received. +In 2017, we completed two significant acreage exchanges that consolidated certain acreage positions in the core area of the Wattenberg Field. Pursuant to the transactions, we exchanged leasehold acreage with a limited number of wells that were in the process of being drilled and completed. Upon closing, we received approximately 15,900 net acres in exchange for approximately 16,200 net acres with minimal cash exchanged between the parties. The differences in net acres are primarily due to variances in working and net revenue interests and in midstream contracts. The assets exchanged were all in the same unit-of-production for property considerations, so it was concluded that this transaction was outside of the scope of the accounting requirements for recording the transaction at fair value and determining gain or loss on the non-monetary exchanges. The new acreage and underlying property costs were recorded at the previous historical cost of the assets we exchanged. +Classification of Assets and Liabilities as Held-for-Sale. During the fourth quarter of 2018, as part of our plan to divest certain of our Delaware Basin crude oil gathering, natural gas gathering and produced water gathering and disposal assets, we began actively marketing the assets for sale; therefore, these assets are classified as held-for-sale as they met the criteria for such classification at December 31, 2018 . We currently expect to execute agreements on the sales of these assets in the first half of 2019. Our Delaware Basin crude oil gathering, natural gas gathering and produced water gathering and disposal assets do not represent a strategic shift in our operations or have a significant impact on our operations or financial results; therefore, we will not account for it as a discontinued operation. Also included in the assets held-for-sale are certain non-core Delaware Basin crude oil and natural gas properties. +During 2017, as part of our plan to divest the Utica Shale properties, we engaged an investment banking firm and began actively marketing the properties for sale; therefore, these properties were classified as held-for-sale as they met the criteria for such classification at December 31, 2017. In March 2018, we completed the Utica Shale Divestiture for net cash proceeds of approximately $ 39.0 million . We recorded a loss on sale of properties and equipment of $ 1.4 million for 2018 , which included post-closing adjustments. The Utica Shale Divestiture did not represent a strategic shift in our operations or have a significant impact on our operations or financial results; therefore, we did not account for it as a discontinued operation. +The following table presents balance sheet data related to assets and liabilities held-for-sale: +As of December 31, +2018 +2017 +(in thousands) +Assets +Properties and equipment, net +$ +137,448 +$ +40,583 +Other assets +3,257 +— +Total assets +$ +140,705 +$ +40,583 +Liabilities +Asset retirement obligation +$ +4,111 +$ +499 +Total liabilities +$ +4,111 +$ +499 +Impairment of Properties and Equipment +The following table presents impairment charges recorded for properties and equipment: +Year Ended December 31, +2018 +2017 +2016 +(in thousands) +Impairment of proved and unproved properties +$ +458,397 +$ +285,465 +$ +5,562 +Amortization of individually insignificant unproved properties +— +422 +1,379 +Land and buildings +— +— +3,032 +Total impairment of properties and equipment +$ +458,397 +$ +285,887 +$ +9,973 +89 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +During 2018 , we recorded impairment charges totaling $458.4 million as we identified current and anticipated near-term leasehold expirations within our non-focus areas of the Delaware Basin and made the determination that we would no longer pursue plans to develop these properties. The impaired non-focus leasehold typically has a higher gas to oil ratio and a greater degree of geologic complexity than our other Delaware Basin properties and is further impacted by widening crude oil and natural gas differentials and increased well development costs. We continue to explore options for our non-focus areas and monitor them for possible future impairment based on similar analyses. We determined the fair value of the properties based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. +The impairment charges noted above include the correction of two errors in the timing of the reporting of certain impairments. In 2018, we corrected an error in our calculation of unproved properties and goodwill originally recorded in 2017, resulting in an additional impairment charge of $6.3 million being recorded during the three months ended March 31, 2018. Further, during the fourth quarter of 2018, we corrected for an additional $8.4 million impairment of unproved properties relating to the three months ended September 30, 2018. This correction had no impact on the year ended December 31, 2018. We evaluated these errors under the guidance of Accounting Standards Codification 250, Accounting Changes and Error Corrections ("ASC 250"). Based on the guidance in ASC 250, we determined that the errors did not have a material impact on our previously-issued financial statements or those of the period of correction. +During 2017, we recorded a charge related to two exploratory dry holes we had drilled in the western area of our Culberson County acreage in the Delaware Basin. We then assessed the impact of the dry holes and various factors related thereto, including the operational and geologic data obtained, the current increased cost environment for drilling and completion services in the Delaware Basin, our decreased future commodity price outlook and the terms of the related lease agreements. Based on the results of this assessment, we concluded that the underlying geologic risk and the challenged economics of future capital expenditures reduced the likelihood that we would perform future development in this area over the remaining lease term for this acreage. Accordingly, we recorded an impairment of $251.6 million covering approximately 13,400 acres during 2017. The amount of the impairment was based on the value assigned to individual lease acres in the final purchase price allocation of the Delaware Basin acquisition. This allocation had included the consideration paid to the sellers, including the effect of the non-cash impact from the deferred tax liability created at the time of the acquisition. We recorded approximately $29 million of additional lease impairments in the Delaware Basin and an impairment charge of $2.1 million related to the Utica Shale properties that were classified as held-for-sale during 2017. Due to the aforementioned events and circumstances, we also evaluated our proved property for possible impairment and concluded that no further impairments were necessary. Future deterioration of commodity prices or other operating circumstances could result in additional impairment charges to our properties and equipment. +Suspended Well Costs. The following table presents the capitalized exploratory well cost pending determination of proved reserves and included in properties and equipment, net on the consolidated balance sheets: +As of December 31, +2018 +2017 +(in thousands, except for number of wells) +Beginning balance +$ +15,448 +$ +— +Additions to capitalized exploratory well costs pending the determination of proved reserves +35,127 +51,776 +Reclassifications to proved properties +(38,387 +) +(36,328 +) +Balance at December 31, +$ +12,188 +$ +15,448 +Number of wells pending determination +2 +3 +90 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Exploration Expenses. The following table presents the major components of exploration, geologic and geophysical expense: +Year Ended December 31, +2018 +2017 +2016 +(in thousands) +Exploratory dry hole costs +$ +113 +$ +41,297 +$ +— +Geological and geophysical costs, including seismic purchases +3,401 +3,881 +3,472 +Operating, personnel and other +2,690 +2,156 +1,197 +Total exploration, geologic and geophysical expense +$ +6,204 +$ +47,334 +$ +4,669 +Exploratory dry hole costs. During 2017, two exploratory dry holes, associated lease costs and related infrastructure assets in the Delaware Basin were expensed at a cost of $41.3 million . The conclusion to expense these items was based on our determination that the acreage on which these wells were drilled was exploratory in nature and, following drilling, that the hydrocarbon production was insufficient for the wells to be deemed economically viable. +NOTE 9 - GOODWILL +Goodwill that resulted from the purchase price allocation of a business combination in the Delaware Basin in December 2016 was determined to be $ 75.1 million . In 2017, we evaluated goodwill for impairment by performing a quantitative test, which involves comparing the estimated fair value of the goodwill reporting unit, which we define as the Delaware Basin, to the carrying value. We determined the fair value of the goodwill by using an estimated after-tax future discounted cash flow analysis, along with a combination of market-based pricing factors for similar acreage, reserve valuation techniques and other fair value considerations. The discounted cash flow analysis used to estimate fair value was based on known or knowable information at the interim measurement date. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. The quantitative test resulted in a determination that a full impairment charge of $ 75.1 million was required; therefore, the charge was recorded in 2017. +91 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 10 - LONG-TERM DEBT +Long-term debt consists of the following: +As of December 31, +2018 +2017 +(in thousands) +Senior notes: +1.125% Convertible Notes due 2021: +Principal amount +$ +200,000 +$ +200,000 +Unamortized discount +(22,766 +) +(30,328 +) +Unamortized debt issuance costs +(2,640 +) +(3,615 +) +1.125% Convertible Notes due 2021, net of unamortized discount and debt issuance costs +174,594 +166,057 +6.125% Senior Notes due 2024: +Principal amount +400,000 +400,000 +Unamortized debt issuance costs +(5,590 +) +(6,570 +) +6.125% Senior Notes due 2024, net of unamortized debt issuance costs +394,410 +393,430 +5.75% Senior Notes due 2026: +Principal amount +600,000 +600,000 +Unamortized debt issuance costs +(6,628 +) +(7,555 +) +5.75% Senior Notes due 2026, net of unamortized debt issuance costs +593,372 +592,445 +Total senior notes +1,162,376 +1,151,932 +Revolving credit facility +32,500 +— +Total long-term debt, net of unamortized discount and debt issuance costs +1,194,876 +1,151,932 +Less current portion of long-term debt +— +— +Long-term debt +$ +1,194,876 +$ +1,151,932 +Senior Notes +2021 Convertible Notes. In September 2016 , we issued $200.0 million of 1.125% convertible senior notes due 2021 in a public offering. The 2021 Convertible Notes are governed by an indenture dated September 14, 2016. The maturity for the payment of principal is September 15, 2021 . Interest at the rate of 1.125% per year is payable in cash semiannually in arrears on each March 15 and September 15 . The proceeds from the issuance of the 2021 Convertible Notes, after deducting offering expenses and underwriting discounts, were used to fund a portion of the purchase price of acquisitions in the Delaware Basin, to pay related fees and expenses and for general corporate purposes. +The 2021 Convertible Notes are convertible prior to March 15, 2021 only upon specified events and during specified periods and, thereafter, at any time, in each case at an initial conversion rate of 11.7113 shares of our common stock per $1,000 principal amount of the 2021 Convertible Notes, which is equal to an initial conversion price of approximately $85.39 per share. The conversion rate is subject to adjustment upon certain events. Upon conversion, the 2021 Convertible Notes may be settled, at our sole election, in shares of our common stock, cash or a combination thereof. We have initially elected a combination settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the 2021 Convertible Notes in cash and to settle the excess conversion value, if any, in shares, as well as cash in lieu of fractional shares. +We may not redeem the 2021 Convertible Notes prior to their maturity date. If we undergo a "fundamental change", as defined in the indenture for the 2021 Convertible Notes, subject to certain conditions, holders of the 2021 Convertible Notes may require us to repurchase all or part of the 2021 Convertible Notes for cash at a price equal to 100 percent of the principal amount of the 2021 Convertible Notes to be repurchased, plus any accrued and unpaid interest to, but excluding, the fundamental change repurchase date. The occurrence of a fundamental change will also result in the 2021 Convertible Notes becoming convertible. +92 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +We allocated the gross proceeds of the 2021 Convertible Notes between the liability and equity components of the debt. The initial $160.5 million liability component was determined based on the fair value of similar debt instruments excluding the conversion feature for similar terms and priced on the same day we issued the 2021 Convertible Notes. The initial $39.5 million equity component represents the debt discount and was calculated as the difference between the fair value of the debt and the gross proceeds of the 2021 Convertible Notes. Approximately $4.8 million in costs associated with the issuance of the 2021 Convertible Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. As of December 31, 2018 , the unamortized debt discount will be amortized over the remaining contractual term to maturity of the 2021 Convertible Notes using the effective interest method. Based upon the December 31, 2018 stock price of $29.76 per share, the “if-converted” value of the 2021 Convertible Notes did not exceed the principal amount. +2024 Senior Notes. In September 2016 , we issued $400.0 million aggregate principal amount of 6.125% senior notes due September 2024 . The proceeds from the issuance of the 2024 Senior Notes, after deducting offering expenses and underwriting discounts, were used to fund a portion of the purchase price of acquisitions in the Delaware Basin, to pay related fees and expenses, and for general corporate purposes. +Interest is payable semi-annually in arrears on March 15 and September 15 . Approximately $7.8 million in costs associated with the issuance of the 2024 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. +The 2024 Senior Notes are redeemable after September 15, 2019 at fixed redemption prices beginning at 104.594 percent of the principal amount redeemed. At any time prior to September 15, 2019, we may redeem all or part of the 2024 Senior Notes at a make-whole price set forth in the indenture which generally approximates the present value of the redemption price at September 15, 2019 and remaining interest payments on the 2024 Senior Notes at the time of redemption. +At any time prior to September 15, 2019 , we may redeem up to 35 percent of the outstanding 2024 Senior Notes with proceeds from certain equity offerings at a redemption price of 106.125 percent of the principal amount of the notes redeemed, plus accrued and unpaid interest, if at least 65 percent of the aggregate principal amount of the 2024 Senior Notes remains outstanding after each such redemption and the redemption occurs within 180 days after the closing of the equity offering. +Upon the occurrence of a "change of control," as defined in the indenture for the 2024 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we may, under certain circumstances, be required to use the net cash proceeds of such asset sale to make an offer to purchase the notes at 100 percent of the principal amount, together with any accrued and unpaid interest to the date of purchase. +2026 Senior Notes. In November 2017, we issued $600.0 million aggregate principal amount 5.75% senior notes due May 15, 2026. The 2026 Senior Notes are governed by an indenture dated November 29, 2017 . The maturity for the payment of principal is May 15, 2026 . Interest at the rate of 5.75% per year is payable in cash semiannually in arrears on each May 15 and November 15 . Approximately $7.6 million in costs associated with the issuance of the 2026 Senior Notes have been capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes using the effective interest method. +The 2026 Senior Notes are redeemable after May 15, 2021 at fixed redemption prices beginning at 104.313 percent of the principal amount redeemed. At any time prior to May 15, 2021 , we may redeem all or part of the 2026 Senior Notes at a make-whole price set forth in the indenture which generally approximates the present value of the redemption price at May 15, 2021 and remaining interest payments on the 2026 Senior Notes at the time of redemption. +At any time prior to May 15, 2021 we may redeem up to 35 percent of the outstanding 2026 Senior Notes with proceeds from certain equity offerings at a redemption price of 105.75 percent of the principal amount of the notes redeemed, plus accrued and unpaid interest, if at least 65 percent of the aggregate principal amount of the 2026 Senior Notes remains outstanding after each such redemption and the redemption occurs within 180 days after the closing of the equity offering. +Upon the occurrence of a "change of control," as defined in the indenture for the 2026 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we may, under certain circumstances, be required to use the net cash proceeds of such asset sale to make an +93 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +offer to purchase the notes at 100 percent of the principal amount, together with any accrued and unpaid interest to the date of purchase. +The 2021 Convertible Notes, the 2024 Senior Notes and the 2026 Senior notes are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the notes; equal in right of payment to our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries. Our wholly-owned subsidiary, PDC Permian, Inc., is a guarantor of our obligations under the 2021 Convertible Notes, the 2024 Senior Notes and the 2026 Senior Notes. +The indentures governing the 2024 Senior Notes and 2026 Senior Notes contain covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make investments; create certain liens; enter into agreements that restrict distributions or other payments by restricted subsidiaries to us; enter into transactions with affiliates; sell assets; consolidate or merge with or into other companies or transfer all or substantially of our assets; and create unrestricted subsidiaries. +As of December 31, 2018 , we were in compliance with all covenants related to the 2021 Convertible Notes, 2024 Convertible Notes and the 2026 Senior Notes. +Revolving Credit Facility +In May 2018, we entered into a Fourth Amended and Restated Credit Agreement (the “Restated Credit Agreement”). The Restated Credit Agreement amends and restates our Third Amended and Restated Credit Agreement dated as of May 21, 2013, as amended. Among other things, the Restated Credit Agreement provides for a maximum credit amount of $2.5 billion , an initial borrowing base of $1.3 billion and an initial elected commitment amount of $700 million . The amount we may borrow under the Restated Credit Agreement is subject to certain limitations under our Notes. In addition, the Restated Credit Agreement extends the maturity date of the facility to May 2023 , reflects improved covenant flexibility and certain reductions in interest rates applicable to borrowings under the facility and includes a $25 million swingline facility. In October 2018, we increased the commitment level on our revolving credit facility to the current borrowing base amount of $1.3 billion . +The revolving credit facility is available for working capital requirements, capital investments, acquisitions, to support letters of credit and for general corporate purposes. The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. The borrowing base is subject to a semi-annual redetermination on November 1 and May 1 based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. +The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greatest of the administrative agent's prime rate, the federal funds rate plus a premium and the rate for dollar deposits in the London interbank market (“LIBOR”) for one month plus a premium) or, at our election, a rate equal to LIBOR for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. As of December 31, 2018 , the applicable interest margin is 0.25 percent for the alternate base rate option or 1.25 percent for the LIBOR option, and the unused commitment fee is 0.375 percent . Principal payments are generally not required until the revolving credit facility expires in May 2023 , unless the borrowing base falls below the outstanding balance. +The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.0:1.0 and (b) not exceed a maximum leverage ratio of 4.0:1.0. As of December 31, 2018 , we were in compliance with all the revolving credit facility covenants. +As of December 31, 2018 and 2017 , debt issuance costs related to our revolving credit facility were $11.5 million and $6.2 million , respectively, and are included in other assets on the consolidated balance sheets. As of December 31, 2018 and 2017 , availability under our revolving credit facility was $1.3 billion and $ 700 million , respectively. As of December 31, 2018 , the weighted-average interest rate on the outstanding balance on our revolving credit facility, exclusive of fees on the unused commitment, was 4.5 percent . +NOTE 11 - CAPITAL LEASES +We periodically enter into non-cancelable lease agreements for vehicles utilized by our operations and field personnel. These leases are being accounted for as capital leases, as the present value of minimum monthly lease payments, including the residual value guarantee, exceeds 90 percent of the fair value of the leased vehicles at inception of the lease. +The following table presents leased vehicles under capital leases: +As of December 31, +2018 +2017 +(in thousands) +Vehicles +$ +7,941 +$ +6,249 +Accumulated depreciation +(3,368 +) +(1,882 +) +$ +4,573 +$ +4,367 +Future minimum lease payments by year and in the aggregate, under non-cancelable capital leases with terms of one year or more, consist of the following: +For the Twelve Months Ending December 31, +Amount +(in thousands) +2019 +$ +2,111 +2020 +2,236 +2021 +698 +2022 +381 +2023 +134 +5,560 +Less executory cost +(278 +) +Less amount representing interest +(603 +) +Present value of minimum lease payments +$ +4,679 +Short-term capital lease obligations +$ +1,779 +Long-term capital lease obligations +2,900 +$ +4,679 +Short-term capital lease obligations are included in other accrued expenses on the consolidated balance sheets. Long-term capital lease obligations are included in other liabilities on the consolidated balance sheets. +94 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 12 - ASSET RETIREMENT OBLIGATIONS +The following table presents the changes in carrying amounts of the asset retirement obligations associated with our crude oil and natural gas properties and midstream assets: +Year Ended December 31, +2018 +2017 +(in thousands) +Beginning balance +$ +87,306 +$ +92,387 +Obligations incurred with development activities +2,793 +3,638 +Obligations incurred with acquisition +4,332 +— +Accretion expense +5,075 +6,306 +Revisions in estimated cash flows +30,166 +(2,860 +) +Obligations discharged with asset retirements +(14,651 +) +(12,165 +) +Balance at December 31 +115,021 +87,306 +Less liabilities held-for-sale +(4,111 +) +(499 +) +Less current portion +(25,598 +) +(15,801 +) +Long-term portion +$ +85,312 +$ +71,006 +Our estimated asset retirement obligations liability is based on historical experience in plugging and abandoning wells, estimated economic lives and estimated plugging and abandonment costs considering federal and state regulatory requirements in effect. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations liability, a corresponding adjustment is made to the properties and equipment balance. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as accretion expense. Short-term asset retirement obligations are included in other accrued expenses on the consolidated balance sheets. +The revisions in estimated cash flows during 2018 were primarily due to changes in estimates of costs for materials and services related to the plugging and abandonment of wells and the shortening of the estimated expected lives of wells. +NOTE 13 - COMMITMENTS AND CONTINGENCIES +Firm Transportation and Processing Agreements. We enter into contracts that provide firm transportation and processing on pipeline systems through which we transport or sell crude oil and natural gas. Satisfaction of the volume requirements includes volumes produced by us, purchased from third parties and produced by our affiliated partnerships and other third-party working, royalty and overriding royalty interest owners, whose volumes we market on their behalf. Our consolidated statements of operations reflect our share of these firm transportation and processing costs. These contracts require us to pay these transportation and processing charges whether or not the required volumes are delivered. +95 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents gross volume information related to our long-term firm transportation, sales and processing agreements for pipeline capacity and water delivery and disposal commitments: +Year Ending December 31, +Area +2019 +2020 +2021 +2022 +2022 and +Through +Expiration +Total +Expiration +Date +Natural gas (MMcf) +Wattenberg Field +23,934 +31,110 +31,025 +31,025 +90,897 +207,991 +April 30, 2026 +Delaware Basin +48,147 +37,430 +21,307 +— +— +106,884 +December 31, 2021 +Gas Marketing +7,117 +7,136 +7,056 +4,495 +— +25,804 +August 31, 2022 +Total +79,198 +75,676 +59,388 +35,520 +90,897 +340,679 +Crude oil (MBbls) +Wattenberg Field +9,713 +5,918 +5,475 +5,475 +3,180 +29,761 +April 30, 2023 +Delaware Basin +7,359 +8,784 +8,030 +8,030 +8,030 +40,233 +December 31, 2023 +Total +17,072 +14,702 +13,505 +13,505 +11,210 +69,994 +Water (MBbls) +Wattenberg Field +3,103 +6,207 +6,207 +6,207 +12,413 +34,137 +December 31, 2024 +Delaware Basin +3,650 +3,660 +3,650 +3,650 +1,770 +16,380 +June 26, 2023 +Total +6,753 +9,867 +9,857 +9,857 +14,183 +50,517 +Dollar commitment (in thousands) +$ +106,844 +$ +78,209 +$ +74,409 +$ +67,354 +$ +102,925 +$ +429,741 +Wattenberg Field. In anticipation of our future drilling activities in the Wattenberg Field, we have entered into two facilities expansion agreements with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities. The midstream provider completed and turned on line the first of the two 200 MMcfd cryogenic plants in August 2018. The second plant is currently scheduled to be completed in the second quarter of 2019. We are bound to the volume requirements in these agreements on the first day of the calendar month following the actual in-service date of the relevant plant. Both agreements require baseline volume commitments, consisting of our gross wellhead volume delivered in November 2016 to this midstream provider, and incremental wellhead volume commitments of 51.5 MMcfd and 33.5 MMcfd for the first and second agreements, respectively, for seven years. We may be required to pay shortfall fees for any volumes under the 51.5 MMcfd and 33.5 MMcfd incremental commitments. Any shortfall in these volume commitments may be offset by other producers’ volumes sold to the midstream provider that are greater than a certain total baseline volume. We are also required for the first three years of the contracts to guarantee a certain target profit margin to the midstream provider on these incremental volumes. +Delaware Basin . In May 2018, we entered into a firm sales agreement that is effective from June 2018 through December 2023 with an integrated marketing company for our crude oil production in the Delaware Basin. Contracted volumes are currently 14,600 barrels of crude oil per day and increase over time to 26,400 barrels of crude oil per day. These agreements are expected to provide price diversification through realization of export market pricing via a Corpus Christi terminal and exposure to Brent-weighted prices. +Commodity Sales . For 2018 , amounts related to long-term transportation volumes, net to our interest, for Wattenberg Field crude oil and Delaware Basin natural gas were $27.3 million and in accordance with the guidance in the New Revenue Standard, were netted against our crude oil and natural gas sales in our consolidated statements of operations. In addition, for 2018 , $1.6 million related to long-term transportation volumes were recorded in transportation, gathering and processing expense in our consolidated statements of operations. For each of 2017 and 2016 , amounts related to long-term transportation volumes for Wattenberg Field crude oil and Utica Shale natural gas were $10.0 million and were recorded in transportation, gathering and processing expense in our consolidated statements of operations. In March 2018, we completed the disposition of our Utica Shale properties. +Litigation and Legal Items. We are involved in various legal proceedings. We review the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in our best interests. We have provided the necessary estimated accruals in the accompanying balance +96 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity. +Action Regarding Partnerships . In December 2017, we received an action entitled Dufresne, et al. v. PDC Energy, et al., filed in the United States District Court for the District of Colorado. The complaint states that it is a derivative action brought by a number of limited partner investors seeking to assert claims on behalf of our two affiliated partnerships, Rockies Region 2006 LP and Rockies Region 2007 LP (collectively, the "Partnerships"), against PDC and includes claims for breach of fiduciary duty and breach of contract. The plaintiffs also included claims against two of our senior officers and three independent members of our Board of Directors for alleged breach of fiduciary duty. The lawsuit accuses PDC, as the managing general partner of the Partnerships, of, among other things, failing to maximize the productivity of the Partnerships’ crude oil and natural gas wells and improperly assigning the Partnerships only interests in the wells, as opposed to leasehold interests in surrounding acreage. In late April 2018, the plaintiffs filed an amendment to their complaint, which alleges additional facts and purports to add direct class action claims in addition to the original derivative claims. We filed a motion to dismiss this amended complaint and the claims against the individuals named as defendants on July 31, 2018. On February 19, 2019, the court granted the motion to dismiss, in part. It dismissed all claims against the individuals named as defendants. It also held that that the plaintiffs were time-barred from using the failure to assign acreage assignments to support their claims for breach of fiduciary duty against PDC. This action has been stayed as a result of the partnership bankruptcy proceedings described in Partnership Bankruptcy Filings below. We are currently unable to estimate any potential damages resulting from this lawsuit. +Partnership Bankruptcy Filings. On October 30, 2018, the Partnerships filed petitions under Chapter 11 of the Bankruptcy Code (the "Chapter 11 Proceedings") in the United States Bankruptcy Court for the Northern District of Texas, Dallas Division (the "Bankruptcy Court"). The Partnerships intend to enter into a transaction with us, pursuant to which the Partnerships will sell substantially all of their assets to us through a Chapter 11 plan of liquidation (the "Chapter 11 Plan") and provide a release of any claims, including those asserted in Dufresne, et al. v. PDC Energy, et al. (the "Dufresne Case"). The Partnerships remain in possession of their assets and continue to operate their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court. In addition, a third-party (the “Responsible Party”) has been designated for the Partnerships. The Responsible Party is expected to oversee all actions for the Partnerships in connection with the Chapter 11 Proceedings, including actions relating to the anticipated transactions with us and seeking approval of the Chapter 11 Plan. In late November and early December, 2018 the plaintiffs in the Dufresne Case filed several pleadings in the Bankruptcy Court, including one to dismiss the bankruptcy on grounds that PDC had no authority to hire the Responsible Party, the Responsible Party had no authority to cause the Partnerships to file bankruptcy, and the bankruptcy was filed solely for the purpose to gain a litigation advantage in and dismiss the Dufresne Case. The parties have agreed to mediate their disputes with respect to the Dufresne Case and the bankruptcy cases. As a result, on December 17, 2018 the Bankruptcy Court entered an agreed order staying the bankruptcy motions and the Dufresne Case until March 20, 2019 to allow the parties to mediate their disputes. We do not believe that the Partnership's Chapter 11 Proceedings will have a material adverse effect on our financial position, results of operations or liquidity, but we cannot predict the outcome of such proceedings. +Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as discussed herein, we are not aware of any material environmental claims existing as of December 31, 2018 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws or other environmental liabilities will not be discovered on our properties. Accrued environmental liabilities are recorded in other accrued expenses on the consolidated balance sheets. The liability ultimately incurred with respect to a matter may exceed the related accrual. +On October 23, 2018, we agreed to an Administrative Order by Consent ("AOC") with the Colorado Oil and Gas Conservation Commission relating to a historical release discovered during the decommissioning of a location in Weld County, Colorado, pursuant to which, among other things, we agreed to a penalty of approximately $130,000 , of which 20 percent would be suspended subject to compliance with certain corrective actions identified in the AOC. In addition to the penalty, we agreed to timely complete certain corrective actions set forth in the AOC relating to procedures for completing future work on buried or partially buried produced water vessels, and to reestablish vegetation and otherwise reclaim the location. +97 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Clean Air Act Agreement and Related Consent Decree. In June 2017, following our receipt of a 2015 Clean Air Act information request from the EPA and a 2015 compliance advisory from the Colorado Department of Public Health and Environment's (“CDPHE”) Air Pollution Control Division, the U.S. Department of Justice, on behalf of the EPA and the state of Colorado, filed a complaint against us in the U.S. District Court for the District of Colorado, claiming that we failed to operate and maintain certain condensate collection facilities at 65 facilities so as to minimize leakage of volatile organic compounds in compliance with applicable law. +In October 2017, we entered into a consent decree to resolve the lawsuit and the compliance advisory. Pursuant to the consent decree, we agreed to implement a variety of operational enhancements and mitigation and similar projects, including vapor control system modifications and verification, increased inspection and monitoring and installation of tank pressure monitors. The three primary elements of the consent decree are: (i) fine/supplemental environmental projects ( $1.5 million cash fine, plus $1 million in supplemental environmental projects) of which the cash fines and the full cost of supplemental environmental projects were paid in the first and third quarters of 2018, respectively, (ii) injunctive relief with an estimated cost of approximately $18 million , primarily representing capital enhancements to our operations and (iii) mitigation with an estimated cost of $1.7 million . We continue to incur costs associated with these activities. If we fail to comply fully with the requirements of the consent decree with respect to those matters, we could be subject to additional liability. We do not believe that the expenditures resulting from the settlement will have a material adverse effect on our consolidated financial statements. +We are in the process of implementing the consent degree program. Over the course of its execution, we have identified certain immaterial deficiencies in our implementation of the program. We report these immaterial deficiencies to the appropriate authorities and remediate them promptly. We do not believe that the penalties and expenditures associated with the consent decree, including any sanctions associated with these deficiencies, will have a material effect on our financial condition or results of operations, but they may exceed $100,000 . +In addition, in December 2018, we were named as a nominal defendant in a derivative action filed in the Delaware chancery court. The complaint, which seeks unspecified monetary damages and various forms of equitable relief, alleges that certain current and former members of our board of directors violated their fiduciary duties, committed waste and were unjustly enriched by, among other things, failing to implement adequate environmental safeguards in connection with the issues that gave rise to the Department of Justice lawsuit and consent decree. We believe that this lawsuit is without merit but cannot predict its outcome. +In addition, we could be the subject of other enforcement actions by regulatory authorities in the future relating to our past, present or future operations. +Lease Agreements. We entered into operating leases, principally for the leasing of natural gas compressors, office space and general office equipment. +The following table presents the minimum future lease payments under the non-cancelable operating leases as of December 31, 2018 : +Year Ending December 31, +2019 +2020 +2021 +2022 +2023 +Thereafter +Total +(in thousands) +Minimum Lease Payments +$ +6,273 +$ +6,365 +$ +6,290 +$ +5,229 +$ +1,385 +$ +2,256 +$ +27,798 +Operating lease expense for 2018 , 2017 and 2016 was $26.7 million , $17.2 million and $10.2 million , respectively. +98 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 14 - COMMON STOCK +Stock-Based Compensation Plans +2018 Equity Incentive Plan . In May 2018, our stockholders approved a long-term equity compensation plan for our employees and non-employee directors (the “2018 Plan”). The 2018 Plan provides for a reserve of 1,800,000 shares of our common stock that may be issued pursuant to awards under the 2018 Plan and a term that expires in March 2028. As of December 31, 2018 , no shares have been issued under the 2018 plan. Shares issued may be either authorized but unissued shares, treasury shares or any combination. Additionally, the 2018 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited or paid out in the form of cash. However, shares tendered or withheld to satisfy the exercise price of options or tax withholding obligations, and shares covering the portion of exercised stock-settled stock appreciation rights ("SARs") (regardless of the number of shares actually delivered), count against the share limit. Awards may be issued in the form of options, SARs, restricted stock, restricted stock units ("RSUs"), performance stock units ("PSUs") and other stock-based awards. Awards may vest over periods of continued service or the satisfaction of performance conditions set at the discretion of the Compensation Committee of our Board of Directors (the "Compensation Committee"), with a minimum one-year vesting period applicable to most awards. With regard to SARs and options, awards have a maximum exercisable period of ten years. +2010 Long-Term Equity Compensation Plan . Our Amended and Restated 2010 Long-Term Equity Compensation Plan, which was most recently approved by stockholders in 2013 (as the same has been amended and restated from time to time, the "2010 Plan"), will remain outstanding and we may use the 2010 Plan to grant awards. However, the share reserve of the 2010 Plan is nearly depleted. As of December 31, 2018 , there were 284,152 shares available for grant under the 2010 Plan. +The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented: +Year Ended December 31, +2018 +2017 +2016 +(in thousands) +Stock-based compensation expense +$ +21,782 +$ +19,353 +$ +19,502 +Income tax benefit +(5,210 +) +(7,372 +) +(7,296 +) +Net stock-based compensation expense +$ +16,572 +$ +11,981 +$ +12,206 +Stock Appreciation Rights +The SARs vest ratably over a three-year period and may generally be exercised at any point after vesting through ten years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance . +The Compensation Committee awarded SARs to our executive officers in 2017 and 2016 . There were no SARs awarded to our executive officers in 2018 . The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions: +Year Ended December 31, +2017 +2016 +Expected term of award (in years) +6.0 years +6.0 years +Risk-free interest rate +2.0 +% +1.8 +% +Expected volatility +53.3 +% +54.5 +% +Weighted-average grant date fair value per share +$ +38.58 +$ +26.96 +The expected term of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. We do not expect to pay or declare dividends in the foreseeable future. +99 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the changes in our SARs for all periods presented (in thousands, except per share data): +Year Ended December 31, +2018 +2017 +2016 +Number of +SARs +Weighted-Average +Exercise +Price +Average Remaining Contractual +Term (in years) +Aggregate Intrinsic +Value +Number of +SARs +Weighted-Average +Exercise +Price +Aggregate Intrinsic +Value +Number of +SARs +Weighted-Average +Exercise +Price +Aggregate Intrinsic +Value +Outstanding at January 1, +298,220 +$ +47.39 +6.5 +$ +2,490 +244,078 +$ +41.36 +$ +7,620 +326,453 +$ +38.99 +$ +4,697 +Awarded +— +— +— +— +54,142 +74.57 +— +58,709 +51.63 +— +Exercised +— +— +— +— +— +— +— +(141,084 +) +40.16 +2,770 +Modified +63,969 +42.83 +— +— +— +— +— +— +— +— +Expired +(71,931 +) +46.34 +— +— +— +— +— +— +— +— +Outstanding at December 31, +290,258 +46.64 +4.6 +125 +298,220 +47.39 +2,490 +244,078 +41.36 +7,620 +Exercisable at December 31, +260,101 +44.88 +4.3 +125 +223,865 +43.28 +2,267 +174,919 +38.72 +5,924 +We expect all SARs outstanding as of December 31, 2018 to vest. The SARS modified during 2018 were related to one employee and the total compensation cost associated with the modification was not material to our consolidated statement of operations. Total compensation cost related to SARs granted and not yet recognized in our consolidated statements of operations as of December 31, 2018 was $0.5 million . The cost is expected to be recognized over a weighted-average period of 0.5 years . +Restricted Stock Units +Time-Based Awards. The fair value of the time-based RSUs is amortized ratably over the requisite service period, primarily three years. The time-based RSUs generally vest ratably on each anniversary following the grant date that a participant is continuously employed . +The following table presents the changes in non-vested time-based RSUs during 2018 : +Shares +Weighted-Average +Grant Date +Fair Value per Share +Non-vested at December 31, 2017 +472,132 +$ +60.23 +Granted +446,743 +50.69 +Vested +(249,317 +) +58.95 +Forfeited +(51,151 +) +56.45 +Non-vested at December 31, 2018 +618,407 +54.16 +The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: +As of/Year Ended December 31, +2018 +2017 +2016 +(in thousands, except per share data) +Total intrinsic value of time-based awards vested +$ +12,282 +$ +16,303 +$ +18,973 +Total intrinsic value of time-based awards non-vested +18,404 +24,334 +34,812 +Market price per common share as of December 31, +29.76 +51.54 +72.58 +Weighted-average grant date fair value per share +50.69 +65.14 +58.52 +100 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Total compensation cost related to non-vested time-based awards and not yet recognized in our consolidated statements of operations as of December 31, 2018 was $20.7 million . This cost is expected to be recognized over a weighted-average period of 1.8 years. +Performance Stock Units +Market-Based Awards. The fair value of the market-based PSUs is amortized ratably over the requisite service period, primarily three years. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of three years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved . +In February 2018 , the Compensation Committee awarded a total of 90,778 market-based PSUs to our executive officers. In addition to continuous employment, the vesting of these PSUs is contingent on our total stockholder return ("TSR"), which is essentially our stock price change including any dividends over a three-year period ending on December 31, 2020, as compared to the TSR of a group of peer companies over the same period. The PSUs will result in a payout between 0 percent and 200 percent of the target PSUs awarded. The weighted-average grant date fair value per PSU granted was computed using the Monte Carlo pricing model using the following assumptions: +Year Ended December 31, +2018 +2017 +2016 +Expected term of award (in years) +3 years +3 years +3 years +Risk-free interest rate +2.4 +% +1.4 +% +1.2 +% +Expected volatility +42.3 +% +51.4 +% +52.3 +% +The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our historical volatility. +The following table presents the change in non-vested market-based awards during 2018 : +Shares +Weighted-Average +Grant Date +Fair Value per Share +Non-vested at December 31, 2017 +52,349 +$ +84.06 +Granted +90,778 +69.98 +Vested +(18,941 +) +72.54 +Forfeited +(21,272 +) +78.65 +Non-vested at December 31, 2018 +102,914 +74.88 +The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: +As of/Year Ended December 31, +2018 +2017 +2016 +(in thousands, except per share data) +Total intrinsic value of market-based awards vested +$ +620 +$ +2,687 +$ +6,562 +Total intrinsic value of market-based awards non-vested +3,063 +2,698 +3,514 +Market price per common share as of December 31, +29.76 +51.54 +72.58 +Weighted-average grant date fair value per share +69.98 +94.02 +72.54 +Total compensation cost related to non-vested market-based awards not yet recognized in our consolidated statements of operations as of December 31, 2018 was $4.7 million . This cost is expected to be recognized over a weighted-average period of 1.8 years. +101 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Treasury Share Purchases +In accordance with our stock-based compensation plans, employees may surrender shares of our common stock to settle tax withholding obligations upon the vesting and exercise of share-based awards. Shares acquired that had been issued pursuant to the 2010 Plan are withheld for reissuance for new grants. For shares reissued for new grants under the 2010 Plan, shares are recorded at cost and upon reissuance we reduce the carrying value of shares acquired and held pursuant to the 2010 Plan by the weighted-average cost per share with an offsetting charge to APIC. During the year ended December 31, 2018 , we acquired 102,647 shares for payment of tax liabilities and reissued 104,068 shares. As of December 31, 2018 , 33,105 shares were available for reissuance pursuant to our 2010 Plan. During the year ended December 31, 2017 , we acquired 107,357 shares for payment of tax liabilities and reissued 83,228 shares. As of December 31, 2017 , 34,526 shares were available for reissuance pursuant to our 2010 Plan. In addition to the shares available for reissuance as of December 31, 2018 and 2017 , we had 12,115 shares and 21,401 shares, respectively, of treasury stock related to a rabbi trust. +Preferred stock +We are authorized to issue 50,000,000 shares of preferred stock, par value $0.01, in one or more series, with such rights, preferences, privileges and restrictions as shall be fixed by our Board of Directors at the time of issuance. As of December 31, 2018 , no preferred shares had been issued. +NOTE 15 - INCOME TAXES +The table below presents the components of our provision for income tax (expense) benefit for the years presented: +Year Ended December 31, +2018 +2017 +2016 +(in thousands) +Current: +Federal +$ +886 +$ +8,443 +$ +9,646 +State +(188 +) +(200 +) +300 +Total current income tax benefit +698 +8,243 +9,946 +Deferred: +Federal +(1,986 +) +193,809 +118,427 +State +(4,118 +) +9,876 +18,822 +Total deferred income tax (expense) benefit +(6,104 +) +203,685 +137,249 +Income tax (expense) benefit +$ +(5,406 +) +$ +211,928 +$ +147,195 +The following table presents a reconciliation of the federal statutory rate to the effective tax rate related to our (expense) benefit for income taxes: +Year Ended December 31, +2018 +2017 +2016 +Federal statutory tax rate +21.0 +% +35.0 +% +35.0 +% +State income tax, net +(6.4 +) +1.8 +2.6 +Federal tax credits +(52.1 +) +— +— +Effect of state income tax rate changes +6.7 +— +0.6 +Change in valuation allowance +45.5 +— +— +Non-deductible compensation +21.8 +(0.3 +) +(0.5 +) +Non-deductible government relations +31.8 +— +— +Other non-deductible items +4.9 +— +— +Federal tax reform rate reduction +— +33.7 +— +Non-deductible goodwill impairment +— +(7.7 +) +— +Other +(0.4 +) +(0.1 +) +(0.3 +) +Effective tax rate +72.8 +% +62.4 +% +37.4 +% +102 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Tax effects of temporary differences that give rise to significant portions of deferred tax assets and deferred tax liabilities at December 31, 2018 and 2017 are presented below. The 2017 amounts include the reduction of our deferred tax assets and liabilities to a projected combined federal and state deferred tax rate of 23.9 percent as a result of the 2017 Tax Act. +As of December 31, +2018 +2017 +(in thousands) +Deferred tax assets: +Deferred compensation +$ +9,963 +$ +6,059 +Asset retirement obligations +27,166 +21,760 +Federal NOL carryforward +54,736 +19,386 +State NOL and tax credit carryforwards, net +13,223 +7,815 +Federal tax - credit carryforwards +7,756 +4,366 +Net change in fair value of unsettled derivatives +— +20,929 +Prepaid revenue +5,288 +— +Other +4,647 +2,453 +Valuation allowance +(3,380 +) +— +Total gross deferred tax assets +119,399 +82,768 +Deferred tax liabilities: +Properties and equipment +270,565 +267,498 +Net change in fair value of unsettled derivatives +41,496 +— +Convertible debt +5,434 +7,262 +Total gross deferred tax liabilities +317,495 +274,760 +Net deferred tax liability +$ +198,096 +$ +191,992 +During the year ending December 31, 2018 , we generated a federal net operating loss ("NOL") of $169.1 million and have prior year federal NOL carryforwards of $31.5 million that will begin to expire in 2036. Also, we acquired a federal NOL of $60.1 million as a component of our 2016 acquisition in the Delaware Basin that will begin to expire in 2034 and is subject to an annual limitation of $15.1 million as a result of the acquisition, which constitutes a change of ownership as defined under IRS Code Section 382. +We have a marginal gas well credit of $5.1 million that can be carried forward 20 years and we have alternative minimum tax credits of $2.7 million that may be carried forward, and pursuant to the new tax law will be refunded over the next three years. +As of December 31, 2018 , we have state NOL carryforwards of $284.6 million that begin to expire in 2030 and state credit carryforwards of $3.3 million that begin to expire in 2022 . Due to the potential non-utilization of our state tax credit carryforwards before their expiration, we have recorded a valuation allowance for the future tax benefit of these credit carryforwards. +Unrecognized tax benefits and related accrued interest and penalties were immaterial for the three-year period ended December 31, 2018 . The statutes of limitations for most of our state tax jurisdictions are open for tax year 2014 forward. +The IRS partially accepted our 2017 tax return. The 2017 tax return is in the IRS CAP Program post-filing review process, with no significant tax adjustments currently proposed. We are currently participating in the CAP Program for the review of our 2018 through 2019 tax years. Participation in the CAP Program has enabled us to have minimal uncertain tax benefits associated with our federal tax return filings. +As of December 31, 2018 , we were current with our income tax filings in all applicable state jurisdictions. +103 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 16 - EARNINGS PER SHARE +Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, stock options, convertible notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. +The following table presents our weighted-average basic and diluted shares outstanding: +Year Ended December 31, +2018 +2017 +2016 +(in thousands) +Weighted-average common shares outstanding - basic +66,059 +65,837 +49,052 +Dilutive effect of: +RSUs and PSUs +173 +— +— +Other equity-based awards +71 +— +— +Weighted-average common shares and equivalents outstanding - diluted +66,303 +65,837 +49,052 +For 2017 and 2016 , we reported a net loss. As a result, our basic and diluted weighted-average common shares outstanding were the same because the effect of the common share equivalents was anti-dilutive. +The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect: +Year Ended December 31, +2018 +2017 +2016 +(in thousands) +Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: +RSUs and PSUs +145 +590 +689 +Convertible notes +— +— +292 +Other equity-based awards +109 +75 +109 +Total anti-dilutive common share equivalents +254 +665 +1,090 +In September 2016 , we issued the 2021 Convertible Notes, which gave the holders the right to convert the aggregate principal amount into 2.3 million shares of our common stock at a conversion price of $85.39 per share. The 2021 Convertible Notes would be included in the diluted earnings per share calculation using the treasury stock method if the average market share price had exceeded the $85.39 conversion price during the periods presented. +104 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 17 - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION +Year Ended December 31, +2018 +2017 +2016 +(in thousands) +Supplemental cash flow information: +Cash payments (receipts) for: +Interest, net of capitalized interest +$ +55,586 +$ +69,880 +$ +43,406 +Income taxes +(6,719 +) +(13,925 +) +167 +Non-cash investing activities: +Issuance of common stock for acquisition of crude oil and natural gas properties +— +— +690,702 +Change in accounts payable related to capital expenditures +36,328 +50,761 +(40,448 +) +Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposal +37,136 +839 +4,894 +Purchase of properties and equipment under capital leases +1,940 +3,497 +1,404 +105 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 18 - SUBSIDIARY GUARANTOR +PDC Permian, Inc., our wholly-owned subsidiary, guarantees our obligations under our publicly-registered senior notes. The following presents the consolidating financial information separately for: +(i) +PDC Energy, Inc. ("Parent"), the issuer of the guaranteed obligations, including non-material subsidiaries; +(ii) +PDC Permian, Inc., the guarantor subsidiary ("Guarantor"), as specified in the indentures related to our senior notes; +(iii) +Eliminations representing adjustments to (a) eliminate intercompany transactions between or among Parent, Guarantor and our other subsidiaries and (b) eliminate the investments in our subsidiaries; and +(iv) +Parent and subsidiaries on a consolidated basis ("Consolidated"). +The Guarantor was 100 percent owned by the Parent beginning in December 2016. The senior notes are fully and unconditionally guaranteed on a joint and several basis by the Guarantor. The guarantee is subject to release in limited circumstances only upon the occurrence of certain customary conditions. Each entity in the consolidating financial information follows the same accounting policies as described in the notes to the consolidated financial statements. +The following consolidating financial statements have been prepared on the same basis of accounting as our consolidated financial statements. Investments in subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Parent and Guarantor are reflected in the eliminations column. +106 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Consolidating Balance Sheets +December 31, 2018 +Parent +Guarantor +Eliminations +Consolidated +(in thousands) +Assets +Current assets: +Cash and cash equivalents +$ +1,398 +$ +— +$ +— +$ +1,398 +Accounts receivable, net +146,529 +34,905 +— +181,434 +Fair value of derivatives +84,492 +— +— +84,492 +Prepaid expenses and other current assets +6,725 +411 +— +7,136 +Total current assets +239,144 +35,316 +— +274,460 +Properties and equipment, net +2,270,711 +1,732,151 +— +4,002,862 +Assets held-for-sale +— +140,705 +— +140,705 +Intercompany receivable +451,601 +— +(451,601 +) +— +Investment in subsidiaries +1,316,945 +— +(1,316,945 +) +— +Fair value of derivatives +93,722 +— +— +93,722 +Other assets +30,084 +2,312 +— +32,396 +Total Assets +$ +4,402,207 +$ +1,910,484 +$ +(1,768,546 +) +$ +4,544,145 +Liabilities and Stockholders' Equity +Liabilities +Current liabilities: +Accounts payable +$ +110,847 +$ +71,017 +$ +— +$ +181,864 +Production tax liability +53,309 +7,410 +— +60,719 +Fair value of derivatives +3,364 +— +— +3,364 +Funds held for distribution +90,183 +15,601 +— +105,784 +Accrued interest payable +14,143 +7 +— +14,150 +Other accrued expenses +73,689 +1,444 +— +75,133 +Total current liabilities +345,535 +95,479 +— +441,014 +Intercompany payable +— +451,601 +(451,601 +) +— +Long-term debt +1,194,876 +— +— +1,194,876 +Deferred income taxes +162,368 +35,728 +— +198,096 +Asset retirement obligations +79,904 +5,408 +— +85,312 +Liabilities held-for-sale +— +4,111 +— +4,111 +Fair value of derivatives +1,364 +— +— +1,364 +Other liabilities +91,452 +1,212 +— +92,664 +Total liabilities +1,875,499 +593,539 +(451,601 +) +2,017,437 +Stockholders' equity +Common shares +661 +— +— +661 +Additional paid-in capital +2,519,423 +1,766,775 +(1,766,775 +) +2,519,423 +Retained earnings +8,727 +(449,830 +) +449,830 +8,727 +Treasury shares +(2,103 +) +— +— +(2,103 +) +Total stockholders' equity +2,526,708 +1,316,945 +(1,316,945 +) +2,526,708 +Total Liabilities and Stockholders' Equity +$ +4,402,207 +$ +1,910,484 +$ +(1,768,546 +) +$ +4,544,145 +107 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Consolidating Balance Sheets +December 31, 2017 +Parent +Guarantor +Eliminations +Consolidated +(in thousands) +Assets +Current assets: +Cash and cash equivalents +$ +180,675 +$ +— +$ +— +$ +180,675 +Accounts receivable, net +160,490 +37,108 +— +197,598 +Fair value of derivatives +14,338 +— +— +14,338 +Prepaid expenses and other current assets +8,284 +329 +— +8,613 +Total current assets +363,787 +37,437 +— +401,224 +Properties and equipment, net +1,891,314 +2,042,153 +— +3,933,467 +Assets held-for-sale +40,583 +— +— +40,583 +Intercompany receivable +250,279 +— +(250,279 +) +— +Investment in subsidiaries +1,617,537 +— +(1,617,537 +) +— +Other assets +42,547 +2,569 +— +45,116 +Total Assets +$ +4,206,047 +$ +2,082,159 +$ +(1,867,816 +) +$ +4,420,390 +Liabilities and Stockholders' Equity +Liabilities +Current liabilities: +Accounts payable +$ +85,000 +$ +65,067 +$ +— +$ +150,067 +Production tax liability +35,902 +1,752 +— +37,654 +Fair value of derivatives +79,302 +— +— +79,302 +Funds held for distribution +83,898 +11,913 +— +95,811 +Accrued interest payable +11,812 +3 +— +11,815 +Other accrued expenses +42,543 +444 +— +42,987 +Total current liabilities +338,457 +79,179 +— +417,636 +Intercompany payable +— +250,279 +(250,279 +) +— +Long-term debt +1,151,932 +— +— +1,151,932 +Deferred income taxes +62,857 +129,135 +— +191,992 +Asset retirement obligations +65,301 +5,705 +— +71,006 +Liabilities held-for-sale +499 +— +— +499 +Fair value of derivatives +22,343 +— +— +22,343 +Other liabilities +57,009 +324 +— +57,333 +Total liabilities +1,698,398 +464,622 +(250,279 +) +1,912,741 +Stockholders' equity +Common shares +659 +— +— +659 +Additional paid-in capital +2,503,294 +1,766,775 +(1,766,775 +) +2,503,294 +Retained earnings +6,704 +(149,238 +) +149,238 +6,704 +Treasury shares +(3,008 +) +— +— +(3,008 +) +Total stockholders' equity +2,507,649 +1,617,537 +(1,617,537 +) +2,507,649 +Total Liabilities and Stockholders' Equity +$ +4,206,047 +$ +2,082,159 +$ +(1,867,816 +) +$ +4,420,390 +108 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Consolidating Statements of Operations +Year Ended December 31, 2018 +Parent +Guarantor +Eliminations +Consolidated +(in thousands) +Revenues +Crude oil, natural gas and NGLs sales +$ +1,050,696 +$ +339,265 +$ +— +$ +1,389,961 +Commodity price risk management gain, net +145,237 +— +— +145,237 +Other income +10,744 +2,717 +— +13,461 +Total revenues +1,206,677 +341,982 +— +1,548,659 +Costs, expenses and other +Lease operating expenses +92,228 +38,729 +— +130,957 +Production taxes +67,819 +22,538 +— +90,357 +Transportation, gathering and processing expenses +16,607 +20,796 +— +37,403 +Exploration, geologic and geophysical expense +1,234 +4,970 +— +6,204 +Impairment of properties and equipment +27 +458,370 +— +458,397 +General and administrative expense +152,798 +17,706 +— +170,504 +Depreciation, depletion and amortization +389,841 +169,952 +— +559,793 +Accretion of asset retirement obligations +4,617 +458 +— +5,075 +(Gain) loss on sale of properties and equipment +(4,387 +) +4,781 +— +394 +Other expenses +11,829 +— +— +11,829 +Total costs, expenses and other +732,613 +738,300 +— +1,470,913 +Income (loss) from operations +474,064 +(396,318 +) +— +77,746 +Interest expense +(73,251 +) +2,521 +— +(70,730 +) +Interest income +413 +— +— +413 +Income (loss) before income taxes +401,226 +(393,797 +) +— +7,429 +Income tax (expense) benefit +(98,611 +) +93,205 +— +(5,406 +) +Equity in loss of subsidiary +(300,592 +) +— +300,592 +— +Net income (loss) +$ +2,023 +$ +(300,592 +) +$ +300,592 +$ +2,023 +Net loss for the Guarantor for the year ended 2018 is primarily the result of impairment of certain unproved Delaware Basin leasehold positions. +109 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Consolidating Statements of Operations +Year Ended December 31, 2017 +Parent +Guarantor +Eliminations +Consolidated +(in thousands) +Revenues +Crude oil, natural gas and NGLs sales +$ +788,400 +$ +124,684 +$ +— +$ +913,084 +Commodity price risk management loss, net +(3,936 +) +— +— +(3,936 +) +Other income +11,901 +567 +— +12,468 +Total revenues +796,365 +125,251 +— +921,616 +Costs, expenses and other +Lease operating expenses +68,031 +21,610 +— +89,641 +Production taxes +53,236 +7,481 +— +60,717 +Transportation, gathering and processing expenses +23,301 +9,919 +— +33,220 +Exploration, geologic and geophysical expense +1,092 +46,242 +— +47,334 +Impairment of properties and equipment +4,951 +280,936 +— +285,887 +Impairment of goodwill +— +75,121 +— +75,121 +General and administrative expense +107,518 +12,852 +— +120,370 +Depreciation, depletion and amortization +403,984 +65,100 +— +469,084 +Accretion of asset retirement obligations +5,965 +341 +— +6,306 +Gain on sale of properties and equipment +(766 +) +— +— +(766 +) +Provision for uncollectible notes receivable +(40,203 +) +— +— +(40,203 +) +Other expenses +13,157 +— +— +13,157 +Total costs, expenses and other +640,266 +519,602 +— +1,159,868 +Income (loss) from operations +156,099 +(394,351 +) +— +(238,252 +) +Loss on extinguishment of debt +(24,747 +) +— +— +(24,747 +) +Interest expense +(79,919 +) +1,225 +— +(78,694 +) +Interest income +2,261 +— +— +2,261 +Income (loss) before income taxes +53,694 +(393,126 +) +— +(339,432 +) +Income tax (expense) benefit +(33,643 +) +245,571 +— +211,928 +Equity in loss of subsidiary +(147,555 +) +— +147,555 +— +Net loss +$ +(127,504 +) +$ +(147,555 +) +$ +147,555 +$ +(127,504 +) +Net loss for the Guarantor for the year ended 2017 is primarily the result of the exploratory dry hole expense, impairment of certain unproved Delaware Basin leasehold positions and the impairment of goodwill. +110 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Consolidating Statements of Operations +Year Ended December 31, 2016 +Parent +Guarantor +Eliminations +Consolidated +(in thousands) +Revenues +Crude oil, natural gas, and NGLs sales +$ +491,750 +$ +5,603 +$ +— +$ +497,353 +Commodity price risk management loss, net +(125,681 +) +— +— +(125,681 +) +Other income +11,241 +2 +— +11,243 +Total revenues +377,310 +5,605 +— +382,915 +Costs, expenses and other +Lease operating expenses +58,401 +1,549 +— +59,950 +Production taxes +31,132 +278 +— +31,410 +Transportation, gathering and processing expenses +18,263 +152 +— +18,415 +Exploration, geologic and geophysical expense +1,197 +3,472 +— +4,669 +Impairment of properties and equipment +9,973 +— +— +9,973 +General and administrative expense +112,166 +304 +— +112,470 +Depreciation, depletion and amortization +415,321 +1,553 +— +416,874 +Accretion of asset retirement obligations +7,070 +10 +— +7,080 +Gain on sale of properties and equipment +(43 +) +— +— +(43 +) +Provision for uncollectible notes receivable +44,038 +— +— +44,038 +Other expenses +10,193 +— +— +10,193 +Total costs, expenses and other +707,711 +7,318 +— +715,029 +Loss from operations +(330,401 +) +(1,713 +) +— +(332,114 +) +Interest expense +(62,002 +) +30 +— +(61,972 +) +Interest income +963 +— +— +963 +Loss before income taxes +(391,440 +) +(1,683 +) +— +(393,123 +) +Income tax benefit +147,195 +— +— +147,195 +Equity in loss of subsidiary +(1,683 +) +— +1,683 +— +Net loss +$ +(245,928 +) +$ +(1,683 +) +$ +1,683 +$ +(245,928 +) +111 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Consolidating Statements of Cash Flows +Year Ended December 31, 2018 +Parent +Guarantor +Eliminations +Consolidated +(in thousands) +Cash flows from operating activities +$ +625,206 +$ +264,096 +$ +— +$ +889,302 +Cash flows from investing activities: +Capital expenditures for development of crude oil and natural gas properties +(482,534 +) +(463,816 +) +— +(946,350 +) +Capital expenditures for other properties and equipment +(9,806 +) +(1,249 +) +— +(11,055 +) +Acquisition of crude oil and natural gas properties +(179,955 +) +(71 +) +— +(180,026 +) +Proceeds from sale of properties and equipment +1,929 +1,633 +— +3,562 +Proceeds from divestiture +44,693 +— +— +44,693 +Restricted cash +1,249 +— +— +1,249 +Intercompany transfers +(199,584 +) +— +199,584 +— +Net cash from investing activities +(824,008 +) +(463,503 +) +199,584 +(1,087,927 +) +Cash flows from financing activities: +Proceeds from revolving credit facility +1,072,500 +— +— +1,072,500 +Repayment of revolving credit facility +(1,040,000 +) +— +— +(1,040,000 +) +Payment of debt issuance costs +(7,704 +) +— +— +(7,704 +) +Purchase of treasury stock +(5,147 +) +— +— +(5,147 +) +Other +(1,373 +) +(177 +) +— +(1,550 +) +Intercompany transfers +— +199,584 +(199,584 +) +— +Net cash from financing activities +18,276 +199,407 +(199,584 +) +18,099 +Net change in cash and cash equivalents +(180,526 +) +— +— +(180,526 +) +Cash and cash equivalents, beginning of period +189,925 +— +— +189,925 +Cash and cash equivalents, end of period +$ +9,399 +$ +— +$ +— +$ +9,399 +112 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Consolidating Statements of Cash Flows +Year Ended December 31, 2017 +Parent +Guarantor +Eliminations +Consolidated +(in thousands) +Cash flows from operating activities +$ +546,954 +$ +50,859 +$ +— +$ +597,813 +Cash flows from investing activities: +Capital expenditures for development of crude oil and natural gas properties +(439,897 +) +(297,311 +) +— +(737,208 +) +Capital expenditures for other properties and equipment +(3,539 +) +(1,555 +) +— +(5,094 +) +Acquisition of crude oil and natural gas properties +(21,000 +) +5,372 +— +(15,628 +) +Proceeds from sale of properties and equipment +10,084 +(93 +) +— +9,991 +Sale of promissory note +40,203 +— +— +40,203 +Restricted cash +(9,250 +) +— +— +(9,250 +) +Sales of short-term investments +49,890 +— +— +49,890 +Purchases of short-term investments +(49,890 +) +— +— +(49,890 +) +Intercompany transfers +(239,191 +) +— +239,191 +— +Net cash from investing activities +(662,590 +) +(293,587 +) +239,191 +(716,986 +) +Cash flows from financing activities: +Proceeds from issuance of senior notes +592,366 +— +— +592,366 +Redemption of senior notes +(519,375 +) +— +— +(519,375 +) +Payment of debt issuance costs +(50 +) +— +— +(50 +) +Purchase of treasury stock +(6,672 +) +— +— +(6,672 +) +Other +(1,195 +) +(76 +) +— +(1,271 +) +Intercompany transfers +— +239,191 +(239,191 +) +— +Net cash from financing activities +65,074 +239,115 +(239,191 +) +64,998 +Net change in cash and cash equivalents +(50,562 +) +(3,613 +) +— +(54,175 +) +Cash and cash equivalents, beginning of period +240,487 +3,613 +— +244,100 +Cash and cash equivalents, end of period +$ +189,925 +$ +— +$ +— +$ +189,925 +113 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Condensed Consolidating Statements of Cash Flows +Year Ended December 31, 2016 +Parent +Guarantor +Eliminations +Consolidated +(in thousands) +Cash flows from operating activities +$ +492,893 +$ +(6,630 +) +$ +— +$ +486,263 +Cash flows from investing activities: +Capital expenditures for development of crude oil and natural gas properties +(436,361 +) +(523 +) +— +(436,884 +) +Capital expenditures for other properties and equipment +(2,282 +) +(1,182 +) +— +(3,464 +) +Acquisition of crude oil and natural gas properties +(1,076,256 +) +2,533 +— +(1,073,723 +) +Proceeds from sale of properties and equipment +4,945 +— +— +4,945 +Intercompany transfers +(9,415 +) +— +9,415 +— +Net cash from investing activities +(1,519,369 +) +828 +9,415 +(1,509,126 +) +Cash flows from financing activities: +Proceeds from revolving credit facility +85,000 +— +— +85,000 +Repayment of revolving credit facility +(122,000 +) +— +— +(122,000 +) +Proceeds from issuance of equity, net of issuance costs +855,074 +— +— +855,074 +Proceeds from issuance of senior notes +392,172 +— +— +392,172 +Proceeds from issuance of convertible senior notes +193,935 +— +— +193,935 +Redemption of convertible notes +(115,000 +) +— +— +(115,000 +) +Payment of debt issuance costs +(15,556 +) +— +— +(15,556 +) +Purchase of treasury shares +(6,935 +) +— +— +(6,935 +) +Other +(577 +) +— +— +(577 +) +Intercompany transfers +— +9,415 +(9,415 +) +— +Net cash from financing activities +1,266,113 +9,415 +(9,415 +) +1,266,113 +Net change in cash and cash equivalents +239,637 +3,613 +— +243,250 +Cash and cash equivalents, beginning of period +850 +— +— +850 +Cash and cash equivalents, end of period +$ +240,487 +$ +3,613 +$ +— +$ +244,100 +The condensed consolidating financial statements for the year ended December 31, 2016 represent one month of activity for the Guarantor as the Delaware Basin acquisition closed in December 2016. +114 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +SUPPLEMENTAL INFORMATION - UNAUDITED +CRUDE OIL AND NATURAL GAS INFORMATION - UNAUDITED +Net Proved Reserves +All of our crude oil, natural gas and NGLs reserves are located in the U.S. We utilize the services of independent petroleum engineers to estimate our crude oil, natural gas and NGLs reserves. As of December 31, 2018 , 2017 and 2016 (as applicable), all of our estimates of proved reserves for the Wattenberg Field and the Utica Shale were based on reserve reports prepared by Ryder Scott Company, L.P., and beginning in 2016 Netherland, Sewell & Associates, Inc. prepared the reserve reports for the Delaware Basin. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC. +Proved reserves are those quantities of crude oil, natural gas and NGLs which can be estimated with reasonable certainty to be economically producible under existing economic conditions and operating methods. Proved developed reserves are the proved reserves that can be produced through existing wells with existing equipment and infrastructure and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for development. All of our proved undeveloped reserves conform to the SEC five-year rule requirement that they be scheduled to be drilled within five years of each location’s initial booking date. +The indicated index prices for our reserves, by commodity, are presented below. +Average Benchmark Prices (1) +As of December 31, +Crude Oil +(per Bbl) (2) +Natural Gas +(per Mcf) (2) +NGLs +(per Bbl) (3) +2018 +$ +65.56 +$ +3.10 +$ +65.56 +2017 +51.34 +2.98 +51.34 +2016 +42.75 +2.48 +42.75 +The netted back price used to estimate our reserves, by commodity, are presented below. +Price Used to Estimate Reserves (4) +As of December 31, +Crude Oil +(per Bbl) +Natural Gas +(per Mcf) +NGLs +(per Bbl) +2018 +$ +61.14 +$ +2.15 +$ +23.04 +2017 +48.68 +2.31 +20.21 +2016 +38.67 +1.85 +11.97 +___________ +(1) +Per SEC rules, the pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of the month prices for the preceding 12 months. +(2) Our benchmark prices for crude oil and natural gas are WTI and Henry Hub, respectively. +(3) +For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. +(4) +These prices are based on the index prices and are net of basin differentials, transportation fees, contractual adjustments and Btu adjustments we experienced for the respective commodity. +115 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +The following tables present the changes in our estimated quantities of proved reserves: +Crude Oil, Condensate (MBbls) +Natural Gas +(MMcf) +NGLs +(MBbls) +Total +(MBoe) +Proved Reserves: +Proved reserves, January 1, 2016 +98,975 +660,737 +63,727 +272,825 +Revisions of previous estimates +(22,097 +) +(80,426 +) +(7,130 +) +(42,631 +) +Extensions, discoveries and other additions +494 +4,094 +355 +1,531 +Acquisition of reserves +50,126 +305,224 +32,586 +133,583 +Dispositions +(601 +) +(4,202 +) +(424 +) +(1,725 +) +Production +(8,728 +) +(51,730 +) +(4,826 +) +(22,176 +) +Proved reserves, December 31, 2016 +118,169 +833,697 +84,288 +341,407 +Revisions of previous estimates +28,334 +96,119 +8,104 +52,457 +Extensions, discoveries and other additions +2,923 +11,541 +1,158 +6,005 +Acquisition of reserves +18,971 +289,223 +19,604 +86,778 +Dispositions +(653 +) +(4,597 +) +(481 +) +(1,900 +) +Production +(12,902 +) +(71,689 +) +(6,981 +) +(31,830 +) +Proved reserves, December 31, 2017 +154,842 +1,154,294 +105,692 +452,917 +Revisions of previous estimates +26,548 +94,738 +12,674 +55,011 +Extensions, discoveries and other additions +8,786 +61,750 +8,868 +27,946 +Acquisition of reserves +19,644 +148,674 +15,936 +60,360 +Dispositions +(2,507 +) +(35,750 +) +(2,656 +) +(11,121 +) +Production +(16,964 +) +(88,017 +) +(8,527 +) +(40,160 +) +Proved reserves, December 31, 2018 +190,349 +1,335,689 +131,987 +544,953 +Proved Developed Reserves, as of: +December 31, 2016 +30,013 +264,452 +24,196 +98,284 +December 31, 2017 +46,862 +365,332 +35,220 +142,971 +December 31, 2018 +61,821 +443,151 +43,856 +179,535 +Proved Undeveloped Reserves, as of: +December 31, 2016 +88,156 +569,245 +60,092 +243,122 +December 31, 2017 +107,980 +788,962 +70,472 +309,946 +December 31, 2018 +128,528 +892,538 +88,131 +365,418 +116 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Developed +Undeveloped +Total +(MBoe) +Proved reserves, January 1, 2016 +70,496 +202,329 +272,825 +Revisions of previous estimates +6,112 +(48,743 +) +(42,631 +) +Extensions, discoveries and other additions +1,531 +— +1,531 +Acquisition of reserves +10,229 +123,354 +133,583 +Dispositions +(99 +) +(1,626 +) +(1,725 +) +Production +(22,176 +) +— +(22,176 +) +Undeveloped reserves converted to developed +32,192 +(32,192 +) +— +Proved reserves, December 31, 2016 +98,285 +243,122 +341,407 +Revisions of previous estimates +18,291 +34,166 +52,457 +Extensions, discoveries and other additions +2,292 +3,713 +6,005 +Acquisition of reserves +1,305 +85,473 +86,778 +Dispositions +(20 +) +(1,880 +) +(1,900 +) +Production +(31,830 +) +— +(31,830 +) +Undeveloped reserves converted to developed +54,648 +(54,648 +) +— +Proved reserves, December 31, 2017 +142,971 +309,946 +452,917 +Revisions of previous estimates +6,284 +48,727 +55,011 +Extensions, discoveries and other additions +7,874 +20,072 +27,946 +Acquisition of reserves +8,758 +51,602 +60,360 +Dispositions +(4,486 +) +(6,635 +) +(11,121 +) +Production +(40,160 +) +— +(40,160 +) +Undeveloped reserves converted to developed +58,294 +(58,294 +) +— +Proved reserves, December 31, 2018 +179,535 +365,418 +544,953 +2018 Activity. During 2018, we increased proved reserves by 92.0 MMBoe, or 20 percent , relative to December 31, 2017. The increase in proved reserves was primarily a result of acreage exchange transactions and acquisitions in the Wattenberg Field and reserve additions on proved acreage resulting from our 2018 development activities. In 2018, we produced 40.2 MMboe. +Revisions of Previous Estimates-Proved Developed Reserves. Proved developed reserves experienced a net positive revision of 11.4 MMBoe due to an increase in prices for crude oil, natural gas and NGLs, offset by net negative revisions of 5.1 MMBoe for an increase in operating costs, performance revisions and other items. +Revisions of Previous Estimates-PUDs. Upward revisions to our PUD reserves were related to an increase of 71.7 MMBoe reflecting newly-booked locations on proven acreage resulting from our drilling activities. Partially offsetting this increase was a negative revision of 26.8 MMBoe in the Wattenberg Field due to drilling schedule changes and updated timing for development of certain locations exceeding the five-year rule. Drilling schedule changes, primarily related to 2018 acreage exchanges, resulted in these locations being reclassified from proved to unproved status. All other changes were due to commodity pricing, lease operating expenses and type curve revisions, which resulted in further upward revisions of 3.8 MMBoe of PUD reserves. +Extensions, Discoveries and Other Additions-Proved Developed Reserves. Developed activity for 2018 included the addition 7.9 MMBoe of developed reserves related to 17 gross ( 9.2 net) newly-drilled wells. +Extensions, Discoveries and Other Additions-PUDs. PUD activity was comprised primarily of 20.1 MMBoe of PUD reserves related to 16 gross ( 15.0 net) PUD locations in the Delaware Basin. +Acquisitions of Reserves-Proved Developed Reserves. Proved developed reserves acquired in various acreage swaps and an acquisition were 8.8 MMBoe during 2018. +Acquisitions of Reserves-PUDs. We acquired 47.6 MMBoe and 4.0 MMBoe of PUD reserves in 2018 in acreage swaps and an acquisition, respectively. +Dispositions-Proved Developed Reserves . Dispositions of 4.5 MMBoe were related to a divestiture and acreage surrendered in various acreage swaps. +117 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Dispositions-PUDs. Dispositions of 6.6 MMBoe reflect that we primarily divested proved acreage with future locations that were not in our five-year drilling plan as of December 31, 2017 in the acreage swap transactions. +At December 31, 2017, we projected a PUD reserve conversion rate of 16 percent for 2018. During 2018, a larger number of wells were turned-in-line than we anticipated, resulting in an actual conversion rate of 19 percent . We converted 58.3 MMBoe of PUD reserves at December 31, 2017 to proved developed reserves as of December 31, 2018. +Based on economic conditions on December 31, 2018, our approved development plan provides for the development of our remaining PUD locations within five years of the date such reserves were initially recorded. As of December 31, 2018, our 2019 PUD reserve conversion rate is expected to be approximately 16 percent . The balance of the PUD reserves are scheduled to be developed over the remaining four years in accordance with our current development plan. The level of capital spending necessary to achieve this drilling schedule is consistent with our recent performance and our outlook for future development activities. +2017 Activity. During 2017, we increased proved reserves by 111.5 MMBoe, or 33 percent , relative to December 31, 2016. The increase in proved reserves was primarily a result of an increase in acquisitions and reserve additions on proved acreage in the Delaware Basin from our 2017 development plan. In 2017, we produced 31.8 MMboe. +Revisions of Previous Estimates-Proved Developed Reserves. Proved developed reserves experienced a net positive revision of 17.7 MMBoe due to an increase in prices for crude oil, natural gas and NGLs and net positive revisions of 0.6 MMBoe reflecting changes in operating costs, performance revisions and other items. +Revisions of Previous Estimates-PUDs. Upward revisions to our PUD reserves were related to an increase of 89.8 MMBoe reflecting newly-booked locations on proven acreage resulting from our drilling activities. Partially offsetting this increase was a negative revision of 58.5 MMBoe in the Wattenberg Field due to drilling schedule changes and updated timing for development of certain locations exceeding the five-year rule. Drilling schedule changes, primarily related to 2017 acreage swaps, resulted in these locations being reclassified from proved to unproved status. All other changes were due to commodity pricing, lease operating expenses and other, which resulted in further upward revisions of 2.9 MMBoe of PUD reserves. +Extensions, Discoveries and Other Additions-Proved Developed Reserves. Developed additions for 2017 included the addition of 2.3 MMBoe of developed reserves related to newly-drilled wells. +Extensions, Discoveries and Other Additions-PUDs. PUD activity was comprised primarily of 3.7 MMBoe of PUD reserves related to PUD locations in the Delaware Basin. +Acquisitions of Reserves-Proved Developed Reserves. Proved developed reserves acquired in various acreage swaps were 1.3 MMBoe during 2017. +Acquisitions of Reserves-PUDs. We acquired 85.5 MMBoe of PUD reserves in 2017 in acreage swaps. +Dispositions-Proved Developed Reserves . Dispositions were related to acreage surrendered in various acreage swaps. +Dispositions-PUDs. Dispositions of PUDs were 1.9 MMBoe, reflecting the fact that we primarily divested proved acreage with future locations that were not in our five-year drilling plan as of December 31, 2016 in the acreage swap transactions. +2016 Activity. During 2016, we increased proved reserves by 68.6 MMBoe, or 25 percent , relative to December 31, 2015. This proved reserve increase was primarily a result of the development of longer lateral length well bores in the Wattenberg Field, which was driven by technology advancements, together with the ability to consolidate our leasehold position to drill longer length laterals with increased working interests. We also acquired proved developed reserves and undeveloped reserves in the Delaware Basin. +Revisions of Previous Estimates-Proved Developed Reserves. Proved developed reserves experienced a net positive revision of 2.6 MMBoe due to a decrease in operating costs and a net positive revision of 3.5 MMBoe for performance revisions and other items. These net positive revisions were partially offset by a decrease in prices for crude oil, natural gas and NGLs. +Revisions of Previous Estimates-PUDs. Downward revisions to our PUD reserves were related to a decrease of 61.0 MMBoe in the Wattenberg Field due to drilling schedule changes and updated timing for development of certain locations +118 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +exceeding the five-year rule. Drilling schedule changes, primarily related to 2016 acreage swaps, resulted in these locations being reclassified from proved to unproved status. Partially offsetting this decrease was a positive revision of 10.8 MMBoe reflecting newly-booked locations on proven acreage resulting from our drilling activities. All other changes were due to commodity pricing, lease operating expenses and other, which resulted in further downward revisions of 1.5 MMBoe of PUD reserves. +Extensions, Discoveries and Other Additions-Proved Developed Reserves. Developed additions for 2016 included the addition 1.5 MMBoe of developed reserves related to newly-drilled wells. +Acquisitions of Reserves-Proved Developed Reserves. Proved developed reserves acquired in various acreage swaps and an acquisition were 10.2 MMBoe during 2016. +Acquisitions of Reserves-PUDs. We acquired 98.1 MMBoe and 25.3 MMBoe of PUD reserves in 2016 in acreage swaps and an acquisition, respectively. +Dispositions-Proved Developed Reserves . Dispositions of 0.1 MMBoe were related to acreage surrendered in various acreage swaps. +Dispositions-PUDs. Dispositions of PUDs were 1.6 MMBoe, reflecting the fact that we primarily divested proved acreage with future locations that were not in our five-year drilling plan as of December 31, 2015 in the acreage swap transactions. +119 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Results of Operations for Crude Oil and Natural Gas Producing Activities +The results of operations for crude oil and natural gas producing activities are presented below. +Year Ended December 31, +2018 +2017 +2016 +(in thousands) +Revenue: +Crude oil, natural gas and NGLs sales +$ +1,389,961 +$ +913,084 +$ +497,353 +Commodity price risk management gain (loss), net +145,237 +(3,936 +) +(125,681 +) +1,535,198 +909,148 +371,672 +Expenses: +Lease operating expenses +130,957 +89,641 +59,950 +Production taxes +90,357 +60,717 +31,410 +Transportation, gathering and processing expenses +37,403 +33,220 +18,415 +Exploration expense +6,204 +47,334 +4,669 +Impairment of properties and equipment +458,397 +285,887 +9,973 +Depreciation, depletion and amortization +551,265 +462,482 +413,105 +Accretion of asset retirement obligations +5,075 +6,306 +7,080 +(Gain) loss on sale of properties and equipment +394 +(766 +) +(43 +) +1,280,052 +984,821 +544,559 +Results of operations for crude oil and natural gas producing +activities before provision for income taxes +255,146 +(75,673 +) +(172,887 +) +Income tax (expense) benefit +(185,667 +) +47,247 +64,733 +Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs +$ +69,479 +$ +(28,426 +) +$ +(108,154 +) +Production costs include those costs incurred to operate and maintain productive wells and related equipment, including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, production and severance taxes and associated administrative expenses. DD&A expense includes those costs associated with capitalized acquisition, exploration and development costs, but does not include the depreciation applicable to support equipment. The provision for income taxes is computed using effective tax rates. +120 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Costs Incurred in Crude Oil and Natural Gas Property Acquisition, Exploration and Development Activities +Costs incurred in crude oil and natural gas property acquisition, exploration and development are presented below. +Year Ended December 31, +2018 +2017 +2016 +(in thousands) +Acquisition of properties: (1) +Proved properties +$ +205,253 +$ +172 +$ +268,567 +Unproved properties +5,477 +18,914 +1,843,985 +Development costs (2) +970,970 +688,165 +383,336 +Exploration costs: (3) +Exploratory drilling +36,704 +80,103 +— +Geological and geophysical +3,401 +3,881 +4,669 +Total costs incurred (4) +$ +1,221,805 +$ +791,235 +$ +2,500,557 +__________ +(1) +Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property. Proved properties +include approximately $40.9 million of infrastructure and pipeline costs in 2016. +(2) +Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells and provide facilities to extract, treat, gather and store crude oil, natural gas and NGLs. Of these costs incurred for the years ended December 31, 2018 , 2017 and 2016 , $438.4 million , $463.4 million and $204.6 million , respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. These costs also include approximately $74.6 million and $32.8 million of infrastructure and pipeline costs in 2018 +and 2017 , respectively. +(3) +Exploration costs represent costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas and NGLs. These costs include, but are not limited to, dry hole contributions and costs of drilling and equipping exploratory wells. +(4) +During 2017, we finalized our purchase price allocation for the 2016 Delaware Basin acquisition within the one year measurement period. The finalization included a reduction to our proved undeveloped and development costs of $24.6 million . We excluded this reduction from our 2017 costs incurred as it did not relate to any cash acquisitions in 2017. +Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities +Aggregate capitalized costs related to crude oil and natural gas exploration and production activities with applicable accumulated DD&A are presented below: +As of December 31, +2018 +2017 +(in thousands) +Proved crude oil and natural gas properties +$ +5,452,613 +$ +4,356,922 +Unproved crude oil and natural gas properties +492,594 +1,097,317 +Uncompleted wells, equipment and facilities +332,264 +265,526 +Capitalized costs +6,277,471 +5,719,765 +Less accumulated DD&A +(2,341,897 +) +(1,803,847 +) +Capitalized costs, net +$ +3,935,574 +$ +3,915,918 +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves +The standardized measure below has been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to our year-end estimated proved reserves. Prices for each of the three years were adjusted by field for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of our commodity derivatives. Production and development costs were based on prices as of December 31 for each of the respective years presented. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service or to depreciation, depletion and amortization expense. Production and development costs include those cash flows associated with the expected ultimate settlement of our asset retirement obligations. Future +121 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +estimated income tax expense is computed by applying the statutory rate in effect at the end of each year to the projected future pre-tax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits and allowances related to the properties. +The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for crude oil, natural gas and NGLs, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves. +As of December 31, +2018 +2017 +2016 +(in thousands) +Future estimated cash flows +$ +17,554,880 +$ +12,340,407 +$ +7,122,525 +Future estimated production costs* +(4,782,948 +) +(3,245,627 +) +(1,624,167 +) +Future estimated development costs +(3,632,822 +) +(2,893,335 +) +(2,219,914 +) +Future estimated income tax expense +(1,404,121 +) +(748,494 +) +(597,476 +) +Future net cash flows +7,734,989 +5,452,951 +2,680,968 +10% annual discount for estimated timing of cash flows +(3,287,273 +) +(2,572,846 +) +(1,260,339 +) +Standardized measure of discounted future estimated net cash flows +$ +4,447,716 +$ +2,880,105 +$ +1,420,629 +___________ +* +Represents future estimated lease operating expenses, production taxes and transportation, gathering and processing expenses. +The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows: +Year Ended December 31, +2018 +2017 +2016 +(in thousands) +Beginning of period +$ +2,880,105 +$ +1,420,629 +$ +1,096,864 +Sales of crude oil, natural gas and NGLs production, net of production costs +(1,131,244 +) +(729,506 +) +(387,576 +) +Net changes in prices and production costs (1) +936,077 +841,713 +(205,760 +) +Extensions, discoveries and improved recovery, less related costs +190,084 +47,240 +15,128 +Sales of reserves +(42,362 +) +(2,613 +) +(3,745 +) +Purchases of reserves +467,807 +224,483 +487,636 +Development costs incurred during the period +462,088 +419,047 +268,672 +Revisions of previous quantity estimates +631,198 +484,431 +(320,286 +) +Changes in estimated income taxes +(232,002 +) +(138,560 +) +(13,630 +) +Net changes in future development costs +(123,663 +) +25,183 +391,145 +Accretion of discount +583,744 +167,487 +133,747 +Timing and other +(174,116 +) +120,571 +(41,566 +) +End of period +$ +4,447,716 +$ +2,880,105 +$ +1,420,629 +__________ +(1) +Our weighted-average price, net of production costs per Boe, in our 2018 reserve report increased to $23.44 as compared to $20.08 for 2017 and $15.73 for 2016 . +The data presented should not be viewed as representing the expected cash flows from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the recent average prices and current costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein. +122 +PDC ENERGY, INC. +QUARTERLY FINANCIAL INFORMATION - UNAUDITED +Quarterly financial data for the years ended December 31, 2018 and 2017 is presented below. The quarterly consolidated statements of operations below reflect our revised presentation. The sum of the quarters may not equal the total of the year's net income or loss per share due to changes in the weighted-average shares outstanding throughout the year. +2018 +Quarter Ended +March 31 (1) +June 30 +September 30 (1) +December 31 (1) +(in thousands, except per share data) +Total revenues +$ +260,600 +$ +212,531 +$ +280,717 +$ +794,811 +Total costs, expenses and other +260,924 +400,770 +270,593 +538,626 +Income (loss) from operations +(324 +) +(188,239 +) +10,124 +256,185 +Income (loss) before income taxes +(17,705 +) +(205,580 +) +(7,310 +) +238,024 +Net income (loss) +$ +(13,139 +) +$ +(160,257 +) +$ +(3,434 +) +$ +178,853 +Earnings per share: +Basic +$ +(0.20 +) +$ +(2.43 +) +$ +(0.05 +) +$ +2.71 +Diluted +(0.20 +) +(2.43 +) +(0.05 +) +2.71 +2017 +Quarter Ended +March 31 +June 30 +September 30 (1) +December 31 (2) +(in thousands, except per share data) +Total revenues +$ +273,707 +$ +275,158 +$ +183,235 +$ +189,516 +Total costs, expenses and other +182,004 +190,522 +579,326 +208,016 +Income (loss) from operations +91,703 +84,636 +(396,091 +) +(18,500 +) +Income (loss) before income taxes +72,476 +65,787 +(414,887 +) +62,808 +Net income (loss) +$ +46,146 +$ +41,250 +$ +(292,537 +) +$ +77,637 +Earnings per share: +Basic +$ +0.70 +$ +0.63 +$ +(4.44 +) +$ +1.18 +Diluted +0.70 +0.62 +(4.44 +) +1.17 +(1) Impairment charges, which are included in total costs, expenses and other above, reflect the correction of two errors in the timing of the +reporting of certain impairments. In 2018, we corrected an error in our calculation of unproved properties and goodwill originally +recorded in 2017, resulting in an additional impairment charge of $6.3 million being recorded during the three months ended March 31, +2018. Further, during the fourth quarter of 2018, we corrected for an additional $8.4 million impairment of unproved properties relating +to the three months ended September 30, 2018. See the footnote titled Properties and Equipment to our consolidated financial statements +included elsewhere in this report. +(2) Net income of $77.6 million for the quarter ended December 31, 2017 is primarily due to an income tax benefit of $114.4 million resulting +from a decrease in deferred tax assets and liabilities related to the 2017 Tax Act. +123 +PDC ENERGY, INC. +FINANCIAL STATEMENT SCHEDULE +Schedule II -VALUATION AND QUALIFYING ACCOUNTS +Description +Beginning +Balance +January 1, +Charged to +Costs and +Expenses +Deductions (1) +Ending +Balance +December 31, +(in thousands) +2018: +Allowance for doubtful accounts +$ +3,128 +$ +1,276 +$ +23 +$ +4,381 +Allowance for expirations of unproved crude oil and natural gas properties +251,159 +388,068 +96,518 +542,709 +2017: +Allowance for uncollectible notes +$ +44,038 +$ +— +$ +44,038 +$ +— +Allowance for doubtful accounts +2,190 +1,108 +170 +3,128 +Allowance for expirations of unproved crude oil and natural gas properties +359 +263,817 +13,017 +251,159 +2016: +Allowance for uncollectible notes +$ +— +$ +44,038 +$ +— +$ +44,038 +Allowance for doubtful accounts +2,009 +1,309 +1,128 +2,190 +Allowance for expirations of unproved crude oil and natural gas properties +144 +215 +— +359 +____________ +(1) +For allowance for uncollectible notes, deductions represent reversals of allowances due to the collection of amounts owed. For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For allowance for expirations of unproved crude oil and natural gas properties, deductions represent actual expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset. +124 +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +As of December 31, 2018 , we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Based on the results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were not effective as of December 31, 2018 because of the material weaknesses in our internal control over financial reporting described below. +Management's Report on Internal Control over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Internal control over financial reporting is a process designed by, or under the supervision of, our CEO and CFO, or persons performing similar functions, and effected by our board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate. +Management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2018 , based upon the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). +A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. +We did not maintain a sufficient complement of personnel within the Land Department as a result of increased volume of leases, which contributed to the ineffective design and maintenance of controls to verify the completeness and accuracy of land administrative records associated with unproved leases, which are used in verifying the completeness, accuracy, valuation, rights and obligations over the accounting of properties and equipment, sales and accounts receivable and costs and expenses. These control deficiencies resulted in immaterial adjustments to our unproved properties, impairment of unproved properties, sales, accounts receivable and depletion expense accounts and related disclosures in our consolidated financial statements for the years ended December 31, 2018 and 2017 . Additionally, these control deficiencies could result in misstatements of substantially all accounts and disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. Accordingly, our management has determined that these control deficiencies constitute material weaknesses. +Because of these material weaknesses, management concluded that we did not maintain effective internal control over financial reporting as of December 31, 2018 . +The effectiveness of our internal control over financial reporting as of December 31, 2018 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears under Item 8. +Remediation Plan for Material Weaknesses +We are committed to continuing to review, optimize and enhance our internal control over financial reporting. In response to the identified material weaknesses, our management, with the oversight of the Audit Committee of our Board of +125 +Directors, has assessed a number of different remediation initiatives to improve our internal control over financial reporting. Building on our efforts during 2017 , we continued throughout 2018 to dedicate significant resources and efforts to improve our internal control over financial reporting and to take steps to remediate the material weaknesses identified above. While certain remediation plans have been implemented, we continue to actively plan for and implement additional remediation measures. +During 2018 , we have taken steps to strengthen the control activities within the Land Department, which include the combination of hiring of additional personnel with relevant experience, increased layers of supervision, and division of responsibilities within the Land Department. We have also designed and implemented control activities to verify the completeness and accuracy of land administrative records associated with unproved leases, including the verification of the reliability of underlying data used in the execution of the control activities. As we continue to evaluate and work to improve our internal control over financial reporting, we may take additional measures to address these control deficiencies, or we may modify certain of the remediation measures described above to improve the operating effectiveness of those measures. These material weaknesses will not be considered remediated until the applicable remediated controls operate for a sufficient period of time and management has concluded, through testing, that these controls are operating effectively. +Changes in Internal Control over Financial Reporting +There were no changes in our internal control over financial reporting during the quarter ended December 31, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. +ITEM 9B. OTHER INFORMATION +None. +126 +PART III +ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2019 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 11. EXECUTIVE COMPENSATION +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2019 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2019 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2019 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2019 Annual Stockholders' meeting and is incorporated by reference in this report. +PART IV +ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES +(a) +(1) +Exhibits: +See Exhibits Index on the following page. +127 +ITEM 16. FORM 10-K SUMMARY +None. +Exhibits Index +Incorporated by Reference +Exhibit Number +Exhibit Description +Form +SEC File Number +Exhibit +Filing Date +Filed Herewith +2.1 +Plan of Conversion, dated June 5, 2015, by PDC Energy, Inc. (the "Company"). +8-K12B +001-37419 +2.1 +6/8/2015 +2.2 +Stock Purchase and Sale Agreement, dated August 23, 2016, by and among the seller parties thereto, Kimmeridge Energy Management Company GP, LLC, Arris Petroleum Corporation and PDC Energy, Inc. +8-K +001-37419 +2.1 +8/24/2016 +2.3 +Asset Purchase and Sale Agreement, dated August 23, 2016, by and among 299 Resources, LLC, 299 Production, LLC, 299 Pipeline, LLC, Kimmeridge Energy Management Company GP, LLC and PDC Energy, Inc. +8-K +001-37419 +2.2 +8/24/2016 +3.1 +Certificate of Incorporation of the Company. +8-K12B +001-37419 +3.1 +6/8/2015 +3.2 +By-laws of the Company. +8-K12B +001-37419 +3.2 +6/8/2015 +4.1 +Form of Common Stock Certificate of the Company. +10-K +001-37419 +4.1 +2/28/2017 +4.2 +Indenture, dated as of November 29, 2017, by and between PDC Energy, Inc., PDC Permian, Inc., a subsidiary guarantor of the Company, and U.S. Bank Trust National Association, as Trustee, relating to the 5.750% Senior Notes due 2026. +8-K +001-37419 +4.1 +11/29/2017 +4.3 +Base Indenture, dated as of September 14, 2016, by and between the Company and U.S. Bank Trust National Association, as Trustee. +8-K +001-37419 +4.1 +9/14/2016 +4.4 +First Supplemental Indenture, dated as of September 14, 2016, by and between the Company and U.S. Bank Trust National Association, as Trustee, relating to the 1.125% Convertible Senior Notes due 2021. +8-K +001-37419 +4.2 +9/14/2016 +4.5 +Indenture, dated as of September 15, 2016, by and between PDC Energy, Inc. and U.S. Bank Trust National Association, as Trustee, relating to the 6.125% Senior Notes due 2024. +8-K +001-37419 +4.1 +9/15/2016 +10.1 +Form of Indemnification Agreement. +8-K +000-07246 +10.1 +6/8/2015 +10.2 +401(k) and Profit Sharing Plan, as amended on January 4, 2016. +10-K +001-37419 +10.2 +2/28/2017 +10.3 +Amended and Restated Non-Employee Director Deferred Compensation Plan. +10-K +001-37419 +10.3 +2/27/2018 +10.4 +2004 Long-Term Equity Compensation Plan amended and restated as of March 8, 2008 ("2004 Plan"). +10-K +000-07246 +10.26 +2/27/2009 +10.4.1 +Summary of 2010 Stock Appreciation Rights and Restricted Stock Awards under the 2004 Plan. +8-K +000-07246 +4/23/2010 +10.5 +Amended and Restated 2010 Long-Term Equity Compensation Plan, as amended. +10-K +001-37419 +10.5 +2/22/2016 +10.6 +Executive Severance Compensation Plan, as amended. +10-K +001-37419 +10.6 +2/22/2016 +10.7 +Form of 2011 Restricted Stock/Stock Appreciation Rights Agreement. +10-K +000-07246 +10.5.2 +2/21/2014 +10.7.1 +Form of 2013 Performance Share Agreement. +10-K +000-07246 +10.9 +2/27/2013 +10.7.2 +Form of 2013 Restricted Stock/Stock Appreciation Rights Agreement. +10-K +000-07246 +10.10 +2/27/2013 +10.7.3 +Form of 2014 Performance Share Agreement. +10-K +000-07246 +10.5.4 +2/19/2015 +10.7.4 +Form of 2014 Restricted Stock/Stock Appreciation Rights Agreement. +10-K +000-07246 +10.5.5 +2/19/2015 +128 +Incorporated by Reference +Exhibit Number +Exhibit Description +Form +SEC File Number +Exhibit +Filing Date +Filed Herewith +10.7.5 +Form of 2015 Performance Share Agreement. +10-K +000-07246 +10.5.6 +2/19/2015 +10.7.6 +Form of 2015 Restricted Stock Unit Agreement. +10-K +000-07246 +10.5.7 +2/19/2015 +10.7.7 +Form of 2015 Stock Appreciation Rights Agreement. +10-K +000-07246 +10.5.8 +2/19/2015 +10.7.8 +Form of 2016 Performance Share Agreement. +10-K +001-37419 +10.7.8 +2/22/2016 +10.7.9 +Form of 2018 Performance Share Agreement. +10-Q +001-37419 +99.1 +5/3/2018 +10.7.10 +Form of 2018 Restricted Stock Unit Agreement (Executives). +10-Q +001-37419 +99.2 +5/3/2018 +10.7.11 +Form of 2018 Restricted Stock Unit Agreement (Directors). +10-Q +001-37419 +99.3 +5/3/2018 +10.9 +Employment Agreement with Daniel W. Amidon, General Counsel and Corporate Secretary, dated as of April 19, 2010. +8-K +000-07246 +10.3 +4/23/2010 +10.9.1 +General Release of Claims, dated as of January 7, 2019 by and between PDC Energy, Inc. and Daniel W. Amidon. +X +10.10 +Employment Agreement with Lance A. Lauck, Senior Vice President of Business Development, dated as of April 19, 2010. +8-K +000-07246 +10.4 +4/23/2010 +10.11 +Fourth Amended and Restated Credit Agreement, dated as of May 23, 2018, among PDC Energy, Inc. as Borrower, each of the Lenders party thereto, and JPMorgan Chase Bank, N.A. as Administrative Agent for the Lenders. +8-K +001-37419 +10.1 +5/25/2018 +10.12 +Change of Control and Severance Plan. +10-K +001-37419 +10.14 +2/28/2017 +10.12.1 +Amendment to the PDC Energy Change of Control and Severance Plan. +10-K +001-37419 +10.14.1 +2/28/2017 +10.13 +2018 Equity Incentive Plan. +8-K +001-37419 +10.1 +5/31/2018 +10.14 +General Release of Claims dated as of February 5, 2018, by and between PDC Energy, Inc. and David W. Honeyfield. +8-K +001-37419 +10.1 +2/9/2018 +10.15 +Investment Agreement, dated December 6, 2016, by and among the Investor parties identified therein and PDC Energy, Inc. (relating to the Stock Purchase and Sale Agreement). +8-K +001-37419 +10.1 +12/7/2016 +10.16 +Investment Agreement, dated December 6, 2016, by and among the Investor parties identified therein and PDC Energy, Inc. (relating to the Asset Purchase and Sale Agreement). +8-K +001-37419 +10.2 +12/7/2016 +21.1 +Subsidiaries. +X +23.1 +Consent of PricewaterhouseCoopers LLP. +X +23.2 +Consent of Ryder Scott Company, L.P., Petroleum Consultants. +X +23.3 +Consent of Netherland, Sewell & Associates, Inc., Petroleum Consultants. +X +31.1 +Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +31.2 +Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +32.1* +Certifications by Chief Executive Officer and Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. +99.1 +Report of Independent Petroleum Consultants - Ryder Scott Company, L.P. +X +129 +Incorporated by Reference +Exhibit Number +Exhibit Description +Form +SEC File Number +Exhibit +Filing Date +Filed Herewith +99.2 +Report of Independent Petroleum Consultants - Netherland, Sewell & Associates, Inc. +X +101.INS +XBRL Instance Document +X +101.SCH +XBRL Taxonomy Extension Schema Document +X +101.CAL +XBRL Taxonomy Extension Calculation Linkbase Document +X +101.DEF +XBRL Taxonomy Extension Definition Linkbase Document +X +101.LAB +XBRL Taxonomy Extension Label Linkbase Document +X +101.PRE +XBRL Taxonomy Extension Presentation Linkbase Document +X +* Furnished herewith. +130 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +PDC ENERGY, INC. +By: /s/ Barton Brookman +Barton Brookman +President and Chief Executive Officer +February 27, 2019 +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated: +Signature +Title +Date +/s/ Barton Brookman +President, Chief Executive Officer and Director +February 27, 2019 +Barton Brookman +(principal executive officer) +/s/ R. Scott Meyers +Senior Vice President and Chief Financial Officer +February 27, 2019 +R. Scott Meyers +(principal financial officer) +/s/ Douglas Griggs +Chief Accounting Officer +February 27, 2019 +Douglas Griggs +(principal accounting officer) +/s/ Jeffrey C. Swoveland +Chairman and Director +February 27, 2019 +Jeffrey C. Swoveland +/s/ Anthony J. Crisafio +Director +February 27, 2019 +Anthony J. Crisafio +/s/ Larry F. Mazza +Director +February 27, 2019 +Larry F. Mazza +/s/ David C. Parke +Director +February 27, 2019 +David C. Parke +/s/ Randy S. Nickerson +Director +February 27, 2019 +Randy S. Nickerson +/s/ Mark E. Ellis +Director +February 27, 2019 +Mark E. Ellis +/s/ Christina M. Ibrahim +Director +February 27, 2019 +Christina M. Ibrahim +131 +GLOSSARY OF UNITS OF MEASUREMENT AND INDUSTRY TERMS +UNITS OF MEASUREMENT +The following presents a list of units of measurement used throughout the document. +Bbl – One barrel of crude oil or NGL or 42 gallons of liquid volume. +Bcf – One billion cubic feet of natural gas volume. +Boe – One barrel of crude oil equivalent. +Btu – British thermal unit. +BBtu – One billion British thermal units. +MBoe – One thousand barrels of crude oil equivalent. +MBbls – One thousand barrels of crude oil. +Mcf – One thousand cubic feet of natural gas volume. +MMBoe – One million barrels of crude oil equivalent. +MMBbls – One million barrels of crude oil. +MMBtu – One million British thermal units. +MMcf – One million cubic feet of natural gas volume. +GLOSSARY OF INDUSTRY TERMS +The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report: +CIG - Colorado Interstate Gas. +Completion - Refers to the installation of permanent equipment for the production of crude oil and natural gas from a recently drilled well or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned. +Developed acreage - Acreage assignable to productive wells. +Development well - A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. +Differentials - The difference between the crude oil and natural gas index spot price and the corresponding cash spot price in a specified location. +Dry well or dry hole - A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well. +Exploratory well - A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. +Extensions, discoveries and other additions - As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates. +Farm-out - Transfer of all or part of the operating rights from a working interest owner to an assignee, who assumes all or some of the burden of development in return for an interest in the property. The assignor usually retains an overriding royalty interest but may retain any type of interest. +Fracture or Fracturing - Procedure to stimulate production by forcing a mixture of fluid and proppant into the formation under high pressure. Fracturing creates artificial fractures in the reservoir rock to increase permeability and porosity, thereby allowing the release of trapped hydrocarbons. +Gross acres or wells - Refers to the total acres or wells in which we have a working interest. +Henry Hub - Refers to the pricing point for natural gas futures contracts traded on NYMEX. +132 +Horizontal drilling - A drilling technique that permits the operator to drill a horizontal well shaft from the bottom of a vertical well and thereby to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons. +Joint interest billing - Process of billing/invoicing the costs related to well drilling, completions and production operations among working interest partners. +Natural gas liquid(s) or NGL(s) - Hydrocarbons which can be extracted from natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs include ethane, propane, butane and other natural gasolines. +Net acres or wells - Refers to gross acres or wells we own multiplied, in each case, by our percentage working interest. References to net acres or wells include our proportionate share of PDCM's and our affiliated partnerships' net acres or wells. +Net production - Crude oil and natural gas production that we own, less royalties and production due to others. +Non-operated - A project in which we are not the operator. +NYMEX - New York Mercantile Exchange. +Operator - The individual or company responsible for the exploration, development and/or production of an oil or gas well or lease. +Overriding royalty - An interest which is created out of the operating or working interest. Its term is coextensive with that of the operating interest. +Possible reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability to exceed the sum of proved, probable and possible reserves. When probabilistic methods are used, there must be at least a 10 percent probability that the actual quantities recovered will equal or exceed the sum of proved, probable and possible estimates. +Present value of future net revenues or (PV-10) - The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, of proved reserves calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using pricing and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization and discounted using an annual discount rate of 10 percent. PV-10 is pre-tax and therefore a non-U.S. GAAP financial measure. +Probable reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Similarly, when probabilistic methods are used, there must be at least a 50 percent probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. +Productive well - An exploratory or developmental well that is not a dry well or dry hole, as defined above. +Proved developed non-producing reserves - Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and/or (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells. +Proved developed producing reserves or PDPs - Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods. +Proved developed reserves - The combination of proved developed producing and proved developed non-producing reserves. +Proved reserves - This term means "proved oil and gas reserves" as defined in SEC Regulation S-X Section 4-10(a) and refers to those quantities of crude oil and condensate, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, +133 +and under existing conditions, operating methods and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +Proved undeveloped reserves or PUDs - Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. +Recomplete or Recompletion - The modification of an existing well for the purpose of producing crude oil and natural gas from a different producing formation. +Reserves - Estimated remaining quantities of crude oil, natural gas, NGLs and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering crude oil, natural gas and NGLs or related substances to market, and all permits and financing required to implement the project. +Royalty - An interest in a crude oil and natural gas lease or mineral interest that gives the owner of the royalty the right to receive a portion of the production from the leased acreage or mineral interest (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +Section - A square tract of land one mile by one mile, containing 640 acres. +Spud - To begin drilling; the act of beginning a hole. +Standardized measure of discounted future net cash flows or standardized measure - Future net cash flows discounted at a rate of 10 percent. Future net cash flows represent the estimated future revenues to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment and (ii) future income tax expense. +Stratigraphic test well - A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. +Undeveloped acreage - Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas, regardless of whether such acreage contains proved reserves. +Waha - Waha West Texas natural gas prices +Working interest - An interest in a crude oil and natural gas lease that gives the owner of the interest the right to drill and produce crude oil and natural gas on the leased acreage. It requires the owner to pay its share of the costs of drilling and production operations. +Workover - Major remedial operations on a producing well to restore, maintain, or improve the well's production. +134 \ No newline at end of file diff --git a/raw/filings/0000077877/2018/0000077877-19-000009/filing_metadata.csv b/raw/filings/0000077877/2018/0000077877-19-000009/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..07f4520161b545e9a26c10b25f144c3560f857c8 --- /dev/null +++ b/raw/filings/0000077877/2018/0000077877-19-000009/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000077877,PDCE,"PDC ENERGY, INC.",10-K,2019-02-28,2018-12-31,2019-02-27T22:42:13.000Z,0000077877-19-000009,pdce-201810xk.htm,PDCE ENERGY 2018 FORM 10-K,25330353,1,0,https://www.sec.gov/Archives/edgar/data/77877/000007787719000009/pdce-201810xk.htm,https://www.sec.gov/Archives/edgar/data/77877/000007787719000009/,2018,2018,1 diff --git a/raw/filings/0000077877/2018/0000077877-19-000009/item1.txt b/raw/filings/0000077877/2018/0000077877-19-000009/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2018/0000077877-19-000009/item13.txt b/raw/filings/0000077877/2018/0000077877-19-000009/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..8e7cff0d402d60e1408551810341138093d4b430 --- /dev/null +++ b/raw/filings/0000077877/2018/0000077877-19-000009/item13.txt @@ -0,0 +1,2 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2019 Annual Stockholders' meeting and is incorporated by reference in this report. \ No newline at end of file diff --git a/raw/filings/0000077877/2018/0000077877-19-000009/item9a.txt b/raw/filings/0000077877/2018/0000077877-19-000009/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..18e1084558e31fa1d5982e79a6e0edf649fbae59 --- /dev/null +++ b/raw/filings/0000077877/2018/0000077877-19-000009/item9a.txt @@ -0,0 +1,18 @@ +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +As of December 31, 2018 , we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Based on the results of this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were not effective as of December 31, 2018 because of the material weaknesses in our internal control over financial reporting described below. +Management's Report on Internal Control over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Internal control over financial reporting is a process designed by, or under the supervision of, our CEO and CFO, or persons performing similar functions, and effected by our board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate. +Management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2018 , based upon the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). +A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. +We did not maintain a sufficient complement of personnel within the Land Department as a result of increased volume of leases, which contributed to the ineffective design and maintenance of controls to verify the completeness and accuracy of land administrative records associated with unproved leases, which are used in verifying the completeness, accuracy, valuation, rights and obligations over the accounting of properties and equipment, sales and accounts receivable and costs and expenses. These control deficiencies resulted in immaterial adjustments to our unproved properties, impairment of unproved properties, sales, accounts receivable and depletion expense accounts and related disclosures in our consolidated financial statements for the years ended December 31, 2018 and 2017 . Additionally, these control deficiencies could result in misstatements of substantially all accounts and disclosures that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. Accordingly, our management has determined that these control deficiencies constitute material weaknesses. +Because of these material weaknesses, management concluded that we did not maintain effective internal control over financial reporting as of December 31, 2018 . +The effectiveness of our internal control over financial reporting as of December 31, 2018 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears under Item 8. +Remediation Plan for Material Weaknesses +We are committed to continuing to review, optimize and enhance our internal control over financial reporting. In response to the identified material weaknesses, our management, with the oversight of the Audit Committee of our Board of +125 +Directors, has assessed a number of different remediation initiatives to improve our internal control over financial reporting. Building on our efforts during 2017 , we continued throughout 2018 to dedicate significant resources and efforts to improve our internal control over financial reporting and to take steps to remediate the material weaknesses identified above. While certain remediation plans have been implemented, we continue to actively plan for and implement additional remediation measures. +During 2018 , we have taken steps to strengthen the control activities within the Land Department, which include the combination of hiring of additional personnel with relevant experience, increased layers of supervision, and division of responsibilities within the Land Department. We have also designed and implemented control activities to verify the completeness and accuracy of land administrative records associated with unproved leases, including the verification of the reliability of underlying data used in the execution of the control activities. As we continue to evaluate and work to improve our internal control over financial reporting, we may take additional measures to address these control deficiencies, or we may modify certain of the remediation measures described above to improve the operating effectiveness of those measures. These material weaknesses will not be considered remediated until the applicable remediated controls operate for a sufficient period of time and management has concluded, through testing, that these controls are operating effectively. +Changes in Internal Control over Financial Reporting +There were no changes in our internal control over financial reporting during the quarter ended December 31, 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. \ No newline at end of file diff --git a/raw/filings/0000077877/2018/0000077877-19-000009/rp_note.txt b/raw/filings/0000077877/2018/0000077877-19-000009/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2018/0000077877-19-000009/rpt_disclosure.txt b/raw/filings/0000077877/2018/0000077877-19-000009/rpt_disclosure.txt new file mode 100644 index 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+☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from __________ to _________ +Commission File Number 001-37419 +PDC ENERGY, INC. +(Exact name of registrant as specified in its charter) +Delaware +95-2636730 +(State of incorporation) +(I.R.S. Employer Identification No.) +1775 Sherman Street, Suite 3000 +Denver , Colorado 80203 +(Address of principal executive offices) (Zip code) +Registrant's telephone number, including area code: ( 303 ) 860-5800 +Securities registered pursuant to Section 12(b) of the Act: +Title of each class +Ticker Symbol +Name of each exchange on which registered +Common Stock, par value $0.01 per share +PDCE +NASDAQ Global Select Market +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes T No £ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes £ No T +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes T No £ +Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes T No £ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act. +Large Accelerated Filer +☒ +Accelerated filer +☐ +Non-accelerated filer +☐ +Smaller reporting company +☐ +Emerging growth company +☐ +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. £ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No T +The aggregate market value of our common stock held by non-affiliates on June 30, 2019 was $ 2.3 billion (based on the closing price of $36.06 per share as of the last business day of the fiscal quarter ending June 30, 2019 ). +As of February 18, 2020 , there were 100,121,539 shares of our common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +We hereby incorporate by reference into this document the information required by Part III of this Form, which will appear in our definitive proxy statement filed pursuant to Regulation 14A for our 2020 Annual Meeting of Stockholders. +PDC ENERGY, INC. +2019 ANNUAL REPORT ON FORM 10-K +TABLE OF CONTENTS +PART I +Page +Items 1. and 2. +Business and Properties +3 +Item 1A. +Risk Factors +20 +Item 1B. +Unresolved Staff Comments +37 +Item 3. +Legal Proceedings +37 +Item 4. +Mine Safety Disclosures +37 +PART II +Item 5. +Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +38 +Item 6. +Selected Financial Data +40 +Item 7. +Management's Discussion and Analysis of Financial Condition and Results of Operations +41 +Item 7A. +Quantitative and Qualitative Disclosures About Market Risk +64 +Item 8. +Financial Statements and Supplementary Data +66 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +125 +Item 9A. +Controls and Procedures +125 +Item 9B. +Other Information +125 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +126 +Item 11. +Executive Compensation +126 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +126 +Item 13. +Certain Relationships and Related Transactions and Director Independence +126 +Item 14. +Principal Accounting Fees and Services +126 +PART IV +Item15. +Exhibits, Financial Statement Schedules +126 +Item 16. +Form 10-K Summary +112 +Signatures +130 +Glossary of Units of Measurements and Industry Terms +131 +PART I +REFERENCES TO THE REGISTRANT +Unless the context otherwise requires, references in this report to "PDC," the "Company," "we," "us," "our" or "ours" refer to the registrant, PDC Energy, Inc. and our wholly-owned subsidiaries consolidated for the purposes of our financial statements. PDC Energy, Inc. is a Delaware corporation, having reincorporated from Nevada in 2015. +GLOSSARY OF UNITS OF MEASUREMENTS AND INDUSTRY TERMS +Units of measurements and industry terms are defined in the Glossary of Units of Measurements and Industry Terms, included at the end of this report. +SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS +This report contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical fact included in and incorporated by reference into this report are "forward-looking statements." Words such as expect, anticipate, intend, plan, believe, seek, estimate, schedule and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements include, among other things, statements regarding future: production, costs and cash flows; drilling locations, zones and growth opportunities; commodity prices and differentials; capital expenditures and projects, including the number of rigs employed; cash flows from operations relative to future capital investments; our stock repurchase program, which may be modified or discontinued at any time; potential additional payments from the sale of our midstream assets; financial ratios and compliance with covenants in our revolving credit facility and other debt instruments; impacts of certain accounting and tax changes; timing and adequacy of infrastructure projects of our midstream providers and the related impact on our midstream capacity and related curtailments; fractionation capacity; impacts of Colorado political matters and expected timing of rulemakings; ability to meet our volume commitments to midstream providers; ability to obtain permits from the Colorado Oil and Gas Conservation Commission ("COGCC") in a timely manner; ongoing compliance with our consent decree and expected timing of certain litigation; and reclassification of the Denver Metro/North Front Range NAA ozone classification to serious. +The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this report or accompanying materials, we may use the term “projection” or similar terms or expressions, or indicate that we have “modeled” certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or the industry in periods beyond the current fiscal year. Because such statements relate to events or conditions further in the future, they are subject to increased levels of uncertainty. +Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to: +• +changes in global production volumes and demand, including economic conditions that might impact demand and prices for products we produce; +• +volatility of commodity prices for crude oil, natural gas and natural gas liquids ("NGLs") and the risk of extended periods of depressed prices; +• +volatility and widening of differentials; +• +reductions in the borrowing base under our revolving credit facility; +• +impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement related to those laws and regulations, liabilities arising thereunder and the costs to comply with those laws and regulations; +• +impact of recent regulatory developments in Colorado with respect to additional permit scrutiny; +• +declines in the value of our crude oil and natural gas properties resulting in impairments; +• +changes in estimates of proved reserves; +• +inaccuracy of estimated reserves and production rates; +• +potential for production decline rates from our wells being greater than expected; +• +timing and extent of our success in discovering, acquiring, developing and producing reserves; +1 +• +availability of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production and the impact of these facilities and regional capacity on the prices we receive for our production; +• +timing and receipt of necessary regulatory permits; +• +risks incidental to the drilling and operation of crude oil and natural gas wells; +• +difficulties in integrating our operations as a result of any significant acquisitions, including the merger with SRC Energy, Inc. ("SRC"), or acreage exchanges; +• +increases or changes in costs and expenses; +• +limitations in the availability of supplies, materials, contractors and services that may delay the drilling or completion of our wells; +• +potential losses of acreage due to lease expirations or otherwise; +• +future cash flows, liquidity and financial condition; +• +competition within the oil and gas industry; +• +availability and cost of capital; +• +our success in marketing crude oil, natural gas and NGLs; +• +effect of crude oil, natural gas and NGLs derivatives activities; +• +impact to our operations, personnel retention, strategy, stock price and expenses caused by the actions of activist shareholders; +• +impact of environmental events, governmental and other third-party responses to such events and our ability to insure adequately against such events; +• +cost of pending or future litigation; +• +effect that acquisitions we may pursue have on our capital requirements; +• +our ability to retain or attract senior management and key technical employees; and +• +success of strategic plans, expectations and objectives for our future operations. +Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under Item 1A, Risk Factors , made in this report and our other filings with the U.S. Securities and Exchange Commission ("SEC") for further information on risks and uncertainties that could affect our business, financial condition, results of operations and cash flows. We caution you not to place undue reliance on forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement. +2 +ITEMS 1. AND 2. BUSINESS AND PROPERTIES +The Company +We are a domestic independent exploration and production company that acquires, explores and develops properties for the production of crude oil, natural gas and NGLs, with operations in the Wattenberg Field in Colorado and the Delaware Basin in Texas. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are primarily focused in the Wolfcamp zones. +The following map presents the general locations of our development and production activities as of December 31, 2019 : +The following table presents selected information regarding our results of operations for the periods presented: +Year Ended/As of +December 31, +Percent Change +2019 +2018 +2019-2018 +(production and reserves in MMBoe, dollars in millions) +Wells: +Gross productive wells +2,649 +2,876 +(7.9 +)% +Net productive wells +2,101 +2,284 +(8.0 +)% +Horizontal percentage +48 +% +39 +% +23 +% +Gross operated wells turned-in-line +135 +165 +(18.2 +)% +Net operated wells turned-in-line +125 +151 +(17.2 +)% +Production: +Wattenberg Field +38.0 +30.7 +23.9 +% +Delaware Basin +11.4 +9.4 +22.1 +% +Utica Shale (1) +— +0.1 +* +Total +49.4 +40.2 +23.0 +% +Reserves: +Proved reserves +610.9 +544.9 +12.1 +% +Proved developed reserves percentage +35 +% +33 +% +6 +% +Standardized measure +$ +3,310 +$ +4,448 +(25.6 +)% +PV-10 (2) +$ +3,837 +$ +5,321 +(27.9 +)% +Liquidity +$ +1,291.0 +$ +1,268.9 +1.7 +% +Leverage ratio +1.4 +1.4 +— +% +(1) In March 2018, we completed the disposition of our Utica Shale properties. +(2) PV-10 is a non-U.S. GAAP financial measure. It is not intended to represent the current market value of our estimated +reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in +accordance with U.S. GAAP, but rather should be considered in addition to the standardized measure. See Part II, +Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of +Non-U.S. GAAP Financial Measures, for a definition of PV-10 and a reconciliation of our PV-10 value to the +standardized measure. +3 +Acquisition +In January 2020, we merged with SRC in a transaction valued at $1.7 billion , inclusive of SRC's net debt (the “ SRC Acquisition ”). We issued approximately 39 million shares of our common stock to SRC shareholders and holders of SRC equity awards, reflecting the issuance of 0.158 of a share of our common stock in exchange for each outstanding share of SRC common stock and the cancellation of outstanding SRC equity awards pursuant to the merger agreement that we entered into with SRC (the "Merger Agreement"). +The following table presents selected information regarding our and SRC's operations as of and for the year ended December 31, 2019 : +Year Ended/As of December 31, 2019 +PDC +SRC +Combined +(production in MBoe, reserves in MMBoe and dollars in millions) +Wells: +Gross productive wells +2,649 +1,529 +4,178 +Net productive wells +2,101 +958 +3,059 +Production: +Crude oil (MBbls) +19,166 +9,813 +28,979 +Natural gas (MMcf) +115,950 +49,471 +165,421 +NGLs (MBbls) +10,923 +4,526 +15,449 +Crude oil equivalent (MBoe) +49,414 +22,584 +71,998 +Average Boe per day (Boe) +135,381 +61,874 +197,255 +Crude oil production percentage +38.8 +% +43.5 +% +40.2 +% +Reserves: +Proved reserves (1) +610.9 +295.0 +905.9 +Proved developed reserves percentage +35 +% +42 +% +37 +% +Crude oil and condensate percentage +32 +% +27 +% +31 +% +(1) Estimated reserve information for SRC is based on assumed realized prices of $50.17 per Bbl of crude oil, $1.69 per Mcf of natural gas +and $9.67 per Bbl of NGLs and SRC's development plan for the related properties. The estimates are not included in the Ryder Scott +Company, L.P. ("Ryder Scott") or Netherland, Sewell, & Associates, Inc. ("NSAI") reports for our properties described below in "Properties - +Proved Reserves" and are subject to the risks and uncertainties described in "Risk Factors - Risks Relating to Our Business and Industry - Our +estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or +underlying assumptions may materially affect the quantities and present value of our reserves." +2020 Strategic Focus +Our planned 2020 capital investments in crude oil and natural gas properties, which we expect to be between $1.0 billion and $1.1 billion , are focused on continued execution of our development plans in the Wattenberg Field, including acreage received in the SRC Acquisition, and Delaware Basin. In allocating our planned expenditures, we consider, among other things, cost efficiencies, midstream capacities and netback pricing, expected future cash flows and rates of return, the political environment and our remaining drilling location inventory in order to best meet our short- and long-term corporate strategy. We are committed to our disciplined approach to managing our development plans. Should commodity pricing or the operating environment deteriorate, we may determine that an adjustment to our development plan is appropriate. +Based on our current production forecast for 2020 and assumed average New York Mercantile Exchange (“NYMEX”) prices of $52.50 per Bbl of crude oil and $2.00 per Mcf of natural gas and an assumed average composite price of $11.00 per Bbl for NGLs, we expect 2020 adjusted cash flows from operations, a non-U.S. GAAP financial measure, to exceed our capital investments in crude oil and natural gas properties by approximately $250 million . Assuming consistent realization percentages, we estimate that for every: +4 +• +$2.50 change in the NYMEX crude oil price from $52.50 , our adjusted cash flows from operations would increase or decrease by approximately $30 million ; +• +$0.25 change in the NYMEX natural gas price from $2.00 , our adjusted cash flows from operations would increase or decrease by approximately $20 million ; and +• +$1.00 change in the composite price for NGLs from $11.00 , our adjusted cash flows from operations would increase or decrease by approximately $20 million . +We may revise our 2020 capital investment program during the year as a result of, among other things, changes in commodity prices and/or our internal long-term outlook for commodity prices, the cost of services for drilling and well completion activities, requirements to hold acreage, drilling results, changes in our borrowing capacity, a significant change in cash flows, regulatory issues, availability of midstream infrastructure and services, requirements to maintain continuous activity on leaseholds or acquisition and/or divestiture opportunities. +Long-Term Business Strategy and Key Strengths +Our long term business strategy focuses on creating shareholder value by delivering attractive returns from responsible development of our crude oil and natural gas properties, maintaining financial strength, generating sustainable cash flows from operations in excess of our capital investments in crude oil and natural gas properties and returning capital to shareholders. We seek to create long-term shareholder value through the following: +• +Strong financial position. We maintain a disciplined financial strategy that focuses on strong liquidity, low leverage ratios and an active commodity derivative program to help mitigate a portion of the risk associated with commod ity price fluctuations. We believe that execution of this strategy will allow us to deliver strong corporate returns year-over-year, even through challenging commodity price environments. As of December 31, 2019, we had total liquidity of $1.3 billion , a leverage ratio, as defined in our revolving line of credit facility agreement, of 1.4 and commodity derivative positions covering approximately 10.8 MMBbls and 3.2 MMBbls of crude oil production for 2020 and 2021, respectively. As of the same date, we had hedged approximately 4.0 Bcf of natural gas production for 2020. +• +Focus on generating sustainable cash flows from operations in excess of capital investments. We are focused on generating multi-year sustainable cash flows from operations in excess of our capital investments through managing capital spending and growth rates, adjusting the timing of completion of our inventory of drilled uncompleted wells ("DUCs"), utilizing commodity derivative instruments, focusing on margin improvement from reductions in our cost structure and through increased capital efficiency from technological innovation. +• +Return of capital to shareholders. We are focused on returning capital to shareholders through our ongoing share repurchase program and a focus on debt reduction. Through February 24, 2020 , we have repurchased an aggregate 5.3 million shares of our outstanding common stock for a total cost of $166.9 million . Through successful execution of our business plan, our projected cash flows are expected to position us to deliver on our commitment to return capital to shareholders. +• +Significant operational control in our core areas. We have, and expect to continue to have, a substantial degree of operational control over our properties. As a result of successfully executing our strategy of acquisitions and acreage trades in our core areas of operations, we have built multiple concentrated acreage positions with high working interests that we believe will allow us to enhance the value of our assets and replenish our drilling inventory. Including wells that we received in the SRC Acquisition, we currently operate approximately 78 percent of all the wells in which we have an interest. This operational control allows us to better manage our drilling, production, operating and administrative costs and to leverage our technical expertise in our core operating areas. Our leaseholds that are held by production further enhance our operational control by providing us with additional flexibility on the timing of drilling of those locations. +• +Project inventory in two premier crude oil, natural gas and NGL plays. We have a substantial multi-year inventory of high-quality horizontal drilling opportunities across two premier U.S. onshore basins: the Wattenberg Field in Weld County, Colorado and the Delaware Basin in Reeves County, Texas. Our portfolio has a proven record of delivering strong and repeatable economic returns and provides us the ability to allocate capital investments and manage risk as each basin has its own operating and competitive dynamic in terms of commodity price markets, service costs, takeaway capacity and regulatory and political considerations. We have a disciplined development program that seeks to expand our project inventory through testing new intervals and considering various spacing configurations. We believe our project inventory will allow us to achieve attractive rates of return and grow our proved reserves and +5 +production in a sustainable fashion. Such expected returns on drilling can vary well by well and are based upon many factors, including but not limited to, commodity prices and well development and operating costs. +• +Efficiency through technology and consolidation. Technological innovation has led to continued improvement in our drilling and completion times. We are utilizing technology to improve the efficiency of our horizontal drilling and completion operations in the Wattenberg Field. In the Delaware Basin, we continue to make progress towards improved capital efficiency through various drilling initiatives and completion designs. The technology associated with our completions process continues to improve as we design wellbore placement and stage spacing and, in the Wattenberg Field, increase the completed lateral length of our wells. In addition, completion equipment, perforation clusters, fluid and sand type and concentration decisions continue to result in more efficient recoveries of crude oil and natural gas reserves. As with our drilling operations, we are currently working toward using the expertise we have developed in the Wattenberg Field to increase the efficiency of our Delaware Basin completions activities. Additionally, acreage consolidation, particularly in the Wattenberg Field, increases our ability to drill longer length lateral wells. Longer laterals allow us to develop our properties with a smaller number of wells and less truck traffic, with resulting benefits for our operations and for the communities in which we operate. +• +Strong environmental, health and safety compliance programs and community outreach. We have focused on establishing effective environmental, health and safety programs that are intended to promote safe working practices for our employees and contractors and to help earn the trust and respect of land owners, regulatory agencies and public officials. This is an important part of our strategy in effectively operating in today’s intensive regulatory climate. For the year ended December 31, 2019 , we achieved our strategic priorities around our environment, health and safety programs. We are also dedicated to being an active and contributing member of the communities in which we operate. We share our success with these communities in various ways, including charitable giving and community event sponsorships. +• +Experienced management team with proven track record. We have a strong executive management team that has an average of 25 years of experience in the oil and gas industry. Collectively, this experience includes technical, operational, commercial, financial and strategic aspects of the oil and gas industry. This team has a proven track record of executing on value-added capital investment programs that have been implemented with a focus on financial discipline and improving on an already strong balance sheet, while growing production and proved reserves. Additionally, our team's experience has helped us continue to achieve our strategic objectives through periods of commodity price volatility, cost inflation and other challenging operating environments. +Operating Areas +Wattenberg Field. In the Wattenberg Field, we have identified a gross operated inventory of approximately 1,600 horizontal drilling locations (including locations received as part of the SRC Acquisition) that we expect to generate acceptable rates of return based on forward strip pricing, with an average lateral length of approximately 8,300 feet. In addition to these drilling locations, we entered 2020 with approximately 230 gross operated DUCs, including 88 gross operated DUCs received as part of the SRC Acquisition. Our Wattenberg Field horizontal drilling locations have been substantially de-risked through multiple years of successful development in the field. We continue to analyze and test various wellbore spacing configurations in areas of the field that we believe have the potential to increase our gross operated inventory. Substantially all of our Wattenberg Field acreage is held by production. Wells in the Wattenberg Field typically have productive horizons at depths of approximately 6,500 to 7,500 feet below the surface. +Delaware Basin. In the Delaware Basin, we have identified a gross operated inventory of approximately 190 horizontal drilling locations that we expect to generate acceptable rates of return based on forward strip pricing, primarily targeting the Wolfcamp A and Wolfcamp B zones, within the oilier eastern and north central portions of our acreage. The average lateral length of these locations is approximately 8,600 feet, compared to an average lateral length of approximately 7,900 feet as of year-end 2018. Some of these locations are within untested target zones that may be subject to a higher degree of uncertainty or may depend upon additional delineation and testing. Our gross operated inventory in the Delaware Basin decreased from year-end 2018, primarily due to the removal of several standard-reach lateral, higher gas-to-oil ratio locations that were negatively impacted by decreased NYMEX natural gas pricing and higher Waha natural gas differentials. We continue to pursue various business development initiatives, with a focus on acreage swaps and joint development projects, designed to increase our Delaware Basin project inventory by establishing longer lateral drilling units capable of delivering attractive economic returns. In addition to these drilling locations, we entered 2020 with approximately 27 gross operated DUCs. Wells in the Delaware Basin typically have productive horizons at depths of approximately 8,000 to 11,500 feet below the surface. +6 +Midstream Asset Divestitures +In the second quarter of 2019, we sold Delaware Basin produced water gathering and disposal, crude oil gathering and natural gas gathering assets (the "Midstream Asset Divestitures") for an aggregate cash purchase price of $345.6 million, subject to certain customary post-closing adjustments, plus potential future long-term incentive payments. We do not currently expect to meet the conditions to receive these incentive payments. Concurrent with the Midstream Asset Divestitures, we entered into agreements with the purchasers which provide us with certain gathering, processing, transportation and water disposal services. Proceeds were allocated first to the assets sold based upon the fair values of the tangible assets, with $179.6 million allocated to the acreage dedication agreements. +Significant Customers +Our most significant customers are Occidental Marketing, Inc., DCP Midstream, LP ("DCP"), Mercuria Energy Trading, Inc. and United Energy Trading, LLC. Sales to each of these customers contributed more than 10 percent of our 2019 revenues. However, given the liquidity in the market for the sale of hydrocarbons, we believe that the loss of any single purchaser, or the aggregate loss of several purchasers, could be managed by selling to alternative purchasers. +Properties +Productive Wells +The following table presents our productive wells: +Productive Wells +As of December 31, 2019 +Crude Oil +Natural Gas +Total +Operating Region/Area +Gross +Net +Gross +Net +Gross +Net +Wattenberg Field (1) +1,163 +809.7 +1,385 +1,212.8 +2,548 +2,022.5 +Delaware Basin +48 +27.6 +53 +50.7 +101 +78.3 +Total productive wells +1,211 +837.3 +1,438 +1,263.5 +2,649 +2,100.8 +(1) Amounts do not include 950 gross (516 net) productive crude oil wells or 579 gross (442 net) productive natural gas wells received in the +SRC Acquisition. +Proved Reserves +The following table presents our proved reserve estimates as of December 31, 2019 , based on reserve reports prepared by our independent petroleum engineering consulting firms, Ryder Scott and NSAI and related information: +Proved Reserves at December 31, 2019 +Proved Reserves (MMBoe) +% of Total Proved Reserves +% Proved Developed +% Liquids +Proved Reserves to Production Ratio (in years)(2) +2019 Production (MBoe) +Wattenberg Field +492.1 +(1 +) +81 +% +33 +% +55 +% +13.0 +37,984 +Delaware Basin +118.8 +19 +% +44 +% +69 +% +10.4 +11,430 +Total +610.9 +100 +% +35 +% +57 +% +12.4 +49,414 +(1) Amount does not include 295.0 MMBoe of proved reserves received in the SRC Acquisition. +(2) Based on 2019 PDC production. +Our proved reserves are sensitive to future crude oil, natural gas and NGLs sales prices and the related effect on the economic productive life of producing properties. Increases in commodity prices may result in a longer economic productive life of a property or the recognition of more economically viable proved undeveloped ("PUD") reserves, while decreases in commodity prices may result in corresponding negative impacts. All of our proved reserves are located in the U.S. +Controls Over Reserve Report Preparation . Our proved reserve estimates are prepared using the definitions for proved reserves set forth in SEC Regulation S-X, Rule 4-10(a) and other applicable SEC rules. Inputs and major assumptions related to +7 +our proved reserves are reviewed annually by an internal team composed of reservoir engineers, geologists, land and management for adherence to SEC guidelines through a detailed review of land and accounting records, available geological and reservoir data and production performance data. The internal team compiles the reviewed data and forwards the applicable data to Ryder Scott or NSAI. Our proved reserves in the Wattenberg Field as of December 31, 2019 were estimated by Ryder Scott and our proved reserves in the Delaware Basin as of that date were estimated by NSAI. +When preparing our reserve estimates, neither Ryder Scott nor NSAI independently verifies the accuracy and completeness of information and data furnished by us with respect to ownership interests, production volumes, well test data, historical costs of operations and development, product prices or any agreements relating to current and future operations of properties or sales of production. Ryder Scott and NSAI prepare estimates of our reserves in conjunction with an ongoing review by our engineers. A final comparison of data is performed to ensure that the reserve estimates are complete, determined pursuant to acceptable industry methods and with a level of detail we deem appropriate. The final estimated reserve reports are prepared by Ryder Scott and NSAI and reviewed by our engineering staff and management prior to issuance by those firms. +Letters which identify the professional qualifications of the individuals at Ryder Scott and NSAI who are responsible for overseeing the preparation of our reserve estimates as of December 31, 2019 have been filed as Exhibits 99.1 and 99.2 to this report. +Internally, the professional qualifications of our lead engineer primarily responsible for overseeing the preparation of our reserve estimates, as defined in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the Society of Petroleum Engineers, qualifies this individual as a Reserve Estimator. This person holds a Masters of Petroleum Engineering from the Colorado School of Mines and a Bachelors of Geology from the University of Colorado and has over 19 years of oil and gas experience. +In determining our proved reserves estimates, we used a combination of performance methods, including decline curve analysis and other computational methods, offset analogies and seismic data and interpretation. All of our proved undeveloped reserves conform to the SEC five-year rule requirement as all proved undeveloped locations are scheduled, according to an adopted development plan, to be drilled within five years of the location’s initial booking date. +Commodity Pricing . Per SEC rules, the pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of the month prices for the preceding 12 months. The NYMEX prices used in preparing the reserves are then adjusted based on energy content, location and basis differentials and other marketing deductions to arrive at the net realized price. +The indicated index prices for our reserves, by commodity, are presented below. +Average Benchmark Prices (1) +As of December 31, +Crude Oil +(per Bbl) (2) +Natural Gas +(per Mcf) (2) +NGLs +(per Bbl) (3) +2019 +$ +55.69 +$ +2.58 +$ +55.69 +2018 +65.56 +3.10 +65.56 +2017 +51.34 +2.98 +51.34 +The netted back price used to estimate our reserves, by commodity, are presented below. +Price Used to Estimate Reserves (4) +As of December 31, +Crude Oil +(per Bbl) +Natural Gas +(per Mcf) +NGLs +(per Bbl) +2019 +$ +52.63 +$ +1.50 +$ +12.21 +2018 +61.14 +2.15 +23.04 +2017 +48.68 +2.31 +20.21 +(1) +Per SEC rules, the pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of the month prices for the preceding 12 months. +(2) Our benchmark prices for crude oil and natural gas are West Texas Intermediate ("WTI") and Henry Hub, respectively. +(3) +For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. +(4) +These prices are based on the index prices and are net of basin differentials, transportation fees, contractual adjustments and Btu adjustments we experienced for the respective commodity. +8 +Commodities and Standardized Measure . Reserve estimates involve judgments and reserves cannot be measured exactly. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geologic and geophysical data and economic changes. Neither the estimated future net cash flows nor the standardized measure of discounted future net cash flows ("standardized measure") is intended to represent the current market value of our proved reserves. For additional information regarding both of these measures, as well as other information regarding our proved reserves, see the Supplemental Information Unaudited - Crude Oil and Natural Gas Information provided with our consolidated financial statements included elsewhere in this report. +The following tables provide information regarding our estimated proved reserves: +As of December 31, +2019 +2018 +2017 +Proved reserves +Crude oil and condensate (MMBbls) +197 +190 +155 +Natural gas (Bcf) +1,558 +1,336 +1,154 +NGLs (MMBbls) +154 +132 +106 +Total proved reserves (MMBoe) +611 +545 +453 +Proved developed reserves (MMBoe) +214 +180 +143 +Estimated undiscounted future net cash flows (in millions) (1) +$ +5,896 +$ +7,735 +$ +5,453 +Standardized measure (in millions) +$ +3,310 +$ +4,448 +$ +2,880 +PV-10 ( in millions) (2) +$ +3,837 +$ +5,321 +$ +3,212 +(1) +Amount represents aggregate undiscounted future net cash flows, before income taxes, estimated by Ryder Scott and NSAI, of approximately $6.8 billion , $9.1 billion and $6.2 billion as of December 31, 2019 , 2018 and 2017 , respectively, less an internally-estimated undiscounted future income tax expense of approximately $0.9 billion , $1.4 billion and $0.7 billion , respectively. +(2) +PV-10 is a non-U.S. GAAP financial measure. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in accordance with U.S. GAAP, but rather should be considered in addition to the standardized measure. See Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10 and a reconciliation of our PV-10 value to the standardized measure. +The additions to our proved reserves at December 31, 2019 as compared to December 31, 2018 were primarily a result of an extended reserve life in the Delaware Basin due to an improved operating cost structure, increased production forecasts for Wattenberg Field proved developed wells due to improved line pressures and an addition of proved undeveloped locations in the Wattenberg Field. +9 +The following table presents our estimated proved developed and undeveloped reserves by category and area: +As of December 31, 2019 +Operating Region/Area +Crude Oil and Condensate (MMBbls) +Natural Gas +(Bcf) +NGLs +(MMBbls) +Crude Oil +Equivalent +(MMBoe) +Percent +Proved developed +Wattenberg Field +47.1 +443.4 +40.7 +161.7 +26 +% +Delaware Basin +19.1 +110.8 +14.7 +52.3 +9 +% +Total proved developed +66.2 +554.2 +55.4 +214.0 +35 +% +Proved undeveloped +Wattenberg Field +94.6 +891.7 +87.2 +330.4 +54 +% +Delaware Basin +36.4 +111.9 +11.4 +66.5 +11 +% +Total proved undeveloped +131.0 +1,003.6 +98.6 +396.9 +65 +% +Total proved reserves +Wattenberg Field +141.7 +1,335.1 +127.9 +492.1 +81 +% +Delaware Basin +55.5 +222.7 +26.1 +118.8 +19 +% +Total proved reserves +197.2 +1,557.8 +154.0 +610.9 +100 +% +Proved Reserves Sensitivity Analysis . We have performed an analysis of our proved reserve estimates as of December 31, 2019 to present sensitivity associated with a lower crude oil price as the value of crude oil influences the value of our proved reserves and PV-10 most significantly. Replacing the 2019 NYMEX price for crude oil used in estimating our reported proved reserves with $50.00 as shown on the table below, and leaving all other parameters unchanged, results in changes to our estimated proved reserves as shown. +Pricing Scenario - NYMEX +Crude Oil (per Bbl) +Natural Gas (per MMBtu) +Proved Reserves (MMBoe) +% Change from December 31, 2019 Estimated Reserves +PV-10 (in Millions) +PV-10 % Change from December 31, 2019 Estimated Reserves +2019 SEC Reserve Report (1) +$ +55.69 +$ +2.58 +610.9 +— +$ +3,837.0 +— +Alternate Price Scenario +$ +50.00 +$ +2.58 +604.6 +(1 +)% +$ +3,201.8 +(17 +)% +(1) +These prices are the SEC NYMEX prices applied to the calculation of the PV-10 value. Such prices have been applied consistently in the alternate pricing scenario to include the impact of adjusting for deductions for any basin differentials, transportation fees, contractual adjustments and Btu adjustments we experienced for the relevant commodity. +Developed and Undeveloped Acreage +The following table presents our developed and undeveloped lease acreage: +As of December 31, 2019 +Developed +Undeveloped +Total +Operating Region/Area +Gross +Net +Gross +Net +Gross +Net +Wattenberg Field (1) (2) +101,400 +95,900 +42,900 +40,600 +144,300 +136,500 +Delaware Basin +28,100 +25,500 +2,400 +300 +30,500 +25,800 +Total acreage +129,500 +121,400 +45,300 +40,900 +174,800 +162,300 +(1) +Of the amounts shown, 78,800 gross (74,200 net) developed lease acres and 23,000 gross (22,100 net) undeveloped lease acres are associated with our approximately 1,600 operated horizontal Wattenberg Field drilling locations targeting the Niobrara or Codell plays. The remaining acres are associated with other zones within the field that we do not currently believe to be economic to develop; therefore, we have not currently identified any potential drilling locations on these acres. +(2) +Amounts do not include approximately 65,000 gross (61,000 net) developed lease acres and 27,000 gross (22,000 net) undeveloped lease acres received in the SRC Acquisition. +10 +Substantially all of our undeveloped acreage in the Wattenberg Field is related to leaseholds that are held by production. Our Wattenberg Field leaseholds at risk to expire in 2020, 2021 and 2022 are not material. In the Delaware Basin, there are drilling obligations or continuous drilling clauses associated with the majority of our acreage. We believe that our current Delaware Basin drilling plan should provide sufficient development to meet these obligations in our core areas over the next few years. In the event that we do not meet the obligations for certain leases, we plan to make any necessary bonus extension payments, changes to our drilling schedule or seek to renew or re-lease the relevant properties. However, we may not be successful in such efforts and may in some cases elect to allow the lease to expire. Our Delaware Basin leaseholds at risk to expire in 2020, 2021 and 2022 are not material. See Item 1A. Risk Factors - Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in substantial lease renewal costs or, if renewal is not feasible, loss of our lease and prospective drilling opportunities. +Drilling Activity. The following tables set forth a summary of our developmental and exploratory well drilling activity for the periods presented. Productive wells consist of wells that were turned-in-line and commenced production during the period, regardless of when drilling was initiated. In-process wells represent wells that are in the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection as of the date shown. We utilize pad drilling operations where multiple wells are developed from the same well pad in both the Wattenberg Field and Delaware Basin. Because we may operate multiple drilling rigs in each operating area, we expect to have in-process wells at any given time. Wells may be in-process for up to a year. +Gross Development Well Drilling Activity +Year Ended December 31, +2019 +2018 +2017 +Operating Region/Area +Productive (1) +In-Process (1) +Non-Productive +Productive +In-Process +Non-Productive (2) +Productive +In-Process +Non-Productive (2) +Wattenberg Field, operated wells +114 +145 +— +139 +133 +— +130 +87 +— +Wattenberg Field, non-operated wells +12 +41 +— +20 +5 +— +12 +14 +1 +Delaware Basin, operated wells +21 +26 +— +26 +22 +1 +9 +10 +— +Delaware Basin, non-operated wells +9 +— +— +11 +— +— +2 +8 +— +Total gross development wells +156 +212 +— +196 +160 +1 +153 +119 +1 +(1 +) +Amounts do not include 82 and 46 gross productive operated and non-operated development wells, respectively, and 88 and seven gross in-process operated and non-operated development wells, respectively, received in the SRC Acquisition. +(2 +) +Represents mechanical failures that resulted in the plugging and abandonment of the well. +Net Development Well Drilling Activity +Year Ended December 31, +2019 +2018 +2017 +Operating Region/Area +Productive (1) +In-Process (1) +Non-Productive +Productive +In-Process +Non-Productive (2) +Productive +In-Process +Non-Productive (2) +Wattenberg Field, operated wells +105.1 +135.0 +— +126.8 +122.4 +— +112.8 +80.1 +— +Wattenberg Field, non-operated wells +1.1 +3.7 +— +2.5 +0.9 +— +1.6 +2.6 +0.1 +Delaware Basin, operated wells +20.1 +25.3 +— +24.5 +16.3 +1.0 +10.1 +9.4 +— +Delaware Basin, non-operated wells +1.3 +— +— +1.2 +— +— +0.4 +1.0 +— +Total net development wells +127.6 +164.0 +— +155.0 +139.6 +1.0 +124.9 +93.1 +0.1 +(1 +) +Amounts do not include 76 and seven net productive operated and non-operated development wells, respectively, and 80 and one net in-process operated and non-operated development wells, respectively, received in the SRC Acquisition. +(2 +) +Represents mechanical failures that resulted in the plugging and abandonment of the well. +11 +Gross Exploratory Well Drilling Activity +Year Ended December 31, +2019 +2018 +2017 +Operating Region/Area +Productive +In-Process +Non-Productive +Productive +In-Process +Non-Productive +Productive +In-Process +Non-Productive +Wattenberg Field, operated wells +— +— +— +— +— +— +— +— +— +Wattenberg Field, non-operated wells +— +— +— +— +— +— +— +— +— +Delaware Basin +2 +4 +— +3 +2 +— +5 +3 +2 +Total gross development wells +2 +4 +— +3 +2 +— +5 +3 +2 +Net Exploratory Well Drilling Activity +Year Ended December 31, +2019 +2018 +2017 +Operating Region/Area +Productive +In-Process +Non-Productive +Productive +In-Process +Non-Productive +Productive +In-Process +Non-Productive +Wattenberg Field, operated wells +— +— +— +— +— +— +— +— +— +Wattenberg Field, non-operated wells +— +— +— +— +— +— +— +— +— +Delaware Basin +2.0 +3.9 +— +2.8 +2.0 +— +3.1 +2.8 +2.0 +Total gross development wells +2.0 +3.9 +— +2.8 +2.0 +— +3.1 +2.8 +2.0 +Title to Properties +We believe that we hold good and defensible leasehold title to substantially all of our crude oil and natural gas properties, in accordance with standards generally accepted in the industry. A preliminary title examination is typically conducted at the time the undeveloped properties are acquired. Prior to the commencement of drilling operations, a title examination is conducted and remedial curative work is performed, as necessary, with respect to discovered defects which we deem to be significant, in order to procure division order title opinions. Title examinations have been performed with respect to substantially all of our producing properties. +The properties we own are subject to royalty, overriding royalty and other outstanding interests. The properties may also be subject to additional burdens, liens or encumbrances customary in the industry, including items such as operating agreements, current taxes, development obligations under crude oil and natural gas leases, farm-out agreements and other restrictions. We do not believe that any of these burdens will materially interfere with our use of the properties. +Substantially all of our crude oil and natural gas properties have been mortgaged or pledged as security for our revolving credit facility. +Governmental Regulation +The U.S. crude oil and natural gas industry is extensively regulated at the federal, state and local levels. The following is a summary of certain laws, rules and regulations currently in force that apply to us. The regulatory environment in which we operate changes frequently and we cannot predict the timing or nature of such changes or their effects on us. +Regulation of Crude Oil and Natural Gas Exploration and Production. Our exploration and production activities are subject to a variety of rules and regulations concerning drilling permits, location, spacing and density of wells, water discharge and disposal, prevention of waste, bonding requirements, surface use and restoration, public health and environmental protection and well plugging and abandonment. The primary state-level regulatory authority regarding these matters in Colorado is the COGCC and the primary authority in Texas is the Texas Railroad Commission. Prior to preparing a surface location and commencing drilling operations on a well, we must procure permits and/or approvals for the various stages of the drilling process from the relevant state and local agencies. In addition, our operations must comply with rules governing the size of drilling and spacing units or proration units and the unitization or pooling of lands and leases. Some states, such as +12 +Colorado, allow the forced pooling or integration of tracts to facilitate exploration while other states, such as Texas, rely primarily or exclusively on voluntary pooling of lands and leases. +In states such as Texas where pooling is primarily or exclusively voluntary, it may be more difficult to form units and therefore to drill and develop our leases in circumstances where we do not own all of the leases in the proposed unit. These risks also exist in Colorado, where a recent rule change has imposed new limits on forced pooling. State laws may also prohibit the venting or flaring of natural gas, which may impact rates of production of crude oil and natural gas from our wells. Leases covering state or federal lands often include additional laws, regulations and conditions which can limit the location, timing and number of wells we can drill and impose other requirements on our operations, all of which can increase our costs. +Regulation of Transportation of Commodities. We move natural gas through pipelines owned by other entities and sell natural gas to other entities that also utilize common carrier pipeline facilities. Natural gas pipeline interstate transmission and storage activities are subject to regulation by the Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act of 1938 ("NGA") and under the Natural Gas Policy Act of 1978 ("NGPA"). Rates and charges for the transportation of natural gas in interstate commerce, and the extension, enlargement or abandonment of jurisdictional facilities, among other things, are subject to regulation. Natural gas pipeline companies hold certificates of public convenience and necessity issued by FERC authorizing ownership and operation of certain pipelines, facilities and properties. +In addition to regulation of natural gas pipeline interstate transmission and storage activities, under the Energy Policy Act of 2005 (the “EPAct 2005”) it is unlawful for “any entity” to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of gas or the purchase or sale of transportation services subject to regulation by FERC. The EPAct 2005 provides FERC with substantial enforcement authority to prohibit such manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. +FERC Order 704 requires that any market participant, including natural gas producers, gatherers and marketers, that engaged in wholesale sales or purchases of natural gas that equaled or exceeded 2.2 MMBtus of physical natural gas in the previous calendar year to report to FERC the aggregate volumes of natural gas produced or sold at wholesale in such calendar year. Order 704 applies only to those transactions that utilize, contribute to or may contribute to the formation of price indices. It is the responsibility of the market participant to determine which individual transactions are to be reported under the guidance of Order 704. Additional information that must be reported includes whether the price in the relevant transaction was reported to any index publisher, and if so, whether such reporting complied with FERC’s policy statement on price reporting. To the extent that we engage in wholesale sales or purchases of natural gas that equal or exceed 2.2 MMBtus of physical natural gas in a calendar year pursuant to transactions utilizing, contributing or having the potential to contribute to the formation of price indices, we may be subject to the reporting requirements of Order 704. +Gathering is exempt from regulation under the NGA, thus allowing gatherers to charge negotiated rates. Gathering lines are, however, subject to state regulation, which includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and rate regulation on a complaint basis. We own certain pipeline facilities in the Delaware Basin that we believe are exempt from regulation under the NGA as “gathering facilities,” but which may in some cases be subject to state regulation. +Although FERC has set forth a general test to determine whether facilities are exempt from regulation under the NGA as “gathering” facilities, FERC’s determinations as to the classification of facilities are performed on a case-by-case basis. With respect to facilities owned by third parties and on which we move natural gas, to the extent that FERC subsequently issues an order reclassifying facilities previously thought to be subject to FERC jurisdiction as non-jurisdictional gathering facilities, and depending on the scope of that decision, our costs of moving natural gas to the point of sale may be increased. Further, to the extent that FERC issues an order reclassifying facilities that we own that were previously thought to be non-jurisdictional gathering facilities as subject to FERC jurisdiction, we could be subject to additional regulatory requirements under the NGA and the NGPA. +Transportation and safety of natural gas is also subject to regulation by the U.S. Department of Transportation, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), under the Natural Gas Pipeline Safety Act of 1968, as amended, which imposes safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities, the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (the “PIPES Act 2006”), and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (the “PIPES Act 2011”). We own certain pipeline facilities in the Delaware Basin that are subject to such regulation by PHMSA. +In addition to natural gas, we move crude oil, condensate and natural gas liquids (collectively, “liquids”) through pipelines owned by other entities and sell such liquids to other entities that also utilize pipeline facilities that may be subject to +13 +regulation by FERC. FERC regulates the rates and terms and conditions of service for the interstate transportation of liquids under the Interstate Commerce Act, as it existed on October 1, 1977 (the “ICA”), and the rules and regulations promulgated thereunder. This includes movements of liquids through any pipelines, including those located solely within one state, that are providing part of the continuous movement of such liquids in interstate commerce for a shipper. The ICA requires that pipelines providing jurisdictional movements maintain a tariff on file with FERC, setting forth established rates and the rules and regulations governing transportation service, which must be “just and reasonable.” The ICA also requires that services be provided in a manner that is not unduly discriminatory or unduly preferential; in some cases, this may result in the proration of capacity among shippers in an equitable manner. +The intrastate transportation of crude oil and NGLs is subject to regulation by state regulatory commissions, which in some cases require the provision of intrastate transportation on a nondiscriminatory basis and the prorationing of capacity on such pipelines under policies set forth in published tariffs. These state-level regulations may also impose certain limitations on the rates that the pipeline owner may charge for transportation. +Transportation of liquids by pipeline is subject to regulation by PHMSA pursuant to the Hazardous Liquids Pipeline Safety Act of 1979, as well as the PIPES Act 2006 and the PIPES Act 2011, which govern the design, installation, testing, construction, operation, replacement and management of liquids pipeline facilities. Liquids that are transported by rail may also be subject to additional regulation by PHMSA. +The availability, terms and cost of transportation affect the amounts we receive for our commodities. Historically, producers were able to flow supplies into interstate pipelines on an interruptible basis; however, recently we have seen an increased need to acquire firm transportation on pipelines in order to avoid curtailments or shut-in gas, which could adversely affect cash flows from the affected area. +Environmental Matters +Our operations are subject to numerous laws and regulations relating to environmental protection. These laws and regulations change frequently, and the effect of these changes is often to impose additional costs or other restrictions on our operations. We cannot predict the occurrence, timing, nature or effect of these changes. We also operate under a number of environmental permits and authorizations. The issuing agencies may take the position that some or all of these permits and authorizations are subject to modification, suspension, or revocation under certain circumstances, but any such action would have to comply with applicable procedures and requirements. +Hazardous Substances and Wastes +We generate wastes that may be subject to the Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. The U.S. Environmental Protection Agency (“EPA”) and various state agencies have adopted requirements that limit the approved disposal methods for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by our operations that are currently exempt from treatment as “hazardous wastes” may in the future be designated as hazardous wastes, and therefore may subject us to more rigorous and costly operating and disposal requirements. In December 2016, the U.S. District Court for the District of Columbia approved a consent decree between the EPA and a coalition of environmental groups. The consent decree requires the EPA to review and determine whether it will revise the RCRA regulations for exploration and production waste to treat such waste as hazardous waste. In April 2019, the EPA, pursuant to the consent decree, determined that revision of the regulations is not necessary. Information comprising the EPA’s review and decision is contained in a document entitled Management of Exploration, Development and Production Wastes: Factors Informing a Decision on the Need for Regulatory Action. The EPA indicated that it will continue to work with states and other organizations to identify areas for continued improvement and to address emerging issues to ensure that exploration, development and production wastes continue to be managed in a manner that is protective of human health and the environment. Environmental groups, however, expressed dissatisfaction with the EPA’s decision and will likely continue to press the issue at the federal and state levels. +We currently own or lease numerous properties that have been used for the exploration and production of crude oil and natural gas for many years. If hydrocarbons or other wastes have been disposed of or released on or under the properties that we own or lease or on or under locations where such wastes have been taken for disposal by us or prior owners or operators of such properties, we could be subject to liability under the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), RCRA and analogous state laws, as well as state laws governing the management of crude oil and natural gas wastes. CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies +14 +that disposed of, transported or arranged for the disposal of the hazardous substances found at the site. Parties who are or were responsible for release of hazardous substances under CERCLA may be subject to full liability for the costs of cleaning up the hazardous substances that have been released into the environment or remediation to prevent future contamination and for damages to natural resources. In addition, under state laws, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. +Hydraulic Fracturing +Hydraulic fracturing is commonly used to stimulate production of crude oil and/or natural gas from dense subsurface rock formations. We consistently utilize hydraulic fracturing in our crude oil and natural gas development programs. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations which are held open by the grains of sand, enabling the crude oil or natural gas to more easily flow to the wellbore. The process is generally subject to regulation by state oil and gas commissions, but is also the subject of various other regulatory initiatives at the federal, state and local levels. +Federal Regulation +Beginning in 2012, the EPA implemented Clean Air Act (“CAA”) standards (New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants) applicable to hydraulically fractured natural gas wells and certain storage vessels. The standards require, among other things, use of reduced emission completions, or “green” completions, to reduce volatile organic compound emissions during well completions as well as new controls applicable to a wide variety of storage tanks and other equipment, including compressors, controllers and dehydrators. +In February 2014, the EPA issued permitting guidance under the Safe Drinking Water Act ("SDWA") for the underground injection of liquids from hydraulically fractured and other wells where diesel is used. Depending upon how it is implemented, this guidance may create duplicative requirements in certain areas, further slow the permitting process in certain areas, increase the costs of operations and result in expanded regulation of hydraulic fracturing activities by the EPA, and may therefore adversely affect even companies, such as us, that do not use diesel fuel in hydraulic fracturing activities. +In May 2014, the EPA issued an advance notice of proposed rulemaking under the Toxic Substances Control Act pursuant to which it will collect extensive information on the chemicals used in hydraulic fracturing fluid, as well as other health-related data, from chemical manufacturers and processors. +The U.S. Department of the Interior, through the Bureau of Land Management (the “BLM”), finalized a rule in 2015 requiring the disclosure of chemicals used, mandating well integrity measures and imposing other requirements relating to hydraulic fracturing on federal lands. The BLM rescinded the rule in December 2017; however, the BLM’s rescission of the rule has been challenged in the United States District Court for the Northern District of California. +In June 2016, the EPA finalized pretreatment standards for indirect discharges of wastewater from the oil and gas extraction industry. The regulation prohibits sending wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned treatment works. +In December 2016, the EPA released a report titled “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources.” The report concluded that activities involved in hydraulic fracturing can have impacts on drinking water under certain circumstances. These and similar studies, depending on their degree of development and nature of results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. +In November 2018, the EPA and the non-profit organization known as the State Review of Oil and Natural Gas Environmental Regulations (“STRONGER”) entered into a Memorandum of Understanding pursuant to which the EPA has affirmed its commitment to meaningful participation in STRONGER’s efforts to develop guidelines for state oil and natural gas environmental regulatory programs, conduct reviews of such programs and publish reports of those reviews. +15 +State Regulation +The states in which we currently operate have adopted or are considering adopting laws and regulations that impose or could impose, among other requirements, stringent permitting or air emission control, chemical disclosure, wastewater disposal, baseline sampling, seismic monitoring, well monitoring and materials handling requirements on hydraulic fracturing and/or well construction and well location requirements and more stringent notification or consultation processes that relate to hydraulic fracturing. Similarly, some states, including Texas, have implemented rules requiring the submission of detailed information related to seismicity in connection with injection well permit applications for the disposal of wastewater. +In 2019, Colorado enacted Senate Bill 19-181 (“SB 19-181”), which changes the mission of the COGCC from fostering responsible and balanced development to regulating development to protect public health and the environment and directs the COGCC to undertake rulemaking on various operational matters including environmental protection, facility siting and wellbore integrity. Pursuant to this direction, in December 2019 the COGCC proposed new regulatory requirements to enhance safety and environmental protection during hydraulic fracturing and to enhance wellbore integrity. +Colorado and Texas require that chemicals used in the hydraulic fracturing of a well be reported in a publicly searchable registry website developed and maintained by the Ground Water Protection Council and Interstate Oil and Gas Compact Commission. +Concerns about hydraulic fracturing have contributed to support for ballot initiatives in Colorado that would dramatically limit the areas of the state in which drilling would be permitted to occur. See Item 1A. Risk Factors-Risks Relating to Our Business and the Industry-Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us. +Local Regulation +Various local and municipal bodies in each of the states in which we operate have sought to impose prohibitions, moratoria and other restrictions on hydraulic fracturing activities. In Colorado, the Colorado Supreme Court ruled in 2016 that the cities of Fort Collins and Longmont did not have the authority to prohibit or impose five-year moratoria on hydraulic fracturing. SB 19-181 gives local governmental authorities increased authority to regulate oil and gas development. The authors of the legislation were clear that SB 19-181 was not intended to allow an outright ban on oil and gas development. However, anti-industry activists in Longmont, Colorado, have argued in court that SB 19-181 permits a local governmental authority to impose such a ban. We primarily operate in the rural areas of the core Wattenberg Field in Weld County, a jurisdiction in which there has historically been significant support for the oil and gas industry. In Texas, legislation enacted in 2015 generally prohibits political subdivisions from banning, limiting or otherwise regulating oil and gas operations. See Item 1A. Risk Factors-Risks Relating to Our Business and the Industry-Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us. +Private Lawsuits +Lawsuits have been filed against other operators in several states, including Colorado, alleging contamination of drinking water as a result of hydraulic fracturing activities. +Greenhouse Gases +The EPA has published findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because such emissions are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings provide the basis for the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. In June 2010, the EPA began regulating GHG emissions from stationary sources. +In the past, Congress has considered proposed legislation to reduce emissions of GHGs. To date, Congress has not adopted any such significant legislation, but could do so in the future. In addition, many states and regions have taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. In February 2014, November 2017 and December 2019, Colorado adopted rules regulating methane emissions from the oil and gas sector. +The Obama administration reached an agreement during the December 2015 United Nations climate change conference in Paris pursuant to which the U.S. initially pledged to make a 26 percent to 28 percent reduction in its GHG +16 +emissions by 2025 against a 2005 baseline and committed to periodically update this pledge every five years starting in 2020 (the "Paris Agreement"). In June 2017, President Trump announced that the U.S. would initiate the formal process to withdraw from the Paris Agreement. In November 2019, the U.S. formally notified the United Nations of its intentions to withdraw from the Paris Agreement. The notification begins a one-year process to complete the withdrawal. +Regulation of methane and other GHG emissions associated with oil and natural gas production could impose significant requirements and costs on our operations. +Air Quality +Our operations are subject to the CAA and comparable state and local requirements. The CAA contains provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and state governments continue to develop regulations to implement these requirements. We may be required to make certain capital investments in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. See the footnote titled Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere in this report for further information regarding the Clean Air Act Section 114 Information Request that we received from the EPA. +In June 2016, the EPA implemented new requirements focused on achieving additional methane and volatile organic compound reductions from the oil and natural gas industry. The rules imposed, among other things, new requirements for leak detection and repair, control requirements for oil well completions, replacement of certain pneumatic pumps and controllers and additional control requirements for gathering, boosting and compressor stations. In September 2018, the EPA proposed revisions to the 2016 rules. The proposed amendments address certain technical issues raised in administrative petitions and include proposed changes to, among other things, the frequency of monitoring for fugitive emissions at well sites and compressor stations. In September 2019, the EPA proposed certain policy amendments to the 2016 rules that would remove all sources in the transmission and storage segment of the oil and natural gas industry from regulation. The proposed amendments would also rescind the methane requirements in the 2016 rules that apply to sources in the production and processing segments of the industry. The EPA is also proposing, in the alternative, to rescind the methane requirements that apply to all sources in the oil and natural gas industry, without removing any sources from the current source category. +In November 2016, the BLM finalized rules to further regulate venting, flaring and leaks during oil and natural gas production activities on onshore federal and Indian leases. The rules require additional controls and impose new emissions and other standards on certain operations on applicable leases, including committed state or private tracts in a federally approved unit or communitized agreement that drains federal minerals. In September 2018, the BLM published a final rule that revises the 2016 rules. The new rule, among other things, rescinds the 2016 rule requirements related to waste-minimization plans, gas-capture percentages, well drilling, well completion and related operations, pneumatic controllers, pneumatic diaphragm pumps, storage vessels and leak detection and repair. The new rule also revised provisions related to venting and flaring. Environmental groups and the States of California and New Mexico have filed challenges to the 2018 rule in the United States District Court for the Northern District of California. +In 2016, the EPA increased the state of Colorado’s non-attainment ozone classification for the Denver Metro North Front Range Ozone Eight-Hour Non-Attainment ("Denver Metro/North Front Range NAA") area from “marginal” to “moderate” under the 2008 national ambient air quality standard (“NAAQS”). This increase in non-attainment status triggered significant additional obligations for the state under the CAA and resulted in Colorado adopting new and more stringent air quality control requirements in November 2017 that are applicable to our operations. In 2019, the EPA increased the state of Colorado’s non-attainment ozone classification for the Denver Metro/North Front Range NAA area from “moderate” to “serious” under the 2008 NAAQS. This “serious” classification will trigger significant additional obligations for the state under the CAA and could result in new and more stringent air quality control requirements, which may in turn result in significant costs, and delays in obtaining necessary permits applicable to our operations. +SB 19-181 also requires, among other things, that the Air Quality Control Commission (“AQCC”) adopt additional rules to minimize emissions of methane and other hydrocarbons and nitrogen oxides from the entire oil and gas fuel cycle. The AQCC anticipates holding several rulemakings over the next several years to implement the requirements of SB 19-181, including a rulemaking to require continuous emission monitoring equipment at oil and gas facilities. In December 2019, the AQCC held the first of several rulemakings that are anticipated as a result of SB 19-181. As part of that rulemaking, the AQCC adopted significant additional and new emission control requirements applicable to oil and gas operations, including, for example, hydrocarbon liquids unloading control requirements and increased LDAR frequencies for facilities in certain proximity to occupied areas. +17 +State-level rules applicable to our operations include regulations imposed by the Colorado Department of Public Health and Environment's ("CDPHE") Air Quality Control Commission, including stringent requirements relating to monitoring, recordkeeping and reporting matters. In October 2019, the CDPHE published a human health risk assessment for oil and gas operations in Colorado, which used oil and gas emission data to model possible human exposure and found a possibility of negative health impacts at distances up to 2,000 feet away under worst case conditions. In response, the COGCC announced that it will more rigorously scrutinize permit applications for wells within 2,000 feet of a building unit, work with CDPHE to obtain better site-specific data on oil and gas emissions, and consider the resulting data for possible future rulemaking. +Water Quality +The federal Clean Water Act (“CWA”) and analogous state laws impose strict controls concerning the discharge of pollutants and fill material, including spills and leaks of crude oil and other substances. The CWA also requires approval and/or permits prior to construction, where construction will disturb certain wetlands or other waters of the U.S. In June 2015, the EPA issued a final rule that attempted to clarify the CWA’s jurisdictional reach over “waters of the United States” (“2015 Clean Water Rule”) and replace the pre-existing 1986 rule and guidance. In February 2018, the EPA issued a rule to delay the applicability of the 2015 Clean Water Rule until February 2020, but this delay rule was struck following a court challenge. Other federal district courts, however, issued rulings temporarily enjoining the applicability of the 2015 Clean Water Rule itself in several states. Taken together, the 2015 Clean Water Rule has been in effect in 22 states, including Colorado, and temporarily stayed in 27 states (the 2015 Clean Water Rule was in effect in certain counties in New Mexico and not in others). In those remaining states, the 1986 rule and guidance remained in effect. In October 2019, the EPA and the USACE issued a final rule to repeal the 2015 Clean Water Rule (the “2019 Repeal Rule”). With the 2019 Repeal Rule, the agencies report that they will implement the pre-2015 Clean Water Rule regulations and guidance nationwide. The 2019 Repeal Rule became effective on December 23, 2019; accordingly, the 2015 Clean Water Rule is no longer in effect in any state. However, numerous legal challenges to the 2019 Repeal Rule have already been filed in federal court. +In February 2019, the EPA and the USACE published a proposed new rule that would differently revise the definition of “waters of the United States” and essentially replace both the 1986 rule and the 2015 Clean Water Rule. On January 23, 2020, the EPA and USACE announced the final new rule, titled the Navigable Waters Protection Rule (“2020 Rule”). The 2020 Rule will go into effect sixty days after publication in the Federal Register. The 2020 Rule will generally regulate four categories of “jurisdictional” waters: (i) territorial seas and traditional navigable waters (i.e., large rivers); (ii) perennial and intermittent tributaries of these waters; (iii) certain lakes, ponds and impoundments; and (iv) wetlands to jurisdictional waters. The 2020 Rule also includes 12 categories of exclusions, or “non-jurisdictional” waters, including groundwater, ephemeral features and diffuse stormwater run-off over upland areas. In particular, the 2020 Rule will likely regulate fewer wetlands areas than were regulated under the 1986 rule and the 2015 Clean Water Rule because it does not regulate wetlands that are not adjacent to jurisdictional waters. Following publication, this new definition of “waters of the United States” will likely be challenged and sought to be enjoined in federal court. If and when the 2020 Rule goes into effect, it will change the scope of the CWA’s jurisdiction, which could result in increased costs and delays with respect to obtaining permits for discharges of pollutants or dredge and fill activities in waters of the U.S., including regulated wetland areas. +In January 2017, the Army Corps of Engineers issued revised and renewed streamlined general nationwide permits that are available to satisfy permitting requirements for certain work in streams, wetlands and other waters of the U.S. under Section 404 of the CWA and the Rivers and Harbors Act. The new nationwide permits took effect in March 2017, or when certified by each state, whichever was later. The oil and gas industry broadly utilizes nationwide permits 12, 14 and 39 for the construction, maintenance and repair of pipelines, roads and drill pads, respectively, and related structures in waters of the U.S. that impact less than a half-acre of waters of the U.S. and meet the other criteria of each nationwide permit. +The CWA also regulates storm water run-off from crude oil and natural gas facilities and requires storm water discharge permits for certain activities. Spill Prevention, Control and Countermeasure (“SPCC”) requirements of the CWA require appropriate secondary containment, load out controls, piping controls, berms and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture or leak. +Endangered Species +The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and bald and golden eagles under the Bald and Golden Eagle Protection Act. Some of our operations may be located in areas that are or may be designated as habitats for endangered or threatened species or that may attract migratory birds, bald eagles or golden eagles. +18 +Other +In October 2015, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration proposed to expand its regulations in a number of ways, including increased regulation of gathering lines, even in rural areas, and proposed additional standards to revise safety regulations applicable to onshore gas transmission and gathering pipelines in 2016. +Crude oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of crude oil spills. In addition to SPCC requirements, the Oil Pollution Act of 1990 (“OPA”) subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from crude oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Historically, we have not experienced any significant crude oil discharge or crude oil spill problems. +In May 2015, the U.S. Department of Transportation issued a final rule regarding the safe transportation of flammable liquids by rail. The final rule imposes certain requirements on “offerors” of crude oil, including sampling, testing and certification requirements. +In February 2018, the COGCC comprehensively amended its regulations for oil, gas and water flowlines to expand requirements addressing flowline registration and safety, integrity management, leak detection and other matters. In November 2019, the COGCC further amended its flowline regulations pursuant to SB 19-181 to impose additional requirements regarding flowline mapping, operational status, certification and abandonment, among other things. The COGCC has also adopted or amended numerous other rules in recent years, including rules relating to safety, flood protection and spill reporting. +We are also subject to rules regarding worker safety and similar matters promulgated by the U.S. Occupational Safety and Health Administration (“OSHA”) and other governmental authorities. OSHA has established workplace safety standards that provide guidelines for maintaining a safe workplace in light of potential hazards, such as employee exposure to hazardous substances. To this end, OSHA adopted a new rule governing employee exposure to silica, including during hydraulic fracturing activities, in March 2016. +Employees +As of December 31, 2019 , we had approximately 540 full-time employees. Our employees are not covered by collective bargaining agreements. We consider relations with our employees to be positive. +WHERE YOU CAN FIND ADDITIONAL INFORMATION +We file annual, quarterly and current reports, proxy statements and other information with the SEC. Our SEC filings are available free of charge from our website at www.pdce.com as soon as reasonably practicable after such material is filed with, or furnished to, the SEC. We also make available free of charge any of our SEC filings by mail. For a mailed copy of a report, please contact PDC Energy, Inc., Investor Relations, 1775 Sherman Street, Suite 3000, Denver, CO 80203, or call (303) 860-5800. +We recommend that you view our website for additional information, as we routinely post information that we believe is important for investors. Our website can be used to access such information as our recent news releases, committee charters, code of business conduct and ethics, stockholder communication policy, director nomination procedures and our whistle blower hotline. While we recommend that you view our website, the information available on our website is not part of this report and is not incorporated by reference. +19 +ITEM 1A. RISK FACTORS +You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as the value of an investment in our common stock or other securities. +Risks Relating to SRC Acquisition +We may not achieve the anticipated benefits of the SRC Acquisition. +The success of the SRC Acquisition will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining our and SRC’s businesses, and there can be no assurance that we will be able to successfully integrate SRC or otherwise realize the anticipated benefits of the SRC Acquisition. Difficulties in integrating SRC into our company may result in the combined company performing differently than expected, in operational challenges or in the failure to realize anticipated expense-related efficiencies. Potential difficulties that may be encountered in the integration process include, among others: +• +the inability to successfully integrate SRC into our company in a manner that permits us to achieve the anticipated benefits and cost savings from the SRC Acquisition; +• +complexities associated with managing a larger, more complex, integrated business; +• +not realizing anticipated operating synergies; +• +integrating personnel from the two companies and the loss of key employees; +• +potential unknown liabilities and unforeseen expenses associated with the SRC Acquisition; +• +integrating relationships with customers, vendors and business partners; +• +performance shortfalls as a result of the diversion of management’s attention caused by the SRC Acquisition and the integration of SRC’s operations into our company; +• +managing expanded environmental and other regulatory compliance obligations related to SRC's facilities and operations; +• +consolidating information technology systems; and +• +the disruption of, or the loss of momentum in, our business or inconsistencies in standards, controls, procedures and policies. +Our results may suffer if we do not effectively manage our expanded operations following the SRC Acquisition. +Following completion of the SRC Acquisition, the size of our business has increased significantly. Our future success will depend, in part, on our ability to manage this expanded business, which poses numerous risks and uncertainties, including the need to integrate the operations and business of SRC into our existing business in an efficient and timely manner, to combine systems and management controls and to integrate relationships with various business partners. Failure to successfully manage the combined company may have an adverse effect on our financial condition, results of operations or cash flows. +Sales of substantial amounts of our common stock in the open market, by former SRC shareholders or otherwise, could depress our stock price. +Former SRC shareholders may not wish to continue to invest in our common stock, or for other reasons may wish to dispose of some or all of their interests in our common stock, and as a result may seek to sell their shares of our common stock. Shares of our common stock that were issued to former holders of SRC common stock in the SRC Acquisition are freely tradable by such stockholders without restrictions or further registration under the Securities Act, provided, however, that any stockholders who are our affiliates will be subject to certain resale restrictions under the Securities Act. These sales (or the perception that these sales may occur), coupled with the increase in the outstanding number of shares of our common stock, may affect the market for, and the market price of, our common stock in an adverse manner. We issued approximately 39 million shares of our common stock to SRC shareholders. As of February 18, 2020 , we had approximately 100 million shares of common stock outstanding and approximately 1.7 million shares of common stock subject to outstanding stock-based compensation arrangements and other rights to purchase or acquire our shares. +If our stockholders, including former SRC shareholders, sell substantial amounts of PDC common stock in the public market, the market price of our common stock may decrease. These sales might also make it more difficult for us to raise capital by selling equity or equity-related securities at a time and price that we otherwise would deem appropriate. +20 +Following the SRC Acquisition, we are proportionately more exposed to regulatory and operational risks associated with oil and gas operations in Colorado and other risks associated with a more geographically-concentrated asset base . +All of SRC’s properties, production and reserves immediately prior to the SRC Acquisition were located in Colorado. As a result of the SRC Acquisition, the percentage of our properties, production and reserves that are located in Colorado have increased and our exposure to the risk of unfavorable regulatory developments in the state have therefore increased as well. Similarly, the operations of both our company and SRC have been adversely affected in recent years by limitations in the availability of adequate midstream infrastructure in the Wattenberg Field. The increased percentage of our combined production located in the Wattenberg Field following the SRC Acquisition has proportionately increased our exposure to this risk, as well as other risks associated with operating in a more concentrated geographic area. +The market price of our common stock will continue to fluctuate, and may decline if the benefits of the SRC Acquisition do not meet the expectations of financial analysts. +The market price of our common stock may fluctuate significantly, including if we do not achieve the anticipated benefits of the SRC Acquisition as rapidly, or to the extent anticipated by, financial analysts or if the effect of the SRC Acquisition on our financial results is not consistent with the expectations of financial analysts. +Risks Relating to Our Business and the Industry +Crude oil, natural gas and NGL prices fluctuate and declines in these prices, or an extended period of low prices, can significantly affect the value of our assets and our financial results and may impede our growth. +Our revenue, profitability, cash flows and liquidity depend in large part upon the prices we receive for our crude oil, natural gas and NGLs. Changes in prices affect many aspects of our business, including: +• +our revenue, profitability and cash flows; +• +our liquidity; +• +the quantity and present value of our reserves; +• +the borrowing base under our revolving credit facility and access to other sources of capital; and +• +the nature and scale of our operations. +The markets for crude oil, natural gas and NGLs are often volatile, and prices may fluctuate in response to, among other things: +• +relatively minor changes in regional, national or global supply and demand; +• +regional, national or global economic conditions, and perceived trends in those conditions; +• +geopolitical factors, such as events that may reduce or increase production from particular oil-producing regions and/or from members of the Organization of Petroleum Exporting Countries ("OPEC"), and global events, such as the ongoing COVID-19 outbreak; and +• +regulatory changes. +The price of oil has historically been volatile, due in recent years to a combination of factors including increased U.S. supply and global economic concerns. In 2019 , oil prices ranged from highs of over $65 per barrel to lows of approximately $45 per barrel. Prices for natural gas and NGLs have also experienced substantial volatility. If we reduce our capital expenditures due to low prices, natural declines in production from our wells will likely result in reduced production and therefore reduced cash flow from operations, which would in turn further limit our ability to make the capital expenditures necessary to replace our reserves and production. +In addition to factors affecting the price of crude oil, natural gas and NGLs generally, the prices we receive for our production are affected by factors specific to us and to the local markets where the production occurs. The prices that we receive for our production are generally lower than the relevant benchmark prices that are used for calculating commodity derivative positions. These differences, or differentials, are difficult to predict and may widen or narrow in the future based on market forces. Differentials can be influenced by, among other things, local or regional supply and demand factors and the terms of our sales contracts. Over the longer term, differentials will be significantly affected by factors such as investment decisions made by providers of midstream facilities and services, refineries and other industry participants and the overall regulatory and economic climate. For example, increases in U.S. domestic oil production generally, or in production from particular basins, may result in widening differentials. We may be materially and adversely impacted by widening differentials on our production and decreasing commodity prices. +21 +The marketability of our production is dependent upon transportation and processing facilities, the capacity and operation of which we do not control. Market conditions or operational impediments affecting midstream facilities and services could hinder our access to crude oil, natural gas and NGL markets, increase our costs or delay production. Our efforts to address midstream issues may not be successful. +Our ability to market our production depends in substantial part on the availability, proximity and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. If adequate midstream facilities and services are not available to us on a timely basis and at acceptable costs, our production and results of operations will be adversely affected. For example, in recent periods, due to ongoing drilling activities by us and third parties and seasonal changes in temperatures, our principal third-party provider in the Wattenberg Field for midstream facilities and services has experienced significantly increased gathering system pressures. The resulting capacity constraints have restricted our production in the area and reduced our revenue. Similarly, rapid production growth in the Permian Basin has strained the available midstream infrastructure there, at times presenting the potential for adverse effects on our operations. The use of alternative forms of transportation for oil production, such as trucks or rail, involves risks, including the risk that increased regulation could lead to increased costs or shortages of trucks or rail-cars. In addition to causing production curtailments, capacity constraints can also reduce the price we receive for the crude oil, natural gas and NGLs we produce. +We rely on third parties to continue to construct additional midstream facilities and related infrastructure to accommodate our growth, and the ability and willingness of those parties to do so is subject to a variety of risks. For example: +• +Decreases in commodity prices in recent years have resulted in reduced investment in midstream facilities by some third parties; +• +Various interest groups have protested the construction of new pipelines, and particularly pipelines near water bodies, in various places throughout the country, and protests have at times physically interrupted pipeline construction activities; +• +Some upstream energy companies have sought to reject volume commitment agreements with midstream providers in bankruptcy proceedings, and the risk that such efforts will succeed, or that upstream energy company counterparties will otherwise be unable or unwilling to satisfy their volume commitments, may have the effect of reducing investment in midstream infrastructure; and +• +The possibility that new or amended regulations, including regulations that increase mandatory setbacks or enhance local control of oil and gas development, could result in severely curtailed drilling activities in Colorado may discourage investment in midstream facilities. +Like other producers, we from time to time enter into volume commitments with midstream providers in order to induce them to provide increased capacity. If our production falls below the level required under these agreements, we could be subject to substantial penalties. +We have pursued a variety of strategies to alleviate some of the risks associated with the midstream services and facilities upon which we rely. There can be no assurance that the strategies we pursue will be successful or adequate to meet our needs. For example, our principal midstream provider in the Wattenberg Field commenced operation of a new facility in the third quarter of 2019 and the benefits to us of that facility were less than we expected. +Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us. +The regulatory environment in which we operate changes frequently, often through the imposition of new or more stringent environmental and other requirements. We cannot predict the nature, timing, cost or effect of such additional requirements, but they may have a variety of adverse effects on us. The types of regulatory changes that could impact our operations vary widely and include, but are not limited to, the following: +• +From time to time ballot initiatives have been proposed in Colorado that would adversely affect our operations. For example, Proposition 112, a voter initiative that qualified for the ballot for the general election in November 2018, would have effectively prohibited the vast majority of our planned drilling activity in Colorado by imposing mandatory 2,500 foot setbacks between new oil and gas wells and any occupied structure or designated "vulnerable area." Although Proposition 112 was defeated at the polls, subsequent legislation significantly amended existing state law to, among other things, require the COGCC to prioritize public health and environmental concerns in its decisions, instruct the COGCC to adopt rules to minimize emissions of methane and other air contaminants, and authorize local governmental authorities to impose limitations on oil and gas development activities more stringent than those imposed at the state level. In October 2019, the CDPHE released a study of potential health risks that modeled certain exposure scenarios at distances up to 2,000 feet, based on +22 +data collected at oil and gas development and production sites. The study concluded that modeling results “support increased concern for short-term adverse effects” in a very narrow set of hypothetical circumstances associated with the development phase of oil and gas operations. As a result, the COGCC has determined that permit applications for locations and wells up to 2,000 feet from building units will be subject to additional agency review to ensure that the application complies with the new legislation. We may therefore experience significant delays in obtaining permits and approvals for some wells and drilling locations. As a result of the SRC Acquisition, the percentage of our combined properties, production and reserves located in Colorado have increased and our exposure to the risk of unfavorable regulatory developments in the state has therefore increased as well. +• +Substantially all of our drilling activities involve the use of hydraulic fracturing, and proposals are made from time to time at the federal, state and local levels to further regulate, or to ban, hydraulic fracturing practices. Additional laws or regulations regarding hydraulic fracturing could, among other things, increase our costs, reduce our inventory of economically viable drilling locations and reduce our reserves. +• +Federal and various state, local and regional governmental authorities have implemented, or considered implementing, regulations that seek to limit or discourage the emission of carbon, methane and other GHGs. For example, the EPA has made findings and issued regulations that require us to establish and report an inventory of greenhouse gas emissions, and the state of Colorado has adopted rules regulating methane emissions from oil and gas operations. In addition, the Obama administration reached an agreement during the December 2015 United Nations climate change conference in Paris pursuant to which the U.S. initially pledged to make a 26 percent to 28 percent reduction in its GHG emissions by 2025 against a 2005 baseline (although President Trump subsequently announced that the U.S. is withdrawing from the Paris Agreement). Additional laws or regulations intended to restrict the emission of GHGs could require us to incur additional operating costs and could adversely affect demand for the oil, natural gas and NGLs that we sell. These new laws or rules could, among other things, require us to install new emission controls on our equipment and facilities, acquire allowances to authorize our GHG emissions, pay taxes related to our emissions and administer and manage a GHG emissions program. In addition, like other energy companies, we could be named as a defendant in GHG-related lawsuits. +• +Proposals are made from time to time to amend U.S. federal and state tax laws in ways that would be adverse to us, including by eliminating certain key U.S. federal income tax preferences currently available with respect to crude oil and natural gas exploration and production. The changes could include (i) the repeal of the percentage depletion deduction for crude oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Also, state severance taxes may increase in the states in which we operate. This could adversely affect our existing operations in the relevant state and the economic viability of future drilling. +• +The development of new environmental initiatives or regulations related to the acquisition, withdrawal, storage and use of surface water or groundwater or treatment and discharge of water waste, may limit our ability to use techniques such as hydraulic fracturing, increase our development and operating costs and cause delays, interruptions or termination of our operations, any of which could have an adverse effect on our operations and financial condition. +See Items 1 and 2, Business and Properties - Governmental Regulation for a summary of certain laws and regulations that currently apply to us. Any of such laws and regulations could be amended, and new laws or regulations could be implemented, in a way that adversely affects our operations. +Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in substantial lease renewal costs or, if renewal is not feasible, loss of our lease and prospective drilling opportunities. +Unless production is established within the spacing units covering our undeveloped acreage, our leases for such acreage will expire. The cost to renew such leases may increase significantly and we may not be able to renew such leases on commercially reasonable terms or at all. Unexpected lease expirations could occur if our actual drilling activities differ materially from our current expectations, and this could result in impairment charges. The risk of lease expiration is greater at times and in areas where the pace of our exploration and development activity slows. Our ability to drill and develop the locations necessary to maintain our leases depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. +23 +A substantial part of our crude oil, natural gas and NGLs production is located in the Wattenberg Field, making us vulnerable to risks associated with operating primarily in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing formations. +Although we have significant leasehold positions in the Delaware Basin in Texas, our current production is primarily located in the Wattenberg Field in Colorado. Because our production is not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including: +• +fluctuations in prices of crude oil, natural gas and NGLs produced from the wells in the area; +• +natural disasters; +• +restrictive governmental regulations; and +• +curtailment of production or interruption in the availability of gathering, processing or transportation infrastructure and services and any resulting delays or interruptions of production from existing or planned new wells. +For example, bottlenecks in processing and transportation that have occurred in some recent periods in the Wattenberg Field have negatively affected our results of operations, and these adverse effects may be disproportionately severe to us compared to our more geographically diverse competitors. Similarly, the concentration of our producing assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules that could adversely affect development activities or production relating to those formations. Such an event could have a material adverse effect on our results of operations and financial condition. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the Wattenberg Field and the Delaware Basin, the demand for, and cost of, drilling rigs, equipment, supplies, chemicals, personnel and oilfield services often increase as well. Shortages or the high cost of drilling rigs, equipment, supplies, chemicals, personnel or oilfield services could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital forecast, which could have a material adverse effect on our business, financial condition or results of operations. All of the producing properties and reserves we acquired in the SRC Acquisition are located in the Wattenberg Field. As a result, the transaction increased the risks we face with respect to the geographic concentration of our properties. +Certain of our properties are subject to land use restrictions, which could limit the manner in which we conduct our business. +Certain of our properties are subject to land use restrictions, including city ordinances, which could limit the manner in which we conduct our business. Such restrictions could affect, among other things, our access to and the permissible uses of our facilities as well as the manner in which we produce oil and natural gas, and may restrict or prohibit drilling in general. The costs we incur to comply with such restrictions may be significant, and we may experience delays or curtailment in the pursuit of development activities and may be precluded from drilling wells in some areas. +We may incur losses as a result of title defects in the properties in which we invest or acquire. +It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform record title examinations before we acquire oil and gas leases and related interests. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property. +24 +We are subject to complex federal, state, local and other laws and regulations that adversely affect the cost and manner of doing business. +Our exploration, development, production and marketing operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning crude oil and natural gas wells and associated facilities. Under these laws and regulations, we could also be liable for personal injuries, property damage and natural resource or other damages, and could be required to change, suspend or terminate operations. Similar to our competitors, we incur substantial operating and capital costs to comply with such laws and regulations. These costs may put us at a competitive disadvantage compared to larger companies in the industry which can more easily capture economies of scale with respect to compliance. A summary of certain laws and regulations that apply to us is set forth in Items 1 and 2 - Business and Properties - Governmental Regulation . +From time to time, we have been subject to sanctions and lawsuits relating to alleged noncompliance with regulatory requirements. For example, in October 2017, in order to settle a lawsuit brought against us by the U.S. Department of Justice, on behalf of the EPA and the State of Colorado, we entered into a consent decree pursuant to which we paid a fine and agreed to implement certain operational changes. The lawsuit claimed that we failed to operate and maintain certain equipment in compliance with applicable law. In addition, as a result of the SRC Acquisition, we are subject to the obligations and requirements of a 2018 Compliance Order on Consent (“COC”) entered into by SRC with CDPHE, applicable to certain SRC oil and gas production facilities. That COC resolved SRC’s alleged violations related to storage tank emissions and contains requirements similar to those contained in our consent decree. The CDPHE has agreed to revise the COC to make the inspection and monitoring requirements, among others, consistent with those contained in our consent decree. This COC will apply only to those facilities formerly subject to the SRC COC. +In May 2019, WildEarth Guardians filed a complaint against several oil and gas operators, including us, in the U.S. District Court for the District of Colorado. The complaint seeks civil penalties and injunctive relief and alleges, among other things, that we failed to obtain a major source air quality permit for two of our production facilities. We have filed a motion to dismiss the complaint. +A major risk inherent in our drilling plans is the possibility that we will be unable to obtain needed drilling permits from relevant governmental authorities in a timely manner. Our ability to obtain the permits needed to pursue our development plans may be impacted by a variety of factors, including opposition by landowners or interest groups. Delays in obtaining regulatory approvals or drilling permits, the failure to obtain a drilling permit for a well, the receipt of a permit with unreasonable or unexpected conditions or costs or the revocation of a previously granted permit, could have a material adverse effect on our ability to explore or develop our properties. +Our ability to produce crude oil, natural gas and NGLs economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of or recycle the water we use at a reasonable cost, in a timely manner and within applicable environmental rules. +Drilling and development activities such as hydraulic fracturing require the use of water and result in the production of wastewater. Our operations could be adversely impacted if we are unable to locate sufficient amounts of water or dispose of or recycle water used in our exploration and production operations. The quantity of water required in certain completion operations, such as hydraulic fracturing, and changing regulations governing usage may lead to water constraints, supply concerns and regulatory issues, particularly in relatively arid climates such as eastern Colorado and western Texas. For example, increased drilling activity in the Delaware Basin in recent years has led to heightened concerns about water supply issues in the area and this may lead to regulatory actions, including rules providing local governments greater authority over water use, that adversely impact our operations. +Our operations depend on being able to reuse or dispose of wastewater in a timely and economic fashion. Wastewater from oil and gas operations is often disposed of through underground injection. Wells in the Delaware Basin typically produce relatively large amounts of water that require disposal and an increased number of earthquakes have been detected in the Delaware Basin in recent years. Some studies have linked earthquakes, or induced seismicity, in certain areas to underground injection, which is leading to increased public and regulatory scrutiny of injection safety. +25 +Reduced commodity prices could result in significant impairment charges and significant downward revisions of proved reserves. +Commodity prices are volatile. Significant and rapid declines in prices have occurred in the past and may occur in the future. Low commodity prices could result in, among other things, significant impairment charges. The cash flow model we use to assess properties for impairment includes numerous assumptions, such as management’s estimates of future oil and gas production and commodity prices, the outlook for forward commodity prices and operating and development costs. All inputs to the cash flow model must be evaluated at each date the estimate of future cash flows for each producing basin is calculated. However, a significant decrease in long-term forward prices alone could result in a significant impairment for our properties that are sensitive to declines in prices. We have incurred impairment charges in a number of recent periods, including charges of $38.5 million and $458.4 million in 2019 and 2018 , respectively, to write down assets. Similar charges could occur in the future. +Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves. +Calculating reserves for crude oil, natural gas and NGLs requires subjective estimates of remaining volumes of underground accumulations of hydrocarbons. Assumptions are also made concerning commodity prices, production levels and operating and development costs over the economic life of the properties. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate. Independent petroleum engineers prepare our estimates of crude oil, natural gas and NGLs reserves using pricing, production, cost, tax and other information that we provide. The reserve estimates are based on assumptions regarding commodity prices, production levels and operating and development costs that may prove to be incorrect. Any significant variance from these assumptions to actual results could greatly affect: +• +the economically recoverable quantities of crude oil, natural gas and NGLs attributable to any particular group of properties; +• +future depreciation, depletion and amortization (“DD&A”) rates and amounts; +• +impairments in the value of our assets; +• +the classifications of reserves based on risk of recovery; +• +estimates of future net cash flows; +• +timing of our capital expenditures; and +• +the amount of funds available for us to borrow under our revolving credit facility. +Some of our reserve estimates must be made with limited production histories, which renders these estimates less reliable than those based on longer production histories. Further, reserve estimates are based on the volumes of crude oil, natural gas and NGLs that are anticipated to be economically recoverable from a given date forward based on economic conditions that exist at that date. The actual quantities of crude oil, natural gas and NGLs recovered will be different than the reserve estimates, in part because they will not be produced under the same economic conditions as are used for the reserve calculations. In addition, quantities of probable and possible reserves by definition are inherently more risky than proved reserves, in part because they have greater uncertainty associated with the recoverable quantities of hydrocarbons. +At December 31, 2019 , approximately 65 percent of our estimated proved reserves were undeveloped. These reserve estimates reflect our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including approximately $3.3 billion during the five years ending December 31, 2024, as estimated in the calculation of our standardized measure of oil and gas activity. The estimated development costs may not be accurate, development may not occur as scheduled and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of initial booking, and we may therefore be required to downgrade any PUDs that are not developed within this five-year time frame. +The present value of the estimated future net cash flows from our proved reserves is not necessarily the same as the current market value of those reserves. Pursuant to SEC rules, the estimated discounted future net cash flows from our proved reserves, and the estimated quantity of those reserves, are based on the prior year’s first day of the month 12-month average crude oil and natural gas index prices. However, factors such as actual prices we receive for crude oil and natural gas and hedging instruments, the amount and timing of actual production, the amount and timing of future development costs, the supply of and demand for crude oil, natural gas and NGLs and changes in governmental regulations or taxation, also affect our actual future net cash flows from our properties. The timing of both our production and incurrence of expenses in connection with the development and production of crude oil and natural gas properties will affect the timing of actual future net cash +26 +flows from proved reserves, and thus their actual present value. In addition, the 10 percent discount factor we use when calculating discounted future net cash flows (the rate required by the SEC) may not be the most appropriate discount factor based on interest rates currently in effect and risks associated with our properties or the industry in general. +Unless reserves are replaced as they are produced, our reserves and production will decline, which would adversely affect our future business, financial condition and results of operations. We may not be able to develop our identified drilling locations as planned. +Producing crude oil, natural gas and NGL reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline may change over time and may exceed our estimates. Our future reserves and production and, therefore, our cash flows and income, are highly dependent on our ability to efficiently develop and exploit our current reserves and to economically find or acquire additional recoverable reserves. We may not be able to develop, discover or acquire additional reserves to replace our current and future production at acceptable costs. Our failure to do so would adversely affect our future operations, financial condition and results of operations. +We have identified a number of well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including: +• +crude oil, natural gas and NGL prices; +• +the availability and cost of capital; +• +drilling and production costs; +• +availability of drilling services and equipment; +• +drilling results; +• +lease expirations or limitations as to depth; +• +midstream constraints; +• +access to and availability of water sourcing and distribution systems; +• +regulatory approvals; and +• +other factors. +Because of these factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce crude oil, natural gas or NGLs from these or any other potential well locations. In addition, the number of drilling locations available to us will depend in part on the spacing of wells in our operating areas. An increase in well density in an area could result in additional locations in that area, but a reduced production performance from the area on a per-well basis. Further, certain of the horizontal wells we intend to drill in the future may require pooling of our lease interests with the interests of third parties. Some states, including Colorado, allow the involuntary pooling of tracts in a relatively broad number of circumstances in order to facilitate exploration, though Colorado now requires applicants to own or secure consent from the owners of more than 45 percent of the minerals to be pooled. Other states, notably Texas, restrict involuntary pooling to a much narrower set of circumstances and consequently these states rely primarily on voluntary pooling of lands and leases. In states such as Texas where pooling is accomplished primarily on a voluntary basis, or in states such as Colorado if we cannot meet the minimum requirement for ownership and consent, it may be more difficult to form units and, therefore, more difficult to fully develop a project if we own less than all (or cannot secure the ownership or consent of the required minimum amount) of the leasehold in the proposed units or one or more of our leases in the proposed units does not provide the necessary pooling authority. If third parties in the proposed units are unwilling to pool their interests with ours, we may be unable to require such pooling on a timely basis or at all, which would limit the total horizontal wells we can drill. Further, the number of available locations will depend in part on the expected lateral lengths of the horizontal wells we drill. Because the intended lateral length of a horizontal well is subject to change for a variety of reasons, our estimated drilling locations will change over time. For this or numerous other reasons, our actual drilling activities may materially differ from those presently identified. +Our inventory of drilling projects includes locations in addition to those that we currently classify as proved, probable and possible. The development of and results from these additional projects are more uncertain than those relating to probable and possible locations, and significantly more uncertain than those relating to proved locations. We have generally accelerated the pace of our development activities in the Wattenberg Field over the past several years, and this has reduced our related inventory of drilling locations. In addition, our Wattenberg Field inventory was further reduced by recent acreage exchange transactions in which we received, among other things, increased working interests in certain locations in exchange for our right to develop other locations. We anticipate that our remaining locations in the field will not, on average, be as productive or as economic as many those we have drilled in recent years, due to lower anticipated overall production or higher gas-to-oil ratios. +27 +In the Delaware Basin, our inventory is subject to, among other things, lease expiration issues and our continued analysis of geologic issues in certain areas. +The wells we drill may not yield crude oil, natural gas or NGLs in commercially viable quantities and productive wells may be less successful than we expect. +A prospect is a property on which our geologists have identified what they believe, based on available information, to be indications of hydrocarbon-bearing rocks. However, given the limitations of available data and technology, our geologists cannot know conclusively prior to drilling and testing whether crude oil, natural gas or NGLs will be present in sufficient quantities to repay drilling or completion costs and generate a profit. Furthermore, even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques do not enable our geologists to be certain as to the quantity of the hydrocarbons in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur greater drilling and testing expenses as a result of such expenditures, which may result in a reduction in our returns. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline. If a well is determined to be dry or uneconomic, which can occur even though it contains some crude oil, natural gas or NGLs, it is classified as a dry hole and must be plugged and abandoned in accordance with applicable regulations. This generally results in the loss of the entire cost of drilling and completion to that point, the cost of plugging and lease costs associated with the prospect. Even wells that are completed and placed into production may not produce sufficient crude oil, natural gas and NGLs to be profitable, or they may be less productive and/or profitable than we expected. For example, the data we use to model anticipated results from wells in a particular area may prove to be not representative of actual results from typical wells in the area, and this could result in production that falls short of estimates reflected in our internal business plans and/or guidance, "type curve" or other disclosures we make to the public. This risk is higher for us in certain areas in the Delaware Basin that have relatively complex geological characteristics and correspondingly greater variability in well results. If we drill a dry hole or unprofitable well on a current or future prospect, or if drilling or completion costs increase, the profitability of our operations will decline and the value of our properties will likely be reduced. Exploratory drilling is typically subject to substantially greater risk than development drilling. In addition, initial results from a well are not necessarily indicative of its performance over a longer period. +Drilling for and producing crude oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations. +Drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling can be unprofitable, not only due to dry holes, but also due to curtailments, delays or cancellations as a result of other factors, including: +• +unusual or unexpected geological formations; +• +pressures; +• +fires; +• +floods; +• +loss of well control; +• +loss of drilling fluid circulation; +• +title problems; +• +facility or equipment malfunctions; +• +unexpected operational events; +• +shortages or delays in the delivery of equipment and services; +• +unanticipated environmental liabilities; +• +compliance with environmental and other governmental requirements; and +• +adverse weather conditions. +Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and regulatory penalties. For example, a loss of containment of hydrocarbons during drilling activities could potentially subject us to civil and/or criminal liability and the possibility of substantial costs, including for environmental remediation. We maintain insurance against various losses and liabilities arising from our operations; however, insurance against certain operational risks may not be available or may be prohibitively expensive relative to the perceived risks presented. For example, we may not have coverage with respect to a pollution event if we are unaware of the event while it is occurring and are therefore unable to report the occurrence of the event to our insurance company within the time frame required under our insurance policy. Thus, losses could occur for uninsurable or uninsured risks or for amounts in excess of existing insurance coverage. The occurrence of an event that is not +28 +fully covered by insurance and/or governmental or third-party responses to an event could have a material adverse effect on our business activities, financial condition and results of operations. We are currently involved in various remedial and investigatory activities at some of our wells and related sites. +In addition, certain technical risks relating to the drilling of horizontal wells - including those relating to our ability to fracture stimulate the planned number of stages and to successfully run casing the length of the well bore - have increased in recent years because we have increased the average lateral length of the horizontal wells we drill. Longer-lateral wells are also typically more expensive and require more time for preparation. In addition, we have transitioned to the use of multi-well pads instead of single-well sites. The use of multi-well pad drilling increases some operational risks because problems affecting the pad or a single well could adversely affect production from all of the wells on the pad. Pad drilling can also make our overall production, and therefore our revenue and cash flows, more volatile, because production from multiple wells on a pad will typically commence simultaneously. While we believe that we will be better served by using multi-well pads with longer lateral wells, the risk component involved in such drilling will be increased in some respects, with the result that we might find it more difficult to achieve economic success in our drilling program. +The inability of one or more of our customers or other counterparties to meet their obligations may adversely affect our financial results. +Substantially all of our accounts receivable result from our crude oil, natural gas and NGLs sales or joint interest billings to a small number of third parties in the energy industry. This concentration of customers and joint interest owners may affect our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our commodity derivatives expose us to credit risk in the event of nonperformance by counterparties. Nonperformance by our customers or derivative counterparties may adversely affect our financial condition and profitability. We face similar risks with respect to our other counterparties, including the lenders under our revolving credit facility and the providers of our insurance coverage. +Seasonal weather conditions and lease stipulations can adversely affect our operations. +Seasonal weather conditions and lease stipulations designed to prohibit or limit operations during crop-growing seasons and to protect wildlife affect operations in some areas. In certain areas drilling and other activities may be restricted or prohibited by lease stipulations, or prevented by weather conditions, for significant periods of time. This limits our operations in those areas and can intensify competition during the active months for drilling rigs, equipment, supplies, chemicals, personnel and oilfield services, which may lead to additional or increased costs or periodic shortages. These constraints, and the resulting high costs or shortages, could delay our operations and materially increase operating and capital costs and therefore adversely affect our profitability. Similarly, extreme temperatures during some recent periods adversely impacted the operation of certain midstream facilities, and therefore our production. Similar events could occur in the future and could negatively impact our results of operations and cash flows. +We have limited control over activities on properties in which we own an interest but we do not operate, which could reduce our production and revenues. +Including wells that we received in the SRC Acquisition, we currently operate approximately 78 percent of all the wells in which we have an interest. If we do not operate a property, we do not have control over normal operating procedures, expenditures or future development of the property. The success and timing of drilling and development activities on properties operated by others therefore depends upon a number of factors outside of our control, including the operator’s timing and amount of capital expenditures, expertise (including safety and environmental compliance) and financial resources, inclusion of other participants in drilling wells and use of technology. The failure of an operator to conduct drilling activities properly, or its breach of the applicable agreements, could reduce production and revenues and adversely affect our profitability. These risks may be heightened during periods of depressed commodity prices as operators may propose activities that we believe to be economically unattractive, leading us to incur non-consent penalties. Our lack of control over non-operated properties also makes it more difficult for us to forecast capital expenditures, production and related matters. +We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects. +We frequently own less than all of the working interest in the oil and gas leases on which we conduct operations. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities, arising from the actions of the other owners. In addition, declines in oil, natural gas and NGL prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, may declare bankruptcy. In the event any of our project partners does not pay its share of such costs, +29 +we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover the costs from the partner. This could materially adversely affect our financial position. +We may not be able to keep pace with technological developments in our industry. +Our industry is characterized by rapid and significant technological advancements. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those or other new technologies at substantial cost. In addition, our competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we were unable to use the most advanced technology, our business, financial condition and results of operations could be materially adversely affected. +Competition in our industry is intense, which may adversely affect our ability to succeed. +Our industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce crude oil, natural gas and NGLs, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, larger companies may have a greater ability to continue exploration activities during periods of low commodity prices. Larger competitors may also be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which could adversely affect our competitive position. These factors could adversely affect our operations and our profitability. +Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel. +Our future success depends to a large extent on the services of our key employees. The loss of one or more of these individuals could have a material adverse effect on our business. Uncertainties created by the SRC Acquisition may make it more challenging for us to retain some employees. Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise. +A failure to complete successful acquisitions would limit our growth. +Because our crude oil and natural gas properties are depleting assets, our future reserves, production volumes and cash flows depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. In addition, we continue to strive to achieve greater efficiencies in our drilling program, and our ability to do so is dependent in part on our ability to complete asset exchanges and other acquisitions that allow us to increase our working interests in particular properties. When attractive opportunities arise, acquiring additional crude oil and natural gas properties, or businesses that own or operate such properties, is a significant component of our strategy. We may not be able to identify attractive acquisition opportunities. If we do identify an appropriate acquisition candidate, we may be unable to negotiate mutually acceptable terms with the seller, finance the acquisition or obtain the necessary regulatory approvals. It may be difficult to agree on the economic terms of a transaction, as a potential seller may be unwilling to accept a price that we believe to be appropriately reflective of prevailing economic conditions. If we are unable to complete suitable acquisitions, it will be more difficult to replace our reserves, and an inability to replace our reserves would have a material adverse effect on our financial condition and results of operations. +Acquisitions of properties are subject to the uncertainties of evaluating recoverable reserves and potential liabilities, including environmental uncertainties. +Acquisitions of producing and undeveloped properties, including the SRC Acquisition, have been an important part of our growth over time. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, development potential, future commodity prices, operating costs, title issues and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we generally perform engineering, environmental, geological and geophysical reviews of the acquired properties that we believe are generally consistent with customary industry practices. However, such reviews are not likely to permit us to become sufficiently +30 +familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well prior to an acquisition and our ability to evaluate undeveloped acreage is inherently imprecise. Even when we inspect a well, we may not always discover structural, subsurface and environmental problems that may exist or arise. In some cases, our review prior to signing a definitive purchase agreement may be even more limited. In addition, we often acquire acreage without any warranty of title except as to claims made by, through or under the transferor. +When we acquire properties, we will generally have potential exposure to liabilities and costs for environmental and other problems existing on the acquired properties, and these liabilities may exceed our estimates. We may not be entitled to contractual indemnification associated with acquired properties. We often acquire interests in properties on an “as is” basis with no or limited remedies for breaches of representations and warranties. Therefore, we could incur significant unknown liabilities, including environmental liabilities or losses due to title defects, in connection with acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, the acquisition of undeveloped acreage is subject to many inherent risks and we may not be able to realize efficiently, or at all, the assumed or expected economic benefits of acreage that we acquire. +Additionally, significant acquisitions can change the nature of our operations depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or may be in different geographic locations than our existing properties. These factors can increase the risks associated with an acquisition. Acquisitions also present risks associated with the additional indebtedness that may be required to finance the purchase price and any related increase in interest expense or other related charges. +The SRC Acquisition presents a number of the foregoing risks - for example, because closing has occurred, we will have no recourse if we subsequently discover unanticipated liabilities or other problems with the properties we acquired in the transaction. In addition, those risks are greater than they were in the case of most of our previous acquisitions given the larger size of the SRC Acquisition. +Some of our acquisitions are structured as asset trades or exchanges. These transactions may give rise to any or all of the foregoing risks. In addition, transactions of this type create a risk that we will undervalue the properties we transfer to the counterparty in the trade or exchange or overvalue the properties we receive. Such an undervaluation or overvaluation would result in the transaction being less favorable to us than we expected. +Complications with the design of our new enterprise resource planning system could adversely impact our business and operations. +We rely extensively on information systems and technology to manage our business and summarize operating results. We implemented a new Enterprise Resource Planning ("ERP") system at the beginning of 2020 to replace our existing operating and financial systems. The ERP system is designed to enhance the maintenance of our financial records, improve operational functionality and provide timely information to our management team related to the operation of the business. The ERP system implementation process has required, and will continue to require, the investment of significant personnel and financial resources. We may not be able to continue to successfully implement the ERP system without experiencing delays, increased costs and other difficulties. If we are unable to successfully manage the new ERP system as planned, our financial position, results of operations and cash flows could be negatively impacted. Additionally, if we do not effectively manage the ERP system as planned or the ERP system does not operate as intended, the effectiveness of our internal control over financial reporting could be adversely affected or our ability to assess those controls adequately could be delayed. +We operate in a litigious environment. The cost of defending any suits brought against us, and any judgments or settlements resulting from such suits, could have an adverse effect on our results of operations and financial condition. +Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, employment litigation, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. For example, in recent years, we have been subject to lawsuits regarding royalty practices and payments, matters relating to certain of our affiliated partnerships and our environmental compliance programs. The outcome of legal proceedings is inherently uncertain. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management attention and other factors. In addition, the resolution of such a proceeding could result in penalties or sanctions, settlement costs and/or judgments, consent decrees or orders requiring a change in our business practices, any of which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties, sanctions or costs may be insufficient. Judgments and estimates to determine accruals or the anticipated range of potential losses related to legal and other proceedings could change from one period to the next, and such changes could be material. Information regarding legal proceedings can found in the +31 +footnote titled Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere in this report. +Our business could be negatively impacted by security threats, including cybersecurity threats and other disruptions. +We face various security threats, including attempts by third parties to gain unauthorized access to competitive information or to render data or systems unusable; threats to the safety of our employees; threats to the security of our infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. There can be no assurance that the procedures and controls we use to monitor these threats and mitigate our exposure to them will be sufficient to prevent them from materializing. +Our industry has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain exploration, development and production activities. We depend on digital technology, including information systems and related infrastructure, as well as cloud applications and services, to store, transmit, process and record sensitive information (including but not limited to trade secrets, employee information and financial and operating data), communicate with our employees and business partners, and for many other activities related to our business. In addition, computer systems control the oil and gas production and processing equipment that are necessary to deliver our production to market. A disruption or failure of these systems, or of the networks and infrastructure on which they rely, may cause damage to critical production, distribution and/or storage assets, delay or prevent delivery to markets, or make it difficult to accurately account for production and settle transactions. +As dependence on digital technologies has increased in our industry, cyber incidents, including deliberate attacks and unintentional events, have also increased. Our systems and infrastructure are subject to damage or interruption from a number of potential sources including natural disasters, software viruses or other malware, power failures, cyber-attacks and other events. We also face various other cyber-security threats from criminal hackers, state-sponsored intrusion, industrial espionage and employee malfeasance, including threats to gain access to sensitive information or to render data or systems unusable. +Our business partners, including vendors, service providers, operating partners, purchasers of our production and financial institutions, are also dependent on digital technology. A vulnerability in the cybersecurity of one or more of our vendors could facilitate an attack on our systems. +Our technologies, systems and networks, and those of our business partners, may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, theft of property or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Although we have not suffered material losses related to cyber-attacks to date, if we were successfully attacked, we could incur substantial remediation and other costs or suffer other negative consequences, such as a loss of competitive information, critical infrastructure, personnel or capabilities essential to our operations. Events of this nature could have a material adverse effect on our reputation, financial condition, results of operations or cash flows. Moreover, as the sophistication of cyber-attacks continues to evolve, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities. +The physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. +Many scientists believe that increasing concentrations of carbon dioxide, methane and other GHGs in the Earth's atmosphere are changing global climate patterns. One consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such events were to occur, or become more frequent, our operations could be adversely affected in various ways, including through damage to our facilities or from increased costs for insurance. +Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. Despite the use of the term “global warming” as a shorthand for climate change, some studies indicate that climate change could cause some areas to experience temperatures substantially colder than their historical averages. As a result, it is difficult to predict how the market for our production could be affected by increased temperature volatility, although if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business. +32 +Risks Relating to Financial Matters +Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our production and reserves, and ultimately our profitability. +Our industry is capital intensive. We expect to continue to make substantial capital expenditures for the exploration, development, production and acquisition of crude oil, natural gas and NGL reserves. To date, we have financed capital expenditures primarily with bank borrowings under our revolving credit facility, cash generated by operations and proceeds from capital markets transactions and the sale of properties. We intend to finance our future capital expenditures utilizing similar financing sources. Our cash flows from operations and access to capital are subject to a number of variables, including: +• +our proved reserves; +• +the amount of crude oil, natural gas and NGLs we are able to produce from existing wells; +• +the prices at which crude oil, natural gas and NGLs are sold; +• +the costs to produce crude oil, natural gas and NGLs; and +• +our ability to acquire, locate and produce new reserves. +If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower commodity prices, operating difficulties or for any other reason, our need for capital from other sources could increase, and there can be no assurance that such other sources of capital would be available at that time on reasonable terms or at all. If we raise funds by issuing additional equity securities, this would have a dilutive effect on existing shareholders. If we raise funds through the incurrence of debt, the risks we face with respect to our indebtedness would increase and we would incur additional interest expense. Our inability to obtain sufficient financing on acceptable terms would adversely affect our financial condition and profitability. +We have a substantial amount of debt and the cost of servicing, and risks related to refinancing, that debt could adversely affect our business. Those risks could increase if we incur more debt. +We have a substantial amount of indebtedness outstanding, and have recently increased our indebtedness as part of the SRC Acquisition, including through the assumption of $550 million aggregate principal amount of 6.25% Senior Notes issued by SRC due December 2025 (the “SRC Senior Notes”). On January 17, 2020, we commenced an offer to repurchase the SRC Senior Notes at 101 percent of the principal amount of the notes, together with any accrued and unpaid interest to the date of purchase. If the SRC Senior notes are tendered to us in full or in part, a significant portion of our liquidity would be required to pay interest and principal on our indebtedness, and we may not generate sufficient cash flows from operations, or have future borrowing capacity available, to enable us to repay our indebtedness or to fund other liquidity needs. +Servicing our indebtedness and satisfying our other obligations will require a significant amount of cash. Our cash flow from operating activities and other sources may not be sufficient to fund our liquidity needs. Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend on our future operating performance, our financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control. We cannot assure you that our business will generate sufficient cash flow from operations, or that sufficient future borrowings will be available to us under our revolving credit facility or otherwise, to fund our liquidity needs. +A substantial decrease in our operating cash flow or an increase in our expenses could make it difficult for us to meet debt service requirements and could require us to modify our operations, including by curtailing our exploration and drilling programs, selling assets, reducing our capital expenditures, refinancing all or a portion of our existing debt or obtaining additional financing. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. In addition, the terms of our debt agreements could restrict us from implementing some of these alternatives. +In the absence of adequate cash from operations and other available capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. We may not be able to consummate these dispositions for fair market value, in a timely manner or at all. Furthermore, any proceeds that we could realize from any dispositions may not be adequate to meet our debt service obligations then due. +33 +Covenants in our debt agreements currently impose, and future financing agreements may impose, significant operating and financial restrictions. +Our current debt agreements contain restrictions, and future financing agreements may contain additional restrictions, on our activities, including covenants that restrict our and our restricted subsidiaries’ ability to: +• +incur additional debt; +• +pay dividends on, redeem or repurchase stock; +• +create liens; +• +make specified types of investments; +• +apply net proceeds from certain asset sales; +• +engage in transactions with our affiliates; +• +engage in sale and leaseback transactions; +• +merge or consolidate; +• +restrict dividends or other payments from restricted subsidiaries; +• +sell equity interests of restricted subsidiaries; and +• +sell, assign, transfer, lease, convey or dispose of assets. +Our revolving credit facility is secured by substantially all of our oil and gas properties as well as a pledge of all ownership interests in our operating subsidiaries. The restrictions contained in our debt agreements may prevent us from taking actions that we believe would be in the best interest of our business, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. We may also incur future debt obligations that subject us to additional restrictive covenants. +Our revolving credit facility has substantial restrictions and financial covenants and our ability to comply with those restrictions and covenants is uncertain. Our lenders can unilaterally reduce our borrowing availability based on anticipated commodity prices. +We expect to depend on our revolving credit facility for part of our future capital needs. The terms of the credit agreement require us to comply with certain financial covenants. Our ability to comply with these covenants in the future is uncertain and will be affected by the levels of cash flows from operations and events or circumstances beyond our control. Our failure to comply with any of the restrictions and covenants under the revolving credit facility or other debt agreements could result in a default under those agreements, which could cause all of our existing indebtedness to become immediately due and payable. +The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based upon projected revenues from the properties securing their loan. Decreases in the price of crude oil, natural gas or NGLs can be expected to have an adverse effect on the borrowing base. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Outstanding borrowings in excess of the borrowing base must be repaid immediately unless we pledge other crude oil and natural gas properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility. Our inability to borrow additional funds under our revolving credit facility could adversely affect our operations and our financial results. +If we are unable to comply with the restrictions and covenants in our debt agreements, the resulting default could lead to an acceleration of payment of funds that we have borrowed and we may not have or be able to obtain the funds necessary to repay those amounts. +Any default under the agreements governing our indebtedness, including a default under our revolving credit facility that is not waived by the required lenders, and the remedies sought by the holders of any such indebtedness, could make us unable to pay principal and interest on our indebtedness and satisfy our other obligations. If we are unable to generate sufficient cash flows and are otherwise unable to obtain the funds necessary to meet required payments of principal and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. In the event of such a default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our revolving credit facility could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation. In addition, the default could result in a cross-default under other debt agreements. If our operating performance declines, we may in the future need to seek waivers from the required lenders under our revolving +34 +credit facility to avoid being in default and we may not be able to obtain such a waiver. If this occurs and no waiver is obtained, we would be in default under our revolving credit facility, the lenders could exercise their rights as described above, and we could be forced into bankruptcy or liquidation. We cannot assure you that we will be granted waivers or amendments to our debt agreements if for any reason we are unable to comply with these agreements, or that we will be able to refinance our debt on terms acceptable to us, or at all. +Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly. +Borrowings under our revolving credit facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase, our debt service obligations on the variable rate indebtedness would increase although the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness and for other purposes would decrease. +We may be adversely affected by the phaseout of the London Interbank Offered Rate ("LIBOR") or the replacement of LIBOR with a different reference rate. +On July 27, 2017, the Financial Conduct Authority (the authority that regulates LIBOR) announced that it would phase out LIBOR by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021, or if alternative rates or benchmarks will be adopted. Changes in the method of calculating LIBOR, or the replacement of LIBOR with an alternative rate or benchmark, may adversely affect interest rates and result in higher borrowing costs. This could materially and adversely affect our results of operations, cash flows and liquidity. We cannot predict the effect of the potential changes to LIBOR or the establishment and use of alternative rates or benchmarks. If LIBOR becomes unavailable, our revolving credit facility requires us to work with the administrative agent to establish an alternate rate of interest and amend our credit agreement to reflect that new rate of interest, and until any such amendment is effective, all loans outstanding under the credit facility will be priced at the alternate base rate set forth in the credit agreement. We will continue to monitor the phaseout of LIBOR and if changes are made to the method of calculating LIBOR or LIBOR ceases to exist, we may also need to amend certain other contracts and cannot predict what alternative rate or benchmark would be negotiated. The phaseout of LIBOR and any amendments to our credit facility or other contracts may result in an increase to our interest expense. In addition, the discontinuance of LIBOR could also cause disruptions to the credit or derivatives markets that would be harmful to our business. +Notwithstanding our current indebtedness levels and restrictive covenants, we may still be able to incur substantial additional debt, which could exacerbate the risks described above. +We may be able to incur additional debt in the future. Although our debt agreements contain restrictions on our ability to incur indebtedness, those restrictions are subject to a number of exceptions. In particular, we may borrow under the revolving credit facility. We may also consider investments in joint ventures or acquisitions that may increase our indebtedness. Adding new debt to current debt levels could intensify the related risks that we and our subsidiaries now face. +Under the “successful efforts” accounting method that we use, unsuccessful exploratory wells must be expensed in the period in which they are determined to be non-productive, which reduces our net income in such periods. +We conduct exploratory drilling in order to identify additional opportunities for future development. Under the “successful efforts” method of accounting that we use, the cost of unsuccessful exploratory wells must be charged to expense in the period in which the wells are determined to be unsuccessful. In addition, lease costs for acreage condemned by the unsuccessful well must also be expensed. In contrast, unsuccessful development wells are capitalized as a part of the investment in the field where they are located. The costs of unsuccessful exploratory wells could result in a significant reduction in our profitability in periods in which the costs are required to be expensed. +Our commodity derivative activities could result in financial losses or reduced income from failure to perform by our counterparties, could limit our potential gains from increases in prices and could result in volatility in our net income. +We use commodity derivatives for a portion of the production from our own wells and for natural gas purchases and sales by our marketing subsidiary to achieve more predictable cash flows, to reduce exposure to adverse fluctuations in commodity prices, and to allow our natural gas marketing company to offer pricing options to natural gas sellers and purchasers. These arrangements expose us to the risk of financial loss in some circumstances, including when purchases or sales are different than expected or the counterparty to the commodity derivative contract defaults on its contractual obligations. In addition, many of our commodity derivative contracts are based on WTI or another crude oil or natural gas index price. The risk that the differential between the index price and the price we receive for the relevant production may change unexpectedly +35 +makes it more difficult to hedge effectively and increases the risk of a hedging-related loss. Also, commodity derivative arrangements may limit the benefit we would otherwise receive from increases in the prices for the relevant commodity. +At December 31, 2019 , we had hedged a total of 10.8 MMBbls and 3.2 MMBbls of crude oil through 2020 and 2021, respectively, and 4.0 Bcf of natural gas through 2020. Additionally, we assumed hedges covering 3.9 MMBbls of crude oil through 2020 in the SRC Acquisition. These hedges may be inadequate to protect us from continuing and prolonged declines in crude oil and natural gas prices. +Since we do not designate our commodity derivatives as cash flow hedges, we do not currently qualify for use of hedge accounting; therefore, changes in the fair value of commodity derivatives are recorded in our income statements and our net income is subject to greater volatility than it would be if our commodity derivative instruments qualified for hedge accounting. For instance, if commodity prices rise significantly, this could result in significant non-cash charges during the relevant period, which could have a material negative effect on our net income. +Our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur. +The occurrence of a significant accident or other event that is not fully covered by insurance, not properly or timely noticed to our carrier, or that is in excess of our insurance coverage, could have a material adverse effect on our operations and financial condition. Insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. In addition, pollution and environmental risks are generally not fully insurable. The cost of obtaining insurance has increased as a result of the SRC Acquisition because of our asset base. +The price of our common stock has been and may continue to be highly volatile, which may make it difficult for shareholders to sell our common stock when desired or at attractive prices. +The market price of our common stock is highly volatile and we expect it to continue to be volatile for the foreseeable future. Adverse events could trigger declines in the price of our common stock, including, among others: +• +changes in production volumes, worldwide demand and prices for crude oil and natural gas; +• +inability to hedge future production at the same pricing level as our current or prior hedges; +• +changes in securities analysts’ estimates of our financial performance; +• +fluctuations in stock market prices and volumes, particularly among securities of energy companies; +• +changes in market valuations and valuation multiples of similar companies; +• +changes in interest rates; +• +announcements regarding adverse timing or lack of success in discovering, acquiring, developing and producing crude oil and natural gas resources; +• +announcements by us or our competitors of significant contracts, new acquisitions, discoveries, commercial relationships, joint ventures or capital commitments; +• +decreases in the amount of capital available to us, including as a result of borrowing base reductions and/or lenders ceasing to participate in our revolving credit facility syndicate; +• +operating results that fall below market expectations or variations in our quarterly operating results; +• +loss of a major customer; +• +loss of a relationship with a partner; +• +regulatory developments +• +the occurrence and severity of environmental events and governmental and other third-party responses to the events; or +• +additions or departures of key personnel. +External events, such as news concerning economic conditions, counterparties to our natural gas or crude oil derivatives arrangements, changes in government regulations impacting the crude oil and natural gas exploration and production industry or the movement of capital into or out of our industry, are also likely to affect the price of our common stock, regardless of our operating performance. For example, there have been recent efforts by some investment advisers, sovereign wealth funds, public pension funds, universities and other investment groups to divest themselves from investments in companies involved in fossil fuel extraction, and these efforts could reduce the trading prices of our securities. Similarly, our stock price could be adversely affected by changes in the way that analysts and investors assess the geological and economic characteristics of the basins in which we operate or the upstream industry in general. Furthermore, general market conditions, including the level of, and fluctuations in, the trading prices of stocks generally could affect the price of our common stock. The stock markets regularly experience price and volume volatility that affects many companies’ stock prices without regard to the +36 +operating performance of those companies. Volatility of this type may affect the trading price of our common stock. Similar factors could also affect the trading prices of our senior notes. +Our certificate of incorporation, bylaws and Delaware law contain provisions that may have an anti-takeover effect and may delay, defer or prevent a tender offer or takeover attempt, which may adversely affect the market price of our common stock. +Our certificate of incorporation and bylaws, and certain provisions of Delaware law, may have anti-takeover effects. +For example, our certificate of incorporation authorizes our board of directors (the "Board") to issue preferred stock without shareholder approval. If our Board elects to issue preferred stock, it could be more difficult for a third party to acquire us, including in circumstances where the acquisition is supported by the holders of a majority of our stock. In addition, other provisions of our certificate of incorporation, bylaws and Delaware law could make it more difficult for a third party to acquire control of us against the wishes of our Board, including: +• +the organization of our Board as a classified board, which provides that approximately one-third of our directors are subject to election each year; +• +bylaw provisions that require advance notice of some types of shareholder proposals; and +• +Delaware law provisions which prohibit us from engaging in any business combination with any "interested stockholder," meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met. +In addition, shareholder activism in our industry has been increasing. If we are unable to work productively with activist or other shareholders, any resulting disagreements or disputes could require substantial management time and attention and could adversely affect our results of operations. +Derivatives legislation and regulation could adversely affect our ability to hedge crude oil and natural gas prices and increase our costs and adversely affect our profitability. +In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) was enacted into law. The Dodd-Frank Act regulates derivative transactions, including our commodity hedging swaps, and could have a number of adverse effects on us, including the following: +• +The Dodd-Frank Act may limit our ability to enter into hedging transactions, thus exposing us to additional risks related to commodity price volatility; commodity price decreases would then have an increased adverse effect on our profitability and revenues. Reduced hedging may also impair our ability to have certainty with respect to a portion of our cash flows, which could lead to decreases in capital spending and, therefore, decreases in future production and reserves. +• +If, as a result of the Dodd-Frank Act or its implementing regulations, we are required to post cash collateral in connection with our derivative positions, this would likely make it impracticable to implement our current hedging strategy. +The above factors could also affect the pricing of derivatives and make it more difficult for us to enter into hedging transactions on favorable terms. +ITEM 1B. UNRESOLVED STAFF COMMENTS +None. +ITEM 3. LEGAL PROCEEDINGS +Information regarding our legal proceedings can found in the footnote titled Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere in this report. +ITEM 4. MINE SAFETY DISCLOSURES +Not applicable. +37 +PART II +ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDERS MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Our common stock, par value $0.01 per share, is traded on the NASDAQ Global Select Market under the symbol PDCE. +As of February 18, 2020 , we had approximately 433 stockholders of record. Since inception, no cash dividends have been declared on our common stock. Cash dividends are restricted under the terms of our revolving credit facility, as well as the indentures governing our 6.125% senior notes due September 15, 2024 (the "2024 Senior Notes"), our 5.75% senior notes due May 15, 2026 (the "2026 Senior Notes") and the SRC Senior Notes. +The following table presents information about our purchases of our common stock during the three months ended December 31, 2019 : +Period +Total Number of Shares Purchased (1) +Average Price Paid per Share +Total Number +of Shares +Purchased as +Part of Publicly +Announced Plans +or Programs (2) +Approximate Dollar Value of Shares That May +Yet Be Purchased +Under the Plans +or Programs (in millions) (3) +October 1 - 31, 2019 +346,080 +$ +26.02 +341,423 +$ +45.6 +November 1 - 30, 2019 +— +— +— +— +December 1 - 31, 2019 +173 +23.87 +— +— +Total fourth quarter 2019 purchases +346,253 +26.02 +341,423 +$ +45.6 +(1) +Certain purchases represent shares withheld from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans. The withheld shares are not issued or considered common stock repurchased under the Stock Repurchase Program described in the footnote titled Common Stock to our accompanying consolidated financial statements included elsewhere in this report. +(2) +In April 2019, the Board approved a program to acquire up to $200 million of our outstanding common stock and in August 2019, effective with the closing of the SRC Acquisition, increased such amount to $525 million. The Stock Repurchase Program does not require any specific number of shares to be acquired, and can be modified or discontinued by the Board at any time. +(3) +Subsequent to December 31, 2019 , we repurchased $12.5 million of our outstanding common stock as part of the Stock Repurchase Program. As of February 24, 2020 , $358.2 million of our outstanding common stock remained available for repurchase under the Stock Repurchase Program. +38 +STOCKHOLDER PERFORMANCE GRAPH +The performance graph below compares the cumulative total return of our common stock over the five-year period ended December 31, 2019 with the cumulative total returns for the same period for the Standard and Poor's ("S&P") 500 Index and the Standard Industrial Code ("SIC") Index. The SIC Index is a weighted composite of 233 crude petroleum and natural gas companies. The cumulative total stockholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on December 31, 2014 , and in the S&P 500 Index and the SIC Index on the same date. The results shown in the graph below are not necessarily indicative of future performance. +39 +ITEM 6. SELECTED FINANCIAL DATA +Year Ended/As of December 31, +2019 +2018 +2017 +2016 (1) +2015 +(in millions, except per share data and as noted) +Statement of Operations: +Crude oil, natural gas and NGLs sales +$ +1,307.3 +$ +1,390.0 +$ +913.1 +$ +497.4 +$ +378.7 +Commodity price risk management gain (loss), net +(162.8 +) +145.2 +(3.9 +) +(125.7 +) +203.2 +Total revenues +1,156.1 +1,548.7 +921.6 +382.9 +595.3 +Net income (loss) +(56.7 +) +2.0 +(127.5 +) +(245.9 +) +(68.3 +) +Earnings per share: +Basic +$ +(0.89 +) +$ +0.03 +$ +(1.94 +) +$ +(5.01 +) +$ +(1.74 +) +Diluted +(0.89 +) +0.03 +(1.94 +) +(5.01 +) +(1.74 +) +Statement of Cash Flows: +Net cash flows from: +Operating activities +$ +858.2 +$ +889.3 +$ +597.8 +$ +486.3 +$ +411.1 +Investing activities +(677.8 +) +(1,087.9 +) +(717.0 +) +(1,509.1 +) +(604.3 +) +Financing activities +(188.9 +) +18.1 +65.0 +1,266.1 +178.0 +Capital expenditures for development of crude oil and natural gas properties (2) +(855.9 +) +(946.4 +) +(737.2 +) +(436.9 +) +(599.5 +) +Acquisition of crude oil and natural gas properties +(13.2 +) +(180.0 +) +(15.6 +) +(1,073.7 +) +— +Balance Sheet: +Total assets +$ +4,448.7 +$ +4,544.1 +$ +4,420.4 +$ +4,485.8 +$ +2,370.5 +Working capital (deficit) +(57.2 +) +(166.6 +) +(16.4 +) +129.2 +30.7 +Total debt, net of unamortized discount and debt issuance costs +1,177.2 +1,194.9 +1,151.9 +1,044.0 +642.4 +Total stockholders' equity +2,335.5 +2,526.7 +2,507.6 +2,622.8 +1,287.2 +Average Pricing and Production Expenses (per Boe and as a percent of sales for production taxes): +Sales price (excluding net settlements on derivatives) +$ +26.46 +$ +34.61 +$ +28.69 +$ +22.43 +$ +24.64 +Lease operating expenses +2.88 +3.26 +2.82 +2.70 +3.71 +Production taxes +1.63 +2.25 +1.91 +1.42 +1.20 +Production taxes (as a percent of sales) +6.2 +% +6.5 +% +6.6 +% +6.3 +% +4.9 +% +Transportation, gathering and processing +0.94 +0.93 +1.04 +0.83 +0.66 +Total production +49,414 +40,160 +31,830 +22,176 +15,369 +Total proved reserves (MMBoe) +610.9 +544.9 +452.9 +341.4 +272.8 +(1) +In 2016, we closed an acquisition in the Delaware Basin for aggregate consideration of approximately $1.76 billion. +(2) +Includes impact of change in accounts payable related to capital expenditures. +40 +ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes thereto included elsewhere in this report. A discussion of changes in our results of operations from 2017 to 2018 has been omitted from this report, but may be found in Item 7, Management's Discussion and Analysis , of our Annual Report on Form 10-K for the year ended December 31, 2018 , filed with the SEC on February 28, 2019. Further, we encourage you to revisit the Special Note Regarding Forward-Looking Statements in Part I of this report. +EXECUTIVE SUMMARY +2019 Financial Overview of Operations and Liquidity +Production volumes increased 23 percent to 49.4 MMBoe in 2019 compared to 2018 . The increase in production volumes was primarily attributable to the continued success of our horizontal Niobrara and Codell drilling program in the Wattenberg Field and growing production from our horizontal Wolfcamp drilling program in our Delaware Basin properties. Total liquids production of crude oil and NGLs comprised 61 percent of production in 2019 . For the month ended December 31, 2019 , we maintained an average production rate of approximately 139,000 Boe per day, up from approximately 129,000 Boe per day for the month ended December 31, 2018 . +Crude oil, natural gas and NGLs sales decreased to $1.3 billion in 2019 compared to $1.4 billion in 2018 , driven by a 24 percent decrease in weighted-average realized commodity prices, partially offset by the 23 percent increase in production. We had negative net settlements from commodity derivative contracts of $17.6 million for 2019 as compared to negative net settlements of $115.5 million for 2018 . The combined revenue from crude oil, natural gas and NGLs sales and net settlements received on our commodity derivative instruments was $1.3 billion in both 2019 and 2018 . +In 2019 , we generated a net loss of $56.7 million or, $0.89 per diluted share, compared to net income of $2.0 million , or $0.03 per diluted share, in 2018. Adjusted EBITDAX, a non-U.S. GAAP financial measure, was $882.7 million in 2019 , up two percent from $868.7 million in 2018 . +Net cash flows from operating activities in 2019 and 2018 were $858.2 million and $889.3 million , respectively, and adjusted cash flows from operations, a non-U.S. GAAP financial measure, were $825.4 million and $808.4 million , respectively. Free cash flow, a non-U.S. GAAP financial measure, was $37.7 million for 2019 as compared to a deficit of $174.3 million for 2018 . +See Reconciliation of Non-U.S. GAAP Financial Measures below for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures. +Acquisition +In January 2020, we merged with SRC in a transaction valued at $1.7 billion , inclusive of SRC's net debt. Upon closing, we issued approximately 39 million shares of our common stock to SRC shareholders, reflecting issuance of 0.158 of a share of our common stock in exchange for each share of SRC common stock held. +Liquidity +Available liquidity as of December 31, 2019 was $1.3 billion , primarily due to $1.3 billion available for borrowing under our revolving credit facility. In October 2019, as part of our semi-annual redetermination, the borrowing base on our revolving credit facility was reaffirmed at $1.6 billion and we elected to retain our commitment amount at $1.3 billion . +41 +Pursuant to closing the SRC Acquisition, the borrowing base on our revolving credit facility increased to $2.1 billion and we elected to increase the aggregate commitment amount under the facility to $1.7 billion. As part of the SRC Acquisition, we assumed $550 million in 6.25% Senior Notes due December 2025 and paid off and terminated SRC's revolving credit facility, which had an outstanding balance of $165 million at closing. The indenture governing the SRC Senior Notes has a change of control provision and on January 17, 2020, we commenced an offer to repurchase the SRC Senior Notes at 101 percent of the principal amount of the notes, together with any accrued and unpaid interest to the date of purchase. Upon expiration of the repurchase offer on February 18, 2020, holders of $447.7 million of the outstanding SRC Senior Notes accepted our redemption offer for a total redemption price of approximately $452.2 million , plus accrued and unpaid interest of $6.2 million . We funded the repurchase with proceeds from our revolving credit facility. +Had we closed the SRC Acquisition in 2019 with our new commitment level, we estimate that our available liquidity as of December 31, 2019 would have been approximately $1.6 billion , comprised of approximately $66.6 million of cash and cash equivalents and approximately $1.5 billion available for borrowing under our revolving credit facility. +Stock Repurchase Program +In April 2019, the Board approved the acquisition of up to $200 million of our outstanding common stock, dependent on market conditions (the "Stock Repurchase Program"). Effective with the closing of the SRC Acquisition, the Board approved an increase and extension of the Stock Repurchase Program from $200 million to $525 million with a target completion date of December 31, 2021. Pursuant to the Stock Repurchase Program, we repurchased 4.7 million shares of outstanding common stock at a cost of $154.4 million during 2019 . Subsequent to December 31, 2019 , we repurchased approximately 0.6 million shares of our outstanding common stock at a cost of $12.5 million . As of February 24, 2020 , $358.2 million of our outstanding common stock remained available for repurchase under the Stock Repurchase Program. +Midstream Asset Divestitures +In the second quarter of 2019, we completed the Midstream Asset Divestitures for an aggregate cash purchase price of $345.6 million ($263.6 million of which was paid upon closing with $82.0 million to be paid in June 2020), subject to certain customary post-closing adjustments, plus potential future long-term incentive payments. We do not currently expect to meet the conditions to receive these incentive payments. Proceeds were allocated first to the assets sold based upon the fair values of the tangible assets, with $179.6 million allocated to the acreage dedication agreements. +42 +2019 Drilling Overview +During 2019 , we ran three drilling rigs in the Wattenberg Field through mid-September and then dropped to a two-rig pace through the remainder of the year. In the Delaware Basin, we ran three rigs through May 2019 and then dropped to a two-rig pace through the remainder of the year. +The following tables summarizes our drilling and completion activity for the year ended December 31, 2019 : +Wells Operated by PDC +Wattenberg Field +Delaware Basin +Total +Gross +Net +Gross +Net +Gross +Net +In-process as of December 31, 2018 +133 +122.4 +18 +17.4 +151 +139.8 +Wells spud +126 +117.0 +33 +31.7 +159 +148.7 +Wells turned-in-line +(114 +) +(105.1 +) +(21 +) +(20.0 +) +(135 +) +(125.1 +) +In-process as of December 31, 2019 +145 +134.3 +30 +29.1 +175 +163.4 +Wells Operated by Others +Wattenberg Field +Delaware Basin +Total +Gross +Net +Gross +Net +Gross +Net +In-process as of December 31, 2018 +5 +2.0 +6 +0.9 +11 +2.9 +Wells spud +55 +4.4 +3 +0.4 +58 +4.8 +Wells turned-in-line +(19 +) +(1.1 +) +(9 +) +(1.3 +) +(28 +) +(2.4 +) +In-process as of December 31, 2019 +41 +5.3 +— +— +41 +5.3 +Our in-process wells represent wells that are in the process of being drilled and/or have been drilled and are waiting to be fractured and/or for gas pipeline connection. Our drilled uncompleted wells are generally completed and turned-in-line within a year of drilling. +2020 Operational and Financial Outlook +We anticipate that our total production for 2020 will range between 205,000 Boe to 215,000 Boe per day, approximately 78,000 Bbls to 82,000 Bbls of which are expected to be crude oil. Our planned 2020 capital investments in crude oil and natural gas properties, which we expect to be between $1.0 billion and $1.1 billion , are focused on continued execution of our development plans in the Wattenberg Field, including acreage received in the SRC Acquisition, and the Delaware Basin. +We believe that we maintain a degree of operational flexibility to control the pace of our capital spending. As we execute our capital investment program, we continually monitor, among other things, expected rates of return, the political environment and our remaining inventory in order to best meet our short- and long-term corporate strategy. Should commodity pricing or the operating environment deteriorate, we may determine that an adjustment to our development plan is appropriate. +Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays in the rural areas of the core Wattenberg Field, which is further delineated between the Kersey, Prairie and Plains development areas, as well as the mix of rural and municipal acreage received in the SRC Acquisition. Our 2020 capital investment program for the Wattenberg Field is approximately 75 percent of our expected total capital investments in crude oil and natural gas properties, of which approximately 95 percent is expected to be invested in operated drilling and completion activity. The majority of the wells we plan to drill in 2020 in the Wattenberg Field are standard-reach lateral (“SRL”), mid-reach lateral (“MRL”) and extended-reach lateral (“XRL”) wells. In 2020 , we anticipate spudding approximately 150 to 175 operated wells and turning-in-line approximately 200 to 225 operated wells. We expect to drill at a three-rig pace in 2020 with an average development cost per well of between $2.7 million and $4.5 million, depending upon the lateral length of the well. The remainder of the Wattenberg Field capital investment program is expected to be used for non-operated drilling, land, capital workovers and facilities projects. +Delaware Basin. Our 2020 capital investment program for the Delaware Basin contemplates operating a single rig into the third quarter, with a second rig planned for the remainder of the year. Total capital investments in crude oil and natural gas properties in the Delaware Basin for 2020 are expected to be approximately 25 percent of our total capital investments in crude oil and natural gas properties, of which approximately 90 percent is expected to be invested in operated drilling and completion +43 +activity. In 2020 , we anticipate spudding approximately 15 to 20 operated wells and turn-in-line approximately 20 to 25 operated wells. The majority of the wells we plan to drill in 2020 in the Delaware Basin are MRL and XRL wells. We expect average development costs per well of between $9.5 million and $11.0 million, depending upon the lateral length of the well. We do not plan to drill any SRL wells in the Delaware Basin in 2020 . +Financial Guidance. We are committed to our disciplined approach to managing our development plans. Based on our current production forecast for 2020 and assumed average NYMEX prices of $52.50 per Bbl of crude oil and $2.00 per Mcf of natural gas and an assumed average composite price of $11.00 per Bbl for NGLs, we expect 2020 adjusted cash flows from operations, a non-U.S. GAAP financial measure, to exceed our capital investments in crude oil and natural gas properties by approximately $250 million . Assuming consistent realization percentages, we estimate that for every: +• +$2.50 change in the NYMEX crude oil price from $52.50 , our adjusted cash flows from operations would increase or decrease by approximately $30 million ; +• +$0.25 change in the NYMEX natural gas price from $2.00 , our adjusted cash flows from operations would increase or decrease by approximately $20 million ; and +• +$1.00 change in the composite price for NGLs from $11.00 , our adjusted cash flows from operations would increase or decrease by approximately $20 million . +We may revise our 2020 capital investment program during the year as a result of, among other things, changes in commodity prices or our internal long-term outlook for commodity prices, requirements to hold acreage, the cost of services for drilling and well completion activities, drilling results, changes in our borrowing capacity, a significant change in cash flows, regulatory issues, requirements to maintain continuous activity on leaseholds or acquisition and/or divestiture opportunities. +The following table provides projected financial guidance for 2020 : +Low +High +Operating Expenses +Lease operating expenses ($/Boe) +$ +2.70 +$ +2.90 +Transportation, gathering and processing expenses ("TGP") ($/Boe) +$ +0.95 +$ +1.15 +Production taxes (percent of crude oil, natural gas and NGL sales) +6.5 +% +7.5 +% +Estimated Price Realizations +Crude oil (percent of NYMEX, excluding TGP) +93 +% +97 +% +Natural gas (percent of NYMEX, excluding TGP) +50 +% +55 +% +NGLs ($/Bbl, excluding TGP) +$ +10.00 +$ +12.00 +On a per unit basis and excluding transaction costs incurred related to the SRC Acquisition of approximately $30 million, we expect our general and administrative expense to be in the range of $1.90 to $2.10 per Boe for 2020. +Ballot Initiative Update +Certain interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, have advanced various alternatives for ballot initiatives which would result in significantly limiting or preventing oil and natural gas development in the state. Proponents of such initiatives have begun the process of attempting to qualify six initiatives to appear on the ballot in November 2020. Five of the initiatives are focused on increased setbacks, with differing distances and criteria, and one is focused on bonding requirements. +These initiatives will undergo a review by the Colorado Legislative Council, and will be the subject of other procedural requirements. If those requirements are satisfied, proponents of the initiatives can begin the process of collecting the signatures needed to qualify them for the November 2020 ballot. We do not know what the outcome of this process will be; however, a similar setback ballot initiative, Proposition 112, qualified for the ballot but failed to pass in 2018. +Because approximately 81 percent of our proved reserves are located in Colorado, the risks we face with respect to these proposals, and possible similar future proposals, are greater than those of our competitors with more geographically +44 +diverse operations. We cannot predict the outcome of the potentially pending initiatives or possible future regulatory developments. +See Part I, Item1A, Risk Factors , for additional information regarding the ballot initiatives. +45 +Results of Operations +Summary Operating Results +The following table presents selected information regarding our operating results: +Year Ended December 31, +Percent Change +2019 +2018 +2017 +2019-2018 +2018-2017 +(dollars in millions, except per unit data) +Production: +Crude oil (MBbls) +19,166 +16,963 +12,902 +13.0 +% +31.5 +% +Natural gas (MMcf) +115,950 +88,017 +71,689 +31.7 +% +22.8 +% +NGLs (MBbls) +10,923 +8,527 +6,981 +28.1 +% +22.1 +% +Crude oil equivalent (MBoe) +49,414 +40,160 +31,830 +23.0 +% +26.2 +% +Average Boe per day (Boe) +135,381 +110,027 +87,206 +23.0 +% +26.2 +% +Crude Oil, Natural Gas and NGLs Sales: +Crude oil +$ +1,020.7 +$ +1,038.0 +$ +625.0 +(1.7 +)% +66.1 +% +Natural gas +151.0 +163.2 +158.3 +(7.5 +)% +3.1 +% +NGLs +135.6 +188.8 +129.8 +(28.2 +)% +45.5 +% +Total crude oil, natural gas and NGLs sales +$ +1,307.3 +$ +1,390.0 +$ +913.1 +(5.9 +)% +52.2 +% +Net Settlements on Commodity Derivatives: +Crude oil +$ +(18.3 +) +$ +(124.4 +) +$ +(2.7 +) +(85.3 +)% +* +Natural gas +0.7 +13.9 +23.3 +(95.0 +)% +(40.3 +)% +NGLs +— +(5.0 +) +(7.3 +) +* +(31.5 +)% +Total net settlements on derivatives +$ +(17.6 +) +$ +(115.5 +) +$ +13.3 +(84.8 +)% +* +Average Sales Price (excluding net settlements on derivatives): +Crude oil (per Bbl) +$ +53.26 +$ +61.19 +$ +48.45 +(13.0 +)% +26.3 +% +Natural gas (per Mcf) +1.30 +1.85 +2.21 +(29.7 +)% +(16.3 +)% +NGLs (per Bbl) +12.41 +22.14 +18.59 +(43.9 +)% +19.1 +% +Crude oil equivalent (per Boe) +26.46 +34.61 +28.69 +(23.5 +)% +20.6 +% +Average Costs and Expenses (per Boe): +Lease operating expenses +$ +2.88 +$ +3.26 +$ +2.82 +(11.7 +)% +15.6 +% +Production taxes +1.63 +2.25 +1.91 +(27.6 +)% +17.8 +% +Transportation, gathering and processing expenses +0.94 +0.93 +1.04 +1.1 +% +(10.6 +)% +General and administrative expense +3.27 +4.25 +3.78 +(23.1 +)% +12.4 +% +Depreciation, depletion and amortization +13.04 +13.94 +14.74 +(6.5 +)% +(5.4 +)% +Lease Operating Expenses by Operating Region (per Boe): +Wattenberg Field +$ +2.50 +$ +2.99 +$ +2.48 +(16.4 +)% +20.6 +% +Delaware Basin +4.15 +4.14 +5.16 +0.2 +% +(19.8 +)% +Utica Shale (1) +— +3.46 +1.66 +* +108.4 +% +* +Percentage change is not meaningful. +Amounts may not recalculate due to rounding. +(1) +In March 2018, we completed the disposition of our Utica Shale properties. +46 +Crude Oil, Natural Gas and NGLs Sales +The year-over-year change in crude oil, natural gas and NGLs sales revenue were primarily due to the following: +Year Ended December 31, +2019 +2018 +(in millions) +Change in: +Production +$ +239.6 +$ +261.6 +Average crude oil price +(152.0 +) +216.1 +Average natural gas price +(64.0 +) +(31.1 +) +Average NGLs price +(106.3 +) +30.3 +Total change in crude oil, natural gas and NGLs sales revenue +$ +(82.7 +) +$ +476.9 +Crude Oil, Natural Gas and NGLs Production +The following table presents crude oil, natural gas and NGLs production. +Year Ended December 31, +Percent Change +Production by Operating Region +2019 +2018 +2017 +2019-2018 +2018-2017 +Crude oil (MBbls) +Wattenberg Field +14,489 +12,809 +10,922 +13.1 +% +17.3 +% +Delaware Basin +4,677 +4,108 +1,699 +13.9 +% +141.8 +% +Utica Shale (1) +— +46 +281 +* +(83.6 +)% +Total +19,166 +16,963 +12,902 +13.0 +% +31.5 +% +Natural gas (MMcf) +Wattenberg Field +91,785 +68,326 +60,106 +34.3 +% +13.7 +% +Delaware Basin +24,165 +19,277 +9,410 +25.4 +% +104.9 +% +Utica Shale (1) +— +414 +2,173 +* +(80.9 +)% +Total +115,950 +88,017 +71,689 +31.7 +% +22.8 +% +NGLs (MBbls) +Wattenberg Field +8,198 +6,455 +5,876 +27.0 +% +9.9 +% +Delaware Basin +2,725 +2,038 +917 +33.7 +% +122.2 +% +Utica Shale (1) +— +34 +188 +* +(81.9 +)% +Total +10,923 +8,527 +6,981 +28.1 +% +22.1 +% +Crude oil equivalent (MBoe) +Wattenberg Field +37,984 +30,652 +26,815 +23.9 +% +14.3 +% +Delaware Basin +11,430 +9,359 +4,184 +22.1 +% +123.7 +% +Utica Shale (1) +— +149 +831 +* +(82.1 +)% +Total +49,414 +40,160 +31,830 +23.0 +% +26.2 +% +Average crude oil equivalent per day (Boe) +Wattenberg Field +104,066 +83,978 +73,466 +23.9 +% +14.3 +% +Delaware Basin +31,315 +25,641 +11,463 +22.1 +% +123.7 +% +Utica Shale (1) +— +408 +2,277 +* +(82.1 +)% +Total +135,381 +110,027 +87,206 +23.0 +% +26.2 +% +* +Percentage change is not meaningful. +Amounts may not recalculate due to rounding. +(1) +In March 2018, we completed the disposition of our Utica Shale properties. +47 +The following table presents our crude oil, natural gas and NGLs production ratio by operating region: +Year Ended December 31, +Production Ratio by Operating Region +2019 +2018 +2017 +Wattenberg Field +Crude oil +38 +% +42 +% +41 +% +Natural gas +40 +% +37 +% +37 +% +NGLs +22 +% +21 +% +22 +% +Total +100 +% +100 +% +100 +% +Delaware Basin +Crude oil +41 +% +44 +% +41 +% +Natural gas +35 +% +34 +% +37 +% +NGLs +24 +% +22 +% +22 +% +Total +100 +% +100 +% +100 +% +Utica Shale (1) +Crude oil +— +% +31 +% +34 +% +Natural gas +— +% +46 +% +43 +% +NGLs +— +% +23 +% +23 +% +Total +— +% +100 +% +100 +% +(1) In March 2018, we completed the disposition of our Utica Shale properties. +Midstream Capacity +Our ability to market our production depends substantially on the availability, proximity and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. If adequate midstream facilities and services are not available to us on a timely basis and at acceptable costs, our production and results of operations could be adversely affected. In recent years, there has been substantial development drilling in our current areas of operation, and this has made it more challenging for providers of midstream infrastructure and services to keep pace with the corresponding increases in field-wide production. The ultimate timing and availability of adequate infrastructure is not within our control and we could experience capacity constraints for extended periods of time that could negatively impact our ability to meet our production targets. Weather, regulatory developments and other factors also affect the adequacy of midstream infrastructure. Like other producers, we from time to time enter into volume commitments with midstream providers in order to incentivize them to provide increased capacity to sufficiently meet our projected volume growth from our areas of operation. If our production falls below the level required under these agreements, we could be subject to transportation charges or aid in construction payments for commitment shortfalls. +Wattenberg Field. Elevated line pressures on gas gathering facilities operated by DCP have adversely affected production from our Wattenberg Field operations from mid-2017 to the early fourth quarter of 2019. However, beginning in the mid-fourth quarter of 2019, through the combination of DCP’s continued system expansions and the availability of additional NGLs takeaway capacity out of the basin, DCP was able to more meaningfully reduce line pressures through most of our operated areas of the Wattenberg Field. As a result of the decreased line pressures, we experienced increased production volumes in the Wattenberg Field in the fourth quarter of 2019 from incremental NGL takeaway expansion projects and increased firm residue gas space obtained by DCP. As we exited 2019, DCP was able to utilize the full capacity of the O’Connor II plant. +As midstream development continues in the field, we anticipate having the ability to move additional volumes on DCP’s system with the start-up of the Cheyenne Connector residue pipeline planned for mid-second quarter of 2020 and the completion of DCP in-basin infrastructure designed to deliver gas volumes to the Latham II plant, which is expected in mid-2020. +Our production in the Wattenberg Field is significantly dependent on DCP's gathering system, and this reliance increased considerably when we closed the SRC Acquisition. We continue to work with our midstream service providers in an effort to ensure all of the existing in-basin infrastructure is fully utilized and that all options for system expansion are evaluated and implemented to the extent possible to accommodate projected future volume growth from the field. +48 +NGL fractionation on the Gulf Coast and Conway continues to operate at or near full capacity and this could potentially impact the operation of gas plants in the Wattenberg Field. Our Wattenberg Field operations are not currently being impacted by NGL fractionation capacity constraints; however, limitations on downstream fractionation capacity could limit the ability of our service providers to adjust ethane and propane recoveries to optimize the plant product mix to maximize revenue. Additional fractionation capacity came online during 2019 and additional capacity is expected to become available throughout 2020. +Delaware Basin. Our production from the Delaware Basin was not materially affected by midstream or downstream capacity constraints during 2019. However, despite the completion and start-up of a new natural gas residue pipeline, natural gas takeaway capacity downstream of in-field gathering and processing facilities in the basin continues to operate close to capacity and near-term production constraints, and lower natural gas netback pricing, are likely until at least the first quarter of 2021, when the next natural gas residue pipeline out of the basin is scheduled to be commissioned. +As discussed above, NGL fractionation on the Gulf Coast and at Conway is running at or near full capacity, and this could potentially impact the operation of gas plants in the Delaware Basin. Two new crude oil pipelines out of the Permian Basin were recently completed and are now operational. As a result, we believe the crude oil takeaway constraints that were experienced in 2018 and early 2019 have been somewhat alleviated for the near future. +49 +Crude Oil, Natural Gas and NGLs Pricing +Our results of operations depend upon many factors. Key factors include market prices of crude oil, natural gas and NGLs and our ability to market our production effectively. Crude oil, natural gas and NGLs prices have a high degree of volatility and our realizations can change substantially. Our realized sales prices for crude oil, natural gas and NGLs decreased during 2019 as compared to 2018 . NYMEX average daily crude oil and NYMEX first-of-the-month natural gas prices decreased 12 percent and 15 percent , respectively, as compared to 2018 . +The following tables present weighted-average sales prices of crude oil, natural gas and NGLs for the periods presented: +Year Ended December 31, +Weighted-Average Realized Sales Price by Operating Region +Percent Change +(excluding net settlements on derivatives) +2019 +2018 +2017 +2019-2018 +2018-2017 +Crude oil (per Bbl) +Wattenberg Field +$ +52.99 +$ +61.14 +$ +48.48 +(13.3 +)% +26.1 +% +Delaware Basin +54.08 +61.37 +48.68 +(11.9 +)% +26.1 +% +Utica Shale (1) +— +58.10 +45.63 +* +27.3 +% +Weighted-average price +53.26 +61.19 +48.45 +(13.0 +)% +26.3 +% +Natural gas (per Mcf) +Wattenberg Field +1.49 +1.90 +2.19 +(21.6 +)% +(13.2 +)% +Delaware Basin +0.57 +1.66 +2.26 +(65.7 +)% +(26.5 +)% +Utica Shale (1) +— +2.68 +2.40 +* +11.7 +% +Weighted-average price +1.30 +1.85 +2.21 +(29.7 +)% +(16.3 +)% +NGLs (per Bbl) +Wattenberg Field +11.51 +20.58 +17.75 +(44.1 +)% +15.9 +% +Delaware Basin +15.12 +27.06 +22.64 +(44.1 +)% +19.5 +% +Utica Shale (1) +— +24.29 +25.06 +* +(3.1 +)% +Weighted-average price +12.41 +22.14 +18.59 +(43.9 +)% +19.1 +% +Crude oil equivalent (per Boe) +Wattenberg Field +26.31 +34.13 +28.55 +(22.9 +)% +19.5 +% +Delaware Basin +26.95 +36.25 +29.80 +(25.7 +)% +21.6 +% +Utica Shale (1) +— +30.98 +27.36 +* +13.2 +% +Weighted-average price +26.46 +34.61 +28.69 +(23.5 +)% +20.6 +% +* +Percentage change is not meaningful. +Amounts may not recalculate due to rounding. +(1) +In March 2018, we completed the disposition of our Utica Shale properties. +Crude oil, natural gas and NGLs revenues are recognized when we transfer control of crude oil, natural gas or NGLs production to the purchaser. We consider the transfer of control to occur when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. +Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related purchase agreement. We use the net-back method when control of the crude oil, natural gas or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering or processing services. In these situations, the purchaser pays us based on a percent of proceeds or a sales price fixed at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index on which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when control of the crude oil, natural gas or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transportation and processing on a per unit basis. Under this +50 +method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses. +As discussed above, we enter into agreements for the sale and transportation, gathering and processing of our production, the terms of which can result in variances in the per unit realized prices that we receive for our crude oil, natural gas and NGLs. Information related to the components and classifications in the consolidated statements of operations is shown below. For crude oil, the average NYMEX prices shown below are based on average daily prices throughout each month and, for natural gas, the average NYMEX pricing is based on first-of-the-month index prices, as in each case this is the method used to sell the majority of these commodities pursuant to terms of the relevant sales agreements. For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. The average realized price both before and after transportation, gathering and processing expenses shown in the table below represents our approximate composite per barrel price for NGLs. +2019 +Average NYMEX Price +Average Realized Price Before Transportation, Gathering and Processing Expenses +Average Realization Percentage Before Transportation, Gathering and Processing Expenses +Average Transportation, Gathering and Processing Expenses +Average Realized Price After Transportation, Gathering and Processing Expenses +Average Realization Percentage After Transportation, Gathering and Processing Expenses +Crude oil (per Bbl) +$ +57.03 +$ +53.26 +93 +% +$ +1.24 +$ +52.02 +91 +% +Natural gas (per MMBtu) +2.63 +1.30 +49 +% +0.17 +1.13 +43 +% +NGLs (per Bbl) +57.03 +12.41 +22 +% +0.10 +12.31 +22 +% +Crude oil equivalent (per Boe) +40.95 +26.46 +65 +% +0.90 +25.56 +62 +% +2018 +Average NYMEX Price +Average Realized Price Before Transportation, Gathering and Processing Expenses +Average Realization Percentage Before Transportation, Gathering and Processing Expenses +Average Transportation, Gathering and Processing Expenses +Average Realized Price After Transportation, Gathering and Processing Expenses +Average Realization Percentage After Transportation, Gathering and Processing Expenses +Crude oil (per Bbl) +$ +64.77 +$ +61.19 +94 +% +$ +0.94 +$ +60.25 +93 +% +Natural gas (per MMBtu) +3.09 +1.85 +60 +% +0.22 +1.63 +53 +% +NGLs (per Bbl) +64.77 +22.14 +34 +% +0.21 +21.93 +34 +% +Crude oil equivalent (per Boe) +47.87 +34.61 +72 +% +0.93 +33.68 +70 +% +2017 +Average NYMEX Price +Average Realized Price Before Transportation, Gathering and Processing Expenses +Average Realization Percentage Before Transportation, Gathering and Processing Expenses +Average Transportation, Gathering and Processing Expenses +Average Realized Price After Transportation, Gathering and Processing Expenses +Average Realization Percentage After Transportation, Gathering and Processing Expenses +Crude oil (per Bbl) +$ +50.95 +$ +48.45 +95 +% +$ +1.41 +$ +47.04 +92 +% +Natural gas (per MMBtu) +3.11 +2.21 +71 +% +0.17 +2.04 +66 +% +NGLs (per Bbl) +50.95 +18.59 +36 +% +0.30 +18.29 +36 +% +Crude oil equivalent (per Boe) +38.83 +28.69 +74 +% +1.04 +27.65 +71 +% +Our average realization percentages for crude oil in 2019 were consistent with those for 2018 . The realization percentage for our natural gas sales decreased as compared to 2018 , primarily due to widening of the basis between NYMEX and the indices upon which we sell our natural gas production. In the Delaware Basin, we experienced certain months during 2019 when the transportation, gathering and processing cost to deliver our natural gas to market exceeded the price we received. The realization percentages for our NGLs sales also decreased as compared to 2018 , primarily due to reductions in prices for the individual NGLs components for 2019 as compared to the same periods in 2018 . As noted above, average +51 +NYMEX prices for both crude oil and natural gas during 2019 decreased as compared to 2018, resulting in lower average realizations. Based on our current pricing projections, we expect realizations in 2020 to decrease relative to 2019. +Commodity Price Risk Management +We use commodity derivative instruments to manage fluctuations in crude oil and natural gas prices, including fixed-price swaps, collars and basis protection swaps on a portion of our estimated crude oil and natural gas production. For our commodity swaps, we ultimately realize the fixed price value related to the swaps. See the footnote titled Commodity Derivative Financial Instruments to our accompanying consolidated financial statements included elsewhere in this report for a summary of our derivative positions as of December 31, 2019 . +Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments, as well as the change in fair value of unsettled commodity derivatives related to our crude oil and natural gas production. +Net settlements of commodity derivative instruments are based on the difference between the crude oil and natural gas index prices at the settlement date of our commodity derivative instruments compared to the respective strike prices contracted for the settlement months that were established at the time we entered into the commodity derivative transaction. The net change in fair value of unsettled commodity derivatives is comprised of the net increase or decrease in the beginning-of-period fair value of commodity derivative instruments that settled during the period and the net change in fair value of unsettled commodity derivatives during the period or from inception of any new contracts entered into during the applicable period. The net change in fair value of unsettled commodity derivatives during the period is primarily related to shifts in the crude oil and natural gas forward curves and changes in certain differentials. +The following table presents net settlements and net change in fair value of unsettled derivatives included in commodity price risk management, net: +Year Ended December 31, +2019 +2018 +2017 +(in millions) +Commodity price risk management gain (loss), net: +Net settlements of commodity derivative instruments: +Crude oil fixed price swaps and collars +$ +(18.3 +) +$ +(139.7 +) +$ +(2.7 +) +Crude oil basis protection swaps +— +15.2 +— +Natural gas fixed price swaps and collars +8.8 +(7.0 +) +19.5 +Natural gas basis protection swaps +(8.1 +) +21.0 +3.8 +NGLs fixed price swaps +— +(5.0 +) +(7.3 +) +Total net settlements of commodity derivative instruments +(17.6 +) +(115.5 +) +13.3 +Change in fair value of unsettled commodity derivative instruments: +Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments +(81.1 +) +64.9 +44.8 +Crude oil fixed price swaps, collars and rollfactors +(62.1 +) +197.0 +(77.9 +) +Natural gas fixed price swaps and collars +0.1 +1.4 +14.7 +Natural gas basis protection swaps +(2.1 +) +(2.6 +) +5.7 +NGLs fixed price swaps +— +— +(4.6 +) +Net change in fair value of unsettled commodity derivative instruments +(145.2 +) +260.7 +(17.3 +) +Total commodity price risk management gain (loss), net +$ +(162.8 +) +$ +145.2 +$ +(4.0 +) +Lease Operating Expenses +Lease operating expenses increased nine percent to $142.2 million in 2019 compared to $131.0 million in 2018 , primarily due to wells turned-in-line during 2019 . Significant changes in lease operating expenses included increases of $10.5 million related to produced water disposal expense, $4.7 related to additional compressor and equipment rental, $2.4 million related to expense for non-operated wells, $2.1 million for payroll and employee benefits related to increases in headcount and $1.4 million related to chemical treatments. The increases were partially offset by decreases of $6.3 million related to workover projects and $4.7 million related to midstream expense resulting from the sale of Delaware Basin midstream assets during the second quarter of 2019. Lease operating expense per Boe decreased by 12 percent to $2.88 for 2019 from $3.26 for 2018 . +52 +Production Taxes +Production taxes, which are comprised mainly of severance tax and ad valorem tax, are directly related to crude oil, natural gas and NGLs sales and are generally assessed as a percentage of net revenues. From time to time, there are adjustments to the statutory rates for these taxes based upon certain credits that are determined by activity levels and relative commodity prices from year-to-year. +Production taxes decreased 11 percent to $80.8 million in 2019 compared to $90.4 million in 2018 , primarily due to the six percent decrease in crude oil, natural gas and NGLs sales for 2019 compared to 2018 , refunds of ad valorem tax related to high-cost natural gas wells and a decrease in ad valorem tax rates in the Delaware Basin. +Transportation, Gathering and Processing Expenses +Transportation, gathering and processing expenses are primarily impacted by the volumes delivered through pipelines and for natural gas gathering and transportation operations. Transportation, gathering and processing expenses increased 24 percent to $46.4 million in 2019 compared to $37.4 million in 2018 , primarily due to an increase in production. Transportation, gathering and processing expenses per Boe remained consistent at $0.94 for 2019 compared to $0.93 for 2018 . +Exploration, Geologic and Geophysical Expense +Geological and geophysical costs. Geological and geophysical costs of $4.1 million in 2019 compared to $6.2 million in 2018 were primarily for the purchase of seismic data related to unproved acreage in the Delaware Basin. +Impairment of Properties and Equipment +The following table sets forth the major components of our impairment of properties and equipment: +Year Ended December 31, +2019 +2018 +2017 +(in millions) +Impairment of proved and unproved properties +$ +10.6 +$ +458.4 +$ +285.5 +Amortization of individually insignificant unproved properties +— +— +0.4 +Impairment of infrastructure and other +27.9 +— +— +Impairment of properties and equipment +$ +38.5 +$ +458.4 +$ +285.9 +During 2019 and 2018 , we recorded impairment charges totaling $10.6 million and $458.4 million , respectively, related to the divestiture of leaseholds and then-current and anticipated near-term leasehold expirations within our non-focus areas of the Delaware Basin that we determined not to develop. We determined the fair value of the properties based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. During 2019 , we also recorded impairments of $27.9 million related to certain midstream facility infrastructure in the Delaware Basin. Upon closing of the Midstream Asset Divestitures, it was determined that the net book value of these assets was not recoverable. +General and Administrative Expense +General and administrative expense decreased five percent to $161.8 million in 2019 compared to $170.5 million in 2018 . The decrease was primarily attributable to decreases of $17.9 million in legal-related fees and $8.2 million in government relations costs. The decreases were partially offset by increases of $7.8 million in costs related to the SRC Acquisition, $6.0 million related to shareholder activism, $3.4 million for the allowance adjustment for royalty owner payments and $1.0 million in payroll and related benefits. +53 +Depreciation, Depletion and Amortization +Crude oil and natural gas properties. During 2019 and 2018 , we invested $787.7 million and $982.7 million , exclusive of changes in accounts payable related to capital expenditures, in the development of our crude oil and natural gas properties, respectively. DD&A expense related to crude oil and natural gas properties is directly related to proved reserves and production volumes. DD&A expense related to crude oil and natural gas properties was $638.5 million , $551.3 million and $462.5 million in 2019 , 2018 and 2017 , respectively. The year-over-year change in DD&A expense for 2019 compared to 2018 related to crude oil and natural gas properties was primarily due to the following: +Year Ended December 31, +2019 +(in millions) +Increase in production +$ +128.9 +Decrease in weighted-average depreciation, depletion and amortization rates +(41.7 +) +Total increase in DD&A expense related to crude oil and natural gas properties +$ +87.2 +The following table presents our per Boe DD&A expense rates for crude oil and natural gas properties: +Year Ended December 31, +Operating Region/Area +2019 +2018 +2017 +(per Boe) +Wattenberg Field +$ +11.82 +$ +12.58 +$ +14.67 +Delaware Basin +16.87 +17.70 +14.89 +Total weighted-average +13.04 +13.73 +14.53 +Loss on sale of properties and equipment +In 2019 , we exchanged acreage located in Reeves County, Texas with a third party. As additional consideration for the acreage acquired, we paid $2.7 million in cash and recognized a loss of $45.6 million based on the carrying value of the acreage sold. +Interest Expense +Interest expense increased by $0.4 million to $71.2 million in 2019 compared to $70.7 million in 2018 . The increase was primarily related to a $4.2 million increase in interest related to our revolving credit facility, partially offset by a $4.1 million increase in capitalized interest. +Interest costs capitalized in 2019 and 2018 were $13.4 million and $9.2 million , respectively. +Provision for Income Taxes +Current income tax benefit in 2019 and 2018 was $1.1 million and $0.7 million, respectively. Current income taxes generally relate to the cash that is paid or recovered for income taxes associated with the applicable period. The remaining portion of the total income tax provision is comprised of deferred income taxes, which are a result of differences in the timing of deductions from our U.S. GAAP presentation of financial statements and the income tax regulations. +Our effective income tax rates for 2019 and 2018 were 5.5 percent and 72.8 percent , respectively, on income/(loss) from operations. +The 2019 rate differs from the federal statutory tax rate primarily due to state taxes, valuation allowance for state tax attributes, stock compensation detriments and nondeductible expenses that consist primarily of officers' compensation, acquisition costs and government lobbying expenses. +54 +The 2018 rate differs from the federal statutory tax rate primarily due to state taxes, federal tax credits, valuation allowance for state tax attributes and nondeductible expenses that consist primarily of officers' compensation cost and government lobbying expenses. +As of the date of this report, we are current with our income tax filings in all applicable state jurisdictions. The Internal Revenue Service ("IRS") partially accepted our 2018 tax return. The 2018 tax return is in the IRS Compliance Assurance Program (the "CAP Program") post-filing review process, with no significant tax adjustments currently proposed. We continue to voluntarily participate in the IRS CAP Program for the 2019 and 2020 tax years. +Net Income (Loss)/Adjusted Net Income (Loss) +The factors resulting in changes in net income (loss) in 2019 and 2018 are discussed above. These same reasons similarly impacted adjusted net income (loss), a non-U.S. GAAP financial measure, with the exception of the net change in fair value of unsettled derivatives, adjusted for taxes, of $110.0 million and $198.3 million in 2019 and 2018 , respectively. Adjusted net income was $53.3 million in 2019 and adjusted net loss was $196.3 million in 2018 . See Reconciliation of Non-U.S. GAAP Financial Measures below for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures. +Financial Condition, Liquidity and Capital Resources +Our primary sources of liquidity are cash flows from operating activities, our revolving credit facility, proceeds raised in debt and equity capital market transactions and asset sales. In 2019 , our net cash flows from operating activities were $858.2 million . +Our primary source of cash flows from operating activities is the sale of crude oil, natural gas and NGLs. Fluctuations in our operating cash flows are principally driven by commodity prices and changes in our production volumes. Commodity prices have historically been volatile and we manage a portion of this volatility through our use of derivative instruments. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the instrument. Our revolving credit facility imposes limits on the amount of our production we can hedge, and we may choose not to hedge the maximum amounts permitted. Therefore, we may still have fluctuations in our cash flows from operating activities due to the remaining non-hedged portion of our future production. +We may use our available liquidity for operating activities, capital investments, working capital requirements, acquisitions and for general corporate purposes. We maintain a significant capital investment program to execute our development plans, which requires capital expenditures to be made in periods prior to initial production from newly developed wells. +From time to time, these activities may result in a working capital deficit; however, we do not believe that our working capital deficit as of December 31, 2019 is an indication of a lack of liquidity. We had working capital deficits of $57.2 million and $166.6 million at December 31, 2019 and December 31, 2018 , respectively. We intend to continue to manage our liquidity position by a variety of means, including through the generation of cash flows from operations, investment in projects with favorable rates of return, protection of cash flows on a portion of our anticipated sales through the use of an active commodity derivative hedging program, utilization of the borrowing capacity under our revolving credit facility and, if warranted, capital markets transactions from time to time. +Our cash and cash equivalents were $1.0 million at December 31, 2019 and availability under our revolving credit facility was $1.3 billion , providing for total liquidity of $1.3 billion as of December 31, 2019 . In October 2019, as part of our semi-annual redetermination, the borrowing base on our revolving credit facility was reaffirmed at $1.6 billion and we elected to retain our commitment amount at $1.3 billion . Based on our current production forecast for 2020 and assumed average NYMEX prices of $52.50 per Bbl of crude oil and $2.00 per Mcf of natural gas and an assumed average composite price of $11.00 per Bbl for NGLs, we expect 2020 adjusted cash flows from operations, a non-U.S. GAAP financial measure, to exceed our capital investments in crude oil and natural gas properties by approximately $250 million . +Pursuant to closing the SRC Acquisition, the borrowing base on our revolving credit facility increased to $2.1 billion and we elected to increase the aggregate commitment amount under the facility to $1.7 billion . Had we closed the SRC Acquisition in 2019 with our new commitment level, we estimate that our available liquidity as of December 31, 2019 would have been approximately $1.6 billion , comprised of approximately $66.6 million of cash and cash equivalents and approximately $1.5 billion available for borrowing under our revolving credit facility. +55 +In the second quarter of 2019, we completed the Midstream Asset Divestitures for an aggregate cash purchase price of $345.6 million ($263.6 million of which was paid upon closing with the remaining $82.0 million to be paid in June 2020), subject to certain customary post-closing adjustments, plus potential future long-term incentive payments. We do not currently expect to meet the conditions to receive these incentive payments. Proceeds were allocated first to the assets sold based upon the fair values of the tangible assets, with $179.6 million allocated to the acreage dedication agreements. +We used the proceeds from these divestitures for our capital investment program. +As a result of merging with SRC, we assumed the SRC Senior Notes and paid off and terminated SRC's revolving credit facility. On January 17, 2020, we commenced an offer to repurchase the outstanding SRC Senior Notes at 101 percent of the principal amount. Upon expiration of the repurchase offer on February 18, 2020, holders of $447.7 million of the outstanding SRC Senior Notes accepted our redemption offer for a total redemption price of approximately $452.2 million , plus accrued and unpaid interest of $6.2 million . We funded the repurchase with proceeds from our revolving credit facility. +In April 2019, the Board approved the acquisition of up to $200 million of our outstanding common stock, depending on market conditions. Pursuant to the Stock Repurchase Program, we repurchased 4.7 million shares of outstanding common stock at a cost of $154.4 million during 2019 . Subsequent to December 31, 2019 , we repurchased approximately 0.6 million shares of our outstanding common stock at a cost of $12.5 million . Additionally, in August 2019, contingent on the closing of the SRC Acquisition, our Board approved an increase and extension to the Stock Repurchase Program from $200 million to $525 million with a target completion date of December 31, 2021. As of February 24, 2020 , $358.2 million of our outstanding common stock remained available for repurchase under the Stock Repurchase Program. +We currently project that we will generate a sufficient level of cash flow through December 2021 to fund the Stock Repurchase Program, while maintaining the ability to pursue additional future return of capital programs, depending on market conditions. Repurchases under the Stock Repurchase Program can be made in open markets at our discretion and in compliance with safe harbor provisions, or in privately negotiated transactions. The Stock Repurchase Program does not require any specific number of shares to be acquired, and can be modified or discontinued by the Board at any time. +Based on our expected cash flows from operations, our cash and cash equivalents and availability under our revolving credit facility, we believe that we will have sufficient capital available to fund our planned activities through the 12-month period following the filing of this report. +Our revolving credit facility is available for working capital requirements, capital investments, acquisitions, to support letters of credit and for general corporate purposes. The borrowing base is primarily based on the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. In August 2019, we entered into a First Amendment to the Restated Credit Agreement. The First Amendment primarily modifies certain sections of the Restated Credit Agreement to permit the consummation of the SRC Acquisition and provides for certain borrowings in connection with the SRC Acquisition. +The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (i) maintain a minimum current ratio of 1.0:1.0 and (ii) not exceed a maximum leverage ratio of 4.0:1.0. At December 31, 2019 , we were in compliance with all covenants in the revolving credit facility with a current ratio of 4.4 :1.0 and a leverage ratio of 1.4 :1.0. We expect to remain in compliance throughout the 12-month period following the filing of this report. +The indentures governing our 2024 Senior Notes, our 2026 Senior Notes and the SRC Senior Notes contain customary restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (i) incur additional debt including under our revolving credit facility, (ii) make certain investments or pay dividends or distributions on our capital stock or purchase, redeem or retire capital stock, (iii) sell assets, including capital stock of our restricted subsidiaries, (iv) restrict the payment of dividends or other payments by restricted subsidiaries to us, (v) create liens that secure debt, (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company. +56 +Cash Flows +Operating Activities. Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes, net settlements from our commodity derivative positions, operating costs and general and administrative expenses. Cash flows from operating activities decreased by $31.1 million to $858.2 million in 2019 as compared to $889.3 million in 2018 , primarily due to a decrease in crude oil, natural gas and NGLs sales of $82.7 million and a decrease in changes in assets and liabilities of $48.1 million , primarily attributable to $95.5 million in deferred midstream gathering credits related to our Midstream Asset Divestitures. These changes were partially offset by an increase in commodity derivative settlements of $97.9 million . +Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased by $17.0 million in 2019 to $825.4 million from $808.4 million in 2018 . The increase was primarily due to the factors mentioned above for changes in cash flows provided by operating activities, without regard to timing of cash payments and receipts of assets and liabilities. Free cash flow, a non-U.S GAAP financial measure, increased by $212.0 million in 2019 to $37.7 million from a free cash flow deficit of $174.3 million in 2018 . The increase was due to the increase in adjusted cash flows from operations, combined with a decrease in capital investments in crude oil and natural gas properties. +See Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures. +Investing Activities. Because crude oil and natural gas production from a well declines rapidly in the first few years of production, we need to continue to commit significant amounts of capital in order to maintain and grow our production and replace our reserves. If capital is not available or is constrained in the future, we will be limited to our cash flows from operations and liquidity under our revolving credit facility as the sources for funding our capital investments. +Cash flows from investing activities primarily consist of the acquisition, exploration and development of crude oil and natural gas properties, net of dispositions of crude oil and natural gas properties. Net cash used in investing activities of $677.8 million during 2019 was primarily related to our drilling and completion activities of $855.9 million . Partially offsetting these investing activities was net cash received from the Midstream Asset Divestitures and certain Delaware Basin crude oil and natural gas properties of $199.4 million. Net cash used in investing activities of $1.1 billion during 2018 was primarily related to cash utilized toward property acquisitions of $180.0 million and our drilling and completion activities of $946.4 million . Partially offsetting these investments was the receipt of approximately $43.5 million, primarily related to the sale of our Utica Shale assets in March 2018. +Financing Activities. Net cash from financing activities in 2019 of $188.9 million was primarily due to the repurchase and retirement of shares of our common stock totaling $154.4 million pursuant to the Stock Repurchase Program, net borrowings from our credit facility of $28.5 million and $4.0 million related to purchases of our stock for employee stock-based compensation tax withholding obligations. +Net cash from financing activities in 2018 of $18.1 million was comprised of net borrowings from our credit facility of $32.5 million, partially offset by $7.7 million of debt issuance costs and $5.1 million related to purchases of our stock. +57 +Contractual Obligations and Contingent Commitments +The following table presents our contractual obligations and contingent commitments as of December 31, 2019 : +Payments due by period +Less than +1-3 +3-5 +Contractual Obligations and Contingent Commitments +Total +1 year +years +years +Thereafter +(in millions) +Long-term liabilities reflected on the consolidated balance sheet (1) +Long-term debt (2) +$ +1,204 +$ +— +$ +200 +$ +404 +$ +600 +Commodity derivative contracts (3) +4 +3 +1 +— +— +Production tax liability +144 +76 +68 +— +— +Deferred oil gathering credit +20 +2 +5 +4 +9 +Deferred midstream gathering credits +176 +7 +23 +29 +117 +Asset retirement obligations +127 +32 +30 +30 +35 +Operating and finance leases +22 +6 +11 +3 +2 +Other liabilities (4) +4 +— +2 +1 +1 +1,701 +126 +340 +471 +764 +Commitments, contingencies and other arrangements (5) +Interest on long-term debt (6) +386 +67 +130 +120 +69 +Firm transportation and processing agreements (7) +581 +85 +207 +147 +142 +967 +152 +337 +267 +211 +Total +$ +2,668 +$ +278 +$ +677 +$ +738 +$ +975 +(1) +Table does not include net deferred income tax liability to taxing authorities of $195.8 million due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. +(2) +Amount presented does not agree with the consolidated balance sheets in that it excludes $14.8 million of unamortized debt discounts and $12.0 million of unamortized debt issuance costs. +(3) +Represents our gross liability related to the fair value of derivative positions. +(4) +Includes deferred compensation to former executive officers and deferred payments related to firm transportation agreements. +(5) +The table does not include termination benefits related to employment agreements with our executive officers, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. +(6) +Amounts presented include $241.5 million to the holders of our 2026 Senior Notes, $122.5 million to the holders of our 2024 Senior Notes and $4.5 million payable to the holders of our 2021 Convertible Notes. Amounts also include interest of $16.7 million related to unutilized commitments at a rate of 0.375 percent per annum. +(7) +Represents our gross commitment which includes volumes produced by us and purchased from third parties and produced by other third-party working, royalty and overriding royalty interest owners whose volumes we market on their behalf. +From time to time, we are a party to various legal proceedings in the ordinary course of business. We are not currently a party to any litigation that we believe would have a materially adverse effect on our business, financial condition, results of operations or liquidity. Information regarding our legal proceedings can be found in the footnote titled Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere in this report. +Off-Balance Sheet Arrangements +At December 31, 2019 , we had no off-balance sheet arrangements, as defined under SEC rules, which have or are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital investments or capital resources. +Critical Accounting Policies and Estimates +We have identified the following policies as critical to business operations and the understanding of our results of operations. This is not a comprehensive list of all of the accounting policies. In many cases, the accounting treatment of a particular transaction is specifically dictated by U.S. GAAP, with no need for our judgment in the application. There are also areas in which our judgment in selecting available alternatives would not produce a materially different result. However, certain of our accounting policies are particularly important to the presentation of our financial position and results of operations and we may use significant judgment in their application. As a result, they are subject to an inherent degree of uncertainty. In +58 +applying those policies, we use our judgment to determine the appropriate assumptions to be used in the determination of certain estimates. Those estimates are based on historical experience, observation of trends in the industry and information available from other outside sources, as appropriate. For a more detailed discussion on the application of these and other accounting policies, see the footnote titled Summary of Significant Accounting Policies to our consolidated financial statements included elsewhere in this report. +Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depleted by the unit-of-production method based on estimated proved developed producing reserves. Property acquisition costs are depleted on the unit-of-production method based on estimated proved reserves. +Annually, we engage independent petroleum engineers to prepare reserve and economic evaluations of all our properties on a well-by-well basis as of December 31. We adjust our crude oil and natural gas reserves for major acquisitions, new drilling and divestitures during the year as needed. The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. Although every reasonable effort is made to ensure that reserve estimates reported represent our most accurate assessments possible, the subjective decisions and variances in available data for various properties increase the likelihood of significant changes in these estimates over time. Because estimates of reserves significantly affect our DD&A expense, a change in our estimated reserves could have an effect on our net earnings. +Exploration costs, including geological and geophysical expenses, the acquisition of seismic data covering unproved acreage and delay rentals, are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but are charged to expense if the well is determined to be nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as the well has found a sufficient quantity of reserves to justify completion as a producing well and we are making sufficient progress assessing our reserves and economic and operating viability. If an in-progress exploratory well is found to be unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the well is classified as a "suspended well" until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time when we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the proper accounting treatment is applied. +Acquisition costs of unproved properties are capitalized when incurred until such properties are transferred to proved properties or charged to expense. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed, and any impairment in value is charged to impairment of crude oil and natural gas properties. The amount of impairment recognized on unproved properties which are not individually significant is determined by amortizing the costs of such properties within appropriate fields based on our historical experience, acquisition dates and average lease terms, with the amortization recognized in impairment of properties and equipment. The valuation of unproved properties is subjective and requires us to make estimates and assumptions which, with the passage of time, may prove to be materially different from actual realizable values. +We assess our crude oil and natural gas properties for possible impairment annually, or upon a triggering event, by comparing carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production and prices at which we reasonably estimate the commodities will be sold. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserve volumes, future operating and development costs, future commodity prices and estimated future cash flows. Any impairment in value is charged to impairment of properties and equipment. The estimates of future prices may differ from current market prices of crude oil and natural gas. Any downward revisions in estimates to our reserve quantities, expectations of falling commodity prices or rising operating costs could result in a triggering event, and therefore, a reduction in undiscounted future net cash flows and an impairment of our crude oil and natural gas properties. Although our cash flow estimates are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. +Crude Oil, Natural Gas and NGLs Sales Revenue Recognition. Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of crude oil, natural gas or NGLs production to the purchaser. We consider the +59 +transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. +Fair Value of Financial Instruments. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. +Commodity Derivative Financial Instruments. We measure the fair value of our commodity derivative instruments based on a pricing model that utilizes market-based inputs, including but not limited to the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of commodity derivative liabilities and the effect of our counterparties' credit standings on the fair value of commodity derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding commodity derivative position. +We validate our fair value measurement by corroborating the original source of inputs, monitoring changes in valuation methods and assumptions and through the review of counterparty statements and other supporting documentation. +Net settlements on our commodity derivative instruments are initially recorded to accounts receivable or payable, as applicable, and may not be received from or paid to counterparties to our commodity derivative contracts within the same accounting period. Such settlements typically occur the month following the maturity of the commodity derivative instrument. We have evaluated the credit risk of the counterparties holding our commodity derivative assets, which are primarily financial institutions who are also major lenders in our revolving credit facility, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding commodity derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our counterparties on the fair value of our commodity derivative instruments is not significant. +Deferred Income Tax Asset Valuation Allowance. Deferred income tax assets are recognized for deductible temporary differences, net operating loss carry-forwards and credit carry-forwards if it is more likely than not that the tax benefits will be realized. To the extent a deferred tax asset is not expected to be realized under the preceding criteria, we establish a valuation allowance. The factors which we consider in assessing whether we will realize the value of deferred income tax assets involve judgments and estimates of both amount and timing. The judgments used in applying these policies are based on our evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results may differ from those estimates. +Accounting for Business Combinations. We utilize the purchase method to account for acquisitions of businesses and assets. The value of the purchase consideration takes into account the degree to which the consideration is objective and measurable such as cash consideration paid to a seller. With the issuance of equity, restrictions upon the sale of the issued stock are taken into consideration. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired +60 +and liabilities assumed based on fair values as of the acquisition date. The purchase price allocations are based on appraisals, discounted cash flows, quoted market prices and estimates by management. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value as such sales represent the amount at which a willing buyer and seller would enter into an exchange for such properties. +In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped and unproved crude oil and natural gas properties. To estimate the fair values of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired, and estimates of future operating and development costs to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of comparable purchased properties to determine an estimation of fair value. +If applicable, we record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. +Acreage Exchanges . From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and providing us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges of non-producing interests and unproved mineral leases in accordance with the guidance prescribed by Accounting Standards Codification 845, Nonmonetary Transactions . For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized in earnings, in accordance with Accounting Standards Codification 820, Fair Value Measurement . +Recent Accounting Standards +See the footnote titled Summary of Significant Accounting Policies - Recently Adopted Accounting Standards to our consolidated financial statements included elsewhere in this report. +Reconciliation of Non-U.S. GAAP Financial Measures +We use "adjusted cash flows from operations," "free cash flow (deficit)," "adjusted net income (loss)" and "adjusted EBITDAX," non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and, in some cases, in providing public guidance on possible future results. In addition, we believe these are measures of our fundamental business and can be useful to us, investors, lenders and other parties in the evaluation of our performance relative to our peers and in assessing acquisition opportunities and capital expenditure projects. These supplemental measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss) or cash flows from operations, investing or financing activities and should not be viewed as liquidity measures or indicators of cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. In the future, we may disclose different non-U.S. GAAP financial measures in order to help us and our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure. +Adjusted cash flows from operations and free cash flow (deficit). We believe adjusted cash flows from operations can provide additional transparency into the drivers of trends in our operating cash flows, such as production, realized sales prices and operating costs, as it disregards the timing of settlement of operating assets and liabilities. We believe free cash flow (deficit) provides additional information that may be useful in an analysis of our ability to generate cash to fund exploration and development activities and to return capital to stockholders. +We are unable to present a reconciliation of forward-looking free cash flow because components of the calculation, including fluctuations in working capital accounts, are inherently unpredictable. Moreover, estimating the most directly +61 +comparable GAAP measure with the required precision necessary to provide a meaningful reconciliation is extremely difficult and could not be accomplished without unreasonable effort. We believe that forward-looking estimates of free cash flow are important to investors because they assist in the analysis of our ability to generate cash from our operations in excess of capital investments in crude oil and natural gas properties. +Adjusted net income (loss). We believe that adjusted net income (loss) provides additional transparency into operating trends, such as production, realized sales prices, operating costs and net settlements on commodity derivative contracts, because it disregards changes in our net income (loss) from mark-to-market adjustments resulting from net changes in the fair value of our unsettled commodity derivative contracts, and these changes are not directly reflective of our operating performance. +Adjusted EBITDAX. We believe that adjusted EBITDAX provides additional transparency into operating trends because it reflects the financial performance of our assets without regard to financing methods, capital structure, accounting methods or historical cost basis. In addition, because adjusted EBITDAX excludes certain non-cash expenses, we believe it is not a measure of income, but rather a measure of our liquidity and ability to generate sufficient cash for exploration, development, acquisitions and to service our debt obligations. +Beginning in the third quarter of 2019, we included a reconciling item for gains or losses on the sale of properties and equipment when calculating adjusted EBITDAX, thereby no longer including such gains or losses in our reported adjusted EBITDAX. We believe this methodology for calculating adjusted EBITDAX will enable greater comparability to our peers, as well as consistent treatment of adjustments for impairment and gains or losses on the sale of properties and equipment. For comparability, all prior periods presented have been conformed to the aforementioned methodology. +PV-10. We define PV-10 as the estimated present value of the future net cash flows from our proved reserves before income taxes, discounted using a 10 percent discount rate. We believe that PV-10 provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. We believe that PV-10 is relevant and useful for evaluating the relative monetary significance of our reserves. Professional analysts, investors and other users of our financial statements may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies' reserves. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable in evaluating us and our reserves. PV-10 is not intended to represent the current market value of our estimated reserves. +62 +The following table presents a reconciliation of each of our non-U.S. GAAP financial measures to its most comparable U.S. GAAP measure: +Year Ended December 31, +2019 +2018 +2017 +(in millions) +Cash flows from operations to adjusted cash flows from operations and free cash flow (deficit): +Net cash from operating activities +$ +858.2 +$ +889.3 +$ +597.8 +Changes in assets and liabilities +(32.8 +) +(80.9 +) +(15.7 +) +Adjusted cash flows from operations +825.4 +808.4 +582.1 +Capital expenditures for development of crude oil and natural gas properties +(855.9 +) +(946.4 +) +(737.2 +) +Change in accounts payable related to capital expenditures +68.2 +(36.3 +) +(50.8 +) +Free cash flow (deficit) +$ +37.7 +$ +(174.3 +) +$ +(205.9 +) +Net income (loss) to adjusted net income (loss): +Net income (loss) +$ +(56.7 +) +2.0 +$ +(127.5 +) +(Gain) loss on commodity derivative instruments +162.8 +(145.2 +) +3.9 +Net settlements on commodity derivative instruments +(17.6 +) +(115.5 +) +13.3 +Tax effect of above adjustments +(35.2 +) +62.4 +(4.1 +) +Adjusted net income (loss) +$ +53.3 +$ +(196.3 +) +$ +(114.4 +) +Net income (loss) to adjusted EBITDAX: +Net income (loss) +$ +(56.7 +) +$ +2.0 +$ +(127.5 +) +(Gain) loss on commodity derivative instruments +162.8 +(145.2 +) +3.9 +Net settlements on commodity derivative instruments +(17.6 +) +(115.5 +) +13.3 +Non-cash stock-based compensation +23.8 +21.8 +19.4 +Interest expense, net +71.1 +70.3 +76.4 +Income tax expense (benefit) +(3.3 +) +5.4 +(211.9 +) +Impairment of properties and equipment +38.5 +458.4 +285.9 +Impairment of goodwill +— +— +75.1 +Exploration, geologic and geophysical expense +4.1 +6.2 +47.3 +Depreciation, depletion and amortization +644.2 +559.8 +469.1 +Accretion of asset retirement obligations +6.1 +5.1 +6.4 +Loss on extinguishment of debt +— +— +24.7 +(Gain) loss on sale of properties and equipment +9.7 +0.4 +(0.7 +) +Adjusted EBITDAX +$ +882.7 +$ +868.7 +$ +681.4 +Cash from operating activities to adjusted EBITDAX: +Net cash from operating activities +$ +858.2 +$ +889.3 +$ +597.8 +Interest expense, net +71.1 +70.3 +76.4 +Amortization of debt discount and issuance costs +(13.6 +) +(12.8 +) +(12.9 +) +Exploration, geologic and geophysical expense +4.1 +6.2 +47.3 +Exploratory dry hole expense +— +(0.1 +) +(41.3 +) +Other +(4.3 +) +(3.3 +) +29.8 +Changes in assets and liabilities +(32.8 +) +(80.9 +) +(15.7 +) +Adjusted EBITDAX +$ +882.7 +$ +868.7 +$ +681.4 +PV-10: +PV-10 +$ +3,837.0 +$ +5,321.3 +$ +3,212.0 +Present value of estimated future income tax discounted at 10% +(526.7 +) +(873.6 +) +(331.9 +) +Standardized measure of discounted future net cash flows +$ +3,310.3 +$ +4,447.7 +$ +2,880.1 +63 +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Market-Sensitive Instruments and Risk Management +We are exposed to market risks associated with interest rate risks, commodity price risk and credit risk. We have established risk management processes to monitor and manage these market risks. +Interest Rate Risk +Changes in interest rates affect the amount of interest we earn on our interest bearing cash and cash equivalents and the interest we pay on borrowings under our revolving credit facility. Our 2021 Convertible Notes, 2024 Senior Notes and 2026 Senior Notes have fixed rates and, therefore, near-term changes in interest rates do not expose us to risk of earnings or cash flow loss; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt. +As of December 31, 2019 , our interest-bearing deposit accounts included money market accounts and checking accounts with various banks. The amount of our interest-bearing cash and cash equivalents as of December 31, 2019 was $ 0.4 million , with a weighted-average interest rate of one percent. Based on a sensitivity analysis of our interest bearing deposits as of December 31, 2019 and assuming we had $ 0.4 million outstanding throughout the period, we estimate that a one percent increase in interest rates would not have a material impact on interest income for the twelve months ended December 31, 2019 . +As of December 31, 2019 , we had $4.0 million outstanding balance on our revolving credit facility. If market interest rates would have increased or decreased by one percent, our interest expense for the twelve months ended December 31, 2019 would have changed by approximately $ 0.3 million . +Commodity Price Risk +We are exposed to the potential risk of loss from adverse changes in the market price of crude oil, natural gas and NGLs. Pursuant to established policies and procedures, we manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. These instruments help us predict with greater certainty the effective crude oil, natural gas and propane prices we will receive for our hedged production. We believe that our commodity derivative policies and procedures are effective in achieving our risk management objectives. +Our realized prices vary regionally based on local market differentials and our transportation agreements. The following table presents average market index prices for crude oil and natural gas for the periods identified, as well as the average sales prices we realized for our crude oil, natural gas and NGLs production: +Year Ended December 31, +2019 +2018 +Average NYMEX Index Price: +Crude oil (per Bbl) +NYMEX +$ +57.03 +$ +64.77 +Natural gas (per MMBtu) +NYMEX +$ +2.63 +$ +3.09 +Average Sales Price Realized: +Excluding net settlements on commodity derivatives +Crude oil (per Bbl) +$ +53.26 +$ +61.19 +Natural gas (per Mcf) +1.30 +1.85 +NGLs (per Bbl) +12.41 +22.14 +Based on a sensitivity analysis as of December 31, 2019 , we estimate that a 10 percent increase in natural gas, crude oil prices and the propane portion of NGLs prices, inclusive of basis, over the entire period for which we have commodity derivatives in place would have resulted in a decrease in the fair value of our derivative positions of $49.7 million, whereas a 10 percent decrease in prices would have resulted in an increase in fair value of $50.1 million. +64 +Credit Risk +Credit risk represents the loss that we would incur if a counterparty fails to perform under its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure and entering into transactions with high-quality counterparties. When exposed to significant credit risk, we analyze the counterparties’ financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We monitor the creditworthiness of significant counterparties through our credit committee, which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. While we believe that our credit risk analysis and monitoring procedures are reasonable, no amount of analysis can assure financial performance by our counterparties. +We primarily use financial institutions which are lenders in our revolving credit facility as counterparties for our derivative financial instruments. Disruption in the credit markets, changes in commodity prices and other factors may have a significant adverse impact on a number of financial institutions. To date, we have had no material counterparty default losses from our commodity derivative financial instruments. See the footnote titled Commodity Derivative Financial Instruments to our consolidated financial statements included elsewhere in this report for more detail on our commodity derivative financial instruments. +Our crude oil, natural gas and NGLs sales are concentrated with a few predominately large customers. This concentrates our credit risk exposure with a small number of large customers. +Disclosure of Limitations +Because the information above included only those exposures that existed at December 31, 2019 , it does not consider those exposures or positions which could arise after that date. Our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, our commodity price risk management strategies at the time and interest rates and commodity prices at the time. +65 +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Index to Consolidated Financial Statements, Financial Statement Schedule and Supplemental Information +Financial Statements: +Report of Independent Registered Public Accounting Firm +67 +Consolidated Balance Sheets - December 31, 2019 and 2018 +70 +Consolidated Statements of Operations - Years Ended December 31, 2019, 2018 and 2017 +71 +Consolidated Statements of Cash Flows - Years Ended December 31, 2019, 2018 and 2017 +72 +Consolidated Statements of Equity - Years Ended December 31, 2019, 2018 and 2017 +73 +Notes to Consolidated Financial Statements +74 +Supplemental Information - Unaudited: +Crude Oil and Natural Gas Information +115 +Quarterly Financial Information +123 +Financial Statement Schedule: +Schedule II - Valuation and Qualifying Accounts - Years Ended December 31, 2019, 2018 and 2017 +124 +66 +Report of Independent Registered Public Accounting Firm +To the Board of Directors and Stockholders of PDC Energy, Inc. +Opinions on the Financial Statements and Internal Control over Financial Reporting +We have audited the accompanying consolidated balance sheets of PDC Energy, Inc. and its subsidiaries (the “Company”) as of December 31, 2019 and 2018, and the related consolidated statements of operations, equity, and cash flows for each of the three years in the period ended December 31, 2019, including the related notes and financial statement schedule listed in the accompanying index (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO. +Change in Accounting Principle +As discussed in Note 2 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019. +Basis for Opinions +The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. +Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. +Definition and Limitations of Internal Control over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and +67 +expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Critical Audit Matters +The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. +Impairment Assessment of Proved Crude Oil and Natural Gas Properties +As described in Notes 2 and 8 to the consolidated financial statements, as of December 31, 2019 the Company’s proved crude oil and natural gas properties were approximately $6,241.8 million. Upon a triggering event or at least annually, the Company assesses its proved crude oil and natural gas properties for possible impairment by comparing the carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production, based upon prices at which the Company estimates the commodity will be sold. If net capitalized costs exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a future discounted cash flows analysis. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices, and estimated future cash flows. Management utilizes the services of independent petroleum engineers (management’s specialists) to estimate their proved crude oil and natural gas reserves. +The principal considerations for our determination that performing procedures relating to the valuation of proved crude oil and natural gas properties is a critical audit matter are there was significant judgment by management, including the use of management’s specialists, when developing the estimates of proved oil and natural gas reserves; which in turn led to a high degree of auditor judgment, effort, and subjectivity in performing procedures to evaluate management’s estimated future cash flows and significant assumptions, including estimates of reserves volumes, future operating and development costs, and future commodity prices, as well as the significant input of interest and net revenue interest inputs used in estimated future cash flows. +Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the impairment assessment of proved crude oil and natural gas properties and the development of future cash flows. These procedures also included, among others, evaluating the completeness and accuracy of ownership records, including inputs of interest and net revenue interests, and evaluating the significant assumptions and method used in the Company’s proved crude oil and natural gas impairment analysis. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimates of proved crude oil and natural gas reserves. As a basis for this work, the specialists’ qualifications and objectivity were understood, as well as the methods and assumptions used by the specialists. The procedures performed also included tests of the data used by the specialists and an evaluation of the specialist’s findings. When evaluating the assumptions relating to the estimates of reserves volumes, future operating and development costs, and future commodity prices, procedures performed included obtaining evidence related to the reasonableness of these assumptions, including whether the assumptions used were reasonable considering the past performance of the Company and whether the assumptions were consistent with evidence obtained in other areas of the audit. +Impairment Assessment of Unproved Crude Oil and Natural Gas Properties +As described in Notes 2 and 8 to the consolidated financial statements, unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized, by field, based on historical experience, acquisition dates, and average lease terms. During the year ended December 31, 2019, the Company recorded impairment charges related to unproved crude oil and natural gas properties of $10.6 million, including those related to unproved crude oil and natural gas properties, primarily resulting from identified current and anticipated leasehold expirations and management’s determination to no longer pursue plans to develop certain properties. As of December 31, 2019, the Company had approximately $403.4 million of unproved crude oil and natural gas properties. +68 +The principal considerations for our determination that performing procedures relating to the impairment assessment of unproved crude oil and natural gas properties is a critical audit matter are there was a high degree of auditor subjectivity and significant audit effort in performing procedures to test the completeness and accuracy of lease records, including leasehold expiration and evaluate plans to develop certain properties. As previously disclosed by management, a material weakness existed during the year related to this matter. +Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the impairment of unproved crude oil and natural gas properties, including the completeness and accuracy of lease records. These procedures also included, among others, evaluating the reasonableness of the Company’s unproved crude oil and natural gas impairment assessment by testing the completeness and accuracy of the lease records, including lease expirations, production data, and identification of dry holes. Procedures were also performed to evaluate the reasonableness of management’s plans to develop certain properties, including the Company’s approved capital budget and average cost to drill. +/s/PricewaterhouseCoopers LLP +Denver, Colorado +February 26, 2020 +We have served as the Company’s auditor since 2007. +69 +PDC ENERGY, INC. +Consolidated Balance Sheets +(in thousands, except share and per share data) +As of December 31, +2019 +2018 +Assets +Current assets: +Cash and cash equivalents +$ +963 +$ +1,398 +Accounts receivable, net +266,354 +181,434 +Fair value of derivatives +28,078 +84,492 +Prepaid expenses and other current assets +8,635 +7,136 +Total current assets +304,030 +274,460 +Properties and equipment, net +4,095,202 +4,002,862 +Assets held-for-sale, net +— +140,705 +Fair value of derivatives +3,746 +93,722 +Other assets +45,702 +32,396 +Total Assets +$ +4,448,680 +$ +4,544,145 +Liabilities and Stockholders' Equity +Liabilities +Current liabilities: +Accounts payable +$ +98,934 +$ +181,864 +Production tax liability +76,236 +60,719 +Fair value of derivatives +2,921 +3,364 +Funds held for distribution +98,393 +105,784 +Accrued interest payable +14,284 +14,150 +Other accrued expenses +70,462 +75,133 +Total current liabilities +361,230 +441,014 +Long-term debt +1,177,226 +1,194,876 +Deferred income taxes +195,841 +198,096 +Asset retirement obligations +95,051 +85,312 +Liabilities held-for-sale +— +4,111 +Fair value of derivatives +692 +1,364 +Other liabilities +283,133 +92,664 +Total liabilities +2,113,173 +2,017,437 +Commitments and contingent liabilities +Stockholders' equity +Common shares - par value $0.01 per share, 150,000,000 authorized, 61,652,412 and 66,148,609 issued as of December 31, 2019 and 2018, respectively +617 +661 +Additional paid-in capital +2,384,309 +2,519,423 +Retained earnings (deficit) +( 47,945 +) +8,727 +Treasury shares - at cost, 34,922 and 45,220 as of December 31, 2019 and 2018, respectively +( 1,474 +) +( 2,103 +) +Total stockholders' equity +2,335,507 +2,526,708 +Total Liabilities and Stockholders' Equity +$ +4,448,680 +$ +4,544,145 +See accompanying Notes to Consolidated Financial Statements +70 +PDC ENERGY, INC. +Consolidated Statements of Operations +(in thousands, except per share data) +Year Ended December 31, +2019 +2018 +2017 +Revenues +Crude oil, natural gas and NGLs sales +$ +1,307,275 +$ +1,389,961 +$ +913,084 +Commodity price risk management gain (loss), net +( 162,844 +) +145,237 +( 3,936 +) +Other income +11,692 +13,461 +12,468 +Total revenues +1,156,123 +1,548,659 +921,616 +Costs, expenses and other +Lease operating expenses +142,248 +130,957 +89,641 +Production taxes +80,754 +90,357 +60,717 +Transportation, gathering and processing expenses +46,353 +37,403 +33,220 +Exploration, geologic and geophysical expense +4,054 +6,204 +47,334 +General and administrative expense +161,753 +170,504 +120,370 +Depreciation, depletion and amortization +644,152 +559,793 +469,084 +Accretion of asset retirement obligations +6,117 +5,075 +6,306 +Impairment of properties and equipment +38,536 +458,397 +285,887 +Impairment of goodwill +— +— +75,121 +(Gain) loss on sale of properties and equipment +9,734 +394 +( 766 +) +Provision for uncollectible notes receivable +— +— +( 40,203 +) +Other expenses +11,317 +11,829 +13,157 +Total costs, expenses and other +1,145,018 +1,470,913 +1,159,868 +Income (loss) from operations +11,105 +77,746 +( 238,252 +) +Loss on extinguishment of debt +— +— +( 24,747 +) +Interest expense +( 71,171 +) +( 70,730 +) +( 78,694 +) +Interest income +72 +413 +2,261 +Income (loss) before income taxes +( 59,994 +) +7,429 +( 339,432 +) +Income tax (expense) benefit +3,322 +( 5,406 +) +211,928 +Net income (loss) +$ +( 56,672 +) +$ +2,023 +$ +( 127,504 +) +Earnings per share: +Basic +$ +( 0.89 +) +$ +0.03 +$ +( 1.94 +) +Diluted +$ +( 0.89 +) +$ +0.03 +$ +( 1.94 +) +Weighted-average common shares outstanding: +Basic +64,032 +66,059 +65,837 +Diluted +64,032 +66,303 +65,837 +See accompanying Notes to Consolidated Financial Statements +71 +PDC ENERGY, INC. +Consolidated Statements of Cash Flows +(in thousands) +Year Ended December 31, +2019 +2018 +2017 +Cash flows from operating activities: +Net income (loss) +$ +( 56,672 +) +$ +2,023 +$ +( 127,504 +) +Adjustments to net income (loss) to reconcile to net cash from operating activities: +Net change in fair value of unsettled commodity derivatives +145,246 +( 260,775 +) +17,260 +Depreciation, depletion and amortization +644,152 +559,793 +469,084 +Impairment of properties and equipment +38,536 +458,397 +285,887 +Accretion of asset retirement obligations +6,117 +5,075 +6,306 +Non-cash stock-based compensation +23,837 +21,782 +19,353 +(Gain) loss on sale of properties and equipment +9,734 +394 +( 766 +) +Amortization of debt discount and issuance costs +13,575 +12,769 +12,907 +Deferred income taxes +( 2,256 +) +6,105 +( 203,685 +) +Impairment of goodwill +— +— +75,121 +Exploratory dry hole costs +— +113 +41,297 +Provision for uncollectible notes receivable +— +— +( 40,203 +) +Loss on extinguishment of debt +— +— +24,747 +Other +3,155 +2,763 +2,265 +Total adjustments to net income (loss) to reconcile to net cash from operating activities: +882,096 +806,416 +709,573 +Changes in assets and liabilities: +Accounts receivable +( 88,304 +) +12,025 +( 60,546 +) +Other assets +( 11,560 +) +( 81 +) +3,364 +Production tax liability +22,240 +35,225 +31,316 +Accounts payable and accrued expenses +( 29,578 +) +16,261 +31,378 +Funds held for future distribution +( 7,298 +) +9,973 +24,472 +Asset retirement obligations +( 21,511 +) +( 13,341 +) +( 10,176 +) +Other liabilities +168,813 +20,801 +( 4,064 +) +Total changes in assets and liabilities +32,802 +80,863 +15,744 +Net cash from operating activities +858,226 +889,302 +597,813 +Cash flows from investing activities: +Capital expenditures for development of crude oil and natural gas properties +( 855,908 +) +( 946,350 +) +( 737,208 +) +Capital expenditures for other properties and equipment +( 20,839 +) +( 11,055 +) +( 5,094 +) +Acquisition of crude oil and natural gas properties +( 13,207 +) +( 180,026 +) +( 15,628 +) +Proceeds from sale of properties and equipment +2,105 +3,562 +9,991 +Proceeds from divestitures +202,076 +44,693 +— +Sale of promissory note +— +— +40,203 +Restricted cash +8,001 +1,249 +( 9,250 +) +Sale of short-term investments +— +— +49,890 +Purchase of short-term investments +— +— +( 49,890 +) +Net cash from investing activities +( 677,772 +) +( 1,087,927 +) +( 716,986 +) +Cash flows from financing activities: +Proceeds from revolving credit facility +1,577,000 +1,072,500 +— +Repayment of revolving credit facility +( 1,605,500 +) +( 1,040,000 +) +— +Proceeds from issuance of senior notes +— +— +592,366 +Redemption of senior notes +— +— +( 519,375 +) +Payment of debt issuance costs +( 72 +) +( 7,704 +) +( 50 +) +Purchase of treasury shares +( 154,363 +) +— +— +Purchase of treasury shares for employee stock-based compensation tax withholding obligations +( 4,003 +) +( 5,147 +) +( 6,672 +) +Principal payments under financing lease obligations +( 1,952 +) +( 1,495 +) +( 1,168 +) +Other +— +( 55 +) +( 103 +) +Net cash from financing activities +( 188,890 +) +18,099 +64,998 +Net change in cash, cash equivalents and restricted cash +( 8,436 +) +( 180,526 +) +( 54,175 +) +Cash, cash equivalents and restricted cash, beginning of year +9,399 +189,925 +244,100 +Cash, cash equivalents and restricted cash, end of year +$ +963 +$ +9,399 +$ +189,925 +See accompanying Notes to Consolidated Financial Statements +72 +PDC ENERGY, INC. +Consolidated Statements of Equity +(in thousands, except share data) +Common Stock +Treasury Stock +Shares +Amount +Additional Paid-in Capital +Shares +Amount +Retained Earnings +Total Stockholders' Equity +Balances, January 1, 2017 +65,704,568 +$ +657 +$ +2,489,557 +( 28,763 +) +$ +( 1,668 +) +$ +134,208 +$ +2,622,754 +Net loss +— +— +— +— +— +( 127,504 +) +( 127,504 +) +Stock-based compensation +250,512 +2 +19,351 +— +— +— +19,353 +Purchase of treasury shares for employee stock-based compensation tax withholding obligations +— +— +— +( 107,357 +) +( 6,672 +) +— +( 6,672 +) +Issuance of treasury shares +— +— +( 5,517 +) +83,228 +5,517 +— +— +Non-employee directors' deferred compensation plan +— +— +— +( 3,035 +) +( 185 +) +— +( 185 +) +Other +— +— +( 97 +) +— +— +— +( 97 +) +Balances, December 31, 2017 +65,955,080 +$ +659 +$ +2,503,294 +( 55,927 +) +$ +( 3,008 +) +$ +6,704 +$ +2,507,649 +Net income +— +— +— +— +— +2,023 +2,023 +Stock-based compensation +193,529 +2 +21,780 +— +— +— +21,782 +Purchase of treasury shares for employee stock-based compensation tax withholding obligations +— +— +— +( 102,647 +) +( 5,147 +) +— +( 5,147 +) +Issuance of treasury shares +— +— +( 5,561 +) +104,068 +5,561 +— +— +Non-employee directors' deferred compensation plan +— +— +— +9,286 +491 +— +491 +Other +— +— +( 90 +) +— +— +— +( 90 +) +Balances, December 31, 2018 +66,148,609 +$ +661 +$ +2,519,423 +( 45,220 +) +$ +( 2,103 +) +$ +8,727 +$ +2,526,708 +Net loss +— +— +— +— +— +( 56,672 +) +( 56,672 +) +Stock-based compensation +213,745 +2 +23,835 +— +— +— +23,837 +Purchase of treasury shares for employee stock-based compensation tax withholding obligations +— +— +— +( 106,151 +) +( 4,003 +) +— +( 4,003 +) +Retirement of treasury shares for employee stock-based compensation tax withholding obligations +( 3,803 +) +— +( 127 +) +3,803 +127 +— +— +Purchase of treasury shares +— +— +— +( 4,706,139 +) +( 154,363 +) +— +( 154,363 +) +Retirement of treasury shares +( 4,706,139 +) +( 46 +) +( 154,317 +) +4,706,139 +154,363 +— +— +Issuance of treasury shares +— +— +( 4,505 +) +112,646 +4,505 +— +— +Balance, December 31, 2019 +61,652,412 +$ +617 +$ +2,384,309 +( 34,922 +) +$ +( 1,474 +) +$ +( 47,945 +) +$ +2,335,507 +See accompanying Notes to Consolidated Financial Statements +73 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION +PDC Energy, Inc. is a domestic independent exploration and production company that acquires, explores and develops properties for the production of crude oil, natural gas and NGLs, with operations in the Wattenberg Field in Colorado and the Delaware Basin in Texas. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are primarily focused in the Wolfcamp zones. We previously operated properties in the Utica Shale in Southeastern Ohio; however, we divested these properties during the first quarter of 2018. As of December 31, 2019 , we owned an interest in approximately 2,649 productive gross wells. +The accompanying audited consolidated financial statements include the accounts of PDC and our wholly-owned subsidiaries. Pursuant to the proportionate consolidation method, our accompanying consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation. +The preparation of our consolidated financial statements in accordance with U.S. GAAP requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of crude oil, natural gas and NGLs sales revenue; crude oil, natural gas and NGLs reserves; estimates of unpaid revenues and unbilled costs; future cash flows from crude oil and natural gas properties; valuation of commodity derivative instruments; exploratory dry hole costs; impairment of proved and unproved properties; impairment of goodwill; valuation and allocations of purchased and exchanged businesses and assets; and valuation of deferred income tax assets . +Certain immaterial reclassifications have been made to our prior period balance sheet to conform to the current period presentation. The reclassifications had no impact on previously reported results. +NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Cash Equivalents. We consider all highly liquid investments with original maturities of three months or less to be cash equivalents. +Restricted Cash. At December 31, 2018 , our total cash, cash equivalents and restricted cash of $ 9.4 million was comprised of $ 1.4 million of cash and cash equivalents and $ 8.0 million of restricted cash. We included restricted cash in other assets at December 31, 2018 . We did not have any restricted cash at December 31, 2019 . +Commodity Derivative Financial Instruments. We are exposed to the effect of market fluctuations in the prices of crude oil, natural gas and NGLs. We employ established policies and procedures to manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. Our policy and our revolving credit facility prohibit the use of crude oil and natural gas derivative instruments for speculative purposes. +Derivative assets and liabilities are recorded on our consolidated balance sheets at fair value. We have elected not to designate any of our commodity derivative instruments as cash flow hedges. Accordingly, changes in the fair value of our commodity derivative instruments are recorded in the consolidated statements of operations. We have elected the normal purchase, normal sale exception for our crude oil and natural gas contracts; therefore, the effects of these contracts are not included in our derivative assets and liabilities. Classification of net settlements resulting from maturities and changes in fair value of unsettled commodity derivatives depends on the purpose of issuing or holding the derivative. The consolidated statements of cash flows reflects the net settlement of commodity derivative instruments in operating cash flows. +The calculation of the commodity derivative instrument's fair value is performed internally and, while we use common industry practices to develop our valuation techniques, changes in our pricing methodologies or the underlying assumptions could result in significantly different fair values. +74 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Properties and Equipment. +Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depleted by the unit-of-production method, based on estimated proved developed producing reserves. Property acquisition costs are depleted on the unit-of-production method based on estimated proved reserves. We have determined that we have two unit-of-production fields: the Wattenberg Field and the Delaware Basin. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations and common cost environments in these areas. We calculate quarterly depreciation, depletion and amortization ("DD&A") expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted for fourth quarter production. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized as a gain or loss. Upon the sale of individual wells or an insignificant portion of a field, the proceeds are credited to accumulated DD&A. +Exploration costs, including geologic and geophysical expenses, seismic costs on unproved leaseholds and delay rentals are charged to expense as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have found a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expense. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as suspended well costs until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the resulting accounting treatment is recorded . +Proved Property Impairment. Annually, or upon a triggering event, we assess our producing crude oil and natural gas properties for possible impairment by comparing carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production and prices at which we reasonably estimate the commodities will be sold. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserve volumes, future operating and development costs, future commodity prices and estimated future cash flows. The estimates of future prices may differ from current market prices of crude oil, natural gas and NGLs. Certain events, including but not limited to downward revisions in estimates of our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event, and therefore a possible impairment of our proved crude oil and natural gas properties. If carrying values exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a discounted future cash flows analysis. The impairment recorded is the amount by which the carrying values exceed fair value. Impairments are included in the consolidated statements of operations line item impairment of properties and equipment, with a corresponding impact on accumulated DD&A. +Unproved Property Impairment. Acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to expense. Unproved crude oil and natural gas properties with individually significant acquisition costs are periodically assessed for impairment. Unproved crude oil and natural gas properties which are not individually significant are amortized by field, based on our historical experience, acquisition dates and average lease terms. Impairment and amortization charges related to unproved crude oil and natural gas properties are charged to the consolidated statements of operations line item impairment of properties and equipment. +75 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Other Property and Equipment. Other property and equipment such as pipelines, vehicles, facilities, office furniture and equipment, buildings and computer hardware and software is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives, which range from two to 35 years . Total depreciation expense related to other property and equipment was $ 5.7 million , $ 8.5 million and $ 6.6 million in 2019 , 2018 and 2017 , respectively. +We review these long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying value of the asset exceeds the estimated future cash flows, an impairment charge is recognized in the amount by which the carrying value of the asset exceeds the fair value of the asset. Impairment and amortization charges related to other property and equipment are charged to the consolidated statements of operations line item impairment of properties and equipment. +Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed, the proceeds are applied and any resulting gain or loss is recognized. +Internal-Use Software. Internal-use software costs incurred during the development stage of our ERP software are capitalized. The development stage generally includes software design, configuration, testing and installation activities. Training and maintenance costs are expensed as incurred, while upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Capitalized internal-use software costs are depreciated over the estimated useful life of the underlying project on a straight-line basis upon completion of the project. As of December 31, 2019 and December 31, 2018 , our capitalized costs for internal-use software were $ 25.9 million and $ 1.4 million , respectively. +Capitalized Interest. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A expense is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our outstanding debt by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $ 13.4 million , $ 9.2 million and $ 5.0 million in 2019 , 2018 and 2017 , respectively. +Assets Held-for-Sale. Assets held-for-sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, earnings multiples or indicative bids, when available. Management considers historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected in the consolidated financial statements. DD&A expense is not recorded on assets once they are classified as held-for-sale. Assets classified as held-for-sale are expected to be disposed of within one year. +Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred tax assets to what we consider realizable. +Debt Issuance Costs. Debt issuance costs are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs for the 2021 Convertible Notes, the 2024 Senior Notes and the 2026 Senior Notes are included in long-term debt and the debt issuance costs for the revolving credit facility are included in other assets. +Asset Retirement Obligations. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value. The initial capitalized cost, net of salvage value, +76 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from, among other things, changes in retirement costs or the estimated timing of settling asset retirement obligations. +Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders’ equity. When we retire treasury shares, we charge any excess of cost over the par value to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings. +Revenue Recognition. Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of crude oil, natural gas or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For 2019 , 2018 and 2017 , the impact of any natural gas imbalances was not significant. +Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related agreement. We use the net-back method when control of the crude oil, natural gas or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. +We use the gross method of accounting when control of the crude oil, natural gas or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses. +Credit Risk and Allowance for Doubtful Accounts. Inherent to our industry is the concentration of crude oil, natural gas and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. We record an allowance for doubtful accounts representing our best estimate of probable losses from our existing accounts receivable. In making our estimate, we consider, among other things, our historical write-offs and the overall creditworthiness of our customers. +Accounting for Business Combinations. We utilize the purchase method to account for acquisitions of businesses. Pursuant to purchase method accounting, we allocate the cost of the acquisition to assets acquired and liabilities assumed based upon respective fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows, quoted market prices and estimates by management, which are Level 3 inputs. When appropriate, we review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. +In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped and unproved crude oil and natural gas properties. To estimate the fair value of these properties, we prepare estimates of crude oil and natural gas reserves. We estimate future prices by using the applicable forward pricing strip to apply to our estimate of reserve quantities acquired and estimates of future operating and development costs to arrive at an estimate of future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted-average cost of capital rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by +77 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of comparable purchased properties to determine an estimation of fair value. +If applicable, we record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities, except goodwill. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. +Acreage Exchanges . From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and providing us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges of non-producing interests and unproved mineral leases in accordance with the guidance prescribed by Accounting Standards Codification 845, Nonmonetary Transactions . For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized in earnings, in accordance with Accounting Standards Codification 820, Fair Value Measurement . +Stock-Based Compensation. Stock-based compensation is recognized in our financial statements based on the grant-date fair value of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the requisite service period for the entire award and we account for forfeitures of stock-based compensation awards as they occur. To the extent compensation cost relates to employees directly involved in crude oil and natural gas exploration and development activities or the development of internal-use software, such amounts may be capitalized to properties and equipment. Amounts not capitalized to properties and equipment are recognized in the related cost and expense line item in the consolidated statements of operations. +Recently Adopted Accounting Standards. +In February 2016, the Financial Accounting Standards Board ("FASB") issued an accounting update and subsequent amendments aimed at increasing the transparency and comparability among organizations by recognizing lease assets and liabilities on the balance sheet and disclosing key information about related leasing arrangements (the “New Lease Standard”). For leases with terms of more than 12 months, the accounting update requires lessees to recognize a right-of-use ("ROU") asset and lease liability for its right to use the underlying asset and the corresponding lease obligation. As provided by practical expedients, we made accounting policy elections to not recognize ROU assets and lease liabilities that arise from short-term leases and to not separate lease and non-lease components for any class of underlying asset. The FASB issued an accounting update which provides an optional transition practical expedient for the adoption of the New Lease Standard that, if elected, permits an organization to not evaluate the accounting for existing land easements that are not accounted for under the previous lease accounting standard. We elected this practical expedient, and accordingly, existing land easements at December 31, 2018 were not assessed. All new or modified land easements entered into after January 1, 2019 are evaluated under the New Lease Standard. The New Lease Standard does not apply to leases of mineral rights to explore for or use crude oil and natural gas. Adoption of the New Lease Standard resulted in increases to other assets of $ 20.1 million , other accrued expenses of $ 4.6 million and other liabilities of $ 15.5 million at January 1, 2019, with no adjustment to the opening balance of retained earnings. +78 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 3 - ACQUISITION +In January 2020, we merged with SRC in a transaction valued at $ 1.7 billion , inclusive of SRC's net debt. Upon closing, we issued approximately 39 million shares of our common stock to SRC shareholders and holders of SRC equity awards, reflecting the issuance of 0.158 of a share of our common stock in exchange for each outstanding share of SRC common stock and the cancellation of outstanding SRC equity awards pursuant to the terms of the Merger Agreement. We expect to account for the SRC Acquisition under the acquisition method of accounting for business combinations and are currently in the process of determining preliminary estimated acquisition date fair values of identifiable assets acquired and liabilities assumed. During 2019 , we recorded transaction costs related to the SRC Acquisition of $ 7.3 million , which are included in general and administrative expense. +As result of closing the SRC Acquisition, the borrowing base on our revolving credit facility increased to $ 2.1 billion and we elected to increase the aggregate commitment amount under our revolving credit facility to $ 1.7 billion . As part of the SRC acquisition, we assumed the SRC Senior Notes and paid off and terminated SRC's revolving credit facility, which had an outstanding balance of $ 165.0 million at closing. The indenture governing the SRC Senior Notes has a change of control provision pursuant to which, if a “Change of Control” occurs, the issuer is required to make an offer to repurchase the SRC Senior Notes at a price equal to 101 percent of the principal amount of the notes, together with any accrued and unpaid interest to the date of purchase. It was determined that the SRC Acquisition did result in a "Change of Control", and on January 17, 2020, we commenced an offer to repurchase the outstanding SRC Senior Notes. Upon expiration of the repurchase offer on February 18, 2020, holders of $ 447.7 million of the outstanding SRC Senior Notes accepted our redemption offer for a total redemption price of approximately $ 452.2 million , plus accrued and unpaid interest of $ 6.2 million . We funded the repurchase with proceeds from our revolving credit facility. +Additionally, in August 2019, effective upon on the closing of the SRC Acquisition, our Board approved an increase and extension to the Stock Repurchase Program from $ 200 million to $ 525 million with a target completion date of December 31, 2021. +79 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 4 - REVENUE RECOGNITION +On January 1, 2018, we adopted the new accounting standard that was issued by the FASB to provide a single, comprehensive model to determine the measurement of revenue and timing of when it is recognized and all related amendments (the “New Revenue Standard”) using the modified retrospective method. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. Based upon our review, we determined that the adoption of the New Revenue Standard would have reduced our crude oil, natural gas and NGLs sales by approximately $ 11.3 million in 2017 with a corresponding decrease in transportation, gathering and processing expenses and no impact on net earnings. To determine the impact on our crude oil, natural gas and NGLs sales and our transportation, processing and gathering expenses for 2018, we applied the new guidance to contracts that were not completed as of December 31, 2017. The adoption of the New Revenue Standard has not significantly impacted our net income. +Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for 2019 , 2018 and 2017 : +Year Ended December 31, +Revenue by Commodity and Operating Region +2019 +2018 +2017 (1) +(in thousands) +Crude oil +Wattenberg Field +$ +767,760 +$ +783,158 +$ +529,562 +Delaware Basin +252,929 +252,107 +82,677 +Utica Shale (2) +— +2,696 +12,814 +Total +$ +1,020,689 +$ +1,037,961 +$ +625,053 +Natural gas +Wattenberg Field +$ +137,143 +$ +130,073 +$ +131,792 +Delaware Basin +13,877 +32,010 +21,251 +Utica Shale (2) +— +1,109 +5,216 +Total +$ +151,020 +$ +163,192 +$ +158,259 +NGLs +Wattenberg Field +$ +94,347 +$ +132,820 +$ +104,298 +Delaware Basin +41,219 +55,148 +20,756 +Utica Shale (2) +— +840 +4,718 +Total +$ +135,566 +$ +188,808 +$ +129,772 +Revenue by Operating Region +Wattenberg Field +$ +999,250 +$ +1,046,051 +$ +765,652 +Delaware Basin +308,025 +339,265 +124,684 +Utica Shale (2) +— +4,645 +22,748 +Total +$ +1,307,275 +$ +1,389,961 +$ +913,084 +(1) +As we have elected the modified retrospective method of adoption for the New Revenue Standard, revenues for 2017 +have not been restated. Such changes would not have been material. +(2) +In March 2018, we completed the disposition of our Utica Shale properties. +80 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 5 - FAIR VALUE OF FINANCIAL INSTRUMENTS +Determination of Fair Value +Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. +Derivative Financial Instruments +We measure the fair value of our derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates such as the LIBOR curve for a similar duration of each outstanding position, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default swap rates and the duration of each outstanding derivative position. +We validate our fair value measurement by corroborating the original source of inputs, monitoring changes in valuation methods and assumptions, and through the review of counterparty statements and other supporting documentation. +Our crude oil and natural gas fixed-price swaps are included in Level 2. Our collars are included in Level 3. Our basis swaps are included in Level 2 and Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis: +As of December 31, +2019 +2018 +Significant Other +Observable +Inputs +(Level 2) +Significant +Unobservable +Inputs +(Level 3) +Total +Significant Other +Observable +Inputs +(Level 2) +Significant +Unobservable +Inputs +(Level 3) +Total +(in thousands) +Total assets +$ +22,886 +$ +8,938 +$ +31,824 +$ +118,521 +$ +59,693 +$ +178,214 +Total liabilities +( 3,089 +) +( 524 +) +( 3,613 +) +( 3,364 +) +( 1,364 +) +( 4,728 +) +Net asset +$ +19,797 +$ +8,414 +$ +28,211 +$ +115,157 +$ +58,329 +$ +173,486 +81 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents a reconciliation of our Level 3 assets measured at fair value: +Year Ended December 31, +2019 +2018 +2017 +(in thousands) +Fair value of Level 3 instruments, net asset (liability) beginning of period +$ +58,329 +$ +( 9,687 +) +$ +( 9,574 +) +Changes in fair value included in consolidated statements of operations line item: +Commodity price risk management gain (loss), net +( 41,749 +) +63,257 +6,241 +Settlements included in consolidated statements of operations line items: +Commodity price risk management gain (loss), net +( 8,166 +) +4,759 +( 6,354 +) +Fair value of Level 3 instruments, net asset (liability) end of period +$ +8,414 +$ +58,329 +$ +( 9,687 +) +Net change in fair value of Level 3 unsettled derivatives included in consolidated statements of operations line item: +Commodity price risk management gain (loss), net +$ +( 22,694 +) +$ +— +$ +( 866 +) +Total +$ +( 22,694 +) +$ +— +$ +( 866 +) +The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. There has been no change in the methodology we apply to measure the fair value of our Level 3 derivative contracts during the periods covered by the financial statements. +Non-Derivative Financial Assets and Liabilities +We utilize fair value on a nonrecurring basis to review our proved crude oil and natural gas properties for possible impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such assets. The fair value of the properties is determined based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. +The portion of our long-term debt related to our revolving credit facility approximates fair value due to the variable nature of related interest rates. We have not elected to account for the portion of our debt related to our senior notes under the fair value option; however, we have determined an estimate of the fair values based on measurements of trading activity and broker and/or dealer quotes, respectively, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes and convertible notes as of December 31, 2019 and 2018 : +As of December 31, +2019 +2018 +Estimated Fair Value +Percent of Par +Estimated Fair Value +Percent of Par +(in millions) +Senior notes: +2021 Convertible Notes +$ +188.6 +94.3 +% +$ +175.4 +87.7 +% +2024 Senior Notes +409.2 +102.3 +% +370.2 +92.5 +% +2026 Senior Notes +599.4 +99.9 +% +532.4 +88.7 +% +The carrying value of the financial instruments included in current assets and current liabilities approximate fair value due to the short-term maturities of these instruments. +82 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 6 - COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS +Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas we enter into commodity derivative contracts to protect against price declines in future periods. While we structure these commodity derivatives to reduce our exposure to decreases in commodity prices, they also limit the benefit we might otherwise receive from price increases. +We believe our commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. As of December 31, 2019 , we had derivative instruments, which were comprised of fixed-price swaps, collars and basis protection swaps, in place for a portion of our anticipated 2020 and 2021 production. Our commodity derivative contracts have been entered into at no upfront cost to us as we hedge our anticipated production at the then-prevailing commodity market prices, without adjustment for premium or discount. +As of December 31, 2019 , our derivative instruments were comprised of fixed-price swaps, collars and basis protection swaps. +• +Fixed-price swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty; +• +Collars contain a fixed floor price (put) and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty; +• +Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For basis protection swaps, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. +83 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +As of December 31, 2019 , we had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted-average contract price is shown. +Collars +Fixed-Price Swaps +Commodity/ Index/ +Maturity Period +Quantity +(Crude oil - +MBls +Natural Gas - BBtu) +Weighted-Average +Contract Price +Quantity (Crude Oil - MBbls +Gas and Basis- +BBtu) +Weighted- +Average +Contract +Price +Fair Value +December 31, +2019 (1) +(in thousands) +Floors +Ceilings +Crude Oil +NYMEX +2020 +3,600 +55.00 +71.68 +7,160 +60.98 +27,162 +2021 +— +— +— +3,200 +55.76 +3,054 +Total Crude Oil +3,600 +10,360 +$ +30,216 +Natural Gas +NYMEX +2020 +— +— +— +4,000 +2.30 +75 +Dominion South +2020 +— +— +— +14 +2.54 +— +Total Natural Gas +— +4,014 +$ +75 +Basis Protection - Natural Gas +CIG +2020 +— +$ +— +$ +— +20,500 +$ +( 0.62 +) +$ +( 2,392 +) +Waha +2020 +— +— +— +4,000 +( 1.40 +) +312 +Total Basis Protection - Natural Gas +— +24,500 +$ +( 2,080 +) +Commodity Derivatives Fair Value +$ +28,211 +(1) +Approximately 28.1 percent of the fair value of our commodity derivative assets and 14.5 percent of the fair value of our commodity derivative liabilities were measured using significant unobservable inputs (Level 3). +Subsequent to December 31, 2019 , we entered into commodity derivative positions covering approximately 1,000 MBbls and 2,000 MBbls of crude oil production for 2020 and 2021, respectively. Additionally, we received commodity derivative positions covering approximately 3,900 MBbls of crude oil production for 2020 as a result of the SRC Acquisition. +We have not elected to designate any of our derivative instruments as cash flow hedges; therefore, these instruments do not qualify for hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the consolidated statements of operations. +84 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the balance sheet location and fair value amounts of our derivative instruments as of December 31, 2019 and 2018 : +Fair Value +Derivative Instruments: +Consolidated Balance Sheet Line Item +2019 +2018 +(in thousands) +Derivative assets: +Current +Commodity derivative contracts +Fair value of derivatives +$ +27,766 +$ +84,492 +Basis protection derivative contracts +Fair value of derivatives +312 +— +28,078 +84,492 +Non-current +Commodity derivative contracts +Fair value of derivatives +3,746 +93,722 +Total derivative assets +$ +31,824 +$ +178,214 +Derivative liabilities: +Current +Commodity derivative contracts +Fair value of derivatives +$ +529 +748 +Basis protection derivative contracts +Fair value of derivatives +2,392 +2,616 +2,921 +3,364 +Non-current +Commodity derivative contracts +Fair value of derivatives +692 +1,364 +Total derivative liabilities +$ +3,613 +$ +4,728 +The following table presents the impact of our derivative instruments on our consolidated statements of operations: +Year Ended December 31, +Consolidated Statements of Operations Line Item +2019 +2018 +2017 +(in thousands) +Commodity price risk management gain (loss), net +Net settlements +$ +( 17,598 +) +$ +( 115,538 +) +$ +13,324 +Net change in fair value of unsettled derivatives +( 145,246 +) +260,775 +( 17,260 +) +Total commodity price risk management gain (loss), net +$ +( 162,844 +) +$ +145,237 +$ +( 3,936 +) +Our financial derivative agreements contain master netting provisions that provide for the net settlement of contracts through a single payment in the event of early termination. We have elected not to offset the fair value positions recorded on our consolidated balance sheets. +The following table reflects the impact of netting agreements on gross derivative assets and liabilities: +As of December 31, 2019 +Derivative Instruments, Gross +Effect of Master Netting Agreements +Derivative Instruments, Net +(in thousands) +Asset derivatives: +Derivative instruments, at fair value +$ +31,824 +$ +( 2,619 +) +$ +29,205 +Liability derivatives: +Derivative instruments, at fair value +$ +3,613 +$ +( 2,619 +) +$ +994 +85 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +As of December 31, 2018 +Derivative instruments, gross +Effect of Master Netting Agreements +Derivative Instruments, Net +(in thousands) +Asset derivatives: +Derivative instruments, at fair value +$ +178,214 +$ +( 3,985 +) +$ +174,229 +Liability derivatives: +Derivative instruments, at fair value +$ +4,728 +$ +( 3,985 +) +$ +743 +NOTE 7 - CONCENTRATION OF RISK +Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts: +As of December 31, +2019 +2018 +(in thousands) +Crude oil, natural gas and NGLs sales +$ +149,758 +$ +155,756 +Joint interest billings +29,510 +19,580 +Midstream asset divestitures deferred payments +81,702 +— +Derivative counterparties +— +3,937 +Other +12,860 +6,542 +Allowance for doubtful accounts +( 7,476 +) +( 4,381 +) +Accounts receivable, net +$ +266,354 +$ +181,434 +Our accounts receivable primarily relate to sales of our crude oil, natural gas and NGLs production, receivable balances from other third parties that own working interests in the properties we operate and derivative counterparties. For the years ended December 31, 2019 and 2018 , amounts written off to allowance for doubtful accounts were not material. As of December 31, 2019 and December 31, 2018 , four and three , respectively, of our customers represented 10 percent or more of our crude oil, natural gas and NGLs accounts receivable balance. +Major Customers. The following table presents the individual customers constituting 10 percent or more of total revenues: +Year Ended December 31, +Customer +2019 +2018 +2017 +Occidental Marketing, Inc. +20.0 +% +— +% +— +% +DCP Midstream, LP +17.0 +% +12.5 +% +19.6 +% +Mercuria Energy Trading, Inc. +16.0 +% +— +% +— +% +United Energy Trading, LLC +11.0 +% +— +% +— +% +Suncor Energy Marketing, Inc. +— +% +— +% +16.4 +% +Derivative Counterparties. We utilize commodity derivative instruments to manage a portion of our exposure to price volatility from producing crude oil, natural gas and NGLs. These arrangements expose us to credit risk of nonperformance by our counterparties. We primarily use financial institutions who are also lenders under our revolving credit facility as counterparties to our commodity derivative contracts. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our current counterparties on the fair value of our derivative instruments is not significant at December 31, 2019 . +86 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Other Accrued Expenses. The following table presents the components of other accrued expenses: +As of December 31, +2019 +2018 +(in thousands) +Employee benefits +$ +21,611 +$ +25,811 +Asset retirement obligations +32,200 +25,598 +Environmental expenses +2,256 +3,038 +Operating and finance leases +5,926 +1,779 +Other +8,469 +18,907 +Other accrued expenses +$ +70,462 +$ +75,133 +Other Liabilities. The following table presents the components of other liabilities as of: +As of December 31, +2019 +2018 +(in thousands) +Production taxes +$ +68,020 +$ +61,310 +Deferred oil gathering credits +20,100 +22,710 +Deferred midstream gathering credits +175,897 +— +Operating and finance leases +15,779 +2,900 +Other +3,337 +5,744 +Other liabilities +$ +283,133 +$ +92,664 +Deferred Oil Gathering Credits. In January 2018, we entered into an agreement that dedicates crude oil from the majority of our Wattenberg Field acreage to the midstream provider's gathering lines and extends the term of the agreement through December 2029. The payment is being amortized over the life of the agreement. Amortization charges related to this deferred oil gathering credit totaling approximately $ 2.0 million and $ 1.4 million for 2019 and 2018 , respectively, are included as a reduction to transportation, gathering and processing expenses. +Deferred Midstream Gathering Credits. In May 2019, concurrent with the sale of our Delaware Basin produced water gathering and disposal midstream assets, we entered into an agreement with the purchaser which dedicates all of our water gathering and disposal volumes in the Delaware Basin via pipeline for a term of 15 years . We recorded a long-term deferred credit of $ 40.5 million attributable to the value of the dedication, which is being amortized using the units-of-production basis. Amortization charges related to this deferred credit totaling $ 0.9 million for 2019 are included as a reduction to lease operating expenses and capital costs. +In May 2019, concurrent with the sale of our Delaware Basin crude oil gathering midstream assets, we entered into an agreement with the purchaser which provides us with gathering and transport for crude oil from dedicated acreage within an area of mutual interest for a term of 15 years . We recorded a long-term deferred credit of $ 28.9 million attributable to the value of the dedication, which is being amortized on a units-of-production basis. Amortization charges related to this deferred credit totaling $ 0.5 million for 2019 are included as crude oil sales. +In June 2019, concurrent with the sale of our Delaware Basin natural gas gathering midstream assets, we entered into an agreement with the purchaser which provides us with gathering, processing and transportation of our natural gas from certain dedicated leases for a term of 22 years . We recorded a long-term deferred credit of $ 110.2 million attributable to the value of the dedication, which is being amortized on a units-of-production basis. Amortization charges related to this deferred credit totaling $ 2.0 million for 2019 are included as a reduction to transportation, gathering and processing expenses. +87 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 8 - PROPERTIES AND EQUIPMENT +The following table presents the components of properties and equipment, net of accumulated DD&A: +As of December 31, +2019 +2018 +(in thousands) +Properties and equipment, net: +Crude oil and natural gas properties +Proved +$ +6,241,780 +$ +5,452,613 +Unproved +403,379 +492,594 +Total crude oil and natural gas properties +6,645,159 +5,945,207 +Infrastructure and other +41,888 +60,612 +Land and buildings +12,312 +11,243 +Construction in progress +408,428 +356,095 +Properties and equipment, at cost +7,107,787 +6,373,157 +Accumulated DD&A +( 3,012,585 +) +( 2,370,295 +) +Properties and equipment, net +$ +4,095,202 +$ +4,002,862 +Midstream Asset Divestitures. During 2019, we completed the sales of our Delaware Basin produced water gathering and disposal, crude oil gathering and natural gas gathering assets (the "Midstream Asset Divestitures") for aggregate proceeds of $ 345.6 million . Concurrent with the Midstream Asset Divestitures, we entered into agreements with the purchasers which provide us with certain gathering, processing, transportation and water disposal services. Proceeds were allocated first to the assets sold based upon the fair values of the tangible assets sold, with the remainder of $ 179.6 million allocated to the acreage dedication agreements. +In May 2019, we completed the sale of our produced water gathering and disposal midstream assets in the Delaware Basin for $ 126.3 million , subject to certain customary post-closing adjustments, plus potential future long-term incentive payments of up to $ 56.3 million . We recorded a gain on the sale of $ 25.7 million based on the fair value of the tangible assets sold during 2019 . +In May 2019, we also completed the sale of our crude oil gathering midstream assets in the Delaware Basin for $ 37.3 million , subject to certain customary post-closing adjustments, plus potential future long-term incentive payments of up to $ 15.2 million . We recorded a loss on the sale of $ 0.2 million based on the fair value of the tangible assets sold during 2019 . +In June 2019, we completed the sale of our natural gas gathering midstream assets in the Delaware Basin for $ 182.0 million ( $ 100.0 million of which was paid upon closing with the remaining $ 82.0 million to be paid in June 2020), subject to certain customary post-closing adjustments, plus potential future long-term incentive payments of up to $ 60.5 million . The $ 82.0 million receivable is included in accounts receivable at December 31, 2019 . We recorded a gain on the sale of $ 8.5 million based on the fair value of the tangible assets sold during 2019 . +The Midstream Asset Divestitures did not represent a strategic shift in our operations or have a significant impact on our operations or financial results; therefore, we did not account for the divested assets as discontinued operations. +Acreage Acquisition. In September 2019, we exchanged acreage located in Reeves County, Texas with a third party. As additional consideration for the acreage acquired, we paid $ 2.7 million in cash and recognized a loss of $ 45.6 million based on the carrying value of the acreage sold. +88 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Classification of Assets and Liabilities as Held-for-Sale. Assets held-for-sale at December 31, 2018 included assets sold in the Midstream Asset Divestitures and certain non-core Delaware Basin crude oil and natural gas properties. The following table presents balance sheet data related to assets and liabilities held-for-sale: +December 31, 2018 +(in thousands) +Assets +Properties and equipment, net +$ +137,448 +Other assets +3,257 +Total assets +$ +140,705 +Liabilities +Asset retirement obligation +$ +4,111 +Total liabilities +$ +4,111 +During 2019 , we sold certain Delaware Basin crude oil and natural gas properties for net cash proceeds of $ 33.4 million , which approximated the net book value, resulting in no gain or loss on the sale. +Impairment Charges. T he following table presents impairment charges recorded for properties and equipment: +Year Ended December 31, +2019 +2018 +2017 +(in thousands) +Impairment of proved and unproved properties +$ +10,599 +$ +458,397 +$ +285,465 +Amortization of individually insignificant unproved properties +— +— +422 +Impairment of infrastructure and other +27,937 +— +— +Total impairment of properties and equipment +$ +38,536 +$ +458,397 +$ +285,887 +During 2019 and 2018 , we recorded impairment charges totaling $ 10.6 million and $ 458.4 million , respectively, related to the divestiture of leaseholds and then-current and anticipated near-term leasehold expirations within our non-focus areas of the Delaware Basin that we determined not to develop. We determined the fair value of the properties based upon estimated future discounted cash flow, a Level 3 input, using estimated production and prices at which we reasonably expect the crude oil and natural gas will be sold. During 2019 , we also recorded impairments of $ 27.9 million related to certain midstream facility infrastructure in the Delaware Basin. Upon closing of the Midstream Asset Divestitures, it was determined that the net book value of these assets was not recoverable. +Suspended Well Costs. The following table presents the capitalized exploratory well cost pending determination of proved reserves and included in properties and equipment: +As of December 31, +2019 +2018 +(in thousands, except for number of wells) +Beginning balance +$ +12,188 +$ +15,448 +Additions to capitalized exploratory well costs pending the determination of proved reserves +31,901 +35,127 +Reclassifications to proved properties +( 28,011 +) +( 38,387 +) +Ending balance +$ +16,078 +$ +12,188 +Number of wells pending determination at period-end +4 +2 +During 2019, the two wells classified as exploratory at December 31, 2018 were reclassified as productive and four new wells drilled were classified as exploratory. +89 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Exploration Expenses. The following table presents the major components of exploration, geologic and geophysical expense: +Year Ended December 31, +2019 +2018 +2017 +(in thousands) +Exploratory dry hole costs +$ +— +$ +113 +$ +41,297 +Geological and geophysical costs, including seismic purchases +3,017 +3,401 +3,881 +Operating, personnel and other +1,037 +2,690 +2,156 +Total exploration, geologic and geophysical expense +$ +4,054 +$ +6,204 +$ +47,334 +Exploratory dry hole costs. During 2017, two exploratory dry holes, associated lease costs and related infrastructure assets in the Delaware Basin were expensed at a cost of $ 41.3 million . The conclusion to expense these items was based on our determination that the acreage on which these wells were drilled was exploratory in nature and, following drilling, that the hydrocarbon production was insufficient for the wells to be deemed economically viable. +NOTE 9 - GOODWILL +Goodwill that resulted from the purchase price allocation of a business combination in the Delaware Basin in December 2016 was determined to be $ 75.1 million . In 2017, we evaluated goodwill for impairment by performing a quantitative test, which involves comparing the estimated fair value of the goodwill reporting unit, which we define as the Delaware Basin, to the carrying value. The quantitative test resulted in a determination that a full impairment charge of $ 75.1 million was required; therefore, the charge was recorded in 2017. +NOTE 10 - LONG-TERM DEBT +Long-term debt consisted of the following as of: +As of December 31, +2019 +2018 +(in thousands) +Senior Notes: +1.125% Convertible Notes due September 2021: +Principal amount +$ +200,000 +$ +200,000 +Unamortized discount +( 14,763 +) +( 22,766 +) +Unamortized debt issuance costs +( 1,666 +) +( 2,640 +) +Net of unamortized discount and debt issuance costs +183,571 +174,594 +6.125% Senior Notes due September 2024: +Principal amount +400,000 +400,000 +Unamortized debt issuance costs +( 4,611 +) +( 5,590 +) +Net of unamortized debt issuance costs +395,389 +394,410 +5.75% Senior Notes due May 2026: +Principal amount +600,000 +600,000 +Unamortized debt issuance costs +( 5,734 +) +( 6,628 +) +Net of unamortized debt issuance costs +594,266 +593,372 +Total senior notes +1,173,226 +1,162,376 +Revolving Credit Facility: +Revolving credit facility due May 2023 +4,000 +32,500 +Total long-term debt, net of unamortized discount and debt issuance costs +$ +1,177,226 +$ +1,194,876 +Senior Notes +90 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +2021 Convertible Notes. In September 2016 , we issued $ 200 million of 1.125 % convertible notes due September 15, 2021 in a public offering. Interest at the rate of 1.125 % per year is payable in cash semiannually in arrears on March 15 and September 15 . +The 2021 Convertible Notes are convertible prior to March 15, 2021 only upon specified events and during specified periods and, thereafter, at any time, at an initial conversion rate of 11.7113 shares of our common stock per $ 1,000 principal amount of the 2021 Convertible Notes, which is equal to an initial conversion price of approximately $ 85.39 per share. The conversion rate is subject to adjustment upon certain events. Upon conversion, the 2021 Convertible Notes may be settled, at our sole election, in shares of our common stock, cash or a combination thereof. We have initially elected a combination settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the 2021 Convertible Notes in cash and to settle the excess conversion value, if any, in shares, as well as cash in lieu of fractional shares. +We may not redeem the 2021 Convertible Notes prior to their maturity date. If we undergo a "fundamental change", as defined in the indenture for the 2021 Convertible Notes, subject to certain conditions, holders of the 2021 Convertible Notes may require us to repurchase all or part of the 2021 Convertible Notes for cash at a price equal to 100 percent of the principal amount of the 2021 Convertible Notes to be repurchased, plus any accrued and unpaid interest. The occurrence of a fundamental change will also result in the 2021 Convertible Notes becoming convertible. +We allocated the gross proceeds of the 2021 Convertible Notes between the liability and equity components of the debt. The initial $ 160.5 million liability component was determined based on the fair value of similar debt instruments excluding the conversion feature priced on the same day we issued the 2021 Convertible Notes. The initial $ 39.5 million equity component represents the debt discount and was calculated as the difference between the fair value of the debt and the gross proceeds of the 2021 Convertible Notes. Approximately $ 4.8 million in costs associated with the issuance of the 2021 Convertible Notes were capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes. As of December 31, 2019 , the unamortized debt discount will be amortized over the remaining contractual term to maturity of the 2021 Convertible Notes. Based upon the December 31, 2019 stock price of $ 26.17 per share, the “if-converted” value of the 2021 Convertible Notes did not exceed the principal amount. +2024 Senior Notes. In September 2016 , we issued $ 400 million aggregate principal amount of 6.125 % senior notes due September 15, 2024 . Interest is payable semi-annually on March 15 and September 15 . Approximately $ 7.8 million in costs associated with the issuance of the 2024 Senior Notes were capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes. The 2024 Senior Notes are redeemable after September 15, 2019 at fixed redemption prices, currently 104.594 percent of the principal amount redeemed. +2026 Senior Notes. In November 2017, we issued $ 600.0 million aggregate principal amount 5.75 % senior notes due May 15, 2026. Interest is payable semi-annually on May 15 and November 15 . Approximately $ 7.6 million in costs associated with the issuance of the 2026 Senior Notes were capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes. +The 2026 Senior Notes are redeemable after May 15, 2021 at fixed redemption prices beginning at 104.313 percent of the principal amount redeemed. At any time prior to May 15, 2021 , we may redeem all or part of the 2026 Senior Notes at a make-whole price set forth in the indenture which generally approximates the present value of the redemption price at May 15, 2021 and remaining interest payments on the 2026 Senior Notes at the time of redemption. +At any time prior to May 15, 2021 we may redeem up to 35 percent of the outstanding 2026 Senior Notes with proceeds from certain equity offerings at a redemption price of 105.75 percent of the principal amount of the notes redeemed, plus accrued and unpaid interest, if at least 65 percent of the aggregate principal amount of the 2026 Senior Notes remains outstanding after each such redemption and the redemption occurs within 180 days after the closing of the equity offering. +The 2021 Convertible Notes, the 2024 Senior Notes and the 2026 Senior notes are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the notes; equal in right of payment to our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries. Our wholly-owned subsidiary, PDC Permian, Inc., is a guarantor of our obligations under the 2021 Convertible Notes, the 2024 Senior Notes and the 2026 Senior Notes. +91 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Upon the occurrence of a "change of control," as defined in the indenture for the 2024 Senior Notes and the 2026 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we may, under certain circumstances, be required to use the net cash proceeds of such asset sale to make an offer to purchase the notes at 100 percent of the principal amount, together with any accrued and unpaid interest to the date of purchase. +The indentures governing the 2024 Senior Notes and 2026 Senior Notes contain covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make investments; create certain liens; enter into agreements that restrict distributions or other payments by restricted subsidiaries to us; enter into transactions with affiliates; sell assets; consolidate or merge with or into other companies or transfer all or substantially of our assets; and create unrestricted subsidiaries. As of December 31, 2019 , we were in compliance with all covenants related to the 2021 Convertible Notes, 2024 Convertible Notes and the 2026 Senior Notes. +Revolving Credit Facility +In May 2018, we entered into a Fourth Amended and Restated Credit Agreement (the “Restated Credit Agreement”). Among other things, the Restated Credit Agreement provides for a maximum credit amount of $ 2.5 billion . The amount we may borrow under the Restated Credit Agreement is subject to certain limitations under our senior notes. In August 2019, we entered into a First Amendment to the Restated Credit Agreement (the "First Amendment"). The First Amendment primarily provided for certain borrowing in connection with the SRC Acquisition and modified certain sections of the Restated Credit Agreement to permit the consummation of the SRC Acquisition. In October 2019, as part of our semi-annual redetermination, the borrowing base on our revolving credit facility was reaffirmed at $ 1.6 billion and we elected to retain our commitment amount at $ 1.3 billion . +As a result of closing the SRC Acquisition, the borrowing base on our revolving credit facility increased to $ 2.1 billion and we elected to increase the aggregate commitment amount under our revolving credit facility to $ 1.7 billion . As part of the SRC acquisition, we assumed the SRC Senior Notes. The SRC Senior Notes contained a change of control provision pursuant to which, if the consummation of the SRC Acquisition resulted in a “Change of Control” under the indenture governing the SRC Senior Notes, we were required to make an offer to repurchase the SRC Senior Notes at a price equal to 101 percent of the principal amount of the notes, together with any accrued and unpaid interest to the date of purchase. It was determined that the SRC Acquisition did result in a "Change of Control", and on January 17, 2020, we commenced an offer to repurchase the outstanding SRC Senior Notes at 101 percent of the principal amount. See the footnote titled Acquisition for information regarding the redemption of the SRC Senior Notes. +The revolving credit facility is available for working capital requirements, capital investments, acquisitions, to support letters of credit and for general corporate purposes. The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. The borrowing base is subject to a semi-annual redetermination on November 1 and May 1 based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. Substantially all of our crude oil and natural gas properties have been mortgaged or pledged as security for our revolving credit facility. +The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greatest of the administrative agent's prime rate, the federal funds rate plus a premium and the rate for dollar deposits in the London interbank market (“LIBOR”) for one month plus a premium) or, at our election, a rate equal to LIBOR for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. As of December 31, 2019 , the applicable interest margin is 0.25 percent for the alternate base rate option or 1.25 percent for the LIBOR option, and the unused commitment fee is 0.375 percent . Principal payments are generally not required until the revolving credit facility expires in May 2023 , unless the borrowing base falls below the outstanding balance. +The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.0:1.0 and (b) not exceed a maximum leverage ratio of 4.0:1.0. As of December 31, 2019 , we were in compliance with all the revolving credit facility covenants. +As of December 31, 2019 and 2018 , debt issuance costs related to our revolving credit facility were $ 8.9 million +92 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +and $ 11.5 million , respectively, and are included in other assets. As of December 31, 2019 and 2018 , availability under our revolving credit facility was $ 1.3 billion . As of December 31, 2019 , the weighted-average interest rate on the outstanding balance on our revolving credit facility, exclusive of fees on the unused commitment, was five percent . +NOTE 11 - LEASES +On January 1, 2019, we adopted the New Lease Standard issued by the FASB. We determine if an arrangement is representative of a lease under the New Lease Standard at contract inception. ROU assets represent our right to use the underlying assets for the lease term and the corresponding lease liabilities represent our obligations to make lease payments arising from the leases. Operating and finance lease ROU assets and liabilities are recognized at the commencement date based on the present value of the expected lease payments over the lease term. As most of our leases do not provide an implicit interest rate, we utilize our incremental borrowing rate based on information available at the commencement date in determining the present value of lease payments. Subsequent measurement, as well as presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. Terms of our leases include options to extend or terminate the lease only when we can ascertain that it is reasonably certain we will exercise that option. +We have operating leases for office space and compressors and finance leases for vehicles. Our leases have remaining lease terms ranging from one to five years . The vehicle leases include options to renew for up to four years. Lease payments associated with vehicle leases also include a contractually stated residual value guarantee. +The following table presents the components of lease costs: +Lease Costs +Year Ended December 31, 2019 +(in thousands) +Operating lease costs +$ +4,917 +Finance lease costs: +Amortization of ROU assets +$ +1,961 +Interest on lease liabilities +252 +Total finance lease costs +$ +2,213 +Short-term lease costs +170,064 +Total lease costs +$ +177,194 +Our operating lease costs are recorded in lease operating expenses or general and administrative expense and our finance lease costs are recorded in DD&A expense and interest expense on our consolidated statements of operations. Our short-term lease costs include amounts that are capitalized as part of the cost of another asset and are recorded as properties and equipment or recognized as expense. +93 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the balance sheet classification and other information regarding our leases as of: +Leases +Consolidated Balance Sheet Line Item +December 31, 2019 +(in thousands) +Operating Leases: +Operating lease ROU assets +Other assets +$ +14,926 +Operating lease obligation - short-term +Other accrued expense +$ +4,159 +Operating lease obligation - long-term +Other liabilities +12,944 +Total operating lease liabilities +$ +17,103 +Finance Leases: +Finance lease ROU assets +Properties and equipment, net +$ +4,637 +Finance lease obligation - short-term +Other accrued expense +$ +1,767 +Finance lease obligation - long-term +Other liabilities +2,835 +Total finance lease liabilities +$ +4,602 +Weighted-average remaining lease term (years) +Operating leases +4.28 +Finance leases +3.17 +Weighted-average discount rate +Operating leases +5.0 +% +Finance leases +5.0 +% +Maturity of lease liabilities by year and in the aggregate, under operating and financing leases with terms of one year or more, as of December 31, 2019 consist of the following: +Operating Leases +Finance Leases +Total +(in thousands) +2020 +$ +4,847 +$ +1,949 +$ +6,796 +2021 +4,923 +1,423 +6,346 +2022 +5,016 +855 +5,871 +2023 +1,559 +637 +2,196 +2024 +950 +95 +1,045 +Thereafter +1,698 +— +1,698 +Total lease payments +18,993 +4,959 +23,952 +Less: Interest and discount +( 1,890 +) +( 357 +) +( 2,247 +) +Present value of lease liabilities +$ +17,103 +$ +4,602 +$ +21,705 +94 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 12 - ASSET RETIREMENT OBLIGATIONS +The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interest in crude oil and natural gas properties: +Year Ended December 31, +2019 +2018 +(in thousands) +Beginning balance +$ +115,021 +$ +87,306 +Obligations incurred with development activities +4,605 +2,793 +Obligations incurred with acquisition +2,882 +4,332 +Accretion expense +6,117 +5,075 +Revisions in estimated cash flows +28,991 +30,166 +Obligations discharged with asset retirements +( 23,426 +) +( 14,651 +) +Obligations discharged with divestitures +( 6,939 +) +— +Balance at December 31 +127,251 +115,021 +Liabilities held-for-sale +— +( 4,111 +) +Current portion +( 32,200 +) +( 25,598 +) +Long-term portion +$ +95,051 +$ +85,312 +Our estimated asset retirement obligations liability is based on historical experience in plugging and abandoning wells, estimated economic lives and estimated plugging, abandonment and surface reclamation costs considering federal and state regulatory requirements in effect at that time. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations liability, a corresponding adjustment is made to the properties and equipment balance. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as accretion expense. Short-term asset retirement obligations are included in other accrued expenses. +The revisions in estimated cash flows during 2019 and 2018 were primarily due to increases in the estimated surface reclamation costs to obtain final well pad reclamation approval from the applicable regulatory agencies. +NOTE 13 - COMMITMENTS AND CONTINGENCIES +Firm Transportation and Processing Agreements. We enter into contracts that provide firm transportation and processing on pipeline systems through which we transport or sell crude oil and natural gas. Satisfaction of the volume requirements includes volumes produced by us and purchased from third parties and other third-party working, royalty and overriding royalty interest owners, whose volumes we market on their behalf. Our consolidated statements of operations reflect our share of these firm transportation and processing costs. These contracts require us to pay these transportation and processing charges whether or not the required volumes are delivered. +95 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents gross volume information related to our long-term firm transportation, sales and processing agreements for pipeline capacity and water delivery and disposal commitments: +Year Ending December 31, +Area +2020 +2021 +2022 +2023 +Thereafter +Total +Expiration +Date +Natural gas (MMcf) +Wattenberg Field +30,608 +31,025 +31,025 +31,025 +63,992 +187,675 +August 31, 2026 +Delaware Basin +37,552 +28,241 +9,125 +9,125 +66,175 +150,218 +March 31, 2031 +Gas Marketing +7,136 +7,056 +4,495 +— +— +18,687 +August 31, 2022 +Total +75,296 +66,322 +44,645 +40,150 +130,167 +356,580 +Crude oil (MBbls) +Wattenberg Field +9,992 +16,243 +16,243 +12,567 +37,255 +92,300 +December 31, 2027 +Delaware Basin +8,784 +8,030 +8,030 +8,030 +— +32,874 +December 31, 2023 +Total +18,776 +24,273 +24,273 +20,597 +37,255 +125,174 +Water (MBbls) +Wattenberg Field +6,224 +6,207 +6,207 +6,206 +6,223 +31,067 +December 31, 2024 +Total +6,224 +6,207 +6,207 +6,206 +6,223 +31,067 +Dollar commitment (in thousands) +$ +85,159 +$ +106,322 +$ +101,107 +$ +85,774 +$ +202,532 +$ +580,894 +Wattenberg Field. We have entered into two facilities expansion agreements with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities. The midstream provider completed and turned on line the first of the two 200 MMcfd cryogenic plants in August 2018 and the second plant was completed in August 2019. We are bound to the volume requirements in these agreements on the first day of the calendar month following the actual in-service date of the relevant plant. Both agreements require baseline volume commitments, consisting of our gross wellhead volume delivered in November 2016 to this midstream provider, and incremental wellhead volume commitments of 51.5 MMcfd and 33.5 MMcfd for the first and second agreements, respectively, for seven years. We may be required to pay shortfall fees for any volumes under the 51.5 MMcfd and 33.5 MMcfd incremental commitments. We are currently satisfying the volume commitment. +Delaware Basin . In May 2018, we entered into a firm sales agreement that is effective from June 2018 through December 2023 with an integrated marketing company for our crude oil production in the Delaware Basin. Contracted volumes are currently 24,000 barrels of crude oil per day and decrease over time to 22,000 barrels of crude oil per day. This agreement is expected to provide price diversification through realization of export market pricing via a Corpus Christi terminal and exposure to Brent-weighted prices. +Crude Oil, Natural Gas and NGLs Sales . For 2019 , amounts related to long-term transportation volumes, net to our interest, for Wattenberg Field crude oil and Delaware Basin natural gas were $ 50.1 million and in accordance with the guidance in the New Revenue Standard, were netted against our crude oil and natural gas sales. In addition, for 2019 and 2018 , $ 1.9 million and $ 1.6 million , respectively, related to long-term transportation volumes were recorded in transportation, gathering and processing expense. Amounts related to long-term transportation volumes for Wattenberg Field crude oil and Utica Shale natural gas of $ 10.0 million for 2017 were recorded in transportation, gathering and processing expense. In March 2018, we completed the disposition of our Utica Shale properties. +Litigation and Legal Items. We are involved in various legal proceedings. We review the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in our best interests. We have provided the necessary estimated accruals in the accompanying balance sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity. +96 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Action Regarding Partnerships . In December 2017, we received an action entitled Dufresne, et al. v. PDC Energy, et al. (the "Dufresne Case"), filed in the United States District Court for the District of Colorado (the "District Court"). The original complaint stated that it was a derivative action brought by a number of limited partner investors seeking to assert claims for breach of fiduciary duties on behalf of our two affiliated partnerships, Rockies Region 2006 LP and Rockies Region 2007 LP (collectively, the "Partnerships"), against PDC. The complaint was subsequently amended to include putative class claims for breach of the partnership agreements. The plaintiffs also included claims against two of our senior officers and three independent members of the Board for allegedly aiding and abetting PDC's purported breach of fiduciary duty. We filed a motion to dismiss on July 31, 2018. On February 19, 2019, the District Court granted the motion to dismiss, in part. It dismissed all claims against the individuals named as defendants. It also held that that the plaintiffs were time-barred from using the failure to assign acreage to the Partnerships as grounds to support their claims for breach of fiduciary duty against PDC. On June 4, 2019, the District Court entered an order holding its opinion on the motion to dismiss in abeyance pending resolution of the Partnerships' bankruptcy cases and staying the litigation. As discussed in more detail below, the District Court in Colorado has dismissed the Dufresne Case. +Partnership Bankruptcy Filings. On October 30, 2018, the Partnerships filed petitions under Chapter 11 of the Bankruptcy Code (the "Chapter 11 Proceedings") in the United States Bankruptcy Court for the Northern District of Texas, Dallas Division (the "Bankruptcy Court"). Prior to the bankruptcy filings, PDC designated a third-party (the “Responsible Party”) to analyze strategic options for the Partnerships. After designation of the Responsible Party and before filing the Chapter 11 Proceedings, PDC and the Partnerships agreed to enter into a transaction pursuant to which PDC would acquire substantially all of the Partnerships’ assets through a Chapter 11 plan of liquidation and obtain a release of claims from the Partnerships, including the claims asserted in the Dufresne Case. In June 2019, the Responsible Party, PDC and the plaintiffs in the Dufresne Case reached a settlement of the matters raised in the Dufresne Case and the Chapter 11 Proceedings. The settlement, which settles all claims asserted against PDC, whether direct or derivative, including, but not limited to, the claims asserted in the Dufresne Case, was incorporated into an Amended Chapter 11 Plan (the “Amended Chapter 11 Plan”). The Disclosure Statement accompanying the Amended Chapter 11 Plan was approved by the Bankruptcy Court in August 2019 along with procedures for soliciting votes on the Amended Chapter 11 Plan. The Amended Chapter 11 Plan was distributed to the Partnership unit holders for voting. On October 2, 2019, the Bankruptcy Court held a hearing to consider confirmation of the Amended Chapter 11 Plan and, on October 3, 2019, entered an order confirming the Amended Chapter 11 Plan. The requirements for the Amended Chapter 11 Plan to become effective were met on October 21, 2019 (the “Effective Date”). As contemplated by the Amended Chapter 11 Plan, on the Effective Date, PDC funded the settlement payment, purchase price for the Partnership’s oil and gas assets and the administrative reserve. Additionally, the Partnership’s oil and gas assets were conveyed to PDC and PDC and the plaintiffs in the Dufresne Case submitted an agreed order dismissing the Dufresne Case with prejudice to the District Court. The District Court entered the agreed order on October 23, 2019, dismissing the Dufresne Case with prejudice. On December 5, 2019, the Bankruptcy Court entered orders approving final fee applications of the debtors' legal representatives and professional service providers, which were paid before the end of 2019, along with distributions of the settlement amount pursuant to the Amended Chapter 11 Plan to the Partnership unit holders. +Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as discussed herein, we are not aware of any material environmental claims existing as of December 31, 2019 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws or other environmental liabilities will not be discovered on our properties. Accrued environmental liabilities are recorded in other accrued expenses. The liability ultimately incurred with respect to a matter may exceed the related accrual. +On October 23, 2018, we agreed to an Administrative Order by Consent ("AOC") with the Colorado Oil and Gas Conservation Commission relating to a historical release discovered during the decommissioning of a location in Weld County, Colorado, pursuant to which, among other things, we agreed to a penalty of approximately $ 130,000 , of which 20 percent would be suspended subject to compliance with certain corrective actions identified in the AOC. In addition to the penalty, we agreed to timely complete certain corrective actions set forth in the AOC relating to procedures for completing future work on buried or partially buried produced water vessels, and to reestablish vegetation and otherwise reclaim the location. We have completed the corrective actions in a timely manner and some of our reclamation activities are ongoing. +In recent years, we have been executing a program to plug and abandon certain of our older vertical wells in the Wattenberg Field. A self-audit of final reclamation activities associated with site retirements, which we concluded in 2019, +97 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +identified deficiencies, including incomplete documentation and agency submittals, inadequate plant growth and incomplete earthwork. In December 2019, we formally disclosed these deficiencies to the COGCC and are working to close this backlog of site reclamation work. We do not believe potential penalties and other expenditures associated with this disclosure will have a material effect on our financial condition or results of operations, but they may exceed $100,000 . +Clean Air Act Agreement and Related Consent Decree. In June 2017, following our receipt of a 2015 Clean Air Act information request from the EPA and a 2015 compliance advisory from the Colorado Department of Public Health and Environment's (“CDPHE”) Air Pollution Control Division, the U.S. Department of Justice, on behalf of the EPA and the state of Colorado, filed a complaint against us in the U.S. District Court for the District of Colorado, claiming that we failed to operate and maintain certain condensate collection facilities at 65 facilities so as to minimize leakage of volatile organic compounds in compliance with applicable law. +In October 2017, we entered into a consent decree to resolve the lawsuit and the compliance advisory. Pursuant to the consent decree, we agreed to implement a variety of operational enhancements and mitigation and similar projects, including vapor control system modifications and verification, increased inspection and monitoring and installation of tank pressure monitors. The three primary elements of the consent decree are: (i) fine/supplemental environmental projects ( $ 1.5 million cash fine, plus $ 1 million in supplemental environmental projects) of which the cash fines and the full cost of supplemental environmental projects were paid in the first and third quarters of 2018, respectively, (ii) injunctive relief with an estimated cost of approximately $ 18 million , primarily representing capital enhancements to our operations and (iii) mitigation with an estimated cost of $ 1.7 million . Additionally, we are subject to the revised requirements of the COC entered into by SRC with CDPHE as described in "Risk Factors -We are subject to complex federal, state, local and other laws and regulations that adversely affect the cost and manner of doing business." We continue to incur costs associated with these activities. If we fail to comply fully with the requirements of the consent decree with respect to those matters, we could be subject to additional liability. We do not believe that the expenditures resulting from the settlement will have a material adverse effect on our consolidated financial statements. +We are in the process of implementing the consent decree program, recently expanded to include the COC. Over the course of its execution, we have identified certain immaterial deficiencies in our implementation of the program. We report these immaterial deficiencies to the appropriate authorities and remediate them promptly. We do not believe that the penalties and expenditures associated with the consent decree, including any sanctions associated with these deficiencies, will have a material effect on our financial condition or results of operations, but they may exceed $100,000 . +In addition, in December 2018, we were named as a nominal defendant in a derivative action filed in the Delaware chancery court. The complaint, which seeks unspecified monetary damages and various forms of equitable relief, alleges that certain current and former members of the Board violated their fiduciary duties, committed waste and were unjustly enriched by, among other things, failing to implement adequate environmental safeguards in connection with the issues that gave rise to the Department of Justice lawsuit and consent decree. We believe that this lawsuit is without merit but cannot predict its outcome. +Further, we could be the subject of other enforcement actions by regulatory authorities in the future relating to our past, present or future operations. +98 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 14 - COMMON STOCK +Stock-Based Compensation Plans +2018 Equity Incentive Plan . In May 2018, our stockholders approved a long-term equity compensation plan for our employees and non-employee directors (the “2018 Plan”). The 2018 Plan provides for a reserve of 1,800,000 shares of our common stock that may be issued pursuant to awards under the 2018 Plan and a term that expires in March 2028. Shares issued may be either authorized but unissued shares, treasury shares or any combination. Additionally, the 2018 Plan permits the reuse or reissuance of shares of common stock which were canceled, expired, forfeited or paid out in the form of cash. However, shares tendered or withheld to satisfy the exercise price of options or tax withholding obligations, and shares covering the portion of exercised stock-settled stock appreciation rights ("SARs") (regardless of the number of shares actually delivered), count against the share limit. Awards may be issued in the form of options, SARs, restricted stock, restricted stock units ("RSUs"), performance stock units ("PSUs") and other stock-based awards. Awards may vest over periods of continued service or the satisfaction of performance conditions set at the discretion of the Compensation Committee of the Board (the "Compensation Committee"), with a minimum one-year vesting period applicable to most awards. With regard to SARs and options, awards have a maximum exercisable period of ten years. We began issuing shares from the 2018 Plan during 2019. As of December 31, 2019 , there were 1,429,004 shares available for grant under the 2018 Plan. +2010 Long-Term Equity Compensation Plan . Our Amended and Restated 2010 Long-Term Equity Compensation Plan, which was most recently approved by stockholders in 2013 (as the same has been amended and restated from time to time, the "2010 Plan"), will remain outstanding and we may continue to use the 2010 Plan to grant awards. As of December 31, 2019 , there were 133,330 shares available for grant under the 2010 Plan. +The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented: +Year Ended December 31, +2019 +2018 +2017 +(in thousands) +Stock-based compensation expense +$ +23,837 +$ +21,782 +$ +19,353 +Income tax benefit +( 5,780 +) +( 5,210 +) +( 7,372 +) +Net stock-based compensation expense +$ +18,057 +$ +16,572 +$ +11,981 +Restricted Stock Units +Time-Based Awards. The fair value of the time-based RSUs is amortized ratably over the requisite service period, primarily three years. The time-based RSUs generally vest ratably on each anniversary following the grant date provided that a participant is continuously employed . +The following table presents the changes in non-vested time-based RSUs to all employees, including executive officers, for 2019 : +Shares +Weighted-Average +Grant Date +Fair Value per Share +Non-vested at December 31, 2018 +618,407 +$ +54.16 +Granted +588,899 +40.34 +Vested +( 307,450 +) +52.98 +Forfeited +( 103,930 +) +45.62 +Non-vested at December 31, 2019 +795,926 +45.51 +99 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: +As of/Year Ended December 31, +2019 +2018 +2017 +(in thousands, except per share data) +Total intrinsic value of time-based awards vested +$ +11,652 +$ +12,282 +$ +16,303 +Total intrinsic value of time-based awards non-vested +20,829 +18,404 +24,334 +Market price per share as of December 31, +26.17 +29.76 +51.54 +Weighted-average grant date fair value per share +40.34 +50.69 +65.14 +Total compensation cost related to non-vested time-based awards and not yet recognized in our consolidated statements of operations as of December 31, 2019 was $ 21.4 million . This cost is expected to be recognized over a weighted-average period of 1.7 years. +Performance Stock Units +Market-Based Awards. The fair value of the market-based PSUs is amortized ratably over the requisite service period, primarily three years. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved, with a maximum vesting period of three years. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved . +The Compensation Committee awarded a total of 139,197 market-based PSUs to our executive officers during 2019 . In addition to continuous employment, the vesting of these PSUs is contingent on our total stockholder return ("TSR"), which is essentially our stock price change including any dividends over a three-year period ending on December 31, 2021, as compared to the TSR of a group of peer companies over the same period. The PSUs will result in a payout between zero and 200 percent of the target PSUs awarded. T he weighted-average grant date fair value per PSU granted was computed using the Monte Carlo pricing model using the following assumptions: +Year Ended December 31, +2019 +2018 +2017 +Expected term of award (in years) +3 +3 +3 +Risk-free interest rate +2.5 +% +2.4 +% +1.4 +% +Expected volatility +41.4 +% +42.3 +% +51.4 +% +The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our historical volatility. +The following table presents the change in non-vested market-based awards during 2019 : +Shares +Weighted-Average +Grant Date +Fair Value per Share +Non-vested at December 31, 2018 +102,914 +$ +74.88 +Granted +139,197 +56.68 +Vested +( 20,969 +) +94.02 +Forfeited +— +— +Non-vested at December 31, 2019 +221,142 +61.61 +100 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: +As of/Year Ended December 31, +2019 +2018 +2017 +(in thousands, except per share data) +Total intrinsic value of market-based awards vested +$ +530 +$ +620 +$ +2,687 +Total intrinsic value of market-based awards non-vested +5,787 +3,063 +2,698 +Market price per share as of December 31, +26.17 +29.76 +51.54 +Weighted-average grant date fair value per share +56.68 +69.98 +94.02 +Total compensation cost related to non-vested market-based awards not yet recognized in our consolidated statements of operations as of December 31, 2019 was $ 7.5 million . This cost is expected to be recognized over a weighted-average period of 1.6 years. +Stock Appreciation Rights +The SARs vest ratably over a three-year period and may generally be exercised at any point after vesting through ten years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance. +The Compensation Committee awarded SARs to our executive officers in 2017 . There were no SARs awarded to our executive officers in 2018 or 2019 . The fair value of each SAR award was estimated on the date of grant using a Black-Scholes pricing model using the following assumptions: +Year Ended December 31, 2017 +Expected term of award (in years) +6 +Risk-free interest rate +2.0 +% +Expected volatility +53.3 +% +Weighted-average grant date fair value per share +$ +38.58 +The expected term of the award was estimated using historical stock option exercise behavior data. The risk-free interest rate was based on the U.S. Treasury yields approximating the expected life of the award in effect at the time of grant. Expected volatilities were based on our historical volatility. +The following table presents the changes in our SARs for all periods presented (in thousands, except per share data): +Year Ended December 31, +2019 +2018 +2017 +Number of +SARs +Weighted-Average +Exercise +Price +Average Remaining Contractual +Term (in years) +Aggregate Intrinsic +Value +Number of +SARs +Weighted-Average +Exercise +Price +Aggregate Intrinsic +Value +Number of +SARs +Weighted-Average +Exercise +Price +Aggregate Intrinsic +Value +Outstanding at January 1, +290,258 +$ +46.64 +4.6 +$ +125 +298,220 +$ +47.39 +$ +2,490 +244,078 +$ +41.36 +$ +7,620 +Awarded +— +— +— +— +— +— +— +54,142 +74.57 +— +Modified +— +— +— +— +63,969 +42.83 +— +— +— +— +Expired +— +— +— +— +( 71,931 +) +46.34 +— +— +— +— +Outstanding at December 31, +290,258 +46.64 +3.6 +41 +290,258 +46.64 +125 +298,220 +47.39 +2,490 +Exercisable at December 31, +276,775 +45.28 +3.4 +41 +260,101 +44.88 +125 +223,865 +43.28 +2,267 +101 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +We expect all SARs outstanding as of December 31, 2019 to vest in 2020. The SARS modified during 2018, as included in the table above, were related to one employee and the total compensation cost associated with the modification was not material to our consolidated statement of operations. Total compensation cost related to SARs granted and not yet recognized in our consolidated statements of operations as of December 31, 2019 is not material and will be recognized within the next twelve months. +Preferred stock +We are authorized to issue 50,000,000 shares of preferred stock, par value $0.01 per share, which may be issued in one or more series, with such rights, preferences, privileges and restrictions as shall be fixed by the Board from time to time. Through December 31, 2019 , no shares of preferred shares had been issued . +Stock Repurchase Program +In April 2019, the Board approved a Stock Repurchase Program to acquire up to $ 200 million of our outstanding common stock, depending on market conditions. Repurchases under the Stock Repurchase Program can be made in open markets at our discretion and in compliance with safe harbor provisions, or in privately negotiated transactions. The Stock Repurchase Program does not require any specific number of shares to be acquired, and can be modified or discontinued by the Board at any time. During 2019 , we repurchased 4.7 million shares of our outstanding common stock at a cost of $ 154.4 million pursuant to the Stock Repurchase Program. Subsequent to December 31, 2019 , we repurchased approximately 0.6 million shares of our outstanding common stock at a cost of $ 12.5 million . Effective upon on the closing of the SRC Acquisition, our Board approved an increase and extension to the Stock Repurchase Program from $ 200 million to $ 525 million . As of February 24, 2020 , $358.2 million of our outstanding common stock remained available for repurchase under the Stock Repurchase Program. Our target completion date for the Stock Repurchase Program is December 31, 2021. +NOTE 15 - INCOME TAXES +The table below presents the components of our provision for income tax (expense) benefit for the years presented: +Year Ended December 31, +2019 +2018 +2017 +(in thousands) +Current: +Federal +$ +1,366 +$ +887 +$ +8,443 +State +( 300 +) +( 188 +) +( 200 +) +Total current income tax benefit +1,066 +699 +8,243 +Deferred: +Federal +4,507 +( 1,986 +) +193,809 +State +( 2,251 +) +( 4,119 +) +9,876 +Total deferred income tax (expense) benefit +2,256 +( 6,105 +) +203,685 +Income tax (expense) benefit +$ +3,322 +$ +( 5,406 +) +$ +211,928 +102 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents a reconciliation of the federal statutory rate to the effective tax rate related to our (expense) benefit for income taxes: +Year Ended December 31, +2019 +2018 +2017 +Federal statutory tax rate +21.0 +% +21.0 +% +35.0 +% +State income tax, net +3.6 +( 6.4 +) +1.8 +Federal tax credits +( 3.3 +) +( 52.1 +) +— +Effect of state income tax rate changes +( 6.4 +) +6.7 +— +Change in valuation allowance +( 0.6 +) +45.5 +— +Non-deductible compensation +( 5.0 +) +21.8 +( 0.3 +) +Non-deductible acquisition costs +( 2.3 +) +— +— +Non-deductible government relations +( 1.0 +) +31.8 +— +Other non-deductible items +( 0.5 +) +4.9 +— +Federal tax reform rate reduction +— +— +33.7 +Non-deductible goodwill impairment +— +— +( 7.7 +) +Other +— +( 0.4 +) +( 0.1 +) +Effective tax rate +5.5 +% +72.8 +% +62.4 +% +T ax effects of temporary differences that give rise to significant portions of deferred tax assets and deferred tax liabilities at December 31, 2019 and 2018 are presented below. +As of December 31, +2019 +2018 +(in thousands) +Deferred tax assets: +Deferred compensation +$ +9,905 +$ +9,963 +Asset retirement obligations +30,993 +27,166 +Federal NOL carryforward +22,965 +54,736 +State NOL and tax credit carryforwards, net +9,508 +13,223 +Federal tax - credit carryforwards +4,448 +7,756 +Prepaid revenue +4,874 +5,288 +Other +3,887 +4,647 +Valuation allowance +( 3,775 +) +( 3,380 +) +Total gross deferred tax assets +82,805 +119,399 +Deferred tax liabilities: +Properties and equipment +268,234 +270,565 +Net change in fair value of unsettled derivatives +6,841 +41,496 +Convertible debt +3,571 +5,434 +Total gross deferred tax liabilities +278,646 +317,495 +Net deferred tax liability +$ +195,841 +$ +198,096 +As of December 31, 2019 , we have prior year federal NOL carryforwards of $ 175.7 million of which $ 31.5 million will begin to expire in 2036. Also, we acquired a federal NOL of $ 60.1 million as a component of our 2016 acquisition in the Delaware Basin that will begin to expire in 2034 and is subject to an annual limitation of $ 15.1 million as a result of the acquisition, which constitutes a change of ownership as defined under IRS Code Section 382. We expect to utilize $ 126.4 million of these NOLs to offset current federal taxable income. +As of December 31, 2019 , we have state NOL carryforwards of $ 265.9 million that begin to expire in 2030 and state credit carryforwards of $ 4.0 million that begin to expire in 2022 . We expect to utilize $ 98.0 million of these NOLs to offset current state taxable income. Due to the potential non-utilization of our state tax credit carryforwards before their expiration, we have recorded a valuation allowance for the future tax benefit of these credit carryforwards. +Unrecognized tax benefits and related accrued interest and penalties were immaterial for the three-year period ended December 31, 2019 . The statutes of limitations for most of our state tax jurisdictions are open for tax year 2015 forward. +103 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The IRS partially accepted our 2018 tax return. The 2018 tax return is in the IRS CAP Program post-filing review process, with no significant tax adjustments currently proposed. We continue to voluntarily participate in the IRS CAP Program for the 2019 and 2020 tax years. Participation in the IRS CAP Program has enabled us to have minimal uncertain tax benefits associated with our federal tax return filings. +NOTE 16 - EARNINGS PER SHARE +Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested restricted stock, outstanding SARs, convertible notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. +The following table presents our weighted-average basic and diluted shares outstanding: +Year Ended December 31, +2019 +2018 +2017 +(in thousands) +Weighted-average common shares outstanding - basic +64,032 +66,059 +65,837 +Dilutive effect of: +RSUs and PSUs +— +173 +— +Other equity-based awards +— +71 +— +Weighted-average common shares and equivalents outstanding - diluted +64,032 +66,303 +65,837 +For 2019 and 2017 , we reported a net loss. As a result, our basic and diluted weighted-average common shares outstanding were the same for those periods because the effect of the common share equivalents was anti-dilutive. +The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect: +Year Ended December 31, +2019 +2018 +2017 +(in thousands) +Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: +RSUs and PSUs +989 +145 +590 +Other equity-based awards +302 +109 +75 +Total anti-dilutive common share equivalents +1,291 +254 +665 +The 2021 Convertible Notes give the holders, at our election, the right to convert the aggregate principal amount into 2.3 million shares of our common stock at a conversion price of $ 85.39 per share. The 2021 Convertible Notes could be included in the diluted earnings per share calculation using the treasury stock method if the average market share price exceeds the $ 85.39 conversion price during the periods presented. During 2019 , 2018 and 2017 , the average market price of our common stock did not exceed the conversion price; therefore, shares issuable upon conversion of the 2021 Convertible Notes were not included in the diluted earnings per share calculation. +104 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 17 - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION +Year Ended December 31, +2019 +2018 (1) +2017 (1) +(in thousands) +Supplemental cash flow information: +Cash payments (receipts) for: +Interest, net of capitalized interest +$ +57,439 +$ +55,586 +$ +69,880 +Income taxes +( 1,167 +) +( 6,719 +) +( 13,925 +) +Non-cash investing and financing activities: +Change in accounts payable related to capital expenditures +( 68,246 +) +36,328 +50,761 +Change in asset retirement obligation, with a corresponding change to crude oil and natural gas properties, net of disposal +29,533 +37,136 +839 +Cash paid for amounts included in the measurement of lease liabilities: +Operating cash flows from operating leases +$ +5,301 +$ +— +$ +— +Operating cash flows from finance leases +253 +— +— +Financing cash flows from finance leases +1,952 +— +— +ROU assets obtained in exchange for lease obligations: +Operating leases +$ +1,428 +$ +— +$ +— +Finance leases +2,323 +— +— +(1) As we have elected the modified retrospective method of adoption for the New Lease, cash flows related to lease liabilities +have not been restated for 2018 and 2017. +105 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 18 - SUBSIDIARY GUARANTOR +PDC Permian, Inc., our wholly-owned subsidiary, guarantees our obligations under our publicly-registered senior notes. The following presents the consolidating financial information separately for: +(i) +PDC Energy, Inc. ("Parent"), the issuer of the guaranteed obligations, including non-material subsidiaries; +(ii) +PDC Permian, Inc., the guarantor subsidiary ("Guarantor"), as specified in the indentures related to our senior notes; +(iii) +Eliminations representing adjustments to (a) eliminate intercompany transactions between or among Parent, Guarantor and our other subsidiaries and (b) eliminate the investments in our subsidiaries; and +(iv) +Parent and subsidiaries on a consolidated basis ("Consolidated"). +The Guarantor is 100 percent owned by the Parent. The senior notes are fully and unconditionally guaranteed on a joint and several basis by the Guarantor. The guarantee is subject to release in limited circumstances only upon the occurrence of certain customary conditions. Each entity in the consolidating financial information follows the same accounting policies as described in the notes to the consolidated financial statements. +The following consolidating financial statements have been prepared on the same basis of accounting as our consolidated financial statements. Investments in subsidiaries are accounted for under the equity method. Accordingly, the entries necessary to consolidate the Parent and Guarantor are reflected in the eliminations column. +106 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Consolidating Balance Sheets +December 31, 2019 +Parent +Guarantor +Eliminations +Consolidated +(in thousands) +Assets +Current assets: +Cash and cash equivalents +$ +963 +$ +— +$ +— +$ +963 +Accounts receivable, net +140,742 +125,612 +— +266,354 +Fair value of derivatives +28,078 +— +— +28,078 +Prepaid expenses and other current assets +8,204 +431 +— +8,635 +Total current assets +177,987 +126,043 +— +304,030 +Properties and equipment, net +2,328,337 +1,766,865 +— +4,095,202 +Intercompany receivable +348,818 +— +( 348,818 +) +— +Investment in subsidiaries +1,286,931 +— +( 1,286,931 +) +— +Fair value of derivatives +3,746 +— +— +3,746 +Other assets +38,863 +6,839 +— +45,702 +Total Assets +$ +4,184,682 +$ +1,899,747 +$ +( 1,635,749 +) +$ +4,448,680 +Liabilities and Stockholders' Equity +Liabilities +Current liabilities: +Accounts payable +$ +72,212 +$ +26,722 +$ +— +$ +98,934 +Production tax liability +67,509 +8,727 +— +76,236 +Fair value of derivatives +2,921 +— +— +2,921 +Funds held for distribution +83,072 +15,321 +— +98,393 +Accrued interest payable +14,281 +3 +— +14,284 +Other accrued expenses +68,803 +1,659 +— +70,462 +Total current liabilities +308,798 +52,432 +— +361,230 +Intercompany payable +— +348,818 +( 348,818 +) +— +Long-term debt +1,177,226 +— +— +1,177,226 +Deferred income taxes +169,520 +26,321 +— +195,841 +Asset retirement obligations +87,749 +7,302 +— +95,051 +Fair value of derivatives +692 +— +— +692 +Other liabilities +105,190 +177,943 +— +283,133 +Total liabilities +1,849,175 +612,816 +( 348,818 +) +2,113,173 +Commitments and contingent liabilities +Stockholders' equity +Common shares +617 +— +— +617 +Additional paid-in capital +2,384,309 +1,766,775 +( 1,766,775 +) +2,384,309 +Retained deficit +( 47,945 +) +( 479,844 +) +479,844 +( 47,945 +) +Treasury shares +( 1,474 +) +— +— +( 1,474 +) +Total stockholders' equity +2,335,507 +1,286,931 +( 1,286,931 +) +2,335,507 +Total Liabilities and Stockholders' Equity +$ +4,184,682 +$ +1,899,747 +$ +( 1,635,749 +) +$ +4,448,680 +107 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Consolidating Balance Sheets +December 31, 2018 +Parent +Guarantor +Eliminations +Consolidated +(in thousands) +Assets +Current assets: +Cash and cash equivalents +$ +1,398 +$ +— +$ +— +$ +1,398 +Accounts receivable, net +146,529 +34,905 +— +181,434 +Fair value of derivatives +84,492 +— +— +84,492 +Prepaid expenses and other current assets +6,725 +411 +— +7,136 +Total current assets +239,144 +35,316 +— +274,460 +Properties and equipment, net +2,270,711 +1,732,151 +— +4,002,862 +Assets held-for-sale, net +— +140,705 +— +140,705 +Intercompany receivable +451,601 +— +( 451,601 +) +— +Investment in subsidiaries +1,316,945 +— +( 1,316,945 +) +— +Fair value of derivatives +93,722 +— +— +93,722 +Other assets +30,084 +2,312 +— +32,396 +Total Assets +$ +4,402,207 +$ +1,910,484 +$ +( 1,768,546 +) +$ +4,544,145 +Liabilities and Stockholders' Equity +Liabilities +Current liabilities: +Accounts payable +$ +110,847 +$ +71,017 +$ +— +$ +181,864 +Production tax liability +53,309 +7,410 +— +60,719 +Fair value of derivatives +3,364 +— +— +3,364 +Funds held for distribution +90,183 +15,601 +— +105,784 +Accrued interest payable +14,143 +7 +— +14,150 +Other accrued expenses +73,689 +1,444 +— +75,133 +Total current liabilities +345,535 +95,479 +— +441,014 +Intercompany payable +— +451,601 +( 451,601 +) +— +Long-term debt +1,194,876 +— +— +1,194,876 +Deferred income taxes +162,368 +35,728 +— +198,096 +Asset retirement obligations +79,904 +5,408 +— +85,312 +Liabilities held-for-sale +— +4,111 +— +4,111 +Fair value of derivatives +1,364 +— +— +1,364 +Other liabilities +91,452 +1,212 +— +92,664 +Total liabilities +1,875,499 +593,539 +( 451,601 +) +2,017,437 +Commitments and contingent liabilities +Stockholders' equity +Common shares +661 +— +— +661 +Additional paid-in capital +2,519,423 +1,766,775 +( 1,766,775 +) +2,519,423 +Retained earnings (deficit) +8,727 +( 449,830 +) +449,830 +8,727 +Treasury shares +( 2,103 +) +— +— +( 2,103 +) +Total stockholders' equity +2,526,708 +1,316,945 +( 1,316,945 +) +2,526,708 +Total Liabilities and Stockholders' Equity +$ +4,402,207 +$ +1,910,484 +$ +( 1,768,546 +) +$ +4,544,145 +108 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Consolidating Statements of Operations +Year Ended December 31, 2019 +Parent +Guarantor +Eliminations +Consolidated +(in thousands) +Revenues +Crude oil, natural gas and NGLs sales +$ +999,250 +$ +308,025 +$ +— +$ +1,307,275 +Commodity price risk management loss, net +( 162,844 +) +— +— +( 162,844 +) +Other income +10,972 +720 +— +11,692 +Total revenues +847,378 +308,745 +— +1,156,123 +Costs, expenses and other +Lease operating expenses +94,829 +47,419 +— +142,248 +Production taxes +61,577 +19,177 +— +80,754 +Transportation, gathering and processing expenses +23,719 +22,634 +— +46,353 +Exploration, geologic and geophysical expense +1,111 +2,943 +— +4,054 +General and administrative expense +144,345 +17,408 +— +161,753 +Depreciation, depletion and amortization +451,282 +192,870 +— +644,152 +Accretion of asset retirement obligations +5,446 +671 +— +6,117 +Impairment of properties and equipment +292 +38,244 +— +38,536 +(Gain) loss on sale of properties and equipment +( 853 +) +10,587 +— +9,734 +Other expenses +11,317 +— +— +11,317 +Total costs, expenses and other +793,065 +351,953 +— +1,145,018 +Income (loss) from operations +54,313 +( 43,208 +) +— +11,105 +Interest expense +( 75,257 +) +4,086 +— +( 71,171 +) +Interest income +71 +1 +— +72 +Loss before income taxes +( 20,873 +) +( 39,121 +) +— +( 59,994 +) +Income tax (expense) benefit +( 5,784 +) +9,106 +— +3,322 +Equity in loss of subsidiary +( 30,015 +) +— +30,015 +— +Net loss +$ +( 56,672 +) +$ +( 30,015 +) +$ +30,015 +$ +( 56,672 +) +109 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Consolidating Statements of Operations +Year Ended December 31, 2018 +Parent +Guarantor +Eliminations +Consolidated +(in thousands) +Revenues +Crude oil, natural gas and NGLs sales +$ +1,050,696 +$ +339,265 +$ +— +$ +1,389,961 +Commodity price risk management gain, net +145,237 +— +— +145,237 +Other income +10,744 +2,717 +— +13,461 +Total revenues +1,206,677 +341,982 +— +1,548,659 +Costs, expenses and other +Lease operating expenses +92,228 +38,729 +— +130,957 +Production taxes +67,819 +22,538 +— +90,357 +Transportation, gathering and processing expenses +16,607 +20,796 +— +37,403 +Exploration, geologic and geophysical expense +1,234 +4,970 +— +6,204 +General and administrative expense +152,798 +17,706 +— +170,504 +Depreciation, depletion and amortization +389,841 +169,952 +— +559,793 +Accretion of asset retirement obligations +4,617 +458 +— +5,075 +Impairment of properties and equipment +27 +458,370 +— +458,397 +(Gain) loss on sale of properties and equipment +( 4,387 +) +4,781 +— +394 +Other expenses +11,829 +— +— +11,829 +Total costs, expenses and other +732,613 +738,300 +— +1,470,913 +Income (loss) from operations +474,064 +( 396,318 +) +— +77,746 +Interest expense +( 73,251 +) +2,521 +— +( 70,730 +) +Interest income +413 +— +— +413 +Income (loss) before income taxes +401,226 +( 393,797 +) +— +7,429 +Income tax (expense) benefit +( 98,611 +) +93,205 +— +( 5,406 +) +Equity in loss of subsidiary +( 300,592 +) +— +300,592 +— +Net income (loss) +$ +2,023 +$ +( 300,592 +) +$ +300,592 +$ +2,023 +Net loss for the Guarantor for the year ended 2018 is primarily the result of impairment of certain unproved Delaware Basin leasehold positions. +110 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Consolidating Statements of Operations +Year Ended December 31, 2017 +Parent +Guarantor +Eliminations +Consolidated +(in thousands) +Revenues +Crude oil, natural gas, and NGLs sales +$ +788,400 +$ +124,684 +$ +— +$ +913,084 +Commodity price risk management loss, net +( 3,936 +) +— +— +( 3,936 +) +Other income +11,901 +567 +— +12,468 +Total revenues +796,365 +125,251 +— +921,616 +Costs, expenses and other +Lease operating expenses +68,031 +21,610 +— +89,641 +Production taxes +53,236 +7,481 +— +60,717 +Transportation, gathering and processing expenses +23,301 +9,919 +— +33,220 +Exploration, geologic and geophysical expense +1,092 +46,242 +— +47,334 +General and administrative expense +107,518 +12,852 +— +120,370 +Depreciation, depletion and amortization +403,984 +65,100 +— +469,084 +Accretion of asset retirement obligations +5,965 +341 +— +6,306 +Impairment of properties and equipment +4,951 +280,936 +— +285,887 +Impairment of goodwill +— +75,121 +— +75,121 +Gain on sale of properties and equipment +( 766 +) +— +— +( 766 +) +Provision for uncollectible notes receivable +( 40,203 +) +— +— +( 40,203 +) +Other expenses +13,157 +— +— +13,157 +Total costs, expenses and other +640,266 +519,602 +— +1,159,868 +Income (loss) from operations +156,099 +( 394,351 +) +— +( 238,252 +) +Loss on extinguishment of debt +( 24,747 +) +— +— +( 24,747 +) +Interest expense +( 79,919 +) +1,225 +— +( 78,694 +) +Interest income +2,261 +— +— +2,261 +Income (loss) before income taxes +53,694 +( 393,126 +) +— +( 339,432 +) +Income tax (expense) benefit +( 33,643 +) +245,571 +— +211,928 +Equity in loss of subsidiary +( 147,555 +) +— +147,555 +— +Net loss +$ +( 127,504 +) +$ +( 147,555 +) +$ +147,555 +$ +( 127,504 +) +Net loss for the Guarantor for the year ended 2017 is primarily the result of the exploratory dry hole expense, impairment of certain unproved Delaware Basin leasehold positions and the impairment of goodwill. +111 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Consolidating Statements of Cash Flows +Year Ended December 31, 2019 +Parent +Guarantor +Eliminations +Consolidated +(in thousands) +Cash flows from operating activities +$ +579,464 +$ +278,762 +$ +— +$ +858,226 +Cash flows from investing activities: +Capital expenditures for development of crude oil and natural gas properties +( 485,725 +) +( 370,183 +) +— +( 855,908 +) +Capital expenditures for other properties and equipment +( 20,361 +) +( 478 +) +— +( 20,839 +) +Acquisition of crude oil and natural gas properties +( 12,141 +) +( 1,066 +) +— +( 13,207 +) +Proceeds from sale of properties and equipment +399 +1,706 +— +2,105 +Proceeds from divestiture +5,515 +196,561 +— +202,076 +Restricted cash +8,001 +— +— +8,001 +Intercompany transfers +105,004 +— +( 105,004 +) +— +Net cash from investing activities +( 399,308 +) +( 173,460 +) +( 105,004 +) +( 677,772 +) +Cash flows from financing activities: +Proceeds from revolving credit facility +1,577,000 +— +— +1,577,000 +Repayment of revolving credit facility +( 1,605,500 +) +— +— +( 1,605,500 +) +Payment of debt issuance costs +( 72 +) +— +— +( 72 +) +Purchase of treasury stock +( 154,363 +) +— +— +( 154,363 +) +Purchase of treasury shares for employee stock-based compensation tax withholding obligations +( 4,003 +) +— +— +( 4,003 +) +Principal payments under financing lease obligations +( 1,654 +) +( 298 +) +— +( 1,952 +) +Intercompany transfers +— +( 105,004 +) +105,004 +— +Net cash from financing activities +( 188,592 +) +( 105,302 +) +105,004 +( 188,890 +) +Net change in cash, cash equivalents and restricted cash +( 8,436 +) +— +— +( 8,436 +) +Cash, cash equivalents and restricted cash, beginning of period +9,399 +— +— +9,399 +Cash, cash equivalents and restricted cash, end of period +$ +963 +$ +— +$ +— +$ +963 +112 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Consolidating Statements of Cash Flows +Year Ended December 31, 2018 +Parent +Guarantor +Eliminations +Consolidated +(in thousands) +Cash flows from operating activities +$ +625,206 +$ +264,096 +$ +— +$ +889,302 +Cash flows from investing activities: +Capital expenditures for development of crude oil and natural gas properties +( 482,534 +) +( 463,816 +) +— +( 946,350 +) +Capital expenditures for other properties and equipment +( 9,806 +) +( 1,249 +) +— +( 11,055 +) +Acquisition of crude oil and natural gas properties +( 179,955 +) +( 71 +) +— +( 180,026 +) +Proceeds from sale of properties and equipment +1,929 +1,633 +— +3,562 +Proceeds from divestiture +44,693 +— +— +44,693 +Restricted cash +1,249 +— +— +1,249 +Intercompany transfers +( 199,584 +) +— +199,584 +— +Net cash from investing activities +( 824,008 +) +( 463,503 +) +199,584 +( 1,087,927 +) +Cash flows from financing activities: +Proceeds from revolving credit facility +1,072,500 +— +— +1,072,500 +Repayment of revolving credit facility +( 1,040,000 +) +— +— +( 1,040,000 +) +Payment of debt issuance costs +( 7,704 +) +— +— +( 7,704 +) +Purchase of treasury shares for employee stock-based compensation tax withholding obligations +( 5,147 +) +— +— +( 5,147 +) +Principal payments under financing lease obligations +( 1,318 +) +( 177 +) +— +( 1,495 +) +Other +( 55 +) +— +— +( 55 +) +Intercompany transfers +— +199,584 +( 199,584 +) +— +Net cash from financing activities +18,276 +199,407 +( 199,584 +) +18,099 +Net change in cash, cash equivalents and restricted cash +( 180,526 +) +— +— +( 180,526 +) +Cash, cash equivalents and restricted cash, beginning of period +189,925 +— +— +189,925 +Cash, cash equivalents and restricted cash, end of period +$ +9,399 +$ +— +$ +— +$ +9,399 +113 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Consolidating Statements of Cash Flows +Year Ended December 31, 2017 +Parent +Guarantor +Eliminations +Consolidated +(in thousands) +Cash flows from operating activities +$ +546,954 +$ +50,859 +$ +— +$ +597,813 +Cash flows from investing activities: +Capital expenditures for development of crude oil and natural gas properties +( 439,897 +) +( 297,311 +) +— +( 737,208 +) +Capital expenditures for other properties and equipment +( 3,539 +) +( 1,555 +) +— +( 5,094 +) +Acquisition of crude oil and natural gas properties +( 21,000 +) +5,372 +— +( 15,628 +) +Proceeds from sale of properties and equipment +10,084 +( 93 +) +— +9,991 +Sale of promissory note +40,203 +— +— +40,203 +Restricted cash +( 9,250 +) +— +— +( 9,250 +) +Sales of short-term investments +49,890 +— +— +49,890 +Purchases of short-term investments +( 49,890 +) +— +— +( 49,890 +) +Intercompany transfers +( 239,191 +) +— +239,191 +— +Net cash from investing activities +( 662,590 +) +( 293,587 +) +239,191 +( 716,986 +) +Cash flows from financing activities: +Proceeds from issuance of senior notes +592,366 +— +— +592,366 +Redemption of senior notes +( 519,375 +) +— +— +( 519,375 +) +Payment of debt issuance costs +( 50 +) +— +— +( 50 +) +Purchase of treasury shares for employee stock-based compensation tax withholding obligations +( 6,672 +) +— +— +( 6,672 +) +Principal payments under financing lease obligations +( 1,092 +) +( 76 +) +— +( 1,168 +) +Other +( 103 +) +— +— +( 103 +) +Intercompany transfers +— +239,191 +( 239,191 +) +— +Net cash from financing activities +65,074 +239,115 +( 239,191 +) +64,998 +Net change in cash, cash equivalents and restricted cash +( 50,562 +) +( 3,613 +) +— +( 54,175 +) +Cash, cash equivalents and restricted cash, beginning of period +240,487 +3,613 +— +244,100 +Cash, cash equivalents and restricted cash, end of period +$ +189,925 +$ +— +$ +— +$ +189,925 +114 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +CRUDE OIL AND NATURAL GAS INFORMATION - UNAUDITED +Net Proved Reserves +All of our crude oil, natural gas and NGLs reserves are located in the U.S. We utilize the services of independent petroleum engineers to estimate our crude oil, natural gas and NGLs reserves. As of December 31, 2019 , 2018 and 2017 (as applicable), all of our estimates of proved reserves for the Wattenberg Field and the Utica Shale were based on reserve reports prepared by Ryder Scott and NSAI prepared the reserve reports for the Delaware Basin. These reserve estimates have been prepared in compliance with professional standards and the reserves definitions prescribed by the SEC. +Proved reserves are those quantities of crude oil, natural gas and NGLs which can be estimated with reasonable certainty to be economically producible under existing economic conditions and operating methods. Proved developed reserves are the proved reserves that can be produced through existing wells with existing equipment and infrastructure and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for development. All of our proved undeveloped reserves conform to the SEC five-year rule requirement that they be scheduled to be drilled within five years of each location’s initial booking date. +The indicated index prices for our reserves, by commodity, are presented below. +Average Benchmark Prices (1) +As of December 31, +Crude Oil +(per Bbl) (2) +Natural Gas +(per Mcf) (2) +NGLs +(per Bbl) (3) +2019 +$ +55.69 +$ +2.58 +$ +55.69 +2018 +65.56 +3.10 +65.56 +2017 +51.34 +2.98 +51.34 +The netted back price used to estimate our reserves, by commodity, are presented below. +Price Used to Estimate Reserves (4) +As of December 31, +Crude Oil +(per Bbl) +Natural Gas +(per Mcf) +NGLs +(per Bbl) +2019 +$ +52.63 +$ +1.50 +$ +12.21 +2018 +61.14 +2.15 +23.04 +2017 +48.68 +2.31 +20.21 +(1) +Per SEC rules, the pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of the month prices for the preceding 12 months. +(2) Our benchmark prices for crude oil and natural gas are WTI and Henry Hub, respectively. +(3) +For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. +(4) +These prices are based on the index prices and are net of basin differentials, transportation fees, contractual adjustments and Btu adjustments we experienced for the respective commodity. +115 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +The following tables present the changes in our estimated quantities of proved reserves: +Crude Oil, Condensate (MBbls) +Natural Gas +(MMcf) +NGLs +(MBbls) +Total +(MBoe) +Proved reserves, January 1, 2017 +118,169 +833,697 +84,288 +341,407 +Revisions of previous estimates +28,334 +96,119 +8,104 +52,457 +Extensions, discoveries and other additions +2,923 +11,541 +1,158 +6,005 +Acquisition of reserves +18,971 +289,223 +19,604 +86,778 +Dispositions +( 653 +) +( 4,597 +) +( 481 +) +( 1,900 +) +Production +( 12,902 +) +( 71,689 +) +( 6,981 +) +( 31,830 +) +Proved reserves, December 31, 2017 +154,842 +1,154,294 +105,692 +452,917 +Revisions of previous estimates +26,548 +94,738 +12,674 +55,011 +Extensions, discoveries and other additions +8,786 +61,750 +8,868 +27,946 +Acquisition of reserves +19,644 +148,674 +15,936 +60,360 +Dispositions +( 2,507 +) +( 35,750 +) +( 2,656 +) +( 11,121 +) +Production +( 16,964 +) +( 88,017 +) +( 8,527 +) +( 40,160 +) +Proved reserves, December 31, 2018 +190,349 +1,335,689 +131,987 +544,953 +Revisions of previous estimates +25,875 +328,290 +31,559 +112,147 +Extensions, discoveries and other additions +1,056 +10,262 +1,519 +4,285 +Acquisition of reserves +553 +4,558 +448 +1,761 +Dispositions +( 1,412 +) +( 5,052 +) +( 614 +) +( 2,868 +) +Production +( 19,166 +) +( 115,950 +) +( 10,923 +) +( 49,414 +) +Proved reserves, December 31, 2019 +197,255 +1,557,797 +153,976 +610,864 +Proved developed reserves, as of: +December 31, 2017 +46,862 +365,332 +35,220 +142,971 +December 31, 2018 +61,821 +443,151 +43,856 +179,535 +December 31, 2019 +66,211 +554,234 +55,411 +213,994 +Proved undeveloped reserves, as of: +December 31, 2017 +107,980 +788,962 +70,472 +309,946 +December 31, 2018 +128,528 +892,538 +88,131 +365,418 +December 31, 2019 +131,044 +1,003,563 +98,565 +396,870 +116 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Developed +Undeveloped +Total +(MBoe) +Proved reserves, January 1, 2017 +98,285 +243,122 +341,407 +Revisions of previous estimates +18,291 +34,166 +52,457 +Extensions, discoveries and other additions +2,292 +3,713 +6,005 +Acquisition of reserves +1,305 +85,473 +86,778 +Dispositions +( 20 +) +( 1,880 +) +( 1,900 +) +Production +( 31,830 +) +— +( 31,830 +) +Undeveloped reserves converted to developed +54,648 +( 54,648 +) +— +Proved reserves, December 31, 2017 +142,971 +309,946 +452,917 +Revisions of previous estimates +6,284 +48,727 +55,011 +Extensions, discoveries and other additions +7,874 +20,072 +27,946 +Acquisition of reserves +8,758 +51,602 +60,360 +Dispositions +( 4,486 +) +( 6,635 +) +( 11,121 +) +Production +( 40,160 +) +— +( 40,160 +) +Undeveloped reserves converted to developed +58,294 +( 58,294 +) +— +Proved reserves, December 31, 2018 +179,535 +365,418 +544,953 +Revisions of previous estimates +27,452 +84,695 +112,147 +Extensions, discoveries and other additions +4,285 +— +4,285 +Acquisition of reserves +441 +1,320 +1,761 +Dispositions +( 474 +) +( 2,394 +) +( 2,868 +) +Production +( 49,414 +) +— +( 49,414 +) +Undeveloped reserves converted to developed +52,169 +( 52,169 +) +— +Proved reserves, December 31, 2019 +213,994 +396,870 +610,864 +2019 Activity. During 2019 , we increased proved reserves by 65.9 MMBoe, or 12 percent , relative to December 31, 2018 . The increase in proved reserves was primarily the result of our 2019 development activities and our future drilling schedule. In 2019 , we produced 49.4 MMboe. +Revisions of Previous Estimates-Proved Developed Reserves. Proved developed reserves experienced a net positive revision of 17.3 MMBoe due to a decrease in operating costs, performance revisions and other items. We also experienced an additional increase of 10.2 MMBoe in proved developed reserves related to our current year drilling activities. These net positive revisions were partially offset by a decrease in prices for crude oil, natural gas and NGLs. +Revisions of Previous Estimates-PUDs. Upward revisions to our PUD reserves were related to an increase of 74.2 MMBoe reflecting additional locations on proven acreage resulting from our drilling plan. Other changes impacting the increase were due to commodity pricing, lease operating expenses and type curve revisions, which resulted in further upward revisions of 23.4 MMBoe of PUD reserves. Partially offsetting this increase was a negative revision of 12.9 MMBoe due to drilling schedule changes. +Extensions, Discoveries and Other Additions-Proved Developed Reserves. Developed activity for 2019 included the addition of 4.3 MMBoe of developed reserves related to three gross ( three net) newly-drilled wells. +Extensions, Discoveries and Other Additions-PUDs. There were no extensions, discoveries or other additions for PUD reserves during 2019. +Acquisitions of Reserves-Proved Developed Reserves. Proved developed reserves acquired in various acreage swaps and acquisitions were 0.4 MMBoe during 2019 . +Acquisitions of Reserves-PUDs. We acquired 1.3 MMBoe of PUD reserves in 2019 in acreage swaps and acquisitions. +Dispositions-Proved Developed Reserves . Dispositions of 0.5 MMBoe were related to a divestiture and acreage surrendered in various acreage swaps. +Dispositions-PUDs. Dispositions of 2.4 MMBoe were related to a divestiture and acreage surrendered in various acreage swaps. +117 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +At December 31, 2018 , we projected a PUD reserve conversion rate of 16 percent for 2019 . During 2019 , a smaller number of wells were turned-in-line than we anticipated, resulting in an actual conversion rate of 14 percent . We converted 52.2 MMBoe of PUD reserves at December 31, 2018 to proved developed reserves as of December 31, 2019 . +Based on economic conditions on December 31, 2019 , our approved development plan provides for the development of our remaining PUD locations within five years of the date such reserves were initially recorded. As of December 31, 2019 , our 2020 PUD reserve conversion rate is expected to be approximately 26 percent . The balance of the PUD reserves are scheduled to be developed over the remaining four years in accordance with our current development plan. The level of capital spending necessary to achieve this drilling schedule is consistent with our recent performance and our outlook for future development activities. +2018 Activity. During 2018, we increased proved reserves by 92.0 MMBoe, or 20 percent , relative to December 31, 2017. The increase in proved reserves was primarily a result of acreage exchange transactions and acquisitions in the Wattenberg Field and reserve additions on proved acreage resulting from our 2018 development activities. In 2018, we produced 40.2 MMboe. +Revisions of Previous Estimates-Proved Developed Reserves. Proved developed reserves experienced a net positive revision of 11.4 MMBoe due to an increase in prices for crude oil, natural gas and NGLs, offset by net negative revisions of 5.1 MMBoe for an increase in operating costs, performance revisions and other items. +Revisions of Previous Estimates-PUDs. Upward revisions to our PUD reserves were related to an increase of 71.7 MMBoe reflecting newly-booked locations on proven acreage resulting from our drilling activities. Partially offsetting this increase was a negative revision of 26.8 MMBoe in the Wattenberg Field due to drilling schedule changes and updated timing for development of certain locations exceeding the five-year rule. Drilling schedule changes, primarily related to 2018 acreage exchanges, resulted in these locations being reclassified from proved to unproved status. All other changes were due to commodity pricing, lease operating expenses and type curve revisions, which resulted in further upward revisions of 3.8 MMBoe of PUD reserves. +Extensions, Discoveries and Other Additions-Proved Developed Reserves. Developed additions for 2018 included the addition of 7.9 MMBoe of developed reserves related to 17 gross ( 9.2 net) newly-drilled wells. +Extensions, Discoveries and Other Additions-PUDs. PUD activity was comprised primarily of 20.1 MMBoe of PUD reserves related to 16 gross ( 15.0 net) PUD locations in the Delaware Basin. +Acquisitions of Reserves-Proved Developed Reserves. Proved developed reserves acquired in various acreage swaps and an acquisition were 8.8 MMBoe during 2018. +Acquisitions of Reserves-PUDs. We acquired 47.6 MMBoe and 4.0 MMBoe of PUD reserves in 2018 in acreage swaps and an acquisition, respectively. +Dispositions-Proved Developed Reserves . Dispositions of 4.5 MMBoe were related to a divestiture and acreage surrendered in various acreage swaps. +Dispositions-PUDs. Dispositions of 6.6 MMBoe reflect that we primarily divested proved acreage with future locations that were not in our five-year drilling plan as of December 31, 2017 in the acreage swap transactions. +At December 31, 2017, we projected a PUD reserve conversion rate of 16 percent for 2018. During 2018, a larger number of wells were turned-in-line than we anticipated, resulting in an actual conversion rate of 19 percent . We converted 58.3 MMBoe of PUD reserves at December 31, 2017 to proved developed reserves as of December 31, 2018. +2017 Activity. During 2017, we increased proved reserves by 111.5 MMBoe, or 33 percent , relative to December 31, 2016. The increase in proved reserves was primarily a result of an increase in acquisitions and reserve additions on proved acreage in the Delaware Basin from our 2017 development plan. In 2017, we produced 31.8 MMBoe. +Revisions of Previous Estimates-Proved Developed Reserves. Proved developed reserves experienced a net positive revision of 17.7 MMBoe due to an increase in prices for crude oil, natural gas and NGLs and net positive revisions of 0.6 MMBoe reflecting changes in operating costs, performance revisions and other items. +118 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Revisions of Previous Estimates-PUDs. Upward revisions to our PUD reserves were related to an increase of 89.8 MMBoe reflecting newly-booked locations on proven acreage resulting from our drilling activities. Partially offsetting this increase was a negative revision of 58.5 MMBoe in the Wattenberg Field due to drilling schedule changes and updated timing for development of certain locations exceeding the five-year rule. Drilling schedule changes, primarily related to 2017 acreage swaps, resulted in these locations being reclassified from proved to unproved status. All other changes were due to commodity pricing, lease operating expenses and other, which resulted in further upward revisions of 2.9 MMBoe of PUD reserves. +Extensions, Discoveries and Other Additions-Proved Developed Reserves. Developed additions for 2017 included the addition of 2.3 MMBoe of developed reserves related to newly-drilled wells. +Extensions, Discoveries and Other Additions-PUDs . PUD activity was comprised primarily of 3.7 MMBoe of PUD locations in the Delaware Basin. +Acquisitions of Reserves-Proved Developed Reserves. Proved developed reserves acquired in various acreage swaps were 1.3 MMBoe during 2017. +Acquisitions of Reserves-PUDs. We acquired 85.5 MMBoe of PUD reserves in 2017 in acreage swaps. +Dispositions-Proved Developed Reserves . Dispositions were related to acreage surrendered in various acreage swaps. +Dispositions-PUDs. Dispositions of PUDs were 1.9 MMBoe, reflecting the fact that we primarily divested proved acreage with future locations that were not in our five-year drilling plan as of December 31, 2016 in the acreage swap transactions. +At December 31, 2016, we projected a PUD reserve conversion rate of 26 percent for 2017. As a result of drilling plans being extended in our Delaware Basin in the first half of 2017, our actual conversion rate was 23 percent , resulting in 54.6 MMBoe of reserves recorded as PUDs at December 31, 2016, being converted to proved developed reserves as of December 31, 2017. +Results of Operations for Crude Oil and Natural Gas Producing Activities +The results of operations for crude oil and natural gas producing activities are presented below. +Year Ended December 31, +2019 +2018 +2017 +(in thousands) +Revenue: +Crude oil, natural gas and NGLs sales +$ +1,307,275 +$ +1,389,961 +$ +913,084 +Commodity price risk management gain (loss), net +( 162,844 +) +145,237 +( 3,936 +) +1,144,431 +1,535,198 +909,148 +Expenses: +Lease operating expenses +142,248 +130,957 +89,641 +Production taxes +80,754 +90,357 +60,717 +Transportation, gathering and processing expenses +46,353 +37,403 +33,220 +Exploration expense +4,054 +6,204 +47,334 +Depreciation, depletion and amortization +638,499 +551,265 +462,482 +Accretion of asset retirement obligations +6,117 +5,075 +6,306 +Impairment of properties and equipment +38,536 +458,397 +285,887 +(Gain) loss on sale of properties and equipment +9,734 +394 +( 766 +) +966,295 +1,280,052 +984,821 +Results of operations for crude oil and natural gas producing +activities before income taxes +178,136 +255,146 +( 75,673 +) +Income tax (expense) benefit +( 9,869 +) +( 185,667 +) +47,247 +Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs +$ +168,267 +$ +69,479 +$ +( 28,426 +) +119 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Production costs include those costs incurred to operate and maintain productive wells and related equipment, including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, production and severance taxes and associated administrative expenses. DD&A expense includes those costs associated with capitalized acquisition, exploration and development costs, but does not include the depreciation applicable to support equipment. The provision for income taxes is computed using effective tax rates. +Costs Incurred in Crude Oil and Natural Gas Property Acquisition, Exploration and Development Activities +Costs incurred in crude oil and natural gas property acquisition, exploration and development are presented below. +Year Ended December 31, +2019 +2018 +2017 +(in thousands) +Acquisition of properties: (1) +Proved properties +$ +16,007 +$ +205,253 +$ +172 +Unproved properties +9,567 +5,477 +18,914 +Development costs (2) +780,851 +970,970 +688,165 +Exploration costs: (3) +Exploratory drilling +32,218 +36,704 +80,103 +Geological and geophysical +3,017 +3,401 +3,881 +Total costs incurred (4) +$ +841,660 +$ +1,221,805 +$ +791,235 +(1) +Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property. +(2) +Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells and provide facilities to extract, treat, gather and store crude oil, natural gas and NGLs. Of these costs incurred for the years ended December 31, 2019 , 2018 and 2017 , $ 308.9 million , $ 438.4 million and $ 463.4 million , respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. These costs also include approximately $ 35.3 million , $ 74.6 million and $ 32.8 million of infrastructure and pipeline costs in 2019 , 2018 and 2017 respectively. +(3) +Exploration costs represent costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas and NGLs. These costs include, but are not limited to, dry hole contributions and costs of drilling and equipping exploratory wells. +(4) +During 2017, we finalized our purchase price allocation for the 2016 Delaware Basin acquisition within the one year measurement period. The finalization included a reduction to our proved undeveloped and development costs of $ 24.6 million . We excluded this reduction from our 2017 costs incurred as it did not relate to any cash acquisitions in 2017. +Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities +Aggregate capitalized costs related to crude oil and natural gas exploration and production activities with applicable accumulated DD&A are presented below: +As of December 31, +2019 +2018 +(in thousands) +Proved crude oil and natural gas properties +$ +6,241,780 +$ +5,452,613 +Unproved crude oil and natural gas properties +403,379 +492,594 +Uncompleted wells, equipment and facilities +382,409 +332,264 +Capitalized costs +7,027,568 +6,277,471 +Less accumulated DD&A +( 2,982,929 +) +( 2,341,897 +) +Capitalized costs, net +$ +4,044,639 +$ +3,935,574 +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves +The standardized measure below has been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to our year-end estimated proved reserves. Prices for each of the three years were adjusted +120 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +by field for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of our commodity derivatives. Production and development costs were based on prices as of December 31 for each of the respective years presented. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service or to depreciation, depletion and amortization expense. Production and development costs include those cash flows associated with the expected ultimate settlement of our asset retirement obligations. Future estimated income tax expense is computed by applying the statutory rate in effect at the end of each year to the projected future pre-tax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits and allowances related to the properties. +The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for crude oil, natural gas and NGLs, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves. +As of December 31, +2019 +2018 +2017 +(in thousands) +Future estimated cash flows +$ +14,590,604 +$ +17,554,880 +$ +12,340,407 +Future estimated production costs (1) +( 4,530,173 +) +( 4,782,948 +) +( 3,245,627 +) +Future estimated development costs +( 3,257,106 +) +( 3,632,822 +) +( 2,893,335 +) +Future estimated income tax expense +( 907,382 +) +( 1,404,121 +) +( 748,494 +) +Future net cash flows +5,895,943 +7,734,989 +5,452,951 +10% annual discount for estimated timing of cash flows +( 2,585,609 +) +( 3,287,273 +) +( 2,572,846 +) +Standardized measure of discounted future estimated net cash flows +$ +3,310,334 +$ +4,447,716 +$ +2,880,105 +(1) Represents future estimated lease operating expenses, production taxes and transportation, gathering and processing expenses. +The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows: +Year Ended December 31, +2019 +2018 +2017 +(in thousands) +Beginning of period +$ +4,447,716 +$ +2,880,105 +$ +1,420,629 +Sales of crude oil, natural gas and NGLs production, net of production costs +( 1,037,920 +) +( 1,131,244 +) +( 729,506 +) +Net changes in prices and production costs (1) +( 2,122,538 +) +936,077 +841,713 +Extensions, discoveries and improved recovery, less related costs +39,606 +190,084 +47,240 +Sales of reserves +( 14,533 +) +( 42,362 +) +( 2,613 +) +Purchases of reserves +18,816 +467,807 +224,483 +Development costs incurred during the period +605,753 +462,088 +419,047 +Revisions of previous quantity estimates +538,242 +631,198 +484,431 +Changes in estimated income taxes +346,826 +( 232,002 +) +( 138,560 +) +Net changes in future development costs +206,003 +( 123,663 +) +25,183 +Accretion of discount +532,127 +583,744 +167,487 +Timing and other +( 249,764 +) +( 174,116 +) +120,571 +End of period +$ +3,310,334 +$ +4,447,716 +$ +2,880,105 +(1) +Our weighted-average price, net of production costs per Boe, in our 2019 reserve report decreased to $ 16.18 as compared to $ 23.44 for 2018 and $ 20.08 for 2017 . +The data presented should not be viewed as representing the expected cash flows from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the recent average prices and current costs utilized in the computation of reported amounts. Any analysis or evaluation of +121 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein. +122 +PDC ENERGY, INC. +QUARTERLY FINANCIAL INFORMATION - UNAUDITED +Quarterly financial data for the years ended December 31, 2019 and 2018 is presented below. The sum of the quarters may not equal the total of the year's net income or loss per share due to changes in the weighted-average shares outstanding throughout the year. +2019 +Quarter Ended +March 31 +June 30 +September 30 +December 31 +(in thousands, except per share data) +Total revenues +$ +134,500 +$ +390,658 +$ +365,943 +$ +265,022 +Total costs, expenses and other +275,120 +280,623 +321,562 +267,713 +Income (loss) from operations +( 140,620 +) +110,035 +44,381 +( 2,691 +) +Income (loss) before income taxes +( 157,588 +) +91,135 +26,570 +( 20,111 +) +Net income (loss) +$ +( 120,176 +) +$ +68,548 +$ +15,908 +$ +( 20,952 +) +Earnings per share: +Basic +$ +( 1.82 +) +$ +1.04 +$ +0.25 +$ +( 0.34 +) +Diluted +( 1.82 +) +1.04 +0.25 +( 0.34 +) +2018 +Quarter Ended +March 31 +June 30 +September 30 +December 31 +(in thousands, except per share data) +Total revenues +$ +260,600 +$ +212,531 +$ +280,717 +$ +794,811 +Total costs, expenses and other +260,924 +400,770 +270,593 +538,626 +Income (loss) from operations +( 324 +) +( 188,239 +) +10,124 +256,185 +Income (loss) before income taxes +( 17,705 +) +( 205,580 +) +( 7,310 +) +238,024 +Net income (loss) +$ +( 13,139 +) +$ +( 160,257 +) +$ +( 3,434 +) +$ +178,853 +Earnings per share: +Basic +$ +( 0.20 +) +$ +( 2.43 +) +$ +( 0.05 +) +$ +2.71 +Diluted +( 0.20 +) +( 2.43 +) +( 0.05 +) +2.71 +123 +PDC ENERGY, INC. +FINANCIAL STATEMENT SCHEDULE +Schedule II -VALUATION AND QUALIFYING ACCOUNTS +Description +Beginning +Balance +January 1, +Charged to +Costs and +Expenses +Deductions (1) +Ending +Balance +December 31, +(in thousands) +2019: +Allowance for doubtful accounts +$ +4,381 +$ +3,209 +$ +114 +$ +7,476 +Allowance for expirations of unproved crude oil and natural gas properties +542,709 +8,523 +544,351 +6,881 +2018: +Allowance for doubtful accounts +3,128 +1,276 +23 +4,381 +Allowance for expirations of unproved crude oil and natural gas properties +251,159 +388,068 +96,518 +542,709 +2017: +Allowance for uncollectible notes +$ +44,038 +$ +— +$ +44,038 +$ +— +Allowance for doubtful accounts +2,190 +1,108 +170 +3,128 +Allowance for expirations of unproved crude oil and natural gas properties +359 +263,817 +13,017 +251,159 +(1) +For allowance for uncollectible notes, deductions represent reversals of allowances due to the collection of amounts owed. For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For allowance for expirations of unproved crude oil and natural gas properties, deductions represent actual expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset. +124 +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +As of December 31, 2019 , we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Based on the results of this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2019 . +Management's Report on Internal Control over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Internal control over financial reporting is a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer, or persons performing similar functions, and effected by our board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate. +Management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2019, based upon the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). +The effectiveness of our internal control over financial reporting as of December 31, 2019 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears under Item 8. +Remediation of Material Weaknesses +We previously identified and disclosed in our Annual Report on Form 10-K for the year ended December 31, 2018 material weaknesses in our internal control over financial reporting related to an insufficient complement of personnel within our Land Department, which contributed to the ineffective design and maintenance of controls to verify the completeness and accuracy of certain land administrative records associated with unproved leases. +We remediated these material weaknesses in 2019 by enhancing the design of existing controls through a combination of new leadership, hiring additional personnel with relevant experience and increased layers of supervision and division of responsibilities within the Land Department. We also redesigned existing control activities to verify the completeness and accuracy of land administrative records associated with unproved leases, including the verification of the reliability of underlying data used in the execution of the control activities. +Changes in Internal Control over Financial Reporting +There were no changes in our internal control over financial reporting during the quarter ended December 31, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. +ITEM 9B. OTHER INFORMATION +None. +125 +PART III +ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2020 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 11. EXECUTIVE COMPENSATION +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2020 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2020 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2020 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2020 Annual Stockholders' meeting and is incorporated by reference in this report. +PART IV +ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES +(a) +(1) +Exhibits: +See Exhibits Index on the following page. +126 +ITEM 16. FORM 10-K SUMMARY +None. +Exhibits Index +Incorporated by Reference +Exhibit Number +Exhibit Description +Form +SEC File Number +Exhibit +Filing Date +Filed Herewith +2.1 +Plan of Conversion, dated June 5, 2015, by PDC Energy, Inc. +8-K12B +001-37419 +2.1 +6/8/2015 +2.2 +Agreement and Plan of Merger, dated as of August 25, 2019 by and between PDC Energy, Inc., and SRC Energy Inc. +8-K +001-37419 +2.1 +8/26/2019 +3.1 +Certificate of Incorporation of PDC Energy, Inc. +8-K12B +001-37419 +3.1 +6/8/2015 +3.2 +Bylaws of PDC Energy, Inc. +8-K12B +001-37419 +3.2 +6/8/2015 +4.1 +Description of Capital Stock +X +4.1.1 +Form of Common Stock Certificate of PDC Energy, Inc. +X +4.2 +Indenture, dated as of November 29, 2017, by and between PDC Energy, Inc., PDC Permian, Inc., a subsidiary guarantor of PDC Energy, Inc., and U.S. Bank Trust National Association, as Trustee, relating to the 5.750% Senior Notes due 2026. +8-K +001-37419 +4.1 +11/29/2017 +4.3 +Base Indenture, dated as of September 14, 2016, by and between PDC Energy, Inc. and U.S. Bank Trust National Association, as Trustee. +8-K +001-37419 +4.1 +9/14/2016 +4.4 +First Supplemental Indenture, dated as of September 14, 2016, by and between PDC Energy, Inc. and U.S. Bank Trust National Association, as Trustee, relating to the 1.125% Convertible Senior Notes due 2021. +8-K +001-37419 +4.2 +9/14/2016 +4.5 +Indenture, dated as of September 15, 2016, by and between PDC Energy, Inc. and U.S. Bank Trust National Association, as Trustee, relating to the 6.125% Senior Notes due 2024. +8-K +001-37419 +4.1 +9/15/2016 +4.6 +Indenture, dated as of November 29, 2017, among SRC Energy, Inc. and U.S. Bank National Association as Trustee. +8-K +001-37419 +4.1 +11/29/2017 +4.7 +First Supplemental Indenture, dated as of January 14, 2020, among PDC Energy, Inc. and U.S. Bank National Association as Trustee. +8-K +001-37419 +4.2 +1/14/2019 +10.1 +Form of Indemnification Agreement. +8-K +000-07246 +10.1 +6/8/2015 +10.2 +401(k) and Profit Sharing Plan, as amended on January 4, 2016. +10-K +001-37419 +10.2 +2/28/2017 +10.3 +Amended and Restated Non-Employee Director Deferred Compensation Plan. +10-K +001-37419 +10.3 +2/27/2018 +10.4 +2004 Long-Term Equity Compensation Plan amended and restated as of March 8, 2008 ("2004 Plan"). +10-K +000-07246 +10.26 +2/27/2009 +10.4.1 +Summary of 2010 Stock Appreciation Rights and Restricted Stock Awards under the 2004 Plan. +8-K +000-07246 +4/23/2010 +10.5 +Amended and Restated 2010 Long-Term Equity Compensation Plan, as amended. +10-K +001-37419 +10.5 +2/22/2016 +10.6 +Executive Severance Compensation Plan, as amended. +10-K +001-37419 +10.6 +2/22/2016 +10.7.1 +Form of 2011 Restricted Stock/Stock Appreciation Rights Agreement. +10-K +000-07246 +10.5.2 +2/21/2014 +10.7.2 +Form of 2013 Restricted Stock/Stock Appreciation Rights Agreement. +10-K +000-07246 +10.10 +2/27/2013 +10.7.3 +Form of 2014 Restricted Stock/Stock Appreciation Rights Agreement. +10-K +000-07246 +10.5.5 +2/19/2015 +10.7.4 +Form of 2015 Stock Appreciation Rights Agreement. +10-K +000-07246 +10.5.8 +2/19/2015 +127 +Incorporated by Reference +Exhibit Number +Exhibit Description +Form +SEC File Number +Exhibit +Filing Date +Filed Herewith +10.7.5 +Form of 2018 Performance Share Agreement. +10-Q +001-37419 +99.1 +5/3/2018 +10.7.6 +Form of 2018 Restricted Stock Unit Agreement (Executives). +10-Q +001-37419 +99.2 +5/3/2018 +10.7.7 +Form of 2018 Restricted Stock Unit Agreement (Directors). +10-Q +001-37419 +99.3 +5/3/2018 +10.7.8 +Form of 2019 Performance Share Agreement. +10-Q +001-37419 +99.1 +5/2/2019 +10.7.9 +Form of 2019 Restricted Stock Unit Agreement (Directors). +10-Q +001-37419 +99.2 +5/2/2019 +10.7.10 +Form of 2019 Restricted Stock Unit Agreement (Executives) (Amended and Restated 2010 Long-Term Equity Compensation Plan). +10-Q +001-37419 +99.3 +5/2/2019 +10.7.11 +Form of 2019 Restricted Stock Unit Agreement (Executives) (2018 Equity Incentive Plan). +10-Q +001-37419 +99.4 +5/2/2019 +10.7.12 +SRC Energy, Inc./PDC Energy, Inc. Merger Performance Share Agreement, dated January 13, 2020, by and between PDC Energy, Inc.(as successor to SRC Energy, Inc.) and Lynn A. Peterson. +8-K +001-37419 +10.2 +1/14/2020 +10.8 +Employment Agreement with Lance A. Lauck, Senior Vice President of Business Development, dated as of April 19, 2010. +8-K +000-07246 +10.4 +4/23/2010 +10.9 +2018 Equity Incentive Plan. +8-K +001-37419 +10.1 +5/31/2018 +10.10 +SRC Energy Inc. 2015 Equity Incentive Plan. +8-K +001-37419 +10.1 +1/14/2020 +10.11 +Fourth Amended and Restated Credit Agreement, dated as of May 23, 2018, among PDC Energy, Inc. as Borrower, each of the Lenders party thereto, and JPMorgan Chase Bank, N.A. as Administrative Agent for the Lenders. +8-K +001-37419 +10.1 +5/25/2018 +10.11.1 +First Amendment to Fourth Amended and Restated Credit Agreement, dated as August 30, 2019, among PDC Energy, Inc. as Borrower, each of the Lenders party thereto, and JPMorgan Chase Bank, N.A. as Administrative Agent for the Lenders. +8-K +001-37419 +10.1 +9/4/2019 +21.1 +Subsidiaries. +X +23.1 +Consent of PricewaterhouseCoopers LLP. +X +23.2 +Consent of Ryder Scott Company, L.P., Petroleum Consultants. +X +23.3 +Consent of Netherland, Sewell & Associates, Inc., Petroleum Consultants. +X +31.1 +Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +31.2 +Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +32.1* +Certifications by Chief Executive Officer and Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. +99.1 +Report of Independent Petroleum Consultants - Ryder Scott Company, L.P. +X +99.2 +Report of Independent Petroleum Consultants - Netherland, Sewell & Associates, Inc. +X +128 +Incorporated by Reference +Exhibit Number +Exhibit Description +Form +SEC File Number +Exhibit +Filing Date +Filed Herewith +101.INS +XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document +X +101.SCH +XBRL Taxonomy Extension Schema Document +X +101.CAL +XBRL Taxonomy Extension Calculation Linkbase Document +X +101.DEF +XBRL Taxonomy Extension Definition Linkbase Document +X +101.LAB +XBRL Taxonomy Extension Label Linkbase Document +X +101.PRE +XBRL Taxonomy Extension Presentation Linkbase Document +X +104 +Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101) +X +* Furnished herewith. +129 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +PDC ENERGY, INC. +By: /s/ Barton Brookman +Barton Brookman +President and Chief Executive Officer +February 26, 2020 +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated: +Signature +Title +Date +/s/ Barton Brookman +President, Chief Executive Officer and Director +February 26, 2020 +Barton Brookman +(principal executive officer) +/s/ R. Scott Meyers +Senior Vice President and Chief Financial Officer +February 26, 2020 +R. Scott Meyers +(principal financial officer) +/s/ Douglas Griggs +Chief Accounting Officer +February 26, 2020 +Douglas Griggs +(principal accounting officer) +/s/ Jeffrey C. Swoveland +Chairman and Director +February 26, 2020 +Jeffrey C. Swoveland +/s/ Anthony J. Crisafio +Director +February 26, 2020 +Anthony J. Crisafio +/s/ Mark E. Ellis +Director +February 26, 2020 +Mark E. Ellis +/s/ Christina M. Ibrahim +Director +February 26, 2020 +Christina M. Ibrahim +/s/ Paul J. Korus +Director +February 26, 2020 +Paul J. Korus +/s/ Randy S. Nickerson +Director +February 26, 2020 +Randy S. Nickerson +/s/ David C. Parke +Director +February 26, 2020 +David C. Parke +/s/ Lynn A. Peterson +Director +February 26, 2020 +Lynn A. Peterson +130 +GLOSSARY OF UNITS OF MEASUREMENT AND INDUSTRY TERMS +UNITS OF MEASUREMENT +The following presents a list of units of measurement used throughout the document. +Bbl – One barrel of crude oil or NGL or 42 gallons of liquid volume. +Bcf – One billion cubic feet of natural gas volume. +Boe – One barrel of crude oil equivalent. +Btu – British thermal unit. +BBtu – One billion British thermal units. +MBoe – One thousand barrels of crude oil equivalent. +MBbls – One thousand barrels of crude oil. +Mcf – One thousand cubic feet of natural gas volume. +MMBoe – One million barrels of crude oil equivalent. +MMBbls – One million barrels of crude oil. +MMBtu – One million British thermal units. +MMcf – One million cubic feet of natural gas volume. +GLOSSARY OF INDUSTRY TERMS +The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report: +CIG - Colorado Interstate Gas. +Completion - Refers to the installation of permanent equipment for the production of crude oil and natural gas from a recently drilled well or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned. +Developed acreage - Acreage assignable to productive wells. +Development well - A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. +Differentials - The difference between the crude oil and natural gas index spot price and the corresponding cash spot price in a specified location. +Dry well or dry hole - A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well. +Exploratory well - A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. +Extensions, discoveries and other additions - As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates. +Farm-out - Transfer of all or part of the operating rights from a working interest owner to an assignee, who assumes all or some of the burden of development in return for an interest in the property. The assignor usually retains an overriding royalty interest but may retain any type of interest. +Fracture or Fracturing - Procedure to stimulate production by forcing a mixture of fluid and proppant into the formation under high pressure. Fracturing creates artificial fractures in the reservoir rock to increase permeability and porosity, thereby allowing the release of trapped hydrocarbons. +Gross acres or wells - Refers to the total acres or wells in which we have a working interest. +Henry Hub - Refers to the pricing point for natural gas futures contracts traded on NYMEX. +131 +Horizontal drilling - A drilling technique that permits the operator to drill a horizontal well shaft from the bottom of a vertical well and thereby to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons. +Joint interest billing - Process of billing/invoicing the costs related to well drilling, completions and production operations among working interest partners. +Natural gas liquid(s) or NGL(s) - Hydrocarbons which can be extracted from natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs include ethane, propane, butane and other natural gasolines. +Net acres or wells - Refers to gross acres or wells we own multiplied, in each case, by our percentage working interest. +Net production - Crude oil and natural gas production that we own, less royalties and production due to others. +Non-operated - A project in which we are not the operator. +NYMEX - New York Mercantile Exchange. +Operator - The individual or company responsible for the exploration, development and/or production of an oil or gas well or lease. +Overriding royalty - An interest which is created out of the operating or working interest. Its term is coextensive with that of the operating interest. +Possible reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability to exceed the sum of proved, probable and possible reserves. When probabilistic methods are used, there must be at least a 10 percent probability that the actual quantities recovered will equal or exceed the sum of proved, probable and possible estimates. +Present value of future net revenues or (PV-10) - The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, of proved reserves calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using pricing and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization and discounted using an annual discount rate of 10 percent. PV-10 is pre-tax and therefore a non-U.S. GAAP financial measure. +Probable reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Similarly, when probabilistic methods are used, there must be at least a 50 percent probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. +Productive well - An exploratory or developmental well that is not a dry well or dry hole, as defined above. +Proved developed non-producing reserves - Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and/or (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells. +Proved developed producing reserves or PDPs - Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods. +Proved developed reserves - The combination of proved developed producing and proved developed non-producing reserves. +Proved reserves - This term means "proved oil and gas reserves" as defined in SEC Regulation S-X Section 4-10(a) and refers to those quantities of crude oil and condensate, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing conditions, operating methods and government regulations - prior to the time at which contracts providing +132 +the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +Proved undeveloped reserves or PUDs - Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. +Recomplete or Recompletion - The modification of an existing well for the purpose of producing crude oil and natural gas from a different producing formation. +Reserves - Estimated remaining quantities of crude oil, natural gas, NGLs and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering crude oil, natural gas and NGLs or related substances to market, and all permits and financing required to implement the project. +Royalty - An interest in a crude oil and natural gas lease or mineral interest that gives the owner of the royalty the right to receive a portion of the production from the leased acreage or mineral interest (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +Section - A square tract of land one mile by one mile, containing 640 acres. +Spud - To begin drilling; the act of beginning a hole. +Standardized measure of discounted future net cash flows or standardized measure - Future net cash flows discounted at a rate of 10 percent. Future net cash flows represent the estimated future revenues to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment and (ii) future income tax expense. +Stratigraphic test well - A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. +Undeveloped acreage - Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas, regardless of whether such acreage contains proved reserves. +Waha - Waha West Texas natural gas prices +Working interest - An interest in a crude oil and natural gas lease that gives the owner of the interest the right to drill and produce crude oil and natural gas on the leased acreage. It requires the owner to pay its share of the costs of drilling and production operations. +Workover - Major remedial operations on a producing well to restore, maintain, or improve the well's production. +133 \ No newline at end of file diff --git a/raw/filings/0000077877/2019/0000077877-20-000010/filing_metadata.csv b/raw/filings/0000077877/2019/0000077877-20-000010/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..f8cb1deb92a674324e572ecd9a127eff4b0035dd --- /dev/null +++ b/raw/filings/0000077877/2019/0000077877-20-000010/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000077877,PDCE,"PDC ENERGY, INC.",10-K,2020-02-27,2019-12-31,2020-02-26T23:22:55.000Z,0000077877-20-000010,pdce-201910xk.htm,PDCE ENERGY 2019 FORM 10-K,27620661,1,1,https://www.sec.gov/Archives/edgar/data/77877/000007787720000010/pdce-201910xk.htm,https://www.sec.gov/Archives/edgar/data/77877/000007787720000010/,2019,2019,1 diff --git a/raw/filings/0000077877/2019/0000077877-20-000010/item1.txt b/raw/filings/0000077877/2019/0000077877-20-000010/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2019/0000077877-20-000010/item13.txt b/raw/filings/0000077877/2019/0000077877-20-000010/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..6c12e451c3c47fe2c3518ace25d3992ab39ed06f --- /dev/null +++ b/raw/filings/0000077877/2019/0000077877-20-000010/item13.txt @@ -0,0 +1,2 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2020 Annual Stockholders' meeting and is incorporated by reference in this report. \ No newline at end of file diff --git a/raw/filings/0000077877/2019/0000077877-20-000010/item9a.txt b/raw/filings/0000077877/2019/0000077877-20-000010/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..ecd9e533c05419b5827daab1938b5b4f100bd9c3 --- /dev/null +++ b/raw/filings/0000077877/2019/0000077877-20-000010/item9a.txt @@ -0,0 +1,13 @@ +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +As of December 31, 2019 , we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Based on the results of this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2019 . +Management's Report on Internal Control over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Internal control over financial reporting is a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer, or persons performing similar functions, and effected by our board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate. +Management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2019, based upon the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). +The effectiveness of our internal control over financial reporting as of December 31, 2019 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears under Item 8. +Remediation of Material Weaknesses +We previously identified and disclosed in our Annual Report on Form 10-K for the year ended December 31, 2018 material weaknesses in our internal control over financial reporting related to an insufficient complement of personnel within our Land Department, which contributed to the ineffective design and maintenance of controls to verify the completeness and accuracy of certain land administrative records associated with unproved leases. +We remediated these material weaknesses in 2019 by enhancing the design of existing controls through a combination of new leadership, hiring additional personnel with relevant experience and increased layers of supervision and division of responsibilities within the Land Department. We also redesigned existing control activities to verify the completeness and accuracy of land administrative records associated with unproved leases, including the verification of the reliability of underlying data used in the execution of the control activities. +Changes in Internal Control over Financial Reporting +There were no changes in our internal control over financial reporting during the quarter ended December 31, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. \ No newline at end of file diff --git a/raw/filings/0000077877/2019/0000077877-20-000010/rp_note.txt b/raw/filings/0000077877/2019/0000077877-20-000010/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2019/0000077877-20-000010/rpt_disclosure.txt b/raw/filings/0000077877/2019/0000077877-20-000010/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..f1865e5caa4e0d3476e80b1a0531a92bcd2ff706 --- /dev/null +++ b/raw/filings/0000077877/2019/0000077877-20-000010/rpt_disclosure.txt @@ -0,0 +1,5 @@ +TRANSACTIONS WITH RELATED PARTIES +During 2020, there was no transaction or series of transactions, nor is there any currently proposed transaction, involving an amount exceeding $120,000 in which the Company is or was a participant and in which any Director, executive officer, known holder of more than five percent of the Company’s voting securities, or any member of the immediate family of any of the foregoing persons, had or has a direct or indirect material interest for which disclosure is required under Item 404 of Regulation S-K. +POLICIES AND PROCEDURES WITH RESPECT TO TRANSACTIONS WITH RELATED PARTIES +The Board has adopted a written policy for the review, approval and ratification of transactions that involve related parties and potential conflicts of interest. The related-party transaction policy applies to each Director and executive officer of the Company, any nominee for election as a Director, any security holder who is known to own more than five percent of the Company’s voting securities, any immediate family member of any of the foregoing persons and any corporation, firm or association in which one or more of the Company’s Directors or executive officers have a substantial interest. +Under our related-party transaction policy, a related-party transaction is a transaction or arrangement involving a related party in which the Company is a participant or that would require disclosure in the Company’s filings with the SEC as a transaction with a related party. The related party must disclose to the Audit Committee any potential related-party transactions and must disclose all material facts with respect to such transaction and relationship. All related-party transactions so disclosed will be reviewed by the Audit Committee. In determining whether to approve or ratify a transaction, the Audit Committee will consider the relevant facts and circumstances of the transaction, which may include factors such as the relationship of the related party to the Company, the materiality or significance of the transaction to the Company and the business purpose and reasonableness of the transaction, whether the transaction is comparable to a transaction that could be available to the Company from an unrelated party and the impact of the transaction on the Company’s business and operations. \ No newline at end of file diff --git a/raw/filings/0000077877/2020/0000077877-21-000020/filing.txt b/raw/filings/0000077877/2020/0000077877-21-000020/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..f0eb607259c6fbad7037a5d4e1cc264423b263af --- /dev/null +++ b/raw/filings/0000077877/2020/0000077877-21-000020/filing.txt @@ -0,0 +1,2802 @@ +pdce-20201231 +PDC ENERGY, INC. 0000077877 12/31 2020 FY false 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Employer Identification No.) +1775 Sherman Street, Suite 3000 +Denver , Colorado 80203 +(Address of principal executive offices) (Zip code) +Registrant's telephone number, including area code: ( 303 ) 860-5800 +Securities registered pursuant to Section 12(b) of the Act: +Title of each class Ticker Symbol Name of each exchange on which registered +Common Stock, par value $0.01 per share PDCE NASDAQ Global Select Market +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes T No £ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes £ No T +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes T No £ +Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes T No £ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definitions of "large accelerated filer," "accelerated filer," "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act. +Large accelerated filer ☒ Accelerated filer ☐ +Non-accelerated filer ☐ Smaller reporting company ☐ +Emerging growth company ☐ +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. £ +Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No T +The aggregate market value of our common stock held by non-affiliates on June 30, 2020 was $ 1.2 billion (based on the closing price of $12.44 per share as of the last business day of the fiscal quarter ending June 30, 2020 ). +As of February 16, 2021 , there were 99,781,332 shares of our common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +We hereby incorporate by reference into this document the information required by Part III of this Form, which will appear in our definitive proxy statement filed pursuant to Regulation 14A for our 2021 Annual Meeting of Stockholders. +PDC ENERGY, INC. +2020 ANNUAL REPORT ON FORM 10-K +TABLE OF CONTENTS +PART I Page +Items 1. and 2. +Business and Properties +3 +Item 1A. +Risk Factors +22 +Item 1B. +Unresolved Staff Comments +36 +Item 3. +Legal Proceedings +36 +Item 4. +Mine Safety Disclosures +36 +PART II +Item 5. +Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +37 +Item 6. +Selected Financial Data +39 +Item 7. +Management's Discussion and Analysis of Financial Condition and Results of Operations +40 +Item 7A. +Quantitative and Qualitative Disclosures About Market Risk +62 +Item 8. +Financial Statements and Supplementary Data +64 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +115 +Item 9A. +Controls and Procedures +115 +Item 9B. +Other Information +115 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +116 +Item 11. +Executive Compensation +116 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +116 +Item 13. +Certain Relationships and Related Transactions and Director Independence +116 +Item 14. +Principal Accounting Fees and Services +116 +PART IV +Item15. +Exhibits, Financial Statement Schedules +116 +Item 16. +Form 10-K Summary +116 +Signatures +120 +Glossary of Units of Measurements and Industry Terms +121 +PART I +REFERENCES TO THE REGISTRANT +Unless the context otherwise requires, references in this report to "PDC," the "Company," "we," "us," "our" or "ours" refer to the registrant, PDC Energy, Inc. and our wholly-owned subsidiaries consolidated for the purposes of our financial statements. +GLOSSARY OF UNITS OF MEASUREMENTS AND INDUSTRY TERMS +Units of measurements and industry terms are defined in the Glossary of Units of Measurements and Industry Terms, included at the end of this report. +SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS +This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act") and Section 21E of the Securities Exchange Act of 1934 ("Exchange Act") and the United States ("U.S.") Private Securities Litigation Reform Act of 1995 regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical fact included in and incorporated by reference into this report are "forward-looking statements." Words such as expect, anticipate, intend, plan, believe, seek, estimate, schedule and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements include, among other things, statements regarding future: production, costs and cash flows; impacts of Colorado political matters, including recent rulemaking initiatives, given our geographic concentration; drilling locations, zones and growth opportunities; commodity prices and differentials; capital expenditures and projects, including the number of rigs employed; cash flows from operations relative to future capital investments; financial ratios and compliance with covenants in our revolving credit facility and other debt instruments; impacts of certain accounting and tax changes; ability to meet our volume commitments to midstream providers and timing and adequacy of midstream infrastructure; the potential return of capital to shareholders through buyback of shares and/or issuance of a dividend; ongoing compliance with our consent decree; risk of our counterparties non-performance on derivative instruments; and our ability to repay our 1.125% convertible notes due 2021 (the "2021 Convertible Notes") and fund planned activities. +The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this report or accompanying materials, we may use the term “projection” or similar terms or expressions, or indicate that we have “modeled” certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or our industry in periods beyond the current fiscal year. Because such statements relate to events or conditions further in the future, they are subject to increased levels of uncertainty. +Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to: +• the COVID-19 pandemic, including its effects on commodity prices, downstream capacity, employee health and safety, business continuity and regulatory matters; +• changes in global production volumes and demand, including economic conditions that might impact demand and prices for the products we produce; +• impact of political and regulatory developments in Colorado, particularly with respect to additional permit scrutiny; +• geopolitical factors, such as events that may reduce or increase production from particular oil-producing regions and/or from members of the Organization of Petroleum Exporting Countries; +• volatility of commodity prices for crude oil, natural gas and natural gas liquids ("NGLs") and the risk of an extended period of depressed prices, including risks relating to decreased revenue, income and cash flow, write-downs and impairments and availability of capital; +• volatility and widening of differentials; +• reductions in the borrowing base under our revolving credit facility; +1 +• impact of governmental policies and/or regulations, including changes in environmental and other laws, the interpretation and enforcement of those laws and regulations, liabilities arising thereunder and the costs to comply with those laws and regulations; +• declines in the value of our crude oil, natural gas and NGLs properties resulting in impairments; +• changes in estimates of proved reserves; +• inaccuracy of reserve estimates and expected production rates; +• potential for production decline rates from our wells being greater than expected; +• timing and extent of our success in discovering, acquiring, developing and producing reserves; +• availability and cost of sufficient pipeline, gathering and other transportation facilities and related infrastructure to process and transport our production and the impact of these facilities and regional capacity on the prices we receive for our production; +• risks incidental to the drilling and operation of crude oil and natural gas wells; +• difficulties in integrating our operations and potential effects on capital requirements as a result of any significant acquisitions or acreage exchanges; +• increases in costs and expenses; +• limitations in the availability of supplies, materials, contractors and services that may delay the drilling or completion of our wells; +• potential losses of acreage due to lease expirations or otherwise; +• future cash flows, liquidity and financial condition; +• competition within the oil and gas industry; +• availability and cost of capital; +• success in marketing our crude oil, natural gas and NGLs; +• effect of crude oil and natural gas derivative activities; +• impact to our operations, personnel retention, strategy, stock price and expenses caused by the actions of activist shareholders; +• impact of environmental events, governmental and other third-party responses to such events and our ability to insure adequately against such events; +• cost of pending or future litigation; +• our ability to replace our oil and natural gas reserves; +• title defects in our oil and natural gas properties; +• civil unrest, terrorist attacks and cyber threats; +• our ability to retain or attract senior management and key technical employees; and +• success of strategic plans, expectations and objectives for our future operations. +Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under Item 1A, Risk Factors , made in this report and our other filings with the U.S. Securities and Exchange Commission ("SEC") for further information on risks and uncertainties that could affect our business, financial condition, results of operations and prospects, which are incorporated by this reference as though fully set forth herein. We caution you not to place undue reliance on the forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement. +2 +ITEMS 1. AND 2. BUSINESS AND PROPERTIES +The Company +We are a domestic independent exploration and production company that acquires, explores and develops properties for the production of crude oil, natural gas and NGLs, with operations in the Wattenberg Field in Colorado and the Delaware Basin in west Texas. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are primarily focused in the horizontal Wolfcamp zones. +The following map presents the general locations of our development and production activities as of December 31, 2020: +3 +The following table presents selected information regarding our results of operations for the periods presented: +Year Ended/As of +December 31, Percent Change +2020 2019 2020-2019 +(production and reserves in MMBoe, dollars in millions) +Wells: +Gross productive wells 3,727 2,649 41 % +Net productive wells 2,841 2,101 35 % +Horizontal percentage 57 % 48 % 19 % +Gross operated wells turned-in-line 137 135 1 % +Net operated wells turned-in-line 129.5 125.0 4 % +Production: +Wattenberg Field 57.5 38.0 51 % +Delaware Basin 10.8 11.4 (5) % +Total 68.4 49.4 38 % +Reserves: +Proved reserves 731.1 610.9 20 % +Proved developed reserves percentage 44 % 35 % 26 % +Standardized measure $ 3,282.2 $ 3,310.3 (1) % +PV-10 (1) +$ 3,454.6 $ 3,837.0 (10) % +Liquidity $ 1,400 $ 1,291 8 % +Leverage ratio 1.7 1.4 21 % +_____________ +(1) PV-10 is a non-U.S. GAAP financial measure. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in accordance with U.S. generally accepted accounting principles (“U.S. GAAP”), but rather should be considered in addition to the standardized measure. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10 and a reconciliation of our PV-10 value to the standardized measure included elsewhere in this report. +Significant 2020 Events +SRC Acquisition +In January 2020, we merged with SRC in a transaction valued at $1.7 billion, inclusive of SRC's net debt (the “SRC Acquisition”). Upon closing, we issued approximately 38.9 million shares of our common stock to SRC shareholders and holders of SRC equity awards, reflecting the issuance of 0.158 of a share of our common stock in exchange for each outstanding share of SRC common stock and the cancellation of outstanding SRC equity awards pursuant to the merger agreement that we entered into with SRC (the "Merger Agreement"). SRC's acreage was located on large, contiguous acreage blocks in the core Wattenberg Field. The acquisition added approximately 83,000 net acres to our asset portfolio. +In connection with the completion of the SRC Acquisition, we paid off and terminated SRC's revolving credit facility and we assumed $550.0 million aggregate principal amount of 6.25% senior notes due December 1, 2025 (the "SRC Senior Notes"). On January 17, 2020, we commenced an offer to repurchase the outstanding SRC Senior Notes at 101 percent of the principal amount. Upon expiration of the repurchase offer on February 18, 2020, holders of $447.7 million of the outstanding SRC Senior Notes accepted our redemption offer for a total redemption price of approximately $452.2 million, plus accrued and unpaid interest of $6.2 million. An aggregate principal amount of approximately $102.3 million of the SRC Senior Notes remains outstanding. We funded the aforementioned payment and termination of SRC's credit facility and repurchase of SRC Senior Notes with proceeds from our revolving credit facility. +4 +Senior Notes Offering +In September 2020, we issued an additional $150.0 million principal amount of our 5.75% Senior Notes due in May 2026 (the "2026 Senior Notes"). The net proceeds from the offering were used to repay a portion of the amount outstanding under our revolving credit facility. +Business Strategy and Key Strengths +Our long-term business strategy focuses on creating shareholder value by: (i) delivering attractive returns from responsible development of our crude oil and natural gas properties; (ii) maintaining financial strength; (iii) generating sustainable cash flows from operations in excess of our capital investments in crude oil and natural gas properties; and (iv) returning capital to shareholders. Our key strengths create long-term shareholder value through the following: +• Strong financial position. We maintain a disciplined financial strategy that focuses on strong liquidity, low leverage ratios and an active commodity derivative program to help mitigate a portion of the risk associated with commodity price fluctuations. We believe that execution of this strategy will allow us to deliver strong corporate cash flows year-over-year, even through challenging commodity price environments. As of December 31, 2020, we had total liquidity of $1.4 billion, a leverage ratio, as defined in our revolving line of credit facility agreement, of 1.7x and commodity derivative positions covering approximately 14.2 MMBbls and 5.8 MMBbls of crude oil production for 2021 and 2022, respectively. As of the same date, we had hedged approximately 94,400 BBtu and 26,100 BBtu of natural gas production for 2021 and 2022, respectively. +• Focus on generating sustainable cash flows from operations in excess of capital investments. We are focused on generating multi-year sustainable cash flows from operations in excess of our capital investments through managing capital spending and growth rates, adjusting the timing of completion of our inventory of drilled uncompleted wells ("DUCs"), utilizing commodity derivative instruments, focusing on margin improvement from reductions in our cost structure and through increased capital efficiency from technological innovation. Our adjusted free cash flows, a non-GAAP measure, is used as a measure of our ability to return capital to shareholders, reduce debt levels and maintain strong liquidity. In 2020, we generated cash flows from operations of $870.1 million and adjusted free cash flows of $399.3 million. +• Absolute debt reduction, conservative total leverage targets and return of capital to shareholders. Through successful execution of our business plan, we meaningfully reduced our indebtedness to below $1.5 billion as of the date of this report. Consistent with our strategic goals, PDC reinstated its Stock Repurchase Program in late February 2021 and our board of directors recently approved a quarterly dividend program expected to commence mid-2021. PDC is positioned to focus on returning capital to shareholders and continued additional debt reductions, with a long-term target leverage ratio of 1.0x or below. +• Significant operational control in our core areas. We have, and expect to continue to have, a substantial degree of operational control over our properties. As a result of successfully executing our strategy of acquisitions and acreage trades in our core areas of operations, we have built multiple concentrated acreage positions with high working interests that we believe will allow us to enhance the value of our assets and replenish our drilling inventory. We currently operate approximately 77 percent of all the wells in which we have an interest. This operational control allows us to better manage our drilling, production, operating and administrative costs and to leverage our technical expertise in our core operating areas. Our leaseholds that are held by production further enhance our operational control by providing us with additional flexibility on the timing of drilling of those locations. +• Strong environmental, health and safety compliance programs and community outreach . We have focused on establishing effective environmental, health and safety programs that are intended to promote safe working practices for our employees and contractors and to help earn the trust and respect of land owners, regulatory agencies and public officials. This is an important part of our strategy in effectively operating in today’s intensive regulatory climate. We are also dedicated to being an active and contributing member of the communities in which we operate. We share our success with these communities in various ways, including charitable giving and community event sponsorships. We also strive to achieve continuous improvement in our corporate governance and have a demonstrated commitment to being responsive to investor input. In September of 2020, we released our inaugural Sustainability Report, which +5 +aligned with a formal Environmental, Social, and Governance ("ESG") reporting framework – Sustainability Accounting Standards Board – and increased transparency into our operations. +• Project inventory in two premier crude oil, natural gas and NGL plays. We have a substantial multi-year inventory of high-quality horizontal drilling opportunities across two premier U.S. onshore basins: the Wattenberg Field in Weld County, Colorado and the Delaware Basin in Reeves County, Texas. Our portfolio has a proven record of delivering strong and repeatable economic returns and provides us the ability to allocate capital investments and manage risk as each basin has its own operating and competitive dynamic in terms of commodity price markets, service costs, takeaway capacity and regulatory and political considerations. We have a disciplined development program that seeks to expand our project inventory through testing new intervals and considering various spacing configurations. We believe our project inventory will allow us to achieve attractive rates of return and grow our proved reserves and production in a sustainable fashion. Such expected returns on drilling can vary well by well and are based upon many factors, including but not limited to, commodity prices and well development and operating costs. +• Efficiency through technology and consolidation. Technological innovation has led to continued improvement in our drilling and completion times. We are utilizing technology to improve the efficiency of our horizontal drilling and completion operations in the Wattenberg Field. We continue to make progress towards improved capital efficiency through various drilling initiatives and completion designs in the Delaware Basin. The technology associated with our completions process continues to improve as we design wellbore placement and stage spacing and, in the Wattenberg Field, increase the completed lateral length of our wells. In addition, completion equipment, perforation clusters, fluid and sand type and concentration decisions continue to result in more efficient recoveries of crude oil and natural gas reserves. We continually optimize the expertise we have developed in the Wattenberg Field, to increase the efficiency of our Delaware Basin processes and procedures. Additionally, acreage consolidation, particularly in the Wattenberg Field, increases our ability to drill longer length lateral wells. Longer laterals allow us to develop our properties with a smaller number of wells and less truck traffic, with resulting benefits for our operations and for the communities in which we operate. +• Experienced management team with proven track record. We have a strong executive management team that has an average of 25 years of experience in the oil and gas industry. Collectively, this experience includes technical, operational, commercial, financial, legal and strategic aspects of the oil and gas industry. This team has a proven track record of executing value-added capital investment programs with a focus on financial discipline and improving on an already strong balance sheet, while growing production and proved reserves. Additionally, our team's experience has helped us continue to achieve our strategic objectives through periods of commodity price volatility, cost inflation and other challenging operating environments. +Operating Areas +Wattenberg Field. In the Wattenberg Field, we have identified a gross operated inventory of approximately 2,000 horizontal drilling locations that we expect to generate acceptable rates of return based on forward strip pricing, with an average lateral length of approximately 9,000 feet. Our inventory consists of approximately 200 gross operated DUCs, 300 approved permits, reflecting approximately 3.5 years of turn-in-line activity based on our current drilling plan, and 1,500 unpermitted locations. Our Wattenberg Field horizontal drilling locations have been substantially de-risked through multiple years of successful development in the field. We continue to analyze and test various wellbore spacing configurations in areas of the field that we believe have the potential to increase our gross operated inventory. Substantially all of our Wattenberg Field acreage is held by production. Wells in the Wattenberg Field typically have productive horizons at depths of approximately 6,500 to 7,500 feet below the surface. We continue to pursue various business development initiatives, with a focus on acreage exchanges or acquisitions, designed to increase our Wattenberg Field project inventory or to increase our ownership in our operated wells. +Delaware Basin. In the Delaware Basin, we have identified a gross operated economic inventory of approximately 115 horizontal drilling locations and 20 gross operated DUCs that we expect to generate acceptable rates of return based on forward strip pricing, targeting the Wolfcamp A and Wolfcamp B zones, within the oilier eastern and north central portions of our acreage. We continue to analyze and test various wellbore spacing configurations in areas of the field. Additionally, we have the possibility of adding inventory locations, outside of our target zones, in the future if the return on the wells meet our required economics. The average lateral length of these locations is approximately 8,900 feet. Wells in the Delaware Basin typically have productive horizons at depths of approximately 9,000 to 11,500 feet below the surface. We continue to pursue +6 +various business development initiatives, with a focus on acreage exchanges and joint development projects, designed to increase our Delaware Basin project inventory by establishing longer lateral drilling units capable of delivering attractive economic returns. +Oil and Gas Production and Operations +Proved Oil and Gas Reserves +The following table presents our proved reserve estimates as of December 31, 2020, 2019 and 2018: +December 31, +2020 2019 2018 +Proved reserves +Crude oil and condensate (MMBbls) +212 197 190 +Natural gas (Bcf) +1,901 1,558 1,336 +NGLs (MMBbls) +203 154 132 +Total proved reserves (MMBoe) +731 611 545 +Proved developed reserves (MMBoe) +322 214 180 +Standardized measure (in millions) +$ 3,282.2 $ 3,310.3 $ 4,447.7 +Estimated undiscounted future net cash flows (in millions) (1) +$ 5,633.1 $ 5,895.9 $ 7,735.0 +PV-10 ( in millions) (2) +$ 3,454.6 $ 3,837.0 $ 5,321.3 +_____________ +(1) Amount represents aggregate undiscounted future net cash flows, before income taxes approximately $5.9 billion, $6.8 billion and $9.1 billion as of December 31, 2020, 2019 and 2018, respectively, less an internally-estimated undiscounted future income tax expense of approximately $0.3 billion, $0.9 billion and $1.4 billion, respectively. +(2) PV-10 is a non-U.S. GAAP financial measure. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in accordance with U.S. GAAP, but rather should be considered in addition to the standardized measure. See Part II, Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10 and a reconciliation of our PV-10 value to the standardized measure. +The additions to our proved reserves at December 31, 2020 as compared to December 31, 2019 were primarily due to the SRC Acquisition which were partially offset by downward revisions as a result of decreases in realized prices and revised drilling plans following the completion of the SRC Acquisition. +The following table presents our proved reserve estimates by category as of December 31, 2020: +As of December 31, 2020 +Operating Region/Area Crude Oil and Condensate (MMBbls) Natural Gas (Bcf) NGLs (MMBbls) Crude Oil Equivalent (MMBoe) Percent +Proved developed +Wattenberg Field 69.1 752.3 80.9 275.5 38 % +Delaware Basin 17.2 108.6 10.8 46.0 6 % +Total proved developed 86.3 860.9 91.7 321.5 44 % +Proved undeveloped +Wattenberg Field 105.7 958.8 102.7 368.1 50 % +Delaware Basin 19.7 81.5 8.1 41.5 6 % +Total proved undeveloped 125.4 1,040.3 110.8 409.6 56 % +Total proved reserves +Wattenberg Field 174.8 1,711.1 183.6 643.6 88 % +Delaware Basin 36.9 190.1 18.9 87.5 12 % +Total proved reserves 211.7 1,901.2 202.5 731.1 100 % +7 +Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Positive impacts of these variables and assumptions may result in a longer economic productive life of a property or the recognition of more economically viable proved undeveloped ("PUD") reserves, while negative impacts of these variables and assumptions may result in corresponding negative impacts. All of our proved reserves are located in the United States. +Commodity Pricing . Per SEC rules, the pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of the month prices for the preceding 12 months. The NYMEX prices used in preparing the reserves are then adjusted based on energy content, location and basis differentials and other marketing deductions to arrive at the net realized price. +Average Benchmark Prices +December 31, +Crude Oil (per Bbl) (1) +Natural Gas (per MMBtu) (1) +NGLs (per Bbl) (2) +2020 $ 39.57 $ 1.99 $ 39.57 +2019 55.69 2.58 55.69 +2018 65.56 3.10 65.56 +____________ +(1) Our benchmark prices for crude oil and natural gas are WTI and Henry Hub, respectively. +(2) For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. +The netted back price used to estimate our reserves, by commodity, are presented below. +Price Used to Estimate Reserves (1) +December 31, Crude Oil +(per Bbl) Natural Gas +(per MMBtu) +NGLs (per Bbl) +2020 $ 37.52 $ 1.26 $ 10.55 +2019 52.63 1.50 12.21 +2018 61.14 2.15 23.04 +____________ +(1) These prices are based on the index prices and are net of basin differentials, transportation fees, contractual adjustments and Btu adjustments we experienced for the respective commodity. +Proved Reserves Sensitivity Analysis. We have performed an analysis of our proved reserve estimates as of December 31, 2020 to present sensitivity associated with a lower crude oil price as the value of crude oil influences the value of our proved reserves and PV-10 most significantly. Replacing the 2020 NYMEX price for crude oil used in estimating our reported proved reserves with $35.00 as shown on the table below, and leaving all other parameters unchanged, results in changes to our estimated proved reserves as shown. +Pricing Scenario - NYMEX +Crude Oil (per Bbl) Natural Gas (per MMBtu) Proved Reserves (MMBoe) % Change from December 31, 2020 Estimated Reserves PV-10 +(in Millions) PV-10 % Change from December 31, 2020 Estimated Reserves +2020 SEC Reserve Report (1) +$ 39.57 $ 1.99 731.1 — $ 3,454.6 — +Alternate Price Scenario $ 35.00 $ 1.99 723.4 (1) % $ 2,921.4 (15) % +_____________ +(1) These prices are the SEC NYMEX prices applied to the calculation of the PV-10 value. Such prices have been applied consistently in the alternate pricing scenario to include the impact of adjusting for deductions for any basin differentials, transportation fees, contractual adjustments and Btu adjustments we experienced for the relevant commodity. +Commodities and Standardized Measure . Reserve estimates involve judgments and reserves cannot be measured exactly. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geologic and geophysical data and economic changes. Neither the estimated future net cash flows nor the +8 +standardized measure of discounted future net cash flows ("standardized measure") is intended to represent the current market value of our proved reserves. +For additional information regarding our standardized measures, as well as other information regarding our proved reserves, see Supplemental Information- Crude Oil and Natural Gas Properties included in Item 8. Financial Statements and Supplementary Data provided with our consolidated financial statements included elsewhere in this report. +Preparation of Reserve Estimates +Our proved reserves estimates as of December 31, 2020 were based on evaluations prepared by our independent petroleum engineering consulting firms, Ryder Scott Company, L.P. ("Ryder Scott") and Netherland, Sewell & Associates, Inc. ("NSAI") (collectively, our "external engineers"). Our proved reserve estimates were prepared in accordance with guidelines established by the SEC and the Financial Accounting Standards Board (the "FASB"). +Controls Over Reserve Report Preparation . Inputs and major assumptions related to our proved reserves are reviewed annually by an internal team composed of reservoir engineers, geologists, land and management for adherence to SEC guidelines through a detailed review of land and accounting records, available geological and reservoir data and production performance data. The internal team compiles the reviewed data and forwards the applicable data to our external engineers. +Annually, the Director of Reservoir Engineering & Technology reviews the reserves to ensure all the necessary significant inputs and steps are completed within our reserve process. After final approval from the Director of Reservoir Engineering & Technology, the results are presented to senior management and to our board of directors for their review. +Together, these internal controls are designed to promote a comprehensive, objective, and accurate reserves estimation process. As an additional confirmation of the reasonableness of our internal estimates, Ryder Scott and NSAI performed an independent evaluation of our estimated proved reserves in the Wattenberg Field and Delaware Basin, respectively, as of December 31, 2020. +When preparing our reserve estimates, our external engineers do not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, production volumes, well test data, historical costs of operations and development, product prices or any agreements relating to current and future operations of properties or sales of production. Our external engineers prepare estimates of our reserves in conjunction with an ongoing review by our engineers. A final comparison of data is performed to ensure that the reserve estimates are complete, determined pursuant to acceptable industry methods and with a level of detail we deem appropriate. The final estimated reserve reports are prepared by our external engineers and reviewed by our engineering staff and management prior to issuance by those firms. +In determining our proved reserves estimates, we used a combination of performance methods, including decline curve analysis and other computational methods, offset analogies and seismic data and interpretation. All of our proved undeveloped reserves conform to the SEC five-year rule requirement as all proved undeveloped locations are scheduled, according to an adopted development plan, to be drilled within five years of the location’s initial booking date. +Qualifications of Responsible Technical Persons. The professional qualifications of our lead engineer primarily responsible for overseeing the preparation of our reserve estimates, as defined in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the Society of Petroleum Engineers, qualifies this individual as a Reserve Estimator. This person holds a Masters of Petroleum Engineering from the Colorado School of Mines and a Bachelors of Geology from the University of Colorado and has over 20 years of oil and gas experience. +Letters which identify the professional qualifications of the individuals at Ryder Scott and NSAI who are responsible for overseeing the preparation of our reserve estimates as of December 31, 2020 have been filed as Exhibits 99.1 and 99.2 to this report. +Production, Prices and Costs +Production and operating data for the years ended December 31, 2020, 2019 and 2018 was included in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations included elsewhere in this report. +9 +Productive Wells +The following table presents our productive wells by operating area as of December 31, 2020: +Crude Oil Natural Gas Total +Operating Region/Area Gross Net Gross Net Gross Net +Wattenberg Field 2,062 1,439.2 1,552 1,310.4 3,614 2,749.6 +Delaware Basin 50 31.7 63 59.2 113 90.9 +Total productive wells 2,112 1,470.9 1,615 1,369.6 3,727 2,840.5 +Developed and Undeveloped Acreage +The following table presents our developed and undeveloped lease acreage as of December 31, 2020: +Developed Undeveloped Total +Operating Region/Area Gross Net Gross Net Gross Net +Wattenberg Field 166,166 154,958 70,797 64,720 236,963 219,678 +Delaware Basin 27,525 25,401 1,362 635 28,887 26,036 +Total acreage 193,691 180,359 72,159 65,355 265,850 245,714 +Developed lease acreage are acres spaced or assigned to productive wells and do not include undrilled acreage held by production under the terms of the lease. Large portions of the acreage that are considered developed under SEC guidelines are developed with vertical wells or horizontal wells that are in a single horizon. We believe much of this acreage has significant remaining development potential in one or more intervals with horizontal wells. Undeveloped acreage are acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves. +Substantially all of our undeveloped acreage in the Wattenberg Field and Delaware Basin are related to leaseholds that are held by production. Our Wattenberg Field leaseholds at risk to expire in 2021, 2022 and 2023 are not material. In the Delaware Basin, the majority of the drilling obligations or continuous drilling clauses associated with the asset have been met. Our Delaware Basin leaseholds at risk to expire in 2021, 2022 and 2023 are not material. See Item 1A. Risk Factors - Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in substantial lease renewal costs or, if renewal is not feasible, loss of our lease and prospective drilling opportunities. +10 +Drilling Results +The following tables set forth a summary of our developmental and exploratory well drilling results for the periods presented. Productive wells consist of wells that were turned-in-line and commenced production during the period, regardless of when drilling was initiated. In-process wells represent wells that are in the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection as of the date shown. We utilize pad drilling operations where multiple wells are developed from the same well pad in both the Wattenberg Field and Delaware Basin. Because we may operate multiple drilling rigs in each operating area, we expect to have in-process wells at any given time. Wells may be in-process for up two years. +Gross Development Well Drilling Activity +Year Ended December 31, +2020 2019 2018 +Operating Region/Area +Productive (1) +In-Process (1) +Non-Productive Productive In-Process Non-Productive Productive In-Process Non-Productive +Wattenberg Field, operated wells 124 214 — 114 145 — 139 133 — +Wattenberg Field, non-operated wells 27 48 — 12 41 — 20 5 — +Delaware Basin, operated wells 13 18 — 21 26 — 26 22 1 +Delaware Basin, non-operated wells — — — 9 — — 11 — — +Total gross development wells 164 280 — 156 212 — 196 160 1 +_____________ +(1) Amounts include 88 and seven gross in-process operated and non-operated development wells, respectively, received in the SRC Acquisition, of which a portion were completed during the period. +Net Development Well Drilling Activity +Year Ended December 31, +2020 2019 2018 +Operating Region/Area +Productive (1) +In-Process (1) +Non-Productive Productive In-Process Non-Productive Productive In-Process +Non-Productive +Wattenberg Field, operated wells 116.5 201.8 — 105.1 135.0 — 126.8 122.4 — +Wattenberg Field, non-operated wells 0.9 3.5 — 1.1 3.7 — 2.5 0.9 — +Delaware Basin, operated wells 13.0 17.2 — 20.1 25.3 — 24.5 16.3 1.0 +Delaware Basin, non-operated wells — — — 1.3 — — 1.2 — — +Total net development wells 130.4 222.5 — 127.6 164.0 — 155.0 139.6 1.0 +_____________ +(1) Amounts include 80 and one net in-process operated and non-operated development wells, respectively, received in the SRC Acquisition, of which a portion were completed during the period. +Exploratory Well Drilling Activity +Year Ended December 31, +2020 2019 2018 +Productive In-Process Productive In-Process Productive In-Process +Operating Region/Area Gross Net Gross Net Gross Net Gross Net Gross Net Gross Net +Delaware Basin 2 2.0 2 1.9 2 2.0 4 3.9 3 2.8 2 2.0 +There were no exploratory drilling activities in the Wattenberg Field during 2020, 2019 and 2018. +11 +Title to Properties +We believe that we hold good and defensible leasehold title to substantially all of our crude oil and natural gas properties, in accordance with standards generally accepted in the industry. A preliminary title examination is typically conducted at the time the undeveloped properties are acquired. Prior to the commencement of drilling operations, a title examination is conducted and remedial curative work is performed, as necessary, with respect to discovered defects which we deem to be significant, in order to procure division order title opinions. Title examinations have been performed with respect to substantially all of our producing properties. +The properties we own are subject to royalty, overriding royalty and other outstanding interests. The properties may also be subject to additional burdens, liens or encumbrances customary in the industry, including items such as operating agreements, current taxes, development obligations under crude oil and natural gas leases, farm-out agreements and other restrictions. We do not believe that any of these burdens will materially interfere with our use of the properties. +Substantially all of our crude oil and natural gas properties have been mortgaged or pledged as security for amounts borrowed under our revolving credit facility. +Offices +As of December 31, 2020, we leased corporate space in 1775 Sherman Street, Suite 3000, Denver, Colorado, where our corporate headquarters is located. We also maintain offices in Evans, Colorado and Midland, Texas. We anticipate closing on the sale of our office building we own in Bridgeport, West Virginia in the first half of 2021. +Significant Customers +We sell our crude oil and natural gas production to marketers and other purchasers which have access to pipeline facilities. In areas where there is no practical access to pipelines, oil is transported to storage facilities by trucks owned or otherwise arranged by the marketers or purchasers. The majority of our crude oil and natural gas production is transported through pipelines. +We made sales to four customers that each contributed to 10 percent or more of our 2020 total crude oil, natural gas and NGLs revenues. However, given the liquidity in the market for the sale of hydrocarbons, we believe that the loss of any single purchaser, or the aggregate loss of several purchasers, could be managed by selling to alternative purchasers. +Seasonality of Business +Weather conditions affect the demand for and prices of crude oil and natural gas. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of our annual results. +Delivery Commitments +Certain of our firm sales agreements for crude oil include delivery commitments. We believe our current production and reserves are sufficient to fulfill these delivery commitments. See Note 12 - Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data for more information. +Governmental Regulation +The U.S. crude oil and natural gas industry is extensively regulated at the federal, state and local levels. The following is a summary of certain laws, rules and regulations currently in force that apply to us. The regulatory environment in which we operate changes frequently and we cannot predict the timing or nature of such changes or their effects on us. +Regulation of Crude Oil and Natural Gas Exploration and Production. Our exploration and production activities are subject to a variety of rules and regulations concerning drilling permits, location, spacing and density of wells, water discharge and disposal, prevention of waste, bonding requirements, surface use and restoration, public health and environmental protection and well plugging and abandonment. The primary state-level regulatory authority regarding these matters in Colorado is the Colorado Oil and Gas Conservation Commission ("COGCC") and in Texas is the Texas Railroad Commission. +12 +Prior to preparing a surface location and commencing drilling operations on a well, we must procure permits and/or approvals for the various stages of the drilling process from the relevant state and local agencies. In addition, our operations must comply with rules governing the size of drilling and spacing units or proration units and the unitization or pooling of lands and leases. Some states, such as Colorado, allow the forced pooling or integration of tracts to facilitate exploration while other states, such as Texas, rely primarily or exclusively on voluntary pooling of lands and leases. +In states such as Texas where pooling is primarily or exclusively voluntary, it may be more difficult to form units and therefore to drill and develop our leases in circumstances where we do not own all of the leases in the proposed unit. These risks also exist in Colorado, where a recent rule change has imposed new limits on forced pooling. State laws may also prohibit the venting or flaring of natural gas, which may impact rates of production of crude oil and natural gas from our wells. Leases covering state or federal lands often include additional laws, regulations and conditions which can limit the location, timing and number of wells we can drill and impose other requirements on our operations, all of which can increase our costs. +Regulation of Transportation of Commodities. We move natural gas through pipelines owned by other entities and sell natural gas to other entities that also utilize common carrier pipeline facilities. Natural gas pipeline interstate transmission and storage activities are subject to regulation by the Federal Energy Regulatory Commission ("FERC") under the Natural Gas Act of 1938 ("NGA") and under the Natural Gas Policy Act of 1978 ("NGPA"). Rates and charges for the transportation of natural gas in interstate commerce, and the extension, enlargement or abandonment of jurisdictional facilities, among other things, are subject to regulation. +In addition, the Energy Policy Act of 2005 (the "EPAct 2005") prohibits “any entity” from using any deceptive or manipulative device or contrivance in connection with the purchase or sale of gas or the purchase or sale of transportation services subject to regulation by FERC. The EPAct 2005 provides FERC with substantial enforcement authority to prohibit such manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. +FERC Order 704 requires that any market participant, including natural gas producers, gatherers and marketers, that engaged in wholesale sales or purchases of natural gas that equaled or exceeded 2.2 MMBtus of physical natural gas in the previous calendar year to report to FERC the aggregate volumes of natural gas produced or sold at wholesale in such calendar year. Order 704 applies only to those transactions that utilize, contribute to or may contribute to the formation of price indices. It is the responsibility of the market participant to determine which individual transactions are to be reported under the guidance of Order 704. Additional information that must be reported includes whether the price in the relevant transaction was reported to any index publisher, and if so, whether such reporting complied with FERC’s policy statement on price reporting. To the extent that we engage in wholesale sales or purchases of natural gas that equal or exceed 2.2 MMBtus of physical natural gas in a calendar year pursuant to transactions utilizing, contributing or having the potential to contribute to the formation of price indices, we may be subject to the reporting requirements of Order 704. +Gathering is exempt from regulation under the NGA, thus allowing gatherers to charge negotiated rates. Gathering lines are, however, subject to state regulation, which includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and rate regulation on a complaint basis. We own certain pipeline facilities in the Delaware Basin that we believe are exempt from regulation under the NGA as “gathering facilities,” but which may in some cases be subject to state regulation. +Although FERC has set forth a general test to determine whether facilities are exempt from regulation under the NGA as “gathering” facilities, FERC’s determinations as to the classification of facilities are performed on a case-by-case basis. With respect to facilities owned by third parties and on which we move natural gas, to the extent that FERC subsequently issues an order reclassifying facilities previously thought to be subject to FERC jurisdiction as non-jurisdictional gathering facilities, and depending on the scope of that decision, our costs of moving natural gas to the point of sale may be increased. Further, to the extent that FERC issues an order reclassifying facilities that we own that were previously thought to be non-jurisdictional gathering facilities as subject to FERC jurisdiction, we could be subject to additional regulatory requirements under the NGA and the NGPA. +Transportation and safety of natural gas is also subject to regulation by the U.S. Department of Transportation, through the Pipeline and Hazardous Materials Safety Administration ("PHMSA"), under the Natural Gas Pipeline Safety Act of 1968, as amended, which imposes safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities, the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (the "PIPES Act 2006"), and +13 +the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (the "PIPES Act 2011"). We own certain pipeline facilities in the Delaware Basin that are subject to such regulation by PHMSA. +In addition to natural gas, we move crude oil, condensate and natural gas liquids (collectively, "liquids") through pipelines owned by other entities and sell such liquids to other entities that also utilize pipeline facilities that may be subject to regulation by FERC. FERC regulates the rates and terms and conditions of service for the interstate transportation of liquids under the Interstate Commerce Act, as it existed on October 1, 1977 (the "ICA"), and the rules and regulations promulgated thereunder. This includes movements of liquids through any pipelines, including those located solely within one state, that are providing part of the continuous movement of such liquids in interstate commerce for a shipper. The ICA requires that pipelines providing jurisdictional movements maintain a tariff on file with FERC, setting forth established rates and the rules and regulations governing transportation service, which must be “just and reasonable.” The ICA also requires that services be provided in a manner that is not unduly discriminatory or unduly preferential; in some cases, this may result in the proration of capacity among shippers in an equitable manner. +The intrastate transportation of crude oil and NGLs is subject to regulation by state regulatory commissions, which in some cases require the provision of intrastate transportation on a nondiscriminatory basis and the prorationing of capacity on such pipelines under policies set forth in published tariffs. These state-level regulations may also impose certain limitations on the rates that the pipeline owner may charge for transportation. +Transportation of liquids by pipeline is subject to regulation by PHMSA pursuant to the Hazardous Liquids Pipeline Safety Act of 1979, as well as the PIPES Act 2006 and the PIPES Act 2011, which govern the design, installation, testing, construction, operation, replacement and management of liquids pipeline facilities. Liquids that are transported by rail may also be subject to additional regulation by PHMSA. +The availability, terms and cost of transportation affect the amounts we receive for our commodities. Historically, producers were able to flow supplies into interstate pipelines on an interruptible basis; however, recently we have seen an increased need to acquire firm transportation on pipelines in order to avoid curtailments or shut-in gas, which could adversely affect cash flows from the affected area. +Democratic control of the House, Senate and White House could lead to increased regulatory oversight and increased regulation and legislation, particularly around oil and gas development on federal lands, climate impacts and taxes. +Environmental Matters +Our operations are subject to numerous laws and regulations relating to environmental protection. These laws and regulations change frequently, and the effect of these changes is often to impose additional costs or other restrictions on our operations. We cannot predict the occurrence, timing, nature or effect of these changes. We also operate under a number of environmental permits and authorizations. The issuing agencies may take the position that some or all of these permits and authorizations are subject to modification, suspension, or revocation under certain circumstances, but any such action would have to comply with applicable procedures and requirements. +Hazardous Substances and Wastes +We generate wastes that may be subject to the Federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes. The U.S. Environmental Protection Agency ("EPA") and various state agencies have adopted requirements that limit the approved disposal methods for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by our operations that are currently exempt from treatment as “hazardous wastes” may in the future be designated as hazardous wastes, and therefore may subject us to more rigorous and costly operating and disposal requirements. In April 2019, the EPA, pursuant to a consent decree between the EPA and a coalition of environmental groups and a related review of RCRA regulations, determined that revision of the regulations is not necessary. The EPA indicated that it will continue to work with states and other organizations to identify areas for continued improvement and to address emerging issues to ensure that exploration, development and production wastes continue to be managed in a manner that is protective of human health and the environment. Environmental groups, however, expressed dissatisfaction with the EPA’s decision and will likely continue to press the issue at the federal and state levels. +14 +We currently own or lease numerous properties that have been used for the exploration and production of crude oil and natural gas for many years. If hydrocarbons or other wastes have been disposed of or released on or under the properties that we own or lease or on or under locations where such wastes have been taken for disposal by us or prior owners or operators of such properties, we could be subject to liability under the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), RCRA and analogous state laws, as well as state laws governing the management of crude oil and natural gas wastes. CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of, transported or arranged for the disposal of the hazardous substances found at the site. Parties who are or were responsible for release of hazardous substances under CERCLA may be subject to full liability for the costs of cleaning up the hazardous substances that have been released into the environment or remediation to prevent future contamination and for damages to natural resources. In addition, under state laws, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. +Hydraulic Fracturing +Hydraulic fracturing is commonly used to stimulate production of crude oil and/or natural gas from dense subsurface rock formations. We consistently utilize hydraulic fracturing in our crude oil and natural gas development programs. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations which are held open by the grains of sand, enabling the crude oil or natural gas to more easily flow to the wellbore. The process is generally subject to regulation by state oil and gas commissions, but is also the subject of various other regulatory initiatives at the federal, state and local levels. +Local Regulation +Various local and municipal bodies in each of the states in which we operate have sought to impose prohibitions, moratoria and other restrictions on hydraulic fracturing activities. In Colorado, Senate Bill 19-181 ("SB 19-181"), gives local governmental authorities increased authority to regulate the siting and surface impacts of oil and gas development. We primarily operate in the rural areas of the core Wattenberg Field in Weld County, a jurisdiction in which there has historically been significant support for the oil and gas industry. In Texas, legislation enacted in 2015 generally prohibits political subdivisions from banning, limiting or otherwise regulating oil and gas operations. See Item 1A. Risk Factors-Risks Relating to Our Business and the Industry-Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us. +State Regulation +The states in which we currently operate have adopted or may adopt laws and regulations that impose or could impose, among other requirements, more stringent permitting processes and increased environmental protection and monitoring. +SB 19-181 changed the mission of the COGCC from fostering responsible and balanced development to regulating development to protect public health and the environment and directed the COGCC to undertake rulemaking on various operational matters. Pursuant to this direction, the COGCC conducted a series of rulemaking hearings during 2020 which resulted in updated regulatory and permitting requirements, including siting requirements. The COGCC commissioners determined that locations with residential or high occupancy building units within 2,000 feet would be subject to additional siting requirements, but also supported “off ramps” allowing oil and gas operators to site their drill pads as close as 500 feet from building units in certain circumstances. However, during the proceedings around SB 19-181, top Democratic leaders in the Colorado House and Senate, who served as authors and sponsors of the bill, made public statements indicating SB 19-181 was not intended to allow an outright ban on oil and gas development. At least one COGCC commissioner has publicly indicated his agreement with that interpretation. +In late July 2020, Governor Polis authored an op-ed stating that both industry and mainstream environmental groups have communicated a willingness to stand down on ballot initiatives in 2020, and to work together to prevent initiatives in 2022, while the regulatory process associated with SB 19-181 is in progress. As part of that agreement, Governor Polis stated that he would “actively oppose” ballot initiatives around the oil and gas industry and acknowledged the importance of regulatory certainty. +15 +It is nevertheless possible that future ballot initiatives will be proposed that would dramatically limit the areas of the state in which drilling would be permitted to occur. See Item 1A. Risk Factors-Risks Relating to Our Business and the Industry-Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us. +Federal Regulation +Beginning in 2012, the EPA implemented Clean Air Act ("CAA") standards (New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants) applicable to hydraulically fractured natural gas wells and certain storage vessels. The standards require, among other things, use of reduced emission completions, or “green” completions, to reduce volatile organic compound emissions during well completions as well as new controls applicable to a wide variety of storage tanks and other equipment, including compressors, controllers and dehydrators. +In February 2014, the EPA issued permitting guidance under the Safe Drinking Water Act ("SDWA") for the underground injection of liquids from hydraulically fractured and other wells where diesel is used. Depending upon how it is implemented, this guidance may create duplicative requirements in certain areas, further slow the permitting process in certain areas, increase the costs of operations and result in expanded regulation of hydraulic fracturing activities by the EPA, and may therefore adversely affect even companies, such as us, that do not use diesel fuel in hydraulic fracturing activities. +In May 2014, the EPA issued an advance notice of proposed rulemaking under the Toxic Substances Control Act pursuant to which it will collect extensive information on the chemicals used in hydraulic fracturing fluid, as well as other health-related data, from chemical manufacturers and processors. +The U.S. Department of the Interior, through the Bureau of Land Management (the "BLM"), finalized a rule in 2015 requiring the disclosure of chemicals used, mandating well integrity measures and imposing other requirements relating to hydraulic fracturing on federal lands. The BLM rescinded the rule in December 2017. The BLM’s rescission of the rule was challenged in the United States District Court for the Northern District of California and in March 2020 the court issued a ruling upholding BLM’s rescission of the rule. That court ruling is currently being appealed. +In June 2016, the EPA finalized pretreatment standards for indirect discharges of wastewater from the oil and gas extraction industry. The regulation prohibits sending wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned treatment works. +Private Lawsuits +Lawsuits have been filed against other operators in several states, including Colorado, alleging contamination of drinking water as a result of hydraulic fracturing activities. +Greenhouse Gases +The EPA has published findings that emissions of carbon dioxide, methane and other greenhouse gases ("GHGs") present an endangerment to public health and the environment because such emissions are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings provide the basis for the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. In June 2010, the EPA began regulating GHG emissions from stationary sources. +In the past, Congress has considered proposed legislation to reduce emissions of GHGs. To date, Congress has not adopted any such significant legislation, but could do so in the future. In addition, many states and regions have taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Since 2014, Colorado has engaged in multiple rulemakings to adopt significant additional adopted rules regulating methane emissions from the oil and gas sector, and Colorado is expected to continue these efforts over the next several years. +16 +The Obama administration reached an agreement during the December 2015 United Nations climate change conference in Paris pursuant to which the U.S. initially pledged to make a 26 percent to 28 percent reduction in its GHG emissions by 2025 against a 2005 baseline and committed to periodically update this pledge every five years starting in 2020 (the "Paris Agreement"). In June 2017, President Trump announced that the U.S. would initiate the formal process to withdraw from the Paris Agreement. In November 2019, the U.S. formally notified the United Nations of its intention to withdraw from the Paris Agreement. The notification began a one-year process for withdrawal on November 4, 2020. On January 20, 2021, President Joe Biden executed an executive order to re-enter the Paris Agreement. +Regulation of methane and other GHG emissions associated with oil and natural gas production could impose significant requirements and costs on our operations. +Air Quality +Our operations are subject to the CAA and comparable state and local requirements. The CAA contains provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and state governments continue to develop regulations to implement these requirements. We may be required to make certain capital investments in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. See the footnote titled Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere in this report for further information regarding the Clean Air Act Section 114 Information Request that we received from the EPA. +In June 2016, the EPA implemented new requirements focused on achieving additional methane and volatile organic compound reductions from the oil and natural gas industry. The rules imposed, among other things, new requirements for leak detection and repair, control requirements for oil well completions, replacement of certain pneumatic pumps and controllers and additional control requirements for gathering, boosting and compressor stations. In September 2018, the EPA proposed revisions to the 2016 rules. The proposed amendments address certain technical issues raised in administrative petitions and include proposed changes to, among other things, the frequency of monitoring for fugitive emissions at well sites and compressor stations. In September 2020, the EPA issued a new rule which amended the 2016 requirements. In this rule, the EPA removed all sources in the transmission and storage segment of the oil and natural gas industry from regulation. The rule also rescinded the methane requirements in the 2016 regulations and loosened monitoring and repair regulations aimed at preventing methane leaks. The new rule was challenged in the U.S. Court of Appeals for the D.C. Circuit, but in October 2020 the Court declined to issue a permanent stay of the new rule while it considered the merits of the challenge. The new rule therefore is currently in effect. However, the future of the new rule is in flux as the Court could vacate the rule such that the original 2016 regulations would go back into effect. +In November 2016, the BLM finalized rules to further regulate venting, flaring and leaks during oil and natural gas production activities on onshore federal and Indian leases (the “2016 Rule”). The 2016 Rule required additional controls and impose new emissions and other standards on certain operations on applicable leases, including committed state or private tracts in a federally approved unit or communitized agreement that drains federal minerals. In September 2018, the BLM published a final rule that revised the 2016 Rule (the “2018 Revised Rule”). The 2018 Revised Rule, among other things, rescinded the 2016 Rule requirements related to waste-minimization plans, gas-capture percentages, well drilling, well completion and related operations, pneumatic controllers, pneumatic diaphragm pumps, storage vessels and leak detection and repair. The 2018 Revised Rule also revised provisions related to venting and flaring. Environmental groups and the States of California and New Mexico filed challenges to the 2018 rule in the United States District Court for the Northern District of California, and in July 2020, the United States District Court for the Northern District of California vacated BLM’s 2018 Revised Rule. However, in October 2020, the United States District Court for the District of Wyoming issued a ruling vacating the 2016 Rule, holding that BLM exceeded its statutory authorities and acted arbitrarily. That ruling is expected to be appealed. +In 2019, the EPA increased the state of Colorado’s non-attainment ozone classification for the Denver Metro North Front Range Ozone Eight-Hour Non-Attainment ("Denver Metro/North Front Range NAA") area from "moderate" to “serious” under the 2008 national ambient air quality standard ("NAAQS"). This increase in non-attainment status to "serious" triggered significant additional obligations for the state under the CAA and resulted in Colorado adopting new and more stringent air quality control requirements in December 2020 that are applicable to our operations. Based on current air quality monitoring data, it is expected that the Denver Metro/North Front Range NAA will be further "bumped-up" to "severe" status in 2021 or 2022. This will trigger additional obligations for the state under the CAA and will result in new and more stringent air quality permitting and control requirements, which may in turn result in significant costs and delays in obtaining necessary permits applicable to our operations. +17 +SB 19-181 also requires, among other things, that the Air Quality Control Commission ("AQCC") adopt additional rules to minimize emissions of methane and other hydrocarbons and nitrogen oxides from the entire oil and gas fuel cycle. The AQCC has undertaken a multi-year rulemaking process to implement the requirements of SB 19-181, including a rulemaking to require continuous emission monitoring equipment at oil and gas facilities. Between December 2019 and December 2020, the AQCC completed several rulemakings as a result of SB 19-181, adopting significant additional and new emission control requirements applicable to oil and gas operations, including, for example, hydrocarbon liquids unloading control requirements, increased LDAR frequencies for facilities in certain proximity to occupied areas, and emission control requirements for certain large natural gas fired engines. The AQCC plans to conduct additional rulemakings related to SB 19-181 in 2021. +Additionally, in response to HB 19-1261, which established statewide greenhouse gas reduction targets, Colorado, on September 30, 2020, released a public comment draft of its Greenhouse Gas Pollution Reduction Roadmap, which details early action steps the state can take toward meeting the near-term goals of reducing greenhouse gas (GHG) pollution 26% by 2025 and 50% by 2030 from 2005 levels. On October 23, 2020, the AQCC issued the Resolution to Ensure Greenhouse Gas Reduction Goals Are Met in support of the roadmap, which estimates emission reductions needed from the oil and gas sector of 36% by 2025 and 50% by 2030. To meet these targets, the CDPHE has also initiated a stakeholder process to develop and consider additional greenhouse gas reduction strategies from the oil and gas sector, to be finalized in a 2021 AQCC rulemaking. +State-level rules applicable to our operations include regulations imposed by the Colorado Department of Public Health and Environment's ("CDPHE") Air Quality Control Commission, including stringent requirements relating to monitoring, recordkeeping and reporting matters. In 2020, the COGCC relied in part on a previously-performed human health risk assessment in adopting new siting requirements. The COGCC also generally prohibited the venting or flaring of natural gas during drilling, completion, and production operations. +While the State of Texas has not formally conducted a recent rulemaking related to air emissions, scrutiny of oil and gas operations and the rules affecting them have increased in recent years. For example, EPA and environmental non-governmental organizations have conducted flyovers with optical gas imaging cameras to survey emissions from oil and gas production facilities and transmission infrastructure. In addition, the Texas Railroad Commission has increased oversight related to flaring, with reporting reviews and site inspections. While none of these activities increases our compliance obligations, they signal the potential for increased enforcement and possible rulemaking in the future. +Water Quality +The federal Clean Water Act ("CWA") and analogous state laws impose strict controls concerning the discharge into regulated waterbodies and wetlands of pollutants and fill material, including spills and leaks of crude oil and other substances. The CWA also requires approval and/or permits prior to construction, where construction will disturb certain wetlands or other federally regulated waters of the U.S. ("WOTUS"). In October 2019, the EPA and the Army Corps of Engineers ("USACE") issued a final rule to repeal previous regulations (the "2019 Repeal Rule") and implement the 1986 WOTUS regulations and guidance nationwide, until a new replacement rule could be adopted. The 2019 Repeal Rule became effective on December 23, 2019. However, numerous legal challenges to the 2019 Repeal Rule have been filed in federal court. +On April 21, 2020, the EPA and USACE issued a final new replacement on the scope of regulated WOTUS, titled the Navigable Waters Protection Rule ("2020 Rule"). The 2020 Rule was judicially challenged in several different lawsuits, which are still pending, but it was preliminarily enjoined only in Colorado and went into effect in all other states on June 22, 2020. In Colorado only, the former 1986 WOTUS rule and related guidance will control until the lawsuit there is resolved. In all other states, the 2020 Rule will remain in effect unless it is invalidated in one or more of the pending lawsuits, or unless it is replaced by the incoming Biden administration, which would take many months. The 2020 Rule generally regulates four categories of “jurisdictional waters": (i) territorial seas and traditional navigable waters (i.e., large rivers); (ii) perennial and intermittent tributaries of these waters; (iii) certain lakes, ponds and impoundments; and (iv) wetlands adjacent to jurisdictional waters. The 2020 Rule also includes 12 categories of exclusions, or “non-jurisdictional” waters, including groundwater, ephemeral features and diffuse stormwater run-off over upland areas. In particular, the 2020 Rule regulates fewer wetlands areas than were regulated under the 1986 rule and the 2015 Clean Water Rule, because it does not regulate wetlands that are not adjacent to jurisdictional waters. If the 2020 WOTUS Rule is invalidated in one or more pending lawsuits, or if it is replaced by a new, more stringent rule on the scope of WOTUS by the incoming administration, it would likely change the scope of the CWA’s jurisdiction, which could result in increased costs and delays with respect to obtaining permits for discharges of pollutants or dredge and fill activities in waters of the U.S., including regulated wetland areas. +18 +In January 2017, the USACE issued revised and renewed streamlined general nationwide permits that are available to satisfy permitting requirements for certain work in streams, wetlands and other regulated waters of the U.S. under Section 404 of the CWA and the Rivers and Harbors Act. The new nationwide permits took effect in March 2017, or when certified by each state, whichever was later. The oil and gas industry broadly utilizes Nationwide Permits 12, 14 and 39 for the construction, maintenance and repair of pipelines, roads and drill pads, respectively, and related structures in waters of the U.S. that impact less than a half-acre of waters of the U.S. and meet the other criteria of each nationwide permit. +In May 2020, a federal court in Montana enjoined the use of Nationwide Permit 12 to construct new oil and gas-related pipelines, on the basis that the USACE had not properly consulted with the U.S. Fish and Wildlife Service when that permit was renewed in 2017. The U.S. Supreme Court in July 2020 significantly narrowed the Montana court’s injunction to cover only the challenged XL Pipeline. The Montana court’s substantive decision is now on appeal to the Ninth Circuit, whose ultimate ruling could affect the oil and gas industry’s ability to use this streamlined permit. In the meantime, in September 2020, the USACE issued a proposal to revise and reissue all 52 current nationwide permits, including No. 12, to lessen the burden on the energy industry and address the flaws alleged in the Montana lawsuit. Among other things, under that proposal existing Nationwide Permit 12 would be broken up into three new separate nationwide permits, with the proposed new Nationwide Permit 12 being limited solely to construction and maintenance of oil and gas pipelines, with other utility-related structures covered by the two new nationwide permits. The proposed new No. 12 would also have decreased requirements for pre-construction notification to the USACE. It is unknown at this time whether that proposed rule will be finalized by the end of the current administration or, if not, whether it will be abandoned or revised by the incoming administration. If the current or revised version of Nationwide Permit 12 is invalidated or stayed by the courts, it would increase the costs and delays for oil and gas operators to construct or maintain pipelines that cross jurisdictional waters of the U.S. +The CWA also regulates storm water run-off from crude oil and natural gas facilities and requires storm water discharge permits for certain activities. Spill Prevention, Control and Countermeasure ("SPCC") requirements of the CWA require appropriate secondary containment, load out controls, piping controls, berms and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture or leak. +Endangered Species +The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and bald and golden eagles under the Bald and Golden Eagle Protection Act. Some of our operations may be located in areas that are or may be designated as habitats for endangered or threatened species or that may attract migratory birds, bald eagles or golden eagles. +Other +In October 2015, the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration proposed to expand its regulations in a number of ways, including increased regulation of gathering lines, even in rural areas, and proposed additional standards to revise safety regulations applicable to onshore gas transmission and gathering pipelines in 2016. +Crude oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of crude oil spills. In addition to SPCC requirements, the Oil Pollution Act of 1990 ("OPA") subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from crude oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Historically, we have not experienced any significant crude oil discharge or crude oil spill problems. +In May 2015, the U.S. Department of Transportation issued a final rule regarding the safe transportation of flammable liquids by rail. The final rule imposes certain requirements on “offerors” of crude oil, including sampling, testing and certification requirements. +In February 2018, the COGCC comprehensively amended its regulations for oil, gas and water flowlines to expand requirements addressing flowline registration and safety, integrity management, leak detection and other matters. In November 2019, the COGCC further amended its flowline regulations pursuant to SB 19-181 to impose additional requirements regarding flowline mapping, operational status, certification and abandonment, among other things. +19 +We are also subject to rules regarding worker safety and similar matters promulgated by the U.S. Occupational Safety and Health Administration ("OSHA") and other governmental authorities. OSHA has established workplace safety standards that provide guidelines for maintaining a safe workplace in light of potential hazards, such as employee exposure to hazardous substances. To this end, OSHA adopted a new rule governing employee exposure to silica, including during hydraulic fracturing activities, in March 2016. +Human Capital Resources +Employee Headcount +As of December 31, 2020, we had 520 full-time employees, 235 of whom are employed in field operations. +Employee Engagement +Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. Therefore, we recognize and support the growth of our employees by offering internal and external development programs. We utilize an online training platform to allocate and track employee trainings, as well as offering on-demand developmental training content. Lastly, to remind our employees of PDC's values, we require all employees to attend an annual harassment awareness training. +We conduct an annual employee satisfaction survey where employees from each of our offices are provided an opportunity for their opinions to be voiced on how we can improve as a company. We report results back to our board of directors, management team and employees and take actions to address areas of employee concern. On a company-wide level, we encourage a culture of volunteerism and have an annual day of service which garners participation from the vast majority of our employees. Additionally, we believe diversity and inclusion provides a business with innovation and a successful workforce. We formed an employee-led diversity and inclusion project team in 2020 that will identify areas for growth and improvement that will build on our current efforts in respect of diversity and inclusion. +Safety Culture +We are committed to the health, safety, and welfare of our employees, contractors, and neighbors. We regularly update our safety policies and procedures to ensure we are meeting or exceeding new requirements and adopting new technologies that improve our responsible operations. Additionally, all PDC field employees receive safety training upon hire, along with frequent meetings and refreshers to reinforce safety as a core value and our most important strategic priority. +PDC utilizes a field monitoring room, which is tied into our field automation, that is staffed 24 hours a day and 365 days a year to identify emergency situations and allows for quick field response. The automation capabilities on a facility can vary from measuring tank levels to security cameras to remote emergency shut-down capabilities. The field monitoring room, in combination with our daily inspections performed on producing locations, facilitates proactive response to events that need attention. +Our continual commitment to safety has resulted in improving safety records, even as operations have grown. At least since the time Occupational Safety and Health Administration ("OSHA") began requiring record-keeping and publication of health and safety information in 1972, we have not had any employee work-related fatalities. A commonly used measure of an organization’s safety performance is Total Recordable Incident Rate ("TRIR"), which equates to the number of injuries requiring medical treatment per 100 full-time employees during a one-year period. We monitor this performance measure and communicate it broadly across the company. We also include both TRIR and Preventable Vehicle Accident Rate ("PVAR") as part of our quantitative performance metrics within our annual incentive program, to prioritize the importance of safety within our company. Our TRIR and PVAR remained notably low for 2020 and 2019. +20 +Employee Compensation and Benefits +Our compensation program is designed to provide the proper incentives to attract, retain and reward employees to achieve results related to our core values and strategic priorities. The structure of our compensation program provides incentives for both short-term and long-term performance. We also seek fairness in total compensation and benefits with reference to external benchmarking against our peers within the industry. All full-time employees are eligible for health insurance, paid and unpaid leaves, a retirement plan and life and disability/accident coverage. +Our employees are not covered by collective bargaining agreements. We consider relations with our employees to be positive. +WHERE YOU CAN FIND ADDITIONAL INFORMATION +We file annual, quarterly and current reports, proxy statements and other information with the SEC, which are maintained and available at www.sec.gov . Our SEC filings are also available free of charge from our website at www.pdce.com as soon as reasonably practicable after such material is filed with, or furnished to, the SEC. We also make available free of charge any of our SEC filings by mail. For a mailed copy of a report, please contact PDC Energy, Inc., Investor Relations, 1775 Sherman Street, Suite 3000, Denver, CO 80203, or call (303) 860-5800. +We recommend that you view our website for additional information, as we routinely post information that we believe is important for investors. Our website can be used to access such information as our recent news releases, committee charters, code of business conduct and ethics, stockholder communication policy, director nomination procedures, sustainability report and our whistle blower hotline. While we recommend that you view our website, the information available on our website is not part of this report and is not incorporated by reference. +21 +ITEM 1A. RISK FACTORS +You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as the value of an investment in our common stock or other securities. +Risks Relating to the Global COVID-19 Pandemic +Our operations have been adversely affected as a result of the ongoing global COVID-19 pandemic and its impacts on crude oil demand and pricing. We expect those impacts to continue in the near-term and we may experience additional impacts in the future. For example: +• Prolonged depressed crude oil prices may have adverse effects on the financial wellbeing of our business, including with respect to revenue, profitability, cash flows and liquidity; quantity and present value of our reserves; the borrowing base under our revolving credit facility; and access to other sources of capital; +• Negative financial impacts may lead to distress and restructuring events affecting working interest partners, vendors, contractors, service providers and other counterparties; +• Negative financial impacts to our business partners may cause delays or failure to pay service providers, which could result in liens being filed against our real and personal property; +• Reduced capital spending and declines in revenues have led to temporary and permanent reductions in our work force and decreases to our director, executive and employee compensation, which may affect our ability to attract and retain experienced technical and other professional personnel; +• Our reduced drilling program may result in losses of acreage due to lease expirations, which could result in impairment charges and the loss of future drilling opportunities; +• State and local orders, ordinances and guidance related to COVID-19 have forced a significant portion of our employees to work remotely, which may result in decreased productivity and continuity among the employee base; +• Current market conditions and impacts on our business generally may lead to an increased risk of litigation; and +• The cumulative effects of COVID-19 on the economy may result in a long-term global recession or depression. +Risks Relating to Our Business and the Industry +Crude oil, natural gas and NGL prices fluctuate and declines in these prices, or an extended period of low prices, can significantly affect the value of our assets and our financial results and may impede our growth. +Our revenue, profitability, cash flows and liquidity depend in large part upon the prices we receive for our crude oil, natural gas and NGLs. Changes in prices affect many aspects of our business, including: +• our revenue, profitability and cash flows; +• our liquidity; +• the quantity and present value of our reserves; +• the borrowing base under our revolving credit facility and access to other sources of capital; and +• the nature and scale of our operations. +The markets for crude oil, natural gas and NGLs are often volatile, and prices may fluctuate in response to, among other things: +• relatively minor changes in regional, national or global supply and demand; +• regional, national or global economic conditions, and perceived trends in those conditions; +• geopolitical factors, such as events that may reduce or increase production from particular oil-producing regions and/or from members of the Organization of Petroleum Exporting Countries ("OPEC"), and global events, such as the ongoing COVID-19 pandemic; and +• regulatory changes. +The price of oil has historically been volatile, due in recent years to a combination of factors including increased U.S. supply and global economic concerns. As a result of the ongoing impact of the COVID-19 pandemic and actions of members of OPEC, in 2020, oil prices ranged from highs of approximately $59 per barrel to lows of approximately negative $40 per barrel +22 +(due to depressed demand and insufficient storage capacity, particularly at the WTI physical settlement location in Cushing, Oklahoma). Prices for natural gas and NGLs have also experienced substantial volatility. If we reduce our capital expenditures due to low prices, natural declines in production from our wells will likely result in reduced production and therefore reduced cash flow from operations, which would in turn further limit our ability to make the capital expenditures necessary to replace our reserves and production. +In addition to factors affecting the price of crude oil, natural gas and NGLs generally, the prices we receive for our production are affected by factors specific to us and to the local markets where the production occurs. The prices that we receive for our production are generally lower than the relevant benchmark prices that are used for calculating commodity derivative positions. These differences, or differentials, are difficult to predict and may widen or narrow in the future based on market forces. Differentials can be influenced by, among other things, local or regional supply and demand factors and the terms of our sales contracts. Over the longer term, differentials will be significantly affected by factors such as investment decisions made by providers of midstream facilities and services, refineries and other industry participants and the overall regulatory and economic climate. For example, increases in U.S. domestic oil production generally, or in production from particular basins, may result in widening differentials. We may be materially and adversely impacted by widening differentials on our production and decreasing commodity prices. +We are subject to complex federal, state, local and other laws and regulations that adversely affect the cost and manner of doing business. Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us. +Our exploration, development, production and marketing operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning crude oil and natural gas wells and associated facilities. Under these laws and regulations, we could also be liable for personal injuries, property damage and natural resource or other damages, and could be required to change, suspend or terminate operations. A summary of certain laws and regulations that apply to us and some potential changes to those laws and regulations is set forth in Items 1 and 2 - Business and Properties - Governmental Regulation . Any of the currently applicable laws and regulations could be amended, including in ways that we do not anticipate, and those changes could adversely affect our operations. +From time to time, we have been subject to sanctions and lawsuits relating to alleged noncompliance with regulatory requirements. For example, in October 2017, in order to settle a lawsuit brought against us by the U.S. Department of Justice, on behalf of the EPA and the State of Colorado, we entered into a consent decree pursuant to which we paid a fine and agreed to implement certain operational changes. The lawsuit claimed that we failed to operate and maintain certain equipment in compliance with applicable law. In addition, as a result of the SRC Acquisition, we are subject to the obligations and requirements of a 2018 Compliance Order on Consent (“COC”) entered into by SRC with CDPHE, applicable to certain SRC oil and gas production facilities we acquired from SRC. The COC resolved SRC’s alleged violations related to storage tank emissions and contains requirements similar to those contained in our consent decree. +The regulatory environment in which we operate also changes frequently, often through the imposition of new or more stringent environmental and other requirements, some of which may apply retroactively. We cannot predict the nature, timing, cost or effect of such additional requirements, but they may have a variety of adverse effects on us. The types of regulatory changes that could impact our operations vary widely and include, but are not limited to, the following: +• As discussed in Items 1 and 2, Business and Properties - Governmental Regulation , the COGCC completed extensive rulemaking hearings under SB 19-181 in 2020, which resulted in the adoption of new requirements for setbacks, permitting, siting cumulative and surface impacts, asset transfers, venting and flaring, and remediation. The implementation of the final rules, particularly as they relate to mandatory setbacks between wells and building units, could have a significant adverse effect on our unpermitted locations and therefore on our future inventory and reserves. Other final rules could have a significant adverse effect on our future operations as well. The COGCC is still in the process of issuing guidance and direction regarding the new requirements, and we cannot predict the impact of these requirements on our inventory and operations. +• Substantially all of our drilling activities involve the use of hydraulic fracturing, and proposals are made from time to time at the federal, state and local levels to further regulate, or to ban, hydraulic fracturing practices. Additional laws or regulations regarding hydraulic fracturing could, among other things, increase our costs, reduce our inventory of economically viable drilling locations and reduce our reserves. +23 +• Federal and various state, local and regional governmental authorities have implemented, or considered implementing, regulations that seek to limit or discourage the emission of carbon, methane and other GHGs. For example, the EPA has made findings and issued regulations that require us to establish and report an inventory of greenhouse gas emissions, and the state of Colorado has adopted rules regulating methane emissions from oil and gas operations. Additional laws or regulations intended to restrict the emission of GHGs could require us to incur additional operating costs and could adversely affect demand for the oil, natural gas and NGLs that we sell. These new laws or rules could, among other things, require us to install new emission controls on our equipment and facilities, acquire allowances to authorize our GHG emissions, pay taxes related to our emissions and administer and manage a GHG emissions program. In addition, like other energy companies, we could be named as a defendant in GHG-related lawsuits. +• Proposals are made from time to time to amend U.S. federal and state tax laws in ways that would be adverse to us, including by eliminating certain key U.S. federal income tax preferences currently available with respect to crude oil and natural gas exploration and production. The changes could include (i) the repeal of the percentage depletion deduction for crude oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Also, state severance taxes may increase in the states in which we operate. This could adversely affect our existing operations in the relevant state and the economic viability of future drilling. +• The development of new environmental initiatives or regulations related to the acquisition, withdrawal, storage and use of surface water or groundwater or treatment and discharge of water waste, may limit our ability to use techniques such as hydraulic fracturing, increase our development and operating costs and cause delays, interruptions or termination of our operations, any of which could have an adverse effect on our operations and financial condition. +A substantial part of our crude oil, natural gas and NGLs production is located in the Wattenberg Field, making us vulnerable to risks associated with operating primarily in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing formations. +Although we have significant leasehold positions in the Delaware Basin in Texas, our current production is primarily located in the Wattenberg Field in Colorado. Because our production is not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including natural disasters, government regulations and midstream interruptions. +For example, bottlenecks in processing and transportation that have occurred in some recent periods in the Wattenberg Field have negatively affected our results of operations, and these adverse effects may be disproportionately severe to us compared to our more geographically diverse competitors. Similarly, the concentration of our producing assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules that could adversely affect development activities or production relating to those formations. Such an event could have a material adverse effect on our results of operations and financial condition. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the Wattenberg Field and the Delaware Basin, the demand for, and cost of, drilling rigs, equipment, supplies, chemicals, personnel and oilfield services often increase as well. Any shortages or increased costs could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital forecast, which could have a material adverse effect on our business, financial condition or results of operations. All of the producing properties and reserves we acquired in the SRC Acquisition are located in the Wattenberg Field. As a result, the transaction increased the risks we face with respect to the geographic concentration of our properties. +The marketability of our production is dependent upon transportation and processing facilities, the capacity and operation of which we do not control. Market conditions or operational impediments affecting midstream facilities and services could hinder our access to crude oil, natural gas and NGL markets, increase our costs or delay production. Our efforts to address midstream issues may not be successful. +Our ability to market our production depends in substantial part on the availability, proximity and capacity of gathering systems, pipelines and processing facilities owned and operated by third parties. If adequate midstream facilities and services are not available to us on a timely basis and at acceptable costs, our production may be curtailed and our results of operations will be adversely affected. In addition to causing production curtailments, capacity constraints can also reduce the price we receive for the crude oil, natural gas and NGLs we produce. +24 +We rely on third parties to continue to construct additional midstream facilities and related infrastructure to accommodate our growth, and the ability and willingness of those parties to do so is subject to a variety of risks. For example: +• Decreases in commodity prices in recent years have resulted in reduced investment in midstream facilities by some third parties; +• Various interest groups have protested the construction of new pipelines, and particularly pipelines near water bodies, in various places throughout the country, and protests have at times physically interrupted pipeline construction activities; +• Some upstream energy companies have sought to reject volume commitment agreements with midstream providers in bankruptcy proceedings, and the risk that such efforts will succeed, or that upstream energy company counterparties will otherwise be unable or unwilling to satisfy their volume commitments, may have the effect of reducing investment in midstream infrastructure; and +• The possibility that new or amended regulations, including regulations that increase mandatory setbacks or enhance local control of oil and gas development, could result in severely curtailed drilling activities in Colorado and may discourage investment in midstream facilities. +Like other producers, we from time to time enter into volume commitments with midstream providers in order to induce them to provide increased capacity. If our production falls below the level required under these agreements, we could be subject to substantial penalties. +Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in substantial lease renewal costs or, if renewal is not feasible, loss of our lease and prospective drilling opportunities. +Unless production is established within the spacing units covering our undeveloped acreage, our leases for such acreage will expire. The cost to renew such leases may increase significantly and we may not be able to renew such leases on commercially reasonable terms or at all. Unexpected lease expirations could occur if our actual drilling activities differ materially from our current expectations, and this could result in impairment charges. The risk of lease expiration is greater at times and in areas where the pace of our exploration and development activity slows. Our ability to drill and develop the locations necessary to maintain our leases depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. +We may incur losses as a result of title defects in the properties in which we invest or acquire. +It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform record title examinations before we acquire oil and gas leases and related interests. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property. +Our ability to produce crude oil, natural gas and NGLs economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of or recycle the water we use at a reasonable cost, in a timely manner and within applicable environmental rules. +Drilling and development activities such as hydraulic fracturing require the use of water and result in the production of wastewater. Our operations could be adversely impacted if we are unable to locate sufficient amounts of water or dispose of or recycle water used in our exploration and production operations. The quantity of water required in certain completion operations, such as hydraulic fracturing, and changing regulations governing usage may lead to water constraints, supply concerns and regulatory issues, particularly in relatively arid climates such as eastern Colorado and western Texas. For example, increased drilling activity in the Delaware Basin in recent years has led to heightened concerns about water supply +25 +issues in the area and this may lead to regulatory actions, including rules providing local governments greater authority over water use, that adversely impact our operations. +Our operations depend on being able to reuse or dispose of wastewater in a timely and economic fashion. Wastewater from oil and gas operations is often disposed of through underground injection. Wells in the Delaware Basin typically produce relatively large amounts of water that require disposal and an increased number of earthquakes have been detected in the Delaware Basin in recent years. Some studies have linked earthquakes, or induced seismicity, in certain areas to underground injection, which is leading to increased public and regulatory scrutiny of injection safety. For example, in November 2020, the COGCC adopted various new requirements on the underground injection of fluid waste. +Reduced commodity prices could result in significant impairment charges and significant downward revisions of proved reserves. +Commodity prices are volatile. Significant and rapid declines in prices have occurred in the past and may occur in the future. Low commodity prices could result in, among other things, significant impairment charges in the future. For example, we incurred impairment charges in a number of recent periods, including charges of $882.4 million and $38.5 million in 2020 and 2019, respectively, to write down assets. Similarly, the significant decline in commodity pricing during 2020 resulted in a reduced year-end proved reserve NYMEX price of $39.57 per barrel of crude and $1.99 per MMBtu of natural gas, a decrease of 29% and 23% respectively from 2019. The decline in pricing resulted in a downward revision of 28.2 MMBoe to reserves for year-end 2020 when compared to year-end 2019. The cash flow model we use to assess properties for impairment includes numerous assumptions, such as management’s estimates of future oil and gas production and commodity prices, the outlook for forward commodity prices and operating and development costs. All inputs to the cash flow model must be evaluated at each date the estimate of future cash flows is made for each producing basin. A significant decrease in long-term forward prices could result in a significant impairment for our properties. +Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions may materially affect the quantities and present value of our reserves. +The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices, and a market based weighted average cost of capital rate. In determining the estimates of reserve and economic evaluations, management utilizes independent petroleum engineers. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate. The reserve estimates are based on assumptions regarding commodity prices, production levels and operating and development costs that may prove to be incorrect. Any significant variance from these assumptions to actual results could greatly affect: +• the economically recoverable quantities of crude oil, natural gas and NGLs attributable to any particular group of properties; +• future depreciation, depletion and amortization (“DD&A”) rates and amounts; +• impairments in the value of our assets; +• the classifications of reserves based on risk of recovery; +• estimates of future net cash flows; +• timing of our capital expenditures; and +• the amount of funds available for us to borrow under our revolving credit facility. +Some of our reserve estimates must be made with limited production histories, which renders these estimates less reliable than those based on longer production histories. Further, reserve estimates are based on the volumes of crude oil, natural gas and NGLs that are anticipated to be economically recoverable from a given date forward based on economic conditions that exist at that date. The actual quantities of crude oil, natural gas and NGLs recovered will be different than the reserve estimates, in part because they will not be produced under the same economic conditions as are used for the reserve calculations. In addition, quantities of probable and possible reserves by definition are inherently more risky than proved reserves, in part because they have greater uncertainty associated with the recoverable quantities of hydrocarbons. +26 +At December 31, 2020, approximately 56 percent of our estimated proved reserves were undeveloped. These reserve estimates reflect our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including approximately $2.3 billion during the five years ending December 31, 2025, as estimated in the calculation of our standardized measure of oil and gas activity. The estimated development costs may not be accurate, development may not occur as scheduled and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of initial booking, and we may therefore be required to downgrade any PUDs that are not developed within this five-year time frame. +The present value of the estimated future net cash flows from our proved reserves is not necessarily the same as the current market value of those reserves. Pursuant to SEC rules, the estimated discounted future net cash flows from our proved reserves, and the estimated quantity of those reserves, are based on the prior year’s first day of the month 12-month average crude oil and natural gas index prices. However, factors such as actual prices we receive for crude oil and natural gas and hedging instruments, the amount and timing of actual production, the amount and timing of future development costs, the supply of and demand for crude oil, natural gas and NGLs and changes in governmental regulations or taxation, also affect our actual future net cash flows from our properties. The timing of both our production and incurrence of expenses in connection with the development and production of crude oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10 percent discount factor we use when calculating discounted future net cash flows (the rate required by the SEC) may not be the most appropriate discount factor based on interest rates currently in effect and risks associated with our properties or the industry in general. +Unless reserves are replaced as they are produced, our reserves and production will decline, which would adversely affect our future business, financial condition and results of operations. We may not be able to develop our identified drilling locations as planned. +Producing crude oil, natural gas and NGL reservoirs are generally characterized by declining production rates that may vary over time and exceed our estimates depending upon reservoir characteristics and other factors. Our future reserves and production and, therefore, our cash flows and income, are highly dependent on our ability to efficiently develop and exploit our current reserves and to economically find or acquire additional recoverable reserves. We may not be able to develop, discover or acquire additional reserves to replace our current and future production at acceptable costs. Our failure to do so would adversely affect our future operations, financial condition and results of operations. +We have identified a number of well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including: +• crude oil, natural gas and NGL prices; +• the availability and cost of capital; +• drilling and production costs; +• availability and cost of drilling rigs, and equipment, supplies, chemicals, personnel and oilfield services; +• drilling results; +• lease expirations or limitations as to depth; +• midstream constraints; +• access to and availability of water sourcing and distribution systems; +• regulatory approvals; and +• other factors. +Because of these factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce crude oil, natural gas or NGLs from these or any other potential well locations. In addition, the number of drilling locations available to us will depend in part on the spacing of wells in our operating areas. An increase in well density in an area could result in additional locations in that area, but a reduced production performance from the area on a per-well basis. Further, certain of the horizontal wells we intend to drill in the future may require pooling of our lease interests with the interests of third parties. Some states, including Colorado, allow the involuntary pooling of tracts in a relatively broad number of circumstances in order to facilitate exploration, though Colorado now requires applicants to own or +27 +secure consent from the owners of more than 45 percent of the minerals to be pooled. Other states, notably Texas, restrict involuntary pooling to a much narrower set of circumstances and consequently these states rely primarily on voluntary pooling of lands and leases. In states such as Texas where pooling is accomplished primarily on a voluntary basis, or in states such as Colorado if we cannot meet the minimum requirement for ownership and consent, it may be more difficult to form units and, therefore, more difficult to fully develop a project if we own less than all (or cannot secure the ownership or consent of the required minimum amount) of the leasehold in the proposed units or one or more of our leases in the proposed units does not provide the necessary pooling authority. If third parties in the proposed units are unwilling to pool their interests with ours, we may be unable to require such pooling on a timely basis or at all, which would limit the total horizontal wells we can drill. Further, the number of available locations will depend in part on the expected lateral lengths of the horizontal wells we drill. Because the intended lateral length of a horizontal well is subject to change for a variety of reasons, our estimated drilling locations will change over time. For this and numerous other reasons, our actual drilling activities may materially differ from those presently identified. +Our inventory of drilling projects includes locations in addition to those that we currently classify as proved, probable and possible. The development of and results from these additional projects are more uncertain than those relating to probable and possible locations, and significantly more uncertain than those relating to proved locations. We have generally accelerated the pace of our development activities in the Wattenberg Field over the past several years, and this has reduced our related inventory of drilling locations. We anticipate that our remaining locations in the field will not, on average, be as productive or as economic as many of those we have drilled in recent years, due to lower anticipated overall production or higher gas-to-oil ratios. In the Delaware Basin, our inventory is subject to, among other things, potential lease expirations and our continued analysis of geologic challenges in certain areas. +The wells we drill may not yield crude oil, natural gas or NGLs in commercially viable quantities and productive wells may be less successful than we expect. +A prospect is a property on which our geologists have identified what they believe, based on available information, to be indications of hydrocarbon-bearing rocks. However, given the limitations of available data and technology, our geologists cannot know conclusively prior to drilling and testing whether crude oil, natural gas or NGLs will be present in sufficient quantities to repay drilling or completion costs and generate a profit. Furthermore, even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques do not enable our geologists to be certain as to the quantity of the hydrocarbons in those structures. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline. If a well is determined to be dry or uneconomic, which can occur even though it contains some crude oil, natural gas or NGLs, it is classified as a dry hole and must be plugged and abandoned in accordance with applicable regulations. This generally results in the loss of the entire cost of drilling and completion to that point, the cost of plugging and lease costs associated with the prospect. Even wells that are completed and placed into production may not produce sufficient crude oil, natural gas and NGLs to be profitable, or they may be less productive and/or profitable than we expected. For example, the data we use to model anticipated results from wells in a particular area may prove to be not representative of actual results from typical wells in the area, and this could result in production that falls short of estimates reflected in our internal business plans and/or guidance, "type curve" or other disclosures we make to the public. This risk is higher for us in certain areas in the Delaware Basin that have relatively complex geological characteristics and correspondingly greater variability in well results. In addition, initial results from a well are not necessarily indicative of its performance over a longer period. +28 +Drilling for and producing crude oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations. +Drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling can be unprofitable, not only due to dry holes, but also due to curtailments, delays or cancellations as a result of other factors, including: +• pressures or irregularities in geological formations; +• fires; +• floods, winter storms and other natural disasters and adverse weather conditions; +• loss of well control; +• loss of drilling fluid circulation and other facility or equipment malfunctions; +• title problems; +• facility or equipment malfunctions; +• unexpected operational events; +• shortages or delays in the delivery of equipment and services; +• unanticipated environmental liabilities; and +• compliance with environmental and other governmental requirements. +Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution, environmental contamination or loss of wells and regulatory penalties. For example, a loss of containment of hydrocarbons during drilling activities could potentially subject us to civil and/or criminal liability and the possibility of substantial costs, including for environmental remediation. We maintain insurance against various losses and liabilities arising from our operations; however, insurance against certain operational risks may not be available or may be prohibitively expensive relative to the perceived risks presented. For example, we may not have coverage with respect to a pollution event if we are unaware of the event while it is occurring and are therefore unable to report the occurrence of the event to our insurance company within the time frame required under our insurance policy. Thus, losses could occur for uninsurable or uninsured risks or for amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance and/or governmental or third-party responses to an event could have a material adverse effect on our business activities, financial condition and results of operations. We are currently involved in various remedial and investigatory activities at some of our wells and related sites. +In addition, certain technical risks relating to the drilling of horizontal wells - including those relating to our ability to fracture stimulate the planned number of stages and to successfully run casing the length of the well bore - have increased in recent years because we have increased the average lateral length of the horizontal wells we drill. Longer-lateral wells are also typically more expensive and require more time for preparation. In addition, we have transitioned to the use of multi-well pads instead of single-well sites. The use of multi-well pad drilling increases some operational risks because problems affecting the pad or a single well could adversely affect production from all of the wells on the pad. Pad drilling can also make our overall production, and therefore our revenue and cash flows, more volatile, because production from multiple wells on a pad will typically commence simultaneously. While we believe that we will be better served by using multi-well pads with longer lateral wells, the risk component involved in such drilling will be increased in some respects, with the result that we might find it more difficult to achieve economic success in our drilling program. +The inability of one or more of our customers or other counterparties to meet their obligations may adversely affect our financial results. +Substantially all of our accounts receivable result from our crude oil, natural gas and NGLs sales or joint interest billings to a small number of third parties in the energy industry. This concentration of customers and joint interest owners may affect our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our commodity derivatives expose us to credit risk in the event of nonperformance by counterparties. Nonperformance by our customers or derivative counterparties may adversely affect our financial condition and profitability. We face similar risks with respect to our other counterparties, including the lenders under our revolving credit facility and the providers of our insurance coverage. +29 +We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects. +We frequently own less than all of the working interest in the oil and gas leases on which we conduct operations. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities, arising from the actions of the other owners. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, may declare bankruptcy. In the event any of our project partners does not pay its share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover the costs from the partner. This could materially adversely affect our financial position. +We may not be able to keep pace with technological developments in our industry. +Our industry is characterized by rapid and significant technological advancements. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those or other new technologies at substantial cost. In addition, our competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we were unable to use the most advanced technology, our business, financial condition and results of operations could be materially adversely affected. +Competition in our industry is intense, which may adversely affect our ability to succeed. +Our industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce crude oil, natural gas and NGLs, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive properties and exploratory prospects or evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, larger companies may have a greater ability to continue exploration activities during periods of low commodity prices. Larger competitors may also be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which could adversely affect our competitive position. These factors could adversely affect our operations and our profitability. +Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel. +Our future success depends to a large extent on the services of our key employees. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise. +A failure to complete successful acquisitions would limit our ability to replace our reserves and impact our financial condition. +Because our crude oil and natural gas properties are depleting assets, our future reserves, production volumes and cash flows depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. In addition, we continue to strive to achieve greater efficiencies in our drilling program, and our ability to do so is dependent in part on our ability to complete asset exchanges and other acquisitions that allow us to increase our working interests in particular properties. We may not be able to identify attractive acquisition opportunities, and if we do identify an appropriate acquisition candidate, we may be unable to negotiate mutually acceptable terms with the seller, finance the acquisition or obtain the necessary regulatory approvals. If we are unable to complete suitable acquisitions on acceptable terms, it will be more difficult to replace our reserves, and an inability to replace our reserves would have a material adverse effect on our financial condition and results of operations. +30 +Acquisitions of properties are subject to the uncertainties of evaluating recoverable reserves and potential liabilities, including environmental uncertainties. +Acquisitions of producing and undeveloped properties, including the SRC Acquisition, have been an important part of our growth over time. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, development potential, future commodity prices, operating costs, title issues and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we generally perform engineering, environmental, geological and geophysical reviews of the acquired properties that we believe are generally consistent with customary industry practices. However, such reviews are not likely to permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well prior to an acquisition and our ability to evaluate undeveloped acreage is inherently imprecise. Even when we inspect a well, we may not always discover structural, subsurface and environmental problems that may exist or arise. In some cases, our review prior to signing a definitive purchase agreement may be even more limited. In addition, we often acquire acreage without any warranty of title except as to claims made by, through or under the transferor. +When we acquire properties, we will generally have potential exposure to liabilities and costs for environmental and other problems existing on the acquired properties, and these liabilities may exceed our estimates. We may not be entitled to contractual indemnification associated with acquired properties. We often acquire interests in properties on an “as is” basis with no or limited remedies for breaches of representations and warranties. Therefore, we could incur significant unknown liabilities, including environmental liabilities or losses due to title defects, in connection with acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, the acquisition of undeveloped acreage is subject to many inherent risks and we may not be able to realize efficiently, or at all, the assumed or expected economic benefits of acreage that we acquire. +Additionally, significant acquisitions can change the nature of our operations depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or may be in different geographic locations than our existing properties. These factors can increase the risks associated with an acquisition. Acquisitions also present risks associated with the additional indebtedness that may be required to finance the purchase price and any related increase in interest expense or other related charges. +The SRC Acquisition presented a number of the foregoing risks - for example, because closing has occurred, we have no recourse if we discover unanticipated liabilities or other problems with the properties we acquired in the transaction. In addition, those risks are greater than they were in the case of most of our previous acquisitions given the larger size of the SRC Acquisition. +Some of our acquisitions are structured as asset trades or exchanges. These transactions may give rise to any or all of the foregoing risks. In addition, transactions of this type create a risk that we will undervalue the properties we transfer to the counterparty in the trade or exchange or overvalue the properties we receive. Such an undervaluation or overvaluation would result in the transaction being less favorable to us than we expected. +We operate in a litigious environment. The cost of defending any suits brought against us, and any judgments or settlements resulting from such suits, could have an adverse effect on our results of operations and financial condition. +Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, employment litigation, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. For example, on January 18, 2021, a purported class action lawsuit was filed against us by a royalty owner alleging we have been improperly deducting certain post-production costs from the owner’s oil royalty payments. While we intend to vigorously defend this suit, the outcome of legal proceedings is inherently uncertain. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management attention and other factors. In addition, the resolution of such a proceeding could result in penalties or sanctions, settlement costs and/or judgments, consent decrees or orders requiring a change in our business practices, any of which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties, sanctions or costs may be insufficient. Judgments and estimates to determine accruals or the anticipated range of potential losses related to legal and other proceedings could change from one period to the next, and such changes could be material. Information regarding legal proceedings can be found in Note 12 - Commitments and Contingencies - Litigation and Legal +31 +Items included in Item 8. Financial Statements and Supplementary Data to our consolidated financial statements included elsewhere in this report. +Our business could be negatively impacted by security threats, including cybersecurity threats and other disruptions. +We face various security threats, including attempts by third parties to gain unauthorized access to, or control of, competitive information or to render data or systems corrupted or unusable; threats to the safety of our employees; threats to the security of our infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. There can be no assurance that the procedures and controls we use to monitor these threats and mitigate our exposure to them will be sufficient to prevent them from materializing. +Our industry has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain exploration, development and production activities. We depend on digital technology, including information systems and related infrastructure, as well as cloud applications and services, to store, transmit, process and record sensitive information (including but not limited to trade secrets, employee information and financial and operating data), communicate with our employees and business partners, and for many other activities related to our business. In addition, computer systems control the oil and gas production and processing equipment that are necessary to deliver our production to market. A disruption or failure of these systems, or of the networks and infrastructure on which they rely, may cause damage to critical production, distribution and/or storage assets, delay or prevent delivery to markets, or make it difficult to accurately account for production and settle transactions. The continuing and evolving threat of cybersecurity attacks has resulted in increased regulatory focus on prevention, which could potentially elevate costs, and failure to comply with these regulations could result in penalties and potential legal liability. +As dependence on digital technologies has increased in our industry, cyber incidents, including deliberate attacks and unintentional events, have also increased. Our systems and infrastructure are, and those of our business partners, including vendors, service providers, operating partners, purchasers of our production and financial institutions may be, subject to damage or interruption from a number of potential sources including natural disasters, software viruses or other malware, power failures, cyber-attacks and other events. We and our business partners also face various other cyber-security threats from criminal hackers, state-sponsored intrusion, industrial espionage and employee malfeasance, including threats to gain access to sensitive information or to render data or systems unusable. +Our technologies, systems and networks, and those of our business partners, may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, theft of property or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. Although we have not suffered material losses related to cyber-attacks to date, if we were successfully attacked, we could incur substantial remediation and other costs or suffer other negative consequences, such as a loss of competitive information, critical infrastructure, personnel or capabilities essential to our operations. Events of this nature could have a material adverse effect on our reputation, financial condition, results of operations or cash flows. Moreover, as the sophistication of cyber-attacks continues to evolve, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities. +The physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. +Many scientists believe that increasing concentrations of carbon dioxide, methane and other GHGs in the Earth's atmosphere are changing global climate patterns. One consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such events were to occur, or become more frequent, our operations could be adversely affected in various ways, including through damage to our facilities or from increased costs for insurance. +Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. As a result, if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business. +32 +Risks Relating to Financial Matters +Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our production and reserves, and ultimately our profitability. Lender hesitancy to offer financing to our industry may increase this risk. +Our industry is capital intensive. We expect to continue to make substantial capital expenditures for the exploration, development, production and acquisition of crude oil, natural gas and NGL reserves. To date, we have financed capital expenditures primarily with bank borrowings under our revolving credit facility, cash generated from operations and proceeds from capital markets transactions and the sale of properties. We intend to finance our future capital expenditures utilizing similar financing sources. Our cash flows from operations and access to capital are subject to a number of variables, including: +• our proved reserves; +• the amount of crude oil, natural gas and NGLs we are able to produce from existing wells; +• the prices at which crude oil, natural gas and NGLs are sold; +• the costs to produce crude oil, natural gas and NGLs; and +• our ability to acquire, locate and produce new reserves. +If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower commodity prices, operating difficulties or for any other reason, our need for capital from other sources could increase, and there can be no assurance that such other sources of capital would be available at that time on reasonable terms or at all. If we raise funds by issuing additional equity securities, this would have a dilutive effect on existing shareholders. If we raise funds through the incurrence of debt, the risks we face with respect to our indebtedness would increase and we would incur additional interest expense. +Additionally, due to recent default rates in the oil and gas industry and other factors, some lenders have expressed a hesitancy to lend to oil and gas producers, and may require terms less favorable to the producers or, in some cases, may refuse to provide financing to the industry altogether. We anticipate that the number of lenders willing to participate in the lending syndicate under our revolving credit facility may decline in the future. Our inability to obtain sufficient financing on acceptable terms would adversely affect our financial condition and profitability. +We have a substantial amount of debt and the cost of servicing, and risks related to refinancing, that debt could adversely affect our business. Those risks could increase if we incur more debt. +We have a substantial amount of indebtedness outstanding. As a result, a significant portion of our cash flows will be required to pay interest and principal on our indebtedness, and we may not generate sufficient cash flows from operations, or have future borrowing capacity available, to enable us to repay our indebtedness or to fund other liquidity needs. +Servicing our indebtedness and satisfying our other obligations will require a significant amount of cash. Our cash flow from operating activities and other sources may not be sufficient to fund our liquidity needs. Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend on our future operating performance, our financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control. We cannot assure you that our business will generate sufficient cash flow from operations, or that sufficient future borrowings will be available to us under our revolving credit facility or otherwise, to fund our liquidity needs. +A substantial decrease in our operating cash flow or an increase in our expenses could make it difficult for us to meet debt service requirements and could require us to modify our operations, including by curtailing our exploration and drilling programs, reducing our capital expenditures, refinancing all or a portion of our existing debt or obtaining additional financing. In addition, we might be required to dispose of material assets or operations to meet our debt service and other obligations. We may not be able to consummate these dispositions for fair market value, in a timely manner or at all. Furthermore, any proceeds that we could realize from any dispositions may not be adequate to meet our debt service obligations then due. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which +33 +could further restrict our business operations. In addition, the terms of our debt agreements could restrict us from implementing some of these alternatives. +Covenants in our debt agreements currently impose, and future financing agreements may impose, significant operating and financial restrictions. +Our current debt agreements contain restrictions, and future financing agreements may contain additional restrictions, on our activities, including covenants that restrict our and our restricted subsidiaries’ ability to: +• incur additional debt; +• pay dividends on, redeem or repurchase stock; +• create liens; +• make specified types of investments; +• apply net proceeds from certain asset sales; +• engage in transactions with our affiliates; +• engage in sale and leaseback transactions; +• merge or consolidate; +• restrict dividends or other payments from restricted subsidiaries; +• sell equity interests of restricted subsidiaries; and +• sell, assign, transfer, lease, convey or dispose of assets. +Our revolving credit facility is secured by substantially all of our oil and gas properties as well as a pledge of all ownership interests in our operating subsidiaries. The restrictions contained in our debt agreements may prevent us from taking actions that we believe would be in the best interest of our business, and may make it difficult for us to successfully execute our business strategy or effectively compete with companies that are not similarly restricted. We may also incur future debt obligations that subject us to additional restrictive covenants. +Our revolving credit facility has substantial restrictions and financial covenants and our ability to comply with those restrictions and covenants is uncertain. Our lenders can unilaterally reduce our borrowing availability based on anticipated commodity prices. +We expect to depend on our revolving credit facility for part of our future capital needs. Our ability to comply with covenants and restrictions in our credit agreement in the future is uncertain and will be affected by the levels of cash flows from operations and events or circumstances beyond our control. Our failure to comply with any of these restrictions and covenants could result in a default under our credit agreement, and cause all of our existing indebtedness to become immediately due and payable. +The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based upon projected revenues from the properties securing their loan. Decreases in the price of crude oil, natural gas or NGLs can be expected to have an adverse effect on the borrowing base. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Outstanding borrowings in excess of the borrowing base must be repaid immediately unless we pledge other crude oil and natural gas properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility. Our inability to borrow additional funds under our revolving credit facility could adversely affect our operations and our financial results. +If we are unable to comply with the restrictions and covenants in our debt agreements, the resulting default could lead to an acceleration of payment of funds that we have borrowed and we may not have or be able to obtain the funds necessary to repay those amounts. +Any default under the agreements governing our indebtedness, including a default under our revolving credit facility that is not waived by the required lenders, and the remedies sought by the holders of any such indebtedness, could make us unable to pay principal and interest on our indebtedness and satisfy our other obligations. If we are unable to generate sufficient cash flows and are otherwise unable to obtain the funds necessary to meet required payments of principal and interest on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the instruments governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. +34 +In the event of such a default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our revolving credit facility could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets, and we could be forced into bankruptcy or liquidation. In addition, the default could result in a cross-default under other debt agreements. If our operating performance declines, we may in the future need to seek waivers from the required lenders under our revolving credit facility to avoid being in default and we may not be able to obtain such a waiver. If this occurs and no waiver is obtained, we would be in default under our revolving credit facility, the lenders could exercise their rights as described above, and we could be forced into bankruptcy or liquidation. We cannot assure you that we will be granted waivers or amendments to our debt agreements if for any reason we are unable to comply with these agreements, or that we will be able to refinance our debt on terms acceptable to us, or at all. +We may be adversely affected by the phaseout of the London Interbank Offered Rate ("LIBOR") or the replacement of LIBOR with a different reference rate. +On July 27, 2017, the Financial Conduct Authority (the authority that regulates LIBOR) announced that it would phase out LIBOR by the end of 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, is in the process of assessing replacing U.S. dollar LIBOR with a newly created index (e.g. secured overnight financing rate). Changes in the method of calculating LIBOR, or the replacement of LIBOR with an alternative rate or benchmark, may adversely affect interest rates and result in higher borrowing costs. This could materially and adversely affect our results of operations, cash flows and liquidity. It is not possible to predict the effect of these changes or the establishment of alternative reference rates in the United States or elsewhere. +Our commodity derivative activities could result in financial losses or reduced income from failure to perform by our counterparties, could limit our potential gains from increases in prices and could result in volatility in our net income. +We use commodity derivatives for a portion of the production from our own wells to achieve more predictable cash flows, to reduce exposure to adverse fluctuations in commodity prices, and to allow our natural gas marketing company to offer pricing options to natural gas sellers and purchasers. These arrangements expose us to the risk of financial loss in some circumstances, including when purchases or sales are different than expected or the counterparty to the commodity derivative contract defaults on its contractual obligations. In addition, many of our commodity derivative contracts are based on WTI or another crude oil or natural gas index price. The risk that the differential between the index price and the price we receive for the relevant production may change unexpectedly makes it more difficult to hedge effectively and increases the risk of a hedging-related loss. Also, commodity derivative arrangements may limit the benefit we would otherwise receive from increases in the prices for the relevant commodity. +At December 31, 2020, we had hedged a total of 20.0 MMBbls crude oil and 120.5 MMBtu of natural gas for 2021 and 2022. These hedges may be inadequate to protect us from continuing and prolonged declines in crude oil and natural gas prices. +Since we do not designate our commodity derivatives as cash flow hedges, we do not currently qualify for use of hedge accounting; therefore, changes in the fair value of commodity derivatives are recorded in our income statements and our net income is subject to greater volatility than it would be if our commodity derivative instruments qualified for hedge accounting. For instance, if commodity prices rise significantly, this could result in significant non-cash charges during the relevant period, which could have a material negative effect on our net income. +Our insurance coverage may not be sufficient to cover some liabilities or losses that we may incur. +The occurrence of a significant accident or other event that is not fully covered by insurance, not properly or timely noticed to our carrier, or that is in excess of our insurance coverage, could have a material adverse effect on our operations and financial condition. Insurance does not protect us against all operational risks. We do not carry business interruption insurance at levels that would provide enough funds for us to continue operating without access to other funds. In addition, pollution and environmental risks are generally not fully insurable. The cost of obtaining insurance has increased as a result of the SRC Acquisition because of the increased size of our asset base. +35 +The price of our common stock has been and may continue to be highly volatile, which may make it difficult for shareholders to sell our common stock when desired or at attractive prices. +The market price of our common stock is highly volatile and we expect it to continue to be volatile for the foreseeable future. Adverse events including changes in production volumes, worldwide demand and prices for crude oil and natural gas, regulatory developments, and changes in securities analysts’ estimates of our financial performance could negatively impact the market price of our common stock. General market conditions, including the level of, and fluctuations in, the trading prices of stocks generally could also have a similar negative impact. The stock markets regularly experience price and volume volatility that affects many companies’ stock prices without regard to the operating performance of those companies. Volatility of this type may affect the trading price of our common stock. Similar factors could also affect the trading prices of our senior notes. +ITEM 1B. UNRESOLVED STAFF COMMENTS +None. +ITEM 3. LEGAL PROCEEDINGS +Information regarding our legal proceedings can be found in Note 12 - Commitments and Contingencies - Litigation and Legal Items included in Item 8. Financial Statements and Supplementary Data to our consolidated financial statements included elsewhere in this report. +ITEM 4. MINE SAFETY DISCLOSURES +Not applicable. +36 +PART II +ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Our common stock, par value $0.01 per share, is traded on the NASDAQ Global Select Market under the symbol "PDCE." +As of February 16, 2021, we had approximately 430 stockholders of record. +While we have not declared any cash dividends on our common stock, our board of directors recently approved a quarterly dividend program expected to commence mid-2021. The dividend program and payment of any future dividends thereunder will be made at the discretion of our board of directors and will depend on our results of operations, cash flows, financial position and capital requirements, as well as general business conditions, legal, tax and regulatory restrictions and other factors our board of directors deems relevant at the time it determines to declare such dividends. +Additionally, our revolving credit facility, as well as the indentures governing our 6.125% senior notes due 2024 (the "2024 Senior Notes"), 2025 Senior Notes and 2026 Senior Notes, the terms of which are summarized in Note 9 - Long-term Debt in Item 8. Financial Statements and Supplementary Data included elsewhere in this report, include restrictions based on our leverage and other certain financial metrics that could impact our ability to pay cash dividends. As we declare dividends in the future, we will monitor compliance with such restrictions. +The following table presents information about our purchases of our common stock during the year ended December 31, 2020: +Period +Total Number of Shares Purchased (1) (3) +Average Price Paid per Share +Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1) +Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs (in millions) +January (2) +485,948 $ 23.72 217,500 $ 366.0 +February 585,455 20.95 552,500 354.5 +March 500,782 15.41 496,000 346.8 +April 49,064 6.29 — 346.8 +May 14,134 11.27 — 346.8 +June 1,021 16.02 — 346.8 +July 6,902 13.34 — 346.8 +August 6,619 14.80 — 346.8 +September 3,121 13.26 — 346.8 +October 68,112 13.28 — 346.8 +November 1,209 15.06 — 346.8 +December 628 18.40 — 346.8 +Total purchases 1,722,995 $ 19.25 1,266,000 $ 346.8 +_____________ +(1) In April 2019, the board of directors approved a program to acquire up to $200.0 million of our outstanding common stock and in August 2019, effective with the closing of the SRC Acquisition, increased such amount to $525.0 million (the "Stock Repurchase Program"). The Stock Repurchase Program does not require any specific number of shares to be acquired, and can be modified or discontinued by the board of directors at any time. We reinstated our Stock Repurchase Program in late February 2021. Repurchases may extend until December 31, 2023. +(2) In January 2020, we merged with SRC, and upon closing, issued approximately 38.9 million shares of our common stock to SRC shareholders. Of the issued shares, 244,333 shares were withheld in lieu of tax liabilities related to the issuance of the stock. +(3) Purchases outside of the Stock Repurchase Program and not in connection with the SRC Acquisition represent shares withheld from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans. The withheld shares are not considered common stock repurchased under the Stock Repurchase Program. +37 +Stockholder Performance Graph +The performance graph below compares the cumulative total return of our common stock over the five-year period ended December 31, 2020 with the cumulative total returns for the same period for the Standard and Poor's ("S&P") 500 Index and the Standard Industrial Code ("SIC") Index. The SIC Index is a weighted composite of 196 crude petroleum and natural gas companies. The cumulative total stockholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on December 31, 2015, and in the S&P 500 Index and the SIC Index on the same date. The results shown in the graph below are not necessarily indicative of future performance. +COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN +Among PDC Energy, Inc., the S&P 500 Index, and a Peer Group +12/15 12/16 12/17 12/18 12/19 12/20 +PDC Energy 100.00 135.97 96.55 55.75 49.03 38.46 +S&P 500 100.00 111.96 136.4 130.42 171.49 203.04 +Peer Group 100.00 137.64 131.01 94.81 85.35 52.16 +38 +ITEM 6. SELECTED FINANCIAL DATA +The selected financial data set forth below should be read in conjunction with Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data of this report. +Year Ended/As of December 31, +2020 (1) +2019 2018 2017 2016 +(in millions, except per share data and as noted) +Statement of Operations: +Crude oil, natural gas and NGLs sales $ 1,152.6 $ 1,307.3 $ 1,390.0 $ 913.1 $ 497.4 +Commodity price risk management gain (loss), net 180.3 (162.8) 145.2 (3.9) (125.7) +Total revenues 1,339.2 1,156.1 1,548.7 921.6 382.9 +Net income (loss) (724.3) (56.7) 2.0 (127.5) (245.9) +Earnings (loss) per share: +Basic $ (7.37) $ (0.89) $ 0.03 $ (1.94) $ (5.01) +Diluted (7.37) (0.89) 0.03 (1.94) (5.01) +Statement of Cash Flows: +Net cash flows from: +Operating activities $ 870.1 $ 858.2 $ 889.3 $ 597.8 $ 486.3 +Investing activities (687.2) (677.8) (1,087.9) (717.0) (1,509.1) +Financing activities (181.3) (188.9) 18.1 65.0 1,266.1 +Capital expenditures for development of crude oil and natural gas properties (551.0) (855.9) (946.4) (737.2) (436.9) +Acquisition of crude oil and natural gas properties (139.8) (13.2) (180.0) (15.6) (1,073.7) +Balance Sheet: +Total assets $ 5,238.0 $ 4,448.7 $ 4,544.1 $ 4,420.4 $ 4,485.8 +Working capital (deficit) (471.6) (57.2) (166.6) (16.4) 129.2 +Total debt, net of unamortized discount and debt issuance costs 1,602.6 1,177.2 1,194.9 1,151.9 1,044.0 +Total stockholders' equity 2,615.5 2,335.5 2,526.7 2,507.6 2,622.8 +Average Pricing and Production Expenses (per Boe and as a percent of sales for production taxes): +Sales price (excluding net settlements on derivatives) $ 16.86 $ 26.46 $ 34.61 $ 28.69 $ 22.43 +Lease operating expenses 2.36 2.88 3.26 2.82 2.70 +Production taxes 0.87 1.63 2.25 1.91 1.42 +Production taxes (as a percent of sales) 5.2 % 6.2 % 6.5 % 6.6 % 6.3 % +Transportation, gathering and processing 1.14 0.94 0.93 1.04 0.83 +Total production 68,368 49,414 40,160 31,830 22,176 +Total proved reserves (MMBoe) 731.1 610.9 544.9 452.9 341.4 +_____________ +(1) In 2020, we closed the SRC Acquisition for aggregate consideration of approximately $1.2 billion. +39 +ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included in Item 8. Financial Statements and Supplementary Data and also with Item 1A. Risk Factors of this report. A discussion of changes in our results of operations from 2018 to 2019 has been omitted from this report but may be found in Item 7. Management's Discussion and Analysis , of our Annual Report on Form 10-K for the year ended December 31, 2019, filed with the SEC on February 27, 2020. Further, we encourage you to review the Special Note Regarding Forward-Looking Statements in Part I of this report. +EXECUTIVE SUMMARY +2020 Financial Overview of Operations and Liquidity +COVID-19 Impact +During 2020, the effects of the coronavirus 2019 (“COVID-19”) pandemic led to a significant decline in global demand for crude oil and natural gas, contributing to a drastic reduction in commodity prices and negatively impacting oil and natural gas producers located in the United States, including PDC. The commodity price environment may remain volatile for an extended period as a result of reduced global oil and natural gas demand and the global economic recession. We expect to be able to fund our operations, planned capital expenditures, working capital and other requirements during the next 12 months and for the foreseeable future. See Item 1A. Risk Factors for additional information regarding the potential impacts of the COVID-19 pandemic. +Financial Matters +Production volumes increased 38 percent to 68.4 MMBoe in 2020 compared to 2019. The majority of the increase is attributed to producing properties acquired in the SRC Acquisition. Total liquids production of crude oil and NGLs comprised 60 percent of production in 2020. For the month ended December 31, 2020, we maintained an average production rate of approximately 178,000 Boe per day, up from approximately 139,000 Boe per day for the month ended December 31, 2019. +Crude oil, natural gas and NGLs sales revenue decreased to $1.2 billion in 2020 compared to $1.3 billion in 2019, driven by a 36 percent decrease in weighted-average realized commodity prices, partially offset by the 38 percent increase in production. +We had positive net settlements from commodity derivative contracts of $279.3 million for 2020 as compared to negative net settlements of $17.6 million for 2019. +The combined revenue from crude oil, natural gas and NGLs sales and net settlements received on our commodity derivative instruments was $1.4 billion in 2020 and $1.3 billion in 2019. +In 2020, we generated a net loss of $724.3 million or, $7.37 per diluted share, compared to net loss of $56.7 million, or $0.89 per diluted share, in 2019. Our net loss for the year ended December 31, 2020 as compared to December 31, 2019 was most significantly impacted by the increase in impairment of properties and equipment and the decrease in crude oil, natural gas and NGLs sales, partially offset by the net commodity price risk management gain. +Adjusted EBITDAX, a non-U.S. GAAP financial measure, was $990.6 million and $882.7 million, in 2020 and 2019, respectively. Cash flows from operations were $870.1 million and $858.2 million in 2020 and 2019, respectively, and adjusted cash flows from operations, a non-U.S. GAAP financial measure, were $921.6 million and $825.4 million, respectively. Adjusted free cash flow, a non-U.S. GAAP financial measure, was $399.3 million for 2020 as compared to $37.7 million for 2019 . +See Reconciliation of Non-U.S. GAAP Financial Measures below for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures. +40 +SRC Acquisition +In January 2020, we merged with SRC in a transaction valued at $1.7 billion, inclusive of SRC's net debt. Upon closing, we issued approximately 38.9 million shares of our common stock to SRC shareholders and holders of SRC equity awards, reflecting the issuance of 0.158 of a share of our common stock in exchange for each share of SRC common stock and the cancellation of outstanding SRC equity awards pursuant to the Merger Agreement. +Liquidity +Available liquidity as of December 31, 2020 was $1.4 billion, which was comprised of $2.6 million of cash and cash equivalents and $1.4 billion available for borrowing under our revolving credit facility. In September 2020, we issued an additional $150.0 million principal amount of 2026 Senior Notes. The net proceeds from the offering were used to repay a portion of the amount outstanding under our revolving credit facility. In October 2020, as part of our fall 2020 semi-annual redetermination, the borrowing base of our credit facility was reduced from $1.7 billion to $1.6 billion, with a corresponding automatic reduction of our elected commitment level to $1.6 billion. Looking into 2021, based on our expected cash flows from operations, our cash and cash equivalents and availability under our revolving credit facility, we believe that we will have sufficient capital available to repay our 2021 Convertible Notes, which mature in September 2021, and to fund our planned activities through the 12-month period following the filing of this report. We exited 2020 with a debt balance of $1.6 billion. +Stock Repurchase Program +As previously noted, our board of directors has approved a Stock Repurchase Program of $525 million, of which approximately $346.8 million remains available. We suspended the program in March 2020 but recently reinstated it in light of our reduced level of indebtedness. The program may extend until December 31, 2023. +Drilling and Completion Overview +We ran three drilling rigs in the Wattenberg Field through the middle of April 2020, when we dropped to a two-rig pace. We released a second rig at the end of May 2020 and continued at a one-rig pace for the remainder of the year. We also released our only completion crew in the Wattenberg Field in early May 2020 but resumed completion activities in September 2020. In the Delaware Basin, we ran one drilling rig through early May 2020 and we released our only active completion crew in March 2020. We did not have material activity in the Delaware Basin for the remainder of 2020. Our total 2020 capital investments in crude oil and natural gas properties was $522.3 million. +The following tables summarize our drilling and completion activity for the year ended December 31, 2020: +Operated Wells +Wattenberg Field +Delaware Basin (1) +Total +Gross Net Gross Net Gross Net +In-process as of December 31, 2019 145 134.3 30 29.1 175 163.4 +Wells spud 105 99.3 3 2.9 108 102.2 +Acquired in-process (2) +88 84.7 — — 88 84.7 +Wells turned-in-line (124) (116.5) (13) (13.0) (137) (129.5) +In-process as of December 31, 2020 214 201.8 20 19.0 234 220.8 +_____________ +(1) In the Delaware Basin, we had eight operated batch drilled wells that were spud in late December 2019 with final laterals being reached in early 2020. +(2) Represents in-process wells and wells being completed that we received as part of the SRC Acquisition. +Our in-process wells represent wells that are in the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection. Our in-process wells are generally completed and turned-in-line within two years of drilling. +2021 Operational and Financial Outlook +We anticipate that our total production for 2021 will range between 190,000 Boe to 200,000 Boe per day, approximately 64,000 Bbls to 68,000 Bbls of which are expected to be crude oil. Our planned 2021 capital investments in crude +41 +oil and natural gas properties, which we expect to be between $500 million and $600 million, are focused on continued execution of our development plans in the Wattenberg Field and the Delaware Basin. +We believe that we maintain a degree of operational flexibility to control the pace of our capital spending. As we execute our capital investment program, we continually monitor, among other things, expected rates of return, the political environment and our remaining inventory in order to best meet our short- and long-term corporate strategy. We may revise our 2021 capital investment program during the year as a result of, among other things, changes in commodity prices or our internal long-term outlook for commodity prices, requirements to hold acreage, the cost of services for drilling and well completion activities, drilling results, changes in our borrowing capacity, a significant change in cash flows, regulatory issues, requirements to maintain continuous activity on leaseholds or acquisition and/or divestiture opportunities. +Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays in the rural areas of the core Wattenberg Field, which is further delineated between the Kersey, Prairie, Plains, and Summit development areas. Our 2021 capital investment program for the Wattenberg Field is approximately 75 percent of our expected total capital investments in crude oil and natural gas properties, of which approximately 90 percent is expected to be invested in operated drilling and completion activity. In 2021, we plan to drill standard-reach lateral ("SRL"), mid-reach lateral (“MRL”) and extended-reach lateral (“XRL”) wells in the Wattenberg Field. In 2021, we anticipate spudding approximately 75 to 85 operated wells and turning-in-line approximately 150 to 175 operated wells. As of December 31, 2020, we have approximately 214 gross operated DUCs and 300 approved permitted locations. In 2021,we expect to operate with one full-time horizontal rig and completion crew along with a part-time spudder rig. Our program is expected to have an average development cost per well between $2.5 million and $3.6 million, depending upon the lateral length of the well. The remainder of the Wattenberg Field capital investment program is expected to be used for land, capital workovers, facilities projects and non-operated drilling. +Delaware Basin. Total capital investments in crude oil and natural gas properties in the Delaware Basin for 2021 are expected to be approximately 25 percent of our total capital investments, of which approximately 90 percent is expected to be invested in operated drilling and completion activity. In 2021, we anticipate spudding and turning-in-line approximately 15 to 20 operated wells. The majority of the wells we plan to drill in 2021 in the Delaware Basin are MRL and XRL wells. We expect to drill at a one-rig pace in 2021 along with a completion crew for four months starting towards the end of the first quarter, with an average development costs per well between $6.7 million and $8.0 million for MRL and XRL wells, depending upon the lateral length of the well. +We are committed to our disciplined approach to managing our development plans. Based on our current production forecast for 2021 and assumed average NYMEX prices of $45.00 per Bbl of crude oil and $2.50 per Mcf of natural gas and an assumed average composite price of $12.00 per Bbl for NGLs, we expect 2021 cash flows from operations to exceed our capital investments in crude oil and natural gas properties. Any excess cash flows from operations will be used towards reducing our indebtedness as well as returning capital to our shareholders. +Colorado Political Update +Certain interest groups in Colorado opposed to oil and natural gas development generally, and hydraulic fracturing in particular, have historically advanced various alternatives for ballot initiatives which would result in significantly limiting or preventing oil and natural gas development in the state. Senate Bill 19-181 ("SB19-181") was enacted by the Colorado legislature in 2019 to address concerns underlying the ballot initiatives. The COGCC conducted a series of rulemaking hearings pursuant to SB 19-181 during 2020 which resulted in updated regulatory and permitting requirements, including setbacks and siting requirements. The COGCC commissioners determined that locations with residential or high occupancy building units, schools or child care facilities within 2,000 feet would be subject to additional siting requirements, but also supported “off ramps” allowing oil and gas operators to site their drill pads as close as 500 feet from residential or high occupancy building units (excluding schools and child care facilities) in certain circumstances. The 2020 rulemaking hearings also resulted in the adoption of a number of other new regulatory requirements, including requirements regarding permitting, cumulative and surface impacts, asset transfers, venting and flaring, and remediation. However, third-party proposals which were presented to the COGCC prohibit or dramatically restrict oil and gas development were not adopted by the Commissioners. Governor Polis has publicly stated his opposition to further ballot initiatives in 2022 while rulemaking under SB 19-181 is in process and has acknowledged the importance of regulatory certainty. +It is nevertheless possible that future ballot initiatives will be proposed that would dramatically limit the areas of the state in which drilling would be permitted to occur. See Part I, Item1A. Risk Factors- Relating to Our Business and the +42 +Industry-Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us. +Results of Operations +Summary of Operating Results +The following table presents selected information regarding our operating results: +Year Ended December 31, +Percent Change +2020 2019 2018 2020-2019 2019-2018 +(dollars in millions, except per unit data) +Production: +Crude oil (MBbls) 23,720 19,166 16,963 24 % 13 % +Natural gas (MMcf) 165,637 115,950 88,017 43 % 32 % +NGLs (MBbls) 17,042 10,923 8,527 56 % 28 % +Crude oil equivalent (MBoe) 68,368 49,414 40,160 38 % 23 % +Average Boe per day (Boe) 186,798 135,381 110,027 38 % 23 % +Crude Oil, Natural Gas and NGLs Sales: +Crude oil $ 816.8 $ 1,020.7 $ 1,038.0 (20) % (2) % +Natural gas 178.8 151.0 163.2 18 % (7) % +NGLs 157.0 135.6 188.8 16 % (28) % +Total crude oil, natural gas and NGLs sales $ 1,152.6 $ 1,307.3 $ 1,390.0 (12) % (6) % +Net Settlements on Commodity Derivatives: +Crude oil 294.4 (18.3) (124.4) * (85) % +Natural gas (15.1) 0.7 13.9 * (95) % +NGLs — — (5.0) * * +Total net settlements on derivatives 279.3 (17.6) (115.5) * (85) % +Average Sales Price (excluding net settlements on derivatives): +Crude oil (per Bbl) $ 34.44 $ 53.26 $ 61.19 (35) % (13) % +Natural gas (per Mcf) 1.08 1.30 1.85 (17) % (30) % +NGLs (per Bbl) 9.21 12.41 22.14 (26) % (44) % +Crude oil equivalent (per Boe) 16.86 26.46 34.61 (36) % (24) % +Average Costs and Expenses (per Boe): +Lease operating expenses $ 2.36 $ 2.88 $ 3.26 (18) % (12) % +Production taxes 0.87 1.63 2.25 (47) % (28) % +Transportation, gathering and processing expenses 1.14 0.94 0.93 21 % 1 % +General and administrative expense 2.36 3.27 4.25 (28) % (23) % +Depreciation, depletion and amortization 9.06 13.04 13.94 (31) % (6) % +Lease Operating Expenses by Operating Region (per Boe): +Wattenberg Field $ 2.15 $ 2.50 $ 2.99 (14) % (16) % +Delaware Basin 3.48 4.15 4.14 (16) % — % +Utica Shale (1) +— — 3.46 * * +____________ +* Percent change is not meaningful. +(1) In March 2018, we completed the disposition of our Utica Shale properties. +43 +Crude Oil, Natural Gas and NGLs Sales +Crude oil, natural gas and NGLs sales revenue for the year ended December 31, 2020 decreased compared to the year ended December 31, 2019 due to the following: +Year Ended December 31, +2020 2019 +(in millions) +Change in: +Production $ 383.2 $ 239.6 +Average crude oil price (446.4) (152.0) +Average natural gas price (37.0) (64.0) +Average NGLs price (54.5) (106.3) +Total change in crude oil, natural gas and NGLs sales revenue $ (154.7) $ (82.7) +Crude Oil, Natural Gas and NGLs Production +The following table presents crude oil, natural gas and NGLs production. +Year Ended December 31, +Percent Change +Production by Operating Region 2020 2019 2018 2020-2019 2019-2018 +Crude oil (MBbls) +Wattenberg Field 19,552 14,489 12,809 35 % 13 % +Delaware Basin 4,168 4,677 4,108 (11) % 14 % +Utica Shale (1) +— — 46 * * +Total 23,720 19,166 16,963 24 % 13 % +Natural gas (MMcf) +Wattenberg Field 140,845 91,785 68,326 53 % 34 % +Delaware Basin 24,792 24,165 19,277 3 % 25 % +Utica Shale (1) +— — 414 * * +Total 165,637 115,950 88,017 43 % 32 % +NGLs (MBbls) +Wattenberg Field 14,495 8,198 6,455 77 % 27 % +Delaware Basin 2,547 2,725 2,038 (7) % 34 % +Utica Shale (1) +— — 34 * * +Total 17,042 10,923 8,527 56 % 28 % +Crude oil equivalent (MBoe) +Wattenberg Field 57,521 37,984 30,652 51 % 24 % +Delaware Basin 10,847 11,430 9,359 (5) % 22 % +Utica Shale (1) +— — 149 * * +Total 68,368 49,414 40,160 38 % 23 % +Average crude oil equivalent per day (Boe) +Wattenberg Field 157,161 104,066 83,978 51 % 24 % +Delaware Basin 29,637 31,315 25,641 (5) % 22 % +Utica Shale (1) +— — 408 * * +Total 186,798 135,381 110,027 38 % 23 % +____________ +* Percent change is not meaningful. +(1) In March 2018, we completed the disposition of our Utica Shale properties. +44 +Net production volumes for oil, natural gas and NGLs increased 38% during 2020 compared to 2019. The overall production increase between periods was primarily due to producing properties acquired in the SRC Acquisition, which added approximately 19.7 MMBoe of incremental production in 2020, and wells turned-in-line during 2020. These volume increases were partially offset by normal field production declines across our existing wells. +The following table presents our crude oil, natural gas and NGLs production ratio by operating region: +Year Ended December 31, +Production Ratio by Operating Region 2020 2019 2018 +Wattenberg Field +Crude oil 34 % 38 % 42 % +Natural gas 41 % 40 % 37 % +NGLs 25 % 22 % 21 % +Total 100 % 100 % 100 % +Delaware Basin +Crude oil 38 % 41 % 44 % +Natural gas 38 % 35 % 34 % +NGLs 24 % 24 % 22 % +Total 100 % 100 % 100 % +Utica Shale (1) +Crude oil — % — % 31 % +Natural gas — % — % 46 % +NGLs — % — % 23 % +Total — % — % 100 % +____________ +(1) In March 2018, we completed the disposition of our Utica Shale properties. +Midstream Capacity +Our ability to market our production depends substantially on the availability, proximity and capacity of in-field gathering systems, compression and processing facilities, as well as transportation pipelines out of the basin, all of which are owned and operated by third parties. If adequate midstream facilities and services are not available on a timely basis and at acceptable costs, our production and results of operations could be adversely affected. In response to the substantial development drilling in our current areas of operation in recent years, third-party midstream providers have significantly expanded their midstream facilities and services. These third-party midstream facility expansions, in conjunction with the more recent slowdown in producer activity, have provided for improved and more stabilized line pressures and a production environment that is more favorable for producers, both currently and for the near term given anticipated producer activity levels. +The ultimate timing and availability of adequate infrastructure remains out of our control. Weather, regulatory developments and other factors also affect the adequacy of midstream infrastructure. Like other producers, from time to time we enter into volume commitments with midstream providers in order to incentivize them to provide increased capacity to sufficiently meet our projected volume growth from our areas of operation. If our production falls below the level required under these agreements, we could be subject to transportation charges or aid in construction payments for commitment shortfalls. +Wattenberg Field . Beginning in the mid-fourth quarter of 2019 and continuing through the fourth quarter of 2020, the combination of DCP Midstream, LP's ("DCP") continued system expansions and the availability of both residue gas and NGL takeaway out of the basin allowed us to experience reduced line pressures for all of our operated areas of the Wattenberg Field. Given current and forecasted activity levels in the basin, we anticipate that this expansion will provide ample processing capacity to accommodate our future operated production. +Our production in the Wattenberg Field is significantly dependent on DCP's gathering system, and this reliance increased considerably when we closed the SRC Acquisition. We continue to work with our midstream service providers in an +45 +effort to ensure all of the existing in-basin infrastructure is fully utilized and that all options for system expansion are evaluated and implemented to the extent possible to accommodate projected future volume growth from the field. +As midstream infrastructure development and upstream capital discipline continues, we anticipate having the ability to move additional volumes on DCP’s system in the long-term. The successful and timely completion of incremental development projects depends on continued capital investment by midstream providers, which could be impacted during times of challenging market conditions. +Delaware Basin . Our production from the Delaware Basin was not materially affected by midstream or downstream capacity constraints during the year ended December 31, 2020. Similar to the Wattenberg Field, our crude oil netback pricing realizations were most negatively impacted by the demand reduction that resulted from COVID-19. +Pipeline utilization in the Permian Basin has fallen from the constrained levels experienced during the first quarter of 2020. The COVID-19-induced downturn also forced widespread curtailments in natural gas production, which lowered pipeline utilization and eventually improved pricing differentials in the basin during the remainder of 2020. The completion of Kinder Morgan’s Permian Highway Pipeline occurred in the fourth quarter of 2020 and provides additional takeaway capacity out of the Permian Basin. A portion of our natural gas production is committed to the use of this pipeline starting in January 2021. +Crude Oil, Natural Gas and NGLs Pricing +Our results of operations depend upon many factors. Key factors include market prices of crude oil, natural gas and NGLs and our ability to market our production effectively. Crude oil, natural gas and NGLs prices have a high degree of volatility and our realizations can change substantially. Our realized sales prices for crude oil, natural gas and NGLs decreased 36 percent during 2020 as compared to 2019. The NYMEX average daily crude oil and NYMEX first-of-the-month natural gas prices decreased 31 percent and 21 percent, respectively, as compared to 2019. The decreases were primarily due to the effects of the COVID-19 pandemic, geopolitical conditions and supply disruptions. +46 +The following table presents weighted-average sales prices of crude oil, natural gas and NGLs for the periods presented: +Year Ended December 31, +Weighted-Average Realized Sales Price by Operating Region Percent Change +(excluding net settlements on derivatives) 2020 2019 2018 2020-2019 2019-2018 +Crude oil (per Bbl) +Wattenberg Field $ 34.21 $ 52.99 $ 61.14 (35) % (13) % +Delaware Basin 35.48 54.08 61.37 (34) % (12) % +Utica Shale (1) +— — 58.10 * * +Weighted-average price 34.44 53.26 61.19 (35) % (13) % +Natural gas (per Mcf) +Wattenberg Field 1.22 1.49 1.90 (18) % (22) % +Delaware Basin 0.28 0.57 1.66 (51) % (66) % +Utica Shale (1) +— — 2.68 * * +Weighted-average price 1.08 1.30 1.85 (17) % (30) % +NGLs (per Bbl) +Wattenberg Field 8.84 11.51 20.58 (23) % (44) % +Delaware Basin 11.32 15.12 27.06 (25) % (44) % +Utica Shale (1) +— — 24.29 * * +Weighted-average price 9.21 12.41 22.14 (26) % (44) % +Crude oil equivalent (per Boe) +Wattenberg Field 16.84 26.31 34.13 (36) % (23) % +Delaware Basin 16.94 26.95 36.25 (37) % (26) % +Utica Shale (1) +— — 30.98 * * +Weighted-average price 16.86 26.46 34.61 (36) % (24) % +____________ +* Percent change is not meaningful. +(1) In March 2018, we completed the disposition of our Utica Shale properties. +Crude oil, natural gas and NGLs revenues are recognized when we transfer control of crude oil, natural gas or NGLs production to the purchaser. We consider the transfer of control to occur when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record sales revenue based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. +Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related purchase agreement. We use the net-back method when control of the crude oil, natural gas or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering or processing services. In these situations, the purchaser pays us based on a percent of proceeds or a sales price fixed at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index on which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when control of the crude oil, natural gas or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transportation and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses. +Beginning in the second quarter of 2020, COVID-19 led to government restrictions on movement and economic activity, triggering a dramatic reduction in crude oil demand. This negatively impacted crude oil netback pricing realizations, which resulted in meaningful production curtailments during the second quarter of 2020. We expect our realized crude oil prices to be volatile through 2021 due to market uncertainties in crude oil demand as a result of COVID-19. +47 +As discussed above, we enter into agreements for the sale and transportation, gathering and processing of our production, the terms of which can result in variances in the per unit realized prices that we receive for our crude oil, natural gas and NGLs. Information related to the components and classifications in the consolidated statements of operations is shown below. For crude oil, the average NYMEX prices shown below are based on average daily prices throughout each month and, for natural gas, the average NYMEX pricing is based on first-of-the-month index prices, as in each case this is the method used to sell the majority of these commodities pursuant to terms of the relevant sales agreements. For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. The average realized price both before and after transportation, gathering and processing expenses shown in the table below represents our approximate composite per barrel price for NGLs. +2020 Average NYMEX Price Average Realized Price Before Transportation, Gathering and Processing Expenses Average Realization Percentage Before Transportation, Gathering and Processing Expenses Average Transportation, Gathering and Processing Expenses Average Realized Price After Transportation, Gathering and Processing Expenses Average Realization Percentage After Transportation, Gathering and Processing Expenses +Crude oil (per Bbl) $ 39.40 $ 34.44 87 % $ 2.34 $ 32.10 81 % +Natural gas (per MMBtu) 2.08 1.08 52 % 0.12 0.96 46 % +NGLs (per Bbl) 39.40 9.21 23 % — 9.21 23 % +Crude oil equivalent (per Boe) 28.52 16.86 59 % 1.10 15.76 55 % +2019 Average NYMEX Price Average Realized Price Before Transportation, Gathering and Processing Expenses Average Realization Percentage Before Transportation, Gathering and Processing Expenses Average Transportation, Gathering and Processing Expenses Average Realized Price After Transportation, Gathering and Processing Expenses Average Realization Percentage After Transportation, Gathering and Processing Expenses +Crude oil (per Bbl) $ 57.03 $ 53.26 93 % $ 1.24 $ 52.02 91 % +Natural gas (per MMBtu) 2.63 1.30 49 % 0.17 1.13 43 % +NGLs (per Bbl) 57.03 12.41 22 % 0.10 12.31 22 % +Crude oil equivalent (per Boe) 40.95 26.46 65 % 0.90 25.56 62 % +2018 Average NYMEX Price Average Realized Price Before Transportation, Gathering and Processing Expenses Average Realization Percentage Before Transportation, Gathering and Processing Expenses Average Transportation, Gathering and Processing Expenses Average Realized Price After Transportation, Gathering and Processing Expenses Average Realization Percentage After Transportation, Gathering and Processing Expenses +Crude oil (per Bbl) $ 64.77 $ 61.19 94 % $ 0.94 $ 60.25 93 % +Natural gas (per MMBtu) 3.09 1.85 60 % 0.22 1.63 53 % +NGLs (per Bbl) 64.77 22.14 34 % 0.21 21.93 34 % +Crude oil equivalent (per Boe) 47.87 34.61 72 % 0.93 33.68 70 % +Our average realization percentages for crude oil decreased in 2020 as compared to 2019, primarily due to higher quantity deducts, larger negative roll realizations and oil storage constraints in the second quarter of 2020, and changes in revenue contracts. +48 +Commodity Price Risk Management +We use commodity derivative instruments to manage fluctuations in crude oil and natural gas prices, including collars, fixed-price exchanges and basis protection exchanges on a portion of our estimated crude oil and natural gas production. For our commodity exchanges, we ultimately realize the fixed price value related to the exchanges. See Note 6 - Commodity Derivative Financial Instruments in Item 8. Financial Statements and Supplementary Data included elsewhere in this report for a summary of our derivative positions as of December 31, 2020. +Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments, and the change in fair value of unsettled commodity derivatives related to our crude oil and natural gas production. +Net settlements of commodity derivative instruments are based on the difference between the crude oil and natural gas index prices at the settlement date of our commodity derivative instruments compared to the respective strike prices contracted for the settlement months that were established at the time we entered into the commodity derivative transaction. The net change in fair value of unsettled commodity derivatives is comprised of the net increase or decrease in the beginning-of-period fair value of commodity derivative instruments that settled during the period and the net change in fair value of unsettled commodity derivatives during the period or from inception of any new contracts entered into during the applicable period. The net change in fair value of unsettled commodity derivatives during the period is primarily related to shifts in the crude oil and natural gas forward price curves and changes in certain differentials. +The following table presents net settlements and net change in fair value of unsettled derivatives included in commodity price risk management, net: +Year Ended December 31, +2020 2019 2018 +(in millions) +Commodity price risk management gain (loss), net: +Net settlements of commodity derivative instruments: +Crude oil collars and fixed price exchanges $ 294.4 $ (18.3) $ (139.7) +Crude oil basis protection exchanges — — 15.2 +Natural gas collars and fixed price exchanges (1.4) 8.8 (7.0) +Natural gas basis protection exchanges (13.7) (8.1) 21.0 +NGLs fixed price exchanges — — (5.0) +Total net settlements of commodity derivative instruments 279.3 (17.6) (115.5) +Change in fair value of unsettled commodity derivative instruments: +Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments (19.9) (81.1) 64.9 +Crude oil collars and fixed price exchanges (49.8) (62.1) 197.0 +Natural gas collars and fixed price exchanges (7.8) 0.1 1.4 +Natural gas basis protection exchanges (21.5) (2.1) (2.6) +Net change in fair value of unsettled commodity derivative instruments (99.0) (145.2) 260.7 +Total commodity price risk management gain (loss), net $ 180.3 $ (162.8) $ 145.2 +Lease Operating Expenses +Lease operating expenses ("LOE") increased by 13 percent to $161.3 million in 2020 compared to $142.2 million in 2019. The year-over-year increase in LOE is primarily attributable to the wells acquired from our SRC Acquisition in January 2020 and wells turned-in-line during 2020. Specifically, the increase was primarily due to $10.0 million in additional well services, an increase of $2.6 million in produced water disposal, and a $2.7 million increase in non-operated well expenses. The increases were partially offset by operational efficiencies achieved during 2020. LOE per Boe decreased 18 percent to $2.36 in 2020 from $2.88 in 2019, primarily due to a 38 percent increase in production volumes. +49 +Production Taxes +Production taxes are comprised mainly of severance tax and ad valorem tax, and are directly related to crude oil, natural gas and NGLs sales and are generally assessed as a percentage of net revenues. From time to time, there are adjustments to the statutory rates for these taxes based upon certain credits that are determined based upon activity levels and relative commodity prices. +Production taxes decreased 26 percent to $59.4 million in 2020 compared to $80.8 million in 2019, primarily due to the 12 percent decrease in crude oil, natural gas and NGLs sales for 2020 compared to 2019, reductions in effective severance tax rates in the Wattenberg Field and well classifications in the Delaware Basin. Production taxes per Boe decreased 47 percent to $0.87 in 2020 compared to $1.63 in 2019 due to lower realized prices for crude oil, natural gas and NGLs and a 38 percent increase in production volumes between periods. +Transportation, Gathering and Processing Expenses +Transportation, gathering and processing expenses ("TGP") increased 68 percent to $77.8 million in 2020 compared to $46.4 million in 2019, primarily due to higher production volumes between periods as a result of the SRC Acquisition, as well as amendments to existing and new crude oil sales contracts, some of which resulted in a change in recognition from a net-back to a gross presentation of TGP. TGP per Boe increased to $1.14 for 2020 compared to $0.94 for 2019. The increase of TGP per Boe between periods was primarily due to an increase in TGP as discussed above, partially offset by an increase in production volume delivered. +Exploration, Geologic and Geophysical Expense +Geological and geophysical costs decreased 66 percent to $1.4 million in 2020 compared to $4.1 million in 2019, primarily due to costs incurred related to geological and geophysical projects and seismic studies in the Delaware Basin in 2019. +Impairment of Properties and Equipment +The following table sets forth the major components of our impairment of properties and equipment: +Year Ended December 31, +2020 2019 2018 +(in millions) +Impairment of proved and unproved properties $ 881.2 $ 10.6 $ 458.4 +Impairment of infrastructure and other 1.2 27.9 — +Total impairment of properties and equipment $ 882.4 $ 38.5 $ 458.4 +Impairment Charges. The significant decline in crude oil prices in the first quarter of 2020 was considered a triggering event that required us to assess our crude oil and natural gas properties for possible impairment. As a result of our assessment, we recorded impairment charges of $881.1 million to our proved and unproved properties. Of these impairment charges, approximately $753.0 million was related to our Delaware Basin proved properties. These impairment charges represented the amount by which the carrying value of the crude oil and natural gas properties exceeded the estimated fair value. The estimated fair value was determined based on estimated future discounted net cash flows. In addition to our proved property impairment, we also recognized approximately $127.3 million of impairment charges in the first quarter of 2020 for our unproved properties in the Delaware Basin. These impairment charges were recognized based on a review of our current drilling plans, estimated future cash flows for probable well locations and expected future lease expirations, primarily in areas where we have no development plans. We did not recognize any significant impairment write-downs with respect to our proved and unproved properties during the remainder of 2020. If crude oil prices decline, or we change other estimates impacting future net cash flows (e.g. reserves, price differentials, future operating and/or development costs), our proved and unproved oil and gas properties could be subject to additional impairments in future periods. +50 +General and Administrative Expense +General and administrative expense decreased slightly to $161.1 million in 2020 compared to $161.8 million in 2019. Transaction costs relating to the SRC Acquisition increased from $7.8 million in 2019 to $19.9 million in 2020, and we also incurred $10.2 million of transition expenses relating to the acquisition in 2020. However, these increases were offset by (i) the non-recurrence of certain 2019 expenses including $6.0 million related to shareholder activism, $5.5 million in consultant fees related to business management and ERP implementation and a $3.4 million allowance for royalty owner payments and (ii) a $6.6 million decrease relating to ongoing corporate cost savings initiatives. +Depreciation, Depletion and Amortization Expense +Crude oil and natural gas properties. During 2020 and 2019, we invested $522.3 million and $787.7 million, respectively, exclusive of changes in accounts payable related to capital expenditures, in the development of our crude oil and natural gas properties. Depreciation, depletion and amortization expense ("DD&A") related to crude oil and natural gas properties is directly related to proved reserves and production volumes. DD&A expense related to crude oil and natural gas properties was $611.0 million and $638.5 million in 2020 and 2019, respectively. +The year-over-year change in DD&A expense for 2020 compared to 2019 related to crude oil and natural gas properties was primarily due to the following: +Year Ended December 31, +2020 +(in millions) +Increase in production $ 220.1 +Decrease in weighted-average depreciation, depletion and amortization rates (247.6) +Total decrease in DD&A expense related to crude oil and natural gas properties +$ (27.5) +The following table presents our per Boe DD&A expense rates for crude oil and natural gas properties: +Year Ended December 31, +Operating Region/Area 2020 2019 2018 +(per Boe) +Wattenberg Field $ 8.80 $ 11.77 $ 12.58 +Delaware Basin 9.68 16.76 17.70 +Total weighted-average 8.94 12.92 13.73 +The decrease in DD&A expense rate in the Delaware Basin was primarily due to the proved property impairment recognized in the first quarter of 2020, which lowered the carrying value of our depletion base. The effect of this impairment, however, was partially offset by 31.3 MMBoe in net downward revisions to our proved reserves in 2020, which were mainly due to lower SEC reserve pricing and a change in our drilling plan year over year due to the SRC Acquisition. +The decrease in DD&A expense rate in the Wattenberg Field was primarily due to the SRC Acquisition, which added 295 MMBoe in total proved reserves, offset by a $1.6 billion increase in our cost basis. +Non-crude oil and natural gas properties. Depreciation expense for non-crude oil and natural gas properties was $8.7 million for the year ended December 31, 2020, compared to $5.7 million for the year ended December 31, 2019. The increase in depreciation expense between periods was primarily due to our new ERP system which was implemented at the beginning of 2020. +51 +Interest Expense, net +Interest expense, net increased by $17.6 million to $88.7 million in 2020 compared to $71.1 million in 2019. The increase was primarily related to a $9.2 million increase in interest expense related to our revolving credit facility as a result of higher borrowings between periods, a $9.2 million increase related to the assumption of the SRC Senior Notes and a $2.5 million increase related to the issuance of an additional $150 million aggregate principal amount of the 2026 Senior Notes in September 2020. Higher credit facility borrowings in 2020 were primarily due to our payment and termination of SRC's revolving credit facility as well as the partial redemption of the SRC Senior Notes in the first quarter of 2020. The increases in interest expense were offset by a $6.3 million increase in capitalized interest in 2020 as compared to 2019. +Provision for Income Taxes +We recorded an income tax benefit of $7.9 million and $3.3 million for 2020 and 2019, respectively, resulting in effective tax rates of 1.1 percent and 5.5 percent on the respective pre-tax losses. The effective tax rate of 1.1 percent for 2020 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21 percent to the pre-tax loss due to the effect of a full valuation allowance against our deferred income tax assets at December 31, 2020 . The effective tax rate of 5.5 percent for 2019 differs from the statutory U.S. federal income tax rate of 21 percent due to state income taxes, non-deductible lobbying expenses, stock-based compensation and non-deductible officers’ compensation. +The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the +periods in which those temporary differences become deductible. At each reporting period, management considers the +scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future +taxable income in making this assessment. As previously noted, we recorded impairments totaling $882.4 million in 2020. These impairments resulted in three years of cumulative historical pre-tax losses and a net deferred tax asset position. The impairment losses were a key consideration that led us to continue to provide a valuation allowance against our net deferred tax assets as of December 31, 2020 since we cannot conclude that it is more likely than not that our net deferred tax asset will be fully realized in future periods. As a result, we recorded a $7.9 million benefit in 2020 to increase our deferred tax valuation allowance to $165.6 million and reduce the carrying value of our deferred tax assets to zero. +Net Income (Loss)/Adjusted Net Income (Loss) +The factors impacting net losses of $724.3 million and $56.7 million in 2020 and 2019, respectively, are discussed above. +Adjusted net loss, a non-U.S. GAAP financial measure, was $625.3 million and for the year ended December 31, 2020 and adjusted net income, a non-U.S. GAAP financial measure, was $53.3 million for the year ended December 31, 2019. With the exception of the tax-affected (when applicable) net change in fair value of unsettled derivatives, the same factors impacted adjusted net income (loss). See Reconciliation of Non-U.S. GAAP Financial Measures below for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures. +Financial Condition, Liquidity and Capital Resources +Our primary sources of liquidity are cash flows from operating activities, borrowings from our revolving credit facility, asset sales and proceeds raised in debt and equity capital market transactions. In 2020, our net cash flows from operating activities were $870.1 million. +Our primary source of cash flows from operating activities is the sale of crude oil, natural gas and NGLs. Fluctuations in our operating cash flows are principally driven by commodity prices and changes in our production volumes. Commodity prices have historically been volatile, and we manage a portion of this volatility through our use of commodity derivative instruments. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the instrument. Our revolving credit facility imposes limits on the amount of our production we can hedge, and we may choose not to hedge the maximum amounts permitted. Therefore, we may still have fluctuations in our cash flows from operating activities due to the remaining non-hedged portion of our future production. +We may use our available liquidity for operating activities, capital investments, working capital requirements, acquisitions and for general corporate purposes. We maintain a significant capital investment program to execute our +52 +development plans, which requires capital expenditures to be made in periods prior to initial production from newly developed wells. +From time to time, these activities may result in a working capital deficit; however, we do not believe that our working capital deficit as of December 31, 2020 is an indication of a lack of liquidity. We had working capital deficits of $471.6 million and $57.2 million at December 31, 2020 and 2019, respectively. The increase was primarily attributable to our 2021 Convertible Notes maturing in September 2021, which resulted in the notes being classified in current liabilities, an increase in the fair value liability of our commodity derivatives and additional current liabilities resulting from the SRC Acquisition. We intend to continue to manage our liquidity position by a variety of means, including through the generation of cash flows from operations, investment in projects with favorable rates of return, protection of cash flows on a portion of our anticipated sales through the use of an active commodity derivative hedging program, utilization of the borrowing capacity under our revolving credit facility and, if warranted, capital markets transactions from time to time. +Our cash and cash equivalents were $2.6 million at December 31, 2020 and availability under our revolving credit facility was $1.4 billion, providing for total liquidity of $1.4 billion as of December 31, 2020. In October 2020, as part of our semi-annual redetermination, the borrowing base of our credit facility was reduced from $1.7 billion to $1.6 billion, with a corresponding reduction of our elected commitment level to $1.6 billion. The borrowing base is primarily based on the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. Based on our current production forecast for 2021 and assumed average NYMEX prices of $45.00 per Bbl of crude oil and $2.50 per Mcf of natural gas and an assumed average composite price of $12.00 per Bbl for NGLs, we expect 2021 cash flows from operations to exceed our capital investments in crude oil and natural gas properties. +As a result of merging with SRC, we assumed the SRC Senior Notes and paid off and terminated SRC's revolving credit facility. On January 17, 2020, we commenced an offer to repurchase the outstanding SRC Senior Notes at 101 percent of the principal amount. Upon expiration of the repurchase offer on February 18, 2020, holders of $447.7 million of the outstanding SRC Senior Notes accepted our redemption offer for a total redemption price of approximately $452.2 million, plus accrued and unpaid interest of $6.2 million. We funded the repurchase with proceeds from our revolving credit facility. An aggregate principal amount of approximately $102.3 million of the SRC Senior Notes remains outstanding. +In September 2020, we issued an additional $150.0 million principal amount of our 2026 Senior Notes. The net proceeds from the offering were used to repay a portion of the amount outstanding under our revolving credit facility. +In April 2019, our board of directors approved the Stock Repurchase Program. Effective with the closing of the SRC Acquisition, our board of directors approved an increase and extension to the Stock Repurchase Program from $200 million to $525 million. Pursuant to the Stock Repurchase Program, we repurchased 1.3 million shares and 4.7 million shares of outstanding common stock at a cost of $23.8 million and $154.4 million during the years ended December 31, 2020 and 2019, respectively. We suspended the program in March 2020; however, we reinstated the program in late February 2021, in light of a reduction in our aggregate indebtedness to below $1.5 billion. Repurchases may extend into 2023 based on current market conditions, although the board of directors could elect to suspend or terminate the program at any time, including if certain share price parameters are not achieved. Approximately $346.8 million remained available for repurchases when we reinstated the program. +In addition, we may from time to time seek to pay down, retire or repurchase our outstanding debt using cash or through exchanges of other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on available funds, prevailing market conditions, our liquidity requirements, contractual restrictions in our revolving credit agreement and other factors. +Based on our expected cash flows from operations, our cash and cash equivalents and availability under our revolving credit facility, we believe that we will have sufficient capital available to repay our 2021 Convertible Notes maturing in September 2021 and to fund our planned activities through the 12-month period following the filing of this report. +Our revolving credit facility is available for working capital requirements, capital investments, acquisitions, to support letters of credit and for general corporate purposes. The borrowing base is primarily based on the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. +53 +The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.0:1.0 and (b) not exceed a maximum leverage ratio of 4.0:1.0. For purposes of the current ratio covenant, the revolving credit facility's definition of total current assets, in addition to current assets as presented under U.S. GAAP, includes, among other things, unused commitments under the revolving credit facility. Additionally, the current ratio covenant calculation allows us to exclude the current portion of our long-term debt and other short-term loans from the U.S. GAAP total current liabilities amount. Accordingly, the existence of a working capital deficit under U.S. GAAP is not necessarily indicative of a violation of the current ratio covenant. At December 31, 2020, we were in compliance with all covenants in the revolving credit facility with a current ratio of 3.5:1.0 and a leverage ratio of 1.7:1.0. We expect to remain in compliance throughout the 12-month period following the filing of this report. +Cash Flows +Operating Activities. Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes, net settlements from our commodity derivative positions, operating costs and general and administrative expenses. Cash flows from operating activities increased by $11.9 million to $870.1 million in 2020 as compared to $858.2 million in 2019. The increase between periods was primarily due to an increase in commodity derivative settlements and $82.0 million received in June 2020 from the divestiture of certain midstream assets in 2019. The increases were partially offset by a decrease in crude oil, natural gas and NGLs sales and a $84.3 million net decrease in working capital. +Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased by $96.2 million in 2020 to $921.6 million from $825.4 million in 2019. The increase was primarily due to the factors mentioned above for changes in cash flows provided by operating activities, without regard to timing of cash payments and receipts of assets and liabilities. Adjusted free cash flow, a non-U.S GAAP financial measure, increased by $361.6 million in 2020 to $399.3 million from $37.7 million in 2019. The increase was primarily due to a decrease in capital investments in crude oil and natural gas properties. +See Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures. +Investing Activities. As crude oil and natural gas production from a well declines rapidly in the first few years of production, we need to continue to commit significant amounts of capital in order to maintain and grow our production and replace our crude oil and natural reserves. If capital is not available or is constrained in the future, we will be limited to our cash flows from operations and liquidity under our revolving credit facility as the sources for funding our capital investments. +Cash flows from investing activities primarily consist of the acquisition, exploration and development of crude oil and natural gas properties, net of dispositions of crude oil and natural gas properties. Net cash used in investing activities of $687.2 million during 2020 was primarily related to our drilling and completion activities of $551.0 million and $139.8 million related to the closing of the SRC Acquisition. +Net cash used in investing activities of $677.8 million during 2019 was primarily related to our drilling and completion activities of $855.9 million. Partially offsetting these investing activities was $202.1 million of net cash received from divestitures of certain midstream assets and Delaware Basin crude oil and natural gas properties. +Financing Activities. Net cash used in financing activities in 2020 of $181.3 million was primarily due to the redemption of a portion of the 2025 Senior Notes totaling $452.2 million, the repurchase and retirement of shares of our common stock totaling $23.8 million pursuant to the Stock Repurchase Program and $9.3 million related to purchases of our stock for employee stock-based compensation tax withholding obligations. These financing cash outflows were financed by our net borrowings from our credit facility of $164 million, proceeds from the issuance of 2026 Senior Notes of $148.5 million and cash flows from operating activities. +Net cash used in financing activities in 2019 of $188.9 million was primarily due to the repurchase and retirement of shares of our common stock totaling $154.4 million pursuant to the Stock Repurchase Program, net borrowings from our credit facility of $28.5 million and $4.0 million related to purchases of our stock for employee stock-based compensation tax withholding obligations. +54 +Subsidiary Guarantor +PDC Permian, Inc., a Delaware corporation (the “Guarantor”), our wholly-owned subsidiary, guarantees our obligations under our 2024 Senior Notes, 2025 Senior Notes and 2026 Senior Notes (collectively, the "Senior Notes") and our 2021 Convertible Notes. The Guarantor holds our assets located in the Delaware Basin. The Senior Notes and 2021 Convertible Notes are fully and unconditionally guaranteed on a joint and several basis by the Guarantor. The guarantees are subject to release in limited circumstances only upon the occurrence of certain customary conditions. +The indentures governing the Senior Notes contain customary restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (a) incur additional debt including under our revolving credit facility, (b) make certain investments or pay dividends or distributions on our capital stock or purchase, redeem or retire capital stock, (c) sell assets, including capital stock of our restricted subsidiaries, (d) restrict the payment of dividends or other payments by restricted subsidiaries to us, (e) create liens that secure debt, (f) enter into transactions with affiliates and (g) merge or consolidate with another company. +The following summarized subsidiary guarantor financial information has been prepared on the same basis of accounting as our condensed consolidated financial statements. Investments in subsidiaries are accounted for under the equity method. +As of/Year Ended December 31, +2020 2019 +Issuer Guarantor Issuer Guarantor +(in millions) +Assets +Current assets $ 271.4 $ (57.8) $ 175.8 $ 126.0 +Intercompany accounts receivable, guarantor subsidiary 107.3 — 348.8 — +Intercompany accounts receivable, non-guarantor subsidiary — — 6.3 — +Investment in guarantor subsidiary 1,767.2 — 1,766.8 — +Properties and equipment, net 3,982.1 877.1 2,328.3 1,766.9 +Other non-current assets 56.6 4.3 41.8 6.8 +Liabilities +Current liabilities $ 751.3 $ 28.5 $ 306.6 $ 52.4 +Intercompany accounts payable — 94.2 — 348.8 +Long-term debt 1,409.5 — 1,177.2 — +Other non-current liabilities 254.9 178.1 361.1 211.6 +Statement of Operations +Crude oil, natural gas and NGLs sales $ 968.8 $ 183.7 $ 999.3 $ 308.0 +Commodity price risk management gain (loss), net 180.3 — (162.8) — +Total revenues 1,151.5 182.5 838.1 308.7 +Production costs 227.0 71.6 180.1 89.2 +Gross profit 741.8 112.1 819.2 218.8 +Impairment of properties and equipment 2.0 880.4 0.3 38.2 +Net income (loss) (49.2) (670.0) (24.6) (30.0) +55 +Contractual Obligations and Contingent Commitments +The following table presents our contractual obligations and contingent commitments as of December 31, 2020: +Payments due by period +Less than 1-3 3-5 +Contractual Obligations and Contingent Commitments Total 1 year years years Thereafter +(in millions) +Long-term liabilities reflected on the consolidated balance sheet +Long-term debt (1) +$ 1,620.3 $ 200.0 $ 168.0 $ 502.3 $ 750.0 +Commodity derivative contracts (2) +134.6 98.2 36.4 — — +Production tax liability 190.1 124.5 65.6 — — +Deferred oil gathering credit 18.1 2.2 4.5 4.5 6.9 +Deferred midstream gathering credits 168.7 9.4 18.9 18.8 121.6 +Asset retirement obligations 166.6 33.9 37.5 37.5 57.7 +Operating and finance leases 20.1 8.6 8.7 2.1 0.7 +Other liabilities (3) +1.2 0.1 0.2 0.2 0.7 +2,319.7 476.9 339.8 565.4 937.6 +Commitments, contingencies and other arrangements (4) +Interest on long-term debt (5) +420.3 88.5 165.2 123.5 43.1 +Firm transportation and processing agreements (6) +516.8 135.4 209.6 124.3 47.5 +937.1 223.9 374.8 247.8 90.6 +Total $ 3,256.8 $ 700.8 $ 714.6 $ 813.2 $ 1,028.2 +____________ +(1) Amount presented does not agree with the consolidated balance sheets as it excludes $6.8 million of unamortized net debt discounts and premium and $10.9 million of unamortized debt issuance costs. +(2) Represents our gross liability related to the fair value of commodity derivative positions. +(3) Includes deferred compensation to former executive officers and deferred payments related to firm transportation agreements. +(4) Excludes termination benefits related to employment agreements with our executive officers, due to the uncertainty surrounding the ultimate settlement of amounts and timing of these obligations. +(5) Amounts presented include $258.8 million to the holders of our 2026 Senior Notes, $98.0 million to the holders of our 2024 Senior Notes, $32.0 million to holders of our 2025 Senior Notes and $2.2 million payable to the holders of our 2021 Convertible Notes. Amounts also include $29.3 million commitment fees due which, as of December 31, 2020, includes a commitment equal to 0.375 percent per annum of the unused portion of the borrowing base of the Company's revolving credit facility. At December 31, 2020, we had variable-rate debt outstanding under our credit facility of $168.0 million. +(6) Represents our gross commitment which includes volumes produced by us and purchased from third parties and produced by other third-party working, royalty and overriding royalty interest owners whose volumes we market on their behalf. +From time to time, we are a party to various legal proceedings in the ordinary course of business. We are not currently a party to any litigation that we believe would have a materially adverse effect on our business, financial condition, results of operations or liquidity. Information regarding our legal proceedings can be found in Note 12 - Commitments and Contingencies - Litigation and Legal Items in Item 8. Financial Statements and Supplementary Data included elsewhere in this report. +Off-Balance Sheet Arrangements +At December 31, 2020, we had no off-balance sheet arrangements, as defined under SEC rules, which have or are reasonably likely to have a material current or future effect on our financial condition, revenues or expenses, results of operations, liquidity, capital investments or capital resources. +Critical Accounting Policies and Estimates +The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with U.S. GAAP. The preparation of these statements requires us to make certain assumptions, judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities and commitments as of the date of our financial statements. We analyze and base our estimates on historical experience and various other assumptions that we believe to be +56 +reasonable under the circumstances. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. +Our significant accounting policies are described in Note 2 - Summary of Significant Accounting Policies in Item 8. Financial Statements and Supplementary Data included elsewhere in this report. We have identified the following policies as critical to the understanding of our financial position and results of operations and which require the application of significant judgment by management. +Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Under this method, costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depleted by the unit-of-production method based on estimated proved developed producing reserves. In determining the estimates of reserve and economic evaluations, management utilizes independent petroleum engineers. +Further, under the successful efforts method, exploration costs, including geological and geophysical expenses, seismic costs on unproved leaseholds and delay rentals are expensed as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. This accounting method may yield significantly different results than the full cost method of accounting. Judgment is required to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of costs incurred. +The successful efforts method inherently relies on the estimation of proved crude oil, natural gas and NGL reserves. Reserve quantities and the related estimates of future net cash flows are used as inputs in our calculation of depletion, evaluation of proved properties for impairment, assessment of expected realizability of our deferred income tax assets and calculation of the standardized measure of discounted future net cash flows. The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. Significant inputs and engineering assumptions used in developing the estimates of proved crude oil and natural gas reserves include reserves volumes, future operating and development costs and historical commodity prices. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. We cannot predict the amounts or timing of such future revisions. +Our reserves estimate has been prepared by our internal and external engineers. For more information regarding reserve estimation, including historical reserve revisions, see Items 1 and 2. Business and Properties - Preparation of Reserves Estimates and Supplemental Oil and Gas Information to the consolidated financial statements included in Item 8. Financial Statements and Supplementary Data included elsewhere in this report. +Annually, or upon a triggering event, we assess the valuation of our proved crude oil and natural gas properties for possible impairment by comparing the carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production and prices at which we estimate the commodity will be sold. If carrying values exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a discounted future cash flows analysis. The impairment recorded is the amount by which the carrying values exceed the fair value. In the impairment assessment we estimate the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices, and a market based weighted average cost of capital rate. +Future commodity prices are estimated by using a combination of assumptions management uses in its budgeting and forecasting process, historical and future prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. In the event that there are downward revisions in estimates to our estimated reserves quantities, commodity prices significantly decline or rising operating costs, management would test the recoverability of the carrying value of our oil and gas properties and, if necessary, record an impairment charge. Fair value is calculated by discounting the future cash flows. The discount factor used is the market based weighted average cost of capital which is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying crude oil and natural gas. +57 +Although our cash flow estimates are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by their nature, highly uncertain and may vary significantly from actual results. +Unproved properties consist of costs to acquire undeveloped leases as well as costs to acquire unproved reserves. Unproved properties with individually significant acquisition costs are periodically assessed for impairment based on remaining average lease terms, drilling results, reservoir performance, seismic interpretation or changes in future plans to develop acreage. Changes in our assumptions of the estimated nonproductive portion of our undeveloped leases could result in additional impairment expense. +Impairment charges would have no effect on cash flows but would result in a decrease in net income for the period in which the impairment charge is recorded. +Asset Retirement Obligations. The majority of our asset retirement obligations ("ARO") relate to the plugging and abandonment of crude oil and gas wells. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. The recognition of an asset retirement obligation requires management to make assumptions that include estimated plugging and abandonment costs, timing of settlements, inflation rates and discount rate. Over time, the liability is accreted for the change in the present value (accretion expense). The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. When the judgments used to estimate the initial fair value of the asset retirement obligation change, an adjustment is recorded to both the obligation and the carrying amount of the related long-lived asset. +Valuation of Commodity Derivative Financial Instruments. Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas we enter into commodity derivative contracts to protect against price declines in future periods. We have not elected to designate any of our derivative instruments as cash flow hedges; therefore, these instruments do not qualify for hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the consolidated statements of operations. Under applicable accounting standards, the fair value of each derivative instrument is recorded as either an asset or liability on the consolidated balance sheet. We measure the fair value of our commodity derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates, volatility factors and nonperformance risk. +Our financial condition, results of operations and liquidity can be significantly impacted by changes in the market value of our commodity derivative instruments due to volatility of commodity prices, including basis differentials. +Deferred Income Tax Asset Valuation Allowance. Deferred income tax assets are recognized for deductible temporary differences, net operating loss carryforwards and credit carryforwards if it is more likely than not that the tax benefits will be realized. We must periodically evaluate whether it is more likely than not we will realize these deferred income tax assets and establish a valuation allowance for those that do not meet the more likely than not threshold. When assessing the need for a valuation allowance, we primarily consider future reversals of existing taxable temporary differences. To a lesser extent, we may also consider future taxable income exclusive of reversing temporary differences and carryfowards, and tax planning strategies that would, if necessary, be implemented to accelerate taxable amounts to utilize expiring carryforwards. The ultimate amount of deferred tax assets realized could be materially different from those recorded, as influenced by future operational performance, potential changes in jurisdictional income tax laws and other circumstances surrounding the actual realization of related tax assets. +Valuation of Business Combinations. As part of our business strategy, we regularly pursue the acquisition of oil and natural gas properties. The purchase price in an acquisition is allocated to the assets acquired and liabilities assumed based on their relative fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. As the allocation of the purchase price is subject to significant estimates, the accuracy of this assessment is inherently uncertain. +58 +In estimating the fair values of assets acquired and liabilities assumed the most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. To estimate the fair values of these properties as part of acquisition accounting, we estimate the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices, and a market based weighted average cost of capital rate. Additionally, for acquisitions with significant unproved properties, we may also review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value as such sales represent the amount at which a willing buyer and seller would enter into an exchange for such properties to determine an estimation of fair value. +If applicable, we record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. +Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. A higher fair value assigned to a property results in a higher depletion expense, which results in lower net earnings. This increases the likelihood of impairment if future commodity prices or reserves quantities are lower than those originally used to determine fair value or if future operating expenses or development costs are higher than those originally used to determine fair value. +Acreage Exchanges . From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and providing us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges of non-producing interests and unproved mineral leases in accordance with the guidance prescribed by Accounting Standards Codification 845, Nonmonetary Transactions . For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized in earnings, in accordance with Accounting Standards Codification 820, Fair Value Measurement . We estimate the fair value of proved crude oil and natural gas properties utilizing the same valuation techniques, significant inputs and assumptions as previously described. +Recent Accounting Pronouncements +See Note 2 - Summary of Significant Accounting Policies - Recently Adopted Accounting Standards in Item 8. Financial Statements and Supplementary Data included elsewhere in this report. +Reconciliation of Non-U.S. GAAP Financial Measures +We use "adjusted cash flows from operations," "adjusted free cash flow (deficit)," "adjusted net income (loss)" and "adjusted EBITDAX," non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and, in some cases, in providing public guidance on possible future results. In addition, we believe these are measures of our fundamental business and can be useful to us, investors, lenders and other parties in the evaluation of our performance relative to our peers and in assessing acquisition opportunities and capital expenditure projects. These supplemental measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss) or cash flows from operations, investing or financing activities and should not be viewed as liquidity measures or indicators of cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. In the future, we may disclose different non-U.S. GAAP financial measures in order to help us and our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure. +Adjusted cash flows from operations and adjusted free cash flow (deficit). We believe adjusted cash flows from operations can provide additional transparency into the drivers of trends in our operating cash flows, such as production, realized sales prices and operating costs, as it disregards the timing of settlement of operating assets and liabilities. We believe adjusted free cash flow (deficit) provides additional information that may be useful in an investor analysis of our ability to generate cash from operating activities from our existing oil and gas asset base to fund exploration and development activities +59 +and to return capital to stockholders in the period in which the related transactions occurred. We exclude from this measure cash receipts and expenditures related to acquisitions and divestitures of oil and gas properties and capital expenditures for other properties and equipment, which are not reflective of the cash generated or used by ongoing activities on our existing producing properties and, in the case of acquisitions and divestitures, may be evaluated separately in terms of their impact on our performance and liquidity. Adjusted free cash flow is a supplemental measure of liquidity and should not be viewed as a substitute for cash flows from operations because it excludes certain required cash expenditures. For example, we may have mandatory debt service requirements or other non-discretionary expenditures which are not deducted from the adjusted free cash flow measure. +We are unable to present a reconciliation of forward-looking adjusted cash flow because components of the calculation, including fluctuations in working capital accounts, are inherently unpredictable. Moreover, estimating the most directly comparable GAAP measure with the required precision necessary to provide a meaningful reconciliation is extremely difficult and could not be accomplished without unreasonable effort. We believe that forward-looking estimates of adjusted cash flow are important to investors because they assist in the analysis of our ability to generate cash from our operations. +Adjusted net income (loss). We believe that adjusted net income (loss) provides additional transparency into operating trends, such as production, realized sales prices, operating costs and net settlements on commodity derivative contracts, because it disregards changes in our net income (loss) from mark-to-market adjustments resulting from net changes in the fair value of our unsettled commodity derivative contracts, and these changes are not directly reflective of our operating performance. +Adjusted EBITDAX. We believe that adjusted EBITDAX provides additional transparency into operating trends because it reflects the financial performance of our assets without regard to financing methods, capital structure, accounting methods or historical cost basis. In addition, because adjusted EBITDAX excludes certain non-cash expenses, we believe it is not a measure of income, but rather a measure of our liquidity and ability to generate sufficient cash for exploration, development, and acquisitions and to service our debt obligations. +Beginning in the third quarter of 2019, we included a reconciling item for gains or losses on the sale of properties and equipment when calculating adjusted EBITDAX, thereby no longer including such gains or losses in our reported adjusted EBITDAX. We believe this methodology for calculating adjusted EBITDAX will enable greater comparability to our peers, as well as consistent treatment of adjustments for impairment and gains or losses on the sale of properties and equipment. For comparability, all prior periods presented have been conformed to the aforementioned methodology. +PV-10. We define PV-10 as the estimated present value of the future net cash flows from our proved reserves before income taxes, discounted using a 10 percent discount rate. We believe that PV-10 provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. We believe that PV-10 is relevant and useful for evaluating the relative monetary significance of our reserves. Professional analysts, investors and other users of our financial statements may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies' reserves. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable in evaluating us and our reserves. PV-10 is not intended to represent the current market value of our estimated reserves. +60 +The following table presents a reconciliation of each of our non-U.S. GAAP financial measures to its most comparable U.S. GAAP measure: +Year Ended December 31, +2020 2019 2018 +(thousands) +Cash flows from operations to adjusted cash flows from operations and adjusted free cash flow (deficit): +Net cash from operating activities $ 870.1 $ 858.2 $ 889.3 +Changes in assets and liabilities 51.5 (32.8) (80.9) +Adjusted cash flows from operations 921.6 825.4 808.4 +Capital expenditures for development of crude oil and natural gas properties (551.0) (855.9) (946.4) +Change in accounts payable related to capital expenditures for oil and gas development activities 28.7 68.2 (36.3) +Adjusted free cash flow (deficit) $ 399.3 $ 37.7 $ (174.3) +Net income (loss) to adjusted net income (loss): +Net income (loss) $ (724.3) $ (56.7) $ 2.0 +Loss (gain) on commodity derivative instruments (180.3) 162.8 (145.2) +Net settlements on commodity derivative instruments 279.3 (17.6) (115.5) +Tax effect of above adjustments (1) +— (35.2) 62.4 +Adjusted net income (loss) $ (625.3) $ 53.3 $ (196.3) +Net income (loss) to adjusted EBITDAX: +Net income (loss) $ (724.3) $ (56.7) $ 2.0 +Loss (gain) on commodity derivative instruments (180.3) 162.8 (145.2) +Net settlements on commodity derivative instruments 279.3 (17.6) (115.5) +Non-cash stock-based compensation 22.2 23.8 21.8 +Interest expense, net 88.7 71.1 70.3 +Income tax expense (benefit) (7.9) (3.3) 5.4 +Impairment of properties and equipment 882.4 38.5 458.4 +Exploration, geologic and geophysical expense 1.4 4.1 6.2 +Depreciation, depletion and amortization 619.7 644.2 559.8 +Accretion of asset retirement obligations 10.1 6.1 5.1 +Loss (gain) on sale of properties and equipment (0.7) 9.7 0.4 +Adjusted EBITDAX $ 990.6 $ 882.7 $ 868.7 +Cash from operating activities to adjusted EBITDAX: +Net cash from operating activities $ 870.1 $ 858.2 $ 889.3 +Interest expense, net 88.7 71.1 70.3 +Amortization and write-off of debt discount, premium and issuance costs (16.8) (13.6) (12.8) +Exploration, geologic and geophysical expense 1.4 4.1 6.2 +Other (4.3) (4.3) (3.4) +Changes in assets and liabilities 51.5 (32.8) (80.9) +Adjusted EBITDAX $ 990.6 $ 882.7 $ 868.7 +PV-10: +Standardized measure of discounted future net cash flows $ 3,282.2 $ 3,310.3 $ 4,447.7 +Present value of estimated future income tax discounted at 10% 172.4 526.7 873.6 +PV-10 $ 3,454.6 $ 3,837.0 $ 5,321.3 +_____________ +(1) Due to the full valuation allowance recorded against our net deferred tax assets, there is no tax effect for the year ended December 31, 2020. +61 +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Market-Sensitive Instruments and Risk Management +We are exposed to market risks associated with interest rate risks, commodity price risk and credit risk. We have established risk management processes to monitor and manage these market risks. +Interest Rate Risk +Changes in interest rates affect the amount of interest we earn on our interest bearing cash, cash equivalents and restricted cash accounts and the interest we pay on borrowings under our revolving credit facility. Our 2021 Convertible Notes, 2024 Senior Notes, 2025 Senior Notes and 2026 Senior Notes have fixed rates, and therefore, near-term changes in interest rates do not expose us to risk of earnings or cash flow loss; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt. +As of December 31, 2020, we had $168.0 million outstanding on our revolving credit facility with a weighted average interest rate of 2.4%. If market interest rates would have increased or decreased by one percent, our interest expense for the year ended December 31, 2020 would have changed by approximately $0.4 million. +Commodity Price Risk +We are exposed to the potential risk of loss from adverse changes in the market price of crude oil, natural gas, natural gas basis and NGLs. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control. Pursuant to established policies and procedures, we manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. These instruments help us predict with greater certainty the effective crude oil and natural gas prices we will receive for our hedged production. We believe that our commodity derivative policies and procedures are effective in achieving our risk management objectives. +Based on a sensitivity analysis as of December 31, 2020, we estimate that a 10 percent increase in natural gas, crude oil prices and the propane portion of NGLs prices, inclusive of basis, over the entire period for which we have commodity derivatives in place would have resulted in a decrease in the fair value of our net derivative assets of $83.2 million, whereas a 10 percent decrease in prices would have resulted in an increase in fair value of our net derivatives assets of $80.9 million. The potential decrease in the fair value of our net derivative assets would be recorded in statements of operations as a loss. We are currently unable to estimate the effects on the earnings of future periods resulting from changes in the market value of our commodity derivative contracts. +Credit Risk +Credit risk represents the loss that we would incur if a counterparty fails to perform its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure. When exposed to significant credit risk, we analyze the counterparty's financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We monitor the creditworthiness of significant counterparties through our credit committee, which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. While we believe that our credit risk analysis and monitoring procedures are reasonable, no amount of analysis can assure performance by our counterparties. +We primarily use financial institutions which are lenders in our revolving credit facility as counterparties for our derivative financial instruments. Disruption in the credit markets, changes in commodity prices and other factors may have a significant adverse impact on a number of financial institutions. To date, we have had no material counterparty default losses from our commodity derivative financial instruments. +Our crude oil, natural gas and NGLs sales are concentrated with a few predominately large customers. This concentrates our credit risk exposure with a small number of large customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. +62 +Disclosure of Limitations +Because the information above included only those exposures that existed at December 31, 2020, it does not consider those exposures or positions which could arise after that date. As a result, our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, our commodity price risk management strategies at the time and interest rates and commodity prices at the time. +63 +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Index to Consolidated Financial Statements, Financial Statement Schedule and Supplemental Information +Financial Statements: +Report of Independent Registered Public Accounting Firm +65 +Consolidated Balance Sheets +68 +Consolidated Statements of Operations +69 +Consolidated Statements of Cash Flows +70 +Consolidated Statements of Stockholders' Equity +71 +Notes to Consolidated Financial Statements +72 +Supplemental Information - Unaudited: +Crude Oil and Natural Gas Information +105 +Quarterly Financial Information +113 +Financial Statement Schedule: +Schedule II - Valuation and Qualifying Accounts - Years Ended December 31, 2020, 2019 and 2018 +114 +64 +Report of Independent Registered Public Accounting Firm +To the Board of Directors and Stockholders of PDC Energy, Inc. +Opinions on the Financial Statements and Internal Control over Financial Reporting +We have audited the accompanying consolidated balance sheets of PDC Energy, Inc. and its subsidiaries (the “Company”) as of December 31, 2020 and 2019, and the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2020, including the related notes and financial statement schedule listed in the accompanying index (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO. +Change in Accounting Principle +As discussed in Note 10 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019. +Basis for Opinions +The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. +Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. +Definition and Limitations of Internal Control over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and +65 +procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Critical Audit Matters +The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. +The Impact of Proved Oil and Natural Gas Reserves on Proved Crude Oil and Natural Gas Properties, Net +As described in Notes 2 and 7 to the consolidated financial statements, the Company’s proved crude oil and natural gas properties balance was $7,524 million as of December 31, 2020, and depreciation, depletion, and amortization (DD&A) expense for the period ended December 31, 2020 was $619.7 million. As disclosed by management, the process of estimating and evaluating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. Significant inputs and engineering assumptions used in developing the estimates of proved crude oil and natural gas reserves include reserves volumes, future operating and development costs and historical commodity prices. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. The Company accounts for crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depleted by the unit-of-production method based on estimated proved developed producing reserves. Reserve estimates are prepared by internal and external engineers (collectively “specialists”). +The principal considerations for our determination that performing procedures relating to the impact of proved crude oil and natural gas reserves on proved crude oil and gas properties, net is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the estimates of proved crude oil and natural gas reserves, which in turn led to (ii) a high degree of auditor judgement, subjectivity, and effort in performing procedures and evaluating the audit evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved crude oil and natural gas reserves related to reserves volumes and the assumptions applied to the data related to future operating and development costs, and commodity prices. +Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved crude oil and natural gas reserves. The work of specialists was used in performing the procedures to evaluate the reasonableness of the reserve volumes. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists and an evaluation of the specialists’ results. These procedures also included, among others, testing the completeness and accuracy of data related to reserves volumes, future operating and development costs, and commodity prices. Additionally, these procedures included evaluating whether the assumptions applied to the aforementioned data were reasonable considering the past performance of the Company. +66 +Valuation of Proved Crude Oil and Natural Gas Properties +As described in Notes 2, 3, and 7 to the consolidated financial statements, as of December 31, 2020, the Company’s proved crude oil and natural gas properties were approximately $7,524 million, which includes impairment charges of $753.0 million to write-down proved properties to their estimated fair value and $1,614 million related to a merger completed during the year. Annually, or upon a triggering event, the Company assesses the valuation of its proved crude oil and natural gas properties for possible impairment by comparing the carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production and prices at which the Company estimates the commodity will be sold. If carrying values exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a discounted future cash flows analysis. The impairment recorded is the amount by which the carrying values exceed the fair value. In the impairment assessment and as part of acquisition accounting, management estimates the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices, and a market based weighted average cost of capital rate. +The principal considerations for our determination that performing procedures relating to the valuation of proved crude oil and natural gas properties is a critical audit matter are (i) the significant judgment by management when developing the undiscounted future cash flow analysis for the impairment assessment and discounted future cash flow analysis for the impairment assessment and acquisition accounting, (ii) the high degree of auditor judgment, effort, and subjectivity in performing procedures and evaluating management’s assumptions related to estimates of reserves volumes, future operating and development costs, future commodity prices and the weighted average cost of capital rate, and (iii) the audit effort involved the use of professionals with specialized skill and knowledge. +Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the impairment assessment and development of future cash flows for impairment and the valuation of acquired proved crude oil and natural gas properties. These procedures also included, among others, (i) testing management’s process for developing the fair value estimate; (ii) evaluating the appropriateness of the undiscounted and discounted cash flow models, (iii) testing the completeness and accuracy of the underlying data used in the models; and (iv) evaluating the significant assumptions used by management related to reserves volumes, future operating and development costs, future commodity prices, and a market based weighted average cost of capital rate. Evaluating the reasonableness of management’s assumptions related to: (i) future operating and development costs involved consideration of the past and anticipated performance of the Company; and (ii) future commodity prices involved consideration of observable market data. The work of specialists was used in performing the procedures to evaluate the reasonableness of the reserve volumes as stated in the Critical Audit Matter titled “Impact of Proved Oil and Natural Gas Reserves on Proved Crude Oil and Natural Gas Properties, Net”. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists and an evaluation of the specialists’ findings. Professionals with specialized skill and knowledge were used to assist in evaluating the appropriateness of the models and the reasonableness of the market based weighted average cost of capital rate. +/s/PricewaterhouseCoopers LLP +Denver, Colorado +February 24, 2021 +We have served as the Company’s auditor since 2007. +67 +PDC ENERGY, INC. +Consolidated Balance Sheets +(in thousands, except share and per share data) +December 31, +2020 2019 +Assets +Current assets: +Cash and cash equivalents $ 2,623 $ 963 +Accounts receivable, net 244,251 266,354 +Fair value of derivatives 48,869 28,078 +Prepaid expenses and other current assets 12,505 8,635 +Total current assets 308,248 304,030 +Properties and equipment, net 4,859,199 4,095,202 +Fair value of derivatives 9,565 3,746 +Other assets 60,961 45,702 +Total Assets $ 5,237,973 $ 4,448,680 +Liabilities and Stockholders' Equity +Liabilities +Current liabilities: +Accounts payable $ 90,635 $ 98,934 +Production tax liability 124,475 76,236 +Fair value of derivatives 98,152 2,921 +Funds held for distribution 177,132 98,393 +Accrued interest payable 14,734 14,284 +Other accrued expenses 81,715 70,462 +Current portion of long-term debt 193,014 — +Total current liabilities 779,857 361,230 +Long-term debt 1,409,548 1,177,226 +Deferred income taxes — 195,841 +Asset retirement obligations 132,637 95,051 +Fair value of derivatives 36,359 692 +Other liabilities 264,034 283,133 +Total liabilities 2,622,435 2,113,173 +Commitments and contingent liabilities +Stockholders' equity +Common shares - par value $ 0.01 per share, 150,000,000 authorized, 99,758,720 and 61,652,412 issued as of December 31, 2020 and 2019, respectively +998 617 +Additional paid-in capital 3,387,754 2,384,309 +Accumulated deficit ( 772,265 ) ( 47,945 ) +Treasury shares - at cost, 37,510 and 34,922 as of December 31, 2020 and 2019, respectively +( 949 ) ( 1,474 ) +Total stockholders' equity 2,615,538 2,335,507 +Total Liabilities and Stockholders' Equity $ 5,237,973 $ 4,448,680 +See accompanying Notes to Consolidated Financial Statements +68 +PDC ENERGY, INC. +Consolidated Statements of Operations +(in thousands, except per share data) +Year Ended December 31, +2020 2019 2018 +Revenues +Crude oil, natural gas and NGLs sales $ 1,152,555 $ 1,307,275 $ 1,389,961 +Commodity price risk management gain (loss), net 180,270 ( 162,844 ) 145,237 +Other income 6,401 11,692 13,461 +Total revenues 1,339,226 1,156,123 1,548,659 +Costs, expenses and other +Lease operating expenses 161,346 142,248 130,957 +Production taxes 59,368 80,754 90,357 +Transportation, gathering and processing expenses 77,835 46,353 37,403 +Exploration, geologic and geophysical expense 1,376 4,054 6,204 +General and administrative expense 161,087 161,753 170,504 +Depreciation, depletion and amortization 619,739 644,152 559,793 +Accretion of asset retirement obligations 10,072 6,117 5,075 +Impairment of properties and equipment 882,393 38,536 458,397 +Loss (gain) on sale of properties and equipment ( 724 ) 9,734 394 +Other expense 10,272 11,317 11,829 +Total costs, expenses and other 1,982,764 1,145,018 1,470,913 +Income (loss) from operations ( 643,538 ) 11,105 77,746 +Interest expense, net ( 88,684 ) ( 71,099 ) ( 70,317 ) +Income (loss) before income taxes ( 732,222 ) ( 59,994 ) 7,429 +Income tax benefit (expense) 7,902 3,322 ( 5,406 ) +Net income (loss) $ ( 724,320 ) $ ( 56,672 ) $ 2,023 +Earnings (loss) per share: +Basic $ ( 7.37 ) $ ( 0.89 ) $ 0.03 +Diluted ( 7.37 ) ( 0.89 ) 0.03 +Weighted-average common shares outstanding: +Basic 98,251 64,032 66,059 +Diluted 98,251 64,032 66,303 +See accompanying Notes to Consolidated Financial Statements +69 +PDC ENERGY, INC. +Consolidated Statements of Cash Flows +(in thousands) +Year Ended December 31, +2020 2019 2018 +Cash flows from operating activities: +Net income (loss) $ ( 724,320 ) $ ( 56,672 ) $ 2,023 +Adjustments to net income (loss) to reconcile to net cash from operating activities: +Net change in fair value of unsettled commodity derivatives 99,001 145,246 ( 260,775 ) +Depreciation, depletion and amortization 619,739 644,152 559,793 +Impairment of properties and equipment 882,393 38,536 458,397 +Accretion of asset retirement obligations 10,072 6,117 5,075 +Non-cash stock-based compensation 22,200 23,837 21,782 +Loss (gain) on sale of properties and equipment ( 724 ) 9,734 394 +Amortization and write-off of debt discount, premium and issuance costs 16,772 13,575 12,769 +Deferred income taxes ( 6,530 ) ( 2,256 ) 6,105 +Other 3,004 3,155 2,876 +Changes in assets and liabilities: +Accounts receivable 139,664 ( 88,304 ) 12,025 +Other assets ( 5,341 ) ( 11,560 ) ( 81 ) +Production tax liability ( 50,803 ) 22,240 35,225 +Accounts payable and accrued expenses ( 66,183 ) ( 29,578 ) 16,261 +Funds held for future distribution ( 23,621 ) ( 7,298 ) 9,973 +Asset retirement obligations ( 27,491 ) ( 21,511 ) ( 13,341 ) +Other liabilities ( 17,753 ) 168,813 20,801 +Net cash from operating activities 870,079 858,226 889,302 +Cash flows from investing activities: +Capital expenditures for development of crude oil and natural gas properties ( 550,964 ) ( 855,908 ) ( 946,350 ) +Capital expenditures for other properties and equipment ( 1,634 ) ( 20,839 ) ( 11,055 ) +Acquisition of crude oil and natural gas properties ( 139,812 ) ( 13,207 ) ( 180,026 ) +Proceeds from sale of properties and equipment 1,641 2,105 3,562 +Proceeds from divestitures 3,610 202,076 44,693 +Restricted cash — 8,001 1,249 +Net cash from investing activities ( 687,159 ) ( 677,772 ) ( 1,087,927 ) +Cash flows from financing activities: +Proceeds from revolving credit facility and other borrowings 1,799,350 1,577,000 1,072,500 +Repayment of revolving credit facility and other borrowings ( 1,635,350 ) ( 1,605,500 ) ( 1,040,000 ) +Proceeds from issuance of senior notes 148,500 — — +Payment of debt issuance costs ( 6,538 ) ( 72 ) ( 7,704 ) +Purchase of treasury shares ( 23,819 ) ( 154,363 ) — +Purchase of treasury shares for employee stock-based compensation tax withholding obligations ( 9,345 ) ( 4,003 ) ( 5,147 ) +Redemption of senior notes ( 452,153 ) — — +Principal payments under financing lease obligations ( 1,905 ) ( 1,952 ) ( 1,495 ) +Other — — ( 55 ) +Net cash from financing activities ( 181,260 ) ( 188,890 ) 18,099 +Net change in cash, cash equivalents and restricted cash 1,660 ( 8,436 ) ( 180,526 ) +Cash, cash equivalents and restricted cash, beginning of year 963 9,399 189,925 +Cash, cash equivalents and restricted cash, end of year $ 2,623 $ 963 $ 9,399 +See accompanying Notes to Consolidated Financial Statements +70 +PDC ENERGY, INC. +Consolidated Statements of Stockholders' Equity +(in thousands, except share data) +Common Stock Additional Paid-in Capital Treasury Stock Retained Earnings (Accumulated Deficit) Total Stockholders' Equity +Shares Amount Shares Amount +Balance at January 1, 2018 65,955,080 $ 659 $ 2,503,294 ( 55,927 ) $ ( 3,008 ) $ 6,704 $ 2,507,649 +Net income — — — — — 2,023 2,023 +Stock-based compensation 193,529 2 21,780 — — — 21,782 +Purchase of treasury shares for employee stock-based compensation tax withholding obligations — — — ( 102,647 ) ( 5,147 ) — ( 5,147 ) +Issuance of treasury shares — — ( 5,561 ) 104,068 5,561 — — +Non-employee directors' deferred compensation plan — — — 9,286 491 — 491 +Other — — ( 90 ) — — — ( 90 ) +Balance at December 31, 2018 66,148,609 661 2,519,423 ( 45,220 ) ( 2,103 ) 8,727 2,526,708 +Net loss — — — — — ( 56,672 ) ( 56,672 ) +Stock-based compensation 213,745 2 23,835 — — — 23,837 +Purchase of treasury shares for employee stock-based compensation tax withholding obligations — — — ( 106,151 ) ( 4,003 ) — ( 4,003 ) +Retirement of treasury shares for employee stock-based compensation tax withholding obligations ( 3,803 ) — ( 127 ) 3,803 127 — — +Purchase of treasury shares — — — ( 4,706,139 ) ( 154,363 ) — ( 154,363 ) +Retirement of treasury shares ( 4,706,139 ) ( 46 ) ( 154,317 ) 4,706,139 154,363 — — +Issuance of treasury shares — — ( 4,505 ) 112,646 4,505 — — +Balance at December 31, 2019 61,652,412 617 2,384,309 ( 34,922 ) ( 1,474 ) ( 47,945 ) 2,335,507 +Net loss — — — — — ( 724,320 ) ( 724,320 ) +Issuance pursuant to acquisition 39,182,045 391 1,014,921 — — — 1,015,312 +Stock-based compensation 529,911 5 19,738 — 2,457 — 22,200 +Purchase of treasury shares for employee stock-based compensation tax withholding obligations — — — ( 456,995 ) ( 9,345 ) — ( 9,345 ) +Retirement of treasury shares for employee stock-based compensation tax withholding obligations ( 339,648 ) ( 3 ) ( 7,407 ) 339,648 7,413 — 3 +Purchase of treasury shares — — — ( 1,266,000 ) ( 23,819 ) — ( 23,819 ) +Retirement of treasury shares ( 1,266,000 ) ( 12 ) ( 23,807 ) 1,266,000 23,819 — — +Issuance of treasury shares — — — 114,759 — — — +Balance at December 31, 2020 99,758,720 $ 998 $ 3,387,754 ( 37,510 ) $ ( 949 ) $ ( 772,265 ) $ 2,615,538 +See accompanying Notes to Consolidated Financial Statements +71 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION +PDC Energy, Inc. is a domestic independent exploration and production company that acquires, explores and develops properties for the production of crude oil, natural gas and NGLs, with operations in the Wattenberg Field in Colorado and the Delaware Basin in west Texas. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are primarily focused in the Wolfcamp zones. We previously operated properties in the Utica Shale in Southeastern Ohio; however, we divested these properties during the first quarter of 2018. As of December 31, 2020, we owned an interest in approximately 3,727 productive gross wells. +The accompanying audited consolidated financial statements include the accounts of PDC and our wholly-owned subsidiaries. Pursuant to the proportionate consolidation method, our accompanying consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated upon consolidation. +During 2020, the effects of coronavirus 2019 (“COVID-19”) led to a significant decline in global demand for crude oil and natural gas, contributing to a drastic reduction in commodity prices and negatively impacting oil and natural gas producers located in the United States, including PDC. The commodity price environment may remain volatile for an extended period as a result of reduced global oil and natural gas demand and the global economic recession. We expect to be able to fund our operations, planned capital expenditures and working capital and other requirements during the next 12 months and the foreseeable future. +NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Use of Estimates in the Preparation of Financial Statements. The preparation of our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America ("U.S. GAAP") requires us to make estimates and assumptions that affect the amounts reported in our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of proved oil and natural gas reserves used in calculating depletion; estimates of unpaid revenues and unbilled costs; future cash flows from proved oil and natural gas reserves on proved oil and natural gas properties used in computing impairment test limitations; valuation of commodity derivative instruments; the estimation of future abandonment obligations used in asset retirement obligations; valuation of proved and unproved crude oil and natural gas properties from purchased and exchanged businesses and assets; and valuation of deferred income tax assets. +Cash and Cash Equivalents. The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. Cash and cash equivalents potentially subject us to a concentration of credit risk as substantially all of our deposits held in financial institutions were in excess of federal deposit insurance limits as of December 31, 2020 and 2019. We maintain our cash and cash equivalents in the form of money market and checking accounts with financial institutions that we believe are creditworthy and are also lenders under our revolving credit facility. +Commodity Derivative Financial Instruments. Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas we enter into commodity derivative contracts to protect against price declines in future periods. We have elected not to designate any of our commodity derivative instruments as cash flow hedges; therefore, these instruments do not qualify for hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the consolidated statements of operations. Under applicable accounting standards, the fair value of each derivative instrument is recorded as either an asset or liability on the consolidated balance sheet. We measure the fair value of our commodity derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates, volatility factors and nonperformance risk. +72 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Properties and Equipment. +Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Under this method, costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depleted by the unit-of-production method based on estimated proved developed producing reserves. We have determined that we have two unit-of-production fields: the Wattenberg Field and the Delaware Basin. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations and common cost environments in these areas. We calculate quarterly depletion expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted for fourth quarter production. The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. Capitalized development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized as a gain or loss. +Exploration costs, including geological and geophysical expenses, seismic costs on unproved leaseholds and delay rentals are expensed as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have identified a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expen se. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as suspended well costs until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the resulting accounting treatment is recorded. +Unproved property costs not subject to depletion primarily include leasehold costs, broker and legal expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Leasehold costs are transferred into costs subject to depletion on an ongoing basis as these properties are evaluated and proved reserves are established. Additional costs not subject to depletion include costs associated with development wells in progress or awaiting completion at year-end. These costs are transferred into costs subject to depletion on an ongoing basis as these wells are completed and proved reserves are established or confirmed. +Proved Property Impairment. Annually, or upon a triggering event, we assess the valuation of our proved crude oil and natural gas properties for possible impairment by comparing the carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production and prices at which we estimate the commodity will be sold. If carrying values exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a discounted future cash flows analysis. The impairment recorded is the amount by which the carrying values exceed the fair value. In the impairment assessment we estimate the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices, and a market based weighted average cost of capital rate. Certain events, including but not limited to downward revisions in estimates of our reserve quantities, expectations of falling commodity prices or rising operating costs, could result in a triggering event, and may result to a possible impairment of our proved crude oil and natural gas properties. +Unproved Property Impairment. Acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to impairment expense. Unproved crude oil and natural gas properties with individually significant acquisition costs are assessed for impairment periodically, or if a triggering event is identified. +73 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Other Property and Equipment. Other property and equipment such as pipelines, vehicles, facilities, office furniture and equipment, buildings and computer hardware and software is carried at cost. Depreciation is provided principally on the straight-line method over the assets' estimated useful lives, which range from two to 35 years. Total depreciation expense related to other property and equipment was $ 8.7 million, $ 5.7 million and $ 8.5 million for the year ended December 31, 2020, 2019 and 2018, respectively. +We review other property and equipment for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying value of the asset exceeds the estimated future cash flows, an impairment charge is recognized for the amount by which the carrying value of the asset exceeds its fair value. +Maintenance and repair costs on other property and equipment are charged to expense as incurred. Major renewals and improvements are capitalized and depreciated over the remaining useful life of the asset. Upon the sale or other disposition of assets, the cost and related accumulated DD&A are removed, the proceeds are applied and any resulting gain or loss is recognized. +Internal-Use Software. Internal-use software costs incurred during the development stage of our enterprise resource planning software are capitalized. The development stage generally includes software design, configuration, testing and installation activities. Training and maintenance costs are expensed as incurred, while upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Capitalized internal-use software costs are depreciated over the estimated useful life of the underlying project on a straight-line basis upon completion of the project. +Capitalized Interest. Interest costs are capitalized as part of the historical cost of acquiring assets. Investments in unproved crude oil and natural gas properties and major development projects, on which DD&A expense is not currently recorded and on which exploration or development activities are in progress, qualify for capitalization of interest. Major construction projects also qualify for interest capitalization until the asset is ready to be placed into service. Capitalized interest is calculated by multiplying our weighted-average interest rate on our outstanding debt by the qualifying costs. Interest capitalized may not exceed gross interest expense for the period. As the qualifying asset is placed into service, we begin amortizing the related capitalized interest over the useful life of the asset. Capitalized interest totaled $ 19.7 million, $ 13.4 million and $ 9.2 million during the year ended December 31, 2020, 2019 and 2018, respectively. +Assets Held-for-Sale. Assets held-for-sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, earnings multiples or indicative bids, when available. We consider historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected on the consolidated financial statements. DD&A expense is not recorded on assets once they are classified as held-for-sale. Assets classified as held-for-sale are expected to be disposed of within one year. +Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred income tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred income tax assets and liabilities are measured using enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred income tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred income tax assets to what we consider realizable. +The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. The Company's policy is to recognize interest and penalties related to uncertain tax positions in interest expense. +74 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Debt Issuance Costs and Discounts. Debt issuance costs and discounts are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs for the Senior Notes are included in long-term debt and the debt issuance costs for the revolving credit facility are included in other assets. +Asset Retirement Obligations. We recognize the estimated liability for future costs associated with the plugging and abandonment of our oil and gas properties resulting from acquisition, construction or normal operation. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value (accretion expense). The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost. Revisions in estimated liabilities can result from, among other things, changes in retirement costs or the estimated timing of settling asset retirement obligations. +Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders’ equity. When we retire treasury shares, we charge any excess of cost over the par value to additional paid-in-capital ("APIC"), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings. +Revenue Recognition. Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of crude oil, natural gas or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record revenues based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For the years ending December 31, 2020, 2019 and 2018, the impact of any natural gas imbalances was not significant. +Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or "gross" method of accounting, depending upon the related agreement. We use the net-back method when control of the crude oil, natural gas or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. +We use the gross method of accounting when control of the crude oil, natural gas or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses. +For our product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC Topic 606 which states the Company is not required to disclose the transaction price allocated to the remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, monthly sales of a product generally represent a separate performance obligation; therefore, future commodity volumes to be delivered and sold are wholly unsatisfied and disclosure of the transaction price allocated to such unsatisfied performance obligations is not required. +Business Combinations. We utilize the acquisition method to account for acquisitions of businesses. Pursuant to the acquisition method, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows and estimates by management, which are Level 3 inputs. When appropriate, we review recent comparable purchases and sales of crude oil and +75 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. +In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped and unproved crude oil and natural gas properties. To estimate the fair value of these properties as part of acquisition accounting, we estimate the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices, and a market based weighted average cost of capital rate. The market based weighted average cost of capital rate is subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of recent comparable purchased properties to determine an estimation of fair value. +If applicable, we record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. +Acreage Exchanges . From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and provide us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges of non-producing interests and unproved mineral leases in accordance with the guidance prescribed by Accounting Standards Codification 845, Nonmonetary Transactions . For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized in earnings, in accordance with Accounting Standards Codification 820, Fair Value Measurement . +Stock-Based Compensation. Stock-based compensation is recognized within our financial statements based on the grant-date fair value of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the requisite service period for the entire award and we account for forfeitures of stock-based compensation awards as they occur. +Fair Value of Assets and Liabilities. The Company follows the authoritative accounting guidance for measuring fair value of assets and liabilities in its financial statements. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. +76 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Leases. We determine if an arrangement is representative of a lease at contract inception. Right-of-use ("ROU") assets represent our right to use the underlying assets for the lease term and the corresponding lease liabilities represent our obligations to make lease payments arising from the leases. Operating and finance lease ROU assets and liabilities are recognized at the commencement date based on the present value of the expected lease payments over the lease term. As most of our leases do not provide an implicit interest rate, we utilize our incremental borrowing rate based on information available at the commencement date in determining the present value of lease payments. Subsequent measurement, as well as presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. Terms of our leases include options to extend or terminate the lease only when we can ascertain that it is reasonably certain we will exercise that option. Leases with an initial term of one year or less are not recorded on the consolidated balance sheets. +We apply the practical expedient that permits combining lease and non-lease components in a contract and accounting for the combination as a single lease component (applied by asset class). +Recently Adopted Accounting Pronouncement +In March 2020, the SEC adopted final rules that amend the financial disclosure requirements for subsidiary issuers and guarantors of registered debt securities in Rule 3-10 of Regulation S-X. The amended rules, which can be found under new Rule 13-01 of Regulation S-X, narrow the circumstances that require separate financial statements of subsidiary issuers and guarantors and streamline the alternative disclosures required in lieu of those statements. The amended rules allow registrants, among other things, to disclose summarized financial information of the issuer and guarantors on a combined basis and to present only the most recently completed fiscal year and subsequent year-to-date interim period. The rule replaces the requirement to provide condensed consolidating financial information with a requirement to present summarized financial information of the issuers and guarantors. These disclosures may be included in the notes to the consolidated financial statements or can be disclosed outside the notes to the consolidated financial statements (i.e. management's discussion and analysis section). The rule is effective in the first quarter of 2021, with earlier adoption permitted. We early adopted the rule in the first quarter of 2020 and have provided these disclosures outside the notes to the condensed consolidated financial statements. In October 2020, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") No. 2020-09, Amendments to SEC Paragraphs Pursuant to SEC Release No. 33-10762 , to align the standards under Accounting Standard Codification 470, Debt , with the SEC final rules discussed above . +Recently Issued Accounting Pronouncement but Not Yet Adopted +In August 2020, FASB issued Accounting Standards Update ("ASU") No. 2020-06, Debt - Debt with conversion and other options and derivatives and hedging on contracts in entity's own equity. Amendments in this ASU simplify accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts on an entity's own equity. The amendments remove the separation models for convertible debt instruments with cash conversion features and convertible instruments with beneficial conversion features. Consequently, a convertible debt instrument will be accounted for as a single liability measured at its amortized cost and convertible preferred stock will be accounted for as a single equity instrument measured at its historical cost as long as no other features require bifurcation and recognition as derivatives. The amendments also modify the accounting for certain contracts in an entity's own equity that are currently accounted for as derivatives because of specific settlement provisions. Lastly, the earnings per share ("EPS") calculation is being amended to (i) require entities to use the if-converted method for all convertible instruments and include the effect of potential share settlement; (ii) clarify that the average market price for the period should be used in the computation of the diluted EPS denominator; and (iii) require entities to use the weighted-average share count from each quarter when calculating the year-to-date weighted average share count for all potentially dilutive securities. The amendments in this ASU are effective for fiscal years beginning after December 31, 2021, including interim periods within those fiscal years and early adoption is permitted. We completed our evaluation of this ASU and we concluded that the amendments would not have a significant impact on our financial statements. We do not intend to adopt the amendments early. +77 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 3 - BUSINESS COMBINATION +In January 2020, we merged with SRC in a transaction valued at $ 1.7 billion, inclusive of SRC's net debt (the "SRC Acquisition"). SRC was an independent oil and natural gas company engaged in the exploration, development and production of unconventional oil and associated liquids-rich natural gas reserves in Weld County, Colorado. The acquisition added approximately 83,000 net acres which are located on large, contiguous acreage blocks in the core of the Wattenberg Field. Upon closing, we issued approximately 38.9 million shares of our common stock to SRC shareholders and holders of SRC equity awards, reflecting the issuance of 0.158 of a share of our common stock in exchange for each outstanding share of SRC common stock and the cancellation of outstanding SRC equity awards pursuant to the terms of the merger agreement that we entered into with the SRC (the "Merger Agreement"). During the year ended December 31, 2020, we recorded transaction costs related to the SRC Acquisition of $ 19.9 million. These expenses were accounted for separately from the assets and liabilities assumed and are included in general and administrative expense in the consolidated statements of operations. +The following table details our final purchase price, valuation and allocation of the purchase price to the assets acquired and liabilities assumed as a result of the SRC Acquisition: +(in thousands) +Consideration: +Cash $ 40 +Retirement of seller's credit facility 166,238 +Total cash consideration 166,278 +Common stock issued 1,009,015 +Shares withheld in lieu of taxes 6,299 +Total consideration $ 1,181,592 +Recognized amounts of identifiable assets acquired and liabilities assumed: +Assets acquired: +Current assets $ 145,792 +Properties and equipment, net - proved 1,613,674 +Properties and equipment, net - unproved 109,615 +Properties and equipment, net - other 16,242 +Deferred tax asset 189,311 +Other assets 11,810 +Total assets acquired $ 2,086,444 +Liabilities assumed: +Current liabilities $ ( 253,967 ) +Senior notes ( 555,500 ) +Asset retirement obligations ( 42,417 ) +Other liabilities ( 52,968 ) +Total liabilities assumed ( 904,852 ) +Total identifiable net assets acquired $ 1,181,592 +This acquisition was accounted for under the acquisition method of accounting for business combinations. Accordingly, we conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the valuation of proved and unproved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs , future commodity prices, lease terms and expirations and a market-based weighted-average cost of capital rate of 10 percent. These inputs require significant judgments and estimates by management at the time of the valuation. +78 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The results of operations for the SRC Acquisition since the closing date have been included in our consolidated financial statements for the year ended December 31, 2020 and include approximately $ 320.9 million of total revenue, and $ 46.5 million of income from operations. +Pro Forma Information. The following unaudited pro forma financial information represents a summary of the consolidated results of operations for the years ended December 31, 2020 and 2019, assuming the acquisition had been completed as of January 1, 2019. The information below reflects certain nonrecurring pro forma adjustments that were directly related to the business combination based on available information and certain assumptions that we believe are reasonable, including (i) the Company's common stock issued to convert SRC's outstanding shares of common stock and equity awards, (ii) the depletion of SRC's fair-valued proved oil and gas properties using the successful efforts method of accounting and (iii) the estimated tax impacts of the proforma adjustments, if any. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the acquisition had been effective as of these dates, or of future results. +Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company and SRC totaling approximately $ 38.0 million and $ 15.9 million for the years ended December 31, 2020 and 2019, respectively. +Year Ended December 31, +2020 2019 +(in thousands, except per share data) +Total revenue $ 1,361,051 $ 1,761,498 +Net income (loss) ( 695,663 ) 139,578 +Earnings (loss) per share: +Basic $ ( 6.97 ) $ 1.36 +Diluted ( 6.97 ) 1.35 +79 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 4 - REVENUE RECOGNITION +Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for the periods presented: +Year Ended December 31, +Revenue by Commodity and Operating Region 2020 2019 2018 +(in thousands) +Crude oil +Wattenberg Field $ 668,948 $ 767,760 $ 783,158 +Delaware Basin 147,902 252,929 252,107 +Utica Shale (1) +— — 2,696 +Total 816,850 1,020,689 1,037,961 +Natural gas +Wattenberg Field 171,755 137,143 130,073 +Delaware Basin 6,997 13,877 32,010 +Utica Shale (1) +— — 1,109 +Total 178,752 151,020 163,192 +NGLs +Wattenberg Field 128,126 94,347 132,820 +Delaware Basin 28,827 41,219 55,148 +Utica Shale (1) +— — 840 +Total 156,953 135,566 188,808 +Revenue by Operating Region +Wattenberg Field 968,829 999,250 1,046,051 +Delaware Basin 183,726 308,025 339,265 +Utica Shale (1) +— — 4,645 +Total $ 1,152,555 $ 1,307,275 $ 1,389,961 +____________ +(1) In March 2018, we completed the disposition of our Utica Shale properties. +Contract Assets. Contract assets include material contributions in aid of construction, which are common in purchase and processing agreements with midstream service providers that are our customers. The intent of the payments is primarily to reimburse the customer for actual costs incurred related to the construction of its gathering and processing infrastructure. Contract assets are included in other assets on the consolidated balance sheets. The contract assets are amortized as a reduction to crude oil, natural gas and NGLs sales revenue during the periods in which the related production is transferred to the customer. +The following table presents the changes in carrying amounts of the contract assets associated with our crude oil, natural gas and NGLs sales revenue for the periods presented: +December 31, +2020 2019 +(in thousands) +Beginning balance $ 11,494 $ 11,144 +Additions 16,739 443 +Amortized as a reduction to crude oil, natural gas and NGLs sales ( 2,361 ) ( 93 ) +Ending balance $ 25,872 $ 11,494 +80 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 5 - FAIR VALUE MEASUREMENTS +Recurring Fair Value Measurements +Derivative Financial Instruments. We measure the fair value of our commodity derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties' credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default exchange rates and the duration of each outstanding derivative position. We validate our fair value measurement by corroborating the original source of inputs, monitoring changes in valuation methods and assumptions, and reviewing counterparty statements and other supporting documentation. +Our crude oil and natural gas fixed-price exchanges are included in Level 2. Our collars are included in Level 3. Our basis exchanges are included in Level 2 and Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis as of the periods presented: +December 31, +2020 2019 +Significant Other +Observable +Inputs +(Level 2) Significant +Unobservable +Inputs +(Level 3) Total Significant Other +Observable +Inputs +(Level 2) Significant +Unobservable +Inputs +(Level 3) Total +(in thousands) +Total assets $ 36,895 $ 21,539 $ 58,434 $ 22,886 $ 8,938 $ 31,824 +Total liabilities ( 104,545 ) ( 29,966 ) ( 134,511 ) ( 3,089 ) ( 524 ) ( 3,613 ) +Net derivative instruments $ ( 67,650 ) $ ( 8,427 ) $ ( 76,077 ) $ 19,797 $ 8,414 $ 28,211 +The following table presents a reconciliation of our Level 3 assets and liabilities measured at fair value: +Year Ended December 31, +2020 2019 2018 +(in thousands) +Fair value of Level 3 instruments, net asset (liability) beginning of period $ 8,414 $ 58,329 $ ( 9,687 ) +Changes in fair value included in consolidated statements of operations line item: +Commodity price risk management gain (loss), net 37,821 ( 41,749 ) 63,257 +Settlements included in consolidated statements of operations line items: +Commodity price risk management gain (loss), net ( 54,662 ) ( 8,166 ) 4,759 +Fair value of Level 3 instruments, net asset (liability) end of period $ ( 8,427 ) $ 8,414 $ 58,329 +Net change in fair value of Level 3 unsettled derivatives included in consolidated statements of operations line item: +Commodity price risk management gain (loss), net $ — $ ( 22,694 ) $ — +Total $ — $ ( 22,694 ) $ — +The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. There has been no change in the methodology we apply to measure the fair value of our Level 3 derivative contracts during the periods covered by the financial statements. +81 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Nonrecurring Fair Value Measurements +Acquisitions and impairment of long-lived assets. We utilize fair value with inputs that are not observable in the market, therefore designated as Level 3 within the valuation hierarchy, on a nonrecurring basis for any acquired assets or businesses and to review our proved and unproved crude oil and natural gas properties for possible impairment. +Asset Retirement Obligations. We measure the fair value of asset retirement obligations as of the date a well begins drilling or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 within the valuation hierarchy. +Other Financial Instruments +The carrying value of the financial instruments included in current assets and current liabilities approximates fair value due to the short-term maturities of these instruments. +Long-term debt. The portion of our long-term debt related to our revolving credit facility approximates fair value, as the applicable interest rates are variable and reflective of market rates. We have not elected to account for the portion of our debt related to our senior notes under the fair value option; however, we have determined an estimate of the fair values based on measurements of trading activity and broker or dealer quotes, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes and convertible notes as of the dates indicated: +December 31, +2020 2019 +Estimated Fair Value Percent of Par Estimated Fair Value Percent of Par +(in millions) +Senior notes: +2021 Convertible Notes $ 196.2 98.1 % $ 188.6 94.3 % +2024 Senior Notes 410.8 102.7 % 409.2 102.3 % +2025 Senior Notes 102.8 100.5 % — — % +2026 Senior Notes 775.5 103.4 % 599.4 99.9 % +NOTE 6 - COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS +Objective and Strategy. Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas we enter into commodity derivative contracts such as collars, fixed-price exchanges and basis protection exchanges, to protect against price declines in future periods. We do not enter into derivative contracts for speculative or trading purposes. +We believe our commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. Depending on changes in oil and gas futures markets and management's view of underlying supply and demand trends, we may increase or decrease our derivative positions from current levels. As of December 31, 2020, we had derivative instruments in place for a portion of our anticipated 2021 and 2022 production. Our commodity derivative contracts have been entered into at no upfront cost to us as we hedge our anticipated production at the then-prevailing commodity market prices, without adjustment for premium or discount. +As of December 31, 2020 and 2019, our derivative instruments were comprised of fixed-price swaps, collars and basis protection swaps. +• Fixed-price swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty; +82 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +• Collars contain a fixed floor price (put) and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty; +• Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For basis protection swaps, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. +Commodity Derivative Contracts. As of December 31, 2020, we had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted-average contract price is shown. +Collars Fixed-Price Exchanges +Commodity/ Index/ +Maturity Period +Quantity (Crude oil - MBbls Natural Gas - BBtu) +Weighted-Average Contract Price +Quantity (Crude Oil - MBbls Gas and Basis- BBtu) +Weighted- Average Contract Price +Fair Value December 31, 2020 (1) (in thousands) +Floors Ceilings +Crude Oil +NYMEX +2021 4,008 $ 38.76 $ 50.05 10,176 $ 47.01 $ ( 20,341 ) +2022 900 40.00 52.05 4,884 41.18 ( 26,440 ) +Total Crude Oil 4,908 15,060 ( 46,781 ) +Natural Gas +NYMEX +2021 62,625 2.46 2.86 31,800 2.40 ( 9,169 ) +2022 17,400 2.50 2.89 8,700 2.62 1,325 +Total Natural Gas 80,025 40,500 ( 7,844 ) +Basis Protection - Natural Gas +CIG +2021 — — — 94,425 ( 0.46 ) ( 19,773 ) +2022 — — — 26,100 ( 0.34 ) ( 1,679 ) +Total Basis Protection - Natural Gas — 120,525 ( 21,452 ) +Commodity Derivatives Fair Value $ ( 76,077 ) +83 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Effect of Derivative Instruments on the Consolidated Balance Sheet. The following table presents the consolidated balance sheet line item and fair value amounts of our derivative instruments as of the dates indicated: +December 31, +Consolidated Balance Sheet Line Item 2020 2019 +(in thousands) +Derivative assets: Current +Commodity derivative contracts Fair value of derivatives $ 48,869 $ 27,766 +Basis protection derivative contracts Fair value of derivatives — 312 +48,869 28,078 +Non-current +Commodity derivative contracts Fair value of derivatives 9,565 3,746 +Total derivative assets $ 58,434 $ 31,824 +Derivative liabilities: Current +Commodity derivative contracts Fair value of derivatives $ 78,379 $ 529 +Basis protection derivative contracts Fair value of derivatives 19,773 2,392 +98,152 2,921 +Non-current +Commodity derivative contracts Fair value of derivatives 34,680 692 +Basis protection derivative contracts Fair value of derivatives 1,679 — +Total derivative liabilities $ 134,511 $ 3,613 +Our financial derivative agreements contain master netting provisions that provide for the net settlement of contracts through a single payment in the event of early termination. We have elected not to offset the fair value positions recorded on our consolidated balance sheets. +The following table reflects the impact of netting agreements on gross derivative assets and liabilities: +As of December 31, 2020 Total Gross Amount Presented on Balance Sheet Effect of Master Netting Agreements Total Net Amount +(in thousands) +Derivative assets: +Derivative instruments, at fair value $ 58,434 $ ( 39,691 ) $ 18,743 +Derivative liabilities: +Derivative instruments, at fair value $ 134,511 $ ( 39,691 ) $ 94,820 +As of December 31, 2019 Total Gross Amount Presented on Balance Sheet Effect of Master Netting Agreements Total Net Amount +(in thousands) +Derivative assets: +Derivative instruments, at fair value $ 31,824 $ ( 2,619 ) $ 29,205 +Derivative liabilities: +Derivative instruments, at fair value $ 3,613 $ ( 2,619 ) $ 994 +84 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Effect of Derivative Instruments on the Consolidated Statements of Operations. The following table presents the impact of our derivative instruments on our consolidated statements of operations: +Year Ended December 31, +Consolidated Statements of Operations Line Item 2020 2019 2018 +(in thousands) +Commodity price risk management gain (loss), net +Net settlements $ 279,271 $ ( 17,598 ) $ ( 115,538 ) +Net change in fair value of unsettled derivatives ( 99,001 ) ( 145,246 ) 260,775 +Total commodity price risk management gain (loss), net $ 180,270 $ ( 162,844 ) $ 145,237 +Derivative Counterparties. Our commodity derivative instruments expose us to credit risk of non-performance by our counterparties. We primarily use financial institutions who are also lenders under our revolving credit facility as counterparties to our commodity derivative contracts. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our current counterparties on the fair value of our derivative instruments is not significant at December 31, 2020; however, this determination may change. +NOTE 7 - PROPERTIES AND EQUIPMENT, NET +The following table presents the components of properties and equipment, net of accumulated DD&A, as of the dates indicated: +December 31, +2020 2019 +(in thousands) +Properties and equipment, net: +Crude oil and natural gas properties +Proved $ 7,523,639 $ 6,241,780 +Unproved 350,677 403,379 +Total crude oil and natural gas properties 7,874,316 6,645,159 +Infrastructure and other 65,027 41,888 +Land and buildings 24,299 12,312 +Construction in progress 523,550 408,428 +Properties and equipment, at cost 8,487,192 7,107,787 +Accumulated DD&A ( 3,627,993 ) ( 3,012,585 ) +Properties and equipment, net $ 4,859,199 $ 4,095,202 +Midstream Asset Divestitures. During the second quarter of 2019, we completed the sales of our Delaware Basin produced water gathering and disposal, crude oil gathering and natural gas gathering assets (the "Midstream Asset Divestitures") for aggregate proceeds of $ 345.6 million. The proceeds were received upon closing, with the exception of $ 82.0 million that we received in June 2020. Concurrent with the Midstream Asset Divestitures, we entered into agreements with the purchasers which provide us with certain gathering, processing, transportation and water disposal services. See Note 8 - Accounts Receivable, Other Accrued Expenses and Other Liabilities for further details regarding these agreements. Proceeds were allocated first to the assets sold based upon the fair values of the tangible assets sold, with the remainder of $ 179.6 million allocated to the acreage dedication agreements. We recorded an aggregate gain on the sale of $ 34.0 million based on the fair value of the tangible assets sold. +The Midstream Asset Divestitures did not represent a strategic shift in our operations or have a significant impact on our operations or financial results; therefore, we did not account for the divested assets as discontinued operations. +85 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Impairments. The following table presents impairment charges recorded for properties and equipment: +Year Ended December 31, +2020 2019 2018 +(in thousands) +Impairment of proved and unproved properties $ 881,238 $ 10,599 $ 458,397 +Impairment of infrastructure and other 1,155 27,937 — +Total impairment of properties and equipment $ 882,393 $ 38,536 $ 458,397 +Oil and Gas Properties. +In the first quarter of 2020, the significant decline in crude oil prices in addition to the ongoing effects of COVID-19 was considered a triggering event that required us to assess our crude oil and natural gas properties for possible impairment. As a result of our assessment, we recorded impairment expense of $ 881.1 million to our proved and unproved properties. +Proved Properties. Of the total impairment expense recognized, approximately $ 753.0 million was related to our Delaware Basin proved properties. These impairment charges represented the amount by which the carrying value of the crude oil and natural gas properties exceeded the estimated fair value. We estimated the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount, a level 3 input. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices, and a discount rate of 17 percent, which was based on a weighted-average cost of capital for the area where the assets are located. There were no further triggering events identified for the remainder of 2020. +There were no impairment charges recognized related to our proved properties during the years ended December 31, 2019 and 2018. +Unproved Properties. We recognized approximately $ 127.3 million of impairment charges for our unproved properties in the Delaware Basin during the three months ended March 31, 2020. These impairment charges were recognized based on the fair value of the properties, a Level 3 input. The fair value is estimated based on a review of our current drilling plans, estimated future cash flows for probable well locations and expected future lease expirations, primarily in areas where we have no development plans. There were no further triggering events identified for the remainder of 2020. +During the years ended December 31, 2019 and 2018, we recorded impairment charges totaling $ 10.6 million and $ 458.4 million related to the divestiture of unproved leaseholds and then-current and anticipated near-term leasehold expirations within our non-focus areas of the Delaware Basin that we determined not to develop. +Other Property and Equipment Impairment. During the year ended December 31, 2019, we recorded impairments of $ 27.9 million related to certain midstream facility infrastructure in the Delaware Basin. Upon closing of the Midstream Asset Divestitures, it was determined that the net book value of these assets was not recoverable. +Suspended Well Costs. The following table presents the capitalized exploratory well cost pending determination of proved reserves and included in properties and equipment as of the dates indicated: +December 31, +2020 2019 +(in thousands, except for number of wells) +Beginning balance $ 16,078 $ 12,188 +Additions to capitalized exploratory well costs pending the determination of proved reserves 11,770 31,901 +Reclassifications to proved properties ( 20,389 ) ( 28,011 ) +Ending balance $ 7,459 $ 16,078 +Number of wells pending determination at period-end 2 4 +86 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Our net capitalized exploratory well costs that have been capitalized for a period greater than one year as of December 31, 2020 was $ 7.5 million, which consists of the entire balance of our suspended well costs. We expect to complete our two gross suspended wells associated with two projects in the first half of 2021. We did not have any capitalized costs for a period greater than one year as of December 31, 2019. During 2020, two wells classified as exploratory as of December 31, 2019 were reclassified as productive and no new wells drilled were classified as exploratory. +Exploration Expenses. The following table presents the major components of exploration, geologic and geophysical expense: +Year Ended December 31, +2020 2019 2018 +(in thousands) +Geological and geophysical costs, including seismic purchases $ 253 $ 3,017 $ 3,401 +Exploratory dry hole costs — — 113 +Operating, personnel and other 1,123 1,037 2,690 +Total exploration, geologic and geophysical expense $ 1,376 $ 4,054 $ 6,204 +NOTE 8 - ACCOUNTS RECEIVABLE, OTHER ACCRUED EXPENSES AND OTHER LIABILITIES +Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts as of the dates indicated: +December 31, +2020 2019 +(in thousands) +Crude oil, natural gas and NGLs sales $ 178,147 $ 149,758 +Joint interest billings 50,329 29,510 +Midstream asset divestitures deferred payments — 81,702 +Other 22,538 12,860 +Allowance for doubtful accounts ( 6,763 ) ( 7,476 ) +Accounts receivable, net $ 244,251 $ 266,354 +The Company's accounts receivable consists mainly of receivables from (i) crude oil, natural gas and NGLs purchasers, (ii) receivable from joint interest owners in the properties we operate and (iii) from derivative counterparties. Most payments for production are received within two months after the production date. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. +Credit and Concentration Risk. Inherent to our industry is the concentration of crude oil, natural gas and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. As of December 31, 2020 and 2019, four of our customers represented 10 percent or more of our crude oil, natural gas and NGLs accounts receivable balance. +During the year ended December 31, 2020, four customers accounted for approximately 31 percent, 17 percent, 16 percent and 13 percent of our total crude oil, natural gas and NGLs sales. During the year ended December 31, 2019, four customers accounted for approximately 20 percent, 17 percent, 16 percent and 11 percent of our total crude oil, natural gas and NGLs sales. During the year ended December 31, 2018, one customer accounted for approximately 13 percent of our total crude oil, natural gas and NGLs sales. However, given the liquidity in the market for the sale of hydrocarbons, we believe that the loss of any single purchaser, or the aggregate loss of several purchasers, could be managed by selling to alternative purchasers. +87 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Other Accrued Expenses. The following table presents the components of other accrued expenses as of the dates indicated: +December 31, +2020 2019 +(in thousands) +Employee benefits $ 23,304 $ 21,611 +Asset retirement obligations 33,933 32,200 +Environmental expenses 10,139 2,256 +Operating and finance leases 7,986 5,926 +Other 6,353 8,469 +Other accrued expenses $ 81,715 $ 70,462 +Other Liabilities. The following table presents the components of other liabilities as of the dates indicated: +December 31, +2020 2019 +(in thousands) +Deferred midstream gathering credits $ 168,478 $ 175,897 +Deferred oil gathering credits 18,090 20,100 +Production taxes 65,592 68,020 +Operating and finance leases 10,763 15,779 +Other 1,111 3,337 +Other liabilities $ 264,034 $ 283,133 +Deferred Midstream Gathering Credits. In the second quarter of 2019, concurrent with the sale of our Delaware Basin midstream assets, we entered into an agreement with the purchasers that dedicated the gathering of certain of our production and all water gathering and disposal volumes in the Delaware Basin. The terms of these agreements range from 15 to 22 years. The acreage dedication agreements resulted in initial cash receipts and are being amortized on a units-of-production basis. The amortization rates are assessed on an annual basis for changes in estimated future production. +Deferred Oil Gathering Credits. In 2018, we entered into an agreement that dedicates crude oil from the majority of our Wattenberg Field acreage to the midstream provider's gathering lines and extends the term of the agreement through December 2029. The acreage dedication agreement resulted in an initial cash receipt and is being amortized over the life of the agreement. +The following table presents the amortization charges related to our deferred credits recognized on the consolidated statements of operations for the periods indicated: +Year Ended December 31, +2020 2019 +(in thousands) +Crude oil, natural gas and NGL sales $ 1,013 $ 439 +Transportation, gathering and processing expenses 5,618 3,659 +Lease operating expenses 2,015 935 +88 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 9 - LONG-TERM DEBT +Long-term debt consisted of the following as of the dates indicated: +December 31, +2020 2019 +(in thousands) +Senior Notes: +1.125% Convertible Notes due September 2021: +Principal amount $ 200,000 $ 200,000 +Unamortized discount ( 6,295 ) ( 14,763 ) +Unamortized debt issuance costs ( 691 ) ( 1,666 ) +Net of unamortized discount and debt issuance costs 193,014 183,571 +6.125% Senior Notes due September 2024: +Principal amount 400,000 400,000 +Unamortized debt issuance costs ( 3,632 ) ( 4,611 ) +Net of unamortized debt issuance costs 396,368 395,389 +6.25% Senior Notes due December 2025: +Principal amount 102,324 — +Unamortized premium 880 — +Net of unamortized premium 103,204 — +5.75% Senior Notes due May 2026: +Principal amount 750,000 600,000 +Unamortized discount ( 1,429 ) — +Unamortized debt issuance costs ( 6,595 ) ( 5,734 ) +Net of unamortized discount and debt issuance costs 741,976 594,266 +Total senior notes 1,434,562 1,173,226 +Revolving Credit Facility: +Revolving credit facility due May 2023 168,000 4,000 +Total debt, net of unamortized discount, premium, and debt issuance costs 1,602,562 1,177,226 +Less current portion of long-term debt 193,014 — +Total long-term debt $ 1,409,548 $ 1,177,226 +Senior Notes +2021 Convertible Notes. In September 2016, we issued $ 200 million of 1.125 % convertible notes due September 15, 2021 (the "2021 Convertible Notes"). Interest is payable semi-annually in arrears on March 15 and September 15. +The 2021 Convertible Notes are convertible prior to March 15, 2021 only upon specified events and during specified periods and, thereafter, at any time, at an initial conversion rate of 11.7113 shares of our common stock per $ 1,000 principal amount of the 2021 Convertible Notes, which is equal to an initial conversion price of approximately $ 85.39 per share. The conversion rate is subject to adjustment upon certain events. Upon conversion, the 2021 Convertible Notes may be settled, at our sole election, in shares of our common stock, cash or a combination thereof. We have initially elected a combination settlement method to satisfy our conversion obligation, which allows us to settle the principal amount of the 2021 Convertible Notes in cash and to settle the excess conversion value, if any, in shares, as well as cash in lieu of fractional shares. +We may not redeem the 2021 Convertible Notes prior to their maturity date. If we undergo a "fundamental change", as defined in the indenture for the 2021 Convertible Notes, subject to certain conditions, holders of the 2021 Convertible Notes +89 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +may require us to repurchase all or part of the 2021 Convertible Notes for cash at a price equal to 100 percent of the principal amount of the 2021 Convertible Notes to be repurchased, plus any accrued and unpaid interest. The occurrence of a fundamental change will also result in the 2021 Convertible Notes becoming convertible. +We allocated the gross proceeds of the 2021 Convertible Notes between the liability and equity components of the debt. The initial $ 160.5 million liability component was determined based on the fair value of similar debt instruments, excluding the conversion feature, priced on the same day we issued the 2021 Convertible Notes. The initial $ 39.5 million equity component represents the debt discount and was calculated as the difference between the fair value of the debt and the gross proceeds of the 2021 Convertible Notes. Approximately $ 4.8 million in costs associated with the issuance of the 2021 Convertible Notes were capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes. Based upon the Company's stock price of $ 20.53 per share as of December 31, 2020, the “if-converted” value of the 2021 Convertible Notes did not exceed the principal amount. +2024 Senior Notes. In September 2016, we issued $ 400 million aggregate principal amount of 6.125 % senior notes due September 15, 2024. Interest is payable semi-annually on March 15 and September 15. Approximately $ 7.8 million in costs associated with the issuance of the 2024 Senior Notes were capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes. The 2024 Senior Notes are redeemable after September 15, 2020 at fixed redemption prices, currently 103.063 percent of the principal amount redeemed. +2025 Senior Notes. Upon completion of the SRC Acquisition in January 2020, we assumed $ 550 million aggregate principal amount of 6.25 % senior notes due December 1, 2025 (the "2025 Senior Notes"). The 2025 Senior Notes were recorded at their approximate fair value of $ 555.5 million. The difference between the acquisition date fair value and the principal amount of the 2025 Senior Notes will be recognized as a reduction to interest expense over the remaining life of the notes. Interest is payable semi-annually on June 1 and December 1. +On January 17, 2020, we commenced an offer to repurchase the 2025 Senior Notes from the holders at 101 percent of the principal amount of the 2025 Senior Notes, together with any accrued and unpaid interest. Upon expiration of the repurchase offer on February 18, 2020, holders of $ 447.7 million of the outstanding 2025 Senior Notes accepted the redemption offer for a total redemption price of approximately $ 452.2 million, plus accrued and unpaid interest of $ 6.2 million. The fair value of the 2025 Senior Notes approximated the repurchase offer price, resulting in recognition of an immaterial loss on extinguishment of the repurchased notes. The repurchase was funded by proceeds from our revolving credit facility. An aggregate principal amount of approximately $ 102.3 million remains outstanding. +On and after December 1, 2020, the Company may redeem the remaining 2025 Senior Notes at a redemption price equal to a specified percentage of the principal amount of the redeemed notes ( 103.125 % for 2021, 101.563 % for 2022, and 100 % for 2023 and thereafter, during the twelve-month period beginning on December 1 of each applicable year), plus accrued and unpaid interest. +2026 Senior Notes. In November 2017, we issued $ 600 million aggregate principal amount 5.75 % senior notes due May 15, 2026 (the "2026 Senior Notes"). Interest is payable semi-annually on May 15 and November 15. Approximately $ 7.6 million in costs associated with the issuance of the 2026 Senior Notes were capitalized as debt issuance costs and are being amortized as interest expense over the life of the notes. +In September 2020, we issued an additional $ 150 million aggregate principal amount of the 2026 Senior Notes at a price equal to 99 percent of par, which resulted in net proceeds of $ 146.7 million, after deducting the original issuance discount of $ 1.5 million and debt issuance costs of $ 1.8 million. The additional 2026 Senior Notes issued have the same terms and conditions as the existing 2026 Senior Notes. +The 2026 Senior Notes are redeemable after May 15, 2021 at fixed redemption prices beginning at 104.313 percent of the principal amount redeemed. At any time prior to May 15, 2021, we may redeem all or part of the 2026 Senior Notes at a make-whole price set forth in the indenture which generally approximates the present value of the redemption price at May 15, 2021 and remaining interest payments on the 2026 Senior Notes at the time of redemption. +Our wholly-owned subsidiary, PDC Permian, Inc., is a guarantor of our obligations under the 2021 Convertible Notes, the 2024 Senior Notes, the 2025 Senior Notes and the 2026 Senior Notes (collectively, the "Senior Notes"). +90 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The Senior Notes are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the notes; equal in right of payment to our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries. +Upon the occurrence of a "change of control," as defined in the indentures for the 2024 Senior Notes, 2025 Senior Notes and 2026 Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal amount of the notes repurchased, together with any accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we may, under certain circumstances, be required to use the net cash proceeds of such asset sale to make an offer to purchase the notes at 100 percent of the principal amount, together with any accrued and unpaid interest to the date of purchase. +The indentures governing the 2024 Senior Notes, 2025 Senior Notes, and 2026 Senior Notes contain covenants that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make investments; create certain liens; enter into agreements that restrict distributions or other payments by restricted subsidiaries to us; enter into transactions with affiliates; sell assets; consolidate or merge with or into other companies or transfer all or substantially of our assets; and create unrestricted subsidiaries. As of December 31, 2020, we were in compliance with all covenants related to the Senior Notes. +Revolving Credit Facility +In May 2018, we entered into a Fourth Amended and Restated Credit Agreement (the “Restated Credit Agreement”). The Restated Credit Agreement provides for a maximum credit amount of $ 2.5 billion. The amount we may borrow under the Restated Credit Agreement is subject to certain limitations. As a result of closing the SRC Acquisition, the borrowing base on our revolving credit facility increased to $ 2.1 billion and we elected to increase the aggregate commitment amount under our revolving credit facility to $ 1.7 billion. In October 2020, as part of our fall 2020 semi-annual redetermination, the borrowing base was reduced to $ 1.6 billion, with a corresponding automatic reduction to our elected commitment level of $ 1.6 billion. As of December 31, 2020 and 2019, availability under our revolving credit facility was $ 1.4 billion and $ 1.3 billion, respectively. +The revolving credit facility is available for working capital requirements, capital investments, acquisitions, to support letters of credit and for general corporate purposes. The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. The borrowing base is subject to a semi-annual redetermination on November 1 and May 1 based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. Substantially all of our crude oil and natural gas properties have been mortgaged or pledged as security for our revolving credit facility. +The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greatest of the administrative agent's prime rate, the federal funds rate plus a premium and the rate for dollar deposits in the London interbank market (“LIBOR”) for one month plus a premium) or, at our election, a rate equal to LIBOR for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. As of December 31, 2020, the applicable interest margin is 0.75 percent for the alternate base rate option or 1.75 percent for the LIBOR option, and the unused commitment fee is 0.375 percent. Principal payments are generally not required until the revolving credit facility expires in May 2023 unless the borrowing base falls below the outstanding balance. +The revolving credit facility contains various restrictive covenants and compliance requirements, which include, among other things: (i) maintenance of certain financial ratios, as defined per the revolving credit facility, including maintenance of minimum current ratio of 1.0:1.0 and not exceed a maximum leverage ratio of 4.0:1.0; (ii) restrictions on the payment of cash dividends; (iii) limits on the incurrence of additional indebtedness; (iv) prohibition on the entry into commodity hedges exceeding a specified percentage of our expected production; and (v) restrictions on mergers and dispositions of assets. As of December 31, 2020, we were in compliance with all the revolving credit facility covenants. +As of December 31, 2020 and 2019, debt issuance costs related to our revolving credit facility were $ 8.1 million and $ 8.9 million, respectively, and are included in other assets line on the consolidated balance sheets. +91 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 10 - LEASES +We adopted ASU 2016-02, Leases , effective January 1, 2019. We have operating leases for office space and compressors and finance leases for vehicles. Our leases have remaining lease terms ranging from one to five years . The vehicle leases include options to renew for up to four years. Lease payments associated with vehicle leases also include a contractually stated residual value guarantee. +The following table presents the components of lease costs for the periods indicated: +Year Ended December 31, +2020 2019 +(in thousands) +Operating lease costs (1) +$ 7,983 $ 4,917 +Finance lease costs: +Amortization of ROU assets 1,812 1,961 +Interest on lease liabilities 179 252 +Total finance lease costs 1,991 2,213 +Short-term lease costs 193,756 170,064 +Total lease costs $ 203,730 $ 177,194 +_______________ +(1) The majority of our operating leases relate to the operation or completion of our wells. Therefore, the lease costs presented in the table above represent the total gross costs the Company incurs, which are not comparable to the Company’s net costs recorded to the consolidated statements of operations, consolidated statements of cash flows or capitalized in the consolidated balance sheets, as amounts therein are reflected net of amounts billed to working interest partners. +92 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Our operating lease costs are recorded in lease operating expenses or general and administrative expense and our finance lease costs are recorded in DD&A expense and interest expense. Our short-term lease costs include amounts that are capitalized as part of the cost of another asset and are recorded as properties and equipment or recognized as expense. +The following table presents the balance sheet classification and other information regarding our leases as of: +December 31, +Consolidated Balance Sheet Line Item 2020 2019 +(in thousands) +Operating Leases: +Operating lease ROU assets Other assets $ 11,722 $ 14,926 +Operating lease obligation - short-term Other accrued expenses 6,520 4,159 +Operating lease obligation - long-term Other liabilities 9,061 12,944 +Total operating lease liabilities $ 15,581 $ 17,103 +Finance Leases: +Finance lease ROU assets Properties and equipment, net $ 3,189 $ 4,637 +Finance lease obligation - short-term Other accrued expenses 1,466 1,767 +Finance lease obligation - long-term Other liabilities 1,702 2,835 +Total finance lease liabilities $ 3,168 $ 4,602 +Weighted-average remaining lease term (years) +Operating leases 3.07 4.28 +Finance leases 2.58 3.17 +Weighted-average discount rate +Operating leases 4.8 % 5.0 % +Finance leases 4.5 % 5.0 % +Maturity of lease liabilities by year and in the aggregate, under operating and financing leases with terms of one year or more, as of December 31, 2020 consist of the following: +Operating Leases Finance Leases Total +(in thousands) +2021 $ 7,055 $ 1,557 $ 8,612 +2022 5,516 933 6,449 +2023 1,559 655 2,214 +2024 950 139 1,089 +2025 950 10 960 +Thereafter 748 — 748 +Total lease payments 16,778 3,294 20,072 +Less: Interest and discount ( 1,197 ) ( 126 ) ( 1,323 ) +Present value of lease liabilities $ 15,581 $ 3,168 $ 18,749 +93 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 11 - ASSET RETIREMENT OBLIGATIONS +The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interests in crude oil and natural gas properties: +Year Ended December 31, +2020 2019 +(in thousands) +Beginning balance $ 127,251 $ 115,021 +Obligations incurred with development activities and other 6,494 4,605 +Obligations incurred with acquisition 47,673 2,882 +Accretion expense 10,072 6,117 +Revisions in estimated cash flows 4,742 28,991 +Obligations discharged with asset retirements ( 28,888 ) ( 23,426 ) +Obligations discharged with divestitures ( 774 ) ( 6,939 ) +Balance at December 31 166,570 127,251 +Current portion ( 33,933 ) ( 32,200 ) +Long-term portion $ 132,637 $ 95,051 +Our estimated asset retirement obligations liability is based on historical experience in plugging and abandoning wells, estimated economic lives and estimated plugging, abandonment and surface reclamation costs considering federal and state regulatory requirements in effect at that time. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations liability, a corresponding adjustment is made to the properties and equipment balance. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as accretion expense. Short-term asset retirement obligations are included in other accrued expenses in our consolidated balance sheets. +The revisions in estimated cash flows for 2019 were primarily due to increases in the estimated surface reclamation costs to obtain final well pad reclamation approval from the applicable regulatory agencies. +94 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 12 - COMMITMENTS AND CONTINGENCIES +The following table presents gross volume information related to our long-term firm transportation, sales and processing agreements for pipeline capacity and water delivery and disposal commitments: +Year Ending December 31, +Area 2021 2022 2023 2024 2025 Thereafter Total Expiration +Date +Natural gas (MMcf) +Wattenberg Field 64,014 64,014 64,014 64,189 52,045 18,779 327,055 August 31, 2026 +Delaware Basin 31,025 9,125 9,125 9,150 9,125 45,650 113,200 December 31, 2030 +Gas Marketing 1,777 1,183 — — — — 2,960 August 31, 2022 +Total 96,816 74,322 73,139 73,339 61,170 64,429 443,215 +Crude oil (MBbls) +Wattenberg Field 17,002 15,330 11,655 9,882 9,855 6,561 70,285 August 31, 2026 +Delaware Basin 8,030 8,030 8,030 — — — 24,090 December 31, 2023 +Total 25,032 23,360 19,685 9,882 9,855 6,561 94,375 +Water (MBbls) +Wattenberg Field 6,207 6,207 6,207 6,223 — — 24,844 December 31, 2024 +Total 6,207 6,207 6,207 6,223 — — 24,844 +Dollar commitment (in thousands) +$ 135,435 $ 114,472 $ 95,082 $ 68,175 $ 56,174 $ 47,489 $ 516,827 +Firm Transportation and Processing Agreements. We enter into contracts that provide firm transportation and processing on pipeline systems through which we transport or sell crude oil and natural gas. Satisfaction of the volume requirements includes volumes produced by us and purchased from third parties and produced by other third-party working, royalty and overriding royalty interest owners, whose volumes we market on their behalf. Our consolidated statements of operations reflect our share of these firm transportation and processing costs. These contracts require us to pay these transportation and processing charges whether or not the required volumes are delivered. We may from time to time find ourselves unable to market our commodities at prices acceptable to us, or at all, which could cause us to be unable to meet these obligations. In such cases, we may be subject to fees, minimum margins or other payments. +Facilities Expansion Agreements. We entered into two facilities expansion agreements with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities in the Wattenberg Field. The midstream provider completed and turned on line the first of the two 200 MMcfd cryogenic plants in August 2018 and the second plant was completed in August 2019. We are bound to the volume requirements in these agreements on the first day of the calendar month following the actual in-service date of the relevant plant. Both agreements require baseline volume commitments, consisting of our gross wellhead volume delivered in November 2016 to this midstream provider, and incremental wellhead volume commitments of 51.75 MMcfd and 33.5 MMcfd for the first and second agreements, respectively, for seven years. In addition, as a result of the SRC Acquisition, we are subject to substantially similar facilities expansion agreements with the same primary midstream provider of 46.4 MMcfd and 43.8 MMcfd, respectively. We may be required to pay shortfall fees for any volumes under 98.2 MMcfd and 77.3 MMcfd incremental commitments. Any shortfall in these volume commitments may be offset by other producers' volumes sold to the midstream provider that are greater than a certain total baseline volume. We are also required for the first three years of the contracts to guarantee a certain target profit margin to the midstream provider on these incremental volumes. The actual shortfall in target profit margin incurred, which we guaranteed to our midstream provider, was included as part of contract assets as part of Other assets on the consolidated balance sheets. +Firm sales agreement . In May 2018, we entered into a firm sales agreement that is effective from June 2018 through December 2023 with an integrated marketing company for our crude oil production in the Delaware Basin. Contracted volumes are currently 24,000 barrels of crude oil per day and decrease over time to 22,000 barrels per day. This agreement is expected to +95 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +provide price diversification through realization of export market pricing via a Corpus Christi terminal and exposure to Brent-weighted prices. +Crude Oil, Natural Gas and NGLs Sales . For the years ended December 31, 2020 and 2019, amounts related to long-term transportation volumes, net to our interest, in the table above were $ 22.2 million and $ 50.1 million, respectively, and were netted against our crude oil and natural gas sales. In addition, amounts related to long-term transportation volumes recorded in transportation, gathering and processing expenses amounted to $ 15.7 million and $ 1.9 million for the years ended December 31, 2020 and 2019, respectively. +Litigation and Legal Items. We are involved in various legal proceedings. We review the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in our best interests. We have provided the necessary estimated accruals in the accompanying consolidated balance sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity. +Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as discussed herein, we are not aware of any material environmental claims existing as of December 31, 2020 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws or other environmental liabilities will not be discovered on our properties. Accrued environmental liabilities are recorded in other accrued expenses in the consolidated balance sheets. +In recent years, we have been executing a program to plug and abandon certain of our older vertical wells in the Wattenberg Field. A self-audit of final reclamation activities associated with site retirements, which we concluded in 2019, identified deficiencies, including incomplete documentation and agency submittals, inadequate plant growth and incomplete earthwork. In December 2019, we formally disclosed these deficiencies to the Colorado Oil and Gas Conservation Commission ("COGCC") and are working to close this backlog of site reclamation work. On August 19, 2020, COGCC issued to PDC a Notice of Alleged Violation ("NOAV") citing a failure to comply with reclamation requirements at multiple locations. During 2020, we similarly assessed and identified deficiencies in reclamation activities at sites acquired through the SRC Acquisition. We do not believe potential penalties and other expenditures associated with the deficiencies disclosed to the COGCC and the resulting NOAV, nor any potential future disclosure of deficiencies associated with reclamation of sites acquired in the SRC Acquisition, will have a material effect on our financial condition or results of operations, but they may exceed $300,000. +As part of our integration activities over the facilities acquired through the SRC Acquisition, we are in the process of conducting a comprehensive air quality compliance audit. We do not believe potential penalties and other expenditures associated with deficiencies identified through the audit will have a material effect on our financial condition or results of operations, but they may exceed $300,000. +Clean Air Act Agreement and Related Consent Decree. In June 2017, following our receipt of a 2015 Clean Air Act information request from the EPA and a 2015 compliance advisory from the Colorado Department of Public Health and Environment's (“CDPHE”) Air Pollution Control Division, the U.S. Department of Justice, on behalf of the EPA and the state of Colorado, filed a complaint against us in the U.S. District Court for the District of Colorado, claiming that we failed to operate and maintain certain condensate collection facilities at 65 facilities so as to minimize leakage of volatile organic compounds in compliance with applicable law. +In October 2017, we entered into a consent decree to resolve the lawsuit and the compliance advisory. Pursuant to the consent decree, we agreed to implement a variety of operational enhancements and environmental mitigations and similar projects, including vapor control system modifications and verification, increased inspection and monitoring and installation of tank pressure monitors. While many of those actions are complete, some requirements will continue until the consent decree is terminated. +96 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +In addition, as a result of the SRC Acquisition, we are subject to the obligations and requirements of a 2018 Compliance Order on Consent ("COC") entered into by SRC with CDPHE, applicable to certain SRC oil and gas production facilities. The CDPHE revised the COC to make the inspection and monitoring requirements, among others, consistent with those contained in our consent decree. +Since the consent decree took effect, and more recently was expanded to include the COC, we have timely implemented the various programs that meet its requirements. Over the course of this execution, we have identified certain immaterial deficiencies in our implementation of the programs. We report these immaterial deficiencies to the appropriate authorities and remediate them promptly. We do not believe that the penalties and expenditures associated with the consent decree, including any sanctions associated with these deficiencies, will have a material effect on our financial condition or results of operations, but they may exceed $300,000. +Further, we could be the subject of other enforcement actions by regulatory authorities in the future relating to our past, present or future operations. +NOTE 13 - COMMON STOCK +Stock-Based Compensation Plans +2018 Equity Incentive Plan . In May 2020, our stockholders approved an amendment to increase the number of shares of our common stock reserved for issuance pursuant to our long-term equity compensation plan for employees and non-employee directors (the “2018 Plan”) from 1,800,000 to 7,050,000 . The 2018 Plan was approved in May 2018 and expires in March 2028. The capital stock available for issuance under the 2018 Plan shall be shares of the Company’s authorized but unissued common stock or previously issued common stock that has been reacquired by the Company. Additionally, to the extent that an award under the 2018 Plan, in whole or in part, is canceled, expired, forfeited, settled in cash or otherwise terminated without delivery of shares, the shares are not deemed to have been delivered under the 2018 Plan and remain available for issuance. Any shares withheld for taxes cannot be recycled under this plan. Awards may be issued in the form of options, stock appreciation rights ("SARs"), restricted stock, restricted stock units ("RSUs"), performance stock units ("PSUs") and other stock-based awards. Awards may vest over periods of continued service or upon the satisfaction of performance conditions set at the discretion of the Compensation Committee of the board of directors (the "Compensation Committee"), with a minimum one-year vesting period applicable to most awards. With regard to SARs and options, awards have a maximum exercisable period of ten years. As of December 31, 2020, there were 5,204,837 shares available for grant under the 2018 Plan. +2010 Long-Term Equity Compensation Plan . Our Amended and Restated 2010 Long-Term Equity Compensation Plan, which was approved by stockholders in 2013 (the "2010 Plan"), remains outstanding and we may continue to use the 2010 Plan to grant awards. No awards may be granted under the 2010 Plan on or after June 5, 2023. As of December 31, 2020, there were 189,154 shares available for grant under the 2010 Plan. +2015 SRC Equity Incentive Plan . Pursuant to the closing of the SRC Acquisition, SRC granted 155,928 PSUs to certain SRC executives under the 2015 SRC Equity Incentive Plan (the “2015 SRC Plan”). These PSUs (the “SRC PSUs”) were granted prior to the consummation of the merger, were assumed and converted into PDC PSUs at a rate of 0.158 per share and remain subject to the same terms and conditions (including performance-vesting terms) that applied immediately prior to the closing of the SRC Acquisition. The PSUs will result in a payout between zero and 200 percent of the target PSUs awarded. As of December 31, 2020, there were no shares available for grant under the 2015 SRC Plan. +97 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented: +Year Ended December 31, +Stock-based compensation expense included in: 2020 2019 2018 +(in thousands) +General and administrative expense $ 21,182 $ 22,754 $ 20,848 +Lease operating expenses 1,018 1,083 934 +Total stock-based compensation expense $ 22,200 $ 23,837 $ 21,782 +Restricted Stock Units +The Company grants to executive officers and employees, time-based RSUs, which vest ratably over a three-year service period. The fair value for these time-based RSUs is based on the market price of our common stock on the grant date and are recognized ratably over the requisite service period. The time-based RSUs generally vest ratably on each anniversary following the grant date provided that a participant is continuously employed. +The following table presents the changes in non-vested time-based RSUs, including executive officers, during the year ended December 31, 2020: +Shares Weighted-Average Grant Date Fair Value per Share +Non-vested at December 31, 2019 795,926 $ 45.51 +Granted 1,203,108 11.98 +Vested ( 534,610 ) 38.08 +Forfeited ( 313,454 ) 22.62 +Non-vested at December 31, 2020 1,150,970 20.14 +The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: +As of/Year Ended December 31, +2020 2019 2018 +(in thousands, except per share data) +Total intrinsic value of time-based awards vested $ 7,312 $ 11,652 $ 12,282 +Total intrinsic value of time-based awards non-vested 23,629 20,829 18,404 +Market price per share as of December 31, 20.53 26.17 29.76 +Weighted-average grant date fair value per share 11.98 40.34 50.69 +Total compensation cost related to non-vested time-based awards and not yet recognized in our consolidated statements of operations as of December 31, 2020 was $ 13.0 million. This cost is expected to be recognized over a weighted-average period of 1.8 years. +Performance Stock Units +The Company grants to certain executive officers PSUs which are subject to market-based vesting criteria as well as a three-year service period. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved. The fair value of the market-based PSUs is amortized ratably over the requisite service period. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. +98 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The Compensation Committee awarded a total of 368,077 market-based PSUs to our executive officers during 2020. In addition to continuous employment, the vesting of these PSUs is contingent on a combination of absolute stock performance and our total stockholder return ("TSR"), which is essentially our stock price change including any dividends over a three-year period ending on December 31, 2022, as compared to the TSR of a group of peer companies over the same period. The PSUs will result in a payout between zero and 250 percent of the target PSUs awarded. +The grant-date fair value was estimated using a Monte Carlo valuation model. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our common stock historical volatility. +The following table summarizes the key assumptions and related information used to determine the grant-date fair value of performance stock units awarded during the periods presented: +Year Ended December 31, +2020 2019 2018 +Expected term of award (in years) 3 3 3 +Risk-free interest rate 1.4 % 2.5 % 2.4 % +Expected volatility 46.6 % 41.4 % 42.3 % +Weighted-average grant date fair value per share $ 33.52 $ 56.68 $ 69.98 +SRC Performance Stock Units. The terms of the SRC PSUs are substantially the same as those of the PDC PSUs, except that the SRC PSUs do not require continuous employment and the performance period associated with the awards of January 1, 2019 through December 31, 2021 predates the grant date . The fair value of the SRC PSU awards was determined on the grant date of January 13, 2020 using the Monte Carlo pricing model using the following assumptions: +Year Ended December 31, 2020 +Expected term of awards (in years) 2 +Risk-free interest rate 1.6 % +Expected volatility 56.9 % +Weighted-average grant date fair value per share $ 33.35 +The expected term of the awards is based on the number of years from the grant date through the end of the performance period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant, extrapolated to approximate the life of the awards. The expected volatility was based on our common stock historical volatility, as well as that of our peer group. +The following table presents the change in non-vested market-based awards, including SRC PSUs, during the year ended December 31, 2020: +Shares Weighted-Average Grant Date Fair Value per Share +Non-vested at December 31, 2019 221,142 $ 61.61 +Granted 524,005 30.29 +Vested ( 156,003 ) 38.59 +Forfeited ( 89,597 ) 46.43 +Non-vested at December 31, 2020 499,547 38.66 +99 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the weighted-average grant date fair value per share and related information as of/for the periods presented: +As of/Year Ended December 31, +2020 2019 2018 +(in thousands, except per share data) +Total intrinsic value of market-based awards vested $ 1,736 $ 530 $ 620 +Total intrinsic value of market-based awards non-vested 10,256 5,787 3,063 +Market price per share as of December 31, 20.53 26.17 29.76 +Weighted-average grant date fair value per share 30.29 56.68 69.98 +Total compensation cost related to non-vested market-based awards not yet recognized in our consolidated statements of operations as of December 31, 2020 was $ 7.6 million. This cost is expected to be recognized over a weighted-average period of 1.7 years. +Stock Appreciation Rights +The SARs vest ratably over a three-year period and may generally be exercised at any point after vesting through ten years from the date of issuance. Pursuant to the terms of the awards, upon exercise, the executive officers will receive, in shares of common stock, the excess of the market price of the award on the date of exercise over the market price of the award on the date of issuance. All outstanding SARs as of December 31, 2020 have vested and the related compensation cost has been fully recognized. As of December 31, 2020, there were 210,675 SARs outstanding and exercisable which have a weighted-average exercise price of $ 49.45 and average remaining contractual term of 3.3 years. Outstanding and exercisable SARs have no intrinsic value as of December 31, 2020. +Preferred Stock +We are authorized to issue 50,000,000 shares of preferred stock, par value $ 0.01 per share, which may be issued in one or more series, with such rights, preferences, privileges and restrictions as shall be fixed by the board of directors from time to time. Through December 31, 2020, no shares of preferred stock have been issued. +Stock Repurchase Program +In April 2019, the board of directors approved the acquisition of up to $ 200 million of our outstanding common stock, depending on market conditions (the "Stock Repurchase Program"). Effective upon the closing of the SRC Acquisition, our board of directors approved an increase and extension to the Stock Repurchase Program from $ 200 million to $ 525 million. Repurchases under the Stock Repurchase Program can be made in open markets at our discretion and in compliance with safe harbor provisions, or in privately negotiated transactions. The Stock Repurchase Program does not require any specific number of shares to be acquired, and can be modified or discontinued by the board of directors at any time. Pursuant to the Stock Repurchase Program, we repurchased 1.3 million shares and 4.7 million shares of outstanding common stock at a cost of $ 23.8 million and $ 154.4 million during the years ended December 31, 2020 and 2019, respectively. We suspended the program in March 2020. However, we reinstated the program in late February 2021. Repurchases may extend until December 31, 2023. As of December 31, 2020, $346.8 million of our outstanding common stock remained available for repurchase under the Stock Repurchase Program. +100 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 14 - INCOME TAXES +The table below presents the components of our provision for income tax (expense) benefit for the years presented: +Year Ended December 31, +2020 2019 2018 +(in thousands) +Current: +Federal $ 1,592 $ 1,366 $ 887 +State ( 220 ) ( 300 ) ( 188 ) +Total current income tax benefit 1,372 1,066 699 +Deferred: +Federal 5,460 4,507 ( 1,986 ) +State 1,070 ( 2,251 ) ( 4,119 ) +Total deferred income tax (expense) benefit 6,530 2,256 ( 6,105 ) +Income tax (expense) benefit $ 7,902 $ 3,322 $ ( 5,406 ) +The following table presents a reconciliation of the federal statutory rate to the effective tax rate related to our (expense) benefit for income taxes: +Year Ended December 31, +2020 2019 2018 +Federal statutory tax rate 21.0 % 21.0 % 21.0 % +State income tax, net 3.0 3.6 ( 6.4 ) +Federal tax credits — ( 3.3 ) ( 52.1 ) +Effect of state income tax rate changes 0.2 ( 6.4 ) 6.7 +Change in valuation allowance ( 22.1 ) ( 0.6 ) 45.5 +Non-deductible compensation ( 0.6 ) ( 5.0 ) 21.8 +Non-deductible acquisition costs ( 0.1 ) ( 2.3 ) — +Non-deductible government relations ( 0.1 ) ( 1.0 ) 31.8 +Other non-deductible items — ( 0.5 ) 4.9 +Other ( 0.2 ) — ( 0.4 ) +Effective tax rate 1.1 % 5.5 % 72.8 % +The effective income tax rates for 2020 and 2019 were 1.1 percent and 5.5 percent on the respective pre-tax losses. The effective tax rate of 1.1 percent for 2020 differs from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21 percent to the pre-tax loss due to the full valuation allowance in effect at December 31, 2020. The effective tax rate of 5.5 percent for 2019 differs from the statutory U.S. federal income tax rate of 21 percent due to state income taxes, non-deductible lobbying expenses, stock-based compensation and nondeductible officers’ compensation. +101 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Tax effects of temporary differences that give rise to significant portions of deferred tax assets and deferred tax liabilities as of the dates indicated: +December 31, +2020 2019 +(in thousands) +Deferred tax assets: +Deferred compensation $ 10,472 $ 9,905 +Asset retirement obligations 39,371 30,993 +Federal NOL carryforward 97,880 22,965 +State NOL and tax credit carryforwards, net 21,034 9,508 +Federal tax - credit carryforwards 3,059 4,448 +Net change in fair value of unsettled commodity derivatives 18,351 — +Prepaid revenue 4,364 4,874 +Other 5,741 3,887 +Valuation allowance ( 165,575 ) ( 3,775 ) +Total gross deferred tax assets 34,697 82,805 +Deferred tax liabilities: +Properties and equipment 33,183 268,234 +Net change in fair value of unsettled commodity derivatives — 6,841 +Convertible debt 1,514 3,571 +Total gross deferred tax liabilities 34,697 278,646 +Net deferred tax liability $ — $ 195,841 +The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the +periods in which those temporary differences become deductible. At each reporting period, management considers the +scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future +taxable income in making this assessment. As previously noted, we recorded impairments totaling $ 882.4 million in 2020. These impairments resulted in three years of cumulative historical pre-tax losses and a net deferred tax asset position. The impairment losses were a key consideration that led us to continue to provide a valuation allowance against our net deferred tax assets as of December 31, 2020 since we cannot conclude that it is more likely than not that our net deferred tax asset will be fully realized in future periods. As a result, we recorded a $ 7.9 million benefit in 2020 to increase our deferred tax valuation allowance to $ 165.6 million and reduce the carrying value of our deferred tax assets to zero. +As of December 31, 2020, we have estimated net operating loss carryfowards ("NOLs") for federal income tax purposes of $ 466 million, of which $304 million was generated before January 1, 2018 and is not subject to the 80 percent limitation of taxable income. Such NOLs will expire beginning 2033. In 2016, we acquired a federal NOL of $ 60.1 million as a component of our acquisition in the Delaware Basin that will begin to expire in 2033. Also, we acquired a federal NOL of $ 232.5 million as component of the SRC Acquisition that will begin to expire in 2037. The federal NOLs acquired as part of our acquisition in the Delaware Basin and the SRC Acquisition are subject to an annual limitation of $ 15.1 million and $ 16.1 million, respectively, as both acquisitions constitute a change of ownership as defined under Internal Revenue Service ("IRS") Code Section 382. +As of December 31, 2020, we have state NOL carryforwards of $ 494.8 million that begin to expire in 2029 and state credit carryforwards of $ 3.7 million that begin to expire in 2022. +Unrecognized tax benefits and related accrued interest and penalties were immaterial for the three-year period ended December 31, 2020. The statutes of limitations for most of our state tax jurisdictions are open for tax year 2017 forward. As of December 31, 2020, there is no liability for unrecognized income tax benefits. +We are subject to the following material taxing jurisdictions: U.S., Colorado, West Virginia, and Texas. As of December 31, 2020, we are current with our income tax filings in all applicable state jurisdictions and are not currently under +102 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +any state income tax examinations. We are open to federal and state tax audits until the applicable statutes of limitations expire, however, the ability for the tax authority to adjust the NOL will continue until three years after NOL is utilized. The statute of limitations has expired for all federal and state returns filed for periods ending before 2016. The IRS has partially accepted our 2019 federal income tax return. The 2019 federal tax return is in the IRS Compliance Assurance Program (the “CAP Program”) post-filing review process, with no significant tax adjustments currently proposed. We continue to voluntarily participate in the IRS CAP Program for the review of our 2020 tax year. Participation in the IRS CAP Program has enabled us to have minimal uncertain tax benefits associated with our federal tax return filings. +NOTE 15 - EARNINGS PER SHARE +Basic earnings per share is computed by dividing net earnings by the weighted-average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested equity-based employee awards, convertible notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. +The following table presents our weighted-average basic and diluted shares outstanding for the periods presented: +Year Ended December 31, +2020 2019 2018 +(in thousands) +Weighted-average common shares outstanding - basic 98,251 64,032 66,059 +Dilutive effect of: +RSUs and PSUs — — 173 +Other equity-based awards — — 71 +Weighted-average common shares and equivalents outstanding - diluted 98,251 64,032 66,303 +We reported a net loss for the years ended December 31, 2020 and 2019. As a result, our basic and diluted weighted-average common shares outstanding were the same for those periods because the effect of the common share equivalents was anti-dilutive. +The following table presents the weighted-average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect for the periods presented: +Year Ended December 31, +2020 2019 2018 +(in thousands) +Weighted-average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: +RSUs and PSUs 1,707 989 145 +Other equity-based awards 229 302 109 +Total anti-dilutive common share equivalents 1,936 1,291 254 +The 2021 Convertible Notes give the holders, at our election, the right to convert the aggregate principal amount into 2.3 million shares of our common stock at a conversion price of $ 85.39 per share. The 2021 Convertible Notes were not included in the diluted earnings per share calculation using the treasury stock method for any periods presented as the average market price of our common stock did not exceed the conversion price. +103 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 16 - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION +Year Ended December 31, +2020 2019 +2018 (1) +(in thousands) +Supplemental cash flow information: +Cash payments (receipts) for: +Interest, net of capitalized interest $ 75,506 $ 57,439 $ 55,586 +Income taxes 9 ( 1,167 ) ( 6,719 ) +Non-cash investing and financing activities: +Issuance of common stock for acquisition of crude oil and natural gas properties, net 1,009,015 — — +Change in accounts payable related to capital expenditures ( 28,676 ) ( 68,246 ) 36,328 +Change in asset retirement obligations, with a corresponding change to crude oil and natural gas properties, net of disposals 54,984 29,533 37,136 +Cash paid for amounts included in the measurement of lease liabilities: +Operating cash flows from operating leases $ 9,246 $ 5,301 $ — +Operating cash flows from finance leases 156 253 — +ROU assets obtained in exchange for lease obligations: +Operating leases $ 4,305 $ 1,428 $ — +Finance leases 703 2,323 — +____________ +(1) As we have elected the modified retrospective method of adoption for ASU 2016-02, Leases, cash flows related to lease liabilities have not been restated for 2018. +104 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +CRUDE OIL AND NATURAL GAS INFORMATION - UNAUDITED +Net Proved Reserves +All of our crude oil, natural gas and NGLs reserves are located in the United States. We utilize the services of independent petroleum engineers to estimate our crude oil, natural gas and NGLs reserves. As of December 31, 2020, 2019 and 2018 (as applicable), all of our estimates of proved reserves for the Wattenberg Field were based on reserve reports prepared by Ryder Scott and all of our estimates for proved reserves for the Delaware Basin were based on reserve reports prepared by NSAI. These reserve estimates have been prepared in compliance with guidelines established by the SEC and FASB. All of our proved undeveloped reserves conform to the SEC five-year rule requirement that they be scheduled to be drilled within five years of each location’s initial booking date. +Reserve estimates are based on an unweighted arithmetic average of commodity prices during the preceding 12-month period, using the closing prices on the first day of each month, as required by the SEC. The table below presents the index prices for our estimated reserves, by commodity, as of the dates indicated: +Average Benchmark Prices +December 31, +Crude Oil +(per Bbl) (1) +Natural Gas +(per MMBtu) (1) +NGLs +(per Bbl) (2) +2020 $ 39.57 $ 1.99 $ 39.57 +2019 55.69 2.58 55.69 +2018 65.56 3.10 65.56 +____________ +(1) Our benchmark prices for crude oil and natural gas are WTI and Henry Hub, respectively. +(2) For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. +The netted back price used to estimate our reserves, by commodity, are presented below. +Price Used to Estimate Reserves (1) +December 31, Crude Oil +(per Bbl) Natural Gas +(per MMBtu) +NGLs +(per Bbl) +2020 $ 37.52 $ 1.26 $ 10.55 +2019 52.63 1.50 12.21 +2018 61.14 2.15 23.04 +____________ +(1) These prices are based on the index prices and are net of basin differentials, transportation fees, contractual adjustments and Btu adjustments we experienced for the respective commodity, including consideration for contracts that are effective as of December 31, 2020. +105 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +The following tables present the changes in our estimated quantities of proved reserves: +Crude Oil, Condensate (MBbls) Natural Gas +(MMcf) NGLs +(MBbls) Total +(MBoe) +Proved reserves, January 1, 2018 154,842 1,154,294 105,692 452,917 +Revisions of previous estimates 26,548 94,738 12,674 55,011 +Extensions, discoveries and other additions 8,786 61,750 8,868 27,946 +Acquisition of reserves 19,644 148,674 15,936 60,360 +Dispositions (2,507) (35,750) (2,656) (11,121) +Production (16,964) (88,017) (8,527) (40,160) +Proved reserves, December 31, 2018 190,349 1,335,689 131,987 544,953 +Revisions of previous estimates 25,875 328,290 31,559 112,147 +Extensions, discoveries and other additions 1,056 10,262 1,519 4,285 +Acquisition of reserves 553 4,558 448 1,761 +Dispositions (1,412) (5,052) (614) (2,868) +Production (19,166) (115,950) (10,923) (49,414) +Proved reserves, December 31, 2019 197,255 1,557,797 153,976 610,864 +Revisions of previous estimates (41,089) (272,243) (14,774) (101,237) +Extensions, discoveries and other additions 812 2,991 324 1,635 +Acquisition of reserves 80,590 795,977 81,770 295,023 +Dispositions (2,116) (17,711) (1,776) (6,844) +Production (23,720) (165,637) (17,042) (68,368) +Proved reserves, December 31, 2020 211,732 1,901,174 202,478 731,073 +Proved developed reserves, as of: +December 31, 2018 61,821 443,151 43,856 179,535 +December 31, 2019 66,211 554,234 55,411 213,994 +December 31, 2020 86,330 860,877 91,702 321,512 +Proved undeveloped reserves, as of: +December 31, 2018 128,528 892,538 88,131 365,418 +December 31, 2019 131,044 1,003,563 98,565 396,870 +December 31, 2020 125,402 1,040,297 110,776 409,561 +106 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Developed Undeveloped Total +(MBoe) +Proved reserves, January 1, 2018 142,971 309,946 452,917 +Revisions of previous estimates 6,284 48,727 55,011 +Extensions, discoveries and other additions 7,874 20,072 27,946 +Acquisition of reserves 8,758 51,602 60,360 +Dispositions (4,486) (6,635) (11,121) +Production (40,160) — (40,160) +Undeveloped reserves converted to developed 58,294 (58,294) — +Proved reserves, December 31, 2018 179,535 365,418 544,953 +Revisions of previous estimates 27,452 84,695 112,147 +Extensions, discoveries and other additions 4,285 — 4,285 +Acquisition of reserves 441 1,320 1,761 +Dispositions (474) (2,394) (2,868) +Production (49,414) — (49,414) +Undeveloped reserves converted to developed 52,169 (52,169) — +Proved reserves, December 31, 2019 213,994 396,870 610,864 +Revisions of previous estimates (8,634) (92,603) (101,237) +Extensions, discoveries and other additions 1,635 — 1,635 +Acquisition of reserves 125,180 169,843 295,023 +Dispositions (2,487) (4,357) (6,844) +Production (68,368) — (68,368) +Undeveloped reserves converted to developed 60,192 (60,192) — +Proved reserves, December 31, 2020 321,512 409,561 731,073 +2020 Activity. During 2020, we increased proved reserves by 120.2 MMBoe, or 20 percent, relative to December 31, 2019. The increase in proved reserves was primarily the result of the SRC Acquisition, partially offset by downward revisions of previous estimates. In 2020, we produced 68.4 MMBoe. +Revisions of Previous Estimates- Proved Developed Reserves. Proved developed reserves experienced a net negative revision of 8.6 MMBoe primarily due to a decrease of 28.2 MMBoe as a result of lower average prices for crude oil, natural gas and NGLs for 2020. The negative revisions were partially offset by a 14.3 MMBoe increase associated with lower operating costs and a 5.3 MMBoe increase related to performance revisions and other items. +Revisions of Previous Estimates- PUDs. Net downward revisions to our previous PUD reserves estimates of 92.6 MMBoe were due to (i) 266.7 MMBoe related to PUD locations that were reclassified to unproven reserves due to drilling schedule changes, (ii) a reduction of 25.5 MMBoe of reserves primarily related to DUCs which were not completed within five years of their initial recording in accordance with SEC rules, and (iii) 11.3 MMBoe related to downward pricing adjustments due to lower average prices for crude oil, natural gas and NGLs for 2020. Drilling schedule changes resulted from PUD downgrades associated with lower realized prices and revised drilling plans following the completion of the SRC Acquisition. The negative revisions were partially offset by a 199.9 MMBoe increase related to additional locations on proved acreage resulting from our drilling plan and 11.0 MMBoe related to performance revisions and other items. +Extensions, Discoveries and Other Additions- Proved Developed Reserves. Developed activity for 2020 included the addition of 1.6 MMBoe of developed reserves related to two gross newly-drilled wells in the Delaware Basin. +Extensions, Discoveries and Other Additions- PUDs. There were no extensions, discoveries or other additions for PUD reserves during 2020. +Acquisitions of Reserves- Proved Developed Reserves. Proved developed reserves acquired primarily pertain to the SRC Acquisition completed in January 2020. +Acquisitions of Reserves- PUDs. Proved undeveloped reserves acquired primarily pertain to the SRC Acquisition completed in January 2020. +107 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Dispositions- Proved Developed Reserves . Dispositions of 2.5 MMBoe were related to a divestiture and acreage surrendered in various acreage exchanges. +Dispositions- PUDs. Dispositions of 4.4 MMBoe were related to a divestiture and acreage surrendered in various acreage exchanges. +At December 31, 2019, we projected a PUD reserve conversion rate of 26 percent for 2020. During 2020, our actual conversion rate was 11 percent primarily due to a change in our drilling plan in April 2020 relating to decreased commodity prices and crude oil demand which resulted in a smaller number of wells turned-in-line than originally anticipated. We converted 60.2 MMBoe of PUD reserves at December 31, 2019 to proved developed reserves as of December 31, 2020. +Based on economic conditions on December 31, 2020, our approved development plan provides for the development of our remaining PUD locations within five years of the date such reserves were initially recorded. As of December 31, 2020, our 2021 PUD reserve conversion rate is expected to be approximately 22 percent . The balance of the PUD reserves are scheduled to be developed over the remaining four years in accordance with our current development plan. The level of capital spending necessary to achieve this drilling schedule is consistent with our recent performance and our outlook for future development activities. +2019 Activity. During 2019, we increased proved reserves by 65.9 MMBoe, or 12 percent, relative to December 31, 2018. The increase in proved reserves was primarily a result of our 2019 development activities and our future +drilling schedule. In 2019, we produced 49.4 MMBoe. +Revisions of Previous Estimates- Proved Developed Reserves. Proved developed reserves experienced a positive revision of 28.3 MMBoe reflecting improved performance revisions, decreased operating costs and other items. An additional increase of 10.2 MMBoe in developed reserves related to our current year drilling activities. These positive revisions were partially offset by a decrease of 11.0 MMBoe for decreases in prices for crude oil, natural gas and NGLs. +Revisions of Previous Estimates- PUDs. Upward revisions to our PUD reserves were related to an increase of 74.2 MMBoe reflecting additional locations on proven acreage resulting from our drilling plan, as well as improved performance revisions and other items, which resulted in further upward revisions of 28.9 MMBoe of PUD reserves. Partially offsetting these increases were negative revisions of 12.9 MMBoe due to drilling schedule changes and 5.5 MMBoe for decreases in prices for crude oil, natural gas and NGLs. +Extensions, Discoveries and Other Additions- Proved Developed Reserves. Developed activity for 2019 included the addition of 4.3 MMBoe of developed reserves related to three gross (three net) newly-drilled wells. +Extensions, Discoveries and Other Additions- PUDs. There were no extensions, discoveries or other additions for PUD reserves during 2019. +Acquisitions of Reserves- Proved Developed Reserves. Proved developed reserves acquired in various acreage exchanges and acquisitions were 0.4 MMBoe during 2019. +Acquisitions of Reserves- PUDs. We acquired 1.3 MMBoe of PUD reserves in 2019 in acreage exchanges and acquisitions. +Dispositions- Proved Developed Reserves . Dispositions of 0.5 MMBoe were related to a divestiture and acreage surrendered in various acreage exchanges. +Dispositions- PUDs. Dispositions of 2.4 MMBoe were related to a divestiture and acreage surrendered in various acreage exchanges. +2018 Activity. During 2018, we increased proved reserves by 92.0 MMBoe, or 20 percent, relative to December 31, 2017. The increase in proved reserves was primarily a result of acreage exchange transactions and acquisitions in the Wattenberg Field and reserve additions on proved acreage resulting from our 2018 development activities. In 2018, we produced 40.2 MMBoe. +108 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Revisions of Previous Estimates- Proved Developed Reserves. Proved developed reserves experienced a net positive revision of 11.4 MMBoe due to an increase in prices for crude oil, natural gas and NGLs, offset by net negative revisions of 5.1 MMBoe for an increase in operating costs, performance revisions and other items. +Revisions of Previous Estimates- PUDs. Upward revisions to our PUD reserves were related to an increase of 71.7 MMBoe reflecting newly-booked locations on proven acreage resulting from our drilling activities. Partially offsetting this increase was a negative revision of 26.8 MMBoe in the Wattenberg Field due to drilling schedule changes and updated timing for development of certain locations exceeding the five-year rule. Drilling schedule changes, primarily related to 2018 acreage exchanges, resulted in these locations being reclassified from proved to unproved status. All other changes were due to commodity pricing, lease operating expenses and type curve revisions, which resulted in further upward revisions of 3.8 MMBoe of PUD reserves. +Extensions, Discoveries and Other Additions- Proved Developed Reserves. Developed additions for 2018 included the addition of 7.9 MMBoe of developed reserves related to 17 gross (9.2 net) newly-drilled wells. +Extensions, Discoveries and Other Additions- PUDs . PUD activity was comprised primarily of 20.1 MMBoe of PUD reserves related to 16 gross (15.0 net) PUD locations in the Delaware Basin. +Acquisitions of Reserves- Proved Developed Reserves. Proved developed reserves acquired in various acreage exchanges were 8.8 MMBoe during 2018. +Acquisitions of Reserves- PUDs. We acquired 47.6 MMBoe and 4.0 MMBoe of PUD reserves in 2018 in acreage exchanges and an acquisition, respectively. +Dispositions- Proved Developed Reserves . Dispositions of 4.5 MMBoe were related to a divestiture and acreage surrendered in various acreage exchanges. +Dispositions- PUDs. Dispositions of PUDs were 6.6 MMBoe reflecting divested proved acreage with future locations that were not in our five-year drilling plan as of December 31, 2017 in the acreage exchange transactions. +109 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Results of Operations for Crude Oil and Natural Gas Producing Activities +The results of operations for crude oil and natural gas producing activities are presented below. +Year Ended December 31, +2020 2019 2018 +(in thousands) +Revenues: +Crude oil, natural gas and NGLs sales $ 1,152,555 $ 1,307,275 $ 1,389,961 +Commodity price risk management gain (loss), net 180,270 (162,844) 145,237 +1,332,825 1,144,431 1,535,198 +Expenses: +Lease operating expenses 161,346 142,248 130,957 +Production taxes 59,368 80,754 90,357 +Transportation, gathering and processing expenses 77,835 46,353 37,403 +Exploration expense 1,376 4,054 6,204 +Depreciation, depletion and amortization 611,003 638,499 551,265 +Accretion of asset retirement obligations 10,072 6,117 5,075 +Impairment of properties and equipment 882,393 38,536 458,397 +(Gain) loss on sale of properties and equipment (724) 9,734 394 +1,802,669 966,295 1,280,052 +Results of operations for crude oil and natural gas producing +activities before provision for income taxes (469,844) 178,136 255,146 +Income tax (expense) benefit 5,168 (9,869) (185,667) +Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs $ (464,676) $ 168,267 $ 69,479 +Production costs include those costs incurred to operate and maintain productive wells and related equipment, including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, production and severance taxes and associated administrative expenses. DD&A expense includes those costs associated with capitalized acquisition, exploration and development costs, but does not include the depreciation applicable to support equipment. The provision for income taxes is computed using effective statutory tax rates. +110 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Costs Incurred in Crude Oil and Natural Gas Activities +Costs incurred in crude oil and natural gas property acquisition, exploration and development are presented below. +Year Ended December 31, +2020 2019 2018 +(in thousands) +Acquisition of properties: (1) +Proved properties $ 1,618,000 $ 16,007 $ 205,253 +Unproved properties 114,202 9,567 5,477 +Development costs (2) +528,686 780,851 970,970 +Exploration costs: (3) +Exploratory drilling 12,892 32,218 36,704 +Geological and geophysical 253 3,017 3,401 +Total costs incurred $ 2,274,033 $ 841,660 $ 1,221,805 +____________ +(1) Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property. +(2) Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells and provide facilities to extract, treat, gather and store crude oil, natural gas and NGLs. Of these costs incurred for the years ended December 31, 2020, 2019 and 2018, $270.7 million, $308.9 million and $438.4 million, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. These costs also include approximately, $35.3 million and $74.6 million of infrastructure and pipeline costs in 2019 and 2018 respectively. Our infrastructure and pipeline assets were divested in 2019. +(3) Exploration costs represent costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas and NGLs. These costs include, but are not limited to, dry hole contributions and costs of drilling and equipping exploratory wells. +Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities +Aggregate capitalized costs related to crude oil and natural gas exploration and production activities with applicable accumulated DD&A are presented below as of the dates indicated: +December 31, +2020 2019 +(in thousands) +Proved crude oil and natural gas properties $ 7,523,639 $ 6,241,780 +Unproved crude oil and natural gas properties 350,677 403,379 +Uncompleted wells, equipment and facilities 523,376 382,409 +Capitalized costs 8,397,692 7,027,568 +Accumulated DD&A (3,590,932) (2,982,929) +Capitalized costs, net $ 4,806,760 $ 4,044,639 +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves +The standardized measure below has been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to our year-end estimated proved reserves. Prices for each of the three years were adjusted by field for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of our commodity derivatives. Production and development costs were based on prices as of December 31 for each of the respective years presented. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service or to depreciation, depletion and amortization expense. Production and development costs include those cash flows associated with the expected ultimate settlement of our asset retirement obligations. Future estimated income tax expense is computed by applying the statutory rate in effect at the end of each year to the projected future pre-tax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits and allowances related to the properties. +111 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves. Changes in the demand for crude oil, natural gas and NGLs, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves. +December 31, +2020 2019 2018 +(in thousands) +Future estimated cash flows $ 12,481,830 $ 14,590,604 $ 17,554,880 +Future estimated production costs (1) +(4,209,459) (4,530,173) (4,782,948) +Future estimated development costs (2,337,806) (3,257,106) (3,632,822) +Future estimated income tax expense (301,507) (907,382) (1,404,121) +Future net cash flows 5,633,058 5,895,943 7,734,989 +10% annual discount for estimated timing of cash flows (2,350,879) (2,585,609) (3,287,273) +Standardized measure of discounted future estimated net cash flows $ 3,282,179 $ 3,310,334 $ 4,447,716 +____________ +(1) Represents future estimated lease operating expenses, production taxes and transportation, gathering and processing expenses. +The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows: +Year Ended December 31, +2020 2019 2018 +(in thousands) +Beginning of period $ 3,310,334 $ 4,447,716 $ 2,880,105 +Sales of crude oil, natural gas and NGLs production, net of production costs (854,006) (1,037,920) (1,131,244) +Net changes in prices and production costs (1) +(1,771,019) (2,122,538) 936,077 +Extensions, discoveries and improved recovery, less related costs +14,110 39,606 190,084 +Sales of reserves (26,771) (14,533) (42,362) +Purchases of reserves 1,969,846 18,816 467,807 +Development costs incurred during the period 329,495 605,753 462,088 +Revisions of previous quantity estimates (775,009) 538,242 631,198 +Changes in estimated income taxes 354,369 346,826 (232,002) +Net changes in future development costs 367,630 206,003 (123,663) +Accretion of discount 572,483 532,127 583,744 +Timing and other (209,283) (249,764) (174,116) +End of period $ 3,282,179 $ 3,310,334 $ 4,447,716 +____________ +(1) Our weighted-average price, net of production costs per Boe, in our 2020 reserve report decreased to $11.32 as compared to $16.18 for 2019 and $23.44 for 2018. +The data presented should not be viewed as representing the expected cash flows from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the recent average prices and current costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein. +112 +PDC ENERGY, INC. +QUARTERLY FINANCIAL INFORMATION - UNAUDITED +Quarterly financial data for the years ended December 31, 2020 and 2019 is presented below. The sum of the quarters may not equal the total of the year's net income or loss per share due to changes in the weighted-average shares outstanding throughout the year. +2020 +Quarter Ended +March 31 June 30 September 30 December 31 +(in thousands, except per share data) +Total revenues $ 757,030 $ 54,416 $ 249,217 $ 278,563 +Total costs, expenses and other 1,205,617 250,393 258,802 267,952 +Income (loss) from operations (448,587) (195,977) (9,585) 10,611 +Income (loss) before income taxes (472,760) (217,759) (30,607) (11,096) +Net income (loss) $ (465,015) $ (221,832) $ (30,783) $ (6,690) +Loss per share: +Basic $ (4.94) $ (2.23) $ (0.31) $ (0.07) +Diluted (4.94) (2.23) (0.31) (0.07) +2019 +Quarter Ended +March 31 June 30 September 30 December 31 +(in thousands, except per share data) +Total revenues $ 134,500 $ 390,658 $ 365,943 $ 265,022 +Total costs, expenses and other 275,120 280,623 321,562 267,713 +Income (loss) from operations (140,620) 110,035 44,381 (2,691) +Income (loss) before income taxes (157,588) 91,135 26,570 (20,111) +Net income (loss) $ (120,176) $ 68,548 $ 15,908 $ (20,952) +Earnings (loss) per share: +Basic $ (1.82) $ 1.04 $ 0.25 $ (0.34) +Diluted (1.82) 1.04 0.25 (0.34) +113 +PDC ENERGY, INC. +FINANCIAL STATEMENT SCHEDULE +Schedule II -VALUATION AND QUALIFYING ACCOUNTS +Description Beginning +Balance +January 1, Charged to +Costs and +Expenses +Deductions (1) +Ending +Balance +December 31, +(in thousands) +2020: +Allowance for doubtful accounts $ 7,476 $ 3,179 $ 3,892 $ 6,763 +Allowance for expirations of unproved crude oil and natural gas properties 6,881 223,895 6,757 224,019 +2019: +Allowance for doubtful accounts $ 4,381 $ 3,209 $ 114 $ 7,476 +Allowance for expirations of unproved crude oil and natural gas properties 542,709 8,523 544,351 6,881 +2018: +Allowance for doubtful accounts $ 3,128 $ 1,276 $ 23 $ 4,381 +Allowance for expirations of unproved crude oil and natural gas properties 251,159 388,068 96,518 542,709 +____________ +(1) For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For allowance for expirations of unproved crude oil and natural gas properties, deductions represent actual expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset. +114 +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +As of December 31, 2020, we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Based on the results of this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2020. +Management's Report on Internal Control over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Internal control over financial reporting is a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer, or persons performing similar functions, and effected by our board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate. +Management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2020, based upon the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Based on this evaluation, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2020. +The effectiveness of our internal control over financial reporting as of December 31, 2020 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears under Item 8. +Changes in Internal Control over Financial Reporting +There were no changes in our internal control over financial reporting during the quarter ended December 31, 2020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. +ITEM 9B. OTHER INFORMATION +None. +115 +PART III +ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2021 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 11. EXECUTIVE COMPENSATION +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2021 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2021 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2021 Annual Stockholders' meeting and is incorporated by reference in this report. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2021 Annual Stockholders' meeting and is incorporated by reference in this report. +PART IV +ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES +(a) (1) Exhibits: +See Exhibits Index on the following page. +ITEM 16. FORM 10-K SUMMARY +None. +Exhibits Index +Incorporated by Reference +Exhibit Number Exhibit Description Form SEC File Number Exhibit Filing Date Filed Herewith +2.1 +Plan of Conversion, dated June 5, 2015, by PDC Energy, Inc. +8-K12B 001-37419 2.1 6/8/2015 +2.2 +Agreement and Plan of Merger, dated as of August 25, 2019 by and between PDC Energy, Inc., and SRC Energy Inc. +8-K 001-37419 2.2 8/26/2019 +3.1 +Certificate of Incorporation of PDC Energy, Inc., as amended. +8-K12B 001-37419 3.1 5/27/2020 +3.2 +Bylaws of PDC Energy, Inc. +8-K12B 001-37419 3.2 6/8/2015 +4.1 +Description of Capital Stock +X +4.2 +Form of Common Stock Certificate of PDC Energy, Inc. +10-K 001-37419 4.1.1 2/26/2020 +116 +Incorporated by Reference +Exhibit Number Exhibit Description Form SEC File Number Exhibit Filing Date Filed Herewith +4.3 +Indenture, dated as of November 29, 2017, by and between PDC Energy, Inc., PDC Permian, Inc., a subsidiary guarantor of PDC Energy, Inc., and U.S. Bank Trust National Association, as Trustee, relating to the 5.750% Senior Notes due 2026. +8-K 001-37419 +4.1 11/29/2017 +4.4 +Base Indenture, dated as of September 14, 2016, by and between PDC Energy, Inc. and U.S. Bank Trust National Association, as Trustee. +8-K 001-37419 4.1 9/14/2016 +4.5 +First Supplemental Indenture, dated as of September 14, 2016, by and between PDC Energy, Inc. and U.S. Bank Trust National Association, as Trustee, relating to the 1.125% Convertible Senior Notes due 2021. +8-K 001-37419 4.2 9/14/2016 +4.7 +Indenture, dated as of September 15, 2016, by and between PDC Energy, Inc. and U.S. Bank Trust National Association, as Trustee, relating to the 6.125% Senior Notes due 2024. +8-K 001-37419 4.1 9/15/2016 +4.8 +Indenture, dated as of November 29, 2017, among SRC Energy, Inc. and U.S. Bank National Association as Trustee, relating to the SRC Energy, Inc. 6.250% Senior Notes due 2025. +8-K 001-37419 4.1 11/29/2017 +4.9 +First Supplemental Indenture, dated as of January 14, 2020, among PDC Energy, Inc. and U.S. Bank National Association as Trustee, related to the SRC Energy, Inc. 6.250% Senior Notes due 2025. +8-K 001-37419 4.2 1/14/2019 +10.1 +Form of Indemnification Agreement. +8-K 000-07246 10.1 6/8/2015 +10.2 +401(k) and Profit Sharing Plan, as amended on January 4, 2016. +10-K 001-37419 10.2 2/28/2017 +10.3 +Amended and Restated Non-Employee Director Deferred Compensation Plan. +10-K 001-37419 10.3 2/27/2018 +10.4 +2004 Long-Term Equity Compensation Plan amended and restated as of March 8, 2008 ("2004 Plan"). +10-K 000-07246 10.26 2/27/2009 +10.5 +Summary of 2010 Stock Appreciation Rights and Restricted Stock Awards under the 2004 Plan. +8-K 000-07246 4/23/2010 +10.6 +Amended and Restated 2010 Long-Term Equity Compensation Plan, as amended. +10-K 001-37419 10.5 2/22/2016 +10.7 +Executive Severance Compensation Plan, as amended and restated. +10-Q 001-37419 10.1 8/6/2020 +10.8 +Form of 2011 Restricted Stock/Stock Appreciation Rights Agreement. +10-K 000-07246 10.5.2 2/21/2014 +10.9 +Form of 2013 Restricted Stock/Stock Appreciation Rights Agreement. +10-K 000-07246 10.10 2/27/2013 +10.10 +Form of 2014 Restricted Stock/Stock Appreciation Rights Agreement. +10-K 000-07246 10.5.5 2/19/2015 +10.11 +Form of 2015 Stock Appreciation Rights Agreement. +10-K 000-07246 10.5.8 2/19/2015 +10.12 +Form of 2019 Performance Share Agreement. +10-Q 001-37419 99.1 5/2/2019 +10.14 +Form of 2019 Restricted Stock Unit Agreement (Directors). +10-Q 001-37419 99.2 5/2/2019 +10.15 +Form of 2019 Restricted Stock Unit Agreement (Executives) (Amended and Restated 2010 Long-Term Equity Compensation Plan). +10-Q 001-37419 99.3 5/2/2019 +10.16 +Form of 2019 Restricted Stock Unit Agreement (Executives) (2018 Equity Incentive Plan). +10-Q 001-37419 99.4 5/2/2019 +117 +Incorporated by Reference +Exhibit Number Exhibit Description Form SEC File Number Exhibit Filing Date Filed Herewith +10.17 +SRC Energy, Inc./PDC Energy, Inc. Merger Performance Share Agreement, dated January 13, 2020, by and between PDC Energy, Inc.(as successor to SRC Energy, Inc.) and Lynn A. Peterson. +8-K 001-37419 10.2 1/14/2020 +10.18 +Form of 2020 Performance Share Agreement. +10-Q 001-37419 99.1 5/7/2020 +10.19 +Form of 2020 Restricted Stock Unit Agreement (Executives). +10-Q 001-37419 99.3 5/7/2020 +10.20 +Form of 2020 Restricted Stock Unit Agreement (Directors). +10-Q 001-37419 99.2 5/7/2020 +10.21 +Employment Agreement with Lance A. Lauck, as amended. +10-Q 001-37419 10.2 8/6/2020 +10.22 +2018 Equity Incentive Plan. +8-K 001-37419 10.1 5/31/2018 +10.23 +Amendment No. 1 to PDC Energy, Inc. 2018 Equity Incentive Plan. +8-K 001-37419 +10.1 5/27/2020 +10.24 +SRC Energy Inc. 2015 Equity Incentive Plan. +8-K 001-37419 10.1 1/14/2020 +10.25 +Fourth Amended and Restated Credit Agreement, dated as of May 23, 2018, among PDC Energy, Inc. as Borrower, each of the Lenders party thereto, and JPMorgan Chase Bank, N.A. as Administrative Agent for the Lenders. +8-K 001-37419 10.1 5/25/2018 +10.26 +First Amendment to Fourth Amended and Restated Credit Agreement, dated as August 30, 2019, among PDC Energy, Inc. as Borrower, each of the Lenders party thereto, and JPMorgan Chase Bank, N.A. as Administrative Agent for the Lenders. +8-K 001-37419 10.1 9/4/2019 +10.27 +Second Amendment to Fourth Amended and Restated Credit Agreement, dated as of May 5, 2020 among PDC Energy, Inc. as Borrower, each of the Lenders party thereto, and JPMorgan Chase Bank, N.A. as administrative Agent for the Lenders. +10-Q 001-37419 10 5/7/2020 +21.1 +Subsidiaries. +10-K 001-37419 21.1 2/26/2020 +23.1 +Consent of PricewaterhouseCoopers LLP. +X +23.2 +Consent of Ryder Scott Company, L.P., Petroleum Consultants. +X +23.3 +Consent of Netherland, Sewell & Associates, Inc., Petroleum Consultants. +X +31.1 +Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +31.2 +Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +32.1* +Certifications by Chief Executive Officer and Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. +99.1 +Report of Independent Petroleum Consultants - Ryder Scott Company, L.P. +X +99.2 +Report of Independent Petroleum Consultants - Netherland, Sewell & Associates, Inc. +X +101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document X +101.SCH XBRL Taxonomy Extension Schema Document X +101.CAL XBRL Taxonomy Extension Calculation Linkbase Document X +118 +Incorporated by Reference +Exhibit Number Exhibit Description Form SEC File Number Exhibit Filing Date Filed Herewith +101.DEF XBRL Taxonomy Extension Definition Linkbase Document X +101.LAB XBRL Taxonomy Extension Label Linkbase Document X +101.PRE XBRL Taxonomy Extension Presentation Linkbase Document X +104 Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101) X +* Furnished herewith. +119 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +PDC ENERGY, INC. +By: /s/ Barton Brookman +Barton Brookman +President and Chief Executive Officer +February 24, 2021 +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated: +Signature Title Date +/s/ Barton Brookman President, Chief Executive Officer and Director February 24, 2021 +Barton Brookman (principal executive officer) +/s/ R. Scott Meyers Senior Vice President and Chief Financial Officer February 24, 2021 +R. Scott Meyers (principal financial officer) +/s/ Douglas Griggs Chief Accounting Officer February 24, 2021 +Douglas Griggs (principal accounting officer) +/s/ Mark E. Ellis Chairman and Director February 24, 2021 +Mark E. Ellis +/s/ Anthony J. Crisafio Director February 24, 2021 +Anthony J. Crisafio +/s/ Christina M. Ibrahim Director February 24, 2021 +Christina M. Ibrahim +/s/ Paul J. Korus Director February 24, 2021 +Paul J. Korus +/s/ Randy S. Nickerson Director February 24, 2021 +Randy S. Nickerson +/s/ David C. Parke Director February 24, 2021 +David C. Parke +/s/ Lynn A. Peterson Director February 24, 2021 +Lynn A. Peterson +120 +GLOSSARY OF UNITS OF MEASUREMENT AND INDUSTRY TERMS +UNITS OF MEASUREMENT +The following presents a list of units of measurement used throughout the document. +Bbl – One barrel of crude oil or NGL or 42 gallons of liquid volume. +Bcf – One billion cubic feet of natural gas volume. +Boe – One barrel of crude oil equivalent. +Btu – British thermal unit. +BBtu – One billion British thermal units. +MBoe – One thousand barrels of crude oil equivalent. +MBbls – One thousand barrels of crude oil. +Mcf – One thousand cubic feet of natural gas volume. +MMBoe – One million barrels of crude oil equivalent. +MMBbls – One million barrels of crude oil. +MMBtu – One million British thermal units. +MMcf – One million cubic feet of natural gas volume. +MMcfd – One million cubic feet of natural gas volume per day. +GLOSSARY OF INDUSTRY TERMS +The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report: +Brent - Brent sweet light crude oil. +CIG - Colorado Interstate Gas. +Completion - Refers to the installation of permanent equipment for the production of crude oil and natural gas from a recently drilled well or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned. +Condensate - Liquid hydrocarbons associated with the production that is primarily natural gas. +Developed acreage - Acreage assignable to productive wells. +Development well - A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. +Differentials - The difference between the crude oil and natural gas index spot price and the corresponding cash spot price in a specified location. +Dry well or dry hole - A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well. +Exploratory well - A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. +Extensions, discoveries and other additions - As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates. +Farm-out - Transfer of all or part of the operating rights from a working interest owner to an assignee, who assumes all or some of the burden of development in return for an interest in the property. The assignor usually retains an overriding royalty interest but may retain any type of interest. +121 +Fracture or Fracturing - Procedure to stimulate production by forcing a mixture of fluid and proppant into the formation under high pressure. Fracturing creates artificial fractures in the reservoir rock to increase permeability and porosity, thereby allowing the release of trapped hydrocarbons. +Gross acres or wells - Refers to the total acres or wells in which we have a working interest. +Henry Hub - Refers to the pricing point for natural gas futures contracts traded on NYMEX. +Horizontal drilling - A drilling technique that permits the operator to drill a horizontal well shaft from the bottom of a vertical well and thereby to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons. +Joint interest billing - Process of billing/invoicing the costs related to well drilling, completions and production operations among working interest partners. +Natural gas liquid(s) or NGL(s) - Hydrocarbons which can be extracted from natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs include ethane, propane, butane and other natural gasolines. +Net acres or wells - Refers to gross acres or wells we own multiplied, in each case, by our percentage working interest. +Net production - Crude oil and natural gas production that we own, less royalties and production due to others. +Non-operated - A project in which we are not the operator. +NYMEX - New York Mercantile Exchange. +Operator - The individual or company responsible for the exploration, development and/or production of an oil or gas well or lease. +Overriding royalty - An interest which is created out of the operating or working interest. Its term is coextensive with that of the operating interest. +Possible reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability to exceed the sum of proved, probable and possible reserves. When probabilistic methods are used, there must be at least a 10 percent probability that the actual quantities recovered will equal or exceed the sum of proved, probable and possible estimates. +Present value of future net revenues or (PV-10) - The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, of proved reserves calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using pricing and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization and discounted using an annual discount rate of 10 percent. PV-10 is pre-tax and therefore a non-U.S. GAAP financial measure. +Probable reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Similarly, when probabilistic methods are used, there must be at least a 50 percent probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. +Productive well - An exploratory or developmental well that is not a dry well or dry hole, as defined above. +Proved developed non-producing reserves - Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and/or +122 +(ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells. +Proved developed producing reserves or PDPs - Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods. +Proved developed reserves - The combination of proved developed producing and proved developed non-producing reserves. +Proved reserves - This term means "proved oil and gas reserves" as defined in SEC Regulation S-X Section 4-10(a) and refers to those quantities of crude oil and condensate, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing conditions, operating methods and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +Proved undeveloped reserves or PUDs - Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. +Recomplete or Recompletion - The modification of an existing well for the purpose of producing crude oil and natural gas from a different producing formation. +Reserves - Estimated remaining quantities of crude oil, natural gas, NGLs and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering crude oil, natural gas and NGLs or related substances to market, and all permits and financing required to implement the project. +Royalty - An interest in a crude oil and natural gas lease or mineral interest that gives the owner of the royalty the right to receive a portion of the production from the leased acreage or mineral interest (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +Spud - To begin drilling; the act of beginning a hole. +Standardized measure of discounted future net cash flows or standardized measure - Future net cash flows discounted at a rate of 10 percent. Future net cash flows represent the estimated future revenues to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment and (ii) future income tax expense. +Stratigraphic test well - A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. +Undeveloped acreage - Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas, regardless of whether such acreage contains proved reserves. +Waha - Waha West Texas natural gas prices +Working interest - An interest in a crude oil and natural gas lease that gives the owner of the interest the right to drill and produce crude oil and natural gas on the leased acreage. It requires the owner to pay its share of the costs of drilling and production operations. +Workover - Major remedial operations on a producing well to restore, maintain, or improve the well's production. +123 \ No newline at end of file diff --git a/raw/filings/0000077877/2020/0000077877-21-000020/filing_metadata.csv b/raw/filings/0000077877/2020/0000077877-21-000020/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..d827d8a55ce962cfc265833877c7a3d05a1b5555 --- /dev/null +++ b/raw/filings/0000077877/2020/0000077877-21-000020/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000077877,PDCE,"PDC ENERGY, INC.",10-K,2021-02-25,2020-12-31,2021-02-24T23:19:46.000Z,0000077877-21-000020,pdce-20201231.htm,10-K,14935823,1,1,https://www.sec.gov/Archives/edgar/data/77877/000007787721000020/pdce-20201231.htm,https://www.sec.gov/Archives/edgar/data/77877/000007787721000020/,2020,2020,1 diff --git a/raw/filings/0000077877/2020/0000077877-21-000020/item1.txt b/raw/filings/0000077877/2020/0000077877-21-000020/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2020/0000077877-21-000020/item13.txt b/raw/filings/0000077877/2020/0000077877-21-000020/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..2ea3e45c9f41f60884a757f2fd80c03c0f23ab63 --- /dev/null +++ b/raw/filings/0000077877/2020/0000077877-21-000020/item13.txt @@ -0,0 +1,2 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2021 Annual Stockholders' meeting and is incorporated by reference in this report. \ No newline at end of file diff --git a/raw/filings/0000077877/2020/0000077877-21-000020/item9a.txt b/raw/filings/0000077877/2020/0000077877-21-000020/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..c6096b8e6bf1e4c2fe6cccf92bce49b2543ed0c0 --- /dev/null +++ b/raw/filings/0000077877/2020/0000077877-21-000020/item9a.txt @@ -0,0 +1,10 @@ +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +As of December 31, 2020, we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Based on the results of this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2020. +Management's Report on Internal Control over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Internal control over financial reporting is a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer, or persons performing similar functions, and effected by our board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate. +Management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2020, based upon the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO"). Based on this evaluation, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2020. +The effectiveness of our internal control over financial reporting as of December 31, 2020 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears under Item 8. +Changes in Internal Control over Financial Reporting +There were no changes in our internal control over financial reporting during the quarter ended December 31, 2020 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. \ No newline at end of file diff --git a/raw/filings/0000077877/2020/0000077877-21-000020/rp_note.txt b/raw/filings/0000077877/2020/0000077877-21-000020/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2020/0000077877-21-000020/rpt_disclosure.txt b/raw/filings/0000077877/2020/0000077877-21-000020/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..f1865e5caa4e0d3476e80b1a0531a92bcd2ff706 --- /dev/null +++ b/raw/filings/0000077877/2020/0000077877-21-000020/rpt_disclosure.txt @@ -0,0 +1,5 @@ +TRANSACTIONS WITH RELATED PARTIES +During 2020, there was no transaction or series of transactions, nor is there any currently proposed transaction, involving an amount exceeding $120,000 in which the Company is or was a participant and in which any Director, executive officer, known holder of more than five percent of the Company’s voting securities, or any member of the immediate family of any of the foregoing persons, had or has a direct or indirect material interest for which disclosure is required under Item 404 of Regulation S-K. +POLICIES AND PROCEDURES WITH RESPECT TO TRANSACTIONS WITH RELATED PARTIES +The Board has adopted a written policy for the review, approval and ratification of transactions that involve related parties and potential conflicts of interest. The related-party transaction policy applies to each Director and executive officer of the Company, any nominee for election as a Director, any security holder who is known to own more than five percent of the Company’s voting securities, any immediate family member of any of the foregoing persons and any corporation, firm or association in which one or more of the Company’s Directors or executive officers have a substantial interest. +Under our related-party transaction policy, a related-party transaction is a transaction or arrangement involving a related party in which the Company is a participant or that would require disclosure in the Company’s filings with the SEC as a transaction with a related party. The related party must disclose to the Audit Committee any potential related-party transactions and must disclose all material facts with respect to such transaction and relationship. All related-party transactions so disclosed will be reviewed by the Audit Committee. In determining whether to approve or ratify a transaction, the Audit Committee will consider the relevant facts and circumstances of the transaction, which may include factors such as the relationship of the related party to the Company, the materiality or significance of the transaction to the Company and the business purpose and reasonableness of the transaction, whether the transaction is comparable to a transaction that could be available to the Company from an unrelated party and the impact of the transaction on the Company’s business and operations. \ No newline at end of file diff --git a/raw/filings/0000077877/2021/0000077877-22-000019/filing.txt b/raw/filings/0000077877/2021/0000077877-22-000019/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..8d82cfc519c9f339b3430e1f7e238c399009c5af --- /dev/null +++ b/raw/filings/0000077877/2021/0000077877-22-000019/filing.txt @@ -0,0 +1,2566 @@ +pdce-20211231 +PDC ENERGY, INC. 0000077877 2021 FY false P1Y 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+(Exact name of registrant as specified in its charter) +Delaware 95-2636730 +(State of incorporation) (I.R.S. Employer Identification No.) +1775 Sherman Street, Suite 3000 +Denver , Colorado 80203 +(Address of principal executive offices) (Zip code) +Registrant’s telephone number, including area code: ( 303 ) 860-5800 +Securities registered pursuant to Section 12(b) of the Act: +Title of each class Ticker Symbol Name of each exchange on which registered +Common Stock, par value $0.01 per share PDCE NASDAQ Global Select Market +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes T No £ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes £ No T +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes T No £ +Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes T No £ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. +Large accelerated filer ☒ Accelerated filer ☐ +Non-accelerated filer ☐ Smaller reporting company ☐ +Emerging growth company ☐ +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. £ +Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No T +The aggregate market value of our common stock held by non-affiliates on June 30, 2021 was $ 4.5 billion (based on the closing price of $45.79 per share as of the last business day of the fiscal quarter ending June 30, 2021 ). +As of February 15, 2022 , there were 96,329,829 shares of our common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +We hereby incorporate by reference into this document the information required by Part III of this Form, which will appear in our definitive proxy statement filed pursuant to Regulation 14A for our 2022 Annual Meeting of Stockholders. +PDC ENERGY, INC. +2021 ANNUAL REPORT ON FORM 10-K +TABLE OF CONTENTS +PART I Page +Items 1. and 2. +Business and Properties +3 +Item 1A. +Risk Factors +23 +Item 1B. +Unresolved Staff Comments +38 +Item 3. +Legal Proceedings +38 +Item 4. +Mine Safety Disclosures +38 +PART II +Item 5. +Market for the Registrant ’ s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +39 +Item 6. +[Reserved] +41 +Item 7. +Management ’ s Discussion and Analysis of Financial Condition and Results of Operations +41 +Item 7A. +Quantitative and Qualitative Disclosures About Market Risk +63 +Item 8. +Financial Statements and Supplementary Data +65 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +108 +Item 9A. +Controls and Procedures +108 +Item 9B. +Other Information +108 +Item 9C. +Disclosure Regarding Foreign Jurisdictions that Prevent Inspections +108 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +109 +Item 11. +Executive Compensation +109 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +109 +Item 13. +Certain Relationships and Related Transactions and Director Independence +109 +Item 14. +Principal Accounting Fees and Services +109 +PART IV +Item15. +Exhibits, Financial Statement Schedules +109 +Item 16. +Form 10-K Summary +109 +Signatures +112 +Glossary of Units of Measurements and Industry Terms +113 +PART I +REFERENCES TO THE REGISTRANT +Unless the context otherwise requires, references in this report to “PDC Energy”, “PDC”, the “Company”, “we”, “us”, “our” or “ours” refer to the registrant, PDC Energy, Inc. and our wholly-owned subsidiaries consolidated for the purposes of our financial statements. +GLOSSARY OF UNITS OF MEASUREMENTS AND INDUSTRY TERMS +Units of measurements and industry terms are defined in the Glossary of Units of Measurements and Industry Terms, included at the end of this report. +SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS +This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (“Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”) and the United States (“U.S.”) Private Securities Litigation Reform Act of 1995 regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical fact included in and incorporated by reference into this report are “forward-looking statements”. Words such as expect, anticipate, intend, plan, believe, seek, estimate, schedule and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements include, among other things, the pending acquisition of Great Western Petroleum, LLC (“Great Western”) and the effects thereof; the expected timing of the acquisition of Great Western and the possibility that the acquisition will not close; statements regarding future: production, costs and cash flows; impacts of Colorado political matters, including initiatives influencing our ability to continue to obtain permits; drilling locations, zones and growth opportunities; commodity prices and differentials; capital expenditures and projects, including the number of rigs employed; cash flows from operations relative to future capital investments; financial ratios and compliance with covenants in our revolving credit facility and other debt instruments; adequacy of midstream infrastructure; the potential return of capital to shareholders through buyback of shares and/or payments of dividends; ongoing compliance with our consent decree; expected impact from emission reduction initiatives; risk of our counterparties non-performance on derivative instruments; and our ability to fund planned activities. +The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this report or accompanying materials, we may use the term “projection” or similar terms or expressions, or indicate that we have “modeled” certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or our industry in periods beyond the current fiscal year. Because such statements relate to events or conditions further in the future, they are subject to increased levels of uncertainty. +Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to: +• market and commodity price volatility, widening price differentials and related impacts to the Company, including decreased revenue, income and cash flow, write-downs and impairments and decreased availability of capital; +• adverse changes to our future cash flows, liquidity and financial condition; +• changes in, and interpretations and enforcement of, environmental and other laws and other political and regulatory developments, including in particular additional permit scrutiny in Colorado; +• the coronavirus 2019 (“COVID-19”) pandemic, including its effects on commodity prices, downstream capacity, employee health and safety, business continuity and regulatory matters; +• declines in the value of our crude oil, natural gas and natural gas liquids (“NGLs”) properties resulting in impairments; +• changes in, and inaccuracy of, reserve estimates and expected production and decline rates; +• timing and extent of our success in discovering, acquiring, developing and producing reserves; +• reductions in the borrowing base under our revolving credit facility; +• availability and cost of capital; +• risks inherent in the drilling and operation of crude oil and natural gas wells; +• timing and cost of wells and facilities; +1 +• availability, cost, and timing of sufficient pipeline, gathering and transportation facilities and related infrastructure; +• limitations in the availability of supplies, materials, contractors and services that may delay the drilling or completion of our wells; +• potential losses of acreage or other impacts due to lease expirations, other title defects, or otherwise; +• risks inherent in marketing our crude oil, natural gas and NGLs; +• effect of crude oil and natural gas derivative activities; +• impact of environmental events, governmental and other third-party responses to such events and our ability to insure adequately against such events; +• cost of pending or future litigation; +• impact to our operations, personnel retention, strategy, stock price and expenses caused by the actions of activist shareholders; +• uncertainties associated with future dividends to our shareholders or share buybacks; +• timing and amounts for cash federal and state income taxes; +• our ability to retain or attract senior management and key technical employees; +• difficulties in integrating our operations as a result of any significant acquisitions, including the pending acquisition of Great Western, or acreage exchanges; +• a failure to complete the acquisition of Great Western or an unanticipated assumption of liabilities or other problems with the acquisition; +• civil unrest, terrorist attacks and cyber threats; and +• success of strategic plans, expectations and objectives for our future operations. +Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under Item 1A, Risk Factors , made in this report and our other filings with the U.S. Securities and Exchange Commission (“SEC”) for further information on risks and uncertainties that could affect our business, financial condition, results of operations and prospects, which are incorporated by this reference as though fully set forth herein. We caution you not to place undue reliance on the forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement. +2 +ITEMS 1. AND 2. BUSINESS AND PROPERTIES +The Company +We are a domestic independent exploration and production company that acquires, explores and develops properties for the production of crude oil, natural gas and NGLs, with operations in the Wattenberg Field in Colorado and the Delaware Basin in west Texas. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are primarily focused in the horizontal Wolfcamp zones. +The following map presents the general locations of our development and production activities as of December 31, 2021: +3 +The following table presents selected information regarding our business and results of operations as of and for the periods presented: +Year Ended/As of +December 31, Percent Change +2021 2020 2021-2020 +(production and reserves in MMBoe, dollars in millions) +Wells: +Gross productive wells 3,471 3,727 (7) % +Net productive wells 2,675 2,841 (6) % +Horizontal percentage 66 % 57 % 16 % +Gross operated wells turned-in-line 167 137 22 % +Net operated wells turned-in-line 160.4 129.5 24 % +Production: +Wattenberg Field 61.9 57.5 8 % +Delaware Basin 9.4 10.8 (13) % +Total 71.3 68.4 4 % +Reserves: +Proved reserves 814.2 731.1 11 % +Proved developed reserves percentage 49 % 44 % 11 % +Standardized measure $ 7,908.2 $ 3,282.2 141 % +PV-10 (1) +$ 9,708.8 $ 3,454.6 181 % +Liquidity 1,514 1,400 8 % +Leverage ratio 0.6 1.7 (65) % +_____________ +(1) PV-10 is a non-U.S. GAAP financial measure. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in accordance with U.S. generally accepted accounting principles (“U.S. GAAP”), but rather should be considered in addition to the standardized measure. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10 and a reconciliation of our PV-10 value to the standardized measure included elsewhere in this report. +Pending Acquisition +On February 26, 2022, we entered into a definitive purchase agreement under which we will acquire Great Western for approximately $1.3 billion, inclusive of Great Western’s net debt (the “Great Western Acquisition”). Great Western is an independent oil and gas company focused on the exploration, production and development of crude oil and natural gas in Colorado. We anticipate acquiring approximately 54,000 net acres in the Core Wattenberg and production of approximately 55,000 Boe per day. The purchase price of the Great Western Acquisition will consist of approximately 4.0 million shares of our common stock and approximately $543 million in cash, pursuant to the Membership Interest Purchase Agreement that we entered into with Great Western (“Acquisition Agreement”). We expect the Great Western Acquisition to be completed in the second quarter of 2022, subject to certain customary closing conditions. +Business Strategy and Key Strengths +Our long-term business strategy focuses on creating shareholder value by: (i) delivering attractive returns from our crude oil and natural gas properties with a keen focus on environmentally responsible and sustainable operations; (ii) maintaining financial strength; (iii) generating sustainable cash flows from operations in excess of our capital investments in crude oil and natural gas properties; and (iv) returning capital to shareholders. Our key strengths create long-term shareholder value through the following: +• Focus on generating sustainable cash flows from operations in excess of capital investments. We are focused on generating multi-year sustainable cash flows from operations in excess of our capital investments through managing capital spending and growth rates, adjusting the timing of completion of our inventory of drilled uncompleted wells +4 +(“DUCs”), utilizing commodity derivative instruments, focusing on margin improvement from reductions in our cost structure and increasing capital efficiency from technological innovation. Our adjusted free cash flows, a non-GAAP measure, is used as a measure of our ability to return capital to shareholders, reduce debt levels and maintain strong liquidity. In 2021, we generated cash flows from operations of $1.55 billion and adjusted free cash flows of $949.0 million. +• Strong financial position, absolute debt reduction and conservative total leverage targets . We maintain a disciplined financial strategy that focuses on strong liquidity, low leverage ratios and an active commodity derivative program to help mitigate a portion of the risk associated with commodity price fluctuations. We believe that execution of this strategy will allow us to deliver strong corporate cash flows year-over-year, even through challenging commodity price environments. Through successful execution of our business plan, as of December 31, 2021, we reduced our indebtedness to below $1.0 billion, had total liquidity of $1.5 billion, and had a leverage ratio, as defined in our revolving line of credit facility agreement, of 0.6x. In addition, as of December 31, 2021, we had commodity derivative positions covering approximately 12.2 MMBbls, 8.3 MMBbls and 1.7 MMBbls of crude oil production for 2022, 2023 and 2024, respectively. As of the same date, we had hedged approximately 69,060 BBtu and 33,398 BBtu of natural gas production for 2022 and 2023, respectively. +• Sustainable return of capital to shareholders. We are committed to generating material and sustainable cash flows in a variety of commodity price environments, and to returning capital to our shareholders. In February 2021, we reinstated our Stock Repurchase Program and our board of directors approved a quarterly dividend program which commenced in May 2021. During 2021 we returned $244.9 million to shareholders through base dividends, share repurchases and a special dividend. For 2022 and beyond, our board of directors and management team are dedicated to a premier return of capital program with a quarterly base dividend and a return of approximately 60% or more of our remaining adjusted free cash flows, a non-U.S. GAAP financial measure, through stock repurchases and special dividends, as needed. +• Committed to meaningful and measurable environmental, social and governance (“ESG”) strategy. Our mission to be a cleaner, safer and more socially responsible company begins with a sound strategy, is supported in the boardroom and is overseen by our newly created Environmental, Social, Governance and Nominating Committee (the “ESG&N Committee”) at the board of directors and is applied at every level of our business. +• Environment. Environmental protection is at the forefront of our ESG efforts. We view ourselves as playing a critical role in reducing greenhouse gas and methane emission intensities for environmentally responsible and sustainable operations. We are committed to the following goals: +◦ Reduce greenhouse gas intensity by 60% from 2020 emissions by 2025 and 74% by 2030. +◦ Reduce methane intensity by 50% from 2020 emissions by 2025 and 70% by 2030. +◦ Eliminate routine flaring by 2025. +• Social. We value our employees and their contribution to the work we do. Employees are our strongest asset and our success is directly related to the quality of our team. We have increased our focus on attracting and retaining a more diverse workforce through expanded internal recruitment efforts and partnerships with diversity-focused organizations within our communities. We are also dedicated to being an active and contributing member of the communities in which we operate. We value two-way communication and encourage community members to reach out to us directly with questions or concerns. Further, we have focused on establishing effective environmental, health and safety programs, trainings and policies that are intended to promote safe working practices for our employees and contractors and to help earn the trust and respect of land owners, regulatory agencies and public officials. This is an important part of our strategy in effectively operating in today’s intensive regulatory climate. +• Governance. We continue to commit to governance best practices and accountability to shareholders as we see this as a critical factor to our long-term success. We consistently seek board refreshment opportunities to ensure our board maintains a high level of diversity, including in thought and experience, and have recently added three new diverse board of director members. To further align with our accountability to our shareholders, in September 2021 we formalized our board oversight of ESG issues by incorporating ESG into the responsibilities of our Nominating and Governance Committee (the “N&G Committee”), which became the ESG&N Committee. In 2021 we added multiple ESG qualitative goals to our short-term incentive (“STI”) +5 +program. This is in addition to our Total Recordable Incident Rate (“TRIR”), Preventable Vehicle Accident Rate (“PVAR”) and Spill Rate as quantitative performance and ESG metrics. The board of directors has also approved an additional quantitative performance metric for greenhouse gas and methane intensity reductions within our STI program, to further align management with our board of directors in our environmental goals. +• Significant operational control in our core areas. We have, and expect to continue to have, a substantial degree of operational control over our properties. As a result of successfully executing our strategy of acquisitions and acreage trades in our core areas of operations, we have built multiple concentrated acreage positions with high working interests that we believe will allow us to enhance the value of our assets and replenish our drilling inventory. We currently operate approximately 78 percent of all the wells in which we have an interest. This operational control allows us to better manage our drilling, production, operating and administrative costs and to leverage our technical expertise in our core operating areas. Our leaseholds that are held by production further enhance our operational control by providing us with additional flexibility on the timing of drilling of those locations. +• Project inventory in two premier crude oil, natural gas and NGL plays. We have a substantial multi-year inventory of high-quality horizontal drilling opportunities across two premier U.S. onshore basins: the Wattenberg Field in Weld County, Colorado and the Delaware Basin in Reeves County, Texas. Our portfolio has a proven record of delivering strong and repeatable economic returns and provides us the ability to allocate capital investments and manage risk as each basin has its own operating and competitive dynamic in terms of commodity price markets, service costs, takeaway capacity and regulatory and political considerations. We have a disciplined development program that seeks to expand our project inventory through testing new intervals and considering various spacing configurations. We believe our project inventory will allow us to achieve attractive rates of return and grow our proved reserves and production in a sustainable fashion. Such expected returns on drilling can vary well by well and are based upon many factors, including but not limited to commodity prices, well development and operating costs. +• Efficiency through technology and synergies from trades and acquisitions. Technological innovation has led to continued improvement in our drilling and completion times and is helping us achieve our emission reduction goals. We are continuously investing in new technology to improve the efficiency of our horizontal drilling and completion operations. For example, advanced completion equipment, including an anticipated electric fleet usage, and refinements in stage spacing, perforation clusters, and fluid and sand type and concentration continue to result in more efficient recoveries of crude oil and natural gas reserves and lower well emissions. Efficiencies are also driven by digital technologies such as artificial intelligence, machine learning and process automation technologies, which are utilized in our field and corporate operations. Additionally, acreage consolidation in both of our operating areas increases our ability to drill longer length lateral wells. Longer laterals allow us to develop our properties with a smaller number of wells and less truck traffic, with resulting benefits for our operations, the environment, and the communities in which we operate. +• Experienced management team with proven track record. We have a strong executive management team that has an average of 27 years of experience in the oil and gas industry. Collectively, this experience includes technical, operational, commercial, financial, legal and strategic aspects of the oil and gas industry. This team has a proven track record of executing value-added capital investment programs with a focus on financial discipline and improving on an already strong balance sheet, while growing production and proved reserves. Additionally, our team’s experience has helped us continue to achieve our strategic objectives through periods of commodity price volatility, cost inflation and other challenging operating environments. +6 +Operating Areas +Wattenberg Field. In the Wattenberg Field, we have identified a gross operated inventory of approximately 1,800 horizontal locations that we expect to generate acceptable rates of return based on forward strip pricing, with an average lateral length of approximately 9,700 feet. Our inventory consists of approximately 145 gross operated DUCs, 235 approved permits, reflecting approximately 3.0 years of turn-in-line activity based on our current drilling plan, and 1,420 unpermitted locations. Our Wattenberg Field locations are subject to Oil and Gas Development Plans (“OGDP”) and Comprehensive Area Plans (“CAP”) regulated by Colorado Oil and Gas Conservation Commission (“COGCC”). We have two submissions in the review process with the COGCC for proposed wells in rural Weld County, one submitted for a multi-pad development plan including approximately 70 wells, and one submitted for a plan including approximately 450 wells. We anticipate a COGCC determination on both applications in 2022 or early 2023. The wells included in these applications represent our planned turn-in-line activity into 2027. +Our Wattenberg Field horizontal drilling locations have been substantially de-risked through multiple years of successful development in the field. We continue to analyze and test various wellbore spacing configurations in areas of the field that we believe have the potential to increase our gross operated inventory. Substantially all of our Wattenberg Field acreage is held by production. Wells in the Wattenberg Field typically have productive horizons at depths of approximately 6,500 to 7,500 feet below the surface. We continue to pursue various business development initiatives, with a focus on acreage exchanges or acquisitions, designed to increase our Wattenberg Field project inventory or to increase our ownership in our operated wells. +Delaware Basin. In the Delaware Basin, as a result of our completion activities and the performance of wells turned-in-line during 2021, we have developed a relaxed spacing program of approximately eight wells per undeveloped section equivalent and new operational techniques reflecting a gross operated economic inventory of approximately 65 horizontal locations, representing three to four years of inventory. Our inventory consists of approximately 20 gross operated DUCs that we expect to generate acceptable rates of return based on forward strip pricing, targeting the Wolfcamp A and Wolfcamp B zones. The average lateral length of these locations is approximately 10,200 feet. Wells in the Delaware Basin typically have productive horizons at depths of approximately 9,000 to 11,500 feet below the surface. In 2022, we are expanding our drilling program to include untested target zones that may be subject to a higher degree of uncertainty as well as innovative drilling techniques. If successful, we anticipate both initiatives will allow us to increase our field inventory. We also continue to pursue various business development initiatives, with a focus on acreage exchanges and joint development projects, designed to increase our Delaware Basin project inventory by establishing longer lateral drilling units capable of delivering attractive economic returns or to increase our ownership in our operated wells. +7 +Oil and Gas Production and Operations +Proved Oil and Gas Reserves +The following table presents our proved reserve estimates as of the dates indicated: +December 31, +2021 2020 2019 +Proved reserves +Crude oil and condensate (MMBbls) +214 212 197 +Natural gas (Bcf) +2,160 1,901 1,558 +NGLs (MMBbls) +240 203 154 +Total proved reserves (MMBoe) +814 731 611 +Proved developed reserves (MMBoe) +399 322 214 +Standardized measure (in millions) +$ 7,908 $ 3,282 $ 3,310 +Estimated undiscounted future net cash flows (in millions) (1) +$ 13,872 $ 5,633 $ 5,896 +PV-10 ( in millions) (2) +$ 9,709 $ 3,455 $ 3,837 +_____________ +(1) Amount represents aggregate undiscounted future net cash flows, before income taxes, of approximately $17.0 billion, $5.9 billion and $6.8 billion as of December 31, 2021, 2020 and 2019, respectively, less an internally-estimated undiscounted future income tax expense of approximately $3.1 billion, $0.3 billion and $0.9 billion, respectively. +(2) PV-10 is a non-U.S. GAAP financial measure. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in accordance with U.S. GAAP, but rather should be considered in addition to the standardized measure. See Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10 and a reconciliation of our PV-10 value to the standardized measure. +The additions to our proved reserves at December 31, 2021 compared to December 31, 2020 were primarily due to positive revisions resulting from our development activities and significant improvements in commodity prices during 2021, resulting in better economics and therefore increased quantities of reserves. +The additions to our proved reserves at December 31, 2020 as compared to December 31, 2019 were primarily due to the reserves acquired from our merger with SRC Energy, Inc. (“SRC Acquisition”), which were partially offset by downward revisions as a result of decreases in realized prices and revised drilling plans following the completion of the SRC Acquisition. +The following table presents our proved reserve estimates by category as of December 31, 2021: +Operating Region/Area Crude Oil and Condensate (MMBbls) Natural Gas (Bcf) NGLs (MMBbls) Crude Oil Equivalent (MMBoe) Percent +Proved developed +Wattenberg Field 77 946 106 341 42 % +Delaware Basin 20 143 14 58 7 % +Total proved developed 97 1,089 120 399 49 % +Proved undeveloped +Wattenberg Field 110 1,026 116 397 49 % +Delaware Basin 7 45 4 18 2 % +Total proved undeveloped 117 1,071 120 415 51 % +Total proved reserves +Wattenberg Field 187 1,972 222 738 91 % +Delaware Basin 27 188 18 76 9 % +Total proved reserves 214 2,160 240 814 100 % +8 +Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Positive impacts of these variables and assumptions may result in a longer economic productive life of a property or the recognition of more economically viable proved undeveloped (“PUD”) reserves, while negative impacts of these variables and assumptions may result in corresponding negative impacts. All of our proved reserves are located in the United States. +Commodity Pricing . Per SEC rules, the pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of the month prices for the preceding 12 months. The NYMEX prices used in preparing the reserves are then adjusted based on energy content, location and basis differentials and other marketing deductions to arrive at the net realized price. +Average Benchmark Prices +December 31, +Crude Oil (per Bbl) (1) +Natural Gas (per MMBtu) (1) +NGLs (per Bbl) (2) +2021 $ 66.56 $ 3.60 $ 66.56 +2020 39.57 1.99 39.57 +2019 55.69 2.58 55.69 +____________ +(1) Our benchmark indexes for crude oil and natural gas are WTI and Henry Hub, respectively. +(2) For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. +The netted back price used to estimate our reserves, by commodity, are presented below. +Price Used to Estimate Reserves (1) +December 31, Crude Oil +(per Bbl) Natural Gas +(per MMBtu) +NGLs (per Bbl) +2021 $ 65.37 $ 2.85 $ 24.96 +2020 37.52 1.26 10.55 +2019 52.63 1.50 12.21 +____________ +(1) These prices are based on index prices and are net of basin differentials, transportation fees, contractual adjustments and Btu adjustments we experienced for the respective commodity. +Proved Reserves Sensitivity Analysis. We have performed an analysis of our proved reserve estimates as of December 31, 2021 to present sensitivity associated with a lower crude oil price as the value of crude oil influences the value of our proved reserves and PV-10 most significantly. +Replacing the 2021 NYMEX price for crude oil used in estimating our reported proved reserves with $60 and $45 as shown on the table below, and leaving all other parameters unchanged, results in changes to our estimated proved reserves as shown. +Pricing Scenario - NYMEX +Crude Oil (per Bbl) Natural Gas (per MMBtu) Proved Reserves (MMBoe) % Change from December 31, 2021 Estimated Reserves PV-10 +(in Millions) PV-10 % Change from December 31, 2021 Estimated Reserves +2021 SEC Reserve Report (1) +$ 66.56 $ 3.60 814,188 — $ 9,708.8 — +Alternate Price Scenario 1 $ 60.00 $ 3.60 809,928 (1) % $ 8,651.6 (11) % +Alternate Price Scenario 2 $ 45.00 $ 3.60 796,618 (2) % $ 6,239.7 (36) % +_____________ +(1) These prices are the SEC NYMEX prices applied to the calculation of the PV-10 value. Such prices have been applied consistently in the alternate pricing scenario to include the impact of adjusting for deductions for any basin differentials, transportation fees, contractual adjustments and Btu adjustments we experienced for the relevant commodity. +9 +Commodities and Standardized Measure . Reserve estimates involve judgments and reserves cannot be measured exactly. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geologic and geophysical data and economic changes. Neither the estimated future net cash flows nor the standardized measure of discounted future net cash flows (“standardized measure”) is intended to represent the current market value of our proved reserves. +For additional information regarding our standardized measures, as well as other information regarding our proved reserves, see Supplemental Information- Crude Oil and Natural Gas Properties included in Item 8. Financial Statements and Supplementary Data provided with our consolidated financial statements included elsewhere in this report. +Preparation of Reserve Estimates +Our proved reserves estimates as of December 31, 2021 were based on evaluations prepared by our independent petroleum engineering consulting firms, Ryder Scott Company, L.P. (“Ryder Scott”) and Netherland, Sewell & Associates, Inc. (“NSAI”) (collectively, our “external engineers”). Our proved reserve estimates were prepared in accordance with guidelines established by the SEC and the Financial Accounting Standards Board (the “FASB”). +Controls Over Reserve Report Preparation . Inputs and major assumptions related to our proved reserves are reviewed annually by an internal team composed of reservoir engineers, geologists, land and management for adherence to SEC guidelines through a detailed review of land and accounting records, available geological and reservoir data and production performance data. The internal team compiles the reviewed data and forwards the applicable data to our external engineers. +Annually, the Director of Reservoir Engineering & Technology reviews the reserves to ensure all the necessary significant inputs and steps are completed within our reserve process. After final approval from the Director of Reservoir Engineering & Technology, the results are presented to senior management and to our board of directors for their review. +Together, these internal controls are designed to promote a comprehensive, objective, and accurate reserves estimation process. As an additional confirmation of the reasonableness of our internal estimates, Ryder Scott and NSAI performed an independent evaluation of our estimated proved reserves in the Wattenberg Field and Delaware Basin, respectively, as of December 31, 2021. +When preparing our reserve estimates, our external engineers do not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, production volumes, well test data, historical costs of operations and development, product prices or any agreements relating to current and future operations of properties or sales of production. Our external engineers prepare estimates of our reserves in conjunction with an ongoing review by our engineers. A final comparison of data is performed to ensure that the reserve estimates are complete, determined pursuant to acceptable industry methods and with a level of detail we deem appropriate. The final estimated reserve reports are prepared by our external engineers and reviewed by our engineering staff and management prior to issuance by those firms. +In determining our proved reserves estimates, we used a combination of performance methods, including decline curve analysis and other computational methods, offset analogies and seismic data and interpretation. All of our proved undeveloped reserves conform to the SEC five-year rule requirement as all proved undeveloped locations are scheduled, according to an adopted development plan, to be drilled within five years of the location’s initial booking date. +Qualifications of Responsible Technical Persons. The professional qualifications of our lead engineer primarily responsible for overseeing the preparation of our reserve estimates, as defined in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the Society of Petroleum Engineers, qualifies this individual as a Reserve Estimator. This person holds a Masters Degree in Petroleum Engineering from the Colorado School of Mines and a Bachelors Degree in Geology from the University of Colorado and has over 21 years of oil and gas experience. +Letters which identify the professional qualifications of the individuals at Ryder Scott and NSAI who are responsible for overseeing the preparation of our reserve estimates as of December 31, 2021 have been filed as Exhibits 99.1 and 99.2 to this report. +10 +Production, Prices and Costs +Production and operating data for the years ended December 31, 2021, 2020 and 2019 is included in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations included elsewhere in this report. +Productive Wells +The following table presents our productive wells by operating area as of December 31, 2021: +Crude Oil Natural Gas Total +Operating Region/Area Gross Net Gross Net Gross Net +Wattenberg Field 2,205 1,586.5 1,129 977.0 3,334 2,563.5 +Delaware Basin 52 37.9 85 73.4 137 111.3 +Total productive wells 2,257 1,624.4 1,214 1,050.4 3,471 2,674.8 +Productive wells consist of producing wells and wells capable of production, including crude oil wells awaiting pipeline connections to commence deliveries, natural gas wells awaiting connection to production facilities and shut-in wells. +Developed and Undeveloped Acreage +The following table presents our developed and undeveloped lease acreage as of December 31, 2021: +Developed Undeveloped Total +Operating Region/Area Gross Net Gross Net Gross Net +Wattenberg Field 166,131 154,726 68,200 63,488 234,331 218,214 +Delaware Basin 27,627 25,316 905 343 28,532 25,659 +Total acreage 193,758 180,042 69,105 63,831 262,863 243,873 +Developed lease acreage are acres spaced or assigned to productive wells and do not include undrilled acreage held by production under the terms of the lease. Large portions of the acreage that are considered developed under SEC guidelines are developed with vertical wells or horizontal wells that are in a single horizon. We believe much of this acreage has significant remaining development potential in one or more intervals with horizontal wells. Undeveloped acreage represents acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves. However, substantially all of our undeveloped acreage in the Wattenberg Field and Delaware Basin is related to leaseholds that are held by production and therefore are not at risk of expiration or delay rental payments. +Our Wattenberg Field leaseholds at risk to expire in 2022, 2023 and 2024 are not material. In the Delaware Basin, the majority of the drilling obligations or continuous drilling clauses associated with the asset have been met. Our Delaware Basin leaseholds at risk to expire in 2022, 2023 and 2024 are not material. See Item 1A. Risk Factors - Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in substantial lease renewal costs or, if renewal is not feasible, loss of our lease and prospective drilling opportunities. +11 +Drilling Results +The following tables set forth a summary of our developmental and exploratory well drilling results for the periods presented. Productive wells consist of wells that were turned-in-line and commenced production during the period, regardless of when drilling was initiated. In-process wells represent wells that are in the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection as of the date shown. We utilize pad drilling operations, where multiple wells are developed from the same well pad, in both the Wattenberg Field and Delaware Basin. Because we may operate multiple drilling rigs in each operating area, we expect to have in-process wells at any given time. Wells may be in-process for up two years. +Operated Development and Exploratory Well Drilling Activity +As of and For the Year Ended December 31, +2021 2020 2019 +Operating Region/Area Gross Net Gross Net Gross Net +Development Wells +Wattenberg Field 149 143.0 124 116.5 114 105.1 +Delaware Basin 16 15.5 13 13.0 21 20.1 +Total development wells 165 158.5 137 129.5 135 125.2 +In-Process Development Wells +Wattenberg Field 143 133.0 214 201.8 145 135.0 +Delaware Basin 21 20.6 18 17.2 26 25.3 +Total in-process wells 164 153.6 232 219.0 171 160.3 +Exploratory Wells - Productive +Delaware Basin 2 1.9 2 2.0 2 2.0 +In-Process Exploratory Wells +Delaware Basin — — 2 1.9 4 3.9 +There were no exploratory drilling activities in the Wattenberg Field during 2021, 2020 and 2019. Additionally, we did not have any dry wells during the same periods in either operating region. +Title to Properties +We believe that we hold good and defensible leasehold title to substantially all of our crude oil and natural gas properties, in accordance with standards generally accepted in the industry. A preliminary title examination is typically conducted at the time the undeveloped properties are acquired. Prior to the commencement of drilling operations, a title examination is conducted and remedial curative work is performed, as necessary, with respect to discovered defects which we deem to be significant, in order to procure division order title opinions. Title examinations have been performed with respect to substantially all of our producing properties. +The properties we own are subject to royalty, overriding royalty and other outstanding interests. The properties may also be subject to additional burdens, liens or encumbrances customary in the industry, including items such as operating agreements, current taxes, development obligations under crude oil and natural gas leases, farm-out agreements and other restrictions. We do not believe that any of these burdens will materially interfere with our use of the properties. +A significant portion of our crude oil and natural gas properties have been mortgaged or pledged as security for amounts borrowed under our revolving credit facility. +12 +Offices +As of December 31, 2021, we leased corporate space in 1775 Sherman Street, Suite 3000, Denver, Colorado, where our corporate headquarters is located. We also maintain offices in Evans, Colorado and Midland, Texas. We sold our office building we owned in Bridgeport, West Virginia in March 2021. In January 2022, we entered into a long-term lease agreement for an office space located in Denver, Colorado. +Significant Customers +We sell our crude oil and natural gas production to marketers and other purchasers which have access to pipeline facilities. In areas where there is no practical access to pipelines, crude oil is transported to storage facilities by trucks owned or otherwise arranged by the marketers or purchasers. The majority of our crude oil and natural gas production is transported through pipelines. +We made sales to three customers that each contributed to 10 percent or more of our 2021 total crude oil, natural gas and NGLs revenues. However, given the liquidity in the market for the sale of hydrocarbons, we believe that the loss of any single purchaser, or the aggregate loss of several purchasers, could be managed by selling to alternative purchasers. +Seasonality of Business +Weather conditions affect the demand for and prices of crude oil and natural gas. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of our annual results. +Delivery Commitments +Certain of our firm sales agreements for crude oil include delivery commitments. We believe our current production and reserves are sufficient to fulfill these delivery commitments. See Note 13 - Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data for more information. +Governmental Regulation +The U.S. crude oil and natural gas industry is extensively regulated at the federal, state and local levels. The following is a summary of certain laws, rules and regulations currently in force that apply to us. The regulatory environment in which we operate changes frequently and we cannot predict the timing or nature of such changes or their effects on us. +Regulation of Crude Oil and Natural Gas Exploration and Production. Our exploration and production activities are subject to a variety of rules and regulations concerning drilling permits, location, spacing and density of wells, water discharge and disposal, prevention of waste, bonding requirements, surface use and restoration, public health and environmental protection and well plugging and abandonment. The primary state-level regulatory authority regarding these matters in Colorado is the COGCC and in Texas is the Texas Railroad Commission. Prior to preparing a surface location and commencing drilling operations on a well, we must procure permits and/or approvals for the various stages of the drilling process from the relevant state and local agencies. In addition, our operations must comply with rules governing the size of drilling and spacing units or proration units and the unitization or pooling of lands and leases. Some states, such as Colorado, allow the forced pooling or integration of tracts to facilitate exploration while other states, such as Texas, rely primarily or exclusively on voluntary pooling of lands and leases. +In states such as Texas where pooling is primarily or exclusively voluntary, it may be more difficult to form units and therefore to drill and develop our leases in circumstances where we do not own all of the leases in the proposed unit. These risks also exist in Colorado, where the COGCC has imposed limits on forced pooling. State laws may also prohibit the venting or flaring of natural gas, which may impact rates of production of crude oil and natural gas from our wells. Leases covering state or federal lands often include additional laws, regulations and conditions which can limit the location, timing and number of wells we can drill and impose other requirements on our operations, all of which can increase our costs. +Regulation of Transportation of Commodities. We move natural gas through pipelines owned by other entities and sell natural gas to other entities that also utilize common carrier pipeline facilities. Natural gas pipeline interstate transmission and +13 +storage activities are subject to regulation by the Federal Energy Regulatory Commission (“FERC”) under the Natural Gas Act of 1938 (“NGA”) and under the Natural Gas Policy Act of 1978 (“NGPA”). Rates and charges for the transportation of natural gas in interstate commerce, and the extension, enlargement or abandonment of jurisdictional facilities, among other things, are subject to regulation. +In addition, the Energy Policy Act of 2005 (the “EPAct 2005”) prohibits “any entity” from using any deceptive or manipulative device or contrivance in connection with the purchase or sale of gas or the purchase or sale of transportation services subject to regulation by FERC. The EPAct 2005 provides FERC with substantial enforcement authority to prohibit such manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties. +FERC Order 704 requires that any market participant, including natural gas producers, gatherers and marketers, that engaged in wholesale sales or purchases of natural gas that equaled or exceeded 2.2 MMBtus of physical natural gas in the previous calendar year to report to FERC the aggregate volumes of natural gas produced or sold at wholesale in such calendar year. Order 704 applies only to those transactions that utilize, contribute to or may contribute to the formation of price indices. It is the responsibility of the market participant to determine which individual transactions are to be reported under the guidance of Order 704. Additional information that must be reported includes whether the price in the relevant transaction was reported to any index publisher, and if so, whether such reporting complied with FERC’s policy statement on price reporting. To the extent that we engage in wholesale sales or purchases of natural gas that equal or exceed 2.2 MMBtus of physical natural gas in a calendar year pursuant to transactions utilizing, contributing or having the potential to contribute to the formation of price indices, we may be subject to the reporting requirements of Order 704. +Gathering is exempt from regulation under the NGA, thus allowing gatherers to charge negotiated rates. Gathering lines are, however, subject to state regulation, which includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and rate regulation on a complaint basis. We own certain pipeline facilities in the Delaware Basin that we believe are exempt from regulation under the NGA as “gathering facilities”, but which may in some cases be subject to state regulation. +Although FERC has set forth a general test to determine whether facilities are exempt from regulation under the NGA as “gathering” facilities, FERC’s determinations as to the classification of facilities are performed on a case-by-case basis. With respect to facilities owned by third parties and on which we move natural gas, to the extent that FERC subsequently issues an order reclassifying facilities previously thought to be subject to FERC jurisdiction as non-jurisdictional gathering facilities, and depending on the scope of that decision, our costs of moving natural gas to the point of sale may be increased. Further, to the extent that FERC issues an order reclassifying facilities that we own that were previously thought to be non-jurisdictional gathering facilities as subject to FERC jurisdiction, we could be subject to additional regulatory requirements under the NGA and the NGPA. +Transportation and safety of natural gas is also subject to regulation by the U.S. Department of Transportation, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), under the Natural Gas Pipeline Safety Act of 1968, as amended, which imposes safety requirements in the design, construction, operation and maintenance of interstate natural gas transmission facilities, the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (the “PIPES Act 2006”), and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (the “PIPES Act 2011”). We own certain pipeline facilities in the Delaware Basin that are subject to regulation under PHMSA. +In addition to natural gas, we move crude oil, condensate and natural gas liquids (collectively, “liquids”) through pipelines owned by other entities and sell such liquids to other entities that also utilize pipeline facilities that may be subject to regulation by FERC. FERC regulates the rates and terms and conditions of service for the interstate transportation of liquids under the Interstate Commerce Act, as it existed on October 1, 1977 (the “ICA”), and the rules and regulations promulgated thereunder. This includes movements of liquids through any pipelines, including those located solely within one state, that are providing part of the continuous movement of such liquids in interstate commerce for a shipper. The ICA requires that pipelines providing jurisdictional movements maintain a tariff on file with FERC, setting forth established rates and the rules and regulations governing transportation service, which must be “just and reasonable”. The ICA also requires that services be provided in a manner that is not unduly discriminatory or unduly preferential; in some cases, this may result in the proration of capacity among shippers in an equitable manner. +14 +The intrastate transportation of liquids is subject to regulation by state regulatory commissions, which in some cases require the provision of intrastate transportation on a nondiscriminatory basis and the prorationing of capacity on such pipelines under policies set forth in published tariffs. These state-level regulations may also impose certain limitations on the rates that the pipeline owner may charge for transportation. +Transportation of liquids by pipeline is subject to regulation by PHMSA pursuant to the Hazardous Liquids Pipeline Safety Act of 1979, as well as the PIPES Act 2006 and the PIPES Act 2011, which govern the design, installation, testing, construction, operation, replacement and management of liquids pipeline facilities. Liquids that are transported by rail may also be subject to additional regulation by PHMSA. +The availability, terms and cost of transportation affect the amounts we receive for our commodities. Historically, producers were able to flow supplies into interstate pipelines on an interruptible basis; however, recently we have seen an increased need to acquire firm transportation on pipelines in order to avoid curtailments or shut-in gas, which could adversely affect cash flows from the affected area. +Democratic control of the House, Senate and White House could lead to increased regulatory oversight and increased regulation and legislation, particularly around oil and gas development on federal lands, climate impacts and taxes. +Environmental Matters +Our operations are subject to numerous laws and regulations relating to environmental protection. These laws and regulations change frequently, and the effect of these changes is often to impose additional costs or other restrictions on our operations. We cannot predict the occurrence, timing, nature or effect of these changes. We also operate under a number of environmental permits and authorizations. The issuing agencies may take the position that some or all of these permits and authorizations are subject to modification, suspension, or revocation under certain circumstances, but any such action would have to comply with applicable procedures and requirements. +Hazardous Substances and Wastes +We generate wastes that may be subject to the Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. The U.S. Environmental Protection Agency (“EPA”) and various state agencies have adopted requirements that limit the approved disposal methods for certain hazardous and non-hazardous wastes. Furthermore, certain wastes generated by our operations that are currently exempt from treatment as “hazardous wastes” may in the future be designated as hazardous wastes, and therefore may subject us to more rigorous and costly operating and disposal requirements. In April 2019, the EPA, pursuant to a consent decree between the EPA and a coalition of environmental groups and a related review of RCRA regulations, determined that revision of the regulations is not necessary. The EPA indicated that it will continue to work with states and other organizations to identify areas for continued improvement and to address emerging issues to ensure that exploration, development and production wastes continue to be managed in a manner that is protective of human health and the environment. Environmental groups, however, expressed dissatisfaction with the EPA’s decision and will likely continue to press the issue at the federal and state levels. +We currently own or lease numerous properties that have been used for the exploration and production of crude oil and natural gas for many years. If hydrocarbons or other wastes have been disposed of or released on or under the properties that we own or lease or on or under locations where such wastes have been taken for disposal by us or prior owners or operators of such properties, we could be subject to liability under the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), RCRA and analogous state laws, as well as state laws governing the management of crude oil and natural gas wastes. CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of, transported or arranged for the disposal of the hazardous substances found at the site. Parties who are or were responsible for release of hazardous substances under CERCLA may be subject to full liability for the costs of cleaning up the hazardous substances that have been released into the environment or remediation to prevent future contamination and for damages to natural resources. In addition, under state laws, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. +15 +Hydraulic Fracturing +Hydraulic fracturing is commonly used to stimulate production of crude oil and/or natural gas from dense subsurface rock formations. We consistently utilize hydraulic fracturing in our crude oil and natural gas development programs. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations which are held open by the grains of sand, enabling the crude oil or natural gas to more easily flow to the wellbore. The process is generally subject to regulation by state oil and gas commissions, but is also the subject of various other regulatory initiatives at the federal, state and local levels. +Local Regulation +Various local and municipal bodies in each of the states in which we operate have sought to impose prohibitions, moratoria and other restrictions on hydraulic fracturing activities. In Colorado, Senate Bill 19-181 (“SB 19-181”) authorizes governmental authorities to regulate the siting and surface impacts of oil and gas development. We primarily operate in the rural areas of the core Wattenberg Field in Weld County, a jurisdiction in which there has historically been significant support for the oil and gas industry. In Texas, legislation enacted in 2015 generally prohibits political subdivisions from banning, limiting or otherwise regulating oil and gas operations. See Item 1A. Risk Factors-Risks Relating to Our Business and the Industry-Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us. +State Regulation +The states in which we currently operate have adopted or may adopt laws and regulations that impose or could impose, among other requirements, more stringent permitting processes and increased environmental protection and monitoring. +SB 19-181 changed the mission of the COGCC from fostering responsible and balanced development to regulating development to protect public health and the environment and directed the COGCC to undertake rulemaking on various operational matters. Pursuant to this direction, the COGCC conducted a series of rulemaking hearings during 2020 which resulted in updated regulatory and permitting requirements, including siting requirements. The new requirements prohibit the siting of locations within 2,000 feet of a school facility or child-care center. A similar 2,000-foot setback requirement applies to residential and high occupancy building units, but there are “off ramps” allowing oil and gas operators to site their drill pads as close as 500 feet from building units in certain circumstances. +In late July 2020, Governor Polis authored an op-ed stating that both industry and mainstream environmental groups have communicated a willingness to work together to prevent ballot initiatives in 2022. As part of that agreement, Governor Polis stated that he would “actively oppose” ballot initiatives around the oil and gas industry and acknowledged the importance of regulatory certainty. +It is nevertheless possible that future ballot initiatives will be proposed that would dramatically limit the areas of the state in which drilling would be permitted to occur. See Item 1A. Risk Factors-Risks Relating to Our Business and the Industry-Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us. +Federal Regulation +The U.S. Department of the Interior, through the Bureau of Land Management (the “BLM”), finalized a rule in 2015 requiring the disclosure of chemicals used, mandating well integrity measures and imposing other requirements relating to hydraulic fracturing on federal lands. The BLM rescinded the rule in December 2017. The BLM’s rescission of the rule was challenged in the United States District Court for the Northern District of California and in March 2020 the court issued a ruling upholding BLM’s rescission of the rule. That court ruling is currently subject to an appeal. +Private Lawsuits +Lawsuits have been filed against other operators in several states, including Colorado, alleging contamination of drinking water as a result of hydraulic fracturing activities. +16 +Greenhouse Gases +The EPA has published findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to public health and the environment because such emissions are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings provide the basis for the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the CAA. In June 2010, the EPA began regulating GHG emissions from stationary sources. +In the past, Congress has considered proposed legislation to reduce emissions of GHGs. To date, Congress has not adopted any such significant legislation, but may do so in the future. In November 2021, the U.S. House of Representatives passed H.R.5376, section 30114 of which would amend the Clean Air Act to impose a fee of $1,500 per ton of methane emitted above specified thresholds from onshore petroleum and natural gas production facilities, natural gas processing facilities, natural gas transmission and compression facilities, and onshore petroleum and natural gas gathering and boosting facilities, among other facilities. The U.S. Senate is currently considering H.R. 5376 and may adopt, modify, or eliminate the methane fee. +In addition, many states and regions have taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Since 2014, Colorado has engaged in multiple rulemakings to adopt significant additional rules regulating methane emissions from the oil and gas sector, and Colorado is expected to continue these efforts over the next several years. +The Obama administration reached an agreement during the December 2015 United Nations climate change conference in Paris pursuant to which the U.S. initially pledged to make a 26 percent to 28 percent reduction in its GHG emissions by 2025 against a 2005 baseline and committed to periodically update this pledge every five years starting in 2020 (the “Paris Agreement”). In April 2021, President Biden announced that the United States would aim to cut its greenhouse gas emissions 50 percent to 52 percent below 2005 levels by 2030. +Regulation of methane and other GHG emissions associated with oil and natural gas production could impose significant requirements and costs on our operations. See our GHG emission reduction goals included in Items 1. and 2. Business and Properties included elsewhere in this report. +Air Quality +Our operations are subject to the Clean Air Act (The “CAA”) and comparable state and local requirements. The CAA contains provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and state governments continue to develop regulations to implement these requirements. We may be required to make certain capital investments in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. See the footnote titled Commitments and Contingencies - Litigation and Legal Items to our consolidated financial statements included elsewhere in this report for further information regarding the Clean Air Act Section 114 Information Request that we received from the EPA. +In June 2016, the EPA implemented new requirements focused on achieving additional methane and volatile organic compound reductions from the oil and natural gas industry. The rules imposed, among other things, new requirements for leak detection and repair, control requirements for oil well completions, replacement of certain pneumatic pumps and controllers and additional control requirements for gathering, boosting and compressor stations. In September 2018, the EPA proposed revisions to the 2016 rules. The proposed amendments address certain technical issues raised in administrative petitions and include proposed changes to, among other things, the frequency of monitoring for fugitive emissions at well sites and compressor stations. In September 2020, the EPA issued a new rule which amended the 2016 requirements. In this rule, the EPA removed all sources in the transmission and storage segment of the oil and natural gas industry from regulation. The rule also rescinded the methane requirements in the 2016 regulations and loosened monitoring and repair regulations aimed at preventing methane leaks. On June 30, 2021, however, President Biden signed into law a joint Congressional resolution disapproving and invalidating much of the 2020 rule amendments under the prior Administration, including the 2020 rule’s rescission of the methane requirements. On November 15, 2021, EPA published a proposed rule that would update and expand existing requirements for the oil and gas industry, as well as creating significant new requirements and standards for new, modified, and existing oil and gas facilities. The proposed new requirements would include, for example, new standards and +17 +emission limitations applicable to storage vessels, well liquids unloading, pneumatic controllers, and flaring of natural gas at both new and existing facilities. The proposed rules for new and modified facilities are estimated to be finalized by the end of 2022, while any standards finalized for existing facilities will require further state rulemaking actions over the next several years before they become applicable and effective. +In November 2016, the BLM finalized rules to further regulate venting, flaring and leaks during oil and natural gas production activities on onshore federal and Indian leases (the “2016 Rule”). The 2016 Rule required additional controls and impose new emissions and other standards on certain operations on applicable leases, including committed state or private tracts in a federally approved unit or communitized agreement that drains federal minerals. In September 2018, the BLM published a final rule that revised the 2016 Rule (the “2018 Revised Rule”). The 2018 Revised Rule, among other things, rescinded the 2016 Rule requirements related to waste-minimization plans, gas-capture percentages, well drilling, well completion and related operations, pneumatic controllers, pneumatic diaphragm pumps, storage vessels and leak detection and repair. The 2018 Revised Rule also revised provisions related to venting and flaring. Environmental groups and the States of California and New Mexico filed challenges to the 2018 rule in the United States District Court for the Northern District of California, and in July 2020, the United States District Court for the Northern District of California vacated the BLM’s 2018 Revised Rule. However, in October 2020, the United States District Court for the District of Wyoming issued a ruling vacating the 2016 Rule, holding that the BLM exceeded its statutory authorities and acted arbitrarily. Both rulings have been appealed. The Spring 2021 Unified Agenda of Regulatory and Deregulatory Actions, published by the Office of Management and Budget’s Office of Information and Regulatory Affairs, identified a potential proposal by the BLM to update its existing rules governing the venting and flaring of natural gas (methane) from onshore Federal and Indian oil and gas leases. The BLM has not yet published such a proposed rule. +In 2019, the EPA increased the state of Colorado’s non-attainment ozone classification for the Denver Metro North Front Range Ozone Eight-Hour Non-Attainment (“Denver Metro/North Front Range NAA”) area from “moderate” to “serious” under the 2008 national ambient air quality standard (“NAAQS”). This increase in non-attainment status to “serious” triggered significant additional obligations for the state under the CAA and resulted in Colorado adopting new and more stringent air quality control requirements in December 2020 that are applicable to our operations. Based on current air quality monitoring data, it is expected that the Denver Metro/North Front Range NAA will be further “bumped-up” to “severe” status in 2022. This will trigger additional obligations for the state under the CAA and will result in new and more stringent air quality permitting and control requirements, which may in turn result in significant costs and delays in obtaining necessary permits applicable to our operations. +SB 19-181 also requires, among other things, that the Air Quality Control Commission (“AQCC”) adopt additional rules to minimize emissions of methane and other hydrocarbons and nitrogen oxides from the entire oil and gas fuel cycle. The AQCC has undertaken a multi-year rulemaking process to implement the requirements of SB 19-181, including a rulemaking to require continuous emission monitoring equipment at oil and gas facilities. Between December 2019 and December 2020, the AQCC completed several rulemakings as a result of SB 19-181, adopting significant additional and new emission control requirements applicable to oil and gas operations, including, for example, hydrocarbon liquids unloading control requirements, increased LDAR frequencies for facilities in certain proximity to occupied areas, and emission control requirements for certain large natural gas fired engines. The AQCC conducted an additional rulemaking in December 2021 related to SB 19-181, which is discussed further below. +Additionally, in response to HB 19-1261, which established statewide greenhouse gas reduction targets, Colorado, on September 30, 2020, released a public comment draft of its Greenhouse Gas Pollution Reduction Roadmap, which details early action steps the state can take toward meeting the near-term goals of reducing greenhouse gas (“GHG”) pollution by 26% by 2025 and 50% by 2030 from 2005 levels. On October 23, 2020, the AQCC issued the Resolution to Ensure Greenhouse Gas Reduction Goals Are Met in support of the roadmap, which estimates emission reductions needed from the oil and gas sector of 36% by 2025 and 50% by 2030. To meet these targets, as well as to address other air quality and environmental justice issues, the AQCC held a hearing in December 2021 and voted to adopt additional requirements and emission limitations applicable to oil and gas facilities in Colorado. The adopted regulatory requirements include, for example, more frequent fugitive emissions monitoring, a statewide GHG intensity program, emission limitations for well liquids unloading, and comprehensive testing of emission control devices. The adopted regulatory requirements are expected to become final and effective in early 2022. +State-level rules applicable to our operations include regulations imposed by the Colorado Department of Public Health and Environment’s (“CDPHE”) Air Quality Control Commission, including stringent requirements relating to monitoring, recordkeeping and reporting matters. In 2020, the COGCC relied in part on a previously-performed human health +18 +risk assessment in adopting new siting requirements. The COGCC also generally prohibited the venting or flaring of natural gas during drilling, completion, and production operations. +While the State of Texas has not formally conducted a recent rulemaking related to air emissions, scrutiny of oil and gas operations and the rules affecting them have increased in recent years. For example, EPA and environmental non-governmental organizations have conducted flyovers with optical gas imaging cameras to survey emissions from oil and gas production facilities and transmission infrastructure. In addition, the Texas Railroad Commission has increased oversight related to flaring, with reporting reviews and site inspections. While none of these activities increases our compliance obligations, they signal the potential for increased enforcement and possible rulemaking in the future. +Water Quality +The federal Clean Water Act (“CWA”) and analogous state laws impose strict controls concerning the discharge into regulated waterbodies and wetlands of pollutants and fill material, including spills and leaks of crude oil and other substances. The CWA also requires approval and/or permits prior to construction, where construction will disturb certain wetlands or other federally regulated waters of the U.S. (“WOTUS”). For years, both via administrative rulemakings and actions and judicial interpretation and intervention, the definition of “WOTUS” and how it has been applied has been in flux. In 2019 and 2020, the EPA and the Army Corps of Engineers (“USACE”) issued a final rule to repeal previous regulations and promulgated a new replacement rule (the “Navigable Waters Protection Rule”). The Navigable Waters Protection Rule was vacated by two separate federal district courts in late 2021. On November 18, 2021, EPA and USACE issued a pre-publication version of another rule largely reinstating the previous 1986 WOTUS rule and guidance “with certain amendments” to reflect “consideration of the agencies’ statutory authority under the CWA and relevant Supreme Court decisions” (the “2021 Proposed Rule”). The 2021 Proposed Rule was published in the Federal Register on December 7, 2021. In addition to the 2021 Proposed Rule, EPA and USACE plan to develop yet another amendment to the WOTUS regulations, which will build upon the regulatory foundation in the 2021 Proposed Rule with the benefit of additional stakeholder engagement and public input. It is unknown at this time when the 2021 Proposed Rule will take effect; when the next forthcoming proposed amendments are expected; and/or whether either new rule will be challenged and withstand any challenges in federal court. Finally, in January 2022, the United States Supreme Court granted review of Sackett vs. EPA , which involves issues related to CWA scope and jurisdiction and could impact the current rulemaking process. Although the outcome of the 2021 Proposed Rule and additional forthcoming amendments to the WOTUS regulations is unknown, the regulations under the Biden Administration are undoubtedly more stringent in terms of the scope of WOTUS, which could ultimately change the scope of the CWA’s jurisdiction and result in increased costs and delays with respect to obtaining permits for discharges of pollutants or dredge and fill activities in waters of the U.S., including regulated wetland areas. As noted above, however, things are constantly in flux and the fate of the definition of “WOTUS” under the CWA and how that ultimately will be applied by the Agencies is yet to be seen. +In May 2020, a federal court in Montana enjoined the use of nationwide permit (“NWP”) 12 to construct new oil and gas-related pipelines, on the basis that the USACE had not properly consulted with the U.S. Fish and Wildlife Service when that permit was renewed in 2017 (the court later amended its ruling to allow use of NWP 12 for non-oil and gas transmission projects). The U.S. Supreme Court in July 2020 significantly narrowed the Montana court’s injunction to cover only the challenged XL Pipeline. On August 11, 2021, the Ninth Circuit granted partial vacatur of the USACE’s appeal of the Montana district court’s opinion, holding the claim before it (the interlocutory appeals and underlying claim relative to the pipeline, which has been halted) was moot, but left to the district court the question of whether the case was moot in its entirety. +In the meantime, in September 2020 and again in January 2021, the USACE issued proposals to revise and reissue all 52 current NWPs, including No. 12, to, among other things, lessen the burden on the energy industry and address the flaws alleged in the Montana lawsuit. Although there are small differences in the September 2020 and January 2021 proposals, they do not impact the changes described below, particularly with NWP 12. The new NWPs became effective in March 2021. Among other things, under the new NWPs, existing NWP 12 was broken up into three new separate NWPs, with the new NWP 12 being limited solely to construction and maintenance of oil and gas pipelines, with other utility-related structures covered by the two new NWPs (i.e., NWP 57 for electric utility line and telecommunications activities and NWP 58 for utility line activities for water and other substances). The new 2021 version of NWP 12 has again been challenged in the District of Montana, by the same plaintiffs on the same grounds, which case is still pending. If the 2021 version of NWP 12 ultimately is invalidated or stayed by the courts, it could increase the costs and delays for oil and gas operators to construct or maintain pipelines that cross jurisdictional WOTUS. +19 +The CWA also regulates storm water run-off from crude oil and natural gas facilities and requires storm water discharge permits for certain activities. Spill Prevention, Control and Countermeasure (“SPCC”) requirements of the CWA require appropriate secondary containment, load out controls, piping controls, berms and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture or leak. +Endangered Species +The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and bald and golden eagles under the Bald and Golden Eagle Protection Act. Some of our operations may be located in areas that are or may be designated as habitats for endangered or threatened species or that may attract migratory birds, bald eagles or golden eagles. +Other +In October 2015, PHMSA proposed to expand its regulations in a number of ways, including increased regulation of gathering lines, even in rural areas, and proposed additional standards to revise safety regulations applicable to onshore gas transmission and gathering pipelines in 2016. In November 2021, PHMSA issued its final rule extending reporting requirements to all onshore gas gathering operators and applying a set of minimum safety requirements to certain onshore gas gathering pipelines with large diameters and high operating pressures. +Crude oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of crude oil spills. In addition to SPCC requirements, the Oil Pollution Act of 1990 (“OPA”) establishes requirements for preparation and EPA approval of Facility Response Plans and subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from crude oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Historically, we have not experienced any significant crude oil discharge or crude oil spill problems. +In February 2018, the COGCC comprehensively amended its regulations for oil, gas and water flowlines to expand requirements addressing flowline registration and safety, integrity management, leak detection and other matters. In November 2019, the COGCC further amended its flowline regulations pursuant to SB 19-181 to impose additional requirements regarding flowline mapping, operational status, certification and abandonment, among other things. +In June 2020, the COGCC amended its regulations regarding wellbore integrity. The amended rules impose additional requirements regarding the permitting, construction, operation, and closure of wells. In June 2021, the COGCC submitted a notice of rulemaking regarding its financial assurance rules. This rulemaking is expected to be completed in early 2022 and could increase the bonding requirements for our current and future oil and gas wells in Colorado. +We are also subject to rules regarding worker safety and similar matters promulgated by the U.S. Occupational Safety and Health Administration (“OSHA”) and other governmental authorities. OSHA has established workplace safety standards that provide guidelines for maintaining a safe workplace in light of potential hazards, such as employee exposure to hazardous substances. To this end, OSHA adopted a new rule governing employee exposure to silica, including during hydraulic fracturing activities, in March 2016. +Human Capital Management +We believe that our employees play a critical role in the achievement of our short-term and long-term business goals. Consequently, we are committed to attracting, retaining and developing highly motivated and qualified employees who share our core values. +Employee Engagement and Retention +We recognize and support the growth of our employees by offering internal and external development programs. We utilize an online training platform to allocate and track employee trainings and offer on-demand developmental training content. In 2021, our employees completed approximately 7,200 hours in aggregate within our platform alone on a variety of training topics to strengthen their skills and advance their careers. These trainings were provided through a virtual environment as a response to COVID-19. +20 +As of December 31, 2021, we had 535 full-time employees, 254 of whom are employed in field operations. During 2021, our voluntary turnover was around 10 percent. Our employees are not covered by collective bargaining agreements. We consider relations with our employees to be generally positive. +Health and Safety Culture +We are committed to the health, safety, and welfare of our employees, contractors, and neighbors. We regularly update our safety policies and procedures in an effort to ensure we are meeting or, where possible, exceeding new requirements and adopting new technologies to responsibly improve our operations. Additionally, all PDC field employees receive safety training upon hire and attend frequent meetings and refreshers to reinforce safety as a core value and our most important strategic priority. As a result of our commitment to health and safety, we have exceeded over three years without a lost time incident in either basin. +Our continual commitment to safety has resulted in improved safety records. Since the time Occupational Safety and Health Administration (“OSHA”) began requiring record-keeping and publication of health and safety information in 1972, we have not had any employee work-related fatalities. A commonly used measure of an organization’s safety performance is TRIR, which represents the number of injuries requiring medical treatment per 100 full-time employees during a one-year period. We monitor this performance measure and communicate it broadly across the company. We also include both TRIR and PVAR as part of our quantitative performance metrics under our STI program. For 2021, our TRIR was well below the most recent Bureau of Labor Statistics average for our industry. +In response to the COVID-19 pandemic, we have developed, implemented and adjusted a number of safety measures to help our employees safely navigate their work and personal responsibilities. +Diversity and Inclusion +We believe diversity and inclusion provides a business with growth and increased innovation and ultimately leads to a successful workforce. We are committed to providing equal opportunity in all aspects of employment and to hiring, evaluating and promoting employees based on skills and performance. We have an employee-led diversity and inclusion project team that identifies areas for growth and improvement, building on our current efforts in respect of diversity and inclusion. +Approximately 27% of our employees are women and 21% are members of a minority group, as defined by the U.S. Equal Employment Opportunity Commission, as of December 31, 2021. As of the same date, 32% of our executives are women and 17% members of a minority group. Since the beginning of 2021, we have expanded the diversity of our board of directors by adding three new diverse members with a unique set of backgrounds. +Employee Compensation and Benefits +Our compensation program is designed to provide competitive salaries and comprehensive incentives to attract, retain and reward employees to achieve results related to our core values and strategic priorities. The structure of our compensation program provides incentives for both short-term and long-term performance. We seek fairness in total compensation and benefits with reference to external benchmarking against our peers in the industry. All full-time employees are eligible for health insurance, paid and unpaid leave, retirement benefits (including an employer match up to 10% of wages), life and disability/accident coverage, and other benefits. We also offer stock awards and profit sharing for eligible employees. We believe that our compensation and benefits package is a strong retention tool and promotes physical, mental, financial and social health within our workforce. +WHERE YOU CAN FIND ADDITIONAL INFORMATION +We file annual, quarterly and current reports, proxy statements and other information with the SEC, which are maintained and available at www.sec.gov . Our SEC filings are also available free of charge from our website at www.pdce.com as soon as reasonably practicable after such material is filed with, or furnished to, the SEC. We also make available free of charge any of our SEC filings by mail. For a mailed copy of a report, please contact PDC Energy, Inc., Investor Relations, 1775 Sherman Street, Suite 3000, Denver, CO 80203, or call (303) 860-5800. +21 +We recommend that you view our website for additional information, as we routinely post information that we believe is important for investors. Our website can be used to access such information as our recent news releases, committee charters, code of business conduct and ethics, stockholder communication policy, director nomination procedures, sustainability report and our whistle blower hotline. While we recommend that you view our website, the information available on our website is not part of this report and is not incorporated by reference. +22 +ITEM 1A. RISK FACTORS +You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as the value of an investment in our common stock or other securities. +Risks Relating to the Global COVID-19 Pandemic +Our operations have been adversely affected as a result of the ongoing global COVID-19 pandemic. In particular, the pandemic contributed to a dramatic decrease in overall global economic activity generally, and crude oil prices in particular, in early 2020, and decreases in commodity prices can have a variety of negative effects on our business. While many of the adverse effects of the COVID-19 pandemic on our business have receded, it continues to be a unpredictable, particularly in the light of Delta, Omicron and other variants of concern, and additional adverse impacts on our business - including depressed crude oil, natural gas, and NGL prices, reductions in force, and reduced capital expenditures - could remain a risk for an indefinite period of time. +Risks Relating to Our Business and the Industry +Crude oil, natural gas and NGL prices fluctuate and declines in these prices, or an extended period of low prices, can significantly affect the value of our assets and our financial results and may impede our growth. +Many aspects of our business depend upon crude oil, natural gas and NGL prices, including: +• our revenue, profitability and cash flows; +• our liquidity; +• the quantity and present value of our reserves; +• the borrowing base under our revolving credit facility and access to other sources of capital; and +• the nature and scale of our operations. +The markets for crude oil, natural gas and NGLs are often volatile, and prices may fluctuate in response to, among other things: +• changes in regional, national or global economic conditions and trends, including supply and demand; +• geopolitical factors and events that reduce or increase production from oil-producing regions and/or from members of the Organization of Petroleum Exporting Countries (“OPEC”), and global events, such as the ongoing COVID-19 pandemic; and +• regulatory changes. +The price of oil has historically been volatile, due in recent years to a combination of factors including increased U.S. supply and global economic concerns. In the past two years, oil prices have ranged from highs over $80 per barrel to lows of approximately negative $40 per barrel. Prices for natural gas and NGLs have also experienced substantial volatility. If we reduce our capital expenditures due to low prices, natural declines in production from our wells will result in reduced cash flow from operations. Reduced cash flow would limit our ability to make the capital expenditures necessary to replace our reserves and production. +In addition to factors generally affecting the price of crude oil, natural gas and NGLs, the prices we receive for our production are affected by factors specific to us and to the local markets where production occurs. The prices we receive for our production vary from the relevant benchmark prices that are used for calculating commodity derivative positions. These differences, or differentials, are difficult to predict and may widen or narrow in the future based on markets and other forces, including local or regional supply and demand factors; terms of our sales contracts; investment decisions made by providers of midstream facilities and services, refineries and other industry participants; and the overall regulatory and economic climate. Widening differentials may materially and adversely impact our business. +We may be unable to return capital to our stockholders, and there is no assurance we will pay any dividends on or repurchase shares of our common stock in the future or at levels anticipated by our stockholders. +During each of the second, third and fourth quarters of 2021, our board of directors declared and paid a quarterly cash dividend of $0.12 per share of common stock, and in December 2021, our board declared and paid a special cash dividend of +23 +$0.50 per share of common stock. Our ability to pay cash dividends in the future depends on, among other things, our liquidity, financial condition, financial requirements, contractual restrictions, restrictions imposed by applicable law and other factors considered relevant by our board. Our board, based on this evaluation, may decide not to declare future dividends, or to declare dividends at rates less than anticipated, either of which could reduce overall returns to our stockholders. +In February 2022, our board of directors has also approved an increase to our Stock Repurchase Program to acquire up to $1.25 billion of our out standing common stock through December 31, 2023. This program is being implemented at the discretion of our board and may be extended, modified or discontinued at any time. We suspended the program in March 2020 due to adverse market conditions but reinstated it in February 2021. +Our overall capital return program may change from time to time, and we cannot guarantee we will continue to pay dividends or repurchase shares. Our announcement of capital return programs does not obligate us to pay any particular dividend amount (except with respect to dividends already declared) or repurchase any specific dollar amount or number of shares of common stock. A reduction, suspension or change in our capital return programs could have a negative effect on our stock price. +We are subject to complex federal, state, local and other laws and regulations that adversely affect the cost and manner of doing business. Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us. +Our exploration, development, production and marketing operations are regulated extensively at the federal, state and local levels. Environmental and other governmental laws and regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning crude oil and natural gas wells and associated facilities. Under these laws and regulations, we could also be liable for personal injuries, property damage and natural resource or other damages, and could be required to change, suspend or terminate operations. A summary of certain laws and regulations that apply to us and some potential changes to those laws and regulations is set forth in Items 1 and 2 - Business and Properties - Governmental Regulation . Any of the currently applicable laws and regulations could be amended, including in ways that we do not anticipate, and those changes could adversely affect our operations. +From time to time, we have been subject to sanctions and lawsuits relating to alleged noncompliance with regulatory requirements. For example, in October 2017, in order to settle a lawsuit brought against us by the U.S. Department of Justice, on behalf of the EPA and the State of Colorado, we entered into a consent decree pursuant to which we paid a fine and agreed to implement certain operational changes. The lawsuit claimed that we failed to operate and maintain certain equipment in compliance with applicable law. In addition, as a result of the SRC Acquisition, we are subject to the obligations and requirements of a 2018 Compliance Order on Consent (“COC”) entered into by SRC with CDPHE, applicable to certain SRC oil and gas production facilities we acquired from SRC. The COC resolved SRC’s alleged violations related to storage tank emissions and contains requirements similar to those contained in our consent decree. +The regulatory environment in which we operate also changes frequently, often through the imposition of new or more stringent environmental and other requirements, some of which may apply retroactively. We cannot predict the nature, timing, cost or effect of such additional requirements, but they may have a variety of adverse effects on us. The types of regulatory changes that could impact our operations vary widely and include, but are not limited to, the following: +• As discussed in Items 1 and 2, Business and Properties - Governmental Regulation , the COGCC completed extensive rulemaking hearings in November 2020 which resulted in the adoption of new requirements for setbacks, permitting, siting cumulative and surface impacts, asset transfers, venting and flaring, and remediation. The implementation of the final rules could have a significant adverse effect on our unpermitted locations and therefore on our future inventory and reserves. For example, the new planning and permitting process associated with long term, landscape level development (referred to as Comprehensive Area Plans) has not yet been successfully utilized by any operators in Colorado due to a lengthy, highly technical, and resource-intensive approval process. The COGCC is still in the process of issuing guidance and direction regarding the new requirements, and we cannot predict the impact of these requirements on our inventory and operations. +• Federal and various state, local and regional governmental authorities have implemented, or considered implementing, regulations that seek to limit or discourage the emission of carbon, methane and other GHGs. For example, the EPA has made findings and issued regulations that require us to establish and report an inventory of +24 +greenhouse gas emissions, and the state of Colorado has adopted rules regulating methane emissions from oil and gas operations. Additional laws or regulations intended to restrict the emission of GHGs could require us to incur additional operating costs and could adversely affect demand for the oil, natural gas and NGLs that we sell. These new laws or rules could, among other things, require us to install new emission controls on our equipment and facilities, acquire allowances to authorize our GHG emissions, pay taxes related to our emissions and administer and manage a GHG emissions program. In addition, like other energy companies, we could be named as a defendant in GHG-related lawsuits. +• Proposals are made from time to time to amend U.S. federal and state tax laws in ways that would be adverse to us, including by eliminating certain key U.S. federal income tax preferences currently available with respect to crude oil and natural gas exploration and production. The changes could include (i) the repeal of the percentage depletion deduction for crude oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain U.S. production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Also, state severance taxes may increase in the states in which we operate. This could adversely affect our existing operations in the relevant state and the economic viability of future drilling. +• The development of new environmental initiatives or regulations related to the acquisition, withdrawal, storage and use of surface water or groundwater or treatment and discharge of water waste, may limit our ability to use techniques such as hydraulic fracturing, increase our development and operating costs and cause delays, interruptions or termination of our operations, any of which could have an adverse effect on our operations and financial condition. +Increasing scrutiny and changing expectations from stakeholders with respect to our ESG practices may impose additional costs on us or expose us to new or additional risks. +Publicly traded companies, both in the oil and natural gas industry and otherwise, are facing increased scrutiny from stakeholders of our practices related to ESG. Attention on these issues may come from stakeholders ranging from the SEC to local governments to institutional investors, and these stakeholders may seek certain outcomes or results on issues they perceive to be material. This could result in reduced access to capital, shareholder proposals and other adverse effects. Companies that fail to adapt or comply with evolving stakeholder expectations, or are perceived as failing to respond appropriately, could suffer from reputational damage and the business, financial condition, and/or stock price of such a company could be materially and adversely impacted. +We have experienced increased pressure from our stakeholders focused on climate change to reduce our carbon footprint and prioritize sustainable energy practices. Our stakeholders may also require us to implement additional ESG procedures or standards in order to meet their expectations for continued investment. +We have publicly communicated commitments related to reductions in methane and greenhouse gas emissions and flaring. It is possible that our stakeholders may not be satisfied with these commitments or our progress towards them. This, or a failure to meet our targets, could lead to decreased access to capital or have a negative impact on our stock price. +Additionally, public sentiment related to the oil and gas industry may be affected by uncertainty or instability resulting from climate change, political leadership changes and subsequent policies, changes in social views regarding the importance of fossil fuels, concerns about environmental impact and investor expectations, resulting in decreased demand for our products. This could have a significant financial and operational impact on our business. +A substantial part of our crude oil, natural gas and NGLs production is located in the Wattenberg Field, making us vulnerable to risks associated with operating primarily in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing formations. +Although we have significant leasehold positions in the Delaware Basin in Texas, our current production is primarily located in the Wattenberg Field in Colorado. Because our production is not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including natural disasters, government regulations and midstream interruptions. +For example, bottlenecks in processing and transportation that have occurred in some recent periods in the Wattenberg Field have negatively affected our results of operations, and these adverse effects may be disproportionately severe to us +25 +compared to our more geographically diverse competitors. Similarly, the concentration of our producing assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules that could adversely affect development activities or production relating to those formations. Such an event could have a material adverse effect on our results of operations and financial condition. In addition, the demand for, and cost of, drilling rigs, equipment, supplies, chemicals, personnel and oilfield services often increase as a result of numerous factors including increases in exploration and production activity, supply chain problems, and labor shortages. Any shortages or increased costs could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital forecast, which could have a material adverse effect on our business, financial condition or results of operations. All of the producing properties and reserves we acquired in the SRC Acquisition are located in the Wattenberg Field. As a result, the transaction increased the risks we face with respect to the geographic concentration of our properties. +The marketability of our production is dependent upon transportation and processing facilities which we do not control. If these facilities are unavailable, or if we are unable to access these facilities on commercially reasonable terms, our operations could be interrupted, negatively affecting our results of operations. +Our ability to market our production depends in substantial part on the availability, proximity and capacity of in-field gathering systems, compression and processing facilities, and transportation pipelines, all of which are owned and operated by third parties. If adequate midstream facilities and services are not available to us on a timely basis and at acceptable costs, our production may be curtailed and our results of operations will be adversely affected. +Availability or capacity issues can be a result of depressed commodity prices that ultimately reduce investment in new midstream facilities, new or amended government regulations curtailing drilling activities in Colorado which could discourage investment in midstream facilities, protests over construction of new pipelines and facilities, weather, fire, or other reasons, and could negatively affect our results of operations. In addition to causing production curtailments, capacity constraints can also reduce the price we receive for the crude oil, natural gas and NGLs we produce. +Like other producers, we from time to time enter into volume commitments with midstream providers in order to induce them to provide increased capacity. If our production falls below the level required under these agreements, we could be subject to substantial shortfalls, deficiency, or similar fees. +Our undeveloped acreage must be drilled before lease expiration, and production must thereafter be maintained under applicable lease terms, to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells and thereafter maintain production under applicable lease terms could result in substantial lease renewal costs or, if renewal is not feasible, loss of our lease and prospective drilling opportunities. +Unless production is established and thereafter maintained under applicable lease terms within the spacing or pooled units covering our undeveloped acreage, our leases for such acreage will expire. The cost to renew such leases may increase significantly and we may not be able to renew such leases on commercially reasonable terms or at all. Unexpected lease expirations could occur if our actual drilling activities or our ongoing production differ materially from our current expectations, and this could result in impairment charges. The risk of lease expiration is greater at times and in areas where the pace of our exploration and development activity slows or production declines or is otherwise shut-in. Our ability to drill, develop, and maintain production under applicable lease terms from the locations necessary to maintain our leases depends on a number of factors, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, and regulatory approvals, all of which are subject to risks and uncertainties. +We may incur losses as a result of title defects in the properties in which we invest or acquire. +It is our practice in acquiring oil and gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of oil and gas lease brokers or landmen who perform record title examinations before we acquire oil and gas leases and related interests. The existence of a material title deficiency can decrease a lease’s value and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property. +26 +Our ability to produce crude oil, natural gas and NGLs economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of or recycle the water we use at a reasonable cost, in a timely manner and within applicable environmental rules. +Drilling and development activities such as hydraulic fracturing require the use of water and result in the production of wastewater. Our operations could be adversely impacted if we are unable to locate sufficient amounts of water or dispose of or recycle water used and produced in our exploration and production operations. The quantity of water required in certain completion operations, such as hydraulic fracturing, and changing regulations governing usage may lead to water constraints, supply concerns and regulatory issues, particularly in relatively arid climates such as eastern Colorado and western Texas. For example, increased drilling activity in the Delaware Basin in recent years has led to heightened concerns about water supply issues in the area and this may lead to regulatory actions, including rules providing local governments greater authority over water use, that adversely impact our operations. +Our operations depend on being able to reuse or dispose of wastewater in a timely and economic fashion. Wastewater from oil and gas operations is often disposed of through underground injection. Wells in the Delaware Basin typically produce relatively large amounts of water that require disposal and an increased number of earthquakes have been detected in the Delaware Basin in recent years. Some studies have linked earthquakes, or induced seismicity, in certain areas to underground injection, which is leading to increased public and regulatory scrutiny of injection safety. This increased scrutiny applied to our Colorado operations as well. For example, in November 2020, the COGCC adopted various new requirements on the underground injection of fluid waste. In December 2021, the Texas Railroad Commission suspended the deep injection of wastewater in the Gardendale Seismic Response Area. +Reduced commodity prices could result in significant impairment charges and significant downward revisions of proved reserves. +Commodity prices are volatile. Significant and rapid declines in prices have occurred in the past and may occur in the future. Low commodity prices could result in, among other things, significant impairment charges in the future. For example, we incurred impairment charges in a number of recent periods, including charges of $882.4 million and $38.5 million in 2020 and 2019, respectively, to write down assets. Similarly, the significant decline in commodity pricing during 2020 resulted in a reduced year-end proved reserve NYMEX price of $39.57 per barrel of crude and $1.99 per MMBtu of natural gas, a decrease of 29% and 23% respectively from 2019. The decline in pricing resulted in a downward revision of 28.2 MMBoe to reserves for year-end 2020 when compared to year-end 2019. The cash flow model we use to assess properties for impairment includes numerous assumptions, such as management’s estimates of future oil and gas production and commodity prices, the outlook for forward commodity prices and operating and development costs. All inputs to the cash flow model must be evaluated at each date the estimate of future cash flows is made for each producing basin. A significant decrease in long-term forward prices could result in a significant impairment for our properties. +Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. +The process of estimating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. In determining the estimates of reserve and economic evaluations, management utilizes independent petroleum engineers. The reserve estimates are based on assumptions regarding commodity prices, production levels and operating and development costs that may prove to be incorrect. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate and revisions in existing reserve estimates occur. +Reserve estimates are based on the volumes of crude oil, natural gas and NGLs that are anticipated to be economically recoverable from a given date forward based on economic conditions that exist at that date. The actual quantities of crude oil, natural gas and NGLs recovered will be different than the reserve estimates, in part because they will not be produced under the same economic conditions as are used for the reserve calculations. +27 +You should not assume that the present value of the estimated future net cash flows from our proved reserves is the current market value of those reserves. Pursuant to SEC rules, the estimated discounted future net cash flows from our proved reserves, and the estimated quantity of those reserves, are based on the average of the previous 12-months’ first day of the month prices and costs as of the date of the estimate. Actual future prices and costs may be materially different. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production and changes in governmental regulations or taxes. Significant variances could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K and cause potential impairment charges. In addition, the 10 percent discount factor we use when calculating discounted future net cash flows (the rate required by the SEC) may not be the most appropriate discount factor based on interest rates currently in effect and risks associated with our properties or the industry in general. +Unless reserves are replaced as they are produced, our reserves and production will decline, which would adversely affect our future business, financial condition and results of operations. We may not be able to develop our identified drilling locations as planned. +Producing crude oil, natural gas and NGL reservoirs are generally characterized by declining production rates that may vary over time and exceed our estimates depending upon reservoir characteristics and other factors. Our future reserves and production and, therefore, our cash flows and income, are highly dependent on our ability to efficiently develop and exploit our current reserves and to economically find or acquire additional recoverable reserves. We may not be able to develop, discover or acquire additional reserves to replace our current and future production at acceptable costs. Our failure to do so would adversely affect our future operations, financial condition and results of operations. +We have identified a number of well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including: +• crude oil, natural gas and NGL prices; +• the availability and cost of capital; +• drilling and production costs; +• availability and cost of drilling rigs, and equipment, supplies, chemicals, personnel and oilfield services; +• drilling results; +• lease expirations or limitations as to depth; +• midstream constraints; +• access to and availability of water sourcing and distribution systems; +• regulatory approvals; and +• other factors. +Because of these factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce crude oil, natural gas or NGLs from these or any other potential well locations. In addition, the number of drilling locations available to us will depend in part on the spacing of wells in our operating areas. An increase in well density in an area could result in additional locations in that area, but a reduced production performance from the area on a per-well basis. Conversely, a decrease in well density could result in fewer locations in an area but possibly increased production performance on a per-well basis. For example, after examining well performance and other factors, we recently determined that our current Delaware Basin position supports fewer wells per unit than previously assumed. Accordingly, as of December 31, 2021, our estimated well locations for our current Delaware Basin position decreased from 135 to 65. +Further, certain of the horizontal wells we intend to drill in the future may require pooling of our lease interests with the interests of third parties. Some states, including Colorado, allow the involuntary pooling of tracts in a relatively broad number of circumstances to facilitate exploration, though Colorado now requires applicants to own or secure consent from the owners of more than 45 percent of the minerals to be pooled. Other states, notably Texas, restrict involuntary pooling to a much narrower set of circumstances and consequently these states rely primarily on voluntary pooling of lands and leases. In states such as Texas where pooling is accomplished primarily on a voluntary basis, or in states such as Colorado if we cannot meet the minimum requirement for ownership and consent, it may be more difficult to form units and, therefore, more difficult to fully develop a project if we own less than all (or cannot secure the ownership or consent of the required minimum amount) of the leasehold in the proposed units or one or more of our leases in the proposed units does not provide the necessary pooling +28 +authority. If third parties in the proposed units are unwilling to pool their interests with ours, we may be unable to require such pooling on a timely basis or at all, which would limit the total horizontal wells we can drill. Further, the number of available locations will depend in part on the expected lateral lengths of the horizontal wells we drill. Because the intended lateral length of a horizontal well is subject to change for a variety of reasons, our estimated drilling locations will change over time. For this and numerous other reasons, our actual drilling activities may materially differ from those presently identified. +Our inventory of drilling projects includes locations in addition to those that we currently classify as proved, probable and possible. The development of and results from these additional projects are more uncertain than those relating to probable and possible locations, and significantly more uncertain than those relating to proved locations. We have generally continued a steady pace of development in the Wattenberg Field over the past several years, and while the SRC Acquisition increased our inventory, continued development has reduced our inventory drilling locations. We also anticipate that our remaining locations in the field will not, on average, be as productive or as economic as many of those we have drilled in recent years, due to lower anticipated overall production or higher gas-to-oil ratios. In the Delaware Basin, our inventory is subject to, among other things, potential lease expirations (as to acreage and/or depths) and our continued analysis of geologic challenges in certain areas. For example, as noted above, we recently reduced our estimated number of locations in the Delaware Basin due to geological issues. +The wells we drill may not yield crude oil, natural gas or NGLs in commercially viable quantities and productive wells may be less successful than we expect. +A prospect is a property on which our geologists have identified what they believe, based on available information, to be indications of hydrocarbon-bearing rocks. However, given the limitations of available data and technology, our geologists cannot know conclusively prior to drilling and testing whether crude oil, natural gas or NGLs will be present in sufficient quantities to repay drilling or completion costs and generate a profit. Furthermore, even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques do not enable our geologists to be certain as to the quantity of the hydrocarbons in those structures. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline. If a well is determined to be dry or uneconomic, which can occur even though it contains some crude oil, natural gas or NGLs, it is classified as a dry hole and plugged and abandoned in accordance with applicable regulations. This generally results in the loss of the entire cost of drilling and completion to that point. Even wells that are completed and placed into production may not produce sufficient crude oil, natural gas and NGLs to be profitable, or they may be less productive and/or profitable than we expected. For example, the data we use to model anticipated results from wells in a particular area may prove to be not representative of actual results from typical wells in the area, and this could result in production that falls short of estimates reflected in our internal business plans and/or guidance, “type curve” or other disclosures we make to the public. This risk is higher for us in certain areas in the Delaware Basin that have relatively complex geological characteristics and correspondingly greater variability in well results. In addition, initial results from a well are not necessarily indicative of its performance over a longer period. +Drilling for and producing crude oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations. +Drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling can be unprofitable, not only due to dry holes, but also due to curtailments, delays or cancellations as a result of other factors, including: +• pressures or irregularities in geological formations; +• fires; +• floods, winter storms and other natural disasters and adverse weather conditions; +• loss of well control; +• loss of drilling fluid circulation and other facility or equipment malfunctions; +• title problems; +• facility or equipment malfunctions; +• unexpected operational events; +• shortages or delays in the delivery of equipment and services; +• unanticipated environmental liabilities; and +• compliance with environmental and other governmental requirements. +29 +Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, loss of wells, pollution, environmental contamination and regulatory penalties. For example, a loss of containment of hydrocarbons during drilling activities could potentially subject us to civil and/or criminal liability and the possibility of substantial costs, including for environmental remediation. We maintain insurance against various losses and liabilities arising from our operations; however, insurance against certain operational risks may not be available or may be prohibitively expensive relative to the perceived risks presented. In addition, we may not have coverage with respect to a pollution event if we are unaware of the event while it is occurring and are therefore unable to report the occurrence of the event to our insurance company within the time frame required under our insurance policy. Thus, losses could occur for which we have no effective insurance coverage. The occurrence of an event that is not fully covered by insurance and/or governmental or third-party responses to an event could have a material adverse effect on our business activities, financial condition and results of operations. We are currently involved in various remedial and investigatory activities at some of our wells and related sites. +In addition, certain technical risks relating to the drilling of horizontal wells - including those relating to our ability to fracture stimulate the planned number of stages and to successfully run casing the length of the well bore - have increased in recent years because we have increased the average lateral length of the horizontal wells we drill. Longer-lateral wells are also typically more expensive and require more time for preparation. In addition, we use multi-well pads instead of single-well sites. The use of multi-well pad drilling increases some operational risks because problems affecting the pad or a single well could adversely affect production from all of the wells on the pad. Pad drilling can also make our overall production, and therefore our revenue and cash flows, more volatile, because production from multiple wells on a pad will typically commence simultaneously. While we believe that we will be better served by using multi-well pads with longer lateral wells, the risk component involved in such drilling will be increased in some respects, with the result that we might find it more difficult to achieve economic success in our drilling program. +The inability of one or more of our customers or other counterparties to meet their obligations may adversely affect our financial results. +Substantially all of our accounts receivable result from our crude oil, natural gas and NGLs sales or joint interest billings to a small number of third parties in the energy industry. This concentration of customers and joint interest owners may affect our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our commodity derivatives expose us to credit risk in the event of nonperformance by counterparties. Nonperformance by our customers or derivative counterparties may adversely affect our financial condition and profitability. We face similar risks with respect to our other counterparties, including the lenders under our revolving credit facility and the providers of our insurance coverage. +We participate in oil and gas operations with third parties who may not be able to fulfill their commitments to our projects. +We frequently own less than all of the working interest in the oil and gas leases and/or wells on which we conduct operations. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities, arising from the actions of the other owners. A partner may be unable or unwilling to pay its share of project costs, and, in some cases, may declare bankruptcy. In the event any of our project partners does not pay its share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover the costs from the partner. This could materially adversely affect our financial position. +We may not be able to keep pace with technological developments in our industry. +Our industry is characterized by rapid and significant technological advancements. As our competitors use or develop new technologies, we may be placed at a competitive disadvantage, and competitive pressures may force us to implement those or other new technologies at substantial cost. In addition, our competitors may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and may in the future allow them to implement new technologies before we can. We may not be able to respond to these competitive pressures and implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete or if we were unable to use the most advanced technology, our business, financial condition and results of operations could be materially adversely affected. +30 +Competition in our industry is intense, which may adversely affect our ability to succeed. +Our industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce crude oil, natural gas and NGLs, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive properties and exploratory prospects or evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, larger companies may have a greater ability to continue exploration activities during periods of low commodity prices. Larger competitors may also be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which could adversely affect our competitive position. These factors could adversely affect our operations and our profitability. +Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel. +Our future success depends to a large extent on the services of our key employees. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise. +A failure to complete successful acquisitions would limit our ability to replace our reserves and impact our financial condition. +Because our crude oil and natural gas properties are depleting assets, our future reserves, production volumes and cash flows depend on our success in developing and exploiting our current reserves efficiently and finding or acquiring additional recoverable reserves economically. In addition, we continue to strive to achieve greater efficiencies in our drilling program, and our ability to do so is dependent in part on our ability to complete asset exchanges and other acquisitions that allow us to increase our working interests in particular properties. We may not be able to identify attractive acquisition opportunities, and if we do identify an appropriate acquisition candidate, we may be unable to negotiate mutually acceptable terms with the seller, finance the acquisition or obtain the necessary regulatory approvals. If we are unable to complete suitable acquisitions on acceptable terms, it will be more difficult to replace our reserves, and an inability to replace our reserves would have a material adverse effect on our financial condition and results of operations. +Acquisitions of properties are subject to the uncertainties of evaluating recoverable reserves and potential liabilities, including environmental uncertainties. +Acquisitions of producing and undeveloped properties have been an important part of our growth over time. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, development potential, future commodity prices, operating costs, title issues and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we generally perform engineering, environmental, geological and geophysical reviews of the acquired properties that we believe are generally consistent with customary industry practices. However, such reviews are not likely to permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not typically inspect every well prior to an acquisition and our ability to evaluate undeveloped acreage is inherently imprecise. Even when we inspect a well, we may not always discover structural, subsurface and environmental problems that may exist or arise after the acquisition. In some cases, our review prior to signing a definitive purchase agreement may be even more limited. In addition, we often acquire acreage without any warranty of title except as to claims made by, through or under the transferor. +When we acquire properties, we will generally have potential exposure to liabilities and costs for environmental and other problems existing on the acquired properties, and these liabilities may exceed our estimates. We may not be entitled to contractual indemnification associated with acquired properties. We often acquire interests in properties on an “as is” basis with no or limited remedies for breaches of representations and warranties. Therefore, we could incur significant unknown liabilities, +31 +including environmental liabilities or losses due to title defects, in connection with acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, the acquisition of undeveloped acreage is subject to many inherent risks and we may not be able to realize efficiently, or at all, the assumed or expected economic benefits of acreage that we acquire. +Additionally, significant acquisitions can change the nature of our operations depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or may be in different geographic locations than our existing properties. These factors can increase the risks associated with an acquisition. Acquisitions also present risks associated with the additional indebtedness that may be required to finance the purchase price and any related increase in interest expense or other related charges. +Some of our acquisitions are structured as asset trades or exchanges. These transactions may give rise to any or all of the foregoing risks. In addition, transactions of this type create a risk that we will undervalue the properties we transfer to the counterparty in the trade or exchange or overvalue the properties we receive. Such an undervaluation or overvaluation would result in the transaction being less favorable to us than we expected. +We operate in a litigious environment. The cost of defending any suits brought against us, and any judgments or settlements resulting from such suits, could have an adverse effect on our results of operations and financial condition. +Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, employment litigation, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. For example, in January 2021, a purported class action lawsuit was filed against us by a royalty owner alleging we have been improperly deducting certain post-production costs from the owner’s oil royalty payments. While we intend to vigorously defend this suit, the outcome of legal proceedings is inherently uncertain. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management attention and other factors. In addition, the resolution of any such legal or other proceedings could result in penalties or sanctions, settlement costs and/or judgments, consent decrees or orders requiring a change in our business practices, any of which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties, sanctions or costs may be insufficient. Judgments and estimates to determine accruals or the anticipated range of potential losses related to legal and other proceedings could change from one period to the next, and such changes could be material. Information regarding legal proceedings can be found in Item 3. Legal Proceedings included elsewhere in this report. +Our business could be negatively impacted by security threats, including cybersecurity threats and other disruptions. +We face various security threats, including attempts by third parties to gain unauthorized access to, or control of, competitive information or to render data or systems corrupted or unusable; threats to the safety of our employees; threats to the security of our infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. There can be no assurance that the procedures and controls we use to monitor these threats and mitigate our exposure to them will be sufficient to prevent them from materializing. +Our industry has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain exploration, development and production activities. We depend on digital technology, including information systems and related infrastructure, as well as cloud applications and services, to store, transmit, process and record sensitive information (including but not limited to trade secrets, employee information and financial and operating data), communicate with our employees and business partners, and for many other activities related to our business. In addition, computer systems control the oil and gas production and processing equipment that are necessary to deliver our production to market. Critical infrastructure targets, such as energy-related assets and transportation assets, may be at greater risk of future cyber-attacks than other targets. A disruption or failure of these systems, or of the networks and infrastructure on which they rely, may cause damage to critical production, distribution and/or storage assets, delay or prevent delivery to markets, or make it difficult to accurately account for production and settle transactions. The various procedures, facilities, infrastructure and controls we utilize to monitor these threats and mitigate our exposure to such threats are costly and labor intensive. Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring. The continuing and evolving threat of cybersecurity attacks has resulted in increased regulatory focus on prevention, which could potentially elevate costs, and failure to comply with these regulations could result in penalties and potential legal liability. +32 +As dependence on digital technologies has increased in our industry, cyber incidents, including deliberate attacks and unintentional events, have also increased. Our systems and infrastructure are, and those of our business partners, including vendors, service providers, operating partners, purchasers of our production and financial institutions may be, subject to damage or interruption from a number of potential sources including natural disasters, software viruses or other malware, power failures, cyber-attacks and other events. We and our business partners also face various other cyber-security threats from criminal hackers, state-sponsored intrusion, industrial espionage and employee malfeasance, including threats to gain access to sensitive information or to render data or systems unusable. +Our technologies, systems and networks, and those of our business partners, may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, theft of property or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. To our knowledge, we have not suffered material losses related to cyber-attacks to date; however, there can be no assurance that we will not suffer material losses in the future either as a result of an interruption to or a breach of our systems or those of our third-party vendors and service providers. If we were successfully attacked, we could incur substantial remediation and other costs or suffer other negative consequences, such as a loss of competitive information, critical infrastructure, personnel or capabilities essential to our operations. Events of this nature could have a material adverse effect on our reputation, financial condition, results of operations or cash flows. Moreover, as the sophistication of cyber-attacks continues to evolve, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities. +The physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects. An economy-wide transition to lower GHG energy sources could have a variety of adverse effects on our operations and financial results. +Many scientists have shown that increasing concentrations of carbon dioxide, methane and other GHGs in the Earth’s atmosphere are changing global climate patterns. One consequence of climate change could be increased severity of extreme weather, such as increased hurricanes and floods. If such events were to occur, or become more frequent, our operations could be adversely affected in various ways, including through damage to our facilities or from increased costs for insurance. +Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for natural gas is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for the fuels that we produce. As a result, if there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business. +Efforts by governments, international bodies, businesses and consumers to reduce GHGs and otherwise mitigate the effects of climate change are ongoing. The nature of these efforts and their effects on our business are inherently unpredictable and subject to change. Certain regulatory responses to climate change issues are discussed above under the heading “We are subject to complex federal, state, local and other laws and regulations that adversely affect the cost and manner of doing business. Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us” and in Items 1 and 2 - Business and Properties - Governmental Regulation. However, actions taken by private parties in anticipation of, or to facilitate, a transition to a lower-GHG economy will affect us as well. For example, our cost of capital may increase if lenders or other market participants decline to invest in fossil fuel-related companies for regulatory or reputational reasons. Similarly, increased demand for low-carbon or renewable energy sources from consumers could reduce the demand for, and the price of, the products we produce. Technological changes, such as developments in renewable energy and low-carbon transportation, could also adversely affect demand for our products. +Risks Relating to Financial Matters +Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our production and reserves, and ultimately our profitability. Lender hesitancy to offer financing to our industry may increase this risk. +Our industry is capital intensive. We expect to continue to make substantial capital expenditures for the exploration, development, production and acquisition of crude oil, natural gas and NGL reserves. To date, we have financed capital expenditures primarily with bank borrowings under our revolving credit facility, cash generated from operations and proceeds +33 +from capital markets transactions and the sale of properties. We intend to finance our future capital expenditures utilizing similar financing sources. Our cash flows from operations and access to capital are subject to a number of variables, including: +• our proved reserves; +• the amount of crude oil, natural gas and NGLs we are able to produce from existing wells; +• the prices at which crude oil, natural gas and NGLs are sold; +• the costs to produce crude oil, natural gas and NGLs; and +• our ability to acquire, locate and produce new reserves. +If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower commodity prices, operating difficulties or for any other reason, our need for capital from other sources could increase, and there can be no assurance that such other sources of capital would be available at that time on reasonable terms or at all. If we raise funds by issuing additional equity securities, this would have a dilutive effect on existing shareholders. If we raise funds through the incurrence of debt, the risks we face with respect to our indebtedness would increase and we would incur additional interest expense. +Additionally, due to recent default rates in the oil and gas industry and other factors, some lenders have expressed a hesitancy to lend to oil and gas producers, and may require terms less favorable to the producers or, in some cases, may refuse to provide financing to the industry altogether. The number of lenders participating in our revolving credit facility decreased in connection with the amendment and restatement of the facility in 2021, and may decline further in the future. Our inability to obtain sufficient financing on acceptable terms would adversely affect our financial condition and profitability. +The cost of servicing, and risks related to refinancing, our debt could adversely affect our business. Those risks could increase if we incur more debt. +As of December 31, 2021, we had a total long-term debt of $950 million. Servicing our indebtedness and satisfying our other obligations will require a significant amount of cash, and cash flow from operating activities and other sources may not be sufficient to fund our liquidity needs. Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend on our future operating performance, our financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control. +A substantial decrease in our operating cash flow or an increase in our expenses could make it difficult for us to meet debt service requirements and could require us to modify our operations, including by curtailing our exploration and drilling programs, reducing our capital expenditures, selling assets, refinancing all or a portion of our existing debt or obtaining additional financing. We may or may not be able to complete any such steps on satisfactory terms. Any ability to generate sufficient cash flows to satisfy our debt obligations or contractual commitments, or to refinance our debt on commercially reasonable terms, could materially and adversely affect our financial condition and results of operations. +Covenants in our debt agreements currently impose, and future financing agreements may impose, operating and financial restrictions. +Our current debt agreements contain restrictions, and future financing agreements may contain additional restrictions, on our activities, including covenants that restrict our and our restricted subsidiaries’ ability to: +• incur additional debt; +• pay dividends on, redeem or repurchase stock; +• create certain liens; +• make specified types of investments; +• apply net proceeds from certain asset sales; +• engage in transactions with our affiliates; +• engage in sales and leaseback transactions; +• merge or consolidate; and +• sell, assign, transfer, lease, convey or dispose of assets. +34 +Our revolving credit facility is secured by substantially all of our oil and gas properties as well as a pledge of all ownership interests in our current operating subsidiaries. The restrictions contained in our current or future debt agreements may prevent us from taking actions that we believe would be in the best interest of our business. In addition, our ability to comply with covenants and restrictions in our debt agreements in the future is uncertain and will be affected by the levels of cash flows from operations and events or circumstances beyond our control. Our failure to comply with any of these restrictions and covenants could result in a default under our debt agreements. In the event of such a default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder, and under other agreements to which a cross-default or cross-acceleration provision applies, to be due and payable, together with accrued and unpaid interest; the lenders under our revolving credit facility could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets; and we could be forced into bankruptcy or liquidation. +Our lenders have sole discretion to set our borrowing availability based on anticipated commodity prices and corporate outlook. +The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based upon projected revenues from the properties securing their loan. Decreases in the price of crude oil, natural gas or NGLs may have an adverse effect on the borrowing base. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Outstanding borrowings in excess of the borrowing base must be repaid immediately unless we pledge other crude oil and natural gas properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility. Our inability to borrow additional funds under our revolving credit facility could adversely affect our operations and our financial results. +Our commodity derivative activities could result in financial losses or reduced income from failure to perform by our counterparties, could limit our potential gains from increases in prices and could result in volatility in our net income. +We use commodity derivatives for a portion of the production from our own wells to achieve more predictable cash flows, to reduce exposure to adverse fluctuations in commodity prices, and to allow our natural gas marketing company to offer pricing options to natural gas sellers and purchasers. These arrangements expose us to the risk of financial loss in some circumstances, including when purchases or sales are different than expected or the counterparty to the commodity derivative contract defaults on its contractual obligations. In addition, many of our commodity derivative contracts are based on WTI or another crude oil or natural gas index price. The risk that the differential between the index price and the price we receive for the relevant production may change unexpectedly makes it more difficult to hedge effectively and increases the risk of a hedging-related loss. Also, commodity derivative arrangements may limit the benefit we would otherwise receive from increases in the prices for the relevant commodity. +At December 31, 2021, we had hedged a total of 22.2 MMBbls crude oil for 2022 to 2024 and 102.5 MMBtu of natural gas for 2022 and 2023. These hedges may be inadequate to protect us from continuing and prolonged declines in crude oil and natural gas prices. +Since we do not designate our commodity derivatives as cash flow hedges, we do not currently qualify for use of hedge accounting; therefore, changes in the fair value of commodity derivatives are recorded in our income statements and our net income is subject to greater volatility than it would be if our commodity derivative instruments qualified for hedge accounting. For instance, if commodity prices rise significantly, this could result in significant non-cash charges during the relevant period, which could have a material negative effect on our net income. +The price of our common stock has been and may continue to be highly volatile, which may make it difficult for shareholders to sell our common stock when desired or at attractive prices. +The market price of our common stock is highly volatile and we expect it to continue to be volatile for the foreseeable future. Adverse events including changes in production volumes, worldwide demand and prices for crude oil and natural gas, regulatory developments, and changes in securities analysts’ estimates of our financial performance could negatively impact the market price of our common stock. General market conditions, including the level of, and fluctuations in, the trading prices of stocks generally could also have a similar negative impact. The stock markets regularly experience price and volume volatility that affects many companies’ stock prices without regard to the operating performance of those companies. Volatility of this type may affect the trading price of our common stock. Similar factors could also affect the trading prices of our senior notes. +35 +Risks Relating to Pending Great Western Acquisition +If completed, the Great Western Acquisition may not achieve its intended results and may result in us assuming unanticipated liabilities. To date, we have conducted only limited diligence regarding the assets and liabilities we would assume in the transaction. +We entered into the Purchase Agreement with the expectation that the Great Western Acquisition would result in various benefits, growth opportunities and synergies. Achieving the anticipated benefits of the transaction is subject to a number of risks and uncertainties. For example, under the Purchase Agreement, we have the opportunity to conduct customary environmental and title due diligence following the execution of the agreement, but our diligence efforts to date have been limited. As a result, we may discover title defects or adverse environmental or other conditions of which we are currently unaware. Environmental, title and other problems could reduce the value of the properties to us, and, depending on the circumstances, we could have limited or no recourse to the sellers with respect to those problems. We would assume substantially all of the liabilities associated with the acquired properties and would be entitled to indemnification in connection with those liabilities in only limited circumstances and in limited amounts. We cannot assure you that such potential remedies will be adequate for any liabilities we incur, and such liabilities could be significant. +As with other acquisitions, the success of the Great Western Acquisition depends on, among other things, the accuracy of our assessment of the reserves and drilling locations associated with the acquired properties, future oil, NGL and natural gas prices and operating costs and various other factors. These assessments are necessarily inexact. As a result, we may not recover the purchase price for the acquisition from the sale of production from the property or recognize an acceptable return from such sales. +The reserves, production and drilling locations estimates with respect to the properties to be acquired in the Great Western Acquisition may differ materially from the actual amounts. +Our estimates of the reserves, production and drilling locations associated with the properties to be acquired in the Great Western Acquisition are based on our analysis of historical production data, assumptions regarding capital expenditures and anticipated production declines. Such analysis is based, in significant part, on data provided by the sellers. We cannot assure you that these estimates are accurate. After such data is further reviewed by us and our independent engineers, the actual reserves, production and number of viable drilling locations may differ materially from the amounts we have estimated. +The transactions contemplated by the Purchase Agreement are subject to conditions that may not be satisfied on a timely basis or at all. Failure to complete the transactions contemplated by the Purchase Agreement could have material and adverse effects on us. +Completion of the Great Western Acquisition is subject to a number of conditions, including the accuracy of the parties’ representations in the Purchase Agreement and the receipt of certain governmental approvals. Such conditions, some of which are beyond our control, may not be satisfied or waived in a timely manner or at all and therefore make the completion and timing of the completion of the Great Western Acquisition uncertain. In addition, the Purchase Agreement contains certain termination rights for both Great Western and us, which if exercised will also result in the Great Western Acquisition not being consummated. Furthermore, the governmental authorities from which the federal regulatory approvals are required may impose conditions on the completion of the Great Western Acquisition or require changes to the terms of the acquisition or the Purchase Agreement. +If the transactions contemplated by the Purchase Agreement are not completed, our business may be adversely affected and, without realizing any of the benefits of having completed the Great Western Acquisition, we will be subject to a number of risks, including the following: we will be required to pay our costs relating to the Great Western Acquisition, such as legal, accounting, and financial advisory fees; time and resources committed by our management to matters relating to the Great Western Acquisition could otherwise have been devoted to pursuing other beneficial opportunities; and the market price of our common stock could be impacted to the extent that the current market price reflects a market assumption that the Great Western Acquisition will be completed. In addition, if the Purchase Agreement is terminated and the Board seeks another acquisition, we cannot be certain that we will be able to find a party willing to enter into a transaction as attractive to us as the Great Western Acquisition. +36 +We will be subject to business uncertainties while the Great Western Acquisition is pending, which could adversely affect our business. +It is possible that certain persons with whom we have a business relationship may delay certain business decisions relating to us, or seek to terminate, change or renegotiate their relationships with us, in connection with the pendency of the Great Western Acquisition. This could negatively affect our revenues, earnings and cash flows, as well as the market price of our common stock, regardless of whether the Great Western Acquisition is completed. Also, our ability to attract, retain and motivate employees may be impaired until the Great Western Acquisition is completed and for a period of time thereafter as current and prospective employees may experience uncertainty about their roles within the combined company following the transaction. +In addition, under the terms of the Purchase Agreement, we are subject to certain restrictions on the conduct of our business prior to the completion of the Great Western Acquisition, which may adversely affect our ability to execute certain of our business strategies. Such limitations could negatively affect our business and operations prior to the completion of the Great Western Acquisition. +Even if the Great Western Acquisition is completed, we may not achieve the anticipated benefits and the Great Western Acquisition may disrupt our current plans or operations. +The success of the Great Western Acquisition will depend, in part, on our ability to realize the anticipated benefits and cost savings from combining our and Great Western’s businesses, and there can be no assurance that we will be able to successfully integrate Great Western or otherwise realize the anticipated benefits of the Great Western Acquisition. Difficulties in integrating Great Western into our company may result in us performing differently than expected, in operational challenges or in the failure to realize anticipated expense-related efficiencies. Potential difficulties that may be encountered in the integration process include, among others: +• the inability to successfully integrate Great Western into PDC in a manner that permits us to achieve the full cost savings or operating synergies anticipated from the Great Western Acquisition; +• complexities associated with managing a larger, more complex, integrated business; +• the disruption or the loss of momentum in, each company’s ongoing business or inconsistencies in standards, controls, procedures and policies. +We are expected to incur significant transaction costs in connection with the Great Western Acquisition, which may be in excess of those we currently anticipate. +We expect to incur a number of non-recurring costs associated with negotiating and completing the Great Western Acquisition, combining the operations of the two companies and achieving desired synergies. These fees and costs have been, and will continue to be, substantial and, in many cases, will be borne by us whether or not the Great Western Acquisition is completed. A substantial majority of our non-recurring expenses will consist of transaction costs related to the Great Western Acquisition and include, among others, fees paid to financial, legal, accounting and other advisors. We will also incur transaction costs related to formulating and implementing integration plans, including facilities and systems consolidation costs and other employment-related costs. We will continue to assess the magnitude of these costs, and we may incur additional unanticipated costs. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, may not offset integration-related costs and achieve a net benefit in the near term or at all. The costs described above and any unanticipated costs and expenses, many of which will be borne by us even if the Great Western Acquisition is not completed, could have an adverse effect on our financial condition and operating results. +After the Great Western Acquisition is completed, PDC will be proportionally more exposed to regulatory risks associated with oil and gas operations in Colorado and other risks associated with a more geographically-concentrated asset base. +PDC's principal assets in terms of production and reserves are located in the Wattenberg Field located within the Denver-Julesburg Basin of Colorado, but we also have a significant acreage position in the Delaware Basin in Texas. During 2021, 87 percent of PDC's production came from its assets in Colorado and 13 percent came from its assets in Texas. All of Great Western’s properties, and all of its current production and reserves, are located in Colorado. Various new regulatory requirements applicable to oil and natural gas operations in Colorado have been proposed or adopted in recent years as described elsewhere in this report. +The increased percentage of PDC's combined production located in the Wattenberg Field following the Great Western Acquisition will proportionately increase PDC's exposure to risks associated with operating in a more concentrated geographic area, including Colorado-specific regulatory and midstream risks as described elsewhere in this section. +37 +ITEM 1B. UNRESOLVED STAFF COMMENTS +None. +ITEM 3. LEGAL PROCEEDINGS +Information regarding our legal proceedings can be found in Note 13 - Commitments and Contingencies - Litigation and Legal Items included in Item 8. Financial Statements and Supplementary Data to our consolidated financial statements included elsewhere in this report. +Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as discussed herein, we are not aware of any material environmental claims existing as of December 31, 2021 which have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws or other environmental liabilities will not be discovered on our properties. Accrued environmental liabilities are recorded in other accrued expenses in the consolidated balance sheets. +Following a self-audit of final reclamation activities associated with site retirements, we formally disclosed identified deficiencies to the Colorado Oil and Gas Conservation Commission (“COGCC”) in December 2019. In August 2020, the COGCC issued a Notice of Alleged Violation (“NOAV”) citing a failure to comply with reclamation requirements at multiple locations. To resolve the alleged violations in July of 2021, the COGCC and PDC jointly agreed to an Administrative Order by Consent (“AOC”) which assessed penalties in the amount of approximately $500,000, with approximately $350,000 suspended pending PDC meeting certain conditions of the AOC. We are implementing programs to meet the requirements of the AOC and correct any identified deficiencies. +On August 30, 2021 and November 1, 2021, the COGCC issued us NOAVs related to the timing of wellhead pressure test reporting for certain wells in the Wattenberg Field. Pursuant to the NOAVs, we have conducted and submitted a comprehensive audit of our wellhead pressure testing and reporting processes. We are actively updating our processes to mitigate against the possibility of the alleged violations occurring in the future. We do not anticipate a material effect on our financial condition or results of operations. However, the potential penalties may exceed $300,000. +Commencing in early 2020, we conducted a comprehensive air quality compliance audit over the facilities acquired in +the SRC Acquisition. Through the self-audit process, we identified certain deficiencies and disclosed them to the Colorado Department of Public Health and Environment (“CDPHE”) and the U.S. Environmental Protection Agency (“EPA”) in July 2021. We do not believe potential penalties and other expenditures associated with the deficiencies identified will have a +material effect on our financial condition or results of operations, but such penalties may exceed $300,000. +Clean Air Act Agreement and Related Consent Decree. We continue to implement the requirements of a consent decree entered into with the CDPHE in 2017, as well as a revised compliance order on consent, the latter of which was modified by the CDPHE after the SRC Acquisition was completed. Per the terms of the agreements, we will apply for termination in early 2022. Over the course of this execution, we have identified certain immaterial deficiencies in our implementation of the programs. We report these immaterial deficiencies to the appropriate authorities and remediate them promptly. We do not believe that the penalties and expenditures associated with the consent decree, including any sanctions associated with these deficiencies, will have a material effect on our financial condition or results of operations, but they may exceed $300,000. +Further, we could be the subject of other enforcement actions by regulatory authorities in the future relating to our past, present or future operations. +ITEM 4. MINE SAFETY DISCLOSURES +Not applicable. +38 +PART II +ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Our common stock, par value $0.01 per share, is traded on the NASDAQ Global Select Market under the symbol “PDCE”. As of February 15, 2022, we had approximately 386 stockholders of record. +In May 2021, our board of directors approved the Company’s quarterly dividend program and we announced the initiation of a quarterly dividend in the amount of $0.12 per share of our common stock. We declared and paid an aggregate amount of $0.86 per share of our common stock during 2021, which included a special dividend of $0.50 per share of our common stock declared and paid in the fourth quarter of 2021. The dividend program and payment of any future dividends thereunder will be made at the discretion of our board of directors and will depend on our results of operations, cash flows, financial position and capital requirements, as well as general business conditions, legal, tax and regulatory restrictions and other factors our board of directors deems relevant at the time it determines to declare such dividends. +Additionally, our revolving credit facility, as well as the indentures governing our 2024 Senior Notes and our 5.75% senior notes due 2026 (the “2026 Senior Notes”), the terms of which are summarized in Note 10 - Long-term Debt in Item 8. Financial Statements and Supplementary Data included elsewhere in this report, include restrictions based on our leverage and other certain financial metrics that could impact our ability to pay cash dividends. As we declare dividends in the future, we will monitor compliance with such restrictions. +The following table presents information about our purchases of our common stock during the year ended December 31, 2021: +Period +Total Number of Shares Purchased (1) (2) +Average Price Paid per Share +Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1) +Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs (in millions) +January 28,831 $ 23.27 — $ 346.8 +February 53,401 32.25 2,289 346.7 +March 596,388 36.99 595,460 324.7 +April 345,614 35.36 255,268 315.7 +May 211,555 40.14 210,310 307.3 +June 201,576 46.39 196,070 298.2 +July 283,191 41.10 280,000 286.7 +August 915,811 39.30 915,000 250.7 +September 281,058 43.47 281,058 238.5 +October 54,680 45.54 50,000 236.2 +November 275,200 54.48 275,200 221.2 +December 692,800 48.95 692,800 187.3 +Total purchases 3,940,105 $ 42.16 3,753,455 $ 187.3 +_____________ +(1) In April 2019, our board of directors approved a program to acquire up to $200.0 million of our outstanding common stock and in August 2019, effective with the closing of the SRC Acquisition, increased such amount to $525.0 million (the “Stock Repurchase Program”). The Stock Repurchase Program does not require any specific number of shares to be acquired, and can be modified or discontinued by our board of directors at any time. We reinstated our Stock Repurchase Program in late February 2021 and in February 2022, our board of directors increased the size of the program to $1.25 billion and extended it through December 31, 2023. +(2) Purchases outside of the Stock Repurchase Program represent shares withheld from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans. The withheld shares are not considered common stock repurchased under the Stock Repurchase Program. +39 +Stockholder Performance Graph +The following performance graph and related information shall deemed to be furnished, but not filed with the SEC. +The graph below matches the cumulative 5-Year total return of our common stock with the cumulative total returns of the Standard and Poor’s (“S&P”) 500 Index and a customized peer group of 126 companies. The cumulative total stockholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on December 31, 2016 and tracks it through December 31, 2021, in the S&P 500 Index and in the customized peer group on the same date. The results shown in the graph below are not necessarily indicative of future stock price performance. +COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN +Among PDC Energy, Inc., the S&P 500 Index, +and a Peer Group +Year Ended December 31, +2016 2017 2018 2019 2020 2021 +PDC Energy 100.00 71.01 41.00 36.06 28.29 69.20 +S&P 500 100.00 121.83 116.49 153.17 181.35 233.41 +Peer Group 100.00 97.71 72.90 66.54 40.68 81.79 +40 +ITEM 6. [RESERVED] +This Item has been omitted as we are no longer required to provide five years of selected financial data. +ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included in Item 8. Financial Statements and Supplementary Data and also with Item 1A. Risk Factors of this report. A discussion of changes in our results of operations and liquidity from 2019 to 2020 has been omitted from this report but can be found in Item 7. Management’s Discussion and Analysis , of our Annual Report on Form 10-K for the year ended December 31, 2020, filed with the SEC on February 25, 2021. Further, we encourage you to review the Special Note Regarding Forward-Looking Statements in Part I of this report. +EXECUTIVE SUMMARY +2021 Financial Overview of Operations and Liquidity +Market Conditions +The crude oil and natural gas industry is cyclical and commodity prices are inherently volatile. Commodity prices reflect global supply and demand dynamics as well as the geopolitical and macroeconomic environment. +Crude Oil Markets +In 2020, the COVID-19 pandemic led to a significant decline in commodity prices due to the decrease in demand for crude oil, negatively impacting crude oil and natural gas producers, such as PDC. Due to the decrease in oil demand, the Organization of Petroleum Exporting Countries (“OPEC”) and other oil producing countries significantly decreased production, resulting in a low level of global supply. During 2021, the global economy slowly recovered from the impacts of COVID-19 and related variants through vaccination distributions. The recovery of the global economy was supported by gradual increases to production volumes from OPEC and other oil producing countries; however, demand growth exceeded the production increases, resulting in higher commodity prices compared to pre-COVID-19 prices. The commodity price environment may remain volatile for an extended period due to, among other things, outbreaks caused by coronavirus variants, the recovery of the economy, unexpected supply disruptions in key producing countries, geopolitical disputes, weather conditions, and ongoing investor and regulatory pressure to replace fossil fuel consumption with lower carbon emission alternatives. +Natural Gas and NGL Markets +In addition to the crude oil market drivers noted above, natural gas and NGL prices are also affected by structural changes in supply and demand, growth in levels of liquified natural gas exports and deviations from seasonally normal weather. Lower inventory levels and lack of reinvestment in supply growth have driven natural gas and NGL prices higher than recent levels. +Financial Matters +Twelve months ended December 31, 2021 +• Production volumes increased 4 percent to 71.3 MMboe in 2021 compared to 2020 as a result of our full-year drilling and completion program during 2021. +• Crude oil, natural gas and NGLs sales increased to $2.6 billion in 2021 compared to $1.2 billion in 2020, primarily due to the 112 percent increase in weighted average realized commodity prices. +• Incurred negative net settlements from our commodity derivative contracts of $410.2 million compared to positive net settlements of $279.3 million in 2020 due to improvement in commodity prices during 2021. +41 +• Combined revenue from crude oil, natural gas and NGLs sales and net settlements from our commodity derivative instruments increased 50 percent to $2.1 billion from $1.4 billion in 2020. +• Generated net income of $522.3 million, or $5.22 per diluted share, compared to a net loss of $724.3 million, or $7.37 per diluted share, in 2020. The net income during the period compared to the net loss in the prior period was significantly impacted by an increase in crude oil, natural gas and NGLs sales of $1,400.0 million and an $882.4 million impairment charge recognized in 2020. These positive factors were partially offset by an increased loss of $881.7 million in commodity price risk management and $105.8 million in additional production taxes between periods. +• Adjusted EBITDAX, a non-U.S. GAAP financial measure, was $1,593.8 million compared to $990.6 million in 2020, primarily due to an increase in sales of $710.5 million, net of negative net derivative settlements. +• Cash flows from operations increased to $1,547.8 million compared to $870.1 million in 2020. Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased to $1,532.6 million compared to $921.6 million in 2020. Adjusted free cash flows, a non-U.S. GAAP financial measure, increased to $949.0 million from $399.3 million in 2020. +See Reconciliation of Non-U.S. GAAP Financial Measures below for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures. +Pending Acquisition +On February 26, 2022, we entered into the Acquisition Agreement to acquire Great Western for approximately $1.3 billion, inclusive of Great Western’s net debt. Great Western is an in dependent oil and gas company focused on the exploration, production and development of crude oil and natural gas in Colorado. We anticipate acquiring approximately 54,000 net acres in the Core Wattenberg and production of approximately 55,000 Boe per day. Under the terms of the Acquisition Agreement, the purchase price of the Great Western Acquisition will consist of approximately 4.0 million shares of our common stock and approximately $543 million in cash. The cash portion of the purchase price is expected to be funded through a combination of cash on hand and availability under our revolving credit facility. We expect the Great Western Acquisition to be completed in the second quarter of 2022, subject to certain customary closing conditions. Upon a successful close, we anticipate adding between $225 million and $275 million to our planned 2022 Wattenberg capital investment. See Item 1A. Risk Factors for risk factors related to the Great Western Acquisition of this report. +Drilling, Completion and Vertical Well Abandonment Overview +During 2021, we operated one full-time drilling rig, one spudder rig and one full-time completion crew in the Wattenberg Field. In addition, we operated one full-time drilling rig and one part-time completion crew, which started in March and ended in June, in the Delaware Basin. Our total capital investments in crude oil and natural gas properties for the year ended December 31, 2021 were $583.7 million. We operated a full-time workover rig in the Wattenberg Field in 2021 for use in our plugging and abandonment program. This program focused on our legacy vertical wells to assist in our horizontal drilling program and to reduce our overall produced well emissions. We spent $30.5 million on this program in 2021. +42 +The following table summarize our drilling, completion and vertical well abandonment activities for the year ended December 31, 2021: +Operated Wells +Wattenberg Field Delaware Basin Total +Gross Net Gross Net Gross Net +In-process as of December 31, 2020 +214 201.8 20 19.0 234 220.8 +Wells spud 78 74.2 19 19.0 97 93.2 +Wells turned-in-line (149) (143.0) (18) (17.4) (167) (160.4) +In-process as of December 31, 2021 +143 133.0 21 20.6 164 153.6 +Plugged and abandoned - Vertical Wells 404 392.0 — — 404 392.0 +Our in-process wells represent wells that are in the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection. Our in-process wells are generally completed and turned-in-line within two years of drilling. +Debt Reductions and Capital Returns +Debt Reduction. During the year ended December 31, 2021, we significantly reduced our indebtedness by $670.3 million. This reduction included net repayments of $168.0 million on our revolving credit facility, resulting in no outstanding balance at the period end. On September 15, 2021, we redeemed and retired our 2021 Convertible Notes with a cash payment for the principal amount of $200 million, plus accrued and unpaid interest. Additionally, on November 3, 2021, we redeemed the aggregate $200 million principal amount of our outstanding 2024 Senior Notes at a redemption price of 101.531 percent of the principal plus accrued and unpaid interest, leaving an aggregate principal amount outstanding of $200 million. Finally, on December 1, 2021, we redeemed the remaining $102.3 million principal amount of our outstanding 6.25% Senior Notes due in 2025 (the “2025 Senior Notes”) at a redemption price of 103.125 percent of the principal plus accrued and unpaid interest. +The redemptions of our 2021 Convertible Notes and 2025 Senior Notes as well as the partial redemption of our 2024 Senior Notes were financed by our cash flows from operations. +Stock Repurchase Program. In February 2021, we reinstated our Stock Repurchase Program. During the year ended December 31, 2021, we repurchased 3.8 million shares of outstanding common stock at a cost of $159.5 million. As of December 31, 2021, $187.3 million remained available under the program. In February 2022, our board of directors increased the size of the program to $1.25 billion, which we anticipate fully utilizing by December 31, 2023. +Dividends . In the second quarter of 2021, our board of directors commenced the declaration and payment of quarterly cash dividends of $0.12 per share of our common stock. In December 2021, our board of directors declared and paid a special dividend of $0.50 per share of our common stock in addition to the regular fourth quarter dividend declared. For the year ended December 31, 2021, our dividends paid totaled $0.86 per share of common stock or $83.6 million in the aggregate. +2022 Operational and Financial Outlook +We anticipate that our production for 2022 will range between 195,000 Boe to 205,000 Boe per day, approximately 62,000 Bbls to 65,000 Bbls of which are expected to be crude oil. Our planned 2022 capital investments in crude oil and natural gas properties, which we expect to be between $675 million and $725 million, are focused on continued execution of our development plans in the Wattenberg Field and the Delaware Basin. Our 2022 capital investments budget incorporates an increase in both basins relating to service cost inflation resulting in an estimated cost increase of approximately 10 to 15 percent per well, based on costs we have experienced since the third quarter of 2021. +We have operational flexibility to control the pace of our capital spending. As we execute our capital investment program, we continually monitor, among other things, expected rates of return, the political environment and our remaining +43 +inventory to best meet our short- and long-term corporate strategy. We may revise our 2022 capital investment program during the year as a result of, among other things, changes in commodity prices or our internal long-term outlook for commodity prices, requirements to hold acreage, the cost of services for drilling and well completion activities, drilling results, changes in our borrowing capacity, a significant change in cash flows, regulatory issues, requirements to maintain continuous activity on leaseholds and acquisition and divestiture opportunities. +Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays in the rural areas of the core Wattenberg Field, which is further delineated between the Kersey, Prairie, Plains, and Summit development areas. Our 2022 capital investment program for the Wattenberg Field represents approximately 75 percent of our expected total capital investments in crude oil and natural gas properties. In 2022, the majority of the wells we plan to drill are 1.5 mile and 2.0 mile lateral wells in the Wattenberg Field. In 2022, we anticipate spudding approximately 130 to 145 operated wells and turning-in-line approximately 115 to 130 operated wells. As of December 31, 2021, we have approximately 145 gross operated DUCs and 235 approved permitted locations. In 2022, we expect to add a rig in March, bringing us to two full-time horizontal rigs and one completion crew along with a part-time spudder rig. +Delaware Basin. Total capital investments in crude oil and natural gas properties in the Delaware Basin for 2022 are expected to be approximately 25 percent of our total capital investments. In 2022, we anticipate spudding and turning-in-line approximately 15 to 20 operated wells. The majority of the wells we plan to drill in 2022 in the Delaware Basin are 2.0 mile lateral wells. +We are committed to our disciplined approach to managing our development plans. Based on our current production forecast for 2022, we expect 2022 cash flows from operations to exceed our capital investments in crude oil and natural gas properties. Our first priority is to pay our quarterly base dividend of $0.25 per share. Then we expect to use approximately 60% or more of our remaining adjusted free cash flows, a non-U.S. GAAP financial measure, for share repurchases and special dividends, as needed. Any remaining adjusted free cash flows will be used for reducing debt, building cash on our consolidated balance sheet or other general corporate purposes. +Regulatory and Political Updates +In Colorado, certain interest groups opposed to oil and natural gas development have proposed ballot initiatives that could hinder or eliminate the ability to develop resources in the state. In 2019, the Colorado legislature passed Senate Bill 19-181 (“SB 19-181”) to address concerns underlying the ballot initiatives. +As part of SB 19-181, a series of rulemaking hearings were conducted, which focused on issues such as permitting requirements, setbacks and siting requirements, resulting in the adoption of new regulatory requirements. Rulemakings focused on financial assurance and permit fees have not been completed. The financial assurance rulemaking could result in increased bonding requirements, though the final language and impact will not be known until early 2022. +A key component of SB 19-181 was the change in the COGCC mission from “fostering” the industry to “regulating” the industry. As a result, changes were made to the permitting process in Colorado. As of January 2021, permits are now designed as Oil and Gas Development Plans (“OGDP”), which streamlines single pad locations or proximate multi-pad locations into a single permitting package. +Operators also have an option to pursue a Comprehensive Area Plan (“CAP”). A CAP is designed to represent an overview of oil and gas development over a larger area over a longer period of time, including a comprehensive cumulative impact analysis, an alternative location analysis, and extensive communication with both local elected officials and communities. A CAP will include multiple OGDPs within its boundaries. As both CAPs and OGDPs are new processes and the COGCC staff is working to develop the appropriate requirements and adjusting to their new operating plan, the time needed to obtain a permit has been prolonged. COGCC rules provide that the permitting process could range between six to twelve months or more from submission to approval. +We cannot predict whether future ballot initiatives or other legislation or regulation will be proposed that would limit the areas of the state in which drilling is permitted to occur or impose other requirements or restrictions. +44 +Wattenberg Permits Update. PDC was granted unanimous approval for an 8-well OGDP located in rural Weld County in October 2021, our first approval under the new permitting process resulting from a company-wide collaborative effort. As part of the permit process, we successfully obtained consent from all nearby residents and landowners, which was an option designed by the COGCC for locations with residential building units within 2,000 feet. Additionally, in September, we submitted our application for an OGDP covering an approximate 70-well, multi-pad development plan. We anticipate a COGCC determination on approval of this OGDP in the second quarter of 2022. +In December, PDC submitted our first CAP. The application proposes approximately 450 wells spread amongst 25 surface locations in Weld County, to be developed over several years. We conducted a comprehensive analysis of potential impacts and have committed to transport all water and commodity production via pipeline and to provide electrical infrastructure to all locations. These commitments will lessen the impact of traffic, noise, light and emissions. Additionally, we developed a dashboard to analyze disproportionately impacted communities in the area and developed a robust communication plan designed to encourage communication with and garner feedback from these key stakeholders. We anticipate a COGCC determination on approval of our CAP by year end 2022 or early 2023, recognizing that there may be delays in this new process. +Together, these applications represent our planned Wattenberg Field turn-in-line activity into 2027. +Environmental, Social and Governance +We are committed to a meaningful and measurable ESG strategy. Our mission to be a cleaner, safer and more socially responsible company begins with a sound strategy, is supported in the boardroom and is overseen by our newly created ESG&N Committee at the board of directors and is applied at every level of our business. +We recognize the importance of reducing our environmental footprint and have created proactive programs and targets related to emission reduction. These initiatives, which include the plugging and abandonment of legacy vertical wells, retrofits of air pneumatics on older facilities, electrification of our facilities, technological innovations and other activities, require capital and operational investments which are proactively and regularly built into our annual budgeting process. We anticipate approximately $80 million in spending relating to ESG in 2022, which include certain expenditures to ensure compliance with state regulations and the plugging and abandonment of approximately 300 legacy vertical wells. We anticipate a similar level of annual spending over the next several years relating to ESG and compliance to achieve our emission target goals outlined below. We do not anticipate these projects having a material impact on our operations. However, we may revise our 2022 ESG budget during the year as a result of, among other things, changes in commodity prices or our internal long-term outlook for commodity prices, a significant change in cash flows or regulatory developments. +During 2021, we implemented the following ESG initiatives: +• Formalized our board oversight of ESG issues by incorporating ESG into our N&G Committee, which became the ESG&N Committee. +• Issued a Sustainability Report addressing a variety of ESG and sustainability matters, including significant Sustainability Accounting Standards Board compliance. The Sustainability Report is available on our website at www.pdce.com and is not incorporated by reference in this report. +• Continued board of directors refreshment by adding two diverse directors and one additional diverse director in February 2022, reflecting a commitment to diversity, refreshment and independence. +• Set aggressive targets to (i) reduce greenhouse gas intensity by 60% from 2020 emissions by 2025 and 74% by 2030, (ii) reduce methane emissions intensity by 50% from 2020 emissions by 2025 and 70% by 2030, and (iii) eliminate routine flaring by 2025. +The SEC and other regulatory bodies are proposing a number of climate change-focused and broader ESG reporting requirements. If adopted, we will modify our disclosures accordingly. +45 +Results of Operations +Summary of Operating Results +The following table presents selected information regarding our operating results for the periods presented: +Year Ended December 31, +Percent Change +2021 2020 2019 +2021-2020 +2020-2019 +(dollars in millions, except per unit data) +Production: +Crude oil (MBbls) 22,682 23,720 19,166 (4) % 24 % +Natural gas (MMcf) 175,747 165,637 115,950 6 % 43 % +NGLs (MBbls) 19,360 17,042 10,923 14 % 56 % +Crude oil equivalent (MBoe) 71,333 68,368 49,414 4 % 38 % +Average Boe per day (Boe) 195,433 186,798 135,381 5 % 38 % +Crude Oil, Natural Gas and NGLs Sales: +Crude oil $ 1,530.8 $ 816.8 $ 1,020.7 87 % (20) % +Natural gas 519.6 178.8 151.0 191 % 18 % +NGLs 502.2 157.0 135.6 220 % 16 % +Total crude oil, natural gas and NGLs sales $ 2,552.6 $ 1,152.6 $ 1,307.3 121 % (12) % +Net Settlements on Commodity Derivatives: +Crude oil $ (289.1) $ 294.4 $ (18.3) (198) % * +Natural gas (121.1) (15.1) 0.7 * * +Total net settlements on derivatives $ (410.2) $ 279.3 $ (17.6) (247) % * +Average Sales Price (excluding net settlements on derivatives): +Crude oil (per Bbl) $ 67.49 $ 34.44 $ 53.26 96 % (35) % +Natural gas (per Mcf) 2.96 1.08 1.30 174 % (17) % +NGLs (per Bbl) 25.94 9.21 12.41 182 % (26) % +Crude oil equivalent (per Boe) 35.78 16.86 26.46 112 % (36) % +Average Costs and Expense (per Boe): +Lease operating expense $ 2.53 $ 2.36 $ 2.88 7 % (18) % +Production taxes 2.32 0.87 1.63 167 % (47) % +Transportation, gathering and processing expenses 1.41 1.14 0.94 24 % 21 % +General and administrative expense 1.79 2.36 3.27 (24) % (28) % +Depreciation, depletion and amortization 8.90 9.06 13.04 (2) % (31) % +Lease Operating Expense by Operating Region (per Boe): +Wattenberg Field $ 2.19 $ 2.15 $ 2.50 2 % (14) % +Delaware Basin 4.76 3.48 4.15 37 % (16) % +____________ +* Percent change is not meaningful. +46 +Crude Oil, Natural Gas and NGLs Sales +Crude oil, natural gas and NGLs sales for the year ended December 31, 2021 increased compared to the year ended December 31, 2020 due to the following: +Year Ended December 31, 2021 +(in millions) +Change in: +Production $ (3.5) +Average crude oil price 749.7 +Average natural gas price 329.9 +Average NGLs price 323.9 +Total change in crude oil, natural gas and NGLs sales revenue $ 1,400.0 +The negative impact in sales relating to the change in production volumes during the year ended December 31, 2021 compared to 2020 was impacted by a 4 percent decrease in crude oil production between periods. +Crude Oil, Natural Gas and NGLs Production +The following table presents crude oil, natural gas and NGLs production for the periods presented: +Year Ended December 31, +Percent Change +Production by Operating Region 2021 2020 2019 +2021-2020 +2020-2019 +Crude oil (MBbls) +Wattenberg Field 18,901 19,552 14,489 (3) % 35 % +Delaware Basin 3,781 4,168 4,677 (9) % (11) % +Total 22,682 23,720 19,166 (4) % 24 % +Natural gas (MMcf) +Wattenberg Field 154,150 140,845 91,785 9 % 53 % +Delaware Basin 21,597 24,792 24,165 (13) % 3 % +Total 175,747 165,637 115,950 6 % 43 % +NGLs (MBbls) +Wattenberg Field 17,300 14,495 8,198 19 % 77 % +Delaware Basin 2,060 2,547 2,725 (19) % (7) % +Total 19,360 17,042 10,923 14 % 56 % +Crude oil equivalent (MBoe) +Wattenberg Field 61,892 57,521 37,984 8 % 51 % +Delaware Basin 9,441 10,847 11,430 (13) % (5) % +Total 71,333 68,368 49,414 4 % 38 % +Average crude oil equivalent per day (Boe) +Wattenberg Field 169,567 157,161 104,066 8 % 51 % +Delaware Basin 25,866 29,637 31,315 (13) % (5) % +Total 195,433 186,798 135,381 5 % 38 % +Net production volumes for oil, natural gas and NGLs increased 4 percent during the year ended December 31, 2021 compared to 2020. The increase in production volume between periods was primarily due to a greater number of wells turned-in-line since the fourth quarter of 2020. This increase was partially offset by normal decline in production from our existing wells and lower performance of wells turned-in-line in the Delaware Basin during 2021. +47 +The following table presents our crude oil, natural gas and NGLs production ratio by operating region for the periods presented: +Year Ended December 31, +Production Ratio by Operating Region 2021 2020 2019 +Wattenberg Field +Crude oil 31 % 34 % 38 % +Natural gas 41 % 41 % 40 % +NGLs 28 % 25 % 22 % +Total 100 % 100 % 100 % +Delaware Basin +Crude oil 40 % 38 % 41 % +Natural gas 38 % 38 % 35 % +NGLs 22 % 24 % 24 % +Total 100 % 100 % 100 % +The change in production mix in the Wattenberg Field during the year ended December 31, 2021 compared to 2020 and 2019 was driven by our 2021 development plan being focused on areas that have a higher gas/oil ratio and due to less bypass processing of gas which increased our NGLs ratio and economics. +Midstream Capacity +Our ability to market our production depends substantially on the availability, proximity and capacity of in-field gathering systems, compression and processing facilities, as well as transportation pipelines out of the basin, all of which are owned and operated by third parties. If adequate midstream facilities and services are not available on a timely basis and at acceptable costs, our production and results of operations could be adversely affected. +The ultimate timing and availability of adequate infrastructure remains out of our control. Weather, regulatory developments and other factors also affect the adequacy of midstream infrastructure. Like other producers, from time to time we enter into volume commitments with midstream providers in order to incentivize them to provide increased capacity to sufficiently meet our projected volume growth from our areas of operation. If our production falls below the level required under these agreements, we could be subject to transportation charges or aid in construction payments for commitment shortfalls. +Our production from the Wattenberg Field and Delaware Basin was not materially affected by midstream or downstream capacity constraints during the year ended December 31, 2021. We continuously monitor infrastructure capacities versus producer activity and production volume forecasts. +Crude Oil, Natural Gas and NGLs Pricing +Our results of operations depend upon many factors. Key factors include market prices of crude oil, natural gas and NGLs and our ability to market our production effectively. Crude oil, natural gas and NGLs prices have a high degree of volatility and our realizations can change substantially. Our weighted average realized commodity prices increased 112 percent during 2021 as compared to 2020. The NYMEX average daily crude oil and NYMEX first-of-the-month natural gas prices increased 72 percent and 81 percent, respectively, as compared to 2020. +48 +The following table presents weighted average sales prices of crude oil, natural gas and NGLs for the periods presented: +Year Ended December 31, +Weighted Average Realized Sales Price by Operating Region Percent Change +(excluding net settlements on derivatives) 2021 2020 2019 +2021-2020 +2020-2019 +Crude oil (per Bbl) +Wattenberg Field $ 67.49 $ 34.21 $ 52.99 97 % (35) % +Delaware Basin 67.47 35.48 54.08 90 % (34) % +Weighted average price 67.49 34.44 53.26 96 % (35) % +Natural gas (per Mcf) +Wattenberg Field 2.98 1.22 1.49 144 % (18) % +Delaware Basin 2.81 0.28 0.57 * (51) % +Weighted average price 2.96 1.08 1.30 174 % (17) % +NGLs (per Bbl) +Wattenberg Field 24.77 8.84 11.51 180 % (23) % +Delaware Basin 35.72 11.32 15.12 216 % (25) % +Weighted average price 25.94 9.21 12.41 182 % (26) % +Crude oil equivalent (per Boe) +Wattenberg Field 34.95 16.84 26.31 108 % (36) % +Delaware Basin 41.25 16.94 26.95 144 % (37) % +Weighted average price 35.78 16.86 26.46 112 % (36) % +____________ +* Percent change is not meaningful. +Crude oil, natural gas and NGLs revenues are recognized when we transfer control of crude oil, natural gas or NGLs production to the purchaser. We consider the transfer of control to occur when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from the crude oil, natural gas or NGLs production. +Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or “gross” method of accounting, depending upon the related purchase agreement. We use the net-back method when control of the crude oil, natural gas or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering or processing services. In these situations, the purchaser pays us based on a percent of proceeds or a sales price fixed at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index on which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when control of the crude oil, natural gas or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transportation and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing (“TGP”) expense. +49 +Information related to the components and classifications of TGP expense on the consolidated statements of operations is shown below. For crude oil, the average NYMEX prices shown below are based on average daily prices throughout each month and, for natural gas, the average NYMEX pricing is based on first-of-the-month index prices, as in each case this is the method used to sell the majority of these commodities pursuant to terms of the relevant sales agreements. For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. The average realized price both before and after TGP expense shown in the table below represents our approximate composite per barrel price for NGLs for the periods presented. +2021 Average NYMEX Price Average Realized Price Before TGP Expense Average Realization Percentage Before TGP Expense +Average TGP Expense (1) +Average Realized Price After TGP Expense Average Realization Percentage After TGP Expense +Crude oil (per Bbl) $ 67.92 $ 67.49 99 % $ 3.10 $ 64.39 95 % +Natural gas (per MMBtu) 3.76 2.96 79 % 0.13 2.83 75 % +NGLs (per Bbl) 67.92 25.94 38 % — 25.94 38 % +Crude oil equivalent (per Boe) 49.29 35.78 73 % 1.30 34.48 70 % +2020 Average NYMEX Price Average Realized Price Before TGP Expense Average Realization Percentage Before TGP Expense +Average TGP Expense (1) +Average Realized Price After TGP Expense Average Realization Percentage After TGP Expense +Crude oil (per Bbl) $ 39.40 $ 34.44 87 % $ 2.34 $ 32.10 81 % +Natural gas (per MMBtu) 2.08 1.08 52 % 0.12 0.96 46 % +NGLs (per Bbl) 39.40 9.21 23 % — 9.21 23 % +Crude oil equivalent (per Boe) 28.52 16.86 59 % 1.10 15.76 55 % +2019 Average NYMEX Price Average Realized Price Before TGP Expense Average Realization Percentage Before TGP Expense +Average TGP Expense (1) +Average Realized Price After TGP Expense Average Realization Percentage After TGP Expense +Crude oil (per Bbl) $ 57.03 $ 53.26 93 % $ 1.24 $ 52.02 91 % +Natural gas (per MMBtu) 2.63 1.30 49 % 0.17 1.13 43 % +NGLs (per Bbl) 57.03 12.41 22 % 0.10 12.31 22 % +Crude oil equivalent (per Boe) 40.95 26.46 65 % 0.90 25.56 62 % +____________ +(1) Average TGP expense excludes unutilized firm transportation fees of $0.11, $0.04, and $0.04 per Boe for the years ended December 31, 2021, 2020, and 2019, respectively. +Our average realization percentages for crude oil, natural gas and NGLs increased in 2021 as compared to 2020 primarily due to the overall increase in commodity prices between periods driven by the improvement in oil and gas product demand that occurred throughout 2021. Additionally, we realized improved differentials resulting from 2021 sales contracts. +Commodity Price Risk Management +We use commodity derivative instruments to manage fluctuations in crude oil and natural gas prices, including collars, fixed-price exchanges, and basis protection exchanges on a portion of our estimated crude oil and natural gas production. For our commodity exchanges, we ultimately realize the fixed price value related to the swaps. See Note 7 - Commodity Derivative Financial Instruments in Item 8. Financial Statements and Supplementary Data included elsewhere in this report for a summary of our derivative positions as of December 31, 2021. +Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments, and the change in fair value of unsettled commodity derivatives related to our crude oil and natural gas production. +50 +Net settlements of commodity derivative instruments are based on the difference between the crude oil and natural gas index prices at the settlement date of our commodity derivative instruments compared to the respective strike prices contracted for the settlement months that were established at the time we entered into the commodity derivative transaction. The net change in fair value of unsettled commodity derivatives is comprised of the net increase or decrease in the beginning-of-period fair value of commodity derivative instruments that settled during the period and the net change in fair value of unsettled commodity derivatives during the period or from inception of any new contracts entered into during the applicable period. The net change in fair value of unsettled commodity derivatives during the period is primarily related to shifts in the crude oil and natural gas forward price curves and changes in certain differentials. +The following table presents net settlements and net change in fair value of unsettled derivatives included in commodity price risk management, net: +Year Ended December 31, +2021 2020 2019 +(in millions) +Commodity price risk management gain (loss), net: +Net settlements of commodity derivative instruments: +Crude oil collars and fixed price exchanges $ (289.1) $ 294.4 $ (18.3) +Natural gas collars and fixed price exchanges (120.1) (1.4) 8.8 +Natural gas basis protection exchanges (1.0) (13.7) (8.1) +Total net settlements of commodity derivative instruments (410.2) 279.3 (17.6) +Change in fair value of unsettled commodity derivative instruments: +Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments 49.3 (19.9) (81.1) +Crude oil collars and fixed price exchanges (269.3) (49.8) (62.1) +Natural gas collars and fixed price exchanges (61.7) (7.8) 0.1 +Natural gas basis protection exchanges (9.6) (21.5) (2.1) +Net change in fair value of unsettled commodity derivative instruments (291.3) (99.0) (145.2) +Total commodity price risk management gain (loss), net $ (701.5) $ 180.3 $ (162.8) +The significant increase in commodity prices during 2021 had an overall unfavorable impact on the fair value and settlements of our commodity derivatives. +Lease Operating Expense +Lease operating (“LOE”) expense increased by 12 percent to $180.7 million in 2021 compared to $161.3 million in 2020. The period-over-period increase in LOE was primarily due to (i) increased activities and payroll costs at our well locations from the COVID-19 induced downturn in 2020, (ii) $5.6 million of additional environmental and regulatory costs in 2021, and (iii) fewer vendor concessions experienced in 2021 as compared to 2020 as the price of commodities has improved. LOE per Boe increased 7 percent to $2.53 in 2021 from $2.36 in 2020. +Production Taxes +Production taxes are comprised mainly of severance tax and ad valorem tax, and are directly related to crude oil, natural gas and NGLs sales and are generally assessed as a percentage of net revenues. From time to time, there are adjustments to the statutory rates for these taxes based upon certain credits that are determined based upon activity levels and relative commodity prices. +Production taxes increased 178 percent to $165.2 million in 2021 compared to $59.4 million in 2020. Production taxes per Boe increased 167 percent to $2.32 in 2021 compared to $0.87 in 2020. The increase in production taxes was primarily due to an increase in crude oil, natural gas and NGLs prices between periods. +51 +Transportation, Gathering and Processing Expense +TGP expense increased 29 percent to $100.4 million in 2021 compared to $77.8 million in 2020. TGP per Boe increased to $1.41 for 2021 compared to $1.14 for 2020. The overall increase in TGP expense for 2021 compared to 2020 was driven by a $14.4 million increase relating to transportation of our crude oil volumes delivered and a $5.1 million increase in unutilized transportation fees relating to our delivery commitment in the Delaware Basin. +Impairment of Properties and Equipment +The following table sets forth the major components of our impairment of properties and equipment for the periods presented: +Year Ended December 31, +2021 2020 2019 +(in millions) +Impairment of proved and unproved properties $ 0.4 $ 881.2 $ 10.6 +Impairment of infrastructure and other — 1.2 27.9 +Total impairment of properties and equipment $ 0.4 $ 882.4 $ 38.5 +There were no significant impairment charges recognized related to our proved and unproved oil and gas properties in 2021. If crude oil prices decline, or we change other estimates impacting future net cash flows (e.g. reserves, price differentials, future operating and/or development costs), our proved and unproved oil and gas properties could be subject to additional impairments in future periods. +During the first quarter of 2020, we recorded impairment charges of $881.1 million to our proved and unproved properties in the Delaware Basin. These impairment charges were due to a significant decline in crude oil prices, which was considered a triggering event that required us to assess our crude oil and natural gas properties for possible impairment. +General and Administrative Expense +General and administrative expense decreased to $127.7 million in 2021 compared to $161.1 million in 2020 primarily due to $30.0 million in transaction and transition costs incurred in 2020 related to the SRC Acquisition and consultant fees related to our ERP implementation of $5.3 million. +Depreciation, Depletion and Amortization Expense +Crude oil and natural gas properties. During 2021 and 2020, we invested $583.6 million and $522.3 million, respectively, exclusive of changes in accounts payable related to capital expenditures, in the development of our crude oil and natural gas properties. Depreciation, depletion and amortization expense (“DD&A”) related to crude oil and natural gas properties is directly related to proved reserves and production volumes. DD&A expense related to crude oil and natural gas properties was $627.5 million and $611.0 million in 2021 and 2020, respectively. The increase in total DD&A expense was primarily due to an increase in production volumes as our weighted average depletion rate between periods was comparable. The decrease in weighted average depletion rate during 2021 compared to 2020 was driven by an increase in proved reserves in our Wattenberg Field as a result of improved commodity prices during 2021. +52 +The year-over-year change in DD&A expense for related to crude oil and natural gas properties was primarily due to the following: +Year Ended December 31, +2021 +(in millions) +Increase in production $ 24.8 +Decrease in weighted average depreciation, depletion and amortization rates (8.3) +Total decrease in DD&A expense related to crude oil and natural gas properties $ 16.5 +The following table presents our per Boe DD&A expense rates for crude oil and natural gas properties for the periods presented: +Year Ended December 31, +2021 2020 2019 +(per Boe) +Operating Region/Area +Wattenberg Field $ 8.68 $ 8.80 $ 11.77 +Delaware Basin 9.59 9.68 16.76 +Total weighted average DD&A expense rate 8.80 8.94 12.92 +Non-crude oil and natural gas properties. Depreciation expense for non-crude oil and natural gas properties was $7.7 million for the year ended December 31, 2021, compared to $8.7 million for the year ended December 31, 2020. +Interest Expense, net +Interest expense, net decreased by $6.0 million to $82.7 million in 2021 compared to $88.7 million in 2020. The decrease was primarily related to reduced borrowings under our revolving credit facility, a full redemption of our 2025 Senior Notes and a partial redemption of our 2024 Senior Notes. These decreases were partially offset by a $6.1 million increase in interest expense related to the issuance of an additional $150 million aggregate principal amount of the 2026 Senior Notes in September 2020 and a $6.9 million loss on extinguishment from partial redemption of our 2024 Senior Notes and full redemption of our 2025 Senior Notes. +Provision for Income Taxes +We recorded income tax expense of $26.6 million for 2021 and an income tax benefit of $7.9 million for 2020, resulting in effective tax rates of 4.8 percent and 1.1 percent on the respective pre-tax income or loss. The effective tax rates differ from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21 percent to the pre-tax loss due to the effect of a valuation allowance against our deferred income tax assets at December 31, 2021 and 2020. +The ultimate realization of deferred tax assets (“DTAs”) is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. The oil and gas property impairments and cumulative pre-tax losses were key considerations that led us to continue to provide a valuation allowance against our DTAs as of December 31, 2021 and 2020 since we cannot conclude that it is more likely than not that our DTAs will be fully realized in future periods. +Future events or new evidence which may lead us to conclude that it is more likely than not that our DTAs will be realized include, but are not limited to, cumulative historical pre-tax earnings, sustained or continued improvements in oil prices, and taxable events that could result from one or more transactions. Given recent improvements in oil and gas prices and improvements in our current earnings, we believe there is a reasonable possibility that, if oil and natural gas prices remain similar to December 31, 2021 pricing levels, sufficient positive evidence may become available within the next 12 months to allow us to reach a conclusion that all or a significant portion of the valuation allowance will no longer be needed. Release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense in +53 +the period the release is recorded. However, the exact timing and amount of the valuation allowance release are subject to change based on the level of profitability that we actually achieve. +Given recent improvements in oil and gas prices and assumptions based on our current production forecasts, we estimate that we will begin to incur cash federal and state income taxes again in 2022 and 2023. +Net Income (Loss)/Adjusted Net Income (Loss) +The factors impacting net income of $522.3 million and net loss of $724.3 million in 2021 and 2020, respectively, are discussed above. +Adjusted net income, a non-U.S. GAAP financial measure, was $799.6 million and for the year ended December 31, 2021 and adjusted net loss, a non-U.S. GAAP financial measure, was $625.3 million for the year ended December 31, 2020. With the exception of the tax-affected (when applicable) net change in fair value of unsettled derivatives, the same factors impacted adjusted net income (loss). See Reconciliation of Non-U.S. GAAP Financial Measures below for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures. +Financial Condition, Liquidity and Capital Resources +Overview +Our primary sources of liquidity are cash and cash equivalents, cash flows from operating activities, unused borrowing capacity from our revolving credit facility, proceeds raised in debt and equity capital market transactions and other sources, such as asset sales. +Our primary source of cash flows from operating activities is the sale of crude oil, natural gas and NGLs. Fluctuations in our operating cash flows are principally driven by commodity prices and changes in our production volumes. Commodity prices have historically been volatile, and we manage a portion of this volatility through our use of commodity derivative instruments. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the instrument. Our revolving credit facility imposes limits on the amount of our production we can hedge, and we may choose not to hedge the maximum amounts permitted. Therefore, we may still have fluctuations in our cash flows from operating activities due to the remaining non-hedged portion of our future production. +We may use our available liquidity for operating activities, capital investments, working capital requirements, acquisitions, capital returns and for general corporate purposes. We maintain a significant capital investment program to execute our development plans, which requires capital expenditures to be made in periods prior to initial production from newly developed wells. From time to time, these activities may result in a working capital deficit; however, we do not believe that our working capital deficit as of December 31, 2021 is an indication of a lack of liquidity. We had working capital deficits of $461.5 million and $471.6 million at December 31, 2021 and 2020, respectively. We intend to continue to manage our liquidity position by a variety of means, including through the generation of cash flows from operations, investment in projects with favorable rates of return, protection of cash flows on a portion of our anticipated sales through the use of an active commodity derivative hedging program, utilization of the borrowing capacity under our revolving credit facility and, if warranted, capital markets transactions from time to time. +From time to time, we may seek to pay down, retire or repurchase our outstanding debt using cash or through exchanges of other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise. +Liquidity +Our cash and cash equivalents were $33.8 million at December 31, 2021 and availability under our revolving credit facility was $1.48 billion, providing for total liquidity of $1.51 billion as of December 31, 2021. The borrowing base is primarily based on the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. +Our material short-term and long-term cash requirements consist primarily of capital expenditures, payments of contractual obligations, dividends, share repurchases and working capital obligations. As commodity prices improve, our +54 +working capital requirements may increase due to higher operating costs and negative settlements on our outstanding commodity derivative contracts. Funding for these requirements may be provided by any combination of our capital resources previously outlined. +On February 26, 2022, we entered into the Acquisition Agreement to acquire Great Western for approximately $1.3 billion, inclusive of Great Western’s net debt. Under the terms of the Acquisition Agreement, the purchase price of the Great Western Acquisition will consist of approximately 4.0 million shares of our common stock and approximately $543 million in cash. The cash portion of the purchase price is expected to be funded through a combination of cash on hand and availability under our revolving credit facility. We expect the Great Western Acquisition to be completed in the second quarter of 2022, subject to certain customary closing conditions. +Upon closing the Great Western Acquisition, we will be required to pay off and terminate Great Western’s revolving credit facility, which had an outstanding balance of $242.0 million as of December 31, 2021. At closing, we are also expecting to pay off Great Western’s $311.9 million 12.0% Senior Notes due September 1, 2025, plus a redemption premium. The payments of the debt balances will be funded through the availability under our revolving credit facility. +Based on our current production forecast for 2022, we expect 2022 cash flows from operations, which are net of expected cash federal and state income taxes, to exceed our capital investments in crude oil and natural gas properties by approximately $1.1 billion. In addition, based on our expected cash flows from operations, our cash and cash equivalents and availability under our revolving credit facility, we believe that we will have sufficient capital available to fund our planned activities through the 12-month period following the filing of this report. We also believe that we will have sufficient expected cash flows from operations to allow us to execute our capital return plan. Future repurchases of common stock or dividend payments will be subject to approval by our board of directors and will depend on our level of earnings, financial requirements, and other factors considered relevant by our board. +Our material cash requirements greater than twelve months from various contractual and other obligations include debt obligations and interest payments; commodity derivative contract liabilities; production taxes; operating and finance leases; asset retirement obligations; and firm transportation and processing agreements included in Item 8. Financial Statements and Supplementary Data to our consolidated financial statements included elsewhere in this report. +The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements to: (a) maintain a minimum current ratio of 1.0:1.0 and (b) not exceed a maximum leverage ratio of 3.5:1.0. For purposes of the current ratio covenant, the revolving credit facility’s definition of total current assets, in addition to current assets as presented under U.S. GAAP, includes, among other things, unused commitments under the revolving credit facility. Additionally, the current ratio covenant calculation allows us to exclude the current portion of our long-term debt and other short-term loans from the U.S. GAAP total current liabilities amount. Accordingly, the existence of a working capital deficit under U.S. GAAP is not necessarily indicative of a violation of the current ratio covenant. At December 31, 2021, we were in compliance with all covenants in the revolving credit facility with a current ratio of 3.1:1.0 and a leverage ratio of 0.6:1.0. +We expect to remain in compliance with the covenants under our credit facility and our Senior Notes throughout the 12-month period following the filing of this report. +55 +Cash Flows +Our cash flows from operating, investing and financing activities are as follows: +Year ended December 31, +2021 2020 2019 +(in thousands) +Cash flows from operating activities $ 1,547,796 $ 870,079 $ 858,226 +Cash flows from investing activities (578,804) (687,159) (677,772) +Cash flows from financing activities (937,786) (181,260) (188,890) +Net increase (decrease) in cash and cash equivalents $ 31,206 $ 1,660 $ (8,436) +Operating Activities. Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes, net settlements from our commodity derivative positions, operating costs and general and administrative expenses. Cash flows from operating activities increased by $677.7 million to $1,547.8 million in 2021 as compared to $870.1 million in 2020. The increase between periods was primarily due to a $1.4 billion increase in crude oil, natural gas and NGLs sales, a $33.4 million decrease in general and administrative expense, and changes in the timing of vendor payments. These increases were partially offset by $410.2 million in cash settlement losses on commodity derivatives in 2021 compared to $279.3 million in cash receipts from derivative settlements in 2020, a $105.8 million increase in production taxes and changes in the timing of receivable collections between periods. +Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased by $611.0 million in 2021 to $1,532.6 million from $921.6 million in 2020. The increase was primarily due to the factors mentioned above for changes in cash flows provided by operating activities, without regard to timing of cash payments and receipts of assets and liabilities. Adjusted free cash flow, a non-U.S GAAP financial measure, increased by $549.7 million in 2021 to $949.0 million from $399.3 million in 2020. The increase was primarily due to the increase in cash flows from operating activities, as discussed above. +See Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures. +Investing Activities. As crude oil and natural gas production from a well declines rapidly in the first few years of production, we need to continue to commit significant amounts of capital in order to maintain and grow our production and replace our crude oil and natural reserves. If capital is not available or is constrained in the future, we will be limited to our cash flows from operations and liquidity under our revolving credit facility as the sources for funding our capital investments. +Cash flows from investing activities primarily consist of the acquisition, exploration and development of crude oil and natural gas properties, net of dispositions of crude oil and natural gas properties. Net cash used in investing activities of $578.8 million during 2021 was primarily related to our drilling and completion activities of $583.1 million, partially offset by $5.1 million in proceeds from the sale of certain properties and equipment. +Net cash used in investing activities of $687.2 million during 2020 was primarily related to our drilling and completion activities of $551.0 million and $139.8 million related to the closing of the SRC Acquisition. +Financing Activities. Net cash used in financing activities in 2021 of $937.8 million was primarily due to (i) net repayments on our credit facility of $168.0 million, (ii) redemption and retirement of our 2021 Convertible Notes and 2025 Senior Notes for $200 million and $105.5 million, respectively, (iii) partial redemption and retirement of our 2024 Senior Notes for $203.1 million, (iv) the repurchase of 3.8 million shares of our common stock for $156.8 million pursuant to our Stock Repurchase Program and (v) dividend payments totaling $83.6 million. Repurchases of our common stock may extend into 2023 based on current market conditions, although our board of directors could elect to suspend or terminate the program at any time, including if certain share price parameters are not achieved. As of December 31, 2021, $187.3 million out of the approved $525 million remained available for repurchases under the program. In February 2022, our board of directors increased the size of the program to $1.25 billion, which we anticipate fully utilizing by December 31, 2023. Future repurchases of common stock +56 +or dividend payments will be subject to approval by our board of directors and will depend on our level of earnings, financial requirements, and other factors considered relevant by our board. +Net cash used in financing activities in 2020 of $181.3 million was primarily due to the redemption of a portion of the 2025 Senior Notes totaling $452.2 million, the repurchase and retirement of shares of our common stock totaling $23.8 million pursuant to the Stock Repurchase Program and $9.3 million related to purchases of our stock for employee stock-based compensation tax withholding obligations. These financing cash outflows were financed by our net borrowings from our credit facility of $164 million, proceeds from the issuance of 2026 Senior Notes of $148.5 million and cash flows from operating activities. +Subsidiary Guarantor +PDC Permian, Inc., a Delaware corporation (the “Guarantor”), our wholly-owned subsidiary, guarantees our obligations under our 2024 Senior Notes and 2026 Senior Notes (collectively, the “Senior Notes”). The Guarantor holds our assets located in the Delaware Basin. The Senior Notes are fully and unconditionally guaranteed on a joint and several basis by the Guarantor. The guarantees are subject to release in limited circumstances only upon the occurrence of certain customary conditions. +The indentures governing the Senior Notes contain customary restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (i) incur additional debt including under our revolving credit facility, (ii) make certain investments or pay dividends or distributions on our capital stock or purchase, redeem or retire capital stock, (iii) sell assets, including capital stock of our restricted subsidiaries, (iv) restrict the payment of dividends or other payments by restricted subsidiaries to us, (v) create liens that secure debt, (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company. +57 +The following summarized subsidiary guarantor financial information has been prepared on the same basis of accounting as our consolidated financial statements. Investments in subsidiaries are accounted for under the equity method. +As of/Year Ended December 31, +2021 2020 +Issuer Guarantor Issuer Guarantor +(in millions) +Assets +Current assets $ 402.6 $ 56.0 $ 271.4 $ (57.8) +Intercompany accounts receivable, guarantor subsidiary — 40.8 107.3 — +Investment in guarantor subsidiary 1,767.2 — 1,767.2 — +Properties and equipment, net 3,875.0 939.9 3,982.1 877.1 +Other non-current assets 58.5 4.8 56.6 4.3 +Liabilities +Current liabilities $ 862.5 $ 57.6 $ 751.3 $ 28.5 +Intercompany accounts payable 27.9 — — 94.2 +Long-term debt 942.1 — 1,409.5 — +Other non-current liabilities 392.3 172.0 254.9 178.1 +Statement of Operations +Crude oil, natural gas and NGLs sales $ 2,163.1 $ 389.5 $ 968.8 $ 183.7 +Commodity price risk management gain (loss), net (701.5) — 180.3 — +Total revenues 1,464.5 391.4 1,151.5 182.5 +Production costs 892.4 189.0 740.7 177.5 +Gross profit (1) +1,270.7 200.4 228.1 6.2 +Impairment of properties and equipment 0.4 — 2.0 880.4 +Net income (loss) 327.7 194.9 (49.2) (670.0) +____________ +(1) Gross profit is calculated as crude oil, natural gas and NGLs sales less production costs. +Critical Accounting Policies and Estimates +The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with U.S. GAAP. The preparation of these statements requires us to make certain assumptions, judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities and commitments as of the date of our financial statements. +Our significant accounting policies are described in Note 2 - Summary of Significant Accounting Policies in Item 8. Financial Statements and Supplementary Data included elsewhere in this report. The following discussion outlines the accounting policies and practices involving the use of estimates and application of significant judgment that are critical in determining our financial results. Changes in the estimates and assumptions discussed below could materially affect the amount or timing of our financial results. +Crude Oil and Natural Gas Reserve Quantities +We account for our crude oil and natural gas properties under the successful efforts method of accounting. Under this method, costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depleted by the unit-of-production method based on estimated proved developed producing reserves. The successful efforts method inherently relies on the estimation of proved crude oil, natural gas and NGL reserves. In determining the estimates of reserve and economic evaluations, management utilizes independent petroleum engineers. Reserve quantities and the related estimates of future net cash flows are used as inputs in our calculation of depletion, evaluation of proved +58 +properties for impairment, assessment of expected realizability of our deferred income tax assets and calculation of the standardized measure of discounted future net cash flows. +The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. Significant inputs and engineering assumptions used in developing the estimates of proved crude oil and natural gas reserves include future production volumes, future operating and development costs and historical commodity prices. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, we continually make revisions to reserve estimates as additional information becomes available. We cannot predict the amounts or timing of such future revisions. +If the estimates of proved reserve quantities decline, the rate at which we record depletion expense will increase, which would reduce future net income. Changes in depletion rate calculations caused by changes in reserve quantities are made prospectively. In addition, a decline in reserve estimates may impact the outcome of our assessment of proved and unproved properties for impairment. Impairments are recorded in the period in which they are identified. +We cannot reasonably predict future commodity prices. However, assuming all other factors are held constant, we performed a sensitivity analysis on our proved reserve estimates as of December 31, 2021, to present a decrease of approximately 10 percent in crude oil price as the value of crude oil influences the value of our proved reserves and PV-10 most significantly. Our proved reserve quantities would decrease by 4.3 MMBoe (1%) and our PV-10 of our proved reserves would decrease by $1.1 billion (11%). During 2021, we had positive revisions to our proved reserve quantities of 52.9 MMBoe as a result of higher average prices for crude oil, natural gas and NGLs. During 2020 and 2019, we had negative revisions of 39.5 and 16.5 MMBoe, respectively, as a result of lower average prices for crude oil, natural gas and NGLs. For more information regarding reserve estimations, including additional crude oil sensitives and descriptions over historical reserve revisions, see Items 1 and 2. Business and Properties - Oil and Gas Production and Operations and Supplemental Oil and Gas Information within our consolidated financial statements included in Item 8. Financial Statements and Supplementary Data included elsewhere in this report. +Impairment of Crude Oil and Natural Gas Properties +Upon a triggering event, we assess the valuation of our proved crude oil and natural gas properties for possible impairment by comparing the carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production and prices at which we estimate the commodity will be sold. If carrying values exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a discounted future cash flows analysis. We estimate the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount. +Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices, and a discount factor. Future commodity prices are estimated by using a combination of assumptions management uses in its budgeting and forecasting process, historical and future prices adjusted for geographical location and quality differentials, as well as other factors that management believes will impact realizable prices. The discount factor used is the market based weighted average cost of capital which is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying crude oil and natural gas. +Unproved properties with individually significant acquisition costs are periodically assessed for impairment and reduced to fair value based on a review over our future development plans, estimated future cash flows for probable well locations and remaining average lease terms. Items that can impact our future development plans can be driven by drilling results, reservoir performance, capital resources and seismic interpretations. Changes in our assumptions of the estimated nonproductive portion of our undeveloped leases could result in additional impairment expense. +Although our cash flow estimates are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by their nature, highly uncertain and may vary significantly from actual results. We cannot predict when or if future impairment charges will be recorded because of the uncertainty in the factors discussed above. +59 +There were no significant impairment charges recognized related to our proved and unproved properties during the year ended December 31, 2021. We recorded impairment charges of $881.1 million to our proved and unproved properties to our Delaware Basin properties in 2020 as a result of the significant decline in crude oil prices. +Valuation of Business Combinations +We follow the acquisition method of accounting for business combinations. Assets acquired and liabilities assumed are recognized at the date of acquisition at their respective estimated fair values. Any excess of the purchase price over the fair value amounts assigned to assets and liabilities is recorded as goodwill. Any deficiency of the purchase price over the estimated fair values of the net assets acquired is recorded as a gain in statements of operations. +In estimating the fair values of assets acquired and liabilities assumed the most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. To estimate the fair values of these properties as part of acquisition accounting, we estimate the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices, and a market based weighted average cost of capital rate. Additionally, for acquisitions with significant unproved properties, we may also review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value as such sales represent the amount at which a willing buyer and seller would enter into an exchange for such properties to determine an estimation of fair value. +Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. A higher fair value assigned to a property results in a higher depletion expense, which results in lower net earnings. This increases the likelihood of impairment if future commodity prices or reserves quantities are lower than those originally used to determine fair value or if future operating expenses or development costs are higher than those originally used to determine fair value. There were no business combinations during the year ended December 31, 2021. +Recent Accounting Pronouncements +There were no significant new accounting standards adopted or new accounting pronouncements that would have potential effect on us as of December 31, 2021. +Reconciliation of Non-U.S. GAAP Financial Measures +We use “adjusted cash flows from operations”, “adjusted free cash flow (deficit)”, “adjusted net income (loss)” and “adjusted EBITDAX”, non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and, in some cases, in providing public guidance on possible future results. In addition, we believe these are measures of our fundamental business and can be useful to us, investors, lenders and other parties in the evaluation of our performance relative to our peers and in assessing acquisition opportunities and capital expenditure projects. These supplemental measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss) or cash flows from operations, investing or financing activities and should not be viewed as liquidity measures or indicators of cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. In the future, we may disclose different non-U.S. GAAP financial measures in order to help us and our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure. +Adjusted cash flows from operations and adjusted free cash flow (deficit). We believe adjusted cash flows from operations can provide additional transparency into the drivers of trends in our operating cash flows, such as production, realized sales prices and operating costs, as it disregards the timing of settlement of operating assets and liabilities. We believe adjusted free cash flow (deficit) provides additional information that may be useful in an investor analysis of our ability to generate cash from operating activities from our existing oil and gas asset base to fund exploration and development activities and to return capital to stockholders in the period in which the related transactions occurred. We exclude from this measure cash receipts and expenditures related to acquisitions and divestitures of oil and gas properties and capital expenditures for other properties and equipment, which are not reflective of the cash generated or used by ongoing activities on our existing producing properties and, in the case of acquisitions and divestitures, may be evaluated separately in terms of their impact on our +60 +performance and liquidity. Adjusted free cash flow is a supplemental measure of liquidity and should not be viewed as a substitute for cash flows from operations because it excludes certain required cash expenditures. For example, we may have mandatory debt service requirements or other non-discretionary expenditures which are not deducted from the adjusted free cash flow measure. +We are unable to present a reconciliation of forward-looking adjusted cash flow because components of the calculation, including fluctuations in working capital accounts, are inherently unpredictable. Moreover, estimating the most directly comparable GAAP measure with the required precision necessary to provide a meaningful reconciliation is extremely difficult and could not be accomplished without unreasonable effort. We believe that forward-looking estimates of adjusted cash flow are important to investors because they assist in the analysis of our ability to generate cash from our operations. +Adjusted net income (loss). We believe that adjusted net income (loss) provides additional transparency into operating trends, such as production, realized sales prices, operating costs and net settlements on commodity derivative contracts, because it disregards changes in our net income (loss) from mark-to-market adjustments resulting from net changes in the fair value of our unsettled commodity derivative contracts, and these changes are not directly reflective of our operating performance. +Adjusted EBITDAX. We believe that adjusted EBITDAX provides additional transparency into operating trends because it reflects the financial performance of our assets without regard to financing methods, capital structure, accounting methods or historical cost basis. In addition, because adjusted EBITDAX excludes certain non-cash expenses, we believe it is not a measure of income, but rather a measure of our liquidity and ability to generate sufficient cash for exploration, development, and acquisitions and to service our debt obligations. +PV-10. We define PV-10 as the estimated present value of the future net cash flows from our proved reserves before income taxes, discounted using a 10 percent discount rate. We believe that PV-10 provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. We believe that PV-10 is relevant and useful for evaluating the relative monetary significance of our reserves. Professional analysts, investors and other users of our financial statements may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies’ reserves. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable in evaluating us and our reserves. PV-10 is not intended to represent the current market value of our estimated reserves. +61 +The following table presents a reconciliation of each of our non-U.S. GAAP financial measures to its most comparable U.S. GAAP measure for the periods presented: +Year Ended December 31, +2021 2020 2019 +(thousands) +Cash flows from operations to adjusted cash flows from operations and adjusted free cash flow: +Net cash from operating activities $ 1,547.8 $ 870.1 $ 858.2 +Changes in assets and liabilities (15.2) 51.5 (32.8) +Adjusted cash flows from operations 1,532.6 921.6 825.4 +Capital expenditures for development of crude oil and natural gas properties (583.1) (551.0) (855.9) +Change in accounts payable related to capital expenditures for oil and gas development activities (0.5) 28.7 68.2 +Adjusted free cash flow $ 949.0 $ 399.3 $ 37.7 +Net income (loss) to adjusted net income (loss): +Net income (loss) $ 522.3 $ (724.3) $ (56.7) +Loss (gain) on commodity derivative instruments 701.5 (180.3) 162.8 +Net settlements on commodity derivative instruments (410.2) 279.3 (17.6) +Tax effect of above adjustments (1) +(14.0) — (35.2) +Adjusted net income (loss) $ 799.6 $ (625.3) $ 53.3 +Net income (loss) to adjusted EBITDAX: +Net income (loss) $ 522.3 $ (724.3) $ (56.7) +Loss (gain) on commodity derivative instruments 701.5 (180.3) 162.8 +Net settlements on commodity derivative instruments (410.2) 279.3 (17.6) +Non-cash stock-based compensation 23.0 22.2 23.8 +Interest expense, net 82.7 88.7 71.1 +Income tax expense (benefit) 26.6 (7.9) (3.3) +Impairment of properties and equipment 0.4 882.4 38.5 +Exploration, geologic and geophysical expense 1.1 1.4 4.1 +Depreciation, depletion and amortization 635.2 619.7 644.2 +Accretion of asset retirement obligations 12.1 10.1 6.1 +Loss (gain) on sale of properties and equipment (0.9) (0.7) 9.7 +Adjusted EBITDAX $ 1,593.8 $ 990.6 $ 882.7 +Cash from operating activities to adjusted EBITDAX: +Net cash from operating activities $ 1,547.8 $ 870.1 $ 858.2 +Interest expense, net (2) +75.8 88.7 71.1 +Amortization and write-off of debt discount, premium and issuance costs (13.5) (16.8) (13.6) +Exploration, geologic and geophysical expense 1.1 1.4 4.1 +Other (2.2) (4.3) (4.3) +Changes in assets and liabilities (15.2) 51.5 (32.8) +Adjusted EBITDAX $ 1,593.8 $ 990.6 $ 882.7 +PV-10: +Standardized measure of discounted future net cash flows $ 7,908.2 $ 3,282.2 $ 3,310.3 +Present value of estimated future income tax discounted at 10% 1,800.6 172.4 526.7 +PV-10 $ 9,708.8 $ 3,454.6 $ 3,837.0 +_____________ +(1) Due to the full valuation allowance recorded against our net deferred tax assets, there is no tax effect for the year ended December 31, 2020. +(2) Excludes loss on extinguishment from early retirement of our senior notes amounting to $6.9 million for the year ended December 31, 2021. +62 +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Market-Sensitive Instruments and Risk Management +We are exposed to market risks associated with interest rate risks, commodity price risk and credit risk. We have established risk management processes to monitor and manage these market risks. +Interest Rate Risk +Changes in interest rates affect the amount of interest we earn on our interest bearing cash, cash equivalents and restricted cash accounts and the interest we pay on borrowings under our revolving credit facility. Our 2024 Senior Notes and 2026 Senior Notes have fixed rates, and therefore, near-term changes in interest rates do not expose us to risk of earnings or cash flow loss; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt. +As of December 31, 2021, we had no outstanding borrowings under our revolving credit facility. +Commodity Price Risk +We are exposed to the potential risk of loss from adverse changes in the market price of crude oil, natural gas, natural gas basis and NGLs. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control. Pursuant to established policies and procedures, we manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. These instruments help us predict with greater certainty the effective crude oil and natural gas prices we will receive for our hedged production. We believe that our commodity derivative policies and procedures are effective in achieving our risk management objectives. +As of December 31, 2021, we had a net liability derivative position of $367.3 million related to our commodity price risk derivatives. Based on a sensitivity analysis as of December 31, 2021, we estimate that a 10 percent increase in +natural gas, crude oil prices and the propane portion of NGLs prices, inclusive of basis, over the entire period for which we have commodity derivatives in place would have resulted in an increase in the fair value of our net derivative liabilities of $85.1 million, whereas a 10 percent decrease in prices would have resulted in a decrease in fair value of our net derivatives liabilities of $82.5 million. The potential increase in the fair value of our net derivative liabilities would be recorded our consolidated statements of operations as a loss. We are currently unable to estimate the effects on the earnings of future periods resulting from changes in the market value of our commodity derivative contracts. +Credit Risk +Credit risk represents the loss that we would incur if a counterparty fails to perform its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure. When exposed to significant credit risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We monitor the creditworthiness of significant counterparties through our credit committee, which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. While we believe that our credit risk analysis and monitoring procedures are reasonable, no amount of analysis can assure performance by our counterparties. +We primarily use financial institutions which are lenders in our revolving credit facility as counterparties for our derivative financial instruments. Disruption in the credit markets, changes in commodity prices and other factors may have a significant adverse impact on a number of financial institutions. To date, we have had no material counterparty default losses from our commodity derivative financial instruments. +Our crude oil, natural gas and NGLs sales are concentrated with a few predominately large customers. This concentrates our credit risk exposure with a small number of large customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. For the year ended December 31, 2021, three customers each accounted for more than 10% of our sales. For each of the years ended December 31, 2020 and 2019, four customers each accounted for more than 10% +63 +of our sales. No other customer accounted for more than 10% of our sales during these periods. Our allowances for credit losses were insignificant as of December 31, 2021. +Disclosure of Limitations +Because the information above included only those exposures that existed at December 31, 2021, it does not consider those exposures or positions which could arise after that date. As a result, our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, our commodity price risk management strategies at the time and interest rates and commodity prices at the time. +64 +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Index to Consolidated Financial Statements, Financial Statement Schedule and Supplemental Information +Financial Statements: +Report of Independent Registered Public Accounting Firm (PCAOB ID 238 ) +66 +Consolidated Balance Sheets +68 +Consolidated Statements of Operations +69 +Consolidated Statements of Cash Flows +70 +Consolidated Statements of Stockholders ’ Equity +71 +Notes to Consolidated Financial Statements +72 +Supplemental Information - Unaudited: +Crude Oil and Natural Gas Information +100 +Financial Statement Schedule: +Schedule II - Valuation and Qualifying Accounts - Years Ended December 31, 2021, 2020 and 2019 +107 +65 +Report of Independent Registered Public Accounting Firm +To the Board of Directors and Stockholders of PDC Energy, Inc. +Opinions on the Financial Statements and Internal Control over Financial Reporting +We have audited the accompanying consolidated balance sheets of PDC Energy, Inc. and its subsidiaries (the “Company”) as of December 31, 2021 and 2020, and the related consolidated statements of operations, of stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 2021, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO. +Basis for Opinions +The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. +Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. +Definition and Limitations of Internal Control over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +66 +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Critical Audit Matters +The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. +The Impact of Proved Oil and Natural Gas Reserves on Proved Crude Oil and Natural Gas Properties, Net +As described in Notes 2 and 8 to the consolidated financial statements, the Company’s proved crude oil and natural gas properties balance was $8,310 million as of December 31, 2021, and depreciation, depletion, and amortization (DD&A) expense for the period ended December 31, 2021 was $635.2 million. As disclosed by management, the process of estimating and evaluating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. Significant inputs and engineering assumptions used in developing the estimates of proved crude oil and natural gas reserves include reserves volumes, future operating and development costs and historical commodity prices. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. The Company accounts for crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depleted by the unit-of-production method based on estimated proved developed producing reserves. Reserve estimates are prepared by internal and external engineers (collectively “specialists”). +The principal considerations for our determination that performing procedures relating to the impact of proved crude oil and natural gas reserves on proved crude oil and gas properties, net is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the estimates of proved crude oil and natural gas reserves, which in turn led to (ii) a high degree of auditor judgement, subjectivity, and effort in performing procedures and evaluating the audit evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved crude oil and natural gas reserves related to reserves volumes and the assumptions applied to the data related to future operating and development costs, and commodity prices. +Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved crude oil and natural gas reserves. The work of specialists was used in performing the procedures to evaluate the reasonableness of the reserve volumes. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists and an evaluation of the specialists’ results. These procedures also included, among others, testing the completeness and accuracy of data related to reserves volumes, future operating and development costs, and commodity prices. Additionally, these procedures included evaluating whether the assumptions applied to the aforementioned data were reasonable considering the past performance of the Company. +/s/ PricewaterhouseCoopers LLP +Denver, Colorado +February 28, 2022 +We have served as the Company’s auditor since 2007. +67 +PDC ENERGY, INC. +Consolidated Balance Sheets +(in thousands, except share and per share data) +December 31, +2021 2020 +Assets +Current assets: +Cash and cash equivalents $ 33,829 $ 2,623 +Accounts receivable, net 398,605 244,251 +Fair value of derivatives 17,909 48,869 +Prepaid expenses and other current assets 8,230 12,505 +Total current assets 458,573 308,248 +Properties and equipment, net 4,814,865 4,859,199 +Fair value of derivatives 15,177 9,565 +Other assets 48,051 60,961 +Total Assets $ 5,336,666 $ 5,237,973 +Liabilities and Stockholders’ Equity +Liabilities +Current liabilities: +Accounts payable $ 127,891 $ 90,635 +Production tax liability 99,583 124,475 +Fair value of derivatives 304,870 98,152 +Funds held for distribution 285,861 177,132 +Accrued interest payable 10,482 14,734 +Other accrued expenses 91,409 81,715 +Current portion of long-term debt — 193,014 +Total current liabilities 920,096 779,857 +Long-term debt 942,084 1,409,548 +Asset retirement obligations 127,526 132,637 +Fair value of derivatives 95,561 36,359 +Deferred income taxes 26,383 — +Other liabilities 314,769 264,034 +Total liabilities 2,426,419 2,622,435 +Commitments and contingent liabilities +Stockholders’ equity +Common shares - par value $ 0.01 per share, 150,000,000 authorized, 96,468,071 and 99,758,720 issued as of December 31, 2021 and 2020, respectively +965 998 +Additional paid-in capital 3,161,941 3,387,754 +Accumulated deficit ( 249,954 ) ( 772,265 ) +Treasury shares - at cost, 54,960 and 37,510 as of December 31, 2021 and 2020, respectively +( 2,705 ) ( 949 ) +Total stockholders’ equity 2,910,247 2,615,538 +Total Liabilities and Stockholders’ Equity $ 5,336,666 $ 5,237,973 +See accompanying Notes to Consolidated Financial Statements +68 +PDC ENERGY, INC. +Consolidated Statements of Operations +(in thousands, except per share data) +Year Ended December 31, +2021 2020 2019 +Revenues +Crude oil, natural gas and NGLs sales $ 2,552,558 $ 1,152,555 $ 1,307,275 +Commodity price risk management gain (loss), net ( 701,456 ) 180,270 ( 162,844 ) +Other income 4,808 6,401 11,692 +Total revenues 1,855,910 1,339,226 1,156,123 +Costs, expenses and other +Lease operating expense 180,659 161,346 142,248 +Production taxes 165,209 59,368 80,754 +Transportation, gathering and processing expense 100,403 77,835 46,353 +Exploration, geologic and geophysical expense 1,064 1,376 4,054 +General and administrative expense 127,733 161,087 161,753 +Depreciation, depletion and amortization 635,184 619,739 644,152 +Accretion of asset retirement obligations 12,086 10,072 6,117 +Impairment of properties and equipment 402 882,393 38,536 +Loss (gain) on sale of properties and equipment ( 912 ) ( 724 ) 9,734 +Other expense 2,490 10,272 11,317 +Total costs, expenses and other 1,224,318 1,982,764 1,145,018 +Income (loss) from operations 631,592 ( 643,538 ) 11,105 +Interest expense, net ( 82,698 ) ( 88,684 ) ( 71,099 ) +Income (loss) before income taxes 548,894 ( 732,222 ) ( 59,994 ) +Income tax benefit (expense) ( 26,583 ) 7,902 3,322 +Net income (loss) $ 522,311 $ ( 724,320 ) $ ( 56,672 ) +Earnings (loss) per share +Basic $ 5.30 $ ( 7.37 ) $ ( 0.89 ) +Diluted 5.22 ( 7.37 ) ( 0.89 ) +Weighted-average common shares outstanding +Basic 98,546 98,251 64,032 +Diluted 100,154 98,251 64,032 +See accompanying Notes to Consolidated Financial Statements +69 +PDC ENERGY, INC. +Consolidated Statements of Cash Flows +(in thousands) +Year Ended December 31, +2021 2020 2019 +Cash flows from operating activities: +Net income (loss) $ 522,311 $ ( 724,320 ) $ ( 56,672 ) +Adjustments to net income (loss) to reconcile to net cash from operating activities: +Net change in fair value of unsettled commodity derivatives 291,268 99,001 145,246 +Depreciation, depletion and amortization 635,184 619,739 644,152 +Impairment of properties and equipment 402 882,393 38,536 +Accretion of asset retirement obligations 12,086 10,072 6,117 +Non-cash stock-based compensation 23,023 22,200 23,837 +(Gain) loss on sale of properties and equipment ( 912 ) ( 724 ) 9,734 +Amortization and write-off of debt discount, premium and issuance costs 13,468 16,772 13,575 +Loss from extinguishment of debt 6,927 — — +Deferred income taxes 26,383 ( 6,530 ) ( 2,256 ) +Other 2,451 3,004 3,155 +Changes in assets and liabilities: +Accounts receivable ( 153,717 ) 139,664 ( 88,304 ) +Other assets 24,678 ( 5,341 ) ( 11,560 ) +Production tax liability 41,381 ( 50,803 ) 22,240 +Accounts payable and accrued expenses 40,183 ( 66,183 ) ( 29,578 ) +Funds held for distribution 108,729 ( 23,621 ) ( 7,298 ) +Asset retirement obligations ( 28,595 ) ( 27,491 ) ( 21,511 ) +Other liabilities ( 17,454 ) ( 17,753 ) 168,813 +Net cash from operating activities 1,547,796 870,079 858,226 +Cash flows from investing activities: +Capital expenditures for development of crude oil and natural gas properties ( 583,108 ) ( 550,964 ) ( 855,908 ) +Capital expenditures for other properties and equipment ( 894 ) ( 1,634 ) ( 20,839 ) +Acquisition of crude oil and natural gas properties — ( 139,812 ) ( 13,207 ) +Proceeds from sale of properties and equipment 5,073 1,641 2,105 +Proceeds from divestitures 125 3,610 202,076 +Restricted cash — — 8,001 +Net cash from investing activities ( 578,804 ) ( 687,159 ) ( 677,772 ) +Cash flows from financing activities: +Proceeds from revolving credit facility and other borrowings 802,800 1,799,350 1,577,000 +Repayment of revolving credit facility and other borrowings ( 970,800 ) ( 1,635,350 ) ( 1,605,500 ) +Proceeds from senior notes — 148,500 — +Redemption of senior notes ( 308,584 ) ( 452,153 ) — +Repayment of convertible notes ( 200,000 ) — — +Payment of debt issuance costs ( 13,066 ) ( 6,538 ) ( 72 ) +Purchase of treasury shares for employee stock-based compensation tax withholding obligations ( 6,038 ) ( 9,345 ) ( 4,003 ) +Purchase of treasury shares under stock repurchase program ( 156,795 ) ( 23,819 ) ( 154,363 ) +Dividends paid ( 83,615 ) — — +Principal payments under financing lease obligations ( 1,688 ) ( 1,905 ) ( 1,952 ) +Net cash from financing activities ( 937,786 ) ( 181,260 ) ( 188,890 ) +Net change in cash and cash equivalents 31,206 1,660 ( 8,436 ) +Cash and cash equivalents, beginning of year 2,623 963 9,399 +Cash and cash equivalents, end of year $ 33,829 $ 2,623 $ 963 +See accompanying Notes to Consolidated Financial Statements +70 +PDC ENERGY, INC. +Consolidated Statements of Stockholders’ Equity +(in thousands) +Common Stock Additional Paid-in Capital Treasury Stock Retained Earnings (Accumulated Deficit) Total Stockholders’ Equity +Shares Amount Shares Amount +Balance at January 1, 2019 66,149 $ 661 $ 2,519,423 ( 45 ) $ ( 2,103 ) $ 8,727 $ 2,526,708 +Net income (loss) — — — — — ( 56,672 ) ( 56,672 ) +Stock-based compensation 213 2 23,835 — — — 23,837 +Purchase of treasury shares for employee stock-based compensation tax withholding obligations — — — ( 106 ) ( 4,003 ) — ( 4,003 ) +Retirement of treasury shares for employee stock-based compensation tax withholding obligations ( 4 ) — ( 127 ) 4 127 — — +Retirement of treasury shares ( 4,706 ) ( 46 ) ( 154,317 ) 4,706 154,363 — — +Issuance of treasury shares — — ( 4,505 ) 112 4,505 — — +Purchase of treasury shares under stock repurchase program — — — ( 4,706 ) ( 154,363 ) — ( 154,363 ) +Balance at December 31, 2019 61,652 617 2,384,309 ( 35 ) ( 1,474 ) ( 47,945 ) 2,335,507 +Net income (loss) — — — — — ( 724,320 ) ( 724,320 ) +Issuance pursuant to acquisition 39,182 391 1,014,921 — — — 1,015,312 +Stock-based compensation 530 5 19,738 — 2,457 — 22,200 +Purchase of treasury shares for employee stock-based compensation tax withholding obligations — — — ( 457 ) ( 9,345 ) — ( 9,345 ) +Retirement of treasury shares for employee stock-based compensation tax withholding obligations ( 339 ) ( 3 ) ( 7,407 ) 339 7,413 — 3 +Retirement of treasury shares ( 1,266 ) ( 12 ) ( 23,807 ) 1,266 23,819 — — +Issuance of treasury shares — — — 115 — — — +Purchase of treasury shares under stock repurchase program — — — ( 1,266 ) ( 23,819 ) — ( 23,819 ) +Balance at December 31, 2020 99,759 998 3,387,754 ( 38 ) ( 949 ) ( 772,265 ) 2,615,538 +Net income (loss) — — — — — 522,311 522,311 +Stock-based compensation 531 5 20,831 — 2,187 — 23,023 +Purchase of treasury shares for employee stock-based compensation tax withholding obligations — — — ( 181 ) ( 6,038 ) — ( 6,038 ) +Retirement of treasury shares for employee stock-based compensation tax withholding obligations ( 117 ) ( 1 ) ( 4,156 ) 117 4,157 — — +Retirement of treasury shares ( 3,705 ) ( 37 ) ( 157,058 ) 3,711 157,401 — 306 +Issuance of treasury shares — — — 89 — — — +Purchase of treasury shares under stock repurchase program — — — ( 3,753 ) ( 159,463 ) — ( 159,463 ) +Dividends declared ($ 0.86 per share) +— — ( 85,430 ) — — — ( 85,430 ) +Balance at December 31, 2021 96,468 $ 965 $ 3,161,941 ( 55 ) $ ( 2,705 ) $ ( 249,954 ) $ 2,910,247 +See accompanying Notes to Consolidated Financial Statements +71 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION +PDC Energy, Inc. is a domestic independent exploration and production company that acquires, explores and develops properties for the production of crude oil, natural gas and NGLs, with operations in the Wattenberg Field in Colorado and the Delaware Basin in west Texas. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are primarily focused in the horizontal Wolfcamp zones. As of December 31, 2021, we owned an interest in approximately 3,500 gross productive wells. +The accompanying audited consolidated financial statements include the accounts of PDC and our wholly-owned subsidiaries. Pursuant to the proportionate consolidation method, our accompanying consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation. +NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Use of Estimates in the Preparation of Financial Statements. The preparation of our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires us to make estimates and assumptions that affect the amounts reported on our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of proved oil and natural gas reserves used in calculating depletion; estimates of unpaid revenues and unbilled costs; future cash flows from proved oil and natural gas reserves on proved oil and natural gas properties used in impairment assessment; valuation of commodity derivative instruments; the estimation of future abandonment obligations used in asset retirement obligations; valuation of proved and unproved crude oil and natural gas properties from purchased and exchanged businesses and assets; and valuation of deferred income tax assets. +Cash and Cash Equivalents. The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. Cash and cash equivalents potentially subject us to a concentration of credit risk as substantially all of our deposits held in financial institutions were in excess of federal deposit insurance limits as of December 31, 2021 and 2020. We maintain our cash and cash equivalents in the form of money market and checking accounts with financial institutions that we believe are creditworthy and are also lenders under our revolving credit facility. +Commodity Derivative Financial Instruments. Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas we enter into commodity derivative contracts to protect against price declines in future periods. We have elected not to designate any of our commodity derivative instruments as cash flow hedges; therefore, these instruments do not qualify for hedge accounting. Accordingly, changes in the fair value of our derivative instruments are recorded in the consolidated statements of operations. Under applicable accounting standards, the fair value of each derivative instrument is recorded as either an asset or liability on the consolidated balance sheet. We measure the fair value of our commodity derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates, volatility factors and nonperformance risk. +Properties and Equipment. +Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Under this method, costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depleted by the unit-of-production method based on estimated proved developed producing reserves. We have determined that we have two unit-of-production fields: the Wattenberg Field and the Delaware Basin. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations and common cost environments in these areas. We calculate quarterly depletion expense by using our estimated prior period-end reserves as the denominator, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted for fourth quarter production. The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under +72 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +changing economic conditions. As a result, revisions in existing reserve estimates occur. Capitalized development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized as a gain or loss. +Exploration costs, including geological and geophysical expenses, seismic costs on unproved leaseholds and delay rentals are expensed as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have identified a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expen se. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as suspended well costs until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the resulting accounting treatment is recorded. +Unproved property costs not subject to depletion primarily include leasehold costs, broker and legal expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Leasehold costs are transferred into costs subject to depletion on an ongoing basis as these properties are evaluated and proved reserves are established. Additional costs not subject to depletion include costs associated with development wells in progress or awaiting completion at year-end. These costs are transferred into costs subject to depletion on an ongoing basis as these wells are completed and proved reserves are established or confirmed. +Proved Property Impairment. Annually, or upon a triggering event, we assess the valuation of our proved crude oil and natural gas properties for possible impairment by comparing the carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production and prices at which we estimate the commodity will be sold. If carrying values exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a discounted future cash flows analysis. The impairment recorded is the amount by which the carrying values exceed the fair value. In the impairment assessment we estimate the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of future production volumes, future operating and development costs, future commodity prices, and a market based weighted average cost of capital rate. Certain events, including but not limited to downward revisions in estimates of our reserve quantities, expectations of falling commodity prices or rising capital and operating costs, could result in a triggering event, and may result to a possible impairment of our proved crude oil and natural gas properties. +Unproved Property Impairment. Acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to impairment expense. Unproved crude oil and natural gas properties with individually significant acquisition costs are assessed for impairment periodically, or if a triggering event is identified. +Other Property and Equipment. Other property and equipment such as vehicles, facilities, office furniture and equipment, buildings and computer hardware and software is carried at cost. Depreciation is provided principally on the straight-line method over the assets’ estimated useful lives, which range from two to 35 years. Total depreciation expense related to other property and equipment was $ 7.7 million, $ 8.7 million and $ 5.7 million for the years ended December 31, 2021, 2020 and 2019, respectively. +We review other property and equipment for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying value of the asset exceeds the estimated future cash flows, an impairment charge is recognized for the amount by which the carrying value of the asset exceeds its fair value. +73 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Internal-Use Software. Internal-use software costs incurred during the development stage of our enterprise resource planning software are capitalized. The development stage generally includes software design, configuration, testing and installation activities. Training and maintenance costs are expensed as incurred, while upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Capitalized internal-use software costs are depreciated over the estimated useful life of the underlying project on a straight-line basis upon completion of the project. +Capitalized Interest. We capitalize interest on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring unevaluated properties to its intended use. Interest capitalized may not exceed gross interest expense for the period. Capitalized interest totaled $ 17.8 million, $ 19.7 million and $ 13.4 million during the year ended December 31, 2021, 2020 and 2019, respectively. +Assets Held-for-Sale. Assets held-for-sale are valued at the lower of their carrying amount or estimated fair value, less costs to sell. If the carrying amount of the assets exceeds their estimated fair value, an impairment loss is recognized. Fair values are estimated using accepted valuation techniques, such as a discounted cash flow model, earnings multiples or indicative bids, when available. We consider historical experience and all available information at the time the estimates are made; however, the fair value that is ultimately realized upon the sale of the assets to be divested may differ from the estimated fair values reflected on the consolidated financial statements. DD&A expense is not recorded on assets once they are classified as held-for-sale. Assets classified as held-for-sale are expected to be disposed of within one year. +Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred income tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred income tax assets and liabilities are measured using enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred income tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred income tax assets to what we consider realizable. +We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. Our policy is to recognize interest and penalties related to uncertain tax positions in interest expense. +Debt Issuance Costs and Discounts. Debt issuance costs and discounts are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs for the Senior Notes are included in long-term debt and the debt issuance costs for the revolving credit facility are included in other assets. +Asset Retirement Obligations. We recognize the estimated liability for future costs associated with the plugging and abandonment of our oil and gas properties resulting from acquisition, construction or normal operation. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value (accretion expense). The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost (presented as part of properties and equipment). Revisions in estimated liabilities can result from, among other things, changes in retirement costs or the estimated timing of settling asset retirement obligations. +Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders’ equity. When we retire treasury shares, we charge any excess of cost over the par value to additional paid-in-capital (“APIC”), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings. +74 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Revenue Recognition. Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of crude oil, natural gas or NGLs production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record revenues based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For the years ending December 31, 2021, 2020 and 2019, the impact of any natural gas imbalances was not significant. +Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or “gross” method of accounting, depending upon the related agreement. We use the net-back method when control of the crude oil, natural gas or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. +We use the gross method of accounting when control of the crude oil, natural gas or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses. +For our product sales that have a contract term greater than one year, the Company has utilized the practical expedient in ASC Topic 606 which states the Company is not required to disclose the transaction price allocated to the remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, monthly sales of a product generally represent a separate performance obligation; therefore, future commodity volumes to be delivered and sold are wholly unsatisfied and disclosure of the transaction price allocated to such unsatisfied performance obligations is not required. +Business Combinations. We utilize the acquisition method to account for acquisitions of businesses. Pursuant to the acquisition method, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows and estimates by management, which are Level 3 inputs. When appropriate, we review recent comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. +In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped and unproved crude oil and natural gas properties. To estimate the fair value of these properties as part of acquisition accounting, we estimate the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices, and a market based weighted average cost of capital rate. The market based weighted average cost of capital rate is subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of recent comparable purchased properties to determine an estimation of fair value. +If applicable, we record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. +75 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Acreage Exchanges . From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and provide us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges in accordance with the guidance prescribed by Accounting Standards Codification 845, Nonmonetary Transactions . For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized in earnings, in accordance with Accounting Standards Codification 820, Fair Value Measurement . +Stock-Based Compensation. Stock-based compensation is recognized within our financial statements based on the grant-date fair value of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the requisite service period for the entire award and we account for forfeitures of stock-based compensation awards as they occur. +Fair Value of Assets and Liabilities. The Company follows the authoritative accounting guidance for measuring fair value of assets and liabilities in its financial statements. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. +Leases. We determine if an arrangement is representative of a lease at contract inception. Right-of-use (“ROU”) assets represent our right to use the underlying assets for the lease term and the corresponding lease liabilities represent our obligations to make lease payments arising from the leases. Operating and finance lease ROU assets and liabilities are recognized at the commencement date based on the present value of the expected lease payments over the lease term. As most of our leases do not provide an implicit interest rate, we utilize our incremental borrowing rate based on information available at the commencement date in determining the present value of lease payments. Subsequent measurement, as well as presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. Terms of our leases include options to extend or terminate the lease only when we can ascertain that it is reasonably certain we will exercise that option. Leases with an initial term of one year or less are not recorded on the consolidated balance sheets. +We apply the practical expedient that permits combining lease and non-lease components in a contract and accounting for the combination as a single lease component (applied by asset class). +NOTE 3 - PENDING ACQUISITION +On February 26, 2022, we entered into a definitive purchase agreement under which we will acquire Great Western Petroleum, LLC (“Great Western”) for approximately $ 1.3 billion, inclusive of Great Western’s net debt (the “Great Western Acquisition”). Great Western is an independent oil and gas company focused on the exploration, production and development of crude oil and natural gas in Colorado. The purchase consideration for the Great Western Acquisition will be made through the transfer of approximately 4.0 million shares of our common stock and approximately $ 543 million in cash, pursuant to the +76 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Membership Interest Purchase Agreement that we entered into with Great Western (“Acquisition Agreement”). We expect the Great Western Acquisition to be completed in the second quarter of 2022, subject to certain customary closing conditions, including diligence. +NOTE 4 - BUSINESS COMBINATION +In January 2020, we merged with SRC Energy, Inc. (“SRC”) in a transaction valued at $ 1.7 billion, inclusive of SRC’s net debt (the “SRC Acquisition”). SRC was an independent oil and natural gas company engaged in the exploration, development and production of unconventional oil and associated liquids-rich natural gas reserves in Weld County, Colorado. The acquisition added approximately 83,000 net acres which are located on large, contiguous acreage blocks in the core of the Wattenberg Field. +Upon closing, we issued approximately 38.9 million shares of our common stock to SRC shareholders and holders of SRC equity awards, reflecting the issuance of 0.158 of a share of our common stock in exchange for each outstanding share of SRC common stock and the cancellation of outstanding SRC equity awards pursuant to the terms of the merger agreement that we entered into with SRC. We finalized the purchase price allocation on December 31, 2020, and we recognized total transaction costs of $ 19.9 million for the year ended December 31, 2020. +The following table details our final purchase price, valuation and allocation of the purchase price to the assets acquired and liabilities assumed as a result of the SRC Acquisition: +(in thousands) +Consideration: +Cash $ 40 +Retirement of seller’s credit facility 166,238 +Total cash consideration 166,278 +Common stock issued 1,009,015 +Shares withheld in lieu of taxes 6,299 +Total consideration $ 1,181,592 +Recognized amounts of identifiable assets acquired and liabilities assumed: +Assets acquired: +Current assets $ 145,792 +Properties and equipment, net - proved 1,613,674 +Properties and equipment, net - unproved 109,615 +Properties and equipment, net - other 16,242 +Deferred tax asset 189,311 +Other assets 11,810 +Total assets acquired $ 2,086,444 +Liabilities assumed: +Current liabilities $ ( 253,967 ) +Senior notes ( 555,500 ) +Asset retirement obligations ( 42,417 ) +Other liabilities ( 52,968 ) +Total liabilities assumed ( 904,852 ) +Total identifiable net assets acquired $ 1,181,592 +77 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +This acquisition was accounted for under the acquisition method of accounting for business combinations. Accordingly, we conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated acquisition date fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the valuation of proved and unproved crude oil and natural gas properties include estimates of reserve volumes, future operating and development costs, future commodity prices, lease terms and expirations and a market-based weighted-average cost of capital rate of 10 percent. These inputs require significant judgments and estimates by management at the time of the valuation. +The results of operations for the SRC Acquisition since the closing date have been included on our consolidated financial statements for the year ended December 31, 2020 and include approximately $ 320.9 million of total revenue, and $ 46.5 million of income from operations. +Pro Forma Information . The following unaudited pro forma financial information represents a summary of the consolidated results of operations for the years ended December 31, 2020, and 2019, assuming the acquisition had been completed as of January 1, 2019. The information below reflects certain nonrecurring pro forma adjustments that were directly related to the business combination based on available information and certain assumptions that we believe are reasonable, including (i) the Company’s common stock issued to convert SRC’s outstanding shares of common stock and equity awards, (ii) the depletion of SRC’s fair-valued proved oil and gas properties using the successful efforts method of accounting and (iii) the estimated tax impacts of the pro forma adjustments, if any. Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company and SRC totaling approximately $ 38.0 million and $ 15.9 million for the years ended December 31, 2020 and 2019, respectively. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the acquisition had been effective as of these dates, or of future results. +Year Ended December 31, +2020 2019 +(in thousands, except per share data) +Total revenue $ 1,361,051 $ 1,761,498 +Net income (loss) ( 695,663 ) 139,578 +Earnings (loss) per share: +Basic $ ( 6.97 ) $ 1.36 +Diluted ( 6.97 ) 1.35 +78 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 5 - REVENUE RECOGNITION +Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for the periods presented: +Year Ended December 31, +Revenue by Commodity and Operating Region 2021 2020 2019 +(in thousands) +Crude oil +Wattenberg Field $ 1,275,666 $ 668,948 $ 767,760 +Delaware Basin 255,135 147,902 252,929 +Total 1,530,801 816,850 1,020,689 +Natural gas +Wattenberg Field 458,870 171,755 137,143 +Delaware Basin 60,733 6,997 13,877 +Total 519,603 178,752 151,020 +NGLs +Wattenberg Field 428,570 128,126 94,347 +Delaware Basin 73,584 28,827 41,219 +Total 502,154 156,953 135,566 +Crude oil, natural gas and NGLs +Wattenberg Field 2,163,106 968,829 999,250 +Delaware Basin 389,452 183,726 308,025 +Total $ 2,552,558 $ 1,152,555 $ 1,307,275 +Contract Assets. Contract assets include material contributions in aid of construction, which are common in purchase and processing agreements with midstream service providers that are our customers. The intent of the payments is primarily to reimburse the customer for actual costs incurred related to the construction of its gathering and processing infrastructure. Contract assets are included in other assets on the consolidated balance sheets. The contract assets are amortized as a reduction to crude oil, natural gas and NGLs sales revenue during the periods in which the related production is transferred to the customer. +The following table presents the changes in carrying amounts of the contract assets associated with our crude oil, natural gas and NGLs sales revenue for the periods presented: +December 31, +2021 2020 +(in thousands) +Beginning balance $ 25,872 $ 11,494 +Additions (Net reduction to additions previously recognized) ( 7,705 ) 16,739 +Amortized as a reduction to crude oil, natural gas and NGLs sales ( 2,695 ) ( 2,361 ) +Ending balance $ 15,472 $ 25,872 +NOTE 6 - FAIR VALUE MEASUREMENTS +Recurring Fair Value Measurements +Derivative Financial Instruments. We measure the fair value of our commodity derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates, volatility factors and nonperformance risk. Nonperformance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties’ credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default exchange rates and the duration of each outstanding derivative position. We use our counterparties’ valuations to assess reasonableness of our fair value measurement. +79 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Our crude oil and natural gas fixed-price exchanges and basis exchanges are included in Level 2. Our collars are included in Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis as of the dates indicated: +December 31, 2021 December 31, 2020 +Consolidated Balance Sheet Line Item Significant Other +Observable +Inputs +(Level 2) Significant +Unobservable +Inputs +(Level 3) Total Significant Other +Observable +Inputs +(Level 2) Significant +Unobservable +Inputs +(Level 3) Total +(in thousands) +Derivative assets +Current Fair value of derivatives $ — $ 17,909 $ 17,909 $ 36,580 $ 12,289 $ 48,869 +Non-current Fair value of derivatives 605 14,572 15,177 315 9,250 9,565 +Total $ 605 $ 32,481 $ 33,086 $ 36,895 $ 21,539 $ 58,434 +Derivative liabilities +Current Fair value of derivatives $ ( 230,695 ) $ ( 74,175 ) $ ( 304,870 ) $ ( 76,420 ) $ ( 21,732 ) $ ( 98,152 ) +Non-current Fair value of derivatives ( 74,715 ) ( 20,846 ) ( 95,561 ) ( 28,125 ) ( 8,234 ) ( 36,359 ) +Total $ ( 305,410 ) $ ( 95,021 ) $ ( 400,431 ) $ ( 104,545 ) $ ( 29,966 ) $ ( 134,511 ) +The following table presents a reconciliation of our Level 3 assets and liabilities measured at fair value for the periods presented: +Year Ended December 31, +2021 2020 2019 +(in thousands) +Fair value of Level 3 instruments, net asset (liability) beginning of period $ ( 8,427 ) $ 8,414 $ 58,329 +Changes in fair value included in consolidated statements of operations line item: +Commodity price risk management gain (loss), net ( 206,109 ) 37,821 ( 41,749 ) +Settlements included in consolidated statements of operations line items: +Commodity price risk management gain (loss), net 151,996 ( 54,662 ) ( 8,166 ) +Fair value of Level 3 instruments, net asset (liability) end of period $ ( 62,540 ) $ ( 8,427 ) $ 8,414 +Net change in fair value of Level 3 unsettled derivatives included in consolidated statements of operations line item: +Commodity price risk management gain (loss), net $ ( 35,108 ) $ — $ ( 22,694 ) +Total $ ( 35,108 ) $ — $ ( 22,694 ) +The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve, which is provided by a third-party vendor. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. There has been no change in the methodology we apply to measure the fair value of our Level 3 derivative contracts during the periods covered by the financial statements. +Nonrecurring Fair Value Measurements +Acquisitions and Impairment of Long-lived Assets. We measure fair value using inputs that are not observable in the market, and are therefore designated as Level 3 within the valuation hierarchy, on a nonrecurring basis for any acquired assets or businesses and to review our proved and unproved crude oil and natural gas properties for possible impairment. +80 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Asset Retirement Obligations. We measure the fair value of asset retirement obligations as of the date a well begins drilling or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 within the valuation hierarchy. +Other Financial Instruments +The carrying value of the financial instruments included in current assets and current liabilities approximates fair value due to the short-term maturities of these instruments. +Long-term Debt. The portion of our long-term debt related to our revolving credit facility approximates fair value, as the applicable interest rates are variable and reflective of market rates. We have not elected to account for the portion of our debt related to our senior notes under the fair value option; however, we have determined an estimate of the fair values based on measurements of trading activity and broker or dealer quotes, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes and convertible notes as of the dates indicated: +December 31, +2021 2020 +Nominal Interest Estimated Fair Value Percent of Par Estimated Fair Value Percent of Par +(in millions) (in millions) +2021 Convertible Notes (1) +1.125 % $ — — % $ 196.2 98.1 % +2024 Senior Notes 6.125 % 202.8 101.4 % 410.8 102.7 % +2025 Senior Notes (2) +6.25 % — — % 102.8 100.5 % +2026 Senior Notes 5.75 % 775.5 103.4 % 775.5 103.4 % +_______________ +(1) Our 2021 Convertible Notes were redeemed and retired on September 15, 2021. +(2) Our 2025 Senior Notes were redeemed and retired on December 1, 2021. +NOTE 7 - COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS +Objective and Strategy. Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas we enter into commodity derivative contracts such as collars, fixed-price exchanges and basis protection exchanges, to protect against price declines in future periods. We do not enter into derivative contracts for speculative or trading purposes. +We believe our commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. Depending on changes in oil and gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our derivative positions from current levels. As of December 31, 2021, we had derivative instruments in place for a portion of our anticipated production in 2022 through 2024. Our commodity derivative contracts have been entered into at no upfront cost to us as we hedge our anticipated production at the then-prevailing commodity market prices, without adjustment for premium or discount. +As of December 31, 2021 and 2020, our derivative instruments were comprised of fixed-price swaps, collars and basis protection swaps. +• Fixed-price swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty; +• Collars contain a fixed floor price (put) and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty; +81 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +• Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For basis protection swaps, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. +Effect of Derivative Instruments on the Consolidated Statements of Operations. The following table presents the impact of our derivative instruments on our consolidated statements of operations for the periods presented: +Year Ended December 31, +Consolidated Statements of Operations Line Item 2021 2020 2019 +(in thousands) +Commodity price risk management gain (loss), net +Net settlements $ ( 410,188 ) $ 279,271 $ ( 17,598 ) +Net change in fair value of unsettled derivatives ( 291,268 ) ( 99,001 ) ( 145,246 ) +Total commodity price risk management gain (loss), net $ ( 701,456 ) $ 180,270 $ ( 162,844 ) +Commodity Derivative Contracts. As of December 31, 2021, we had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is presented: +Collars Fixed-Price Swaps +Commodity/ Index/ +Maturity Period +Quantity (Crude oil - MBbls Natural Gas - BBtu) +Weighted Average Contract Price +Quantity (Crude Oil - MBbls Gas and Basis- BBtu) +Weighted Average Contract Price +Fair Value December 31, 2021 (in thousands) +Floors Ceilings +Crude Oil +NYMEX +2022 5,472 $ 53.18 $ 67.33 6,744 $ 44.42 $ ( 235,146 ) +2023 2,775 55.00 70.00 5,502 56.83 ( 58,299 ) +2024 225 55.00 75.12 1,500 61.27 ( 2,276 ) +Total Crude Oil 8,472 13,746 ( 295,721 ) +Natural Gas +NYMEX +2022 35,460 3.14 4.78 33,600 2.70 ( 41,165 ) +2023 3,000 3.00 4.42 30,398 2.68 ( 19,171 ) +Total Natural Gas 38,460 63,998 ( 60,336 ) +Basis Protection - Natural Gas +CIG +2022 — — — 69,060 ( 0.25 ) ( 10,650 ) +2023 — — — 29,438 ( 0.27 ) ( 638 ) +Total Basis Protection - Natural Gas — 98,498 ( 11,288 ) +Commodity Derivatives Fair Value $ ( 367,345 ) +82 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Subsequent to December 31, 2021, we entered into the following commodity derivative positions covering our crude oil and natural gas production: +Collars Fixed-Price Swaps +Commodity/ Index/ +Maturity Period +Quantity +(Crude oil - +MBbls +Natural Gas - BBtu) +Weighted Average +Contract Price +Quantity +(Crude oil - +MBbls +Natural Gas - BBtu) +Weighted- +Average +Contract +Price +Floors Ceilings +Crude Oil - NYMEX +2023 1,050 $ 55.00 $ 79.14 — $ — +2024 — — — 2,208 70.25 +Natural Gas - NYMEX +2023 12,060 3.08 4.35 — — +Natural Gas Basis Protection - CIG +2023 — — — 12,060 ( 0.29 ) +Effect of Derivative Instruments on the Consolidated Balance Sheet. The balance sheet line items and fair value amounts of our derivative instruments are disclosed in Note 6 - Fair Value Measurements . +Our financial derivative agreements contain master netting provisions that provide for the net settlement of contracts through a single payment in the event of early termination. We have elected not to offset the fair value positions recorded on our consolidated balance sheets. +The following table reflects the impact of netting agreements on gross derivative assets and liabilities: +Total Gross Amount Presented on the Balance Sheet Effect of Master Netting Agreements Total Net Amount +As of December 31, 2021 (in thousands) +Derivative asset instruments, at fair value $ 33,086 $ ( 33,086 ) $ — +Derivative liability instruments, at fair value $ 400,431 $ ( 33,086 ) $ 367,345 +As of December 31, 2020 +Derivative asset instruments, at fair value $ 58,434 $ ( 39,691 ) $ 18,743 +Derivative liability instruments, at fair value $ 134,511 $ ( 39,691 ) $ 94,820 +Derivative Counterparties. Our commodity derivative instruments expose us to the risk of non-performance by our counterparties. We use financial institutions who are also lenders under our revolving credit facility as counterparties to our commodity derivative contracts. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of nonperformance of our current counterparties on the fair value of our derivative instruments is not significant at December 31, 2021; however, this determination may change. +83 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 8 - PROPERTIES AND EQUIPMENT, NET +The following table presents the components of properties and equipment, net of accumulated depreciation, depletion and amortization (“DD&A”), as of the dates indicated: +December 31, +2021 2020 +(in thousands) +Properties and equipment, net: +Crude oil and natural gas properties +Proved $ 8,310,018 $ 7,523,639 +Unproved 306,181 350,677 +Total crude oil and natural gas properties 8,616,199 7,874,316 +Equipment and other 63,099 65,027 +Land and buildings 19,928 24,299 +Construction in progress 371,968 523,550 +Properties and equipment, at cost 9,071,194 8,487,192 +Accumulated DD&A ( 4,256,329 ) ( 3,627,993 ) +Properties and equipment, net $ 4,814,865 $ 4,859,199 +Impairment of Oil and Gas Properties. The following table presents impairment charges recorded for properties and equipment for the periods presented: +Year Ended December 31, +2021 2020 2019 +(in thousands) +Impairment of proved and unproved properties $ 402 $ 881,238 $ 10,599 +Impairment of infrastructure and other — 1,155 27,937 +Total impairment of properties and equipment $ 402 $ 882,393 $ 38,536 +Oil and Gas Properties. +In the first quarter of 2020, the significant decline in crude oil prices in addition to the ongoing effects of the COVID-19 pandemic were considered a triggering event that required us to assess our crude oil and natural gas properties for possible impairment. As a result of our assessment, we recorded impairment expense of $ 881.1 million to our proved and unproved properties. During the year ended December 31, 2021, there were no significant impairments recognized. +Proved Properties. Of the total impairment expense recognized in 2020, approximately $ 753.0 million was related to our Delaware Basin proved properties. These impairment charges represented the amount by which the carrying value of the crude oil and natural gas properties exceeded the estimated fair value. We estimated the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount, a Level 3 input. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of future production volumes, future operating and development costs, future commodity prices, and a discount rate of 17 percent, which was based on a weighted average cost of capital for the area where the assets are located. There were no impairment charges recognized related to our proved properties during the year ended December 31, 2019. +Unproved Properties. We recognized approximately $ 127.3 million of impairment charges for our unproved properties in the Delaware Basin in 2020. These impairment charges were recognized based on the fair value of the properties, a Level 3 input. The fair value is estimated based on a review of our current drilling plans, estimated future cash flows for probable well locations and expected future lease expirations, primarily in areas where we have no development plans. +During the year ended December 31, 2019, we recorded impairment charges totaling $10.6 million related to the divestiture of unproved leaseholds and then-current and anticipated near-term leasehold expirations within our non-focus areas of the Delaware Basin that we determined not to develop. +84 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Other Property and Equipment Impairment. During the year ended December 31, 2019, we recorded impairments of $27.9 million related to certain midstream facility infrastructure in the Delaware Basin. Upon the divestiture of certain midstream assets, it was determined that the net book value of these assets was not recoverable. +Suspended Well Costs. The following table presents the capitalized exploratory well cost pending determination of proved reserves and included in properties and equipment for the periods presented: +Year Ended December 31, +2021 2020 2019 +(in thousands, except for number of wells) +Beginning balance $ 7,459 $ 16,078 $ 12,188 +Additions to capitalized exploratory well costs pending the determination of proved reserves 5,902 11,770 31,901 +Reclassifications to proved properties ( 13,361 ) ( 20,389 ) ( 28,011 ) +Ending balance $ — $ 7,459 $ 16,078 +Number of wells pending determination at period-end — 2 4 +As of December 31, 2020, our net capitalized exploratory well costs that have been capitalized for a period greater than one year was $ 7.5 million, which consists of the entire balance of our suspended well costs and relates to two gross suspended wells associated with two projects. During the year ended December 31, 2021, both exploratory wells were determined to be successful producing wells and were reclassified into proved properties. We have no remaining exploratory wells pending determination as of December 31, 2021. +NOTE 9 - ACCOUNTS RECEIVABLE, OTHER ACCRUED EXPENSES AND OTHER LIABILITIES +Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts as of the dates indicated: +December 31, +2021 2020 +(in thousands) +Crude oil, natural gas and NGLs sales $ 368,991 $ 178,147 +Joint interest billings 24,860 35,396 +Other 10,809 37,471 +Allowance for doubtful accounts ( 6,055 ) ( 6,763 ) +Accounts receivable, net $ 398,605 $ 244,251 +The Company’s accounts receivable consist mainly of receivables from (i) crude oil, natural gas and NGLs purchasers, (ii) joint interest owners in the properties we operate and (iii) derivative counterparties. Most payments for production are received within two months after the production date. For receivables from joint interest owners, we typically have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. +Credit and Concentration Risk. Inherent to our industry is the concentration of crude oil, natural gas and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. +85 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Given the liquidity in the market for the sale of hydrocarbons, we believe that the loss of any single purchaser, or the aggregate loss of several purchasers, could be managed by selling to alternative purchasers in our operating areas. The following major customers accounted for 10 percent or more of our total crude oil, natural gas, and NGLs sales for at least one of the periods presented: +Year Ended December 31, +2021 2020 2019 +Major customer #1 32 % 31 % 20 % +Major customer #2 11 % 16 % 16 % +Major customer #3 10 % 13 % 11 % +Major customer #4 9 % 17 % 17 % +Other Accrued Expenses. The following table presents the components of other accrued expenses as of the dates indicated: +December 31, +2021 2020 +(in thousands) +Employee benefits $ 29,319 $ 23,304 +Asset retirement obligations 32,146 33,933 +Environmental expenses 11,942 10,139 +Operating and finance leases 7,197 7,986 +Other 10,805 6,353 +Other accrued expenses $ 91,409 $ 81,715 +Other Liabilities. The following table presents the components of other liabilities as of the dates indicated: +December 31, +2021 2020 +(in thousands) +Deferred midstream gathering credits $ 159,788 $ 168,478 +Deferred oil gathering credits 16,080 18,090 +Production taxes 131,865 65,592 +Operating and finance leases 6,274 10,763 +Other 762 1,111 +Other liabilities $ 314,769 $ 264,034 +Deferred Midstream Gathering Credits. In 2019, we entered into agreements pursuant to which we dedicated the gathering of certain of our production and all water gathering and disposal volumes in the Delaware Basin. The terms of these agreements range from 15 to 22 years. The acreage dedication agreements resulted in initial cash receipts and are being amortized on a units-of-production basis. The amortization rates are assessed on an annual basis for changes in estimated future production. +Deferred Oil Gathering Credits. In 2018, we entered into an agreement that dedicates crude oil from the majority of our Wattenberg Field acreage to the midstream provider’s gathering lines and extends the term of the agreement through December 2029. The acreage dedication agreement resulted in an initial cash receipt and is being amortized on a units-of-production basis. The amortization rates are assessed on an annual basis for changes in estimated future production. +86 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the amortization charges related to our deferred credits recognized on the consolidated statements of operations for the periods indicated: +Year Ended December 31, +2021 2020 +(in thousands) +Crude oil, natural gas and NGLs sales $ — $ 1,013 +Transportation, gathering and processing expense 7,317 5,618 +Lease operating expense 2,422 2,015 +NOTE 10 - LONG-TERM DEBT +Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $7.9 million and $17.8 million as of December 31, 2021 and December 31, 2020, respectively, consists of the following: +December 31, +2021 2020 +(in thousands) +Revolving credit facility due November 2026 $ — $ 168,000 +1.125% Convertible Notes due September 2021 — 193,014 +6.125% Senior Notes due September 2024 198,674 396,368 +6.25% Senior Notes due December 2025 — 103,204 +5.75% Senior Notes due May 2026 743,410 741,976 +Total debt, net of unamortized discount, premium and debt issuance costs 942,084 1,602,562 +Less: Current portion of long-term debt — 193,014 +Total long-term debt $ 942,084 $ 1,409,548 +Revolving Credit Facility +In November 2021, we entered into a Fifth Amended and Restated Credit Agreement (the “Restated Credit Agreement”), which provides for a maximum credit amount of $ 2.5 billion, subject to certain limitations, an initial borrowing base of $ 2.4 billion and an elected commitment of $ 1.5 billion. The Restated Credit Agreement matures on the earlier to occur of (i) the end of the five year term on November 2, 2026 or (ii) the date that is 91 days prior to the scheduled maturity of the 2026 Senior Notes if the aggregate outstanding principal amount of those notes exceeds $500 million and our commitment utilization exceeds 50%. +The revolving credit facility is available for working capital requirements, capital investments, acquisitions, to support letters of credit and for general business purposes. The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. The borrowing base is subject to a semi-annual redetermination on November 1 and May 1 based upon quantification of our reserves at June 30 and December 31, and is also subject to a redetermination upon the occurrence of certain events. Substantially all of our crude oil and natural gas properties have been mortgaged or pledged as security for our revolving credit facility. The Restated Credit Agreement includes an investment grade period election pursuant to which we have an option to remove our borrowing base limitations and terminate the liens securing the Restated Credit Agreement when certain debt ratings are achieved. +As of December 31, 2021, we had a borrowing base of $ 2.4 billion, an elected commitment of $ 1.5 billion and availability under our revolving credit facility of $ 1.5 billion, net of $ 19.9 million of letters of credit outstanding. +The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greatest of the administrative agent's prime rate, the federal funds rate plus a premium and the rate for dollar deposits in the Secured Overnight Financing Rate (“SOFR”) for one month, plus a premium) or, at our election, a rate equal to SOFR for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. As of December 31, 2021, the applicable interest margin is 0.75 percent for the alternate base rate option or 1.75 percent for the SOFR option, and the unused commitment fee is 0.375 percent. Principal payments are generally not required until the maturity date of the revolving credit +87 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +facility, unless the borrowing base falls below the outstanding balance. The Restated Credit Agreement also includes the ability to add certain sustainability-linked key performance indicators to be agreed upon between us, the administrative agent and a majority of the lenders and that may impact the applicable margin and commitment fee rate. +The revolving credit facility contains various restrictive covenants and compliance requirements, which include, among other things: (i) maintenance of certain financial ratios, as defined per the revolving credit facility, including a minimum current ratio of 1.0:1.0 and a maximum leverage ratio of 3.50:1.0; (ii) restrictions on the payment of cash dividends; (iii) limits on the incurrence of additional indebtedness; (iv) prohibition on the entry into commodity hedges exceeding a specified percentage of our expected production; and (v) restrictions on mergers and dispositions of assets. As of December 31, 2021, we were in compliance with all covenants related to our revolving credit facility. +As of December 31, 2021 and 2020, debt issuance costs related to our revolving credit facility were $ 16.9 million and $ 8.1 million, respectively, and are included in other assets on our consolidated balance sheets. +Senior Notes and Convertible Notes +The following table summarizes the face values, interest rates, maturity dates, semi-annual interest payment dates, and optional redemption periods related to our outstanding senior note obligations as of December 31, 2021: +2024 Senior Notes 2026 Senior Notes +Outstanding principal amounts (in thousands) $ 200,000 $ 750,000 +Interest rate 6.125 % 5.75 % +Maturity date September 15, 2024 May 15, 2026 +Interest payment dates March 15, September 15 May 15, November 15 +Redemption periods (1) +September 15, 2022 May 15, 2024 +_____________ +(1) At any time prior to the indicated dates, we have the option to redeem all or a portion of our senior notes of the applicable series at the redemption amounts specified in the respective senior note indenture plus accrued and unpaid interest to the date of redemption. On or after the indicated dates, we may redeem all or a portion of the senior notes at a redemption amount equal to 100% of the principal amount of the senior notes being redeemed plus accrued and unpaid interest to the date of redemption. +Our wholly-owned subsidiary, PDC Permian, Inc., is a guarantor of our obligations under the 2024 Senior Notes and the 2026 Senior Notes (collectively, the “Senior Notes”). +The Senior Notes are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the notes; equal in right of payment to our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries. +Upon the occurrence of a “change of control”, as defined in the indentures for the Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal amount of the notes repurchased, together with accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we may, under certain circumstances, be required to use the net cash proceeds of such asset sale to make an offer to purchase the notes at 100 percent of the principal amount, together with accrued and unpaid interest to the date of purchase. +The indentures governing the Senior Notes contain covenants and restricted payment provisions that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make investments; create certain liens; enter into agreements that restrict distributions or other payments by restricted subsidiaries to us; enter into transactions with affiliates; sell assets; consolidate or merge with or into other companies or transfer all or substantially of our assets; and create unrestricted subsidiaries. As of December 31, 2021, we were in compliance with all covenants and all restricted payment provisions related to our Senior Notes. +Retirement of Convertible Notes. On September 15, 2021, we redeemed and retired our 2021 Convertible Notes with a cash payment for the principal amount of $ 200 million plus accrued and unpaid interest. +88 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Early Retirement of Senior Notes. In November 2021, we redeemed $ 200 million in aggregate principal amount of our 2024 Senior Notes at a redemption price of 101.531 percent of the principal plus accrued and unpaid interest, leaving an aggregate principal amount outstanding of $ 200 million. Additionally, in December 2021, we redeemed the remaining $ 102.3 million principal amount of our 2025 Senior Notes at a redemption price of 103.125 percent of the principal plus accrued and unpaid interest. We recognized an aggregate loss on extinguishment of $ 6.9 million from the partial redemption of our 2024 Senior Notes and retirement of our 2025 Senior Notes. The loss on extinguishment was presented as part of interest expense, net on the consolidated statement of operations. +NOTE 11 - LEASES +We have operating leases for office space and well equipment, and finance leases for vehicles. Our leases have remaining lease terms ranging from one to five years . The vehicle leases include an option to renew on a month-to-month basis after the primary term. Lease payments associated with vehicle leases also include a contractually stated residual value guarantee. +The following table presents the components of lease costs for the periods presented: +Year Ended December 31, +2021 2020 +(in thousands) +Operating lease costs (1) +$ 6,125 $ 7,983 +Finance lease costs: +Amortization of ROU assets 1,752 1,812 +Interest on lease liabilities 164 179 +Total finance lease costs 1,916 1,991 +Short-term lease costs (1) +203,361 193,756 +Total lease costs $ 211,402 $ 203,730 +_______________ +(1) The majority of our operating leases relate to the operation or completion of our wells. Therefore, the lease costs presented in the table above represent the total gross costs we incur, which are not comparable to our net costs recorded to the consolidated statements of operations, consolidated statements of cash flows or capitalized in the consolidated balance sheets, as amounts therein are reflected net of amounts billed to working interest partners. +Our operating lease costs are recorded in lease operating expenses or general and administrative expense and our finance lease costs are recorded in DD&A expense and interest expense. Our short-term lease costs include amounts that are capitalized as part of the cost of assets and are recorded as properties and equipment or recognized as expense. +89 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the balance sheet classification and other information regarding our leases as of the dates indicated: +December 31, +Consolidated Balance Sheet Line Item 2021 2020 +(in thousands) +Operating lease ROU assets Other assets $ 7,630 $ 11,722 +Finance lease ROU assets Properties and equipment, net $ 3,483 $ 3,189 +Total ROU assets $ 11,113 $ 14,911 +Operating lease obligation - short-term Other accrued expenses 5,937 6,520 +Operating lease obligation - long-term Other liabilities 4,044 9,061 +Finance lease obligation - short-term Other accrued expenses 1,260 1,466 +Finance lease obligation - long-term Other liabilities 2,230 1,702 +Total lease liabilities $ 13,471 $ 18,749 +Weighted average remaining lease term (years) 2.8 3.0 +Weighted average discount rate 4.8 % 4.8 % +Maturity of lease liabilities by year and in the aggregate, under operating and financing leases with terms of one year or more, as of December 31, 2021 consist of the following: +Operating Leases Finance Leases Total +(in thousands) +2022 $ 6,214 $ 1,378 $ 7,592 +2023 1,767 1,119 2,886 +2024 950 612 1,562 +2025 950 473 1,423 +2026 747 148 895 +Total lease payments 10,628 3,730 14,358 +Less: Interest and discount ( 647 ) ( 240 ) ( 887 ) +Present value of lease liabilities $ 9,981 $ 3,490 $ 13,471 +In January 2022, we entered into a 11-year lease agreement for an office space expected to commence in March 2022 with aggregate lease payments of approximately $ 32 million. +90 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 12 - ASSET RETIREMENT OBLIGATIONS +The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interests in crude oil and natural gas properties for the periods presented: +Year Ended December 31, +2021 2020 +(in thousands) +Beginning balance $ 166,570 $ 127,251 +Obligations incurred with development activities and other 4,750 6,494 +Obligations incurred with acquisition — 47,673 +Accretion expense 12,086 10,072 +Revisions in estimated cash flows 10,609 4,742 +Obligations discharged with asset retirements and divestitures ( 34,343 ) ( 29,662 ) +Asset retirement obligations at end of period 159,672 166,570 +Current portion (1) +( 32,146 ) ( 33,933 ) +Long-term portion $ 127,526 $ 132,637 +_______________ +(1) The current portion of the asset retirement obligation is included in other accrued expenses on our consolidated balance sheets. +Our estimated asset retirement obligations liability is based on historical experience in plugging and abandoning wells, estimated economic lives and estimated plugging, abandonment and surface reclamation costs considering federal and state regulatory requirements in effect at that time. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations liability, a corresponding adjustment is made to the properties and equipment balance. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as accretion expense. +NOTE 13 - COMMITMENTS AND CONTINGENCIES +The following table presents our firm transportation, sales and processing, water delivery and disposal and purchase commitments: +Year Ending December 31, +2022 2023 2024 2025 2026 Thereafter Total Expiration +Date for Thereafter +Natural gas (MMcf) 82,264 82,264 82,489 70,296 37,029 73,050 427,392 December 31, 2030 +Crude oil (MBbls) 23,360 19,685 9,882 9,855 6,561 — 69,343 +Water (MBbls) 6,207 6,207 6,224 — — — 18,638 +Purchase obligation (Tons) 110,000 300,000 — 410,000 +Dollar commitment (in thousands) +$ 153,857 $ 157,370 $ 92,247 $ 77,491 $ 39,631 $ 37,811 $ 558,407 +91 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Firm Transportation and Processing Agreements. We enter into contracts that provide firm transportation and processing on pipeline systems through which we transport or sell crude oil and natural gas. Satisfaction of the volume requirements includes volumes produced by us and purchased from third parties and produced by other third-party working, royalty and overriding royalty interest owners, whose volumes we market on their behalf. Our consolidated statements of operations reflect our share of these firm transportation and processing costs. These contracts require us to pay these transportation and processing charges whether or not the required volumes are delivered. We may from time to time find ourselves unable to market our commodities at prices acceptable to us, or at all, which could cause us to be unable to meet these obligations. In such cases, we may be subject to fees, minimum margins or other payments. Payments related to our long-term transportation and processing agreements, net of interests, were $ 31.3 million, $ 21.4 million, and $ 27.3 million for the years ended December 31, 2021, 2020, and 2019, respectively. +Facilities Expansion Agreements. We entered into two facilities expansion agreements with our primary midstream provider to expand and improve its natural gas gathering pipelines and processing facilities in the Wattenberg Field. The midstream provider completed and turned on line two 200 MMcfd cryogenic plants in 2018 and 2019. Both agreements require baseline volume commitments and aggregate incremental wellhead volume commitments of 98.1 MMcfd and 77.3 MMcfd for the first and second agreements, respectively. We may be required to pay shortfall fees for any volumes under aggregate incremental commitments. Any shortfall in these volume commitments may be offset by other producers’ volumes sold to the midstream provider that are greater than a certain total baseline volume. We are also required for the first three years of the contracts to guarantee a certain target profit margin to the midstream provider on these incremental volumes. The actual net shortfall in target profit margin incurred, which we guaranteed to our midstream provider, was included as part of contract assets as part of other assets on the consolidated balance sheets. +Firm sales agreement . As of December 31, 2021 we had a firm sales agreement with an integrated marketing company for our crude oil production in the Delaware Basin through 2023. This agreement is expected to provide price diversification through realization of export market pricing via a Corpus Christi terminal and exposure to Brent-weighted prices. This agreement does not require physical delivery of the minimum volumes of crude oil over the contractual term. However, if we do not sell and deliver at least the minimum contract volume pursuant to the agreement, we are required to pay transportation reservation charges related to the undelivered volume. For the years ended December 31, 2021 and 2020, we did not incur material transportation reservation charges under this agreement. +Purchase Obligation. As of December 31, 2021 we had a purchase agreement to buy a minimum volume of frac sand at a fixed sales price effective June 2022 through December 2023. The obligation included in the table above represents the minimum financial commitments pursuant to the terms of the agreement as of December 31, 2021. +Litigation and Legal Items. We are involved in various legal proceedings. We review the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in our best interests. We have provided the necessary estimated accruals in the accompanying consolidated balance sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity. +NOTE 14 - COMMON STOCK +Stock-Based Compensation Plans +2018 Equity Incentive Plan . In 2020, our stockholders approved an amendment to increase the number of shares of our common stock reserved for issuance pursuant to our long-term equity compensation plan for employees and non-employee directors (the “2018 Plan”) from 1,800,000 to 7,050,000 shares. The 2018 Plan expires in March 2028. The capital stock available for issuance under the 2018 Plan consists of shares of the Company’s authorized but unissued common stock or previously issued common stock that has been reacquired by the Company. Additionally, to the extent that an award under the 2018 Plan, in whole or in part, is canceled, expired, forfeited, settled in cash or otherwise terminated without delivery of shares, such shares remain available for issuance. Any shares withheld for taxes cannot be recycled under this plan. Awards may be issued in the form of options, stock appreciation rights (“SARs”), restricted stock, restricted stock units (“RSUs”), performance stock units (“PSUs”) and other stock-based awards. Awards may vest over periods of continued service or upon the satisfaction of performance conditions set at the discretion of the Compensation Committee of our board of directors (the “Compensation Committee”), with a minimum one-year vesting period applicable to most awards. With regard to SARs and options, awards +92 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +have a maximum exercisable period of ten years. As of December 31, 2021, there were 4,177,611 shares available for grant under the 2018 Plan. +2010 Long-Term Equity Compensation Plan . Our Amended and Restated 2010 Long-Term Equity Compensation Plan, approved in 2013 (the “2010 Plan”), remains outstanding and we may continue to use the 2010 Plan to grant awards. No awards may be granted under the 2010 Plan on or after June 5, 2023. As of December 31, 2021, there were 314,413 shares available for grant under the 2010 Plan. +2015 SRC Equity Incentive Plan . Pursuant to the closing of the SRC Acquisition, SRC granted PSUs to certain SRC executives (the “SRC PSUs”) under the 2015 SRC Equity Incentive Plan (the “2015 SRC Plan”). The SRC PSUs were converted into 155,928 PDC PSUs and remained subject to the same terms and conditions (including performance-vesting terms) that applied immediately prior to the closing of the SRC Acquisition. As of December 31, 2021, all converted SRC PSUs vested and there were no shares available for grant under the 2015 SRC Plan. +The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented: +Year Ended December 31, +2021 2020 2019 +(in thousands) +General and administrative expense $ 21,830 $ 21,182 $ 22,754 +Lease operating expense 1,193 1,018 1,083 +Total stock-based compensation expense $ 23,023 $ 22,200 $ 23,837 +Restricted Stock Units +The Company grants to executive officers and employees time-based RSUs, which vest ratably over a three-year service period. The fair value of these time-based RSUs is based on the market price of our common stock on the grant date and is recognized ratably over the requisite service period. The time-based RSUs generally vest ratably on each anniversary following the grant date provided that a participant is continuously employed. +The following table presents the changes in non-vested time-based RSUs to eligible employees, including executive officers, during the year ended December 31, 2021: +Shares Weighted Average Grant-Date Fair Value per Share +Non-vested at beginning of period 1,150,970 $ 20.14 +Granted 657,972 33.64 +Vested ( 547,985 ) 24.86 +Forfeited ( 95,770 ) 22.74 +Non-vested at end of period 1,165,187 25.33 +The weighted average grant-date fair value of restricted stock units was $ 33.64 , $ 11.98 and $ 40.34 for the years ended December 31, 2021, 2020 and 2019, respectively. The total grant-date fair value of restricted stock units that vested for the years ended December 31, 2021, 2020 and 2019 was $ 13.6 million, $ 20.4 million and $ 16.3 million, respectively. Total compensation cost related to non-vested time-based awards and not yet recognized on the consolidated statements of operations as of December 31, 2021 was $ 18.2 million. This cost is expected to be recognized over a weighted average period of 1.6 years. +93 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Performance Stock Units +The Company grants to certain executive officers PSUs which are subject to market-based vesting criteria as well as a three-year service period. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved. The fair value of the market-based PSUs is amortized ratably over the requisite service period. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. +The Compensation Committee awarded a total of 207,655 market-based PSUs to our executive officers during 2021. In addition to continuous employment, the vesting of these PSUs is contingent on a combination of absolute stock performance and our total stockholder return (“TSR”), which is essentially our stock price change including any dividends over a three-year period ending on December 31, 2023, as compared to the TSR of a group of peer companies over the same period. The PSUs will result in a payout between zero and 250 percent of the target PSUs awarded. +The grant-date fair value was estimated using a Monte Carlo valuation model. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our common stock historical volatility. +The following table summarizes the key assumptions and related information used to determine the grant-date fair value of performance stock units awarded during the periods presented: +Year Ended December 31, +2021 2020 2019 +Expected term of award (in years) 3 3 3 +Risk-free interest rate 0.2 % 1.4 % 2.5 % +Expected volatility 84.6 % 46.6 % 41.4 % +Weighted average grant-date fair value per share $ 54.01 $ 33.52 $ 56.68 +The expected term of the awards is based on the number of years from the grant date through the end of the performance period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant, extrapolated to approximate the life of the awards. The expected volatility was based on our common stock historical volatility, as well as that of our peer group. +The following table presents the change in non-vested market-based awards during the year ended December 31, 2021: +Shares Weighted Average Grant-Date Fair Value per Share +Non-vested at December 31, 2020 499,547 $ 38.66 +Granted 207,655 54.01 +Vested ( 267,973 ) 43.10 +Non-vested at December 31, 2021 439,229 43.21 +The total grant-date fair value of performance stock units that vested in the years ended December 31, 2021, 2020 and 2019 was $ 11.6 million, $ 4.7 million and $ 2.0 million, respectively. On December 31, 2021, the service period lapsed on 112,045 performance stock units granted in 2019 and 155,928 SRC PSUs that earned 1.90 shares for each vested award resulting in 503,615 aggregate shares of common stock being issued in January 2022. Total compensation cost related to non-vested market-based awards not yet recognized on the consolidated statements of operations as of December 31, 2021 was $ 10.5 million. This cost is expected to be recognized over a weighted average period of 1.5 years. +94 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Preferred Stock +We are authorized to issue 50,000,000 shares of preferred stock, par value $ 0.01 per share, which may be issued in one or more series, with such rights, preferences, privileges and restrictions as shall be fixed by our board of directors from time to time. Through December 31, 2021, no shares of preferred stock have been issued. +Stock Repurchase Program +In 2019, our board of directors approved the repurchase of up to $ 200 million of our outstanding common stock (the “Stock Repurchase Program”). Effective upon the closing of the SRC Acquisition, our board of directors approved an increase and extension to the Stock Repurchase Program from $ 200 million to $ 525 million. Repurchases under the Stock Repurchase Program can be made in open markets at our discretion and in compliance with safe harbor provisions, or in privately negotiated transactions. The Stock Repurchase Program does not require any specific number of shares to be acquired, is subject to market conditions and can be modified or discontinued by the board of directors at any time. Pursuant to the Stock Repurchase Program, we repurchased 3.8 million and 1.3 million shares of outstanding common stock at a cost of $ 159.5 million and $ 23.8 million during the years ended December 31, 2021 and 2020, respectively. We suspended the program in 2020 due to adverse market conditions but reinstated it in 2021. As of December 31, 2021, $ 187.3 million remained available under the program for repurchases of our outstanding common stock. In February 2022, our board of directors increased the size of the program to $ 1.25 billion and extended it through December 31, 2023. The Stock Repurchase Program is being implemented at the discretion of our board of directors and may be suspended, modified, extended or discontinued by our board of directors at any time. +Dividends +In the second quarter of 2021, our board of directors commenced the declaration and payment of quarterly cash dividends of $ 0.12 per share of our outstanding common stock. In December 2021, our board of directors declared and paid a special dividend of $0.50 per share of our outstanding common stock in addition to the fourth quarter dividend. For the year ended December 31, 2021, our dividends paid totaled $ 0.86 per share of common stock or $ 83.6 million. All RSUs and PSUs receive a dividend equivalent per unit, recognized as a liability included in other liabilities on the consolidated balance sheets, until the recipients receive the equivalents upon vesting. Dividends declared were recorded as a reduction of additional paid-in capital as there were no retained earnings as of the date of declaration. Future dividend payments must be approved by our board of directors and will depend on our liquidity, financial requirements, and other factors considered relevant by our board. +NOTE 15 - INCOME TAXES +The table below presents the components of our provision for income tax (expense) benefit for the periods presented: +Year Ended December 31, +2021 2020 2019 +(in thousands) +Current: +Federal $ — $ 1,592 $ 1,366 +State ( 200 ) ( 220 ) ( 300 ) +Total current income tax benefit ( 200 ) 1,372 1,066 +Deferred: +Federal ( 23,790 ) 5,460 4,507 +State ( 2,593 ) 1,070 ( 2,251 ) +Total deferred income tax (expense) benefit ( 26,383 ) 6,530 2,256 +Income tax (expense) benefit $ ( 26,583 ) $ 7,902 $ 3,322 +95 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents a reconciliation of the federal statutory rate to the effective tax rate related to our (expense) benefit for income taxes for the periods presented: +Year Ended December 31, +2021 2020 2019 +Federal statutory tax rate 21.0 % 21.0 % 21.0 % +State income tax, net 3.2 3.0 3.6 +Federal tax credits — — ( 3.3 ) +Effect of state income tax rate changes — 0.2 ( 6.4 ) +Change in valuation allowance ( 19.8 ) ( 22.1 ) ( 0.6 ) +Non-deductible compensation 0.3 ( 0.6 ) ( 5.0 ) +Non-deductible acquisition costs — ( 0.1 ) ( 2.3 ) +Non-deductible government relations 0.1 ( 0.1 ) ( 1.0 ) +Other non-deductible items — — ( 0.5 ) +Other — ( 0.2 ) — +Effective tax rate 4.8 % 1.1 % 5.5 % +The effective income tax rates for 2021 and 2020 were 4.8 percent and 1.1 percent on the respective pre-tax income or loss. The effective tax rates of 4.8 percent for 2021 and 1.1 percent for 2020 differ from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21 percent to the pre-tax income or loss due to the valuation allowance in effect at December 31, 2021 and 2020. The effective tax rate of 5.5 percent for 2019 differs from the statutory U.S. federal income tax rate of 21 percent due to state income taxes, non-deductible lobbying expenses, stock-based compensation and nondeductible officers’ compensation. +Tax effects of temporary differences that give rise to significant portions of deferred tax assets and deferred tax liabilities as of the dates indicated: +December 31, +2021 2020 +(in thousands) +Deferred tax assets: +Deferred compensation $ 9,949 $ 10,472 +Asset retirement obligations 38,274 39,371 +Federal NOL carryforward 97,555 97,880 +State NOL and tax credit carryforwards, net 20,266 21,034 +Federal tax - credit carryforwards 3,059 3,059 +Net change in fair value of unsettled commodity derivatives 88,053 18,351 +Prepaid revenue 3,854 4,364 +Other 4,454 5,741 +Valuation allowance ( 56,634 ) ( 165,575 ) +Total gross deferred tax assets 208,830 34,697 +Deferred tax liabilities: +Properties and equipment 235,213 33,183 +Convertible debt — 1,514 +Total gross deferred tax liabilities 235,213 34,697 +Net deferred tax liability $ 26,383 $ — +96 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +We consider whether a portion, or all, of our deferred tax assets (“DTAs”) will be realized based on a more likely than not standard of judgment. The ultimate realization of DTAs is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, management considers the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, tax planning strategies and projected future taxable income in making this assessment. The oil and gas property impairments and cumulative pre-tax losses were key considerations that led us to continue to provide a valuation allowance against our DTAs as of December 31, 2021 and 2020 since we cannot conclude that it is more likely than not that our DTAs will be fully realized in future periods. +Future events or new evidence which may lead us to conclude that it is more likely than not that our DTAs will be realized include, but are not limited to, cumulative historical pre-tax earnings, sustained or continued improvements in oil prices, and taxable events that could result from one or more transactions. Given recent improvements in oil and gas prices and improvements in our current earnings, we believe there is a reasonable possibility that, if oil and natural gas prices remain similar to December 31, 2021 pricing levels, sufficient positive evidence may become available within the next 12 months to allow us to reach a conclusion that all or a significant portion of the valuation allowance will no longer be needed. Release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense in the period the release is recorded. However, the exact timing and amount of the valuation allowance release are subject to change based on the level of profitability that we actually achieve. +As of December 31, 2021, we have estimated net operating loss carryforwards (“NOLs”) for federal income tax purposes of $ 464.5 million, of which $ 304 million was generated before January 1, 2018 and is not subject to the 80 percent limitation of taxable income. Such NOLs will expire beginning in 2033. In 2016, we acquired a federal NOL of $ 60.1 million as a component of our acquisition in the Delaware Basin that will begin to expire in 2033. Also, we acquired a federal NOL of $ 232.5 million as a component of the SRC Acquisition that will begin to expire in 2037. The federal NOLs acquired as part of the Delaware Basin acquisition and the SRC Acquisition are subject to an annual limitation of $ 15.1 million and $ 16.1 million, respectively, as both acquisitions constitute a change of ownership as defined under Internal Revenue Service (“IRS”) Code Section 382. +As of December 31, 2021, we have state NOL carryforwards of $ 479.4 million that begin to expire in 2029 and state credit carryforwards of $ 3.9 million that begin to expire in 2022. +Unrecognized tax benefits and related accrued interest and penalties were immaterial for the three-year period ended December 31, 2021. As of December 31, 2021, there is no liability for unrecognized income tax benefits. +We are subject to the following material taxing jurisdictions: U.S., Colorado, West Virginia, and Texas. As of December 31, 2021, we are current with our income tax filings in all applicable state jurisdictions and are not currently under any state income tax examinations. We are open to federal and state tax audits until the applicable statutes of limitations expire, however, the ability for the tax authority to adjust the NOL will continue until three years after the NOL is utilized. The statute of limitations has expired for all federal and state returns filed for periods ending before 2016. The IRS has accepted our 2019 federal income tax return with no tax adjustments. The 2020 federal tax return is currently in the IRS Compliance Assurance Program (the “CAP Program”) post-filing review process. We continue to voluntarily participate in the IRS CAP Program for the review of our 2021 tax year. Participation in the IRS CAP Program has enabled us to have minimal uncertain tax benefits associated with our federal tax return filings. The statutes of limitations for most of our state tax jurisdictions are open for tax years after 2016. +NOTE 16 - EARNINGS PER SHARE +Basic earnings per share is computed by dividing net earnings by the weighted average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested equity-based employee awards, convertible notes and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. +97 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents our weighted average basic and diluted shares outstanding for the periods presented: +Year Ended December 31, +2021 2020 2019 +(in thousands) +Weighted average common shares outstanding - basic 98,546 98,251 64,032 +Dilutive effect of: +RSUs and PSUs 1,596 — — +Other equity-based awards 12 — — +Weighted average common shares and equivalents outstanding - diluted 100,154 98,251 64,032 +We reported a net loss for the years ended December 31, 2020 and 2019. As a result, our basic and diluted weighted average common shares outstanding were the same for those periods because the effect of the common share equivalents was anti-dilutive. +The following table presents the weighted average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect for the periods presented: +Year Ended December 31, +2021 2020 2019 +(in thousands) +Weighted average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: +RSUs and PSUs 28 1,707 989 +Other equity-based awards 116 229 302 +Total anti-dilutive common share equivalents 144 1,936 1,291 +When outstanding, the 2021 Convertible Notes gave the holders, at our election, the right to convert the aggregate principal amount into 2.3 million shares of our common stock at a conversion price of $ 85.39 per share. The 2021 Convertible Notes were not included in the diluted earnings per share calculation using the treasury stock method for any periods presented as the average market price of our common stock did not exceed the conversion price. Further, the 2021 Convertible Notes were fully retired on the maturity date, September 15, 2021. +98 +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 17 - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION +Year Ended December 31, +2021 2020 2019 +(in thousands) +Supplemental cash flow information +Cash payments (receipts) for +Interest, net of capitalized interest $ 66,647 $ 75,506 $ 57,439 +Income taxes ( 1,057 ) 9 ( 1,167 ) +Non-cash investing and financing activities +Change in accounts payable related to capital expenditures 519 ( 28,676 ) ( 68,246 ) +Change in asset retirement obligations, with a corresponding change to crude oil and natural gas properties, net of disposals 11,673 54,984 29,533 +Issuance of common stock for acquisition of crude oil and natural gas properties, net — 1,009,015 — +Cash paid for amounts included in the measurement of lease liabilities +Operating cash flows from operating leases $ 7,603 $ 9,246 $ 5,301 +Operating cash flows from finance leases 117 156 253 +Right-of-use assets obtained in exchange for lease obligations +Operating leases $ 1,457 $ 4,305 $ 1,428 +Finance leases 2,109 703 2,323 +99 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +CRUDE OIL AND NATURAL GAS INFORMATION - UNAUDITED +Net Proved Reserves +All of our crude oil, natural gas and NGLs reserves are located in the United States. We utilize the services of independent petroleum engineers to estimate our crude oil, natural gas and NGLs reserves. As of December 31, 2021, 2020 and 2019 (as applicable), all of our estimates of proved reserves for the Wattenberg Field were based on reserve reports prepared by Ryder Scott and all of our estimates for proved reserves for the Delaware Basin were based on reserve reports prepared by NSAI. These reserve estimates have been prepared in compliance with guidelines established by the SEC and FASB. All of our proved undeveloped reserves conform to the SEC five-year rule requirement that they be scheduled to be drilled within five years of each location’s initial booking date. +Reserve estimates are based on an unweighted arithmetic average of commodity prices during the preceding 12-month period, using the closing prices on the first day of each month, as required by the SEC. The table below presents the index prices for our estimated reserves, by commodity, as of the dates indicated: +Average Benchmark Prices +December 31, +Crude Oil +(per Bbl) (1) +Natural Gas +(per MMBtu) (1) +NGLs +(per Bbl) (2) +2021 $ 66.56 $ 3.60 $ 66.56 +2020 39.57 1.99 39.57 +2019 55.69 2.58 55.69 +____________ +(1) Our benchmark indexes for crude oil and natural gas are WTI and Henry Hub, respectively. +(2) For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. +The netted back price used to estimate our reserves, by commodity, are presented below: +Price Used to Estimate Reserves (1) +December 31, Crude Oil +(per Bbl) Natural Gas +(per MMBtu) +NGLs +(per Bbl) +2021 $ 65.37 $ 2.85 $ 24.96 +2020 37.52 1.26 10.55 +2019 52.63 1.50 12.21 +____________ +(1) These prices are based on the index prices and are net of basin differentials, transportation fees, contractual adjustments and Btu adjustments we experienced for the respective commodity, including consideration for contracts that are effective as of December 31, 2021. +100 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +The following tables present the changes in our estimated quantities of proved reserves: +Crude Oil, Condensate (MBbls) Natural Gas +(MMcf) NGLs +(MBbls) Total +(MBoe) +Proved reserves, January 1, 2019 190,349 1,335,689 131,987 544,953 +Revisions of previous estimates 25,875 328,290 31,559 112,147 +Extensions, discoveries and other additions 1,056 10,262 1,519 4,285 +Acquisition of reserves 553 4,558 448 1,761 +Dispositions (1,412) (5,052) (614) (2,868) +Production (19,166) (115,950) (10,923) (49,414) +Proved reserves, December 31, 2019 197,255 1,557,797 153,976 610,864 +Revisions of previous estimates (41,089) (272,243) (14,774) (101,237) +Extensions, discoveries and other additions 812 2,991 324 1,635 +Acquisition of reserves 80,590 795,977 81,770 295,023 +Dispositions (2,116) (17,711) (1,776) (6,844) +Production (23,720) (165,637) (17,042) (68,368) +Proved reserves, December 31, 2020 211,732 1,901,174 202,478 731,073 +Revisions of previous estimates 22,651 408,540 54,634 145,375 +Extensions, discoveries and other additions 528 1,584 168 960 +Acquisition of reserves 1,616 24,174 2,469 8,113 +Dispositions — — — — +Production (22,682) (175,747) (19,360) (71,333) +Proved reserves, December 31, 2021 213,845 2,159,725 240,389 814,188 +Proved developed reserves, as of: +December 31, 2019 66,211 554,234 55,411 213,994 +December 31, 2020 86,330 860,877 91,702 321,512 +December 31, 2021 97,420 1,088,700 120,132 399,002 +Proved undeveloped reserves, as of: +December 31, 2019 131,044 1,003,563 98,565 396,870 +December 31, 2020 125,402 1,040,297 110,776 409,561 +December 31, 2021 116,425 1,071,025 120,257 415,186 +101 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Developed Undeveloped Total +(MBoe) +Proved reserves, January 1, 2019 179,535 365,418 544,953 +Revisions of previous estimates 27,452 84,695 112,147 +Extensions, discoveries and other additions 4,285 — 4,285 +Acquisition of reserves 441 1,320 1,761 +Dispositions (474) (2,394) (2,868) +Production (49,414) — (49,414) +Undeveloped reserves converted to developed 52,169 (52,169) — +Proved reserves, December 31, 2019 213,994 396,870 610,864 +Revisions of previous estimates (8,634) (92,603) (101,237) +Extensions, discoveries and other additions 1,635 — 1,635 +Acquisition of reserves 125,180 169,843 295,023 +Dispositions (2,487) (4,357) (6,844) +Production (68,368) — (68,368) +Undeveloped reserves converted to developed 60,192 (60,192) — +Proved reserves, December 31, 2020 321,512 409,561 731,073 +Revisions of previous estimates 75,005 70,370 145,375 +Extensions, discoveries and other additions 960 — 960 +Acquisition of reserves 519 7,594 8,113 +Dispositions — — — +Production (71,333) — (71,333) +Undeveloped reserves converted to developed 72,339 (72,339) — +Proved reserves, December 31, 2021 399,002 415,186 814,188 +2021 Activity. During 2021, we increased proved reserves by 83.1 MMBoe, or 11 percent, relative to December 31, 2020. The increase in proved reserves was primarily due to positive revisions resulting from our development activities and significant improvements in commodity prices during 2021, resulting in better economics. In 2021, we produced 71.3 MMBoe. +Revisions of Previous Estimates- Proved Developed Reserves. Proved developed reserves experienced a net positive revision of 75.0 MMBoe primarily due to (i) an increase of 44.3 MMBoe as a result of extended well lives directly correlated with the higher average prices for crude oil, natural gas and NGLs in 2021, (ii) a 24.9 MMBoe increase related to our operated and non-operated current year drilling activities not included within our five year development plan in the prior year, and (iii) an increase of 8.9 MMBoe related to performance revisions and other factors. The positive revisions were partially offset by a 3.1 MMBoe decrease associated with higher operating costs. +Revisions of Previous Estimates- PUDs. Net upward revisions to our previous PUD reserves estimates of 70.4 MMBoe were due to (i) a 166.5 MMBoe increase related to additional locations on proved acreage resulting from our 2021 development activities and changes to our drilling schedule resulting from state regulatory permitting process changes passed in 2021, (ii) a 8.6 MMBoe increase related to extended well lives directly correlated with the upward pricing adjustments due to improved average prices for crude oil, natural gas and NGLs in 2021, and (iii) 3.5 MMBoe related to performance revisions and other items. The positive revisions were partially offset by a 96.4 MMBoe downward revision primarily related to PUD locations that were reclassified to unproven reserves in our Wattenberg Field due to changes to our drilling schedule mainly resulting from state regulatory permitting process changes passed in 2021. Finally, a reduction of 11.8 MMBoe was recognized for locations no longer expected to be developed within five years of their initial recording in accordance with SEC rules. +Extensions, Discoveries and Other Additions- Proved Developed Reserves. Developed activity for 2021 included the addition of 1.0 MMBoe of developed reserves related to two gross newly turned-in-line wells in the Delaware Basin. +Acquisitions of Reserves- Proved Developed Reserves and PUDs. Proved developed and PUD reserves acquired primarily pertains to certain nonmonetary exchanges during 2021. +At December 31, 2020, we projected a PUD reserve conversion rate of 22 percent for 2021. During 2021, our actual conversion rate was 18 percent primarily due to a change in timing of completion activities in the Wattenberg Field. We converted 72.3 MMBoe of PUD reserves at December 31, 2020 to proved developed reserves as of December 31, 2021. +102 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Based on economic conditions on December 31, 2021, our approved development plan provides for the development of our remaining PUD locations within five years of the date such reserves were initially recorded. The level of capital spending necessary to execute our development plan is consistent with our recent performance and updated drilling program. +2020 Activity. During 2020, we increased proved reserves by 120.2 MMBoe, or 20 percent, relative to December 31, 2019. The increase in proved reserves was primarily a result of our of the SRC Acquisition, partially offset by downward revisions of previous estimates. In 2020, we produced 68.4 MMBoe. +Revisions of Previous Estimates- Proved Developed Reserves. Proved developed reserves experienced a negative revision of 8.6 MMBoe primarily due to a decrease of 28.2 MMBoe as a result of lower average prices for crude oil, natural gas and NGLs for 2020. The negative revisions were partially offset by a 14.3 MMBoe increase associated with lower operating costs and a 5.3 MMBoe increase related to performance revisions and other items. +Revisions of Previous Estimates- PUDs. Net downward revisions to our previous PUD reserves estimates of 92.6 MMBoe were due to (i) 266.7 MMBoe related to PUD locations that were reclassified to unproven reserves due to drilling schedule changes, (ii) a reduction of 25.5 MMBoe was recognized for locations no longer expected to be developed within five years of their initial recording in accordance with SEC rules, and (iii) 11.3 MMBoe related to downward pricing adjustments due to lower average prices for crude oil, natural gas and NGLs for 2020. Drilling schedule changes resulted from PUD downgrades associated with lower realized prices and revised drilling plans following the completion of the SRC Acquisition. The negative revisions were partially offset by a 199.9 MMBoe increase related to additional locations on proved acreage resulting from our drilling plan and 11.0 MMBoe related to performance revisions and other items. +Extensions, Discoveries and Other Additions- Proved Developed Reserves. Developed activity for 2020 included the addition of 1.6 MMBoe of developed reserves related to two gross newly-drilled wells in the Delaware Basin. +Extensions, Discoveries and Other Additions- PUDs. There were no extensions, discoveries or other additions for PUD reserves during 2020. +Acquisitions of Reserves- Proved Developed Reserves. Proved developed reserves acquired primarily pertain to the SRC Acquisition completed in January 2020. +Acquisitions of Reserves- PUDs. Proved undeveloped reserves acquired primarily pertain to the SRC Acquisition completed in January 2020. +Dispositions- Proved Developed Reserves . Dispositions of 2.5 MMBoe were related to a divestiture and acreage surrendered in various acreage exchanges. +Dispositions- PUDs. Dispositions of 4.4 MMBoe were related to a divestiture and acreage surrendered in various acreage exchanges. +2019 Activity. During 2019, we increased proved reserves by 65.9 MMBoe, or 12 percent, relative to December 31, 2018. The increase in proved reserves was primarily a result of acreage exchange transactions and acquisitions in the Wattenberg Field and reserve additions on proved acreage resulting from our 2019 development activities. In 2019, we produced 49.4 MMBoe. +Revisions of Previous Estimates- Proved Developed Reserves. Proved developed reserves experienced a positive revision of 28.3 MMBoe reflecting improved performance revisions, decreased operating costs and other items. An additional increase of 10.2 MMBoe in developed reserves related to our current year drilling activities. These positive revisions were partially offset by a decrease of 11.0 MMBoe for decreases in prices for crude oil, natural gas and NGLs. +Revisions of Previous Estimates- PUDs. Upward revisions to our PUD reserves were related to an increase of 74.2 MMBoe reflecting additional locations on proven acreage resulting from our drilling plan, as well as improved performance revisions and other items, which resulted in further upward revisions of 28.9 MMBoe of PUD reserves. Partially offsetting these increases were negative revisions of 12.9 MMBoe due to drilling schedule changes and 5.5 MMBoe for decreases in prices for crude oil, natural gas and NGLs. +103 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Extensions, Discoveries and Other Additions- Proved Developed Reserves. Developed additions for 2019 included the addition of 4.3 MMBoe of developed reserves related to three gross (three net) newly-drilled wells. +Extensions, Discoveries and Other Additions- PUDs . There were no extensions, discoveries or other additions for PUD reserves during 2019. +Acquisitions of Reserves- Proved Developed Reserves. Proved developed reserves acquired in various acreage exchanges and acquisitions were 0.4 MMBoe during 2019. +Acquisitions of Reserves- PUDs. We acquired 1.3 MMBoe of PUD reserves in 2019 in acreage exchanges and acquisitions. +Dispositions- Proved Developed Reserves . Dispositions of 0.5 MMBoe were related to a divestiture and acreage surrendered in various acreage exchanges. +Dispositions- PUDs. Dispositions of PUDs were 2.4 MMBoe were related to a divestiture and acreage surrendered in various acreage exchanges. +Results of Operations for Crude Oil and Natural Gas Producing Activities +The results of operations for crude oil and natural gas producing activities for the periods presented below: +Year Ended December 31, +2021 2020 2019 +(in thousands) +Revenues: +Crude oil, natural gas and NGLs sales $ 2,552,558 $ 1,152,555 $ 1,307,275 +Commodity price risk management gain (loss), net (701,456) 180,270 (162,844) +1,851,102 1,332,825 1,144,431 +Expenses: +Lease operating expenses 180,659 161,346 142,248 +Production taxes 165,209 59,368 80,754 +Transportation, gathering and processing expenses 100,403 77,835 46,353 +Exploration expense 1,064 1,376 4,054 +Depreciation, depletion and amortization 627,466 611,003 638,499 +Accretion of asset retirement obligations 12,086 10,072 6,117 +Impairment of properties and equipment 402 882,393 38,536 +(Gain) loss on sale of properties and equipment (912) (724) 9,734 +1,086,377 1,802,669 966,295 +Results of operations for crude oil and natural gas producing +activities before provision for income taxes 764,725 (469,844) 178,136 +Income tax (expense) benefit (37,013) 5,168 (9,869) +Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs $ 727,712 $ (464,676) $ 168,267 +Production costs include those costs incurred to operate and maintain productive wells and related equipment, including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, production and severance taxes and associated administrative expenses. DD&A expense includes those costs associated with capitalized acquisition, exploration and development costs, but does not include the depreciation applicable to support equipment. The provision for income taxes is computed using effective statutory tax rates. +104 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Costs Incurred in Crude Oil and Natural Gas Activities +Costs incurred in crude oil and natural gas property acquisition, exploration and development for the periods presented: +Year Ended December 31, +2021 2020 2019 +(in thousands) +Acquisition of properties: (1) +Proved properties $ 1 $ 1,618,000 $ 16,007 +Unproved properties 3,151 114,202 9,567 +Development costs (2) +583,488 528,686 780,851 +Exploration costs: (3) +Exploratory drilling 6,902 12,892 32,218 +Geological and geophysical 64 253 3,017 +Total costs incurred $ 593,606 $ 2,274,033 $ 841,660 +____________ +(1) Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property. +(2) Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells and provide facilities to extract, treat, gather and store crude oil, natural gas and NGLs. Of these costs incurred for the years ended December 31, 2021, 2020 and 2019, $227.8 million, $270.7 million and $308.9 million, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. These costs also include $35.3 million of infrastructure and pipeline costs in 2019. Our infrastructure and pipeline assets were divested in 2019. +(3) Exploration costs represent costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas and NGLs. These costs include, but are not limited to, dry hole contributions and costs of drilling and equipping exploratory wells. +Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities +Aggregate capitalized costs related to crude oil and natural gas exploration and production activities with applicable accumulated DD&A are presented below as of the dates indicated: +December 31, +2021 2020 +(in thousands) +Proved crude oil and natural gas properties $ 8,310,018 $ 7,523,639 +Unproved crude oil and natural gas properties 306,181 350,677 +Uncompleted wells, equipment and facilities 371,360 523,376 +Capitalized costs 8,987,559 8,397,692 +Accumulated DD&A (4,218,330) (3,590,932) +Capitalized costs, net $ 4,769,229 $ 4,806,760 +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves +The standardized measure below has been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to our year-end estimated proved reserves. Prices for each of the three years were adjusted by field for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of our commodity derivatives. Production and development costs were based on prices as of December 31 for each of the respective years presented. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service or to depreciation, depletion and amortization expense. Production and development costs include those cash flows associated with the expected ultimate settlement of our asset retirement obligations. Future estimated income tax expense is computed by applying the statutory rate in effect at the end of each year to the projected future pre-tax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits and allowances related to the properties. +105 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves as of the dates indicated. Changes in the demand for crude oil, natural gas and NGLs, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves. +December 31, +2021 2020 2019 +(in thousands) +Future estimated cash flows $ 26,143,031 $ 12,481,830 $ 14,590,604 +Future estimated production costs (1) +(6,325,129) (4,209,459) (4,530,173) +Future estimated development costs (2,857,951) (2,337,806) (3,257,106) +Future estimated income tax expense (3,088,187) (301,507) (907,382) +Future net cash flows 13,871,764 5,633,058 5,895,943 +10% annual discount for estimated timing of cash flows (5,963,592) (2,350,879) (2,585,609) +Standardized measure of discounted future estimated net cash flows $ 7,908,172 $ 3,282,179 $ 3,310,334 +____________ +(1) Represents future estimated lease operating expenses, production taxes and transportation, gathering and processing expenses. +The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows for the periods presented: +Year Ended December 31, +2021 2020 2019 +(in thousands) +Beginning of period $ 3,282,179 $ 3,310,334 $ 4,447,716 +Sales of crude oil, natural gas and NGLs production, net of production costs (2,106,287) (854,006) (1,037,920) +Net changes in prices and production costs (1) +5,312,870 (1,771,019) (2,122,538) +Extensions, discoveries and improved recovery, less related costs 20,201 14,110 39,606 +Sales of reserves — (26,771) (14,533) +Purchases of reserves 76,440 1,969,846 18,816 +Development costs incurred during the period 338,098 329,495 605,753 +Revisions of previous quantity estimates 2,645,379 (775,009) 538,242 +Changes in estimated income taxes (1,628,304) 354,369 346,826 +Net changes in future development costs (168,332) 367,630 206,003 +Accretion of discount 345,454 572,483 532,127 +Timing and other (209,526) (209,283) (249,764) +End of period $ 7,908,172 $ 3,282,179 $ 3,310,334 +____________ +(1) Our weighted average price, net of production costs per Boe, in our 2021 reserve report increased to $24.34 as compared to $11.32 for 2020 and $16.18 for 2019. +The data presented should not be viewed as representing the expected cash flows from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the recent average prices and current costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein. +106 +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +FINANCIAL STATEMENT SCHEDULE +Schedule II -VALUATION AND QUALIFYING ACCOUNTS +Description Beginning +Balance +January 1, Charged to +Costs and +Expenses +Deductions (1) +Ending +Balance +December 31, +(in thousands) +2021: +Allowance for doubtful accounts $ 6,763 $ (359) $ (349) $ 6,055 +Allowance for expirations of unproved crude oil and natural gas properties 224,019 — (17,691) 206,328 +2020: +Allowance for doubtful accounts $ 7,476 $ 3,179 $ (3,892) $ 6,763 +Allowance for expirations of unproved crude oil and natural gas properties 6,881 223,895 (6,757) 224,019 +2019: +Allowance for doubtful accounts $ 4,381 $ 3,209 $ (114) $ 7,476 +Allowance for expirations of unproved crude oil and natural gas properties 542,709 8,523 (544,351) 6,881 +____________ +(1) For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For allowance for expirations of unproved crude oil and natural gas properties, deductions represent actual expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset. +107 +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +As of December 31, 2021, we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Based on the results of this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2021. +Management’s Report on Internal Control over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Internal control over financial reporting is a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer, or persons performing similar functions, and effected by our board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate. +Management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2021, based upon the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on this evaluation, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2021. +The effectiveness of our internal control over financial reporting as of December 31, 2021 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears under Item 8. +Changes in Internal Control over Financial Reporting +There were no changes in our internal control over financial reporting during the quarter ended December 31, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. +ITEM 9B. OTHER INFORMATION +None. +ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS +Not applicable. +108 +PART III +ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2022 Annual Stockholders’ meeting and is incorporated by reference in this report. +ITEM 11. EXECUTIVE COMPENSATION +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2022 Annual Stockholders’ meeting and is incorporated by reference in this report. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2022 Annual Stockholders’ meeting and is incorporated by reference in this report. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2022 Annual Stockholders’ meeting and is incorporated by reference in this report. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2022 Annual Stockholders’ meeting and is incorporated by reference in this report. +PART IV +ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES +(a) (1) Exhibits: +See Exhibits Index on the following page. +ITEM 16. FORM 10-K SUMMARY +None. +Exhibits Index +Incorporated by Reference +Exhibit Number Exhibit Description Form SEC File Number Exhibit Filing Date Filed Herewith +2.1 +Plan of Conversion, dated June 5, 2015, by PDC Energy, Inc. +8-K12B 001-37419 2.1 6/8/2015 +2.2 +Agreement and Plan of Merger, dated as of August 25, 2019 by and between PDC Energy, Inc., and SRC Energy Inc. +8-K 001-37419 2.1 8/26/2019 +2.3 +Membership Interest Purchase Agreement, dated as of February 26, 2022, by and among PDC Energy, Inc., Great Western Petroleum, LLC, and the members of Great Western Petroleum, LLC. +8-K 001-37419 2.1 2/28/2022 +3.1 +Certificate of Incorporation of PDC Energy, Inc., as amended. +8-K12B 001-37419 3.1 5/27/2020 +3.2 +Bylaws of PDC Energy, Inc. +8-K12B 001-37419 3.2 6/8/2015 +4.1 +Description of Capital Stock +X +109 +Incorporated by Reference +Exhibit Number Exhibit Description Form SEC File Number Exhibit Filing Date Filed Herewith +4.2 +Form of Common Stock Certificate of PDC Energy, Inc. +10-K 001-37419 4.1.1 2/26/2020 +4.3 +Base Indenture, dated as of September 14, 2016, by and between PDC Energy, Inc. and U.S. Bank Trust National Association, as Trustee. +8-K 001-37419 4.1 9/14/2016 +4.4 +Indenture, dated as of September 15, 2016, by and between PDC Energy, Inc. and U.S. Bank Trust National Association, as Trustee, relating to the 6.125% Senior Notes due 2024. +8-K 001-37419 4.1 9/15/2016 +10.1 +Form of Indemnification Agreement. +8-K 000-07246 10.1 6/8/2015 +10.2 +Amended and Restated 2010 Long-Term Equity Compensation Plan, as amended. +10-K 001-37419 10.5 2/22/2016 +10.3 +Executive Severance Compensation Plan, as amended and restated. +10-Q 001-37419 10.1 8/6/2020 +10.4 +Form of 2013 Restricted Stock/Stock Appreciation Rights Agreement. +10-K 000-07246 10.10 2/27/2013 +10.5 +Form of 2014 Restricted Stock/Stock Appreciation Rights Agreement. +10-K 000-07246 10.5.5 2/19/2015 +10.6 +Form of 2015 Stock Appreciation Rights Agreement. +10-K 000-07246 10.5.8 2/19/2015 +10.7 +Form of 2019 Performance Share Agreement. +10-Q 001-37419 99.1 5/2/2019 +10.8 +Form of 2019 Restricted Stock Unit Agreement (Executives) (Amended and Restated 2010 Long-Term Equity Compensation Plan). +10-Q 001-37419 99.3 5/2/2019 +10.9 +Form of 2019 Restricted Stock Unit Agreement (Executives) (2018 Equity Incentive Plan). +10-Q 001-37419 99.4 5/2/2019 +10.10 +SRC Energy, Inc./PDC Energy, Inc. Merger Performance Share Agreement, dated January 13, 2020, by and between PDC Energy, Inc.(as successor to SRC Energy, Inc.) and Lynn A. Peterson. +8-K 001-37419 10.2 1/14/2020 +10.11 +Form of 2020 Performance Share Agreement. +10-Q 001-37419 99.1 5/7/2020 +10.12 +Form of 2020 Restricted Stock Unit Agreement (Executives). +10-Q 001-37419 99.3 5/7/2020 +10.13 +Form of 2021 Performance Share Agreement. +10-Q 001-37419 99.1 5/6/2021 +10.14 +Form of 2021 Restricted Stock Unit Agreement (Directors). +10-Q 001-37419 99.2 5/6/2021 +10.15 +Form of 2021 Restricted Stock Unit Agreement (Executives). +10-Q 001-37419 99.3 5/6/2021 +10.16 +Employment Agreement with Lance A. Lauck, as amended. +10-Q 001-37419 10.2 8/6/2020 +10.17 +2018 Equity Incentive Plan. +8-K 001-37419 10.1 5/31/2018 +10.18 +Amendment No. 1 to PDC Energy, Inc. 2018 Equity Incentive Plan. +8-K 001-37419 +10.1 5/27/2020 +10.19 +SRC Energy Inc. 2015 Equity Incentive Plan. +8-K 001-37419 10.1 1/14/2020 +10.20 +Fifth Amended and Restated Credit Agreement, dated as of November 2, 2021 among PDC Energy, Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent and The Lenders Party Hereto +10-Q 001-37419 10.1 11/3/2021 +21.1 +Subsidiaries. +10-K 001-37419 21.1 2/26/2020 +23.1 +Consent of PricewaterhouseCoopers LLP. +X +23.2 +Consent of Ryder Scott Company, L.P., Petroleum Consultants. +X +110 +Incorporated by Reference +Exhibit Number Exhibit Description Form SEC File Number Exhibit Filing Date Filed Herewith +23.3 +Consent of Netherland, Sewell & Associates, Inc., Petroleum Consultants. +X +31.1 +Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +31.2 +Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +32.1* +Certifications by Chief Executive Officer and Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. +99.1 +Report of Independent Petroleum Consultants - Ryder Scott Company, L.P. +X +99.2 +Report of Independent Petroleum Consultants - Netherland, Sewell & Associates, Inc. +X +101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document X +101.SCH XBRL Taxonomy Extension Schema Document X +101.CAL XBRL Taxonomy Extension Calculation Linkbase Document X +101.DEF XBRL Taxonomy Extension Definition Linkbase Document X +101.LAB XBRL Taxonomy Extension Label Linkbase Document X +101.PRE XBRL Taxonomy Extension Presentation Linkbase Document X +104 Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101) X +* Furnished herewith. +111 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +PDC ENERGY, INC. +By: /s/ Barton Brookman +Barton Brookman +President and Chief Executive Officer +February 28, 2022 +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated: +Signature Title Date +/s/ Barton Brookman President, Chief Executive Officer and Director February 28, 2022 +Barton Brookman (principal executive officer) +/s/ R. Scott Meyers Senior Vice President and Chief Financial Officer February 28, 2022 +R. Scott Meyers (principal financial officer) +/s/ Douglas Griggs Chief Accounting Officer February 28, 2022 +Douglas Griggs (principal accounting officer) +/s/ Mark E. Ellis Non-Executive Chairman of the Board of Directors February 28, 2022 +Mark E. Ellis +/s/ Pamela R. Butcher Director February 28, 2022 +Pamela R. Butcher +/s/ Paul J. Korus Director February 28, 2022 +Paul J. Korus +/s/ David C. Parke Director February 28, 2022 +David C. Parke +/s/ Lynn A. Peterson Director February 28, 2022 +Lynn A. Peterson +/s/ Carlos A. Sabater Director February 28, 2022 +Carlos A. Sabater +/s/ Diana L. Sands Director February 28, 2022 +Diana L. Sands +112 +GLOSSARY OF UNITS OF MEASUREMENT AND INDUSTRY TERMS +UNITS OF MEASUREMENT +The following presents a list of units of measurement used throughout the document. +Bbl – One barrel of crude oil or NGL or 42 gallons of liquid volume. +Bcf – One billion cubic feet of natural gas volume. +Boe – One barrel of crude oil equivalent. +Btu – British thermal unit. +BBtu – One billion British thermal units. +MBoe – One thousand barrels of crude oil equivalent. +MBbls – One thousand barrels of crude oil. +Mcf – One thousand cubic feet of natural gas volume. +MMBoe – One million barrels of crude oil equivalent. +MMBbls – One million barrels of crude oil. +MMBtu – One million British thermal units. +MMcf – One million cubic feet of natural gas volume. +MMcfd – One million cubic feet of natural gas volume per day. +GLOSSARY OF INDUSTRY TERMS +The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report: +Brent - Brent sweet light crude oil. +CIG - Colorado Interstate Gas. +Completion - Refers to the installation of permanent equipment for the production of crude oil and natural gas from a recently drilled well or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned. +Condensate - Liquid hydrocarbons associated with the production that is primarily natural gas. +Developed acreage - Acreage assignable to productive wells. +Development well - A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. +Differentials - The difference between the crude oil and natural gas index spot price and the corresponding cash spot price in a specified location. +Dry well or dry hole - A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well. +Exploratory well - A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. +Extensions, discoveries and other additions - As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates. +Fracture or Fracturing - Procedure to stimulate production by forcing a mixture of fluid and proppant into the formation under high pressure. Fracturing creates artificial fractures in the reservoir rock to increase permeability and porosity, thereby allowing the release of trapped hydrocarbons. +Gross acres or wells - Refers to the total acres or wells in which we have a working interest. +113 +Henry Hub - Refers to the pricing point for natural gas futures contracts traded on NYMEX. +Horizontal drilling - A drilling technique that permits the operator to drill a horizontal well shaft from the bottom of a vertical well and thereby to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons. +Intensity - Greenhouse gas and methane intensity is reported as total metric tons of methane emissions divided by gross annual production in MBOE. +Joint interest billing - Process of billing/invoicing the costs related to well drilling, completions and production operations among working interest partners. +Natural gas liquid(s) or NGL(s) - Hydrocarbons which can be extracted from natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs include ethane, propane, butane and other natural gasolines. +Net acres or wells - Refers to gross acres or wells we own multiplied, in each case, by our percentage working interest. +Net production - Crude oil and natural gas production that we own, less royalties and production due to others. +Non-operated - A project in which we are not the operator. +NYMEX - New York Mercantile Exchange. +Operator - The individual or company responsible for the exploration, development and/or production of an oil or gas well or lease. +Overriding royalty - An interest which is created out of the operating or working interest. Its term is coextensive with that of the operating interest. +Possible reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability to exceed the sum of proved, probable and possible reserves. When probabilistic methods are used, there must be at least a 10 percent probability that the actual quantities recovered will equal or exceed the sum of proved, probable and possible estimates. +Present value of future net revenues or (PV-10) - The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, of proved reserves calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using pricing and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization and discounted using an annual discount rate of 10 percent. PV-10 is pre-tax and therefore a non-U.S. GAAP financial measure. +Probable reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Similarly, when probabilistic methods are used, there must be at least a 50 percent probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. +Productive well - An exploratory or developmental well that is not a dry well or dry hole, as defined above. +Proved developed non-producing reserves - Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and/or (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells. +114 +Proved developed producing reserves or PDPs - Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods. +Proved developed reserves - The combination of proved developed producing and proved developed non-producing reserves. +Proved reserves - This term means “proved oil and gas reserves” as defined in SEC Regulation S-X Section 4-10(a) and refers to those quantities of crude oil and condensate, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing conditions, operating methods and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +Proved undeveloped reserves or PUDs - Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. +Recomplete or Recompletion - The modification of an existing well for the purpose of producing crude oil and natural gas from a different producing formation. +Reserves - Estimated remaining quantities of crude oil, natural gas, NGLs and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering crude oil, natural gas and NGLs or related substances to market, and all permits and financing required to implement the project. +Royalty - An interest in a crude oil and natural gas lease or mineral interest that gives the owner of the royalty the right to receive a portion of the production from the leased acreage or mineral interest (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +Spud - To begin drilling; the act of beginning a hole. +Standardized measure of discounted future net cash flows or standardized measure - Future net cash flows discounted at a rate of 10 percent. Future net cash flows represent the estimated future revenues to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment and (ii) future income tax expense. +Stratigraphic test well - A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. +Undeveloped acreage - Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas, regardless of whether such acreage contains proved reserves. +Waha - Waha West Texas natural gas prices +Working interest - An interest in a crude oil and natural gas lease that gives the owner of the interest the right to drill and produce crude oil and natural gas on the leased acreage. It requires the owner to pay its share of the costs of drilling and production operations. +Workover - Major remedial operations on a producing well to restore, maintain, or improve the well’s production. +115 \ No newline at end of file diff --git a/raw/filings/0000077877/2021/0000077877-22-000019/filing_metadata.csv b/raw/filings/0000077877/2021/0000077877-22-000019/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..d008ccc1fe0c942ecaa4a526a259e1baf315eb2b --- /dev/null +++ b/raw/filings/0000077877/2021/0000077877-22-000019/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000077877,PDCE,"PDC ENERGY, INC.",10-K,2022-02-28,2021-12-31,2022-02-28T13:11:44.000Z,0000077877-22-000019,pdce-20211231.htm,10-K,14341824,1,1,https://www.sec.gov/Archives/edgar/data/77877/000007787722000019/pdce-20211231.htm,https://www.sec.gov/Archives/edgar/data/77877/000007787722000019/,2021,2021,1 diff --git a/raw/filings/0000077877/2021/0000077877-22-000019/item1.txt b/raw/filings/0000077877/2021/0000077877-22-000019/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2021/0000077877-22-000019/item13.txt b/raw/filings/0000077877/2021/0000077877-22-000019/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..d6785aae93be93a9449574780c22a1e915ec813c --- /dev/null +++ b/raw/filings/0000077877/2021/0000077877-22-000019/item13.txt @@ -0,0 +1,2 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2022 Annual Stockholders’ meeting and is incorporated by reference in this report. \ No newline at end of file diff --git a/raw/filings/0000077877/2021/0000077877-22-000019/item9a.txt b/raw/filings/0000077877/2021/0000077877-22-000019/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..b4869fafafb7cc504bded34e692333d471d40f6b --- /dev/null +++ b/raw/filings/0000077877/2021/0000077877-22-000019/item9a.txt @@ -0,0 +1,10 @@ +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +As of December 31, 2021, we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Based on the results of this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2021. +Management’s Report on Internal Control over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Internal control over financial reporting is a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer, or persons performing similar functions, and effected by our board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate. +Management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2021, based upon the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on this evaluation, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2021. +The effectiveness of our internal control over financial reporting as of December 31, 2021 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears under Item 8. +Changes in Internal Control over Financial Reporting +There were no changes in our internal control over financial reporting during the quarter ended December 31, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. \ No newline at end of file diff --git a/raw/filings/0000077877/2021/0000077877-22-000019/rp_note.txt b/raw/filings/0000077877/2021/0000077877-22-000019/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2021/0000077877-22-000019/rpt_disclosure.txt b/raw/filings/0000077877/2021/0000077877-22-000019/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..d95674288f5e8b8f8218b40467858b2ca9c4818d --- /dev/null +++ b/raw/filings/0000077877/2021/0000077877-22-000019/rpt_disclosure.txt @@ -0,0 +1,2 @@ +TRANSACTIONS WITH RELATED PARTIES +During 2022, there was no transaction or series of transactions, nor is there any currently proposed transaction, involving an amount exceeding $120,000 in which the Company is or was a participant and in which any Director, executive officer, known holder of more than 5% of the Company’s voting securities, or any member of the immediate family of any of the foregoing persons, had or has a direct or indirect material interest for which disclosure is required under Item 404 of Regulation S-K. \ No newline at end of file diff --git a/raw/filings/0000077877/2022/0000077877-23-000012/filing.txt 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0000077877 pdce:SRCNOLMember 2022-12-31 0000077877 pdce:StateNolCarryforwardsMember 2022-12-31 0000077877 pdce:StateCreditCarryforwardsMember pdce:A2022Member 2022-12-31 0000077877 us-gaap:StockOptionMember 2022-01-01 2022-12-31 0000077877 us-gaap:StockOptionMember 2021-01-01 2021-12-31 0000077877 us-gaap:StockOptionMember 2020-01-01 2020-12-31 +Table of cont ents +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31 , 2022 +or +☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from __________ to _________ +Commission File Number 001-37419 +PDC ENERGY, INC. +(Exact name of registrant as specified in its charter) +Delaware 95-2636730 +(State of incorporation) (I.R.S. Employer Identification No.) +1775 Sherman Street, Suite 3000 +Denver , Colorado 80203 +(Address of principal executive offices) (Zip code) +Registrant’s telephone number, including area code: ( 303 ) 860-5800 +Securities registered pursuant to Section 12(b) of the Act: +Title of each class Ticker Symbol Name of each exchange on which registered +Common Stock, par value $0.01 per share PDCE NASDAQ Global Select Market +Securities registered pursuant to Section 12(g) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes T No £ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes £ No T +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes T No £ +Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes T No £ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. +Large accelerated filer ☒ Accelerated filer ☐ +Non-accelerated filer ☐ Smaller reporting company ☐ +Emerging growth company ☐ +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. £ +Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No T +The aggregate market value of our common stock held by non-affiliates on June 30, 2022 was $ 5.9 billion (based on the closing price of $61.61 per share as of the last business day of the fiscal quarter ending June 30, 2022 ). +As of February 14, 2023 , there were 88,389,372 shares of our common stock outstanding. +DOCUMENTS INCORPORATED BY REFERENCE +We hereby incorporate by reference into this document the information required by Part III of this Form, which will appear in our definitive proxy statement filed pursuant to Regulation 14A for our 2023 Annual Meeting of Stockholders. +Table of cont ents +PDC ENERGY, INC. +2022 ANNUAL REPORT ON FORM 10-K +TABLE OF CONTENTS +PART I Page +Items 1. and 2. +Business and Properties +3 +Item 1A. +Risk Factors +20 +Item 1B. +Unresolved Staff Comments +33 +Item 3. +Legal Proceedings +33 +Item 4. +Mine Safety Disclosures +34 +PART II +Item 5. +Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +35 +Item 6. +[Reserved] +37 +Item 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +37 +Item 7A. +Quantitative and Qualitative Disclosures About Market Risk +58 +Item 8. +Financial Statements and Supplementary Data +60 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +101 +Item 9A. +Controls and Procedures +101 +Item 9B. +Other Information +101 +Item 9C. +Disclosure Regarding Foreign Jurisdictions that Prevent Inspections +101 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +102 +Item 11. +Executive Compensation +102 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +102 +Item 13. +Certain Relationships and Related Transactions and Director Independence +102 +Item 14. +Principal Accounting Fees and Services +102 +PART IV +Item15. +Exhibits, Financial Statement Schedules +102 +Item 16. +Form 10-K Summary +102 +Signatures +105 +Glossary of Units of Measurements and Industry Terms +106 +Table of cont ents +PART I +REFERENCES TO THE REGISTRANT +Unless the context otherwise requires, references in this report to “PDC Energy”, “PDC”, the “Company”, “we”, “us”, “our” or “ours” refer to the registrant, PDC Energy, Inc. and our wholly-owned subsidiaries consolidated for the purposes of our financial statements. +GLOSSARY OF UNITS OF MEASUREMENTS AND INDUSTRY TERMS +Units of measurements and industry terms are defined in the Glossary of Units of Measurements and Industry Terms, included at the end of this report. +SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS +This Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 (“Securities Act”) and Section 21E of the Securities Exchange Act of 1934 (“Exchange Act”) and the United States (“U.S.”) Private Securities Litigation Reform Act of 1995 regarding our business, financial condition, results of operations and prospects. All statements other than statements of historical fact included in and incorporated by reference into this report are “forward-looking statements”. Words such as expect, anticipate, intend, plan, believe, seek, estimate, schedule and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements include, among other things, statements regarding future: production, costs and cash flows; drilling locations, zones and growth opportunities; impacts of Colorado political matters, including initiatives influencing our ability to continue to obtain permits and the timing of such receipt; commodity prices and differentials; capital expenditures and projects, including the number of rigs employed; cash flows from operations relative to future capital investments; financial ratios and compliance with covenants in our revolving credit facility and other debt instruments; adequacy of midstream infrastructure; the potential return of capital to shareholders through buyback of shares and/or payments of dividends; expected impact from emission reduction initiatives; risk of our counterparties non-performance on derivative instruments; and our ability to fund planned activities. +The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this report reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this report or accompanying materials, we may use the term “projection” or similar terms or expressions, or indicate that we have “modeled” certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or our industry in periods beyond the current fiscal year. Because such statements relate to events or conditions further in the future, they are subject to increased levels of uncertainty. +Important factors that could cause actual results to differ materially from the forward-looking statements include, but are not limited to: +• market and commodity price volatility, widening price differentials and related impacts to the Company, including decreased revenue, income and cash flow, write-downs and impairments and decreased availability of capital; +• difficulties in integrating our operations as a result of any significant acquisitions, including the recent acquisition of Great Western Petroleum, LLC (“Great Western”), or acreage exchanges; +• adverse changes to our future cash flows, liquidity and financial condition; +• changes in, and interpretations and enforcement of, environmental and other laws and other political and regulatory developments, including in particular additional permit scrutiny in Colorado; +• the impact of public health crises, including the coronavirus 2019 (“COVID-19”) pandemic, its effects on commodity prices, downstream capacity, employee health and safety, business continuity and regulatory matters; +• declines in the value of our crude oil, natural gas and natural gas liquids (“NGLs”) properties resulting in impairments; +• changes in, and inaccuracy of, reserve estimates and expected production and decline rates; +• timing and extent of our success in discovering, acquiring, developing and producing reserves; +• reductions in the borrowing base under our revolving credit facility; +1 +Table of cont ents +• availability and cost of capital; +• risks inherent in the drilling and operation of crude oil and natural gas wells; +• ability to add to our gross operated inventory through wellbore spacing and untested zones; +• timing and cost of wells and facilities; +• availability, cost, and timing of sufficient pipeline, gathering and transportation facilities and related infrastructure; +• limitations in the availability of supplies, materials, contractors and services that may delay the drilling or completion of our wells; +• potential losses of acreage or other impacts due to lease expirations, other title defects, or otherwise; +• risks inherent in marketing our crude oil, natural gas and NGLs; +• effect of crude oil and natural gas derivative activities; +• impact of environmental events, governmental and other third-party responses to such events and our ability to insure adequately against such events; +• cost of pending or future litigation; +• impact to our operations, personnel retention, strategy, stock price and expenses caused by the actions of activist shareholders; +• uncertainties associated with future dividends to our shareholders or share buybacks; +• timing and amounts for cash federal and state income taxes; +• our ability to retain or attract senior management and key technical employees; +• an unanticipated assumption of liabilities or other problems with business acquisitions; +• cybersecurity disruptions to our operations from breaches of our information technology systems, or from breaches of third party systems; +• physical, financial and transition risks relating to climate change; +• changes in general economic, business or industry conditions, including changes in interest rates and inflation rates and concerns regarding national or global recessionary conditions; +• our ability to achieve our emissions reductions, flaring and other environmental, social and governance goals; +• the impact of the loss of a single customer or any purchaser of our products; and +• success of strategic plans, expectations and objectives for our future operations. +Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under Item 1A, Risk Factors , made in this report and our other filings with the U.S. Securities and Exchange Commission (“SEC”) for further information on risks and uncertainties that could affect our business, financial condition, results of operations and prospects, which are incorporated by this reference as though fully set forth herein. We caution you not to place undue reliance on the forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this report or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement. +2 +Table of cont ents +ITEMS 1. AND 2. BUSINESS AND PROPERTIES +The Company +We are a domestic independent exploration and production company that acquires, explores and develops properties for the production of crude oil, natural gas and NGLs, with operations in the Wattenberg Field in Colorado and the Delaware Basin in west Texas. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are primarily focused in the horizontal Wolfcamp zones. +The following map presents the general locations of our development and production activities as of December 31, 2022: +3 +Table of cont ents +The following table presents selected information regarding our business and results of operations as of and for the periods presented: +Year Ended/As of +December 31, Percent Change +2022 2021 2022-2021 +(production and reserves in MMBoe, dollars in millions) +Wells: +Gross productive wells 4,098 3,471 18 % +Net productive wells 3,152 2,675 18 % +Horizontal percentage 74 % 66 % 12 % +Gross operated wells turned-in-line 183 167 10 % +Net operated wells turned-in-line 169 160 6 % +Production: +Wattenberg Field 74.0 61.9 20 % +Delaware Basin 11.0 9.4 17 % +Total 85.0 71.3 19 % +Reserves: +Proved reserves 1,100 814 35 % +Proved developed reserves percentage 47 % 49 % (4) % +Standardized measure $ 14,987 $ 7,908 90 % +PV-10 (1) +$ 19,053 $ 9,709 96 % +Available liquidity (2) +1,116 1,514 (26) % +Leverage ratio 0.5 0.6 (17) % +_____________ +(1) PV-10 is a non-U.S. GAAP financial measure. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in accordance with U.S. generally accepted accounting principles (“U.S. GAAP”), but rather should be considered in addition to the standardized measure. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10 and a reconciliation of our PV-10 value to the standardized measure included elsewhere in this report. +(2) Calculated as cash and cash equivalents plus availability under our credit facility, net of outstanding letters of credit, as of December 31. +Major Developments in 2022 +Great Western Acquisition. On May 6, 2022, we completed the acquisition of Great Western for approximately $1.4 billion, inclusive of Great Western’s net debt (the “Great Western Acquisition”). Great Western is an independent oil and gas company focused on the exploration, production and development of crude oil and natural gas in Colorado. The consideration paid was $542.5 million in cash and approximately 4.0 million shares of our common stock, valued at $293.3 million on the acquisition date, and payments totaling $597.0 million for termination of Great Western’s debt. As a result of the Great Western Acquisition, we acquired approximately 54,000 net acres in the core Wattenberg Field and production of approximately 50,000 Boe per day. We financed the cash portion of the purchase price of Great Western Acquisition and the settlement of Great Western’s debt through borrowings under our credit facility. We repaid the majority of our borrowings under our credit facility resulting from the Great Western Acquisition through cash flows from operating activities generated during 2022. As of December 31, 2022, we have a remaining balance on our credit facility of $370 million. +Capital Returns. In February 2022, our board of directors approved a new stock repurchase program that reset the total repurchase value to $1.25 billion and an increase in our quarterly base dividend from $0.12 per share to $0.25 per share. After the completion of Great Western Acquisition, in May 2022, our board of directors approved an additional increase in our quarterly base dividend from $0.25 per share to $0.35 per share. We also repurchased 12 million shares, or about 12 percent of our weighted average common stock outstanding, in 2022. Overall in 2022, we returned over 68 percent of our post base dividend adjusted free cash flows, a non-U.S. GAAP financial measure, through a combination of stock repurchases and quarterly and special dividends to shareholders. +4 +Table of cont ents +Successful Approvals and Significant Progress of Wattenberg Permits. In June 2022, the Colorado Oil and Gas Conservation Commission (“COGCC”) granted PDC unanimous approval for a 69-well Oil and Gas Development Plan (“OGDP”) and a 30-well OGDP, our second and third approvals under the new permitting process. Additionally, in December 2022, the COGCC unanimously approved our first Comprehensive Area Plan (“CAP”), filed in December 2021, which encompasses approximately 450 wells in Weld County, Colorado. Following the approval of the CAP, we will submit individual OGDP packages for each of the locations within the CAP. The CAP, along with our prior OGDPs, represent the majority of our projected Wattenberg Field turn-in-line activity into 2028 based on our current pace and drilling plan in 2023. +Meaningful Milestone in Environment, Social and Governance (“ESG”). In May 2022, our board of directors approved quantitative metrics for greenhouse gas (“GHG”) intensity and methane emissions reductions for our 2022 short-term incentive program, including 15% GHG and 30% methane emissions reduction targets from 2021 to 2022. In total, over 25% of our short-term incentive program is tied to ESG, environmental, health and safety initiatives. Further, in September 2022, we issued our first climate-related annual sustainability report aligned with the Taskforce on Climate-Related Financial Disclosures (“TCFD”). +Our Business Strategies +Our long-term business strategy focuses on creating shareholder value by: +• Delivering attractive returns from our crude oil and natural gas properties with a keen focus on environmentally responsible and sustainable operations; +• Maintaining financial strength; +• Generating sustainable adjusted free cash flows, a non-U.S. GAAP financial measure; +• Returning capital to shareholders; and +• Driving continued improvement in our health, safety, and ESG programs. +Our Competitive Strengths +The following key attributes create long-term shareholder value: +• Strong financial position and sustainable capital return program. We are focused on generating multi-year sustainable cash flows from operations in excess of our capital investments and maintaining a disciplined financial strategy that focuses on strong liquidity, a low leverage ratio and an active commodity derivative program to help mitigate a portion of the risk associated with commodity price fluctuations. We are committed to returning capital to our shareholders in a variety of commodity price environments. We are dedicated to a premier return of capital program with a quarterly base dividend and a return of approximately 60 percent or more of our post base dividend adjusted free cash flows, a non-U.S. GAAP financial measure, through stock repurchases and special dividends, as needed. +• Project inventory in premier crude oil, natural gas and NGL plays. We have a substantial multi-year inventory of high-quality horizontal drilling opportunities across two premier U.S. onshore basins: the Wattenberg Field in northeast Colorado and the Delaware Basin in Reeves County, Texas. Our portfolio has a proven record of delivering strong and repeatable economic returns and provides us the ability to allocate capital investments and manage risk as each basin has its own operating and competitive dynamic in terms of commodity price markets, service costs, takeaway capacity and regulatory and political considerations. +• Efficiency through technology and synergies from trades and accretive acquisitions. Technological innovation has led to continued improvement in our drilling and completion times and is helping us achieve our emission reduction goals. We are continuously investing in new technology to improve the efficiency and reduce the cost of our horizontal drilling and completion operations. Acreage consolidation made through trades or acquisitions in our operating areas +5 +Table of cont ents +increases our ability to drill longer length lateral wells which allows us to develop our properties with a smaller number of wells. +• Committed to meaningful and measurable ESG strategy. We are committed to being a cleaner, safer and more socially responsible company. +• Environment. We are committed to and are making meaningful progress on the following goals: +◦ Reduce GHG intensity by 60% from 2020 levels by 2025 and 74% by 2030 +◦ Reduce methane intensity by 50% from 2020 levels by 2025 and 70% by 2030 +◦ Eliminate routine flaring, as defined by the World Bank, by 2025 +• Social. We value our employees’ contributions and we focus on attracting and retaining a more diverse workforce. We strive to establish effective environmental, health and safety programs that promote safe practices for our employees and contractors. +• Governance. We continue to commit to governance best practices and accountability to shareholders as we see this as a critical factor to our long-term success. +Operating Areas +Wattenberg Field. In the Wattenberg Field, we have identified a gross operated inventory of approximately 2,100 horizontal locations that we expect to generate acceptable rates of return based on forward strip pricing, with an average lateral length of approximately 10,000 feet. Our inventory consists of approximately 200 gross operated DUCs, 915 approved permits or CAP locations, reflecting approximately five years of turn-in-line activity based on our current drilling plan, and 985 unpermitted locations. The 2022 CAP, along with our prior OGDPs, represent the majority of our projected Wattenberg Field turn-in-line activity into 2028 based on our current pace and drilling plan in 2023. +Our Wattenberg Field horizontal drilling locations have been substantially de-risked through multiple years of successful development in the field. We continue to analyze and test various wellbore spacing configurations in areas of the field that we believe have the potential to increase our gross operated inventory. Substantially all of our Wattenberg Field acreage is held by production. Wells in the Wattenberg Field typically have productive horizons at depths of approximately 6,500 to 7,500 feet below the surface, reaching the Niobrara and Codell plays. We continue to pursue various business development initiatives, with a focus on acreage exchanges or acquisitions, designed to increase our Wattenberg Field project inventory or to increase our ownership in our operated wells. +Delaware Basin. In the Delaware Basin, with a relaxed spacing program of approximately eight wells per undeveloped section equivalent and new operational techniques, we have a gross operated economic inventory of approximately 60 horizontal locations, representing approximately three years of inventory based on our current drilling plan. Our inventory consists of 12 gross operated DUCs that we expect to generate acceptable rates of return based on forward strip pricing, targeting the Wolfcamp A and B zones. The average lateral length of these locations is approximately 11,100 feet. Wells in the Delaware Basin typically have productive stacked-pay horizons at depths of approximately 9,000 to 11,500 feet below the surface, reaching the Wolfcamp zones. In 2023, our drilling program will include some untested target zones that may be subject to a higher degree of uncertainty. If successful, we anticipate the program will allow us to increase our field inventory. We continue to pursue various business development initiatives, with a focus on acreage exchanges and joint development projects, designed to increase our Delaware Basin project inventory by establishing longer lateral drilling units capable of delivering attractive economic returns or to increase our ownership in our operated wells. +We currently operate approximately 79 percent of the wells in which we have an interest. This operational control allows us to better manage our drilling, production, operating and administrative costs and to leverage our technical expertise in our core operating areas. Our leaseholds that are held by production further enhance our operational control by providing us with additional flexibility on the timing of drilling of locations on those leases. +6 +Table of cont ents +Oil and Gas Production and Operations +Proved Oil and Gas Reserves +The following table presents our proved reserve estimates as of the dates indicated: +December 31, +2022 2021 2020 +Proved reserves +Crude oil and condensate (MMBbls) +270 214 212 +Natural gas (Bcf) +2,893 2,160 1,901 +NGLs (MMBbls) +348 240 203 +Total proved reserves (MMBoe) +1,100 814 731 +Proved developed reserves (MMBoe) +518 399 322 +Standardized measure (in millions) +$ 14,987 $ 7,908 $ 3,282 +Estimated undiscounted future net cash flows (in millions) (1) +$ 26,916 $ 13,872 $ 5,633 +PV-10 ( in millions) (2) +$ 19,053 $ 9,709 $ 3,455 +_____________ +(1) Amount represents aggregate undiscounted future net cash flows, before income taxes, of approximately $34.0 billion, $17.0 billion and $5.9 billion as of December 31, 2022, 2021 and 2020, respectively, less an internally-estimated undiscounted future income tax expense of approximately $7.1 billion, $3.1 billion and $0.3 billion, respectively. +(2) PV-10 is a non-U.S. GAAP financial measure. It is not intended to represent the current market value of our estimated reserves. PV-10 should not be considered in isolation or as a substitute for the standardized measure reported in accordance with U.S. GAAP, but rather should be considered in addition to the standardized measure. See Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations - Reconciliation of Non-U.S. GAAP Financial Measures, for a definition of PV-10 and a reconciliation of our PV-10 value to the standardized measure. +The additions to our proved reserves at December 31, 2022 as compared to December 31, 2021 were primarily due to (i) the reserves acquired in the Great Western Acquisition, (ii) positive revisions resulting from our development activities and (iii) upward revisions as a result of significant improvements in commodity prices during 2022, resulting in better economics and therefore increased quantities of reserves. +The additions to our proved reserves at December 31, 2021 compared to December 31, 2020 were primarily due to positive revisions resulting from our development activities and significant improvements in commodity prices during 2021, resulting in better economics. +The additions to our proved reserves at December 31, 2020 as compared to December 31, 2019 were primarily due to the reserves acquired from our merger with SRC Energy, Inc. (“SRC Acquisition”), which were partially offset by downward revisions as a result of decreases in realized prices and revised drilling plans following the completion of the SRC Acquisition. +7 +Table of cont ents +The following table presents our proved reserve estimates by category as of December 31, 2022: +Operating Region/Area Crude Oil and Condensate (MMBbls) Natural Gas (Bcf) NGLs (MMBbls) Crude Oil Equivalent (MMBoe) Percent +Proved developed +Wattenberg Field 102 1,209 154 457 41 % +Delaware Basin 22 146 15 61 6 % +Total proved developed 124 1,355 169 518 47 % +Proved undeveloped +Wattenberg Field 135 1,458 171 549 50 % +Delaware Basin 11 80 8 33 3 % +Total proved undeveloped 146 1,538 179 582 53 % +Total proved reserves +Wattenberg Field 237 2,667 325 1,006 91 % +Delaware Basin 33 226 23 94 9 % +Total proved reserves 270 2,893 348 1,100 100 % +Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Positive impacts of these variables and assumptions may result in a longer economic productive life of a property or the recognition of more economically viable proved undeveloped (“PUD”) reserves, while negative impacts of these variables and assumptions may result in corresponding negative impacts. All of our proved reserves are located in the United States. +Commodity Pricing . Per SEC rules, the pricing used to prepare the proved reserves is based on the unweighted arithmetic average of the first of the month prices for the preceding 12 months. The NYMEX prices used in preparing the reserves are then adjusted based on energy content, location and basis differentials and other marketing deductions to arrive at the net realized price. +Average Benchmark Prices +December 31, +Crude Oil (per Bbl) (1) +Natural Gas (per MMBtu) (1) +NGLs (per Bbl) (2) +2022 $ 93.67 $ 6.36 $ 93.67 +2021 66.56 3.60 66.56 +2020 39.57 1.99 39.57 +____________ +(1) Our benchmark indexes for crude oil and natural gas are WTI and Henry Hub, respectively. +(2) For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. +The netted back price used to estimate our reserves, by commodity, are presented below. +Price Used to Estimate Reserves (1) +December 31, Crude Oil +(per Bbl) Natural Gas +(per Mcf) +NGLs (per Bbl) +2022 $ 94.23 $ 4.82 $ 31.60 +2021 65.37 2.85 24.96 +2020 37.52 1.26 10.55 +____________ +(1) These prices are based on index prices and are net of basin differentials, transportation fees, contractual adjustments and Btu adjustments we experienced for the respective commodity. +Proved Reserves Sensitivity Analysis. We have performed an analysis of our proved reserve estimates as of December 31, 2022 to present sensitivity associated with a lower crude oil price as the value of crude oil influences the value of our proved reserves and PV-10 most significantly. +8 +Table of cont ents +Replacing the 2022 NYMEX price for crude oil used in estimating our reported proved reserves with $75 per Bbl and $50 per Bbl as shown on the table below, and leaving all other parameters unchanged, including natural gas pricing, NGL pricing and future costs, results in changes to our estimated proved reserves as shown. +Pricing Scenario - NYMEX +Crude Oil (per Bbl) Natural Gas (per MMBtu) Proved Reserves (MMBoe) % Change from December 31, 2022 Estimated Reserves PV-10 +(in Millions) PV-10 % Change from December 31, 2022 Estimated Reserves +2022 SEC Reserve Report (1) +$ 93.67 $ 6.36 1,099,766 — $ 19,053.0 — +Alternate Price Scenario 1 $ 75.00 $ 6.36 1,092,010 (1) % $ 15,270.0 (20) % +Alternate Price Scenario 2 $ 50.00 $ 6.36 1,075,461 (2) % $ 10,185.0 (47) % +_____________ +(1) These prices are the SEC NYMEX prices applied to the calculation of the PV-10 value. Such prices have been applied consistently in the alternate pricing scenario to include the impact of adjusting for deductions for any basin differentials, transportation fees, contractual adjustments and Btu adjustments we experienced for the relevant commodity. +Reserves and Standardized Measure . Reserve estimates involve judgments and reserves cannot be measured exactly. The estimates must be reviewed periodically and adjusted to reflect additional information gained from reservoir performance, new geologic and geophysical data and economic changes. Neither the estimated future net cash flows nor the standardized measure of discounted future net cash flows (“standardized measure”) is intended to represent the current market value of our proved reserves. +For additional information regarding our standardized measures, as well as other information regarding our proved reserves, see Supplemental Information- Crude Oil and Natural Gas Properties included in Item 8. Financial Statements and Supplementary Data provided with our consolidated financial statements included elsewhere in this report. +Preparation of Reserve Estimates +Our proved reserves estimates as of December 31, 2022 were based on evaluations prepared by our independent petroleum engineering consulting firms, Ryder Scott Company, L.P. (“Ryder Scott”) and Netherland, Sewell & Associates, Inc. (“NSAI”) (collectively, our “external engineers”). Our proved reserve estimates were prepared in accordance with guidelines established by the SEC and the Financial Accounting Standards Board (the “FASB”). +Controls Over Reserve Report Preparation . Inputs and major assumptions related to our proved reserves are reviewed annually by an internal team composed of reservoir engineers, geologists, land and management for adherence to SEC guidelines through a detailed review of land and accounting records, available geological and reservoir data and production performance data. The internal team compiles the reviewed data and forwards the applicable data to our external engineers. +Annually, the Director of Reservoir Engineering & Technology reviews the reserves to ensure all the necessary significant inputs and steps are completed within our reserve process. After final approval from the Director of Reservoir Engineering & Technology, the results are presented to senior management and to our board of directors for their review. +Together, these internal controls are designed to promote a comprehensive, objective, and accurate reserves estimation process. As an additional confirmation of the reasonableness of our internal estimates, Ryder Scott and NSAI performed an independent evaluation of our estimated proved reserves in the Wattenberg Field and Delaware Basin, respectively, as of December 31, 2022. +When preparing our reserve estimates, our external engineers do not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, production volumes, well test data, historical costs of operations and development, product prices or any agreements relating to current and future operations of properties or sales of production. Our external engineers prepare estimates of our reserves in conjunction with an ongoing review by our engineers. A final comparison of data is performed to ensure that the reserve estimates are complete, determined pursuant to acceptable industry methods and with a level of detail we deem appropriate. The final estimated reserve reports are +9 +Table of cont ents +prepared by our external engineers and reviewed by our engineering staff and management prior to issuance by the respective firms. +In determining our proved reserves estimates, we used a combination of performance methods, including decline curve analysis and other computational methods, offset analogies and seismic data and interpretation. All of our proved undeveloped reserves conform to the SEC five-year rule requirement as all proved undeveloped locations are scheduled, according to an adopted development plan, to be drilled within five years of the location’s initial booking date. +Qualifications of Responsible Technical Persons. The professional qualifications of our lead engineer primarily responsible for overseeing the preparation of our reserve estimates, as defined in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information as promulgated by the Society of Petroleum Engineers, qualifies this individual as a Reserve Estimator. This person holds a Masters Degree in Petroleum Engineering from the Colorado School of Mines and a Bachelors Degree in Geology from the University of Colorado and has over 22 years of oil and gas experience. +Letters which identify the professional qualifications of the individuals at Ryder Scott and NSAI who are responsible for overseeing the preparation of our reserve estimates as of December 31, 2022 have been filed as Exhibits 99.1 and 99.2 to this report. +Production, Prices and Costs +Production and operating data for the years ended December 31, 2022, 2021 and 2020 is included in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations included elsewhere in this report. +Productive Wells +The following table presents our productive wells by operating area as of December 31, 2022: +Crude Oil Natural Gas Total +Operating Region/Area Gross Net Gross Net Gross Net +Wattenberg Field 3,013 2,224 930 801 3,943 3,025 +Delaware Basin 53 37 102 90 155 127 +Total productive wells 3,066 2,261 1,032 891 4,098 3,152 +Productive wells consist of producing wells and wells capable of production, including crude oil wells awaiting pipeline connections to commence deliveries, natural gas wells awaiting connection to production facilities and shut-in wells. +Developed and Undeveloped Acreage +The following table presents our developed and undeveloped lease acreage as of December 31, 2022: +Developed Undeveloped Total +Operating Region/Area Gross Net Gross Net Gross Net +Wattenberg Field 222,037 201,827 80,950 72,741 302,987 274,568 +Delaware Basin 27,636 24,703 959 906 28,595 25,609 +Total acreage 249,673 226,530 81,909 73,647 331,582 300,177 +Developed lease acreage are acres spaced or assigned to productive wells and do not include undrilled acreage held by production under the terms of the lease. Large portions of the acreage that are considered developed under SEC guidelines are developed with vertical wells or horizontal wells that are in a single horizon. We believe the majority of this acreage has significant remaining development potential in one or more intervals with horizontal wells. Undeveloped acreage represents acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves. However, substantially all of our undeveloped acreage in the Wattenberg Field and Delaware Basin is related to leaseholds that are held by production and therefore are not at risk of expiration or delay rental payments. +10 +Table of cont ents +Our Wattenberg Field and Delaware Basin leaseholds at risk to expire in 2023 through 2025 are not material. See Item 1A. Risk Factors - Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in substantial lease renewal costs or, if renewal is not feasible, loss of our lease and prospective drilling opportunities. +Drilling Results +The following tables set forth a summary of our developmental and exploratory well drilling results for the periods presented. Productive wells consist of wells that were turned-in-line and commenced production during the period, regardless of when drilling was initiated. In-process wells represent wells that are in the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection as of the date shown. We utilize pad drilling operations, where multiple wells are developed from the same well pad, in both the Wattenberg Field and Delaware Basin. Because we may operate multiple drilling rigs in each operating area, we expect to have in-process wells at any given time. Wells may be in-process for up two years. +Operated Development and Exploratory Well Drilling Activity +As of and For the Year Ended December 31, +2022 2021 2020 +Operating Region/Area Gross Net Gross Net Gross Net +Development Wells +Wattenberg Field 164 150 149 143 124 117 +Delaware Basin 19 19 16 16 13 13 +Total development wells 183 169 165 159 137 130 +In-Process Development Wells +Wattenberg Field 200 185 143 133 214 202 +Delaware Basin 12 12 21 21 18 17 +Total in-process wells 212 197 164 154 232 219 +Developmental Wells - Dry Hole +Wattenberg Field 1 1 — — — — +Delaware Basin 2 2 — — — — +Total developmental wells - dry hole 3 3 — — — — +Exploratory Wells - Delaware Basin +Productive — — 2 2 2 2 +Dry Hole 1 1 — — — — +In-Process — — — — 2 2 +There were no exploratory drilling activities in the Wattenberg Field during 2022, 2021 and 2020. +Title to Properties +We believe that we hold good and defensible leasehold title to substantially all of our crude oil and natural gas properties, in accordance with standards generally accepted in the industry. A preliminary title examination is typically conducted at the time the undeveloped properties are acquired. Prior to the commencement of drilling operations, a title examination is conducted and remedial curative work is performed, as necessary, with respect to discovered defects which we deem to be significant, in order to procure division order title opinions. Title examinations have been performed with respect to substantially all of our producing properties. +The properties we own are subject to royalty, overriding royalty and other outstanding interests. The properties may also be subject to additional burdens, liens or encumbrances customary in the industry, including items such as operating agreements, current taxes, development obligations under crude oil and natural gas leases, farm-out agreements and other restrictions. We do not believe that any of these burdens will materially interfere with our use of the properties. +11 +Table of cont ents +Substantially all of our crude oil and natural gas properties have been mortgaged or pledged as security for amounts borrowed under our revolving credit facility. +Offices +As of December 31, 2022, we leased corporate space in 1775 Sherman Street, Suite 3000, Denver, Colorado, where our corporate headquarters is located. We also maintain offices in Evans, Colorado and Midland, Texas. In January 2022, we entered into a long-term lease agreement for office space located in Denver, Colorado. +Significant Customers +We sell our crude oil and natural gas production to marketers and other purchasers which have access to pipeline facilities. In areas where there is no practical access to pipelines, crude oil is transported to storage facilities by trucks owned or otherwise arranged by the marketers or purchasers. The majority of our crude oil and natural gas production is transported through pipelines. +We made sales to one customer that represented 10 percent or more of our 2022 total crude oil, natural gas and NGLs revenues. However, given the liquidity in the market for the sale of hydrocarbons, we believe that the loss of any single purchaser, or the aggregate loss of several purchasers, could be managed by selling to alternative purchasers. +Seasonality of Business +Weather conditions affect the demand for and prices of crude oil and natural gas. Due to these seasonal fluctuations, including severe weather conditions, our results of operations for individual quarterly periods may not be indicative of our annual results. +Delivery Commitments +Certain of our firm sales agreements for crude oil include delivery commitments. We believe our current production and reserves are sufficient to fulfill these delivery commitments. See Note 12 - Commitments and Contingencies in Item 8. Financial Statements and Supplementary Data for more information. +Governmental Regulation +The U.S. crude oil and natural gas industry is extensively regulated at the federal, state and local levels. The following is a summary of certain laws, rules and regulations currently in force that apply to us. The regulatory environment in which we operate changes frequently and we cannot predict the timing or nature of such changes or their effects on us. +Regulation of Crude Oil and Natural Gas Exploration and Production. Our exploration and production activities are subject to a variety of rules and regulations concerning drilling permits, location, spacing and density of wells, water discharge and disposal, prevention of waste, bonding requirements, surface use and restoration, public health and environmental protection and well plugging and abandonment. The primary state-level regulatory authority regarding these matters in Colorado is the COGCC and in Texas is the Texas Railroad Commission. Prior to preparing a surface location and commencing drilling operations on a well, we must procure permits and/or approvals for the various stages of the drilling process from the relevant state and local agencies. In addition, our operations must comply with rules governing the size of drilling and spacing units or proration units and the unitization or pooling of lands and leases. Some states, such as Colorado, allow the forced pooling or integration of tracts to facilitate exploration while other states, such as Texas, rely primarily or exclusively on voluntary pooling of lands and leases. +In states such as Texas where pooling is primarily or exclusively voluntary, it may be more difficult to form units and therefore to drill and develop our leases in circumstances where we do not own all of the leases in the proposed unit. These risks may also exist in Colorado, where the COGCC has recently imposed minimum requirements for ownership and consent in order to obtain a force pooling order. State laws may also prohibit the venting or flaring of natural gas, which may impact rates of production of crude oil and natural gas from our wells. Leases covering state or federal lands often include additional laws, +12 +Table of cont ents +regulations and conditions which can limit the location, timing and number of wells we can drill and impose other requirements on our operations, all of which can increase our costs. +Regulation of Transportation of Commodities. We move crude oil, natural gas and NGLs through pipelines owned by other entities and sell these commodities to other entities that also utilize common carrier pipeline facilities. The Federal Energy Regulatory Commission regulates (i) the interstate transmission and storage of gas under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, and (ii) the interstate movement of liquids, including crude and NGLs, under the Interstate Commerce Act as it existed on October 1, 1977, as well as rules and regulations promulgated under such statutes and other laws. The availability, terms and cost of transportation can be impacted by these regulations and may affect the amounts we receive for our commodities. +Democratic control of the House, Senate and White House could lead to increased regulatory oversight and increased regulation and legislation, particularly around oil and gas development on federal lands, climate impacts and taxes. +Environmental Matters +Our operations are subject to numerous laws and regulations relating to environmental protection. These laws and regulations change frequently, and the effect of these changes is often to impose additional costs or other restrictions on our operations. We cannot predict the occurrence, timing, nature or effect of these changes. We also operate under a number of environmental permits and authorizations. The issuing agencies may take the position that some or all of these permits and authorizations are subject to modification, suspension, or revocation under certain circumstances, but any such action would have to comply with applicable procedures and requirements. +Hazardous Substances and Wastes +We generate wastes that may be subject to the Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes. Pursuant to these statutes, the U.S. Environmental Protection Agency (“EPA”) and various state agencies have adopted requirements that require approved disposal methods for certain hazardous and non-hazardous wastes. From time to time, EPA considers adoption of stricter disposal standards under RCRA. If new standards are adopted, it could increase maintenance and capital expenditures and operating expenses. Furthermore, certain wastes generated by our operations that are currently exempt from treatment as “hazardous wastes” may in the future be designated as hazardous wastes, and therefore may subject us to more rigorous and costly operating and disposal requirements. +We currently own or lease numerous properties that have been used for the exploration and production of crude oil and natural gas for many years. If hydrocarbons or other wastes have been disposed of or released on or under the properties that we own or lease or on or under locations where such wastes have been taken for disposal by us or prior owners or operators of such properties, we could be subject to liability under the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), RCRA and analogous state laws, as well as state laws governing the management of crude oil and natural gas wastes. CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the owner or operator of the disposal site or sites where the release occurred and companies that disposed of, transported or arranged for the disposal of the hazardous substances found at the site. Parties who are or were responsible for release of hazardous substances under CERCLA may be subject to full liability for the costs of cleaning up the hazardous substances that have been released into the environment or remediation to prevent future contamination and for damages to natural resources. In addition, under state laws, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. +Hydraulic Fracturing +Hydraulic fracturing is commonly used to stimulate production of crude oil and/or natural gas from dense subsurface rock formations. We consistently utilize hydraulic fracturing in our crude oil and natural gas development programs. The process involves the injection of water, sand and additives under pressure into a targeted subsurface formation. The water and pressure create fractures in the rock formations which are held open by the grains of sand, enabling the crude oil or natural gas to more easily flow to the wellbore. The process is generally subject to regulation by state oil and gas commissions, but is also the subject of various other regulatory initiatives at the federal, state and local levels. +13 +Table of cont ents +Local Regulation +Various local and municipal bodies in each of the states in which we operate have sought to impose prohibitions, moratoria and other restrictions on hydraulic fracturing activities. In Colorado, Senate Bill 19-181 (“SB 19-181”) authorizes governmental authorities to regulate the siting and surface impacts of oil and gas development. We primarily operate in the rural areas of the core Wattenberg Field in Weld County, a jurisdiction in which there has historically been significant support for the oil and gas industry. Following the acquisition of Great Western in 2022, however, we also have significant acreage and operations in Adams County, a more urban setting that poses more regulatory challenges. In Texas, legislation enacted in 2015 generally prohibits political subdivisions from banning, limiting or otherwise regulating oil and gas operations. See Item 1A. Risk Factors-Risks Relating to Our Business and the Industry-Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us. +State Regulation +The states in which we currently operate have adopted or may adopt laws and regulations that impose or could impose, among other requirements, more stringent permitting processes and increased environmental protection and monitoring. +SB 19-181 changed the mission of the COGCC from fostering responsible and balanced development to regulating development to protect public health and the environment and directed the COGCC to undertake rulemaking on various operational matters. Pursuant to this direction, the COGCC conducted a series of rulemaking hearings during 2020 which resulted in updated regulatory and permitting requirements, including siting requirements. The requirements prohibit the siting of locations within 2,000 feet of a school facility or child-care center. A similar 2,000-foot setback requirement applies to residential and high occupancy building units, but there are “off ramps” allowing oil and gas operators to site their drill pads as close as 500 feet from building units in certain circumstances. +In July 2020, Governor Polis authored an op-ed stating that both industry and mainstream environmental groups communicated a willingness to work together to prevent ballot initiatives in 2022. As part of that agreement, Governor Polis stated that he would “actively oppose” ballot initiatives around the oil and gas industry and acknowledged the importance of regulatory certainty. There were no oil and gas ballot initiatives in 2022 that would have imposed additional regulations on the oil and gas industry. +It is nevertheless possible that future ballot initiatives will be proposed that could limit the areas of the state in which drilling would be permitted to occur or otherwise impose increased regulations on our industry. See Item 1A. Risk Factors-Risks Relating to Our Business and the Industry-Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us. +Federal Regulation +The U.S. Department of the Interior, through the Bureau of Land Management (the “BLM”), finalized a rule in 2015 requiring the disclosure of chemicals used, mandating well integrity measures and imposing other requirements relating to hydraulic fracturing on federal lands. The BLM rescinded the rule in December 2017. The BLM’s rescission of the rule was challenged in the United States District Court for the Northern District of California and in March 2020 the court issued a ruling upholding BLM’s rescission of the rule. That court ruling is currently subject to an appeal. +Private Lawsuits +Lawsuits have been filed against other operators in several states, including Colorado, alleging contamination of drinking water as a result of hydraulic fracturing activities. +Greenhouse Gases +The EPA has published findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because such emissions are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings provide the basis for the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the Clean Air Act (“CAA”). In June 2010, the EPA began regulating GHG emissions from stationary sources. +14 +Table of cont ents +In the past, Congress has considered proposed legislation to reduce emissions of GHGs. On August 16, 2022, the Inflation Reduction Act of 2022 (“IRA”) was signed into law. The IRA imposes a fee of up to $1,500 per metric ton of methane emitted above specified thresholds from onshore petroleum and natural gas production facilities, natural gas processing facilities, natural gas transmission and compression facilities, and onshore petroleum and natural gas gathering and boosting facilities, among other facilities. The fees will apply to methane emissions after January 1, 2024. We do not anticipate that such fees will have material effect on our financial condition or results of operations. Congress may adopt additional significant legislation in the future to reduce emissions of GHGs. +In addition, many states and regions have taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Since 2014, Colorado has engaged in multiple rulemakings to adopt significant additional rules regulating methane emissions from the oil and gas sector. +In response to Colorado’s established statewide Climate Action Plan to Reduce Pollution, HB 19-1261, in September 2020, the state released a public comment draft of its Greenhouse Gas Pollution Reduction Roadmap, which detailed early action steps the state can take toward meeting the near-term goals of reducing GHG pollution by 26% by 2025 and 50% by 2030 from 2005 levels. In October 2020, the Air Quality Control Commission (“AQCC”) issued the Resolution to Ensure Greenhouse Gas Reduction Goals Are Met in support of the roadmap, which estimates emission reductions needed from the oil and gas sector of 36% by 2025 and 50% by 2030. To meet these targets, as well as to address other air quality and environmental justice issues, the AQCC held a hearing in December 2021 and voted to adopt additional requirements and emission limitations applicable to oil and gas facilities in Colorado. The adopted regulatory requirements include, for example, more frequent fugitive emissions monitoring, a statewide GHG intensity program, emission limitations for well liquids unloading, and comprehensive testing of emission control devices. Colorado is expected to engage in additional rulemakings over the next several years related to GHG reductions in the oil and gas industry. +In April 2021, President Biden announced that the United States would aim to cut its greenhouse gas emissions 50 percent to 52 percent below 2005 levels by 2030. This commitment will be part of the United States’ “nationally determined contribution,” or NDC, to the Paris Climate Agreement. The NDC will commit the United States to a voluntary GHG emission reduction target and outline domestic climate mitigation measures to achieve that target. +Regulation of methane and other GHG emissions associated with oil and natural gas production could impose significant requirements and costs on our operations. See our GHG emission reduction goals included in Items 1. and 2. Business and Properties included elsewhere in this report. +Air Quality +Our operations are subject to the CAA and comparable state and local requirements. The CAA contains provisions that may result in the gradual imposition of certain pollution control requirements with respect to air emissions from our operations. The EPA and state governments continue to develop regulations to implement these requirements. We may be required to make certain capital investments in the next several years for air pollution control equipment in connection with maintaining or obtaining operating permits and approvals addressing other air emission-related issues. +In June 2016, the EPA implemented new requirements focused on achieving additional methane and volatile organic compound reductions from the oil and natural gas industry. The rules imposed, among other things, new requirements for leak detection and repair, control requirements for oil well completions, replacement of certain pneumatic pumps and controllers and additional control requirements for gathering, boosting and compressor stations. In November 2021, EPA published a proposed rule that would update and expand existing requirements for the oil and gas industry, as well as creating significant new requirements and standards for new, modified, and existing oil and gas facilities. The proposed new requirements would include, for example, new standards and emission limitations applicable to storage vessels, well liquids unloading, pneumatic controllers, and flaring of natural gas at both new and existing facilities. In November 2022, the EPA published a supplemental proposal to update, strengthen, and expand the standards proposed in November 2021. The proposed rules for new and modified facilities are estimated to be finalized by the end of 2023, while any standards finalized for existing facilities will require further state rulemaking actions over the next several years before they become applicable and effective. +In November 2022, the BLM published a proposed rule that would regulate venting, flaring and leaks during oil and gas production activities on federal and Indian leases. If finalized as proposed, the rule would limit gas that may be flared royalty-free during well completions, production testing, and emergencies; establish a monthly volume limit on royalty-free +15 +Table of cont ents +flaring due to pipeline capacity constraints, midstream processing failures, or other similar events; require vapor recovery systems on oil tanks; require operators to maintain leak detection and repair (“LDAR”) programs; prohibit the use of certain natural-gas-activated pneumatic controllers and pneumatic diaphragm pumps; and require operators to submit waste minimization plans with applications for permit to drill, among other requirements. +In 2019, the EPA increased the state of Colorado’s non-attainment ozone classification for the Denver Metro North Front Range Ozone Eight-Hour Non-Attainment (“Denver Metro/North Front Range NAA”) area from “moderate” to “serious” under the 2008 national ambient air quality standard (“NAAQS”). This increase in non-attainment status to “serious” triggered significant additional obligations for the state under the CAA and resulted in Colorado adopting new and more stringent air quality control requirements in December 2020 that are applicable to our operations. The Denver Metro/North Front Range NAA was further “bumped-up” to “severe” status in 2022. This will trigger additional obligations for the state under the CAA and will result in new and more stringent air quality permitting and control requirements. +In addition, SB 19-181 requires, among other things, that the AQCC adopt additional rules to minimize emissions of methane and other hydrocarbons and nitrogen oxides from the entire oil and gas fuel cycle. The AQCC has undertaken a multi-year rulemaking process to implement the requirements of SB 19-181, including a rulemaking to require continuous emission monitoring equipment at oil and gas facilities. Since December 2019, the AQCC completed several rulemakings as a result of SB 19-181 and other state legislation, adopting significant additional and new emission control and monitoring requirements applicable to oil and gas operations, including, for example, hydrocarbon liquids unloading control requirements, increased LDAR frequencies for facilities in certain proximity to occupied areas, and emission control requirements for certain large natural gas fired engines. The AQCC is expected to conduct additional rulemakings over the next several years that may result in additional regulatory requirements for oil and gas facilities. +Scrutiny of oil and gas operations and the rules affecting them have increased in Texas in recent years. For example, EPA and environmental non-governmental organizations have conducted flyovers with optical gas imaging cameras to survey emissions from oil and gas production facilities and transmission infrastructure. In addition, the Texas Railroad Commission has increased oversight related to flaring, with reporting reviews and site inspections. While none of these activities increases our compliance obligations, they signal the potential for increased enforcement and possible rulemaking in the future. +Water Quality +The federal Clean Water Act (“CWA”) and analogous state laws impose strict controls concerning the discharge into regulated waterbodies and wetlands of pollutants and fill material, including spills and leaks of crude oil and other substances. The CWA also requires approval and/or permits prior to construction, where construction will disturb certain wetlands or other federally regulated waters of the U.S. (“WOTUS”). For years, both via administrative rulemakings and actions and judicial interpretation and intervention, the definition of “WOTUS” and how it has been applied has been in flux. In 2019 and 2020, the EPA and the Army Corps of Engineers (“USACE”) issued a final rule to repeal previous regulations and promulgated a new replacement rule (the “Navigable Waters Protection Rule”). The Navigable Waters Protection Rule was vacated by two separate federal district courts in late 2021. In November 2021, EPA and USACE issued a pre-publication version of another rule largely reinstating the previous 1986 WOTUS rule and guidance “with certain amendments” to reflect “consideration of the agencies’ statutory authority under the CWA and relevant Supreme Court decisions” (the “2021 Proposed Rule”). The 2021 Proposed Rule was published in the Federal Register in December 2021. In addition to the 2021 Proposed Rule, in September 2022, the EPA and USACE sent the draft final rule to implement the 2021 Proposed Rule to the Office of Management and Budget for interagency review, but no final rule has yet been issued by the agencies. It is unknown at this time when the 2021 Proposed Rule will take effect; when the next forthcoming proposed amendments are expected; and/or whether either new rule will be challenged and withstand any challenges in federal court. Finally, in January 2022, the United States Supreme Court granted review of Sackett vs. EPA , which involves issues related to CWA scope and jurisdiction and could impact the current rulemaking process. The Supreme Court heard oral argument in Sackett i n October 2022, and a decision is expected in 2023. Although the outcome of the 2021 Proposed Rule and additional forthcoming amendments to the WOTUS regulations is unknown, the regulations under the Biden Administration are undoubtedly more stringent in terms of the scope of WOTUS, which could ultimately change the scope of the CWA’s jurisdiction and result in increased costs and delays with respect to obtaining permits for discharges of pollutants or dredge and fill activities in waters of the U.S., including regulated wetland areas. As noted above, however, things are constantly in flux and the fate of the definition of “WOTUS” under the CWA and how that ultimately will be applied by the Agencies is yet to be seen. +16 +Table of cont ents +The CWA also regulates storm water run-off from crude oil and natural gas facilities and requires storm water discharge permits for certain activities. Spill Prevention, Control and Countermeasure (“SPCC”) requirements of the CWA require appropriate secondary containment, load out controls, piping controls, berms and other measures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture or leak. +Endangered Species +The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act and bald and golden eagles under the Bald and Golden Eagle Protection Act. Some of our operations are located in areas that are or may be designated as habitats for endangered or threatened species or that may attract migratory birds, bald eagles, golden eagles or other wildlife. The designation of these habitats could cause us to incur additional costs or become subject to operating restrictions or bans in the affected areas. +Other +Crude oil production is subject to many of the same operating hazards and environmental concerns as natural gas production, but is also subject to the risk of crude oil spills. In addition to SPCC requirements, the Oil Pollution Act of 1990 (“OPA”) establishes requirements for preparation and EPA approval of Facility Response Plans and subjects owners of facilities to strict joint and several liability for all containment and cleanup costs and certain other damages arising from crude oil spills. Noncompliance with OPA may result in varying civil and criminal penalties and liabilities. Historically, we have not experienced any significant crude oil discharge or crude oil spill problems. +In February 2018, the COGCC comprehensively amended its regulations for oil, gas and water flowlines to expand requirements addressing flowline registration and safety, integrity management, leak detection and other matters. In November 2019, the COGCC further amended its flowline regulations pursuant to SB 19-181 to impose additional requirements regarding flowline mapping, operational status, certification and abandonment, among other things. +In June 2020, the COGCC amended its regulations regarding wellbore integrity. The amended rules impose additional requirements regarding the permitting, construction, operation, and closure of wells. Furthermore, in March 2022, the COGCC adopted new financial assurance rules pursuant to SB 19-181 that require every operator to provide assurance that it is financially capable of fulfilling the obligations imposed by the COGCC’s rules. In particular, the rules increase the financial assurance required for inactive or low producing wells and require that operators maintain single well financial assurance to cover the full cost of plugging, abandoning, and reclaiming wells, with a focus on inactive and transferred wells. The new financial assurance rules became effective on April 30, 2022. PDC will obtain a $40 million bond in 2023 in order to comply with the rules. +In addition, on May 10, 2022, the Colorado Legislature adopted SB 22-198, the “Orphaned Oil and Gas Well Enterprise” bill, which requires each oil and gas operator in Colorado to pay a mitigation fee to the “enterprise” for each well that has been spud but not yet plugged and abandoned. The COGCC submitted a notice of rulemaking on May 18, 2022 to implement SB 22-198 by amending the COGCC’s annual registration fee rules to now require that an operator’s annual registration fee be paid to the enterprise as a “mitigation fee.” In addition, the newly established “Enterprise Board” now has the authority to adjust the dollar amount of the mitigation fee. The amendments became effective on June 30, 2022, and may increase the registration fees required for current and future oil and gas wells in Colorado. +Finally, on August 30, 2022, environmental groups filed a petition for rulemaking with the COGCC, petitioning the COGCC to adopt new rules to evaluate and address the cumulative air impacts of oil and gas development in Colorado. The petition proposes to address the cumulative air impacts of oil and gas development by effectively prohibiting any oil and gas project located in an area where the air quality exceeds, or may exceed, applicable air quality standards. In effect, the petition for rulemaking calls for a blanket prohibition on oil and gas development in much of Colorado. The COGCC denied the petition; however, the COGCC initiated a cumulative impacts stakeholder process to determine how best to address cumulative impacts going forward, which may include additional regulations. +We are also subject to rules regarding worker safety and similar matters promulgated by the U.S. Occupational Safety and Health Administration (“OSHA”) and other governmental authorities. OSHA has established workplace safety standards that provide guidelines for maintaining a safe workplace in light of potential hazards, such as employee exposure to hazardous +17 +Table of cont ents +substances. To this end, OSHA adopted a new rule governing employee exposure to silica, including during hydraulic fracturing activities, in March 2016. +Human Capital Management +We believe that our employees play a critical role in the achievement of our short-term and long-term business goals. Consequently, we are committed to attracting, retaining and developing highly motivated and qualified employees who share our core values. +Employee Engagement and Retention +We recognize and support the growth of our employees by offering internal and external development programs. We offer on-demand developmental training content and provide educational benefits and developmental stipends to support employees’ continued professional development. We utilize an online training platform to allocate and track certain employee trainings. In 2022, our employees completed approximately 8,900 hours in aggregate within our platform alone on a variety of training topics, including safety, to strengthen their skills and advance their careers. We also conduct an annual advanced leadership program for targeted employees at different levels of the Company to promote cross departmental collaboration and further develop leadership skills through simulations and actual business projects. +As of December 31, 2022, we had 616 full-time employees, 301 of whom are employed in field operations. We also engage independent contractors and service providers on an as needed basis to support our business operations. During 2022, our voluntary turnover was around 10 percent. Our employees are not covered by collective bargaining agreements. +Employee Compensation and Benefits +Our compensation program is designed to provide competitive salaries and comprehensive incentives to attract, retain and reward employees to achieve results related to our core values and strategic priorities. The structure of our compensation program provides incentives for both short-term and long-term performance. We seek fairness in total compensation and benefits with reference to external benchmarking against our peers in the industry. All full-time employees are eligible for health insurance, paid and unpaid leave, retirement benefits (including an employer match up to 10% of wages), life and disability/accident coverage, well-being and other benefits. We offer stock awards that vest over multiple years to support retention, reward performance, and align the interests of our employees with stockholders through encouragement of stock ownership. We believe that our compensation and benefits package is a strong retention tool and promotes physical, mental, financial and social health within our workforce. +Community Involvement +We are dedicated to community well-being and success and we seek to be a good partner in the communities in areas in which we operate. All of our employees are encouraged to participate in community outreach events and partnerships to support the communities where we operate, and we support our employees’ ongoing efforts to enrich the communities where they live and work. In 2022, our employees recorded approximately 7,500 volunteer hours in their communities. +Diversity, Equity and Inclusion (“DEI”) +We believe diversity, equity and inclusion provides a business with growth and increased innovation and ultimately leads to a successful workforce. We are committed to providing equal opportunity in all aspects of employment and to hiring, evaluating and promoting our employees based on skills and performance. We have an employee-led DEI project team working with a third party specialist to develop a DEI charter for incorporation into our overall strategy. +Approximately 26%, or 163, of our employees are women and 23% or 143, are members of a minority group, as defined by the U.S. Equal Employment Opportunity Commission, as of December 31, 2022. As of the same date, 28%, or 38, of our executives are women and 18%, or 25, are members of a minority group. Since the beginning of 2021, we have expanded the diversity of our board of directors by adding three new diverse members with a unique set of backgrounds and experiences. +18 +Table of cont ents +Health and Safety Culture +We are committed to the health, safety, and welfare of our employees, contractors, and neighbors. We regularly update our safety policies and procedures in an effort to ensure we are meeting or, where possible, exceeding new requirements and adopting new technologies to responsibly improve our operations. Additionally, all PDC field employees receive safety training upon hire and attend frequent meetings and refreshers to reinforce safety as a core value and our most important strategic priority. As a result of our commitment to health and safety, we have gone over four years without an employee lost time incident in either basin. +Our continual commitment to safety has resulted in improved safety records. Since the time the Occupational Safety and Health Administration (“OSHA”) began requiring record-keeping and publication of health and safety information in 1972, we have not had any employee work-related fatalities. A commonly used measure of an organization’s safety performance is Total Recordable Incident Rate (“TRIR”), which represents the number of injuries requiring medical treatment per 100 full-time employees during a one-year period. We monitor this performance measure and communicate it broadly across the company. We also include both TRIR and Preventable Vehicle Accident Rate as part of our quantitative performance metrics under our STI program. For 2022, our TRIR was below the most recent Bureau of Labor Statistics average for our industry. +Refer to our Corporate Social Responsibility Report published on our website for performance highlights regarding various human capital measures and additional sustainability information. Information contained in our Corporate Social Responsibility Report is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K. +WHERE YOU CAN FIND ADDITIONAL INFORMATION +We file annual, quarterly and current reports, proxy statements and other information with the SEC, which are maintained and available at www.sec.gov . Our SEC filings are also available free of charge from our website at www.pdce.com as soon as reasonably practicable after such material is filed with, or furnished to, the SEC. We also make available free of charge any of our SEC filings by mail. For a mailed copy of a report, please contact PDC Energy, Inc., Investor Relations, 1775 Sherman Street, Suite 3000, Denver, CO 80203, or call (303) 860-5800. +We recommend that you view our website for additional information, as we routinely post information that we believe is important for investors. Our website can be used to access such information as our recent news releases, committee charters, code of business conduct and ethics, stockholder communication policy, director nomination procedures, sustainability report and our whistle blower hotline. While we recommend that you view our website, the information available on our website is not part of this report and is not incorporated by reference. +19 +Table of cont ents +ITEM 1A. RISK FACTORS +You should carefully consider the following risk factors in addition to the other information included in this report. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as the value of an investment in our common stock or other securities. +Adverse changes in general economic conditions could have a material adverse effect on our business, results of operations and financial condition. +Current or future economic uncertainties or downturns, including those caused by the COVID-19 pandemic, could adversely affect our business and operating results. Adverse macroeconomic conditions may result from, among other things, changes in gross domestic product growth, financial and credit market fluctuations, rising inflation, recessions, political deadlocks, natural catastrophes, pandemics, military conflicts (such as the Russian invasion of Ukraine) or terrorist attacks, whether in the United States, Europe, the Asia Pacific region or elsewhere, and may result in adverse impacts on our business, including depressed crude oil, natural gas and NGL pricing, reductions in force, and reduced capital expenditures. +For example, during 2021 and 2022, the United States experienced inflation rates of approximately 7% and 6.5%, respectfully, according to data from the U.S. Bureau of Labor Statistics, which were significant increases relative to prior years. If inflation rates remain elevated or increase further, our expenses and operating costs are likely to increase as well. Inflation may also result in higher interest rates and otherwise adversely impact the macroeconomic environment, which in turn could adversely impact commodity pricing. Additionally, in recent periods the U.S. has experienced a labor shortage, which has contributed to an environment of escalating wages and salaries, which may also adversely affect our operating costs and contribute to general inflationary pressures. +We cannot predict the timing, strength or duration of any economic slowdown, instability or recovery, generally or within any particular industry. If economic conditions in the general economy or industries in which we operate do not improve, or worsen from present levels, our business, operating results, financial condition and cash flows could be adversely affected. +Risks Relating to Our Business and the Industry +Crude oil, natural gas and NGL prices fluctuate and declines in these prices, or an extended period of low prices, can significantly affect the value of our assets and our financial results and may impede our growth. +Many aspects of our business depend upon crude oil, natural gas and NGL prices, including: +• our revenue, profitability and cash flows; +• our liquidity; +• the quantity and present value of our reserves; +• the borrowing base under our revolving credit facility and access to other sources of capital; and +• the nature and scale of our operations. +The markets for crude oil, natural gas and NGLs are often volatile, and prices may fluctuate in response to, among other things: +• changes in regional, national or global economic conditions and trends, including supply and demand; +• geopolitical factors and events that reduce or increase production from oil-producing regions and/or from members of the Organization of Petroleum Exporting Countries (“OPEC”), and global events, such as the ongoing COVID-19 pandemic, and Russia’s invasion of Ukraine; and +• regulatory changes. +The price of oil has historically been volatile due to a variety of factors including global supply and economic conditions. In the past two years, oil prices have ranged from highs over $130 per barrel to lows of approximately $45 per barrel. Prices for natural gas and NGLs have also experienced substantial volatility. If we reduce our capital expenditures due to low prices, natural declines in production from our wells will result in reduced cash flow from operations. Reduced cash flow would limit our ability to make the capital expenditures necessary to replace our reserves and production. +20 +Table of cont ents +In addition to factors generally affecting the price of crude oil, natural gas and NGLs, the prices we receive for our production are affected by factors specific to us and to the local markets where production occurs. The prices we receive for our production vary from the relevant benchmark prices that are used for calculating commodity derivative positions. These differences, or differentials, are difficult to predict and may widen or narrow in the future based on markets and other forces, including local or regional supply and demand factors; terms of our sales contracts; investment decisions made by providers of midstream facilities and services, refineries and other industry participants; and the overall regulatory and economic climate. Widening differentials may materially and adversely impact our business. +We are subject to complex federal, state, local and other laws and regulations that adversely affect the cost and manner of doing business. Changes in laws and regulations applicable to us could increase our costs, impose additional operating restrictions or have other adverse effects on us. +Our exploration, development, production and marketing operations are regulated extensively at the federal, state and local levels. Laws and regulations have increased the costs of planning, designing, drilling, installing, operating and abandoning crude oil and natural gas wells and associated facilities. Under these laws and regulations, we could also be liable for personal injuries, property damage and natural resource or other damages, and could be required to change, suspend or terminate operations. A summary of certain laws and regulations that apply to us and some potential changes to those laws and regulations is set forth in Items 1 and 2 - Business and Properties - Governmental Regulation . Any of the currently applicable laws and regulations could be amended, including in ways that we do not anticipate, and those changes could adversely affect our operations. +From time to time, we have been subject to sanctions and lawsuits relating to alleged noncompliance with regulatory requirements. For example, in October 2017, in order to settle a lawsuit brought against us by the U.S. Department of Justice, on behalf of the EPA and the State of Colorado, we entered into a consent decree (“CD”) pursuant to which we paid a fine and agreed to implement certain operational changes. In addition, as a result of the acquisition of SRC Energy, Inc. (“SRC”), and Great Western Petroleum, LLC (“GW”), we became subject to SRC’s 2018 Compliance Order on Consent (“SRC COC”) and GW’s 2018 Compliance Order on Consent (“GW COC”), each of which involved issues similar to those addressed in the CD. As of December 31, 2022, each of these matters have been resolved. The CD was terminated on December 15, 2022; the SRC COC was terminated on February 28, 2022; and the GW COC was terminated on November 7, 2022. We may, however, be subject to similar lawsuits and orders in the future. +The regulatory environment in which we operate also changes frequently, often through the imposition of new or more stringent environmental and other requirements, some of which may apply retroactively. We cannot predict the nature, timing, cost or effect of such additional requirements, but they may have a variety of adverse effects on us. The types of regulatory changes that could impact our operations vary widely and include, but are not limited to, the following: +• As discussed in Items 1 and 2, Business and Properties - Governmental Regulation , there is continued ambiguity around COGCC permitting rules as implementation continues. In 2023, we anticipate continued rulemakings and guidance from the COGCC Commissioners and staff. We expect to participate in the stakeholder process to create rules and guidance around high-priority habitat, workers safety and cumulative impacts. We cannot predict the ultimate impact of these requirements on our inventory and operations. +• Federal and various state, local and regional governmental authorities have implemented, or considered implementing, regulations that seek to limit or discourage the emission of carbon, methane and other GHGs. Additional laws or regulations intended to restrict the emission of GHGs could require us to incur additional operating costs and could adversely affect demand for the oil, natural gas and NGLs that we sell. These new laws or rules could, among other things, require us to install new emission controls on our equipment and facilities, acquire allowances to authorize our GHG emissions, pay taxes related to our emissions and administer and manage a GHG emissions program. In addition, like other energy companies, we could be named as a defendant in GHG-related lawsuits. +• The development of new environmental initiatives or regulations related to the acquisition, withdrawal, storage and use of surface water or groundwater or treatment and discharge of water waste, may limit our ability to use techniques such as hydraulic fracturing, increase our development and operating costs and cause delays, interruptions or termination of our operations, any of which could have an adverse effect on our operations and financial condition. +• Corporate governance, public disclosure and compliance practices continue to evolve based upon continuing legislative action, SEC rulemaking and policy positions taken by large institutional stockholders and proxy +21 +Table of cont ents +advisors. As a result, the number of rules, regulations and standards applicable to us may become more burdensome to comply with, could increase scrutiny of our practices and policies by these or other groups and increase our legal and financial compliance costs and the amount of time management must devote to governance and compliance activities. For example, the SEC has recently proposed rules requiring that issuers provide significantly increased disclosures concerning cybersecurity matters, insider trading policies and procedures and the impact of climate changes on their business. +Increasing scrutiny, changing expectations from stakeholders and proposed reporting requirements by regulatory bodies with respect to climate-related risk and ESG may impose additional costs on us or expose us to new or additional risks. +Publicly traded companies, both in the oil and natural gas industry and otherwise, are facing increased scrutiny from stakeholders regarding climate changes and ESG matters. Attention to these issues has come from stakeholders including the SEC, local governments and institutional investors, and these stakeholders have and may in the future seek certain outcomes or results on issues they perceive to be material. For example, the SEC has recently proposed rules to enhance and standardize climate-related disclosures for investors. This increased scrutiny could result in reduced access to capital, shareholder proposals and other adverse effects. Companies that fail to adapt or comply with evolving stakeholder expectations, or are perceived as failing to respond appropriately, could suffer from reputational damage and the business, financial condition, and/or stock price of such a company could be materially and adversely impacted. +Many scientists have shown that increasing concentrations of carbon dioxide, methane and other GHGs in the Earth’s atmosphere are changing global climate patterns. The following is a summary of potential climate-related risks that could adversely affect us: +Transition Risks. Transition risks are related to the transition to a lower-carbon economy and include the risk of reduced demand and lower prices for our production. +Policy and Legal Risks. Policy risks include those arising from the regulatory actions intended to discourage activities that contribute to the adverse effects of climate change or to promote adaptation to climate change. President Biden’s administration has made addressing climate change a high priority, and this could lead to a more challenging regulatory environment. Examples of policy actions from federal, state or local governments that could increase the costs of our operations, reduce our future development or production or reduce demand for our oil and gas include the implementation of carbon-pricing mechanisms, regulations designed to shift energy use toward lower emission sources, regulations regarding energy and water use efficiency, regulations disallowing development or production activity on high ozone level days, and regulations intended to promote sustainable land use. Policy actions also may include restrictions or bans on oil and gas activities, which could lead to write-downs or impairments of our assets. +Legal risks include potential lawsuits based on alleged failures to mitigate impacts of climate change, failures to adapt to climate change and disclosure matters. For example, we may be subject to climate‐related litigation such as “greenwashing” suits with respect to our operations, disclosures, or products. Although we are not a party to any such climate-related or “greenwashing” litigation currently, unfavorable rulings against us in any such case brought against us in the future could significantly impact our operations and could have an adverse impact on our financial condition. +Technology Risks. Technological improvements or innovations that support the transition to a lower-carbon, more energy efficient economic system may have a significant impact on us. The development and use of emerging technologies in renewable energy, battery storage, and energy efficiency may reduce demand for oil and gas, resulting in lower prices and revenues, and higher costs. In addition, many automobile manufacturers have announced plans to shift production from internal combustion engine vehicles to electric powered vehicles, and some states and foreign countries have announced bans on sales of internal combustion engine vehicles beginning as early as 2025, which could reduce demand for oil. +Market Risks. Markets could be affected by climate change through shifts in supply and demand for certain commodities, especially carbon-intensive commodities such as oil and gas and other products dependent on oil and gas. Lower demand for our oil and gas production could result in lower prices and lower revenues. Market risk also may take the form of limited access to capital as investors shift investments to less carbon-intensive industries and alternative energy industries. In addition, certain investment advisers, banks, and sovereign wealth, pension, and endowment funds have in recent years been promoting divestment of investments in fossil fuel companies and pressuring lenders to limit funding to companies engaged in +22 +Table of cont ents +the extraction, production, and sale of oil and gas. We have substantial capital requirements, and we may not be able to obtain needed financing on satisfactory terms, or at all. +Reputational Risk. Climate change is a potential source of reputational risk, which is tied to changing customer or community perceptions of an organization’s contribution to, or detraction from, the transition to a lower-carbon economy. +Physical Risks . Potential physical risks resulting from climate change may be event driven (including increased severity of extreme weather events, such as hurricanes, droughts, or floods) or may be driven by longer-term shifts in climate patterns that may cause sea levels to rise or chronic heat waves. Potential physical risks may cause direct damage to assets and indirect impacts, such as supply chain disruption, and also could include changes in water availability, sourcing, and quality, which could impact drilling and completion operations. These physical risks could cause increased costs, production disruptions, and lower revenues and could substantially increase the cost or limit the availability of insurance. +A substantial part of our crude oil, natural gas and NGLs production is located in the Wattenberg Field, making us vulnerable to risks associated with operating primarily in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing formations. +Although we have significant leasehold positions in the Delaware Basin in Texas, our current production is primarily located in the Wattenberg Field in Colorado. Because our production is not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including natural disasters, government regulations and midstream interruptions. +For example, bottlenecks in processing and transportation that have occurred in some recent periods in the Wattenberg Field have negatively affected our results of operations, and these adverse effects may be disproportionately severe to us compared to our more geographically diverse competitors. Similarly, the concentration of our producing assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules that could adversely affect development activities or production relating to those formations. Such an event could have a material adverse effect on our results of operations and financial condition. In addition, the demand for, and cost of, drilling rigs, equipment, supplies, chemicals, personnel and oilfield services often increase as a result of numerous factors including increases in exploration and production activity, supply chain problems, and labor shortages. Any shortages or increased costs could delay or adversely affect our development and exploration operations or cause us to incur significant expenditures that are not provided for in our capital forecast, which could have a material adverse effect on our business, financial condition or results of operations. All of the producing properties and reserves we acquired in the past three years are located in the Wattenberg Field. As a result, the transactions increased the risks we face with respect to the geographic concentration of our properties. +The marketability of our production is dependent upon transportation and processing facilities which we do not control. If these facilities are unavailable, or if we are unable to access these facilities on commercially reasonable terms, our operations could be interrupted, negatively affecting our results of operations. +Our ability to market our production depends in substantial part on the availability, proximity and capacity of in-field gathering systems, compression and processing facilities, and transportation pipelines, all of which are owned and operated by third parties. If adequate midstream facilities and services are not available to us on a timely basis and at acceptable costs, our production may be curtailed and our results of operations will be adversely affected. +Availability or capacity issues can be a result of increased commodity prices that incentivize increased drilling and completion activities and increase commodity supplies, potentially constraining transportation capacity and subsequently lowering production volumes and realized prices. The increased commodity supplies can sometimes be more heavily weighted toward one commodity versus another. For instance, increased crude oil and natural gas prices in the first half of 2022 have incentivized producers in the Permian Basin to increase the level of drilling and completion activities. The potential increase in production levels has led to high utilization of the existing pipeline capacity out of the region. Until new pipeline expansions are placed in service, the transportation constraints in the Permian Basin may lead to lower realized natural gas prices. +These issues can also result from depressed commodity prices that ultimately reduce investment in new midstream facilities. Additionally, protests over construction of new pipelines and facilities, new or amended government regulations curtailing drilling activities in Colorado which could discourage investment in midstream facilities, extreme weather, fire, or other reasons could also negatively affect our production volumes and realized prices. +23 +Table of cont ents +Like other producers, we from time to time enter into volume commitments with midstream providers in order to induce them to provide increased capacity. If our production falls below the level required under these agreements, we could be subject to substantial shortfalls, deficiency, or similar fees. +Our undeveloped acreage must be drilled before lease expiration, and production must thereafter be maintained under applicable lease terms to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells and thereafter maintain production under applicable lease terms could result in substantial lease renewal costs or, if renewal is not feasible, loss of our lease and prospective drilling opportunities. +Unless production is established and thereafter maintained under applicable lease terms within the spacing or pooled units covering our undeveloped acreage, our leases for such acreage will expire. The cost to renew such leases may increase significantly and we may not be able to renew such leases on commercially reasonable terms or at all. Unexpected lease expirations could occur if our actual drilling activities or our ongoing production differ materially from our current expectations, and this could result in impairment charges. The risk of lease expiration is greater at times and in areas where the pace of our exploration and development activity slows or production declines or is otherwise shut-in. Our ability to drill, develop, and maintain production under applicable lease terms from the locations necessary to maintain our leases depends on a number of factors, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, and regulatory approvals, all of which are subject to risks and uncertainties. +We may incur losses as a result of title defects in the properties in which we invest or acquire. +Prior to acquiring oil and gas leases or interests, we engage oil and gas lease brokers or landmen (rather than title attorneys) to perform record title examinations. The existence of a material title deficiency can decrease a lease’s value and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property. +Our ability to produce crude oil, natural gas and NGLs economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling and completion operations or are unable to dispose of or recycle the water we use at a reasonable cost, in a timely manner and within applicable environmental rules. +Drilling and development activities such as hydraulic fracturing require the use of water and result in the production of wastewater. Our operations could be adversely impacted if we are unable to locate sufficient amounts of water or dispose of or recycle water used and produced in our exploration and production operations. The quantity of water required in certain completion operations, such as hydraulic fracturing, and changing regulations governing usage may lead to water constraints, supply concerns and regulatory issues, particularly in relatively arid climates such as eastern Colorado and western Texas. For example, increased drilling activity in the Delaware Basin in recent years has led to heightened concerns about water supply issues in the area and this may lead to regulatory actions, including rules providing local governments greater authority over water use, that adversely impact our operations. +Our operations depend on being able to reuse or dispose of wastewater in a timely and economic fashion. Wastewater from oil and gas operations is often disposed of through underground injection. Wells in the Delaware Basin typically produce relatively large amounts of water that require disposal and an increased number of earthquakes have been detected in the Delaware Basin in recent years. Some studies have linked earthquakes, or induced seismicity, in certain areas to underground injection, which is leading to increased public and regulatory scrutiny of injection safety. For example, in November 2022, a magnitude 5.4 earthquake occurred within the Delaware Basin. In response, the Texas Railroad Commission has taken actions to significantly reduce deep and shallow salt water disposal injection volumes in certain areas. This increased scrutiny applies to our Colorado operations as well, though to a lesser extent. +24 +Table of cont ents +Reduced commodity prices could result in significant impairment charges and significant downward revisions of proved reserves. +Commodity prices are volatile. Significant and rapid declines in prices have occurred in the past and may occur in the future. Low commodity prices could result in, among other things, significant impairment charges in the future. For example, we incurred impairment charges in a number of recent periods, including charges of $882.4 million in 2020, to write down assets. Similarly, the significant decline in commodity pricing that occurred in 2020 resulted in a reduced year-end proved reserve NYMEX price of $39.57 per barrel of crude and $1.99 per MMBtu of natural gas, a decrease of 29% and 23% respectively, from 2019. The decline in pricing resulted in a downward revision of 28.2 MMBoe to our reserves for year-end 2020 when compared to year-end 2019. The cash flow model we use to assess properties for impairment includes numerous assumptions, such as management’s estimates of future oil and gas production and commodity prices, the outlook for forward commodity prices and operating and development costs. All inputs to the cash flow model must be evaluated at each date the estimate of future cash flows is made for each producing basin. A significant decrease in long-term forward prices could result in a significant impairment for our properties. +Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. +The process of estimating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. In determining the estimates of reserve and economic evaluations, management utilizes independent petroleum engineers. The reserve estimates are based on assumptions regarding commodity prices, production levels and operating and development costs that may prove to be incorrect. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate and revisions in existing reserve estimates occur. +Reserve estimates are based on the volumes of crude oil, natural gas and NGLs that are anticipated to be economically recoverable from a given date forward based on economic conditions that exist at that date. The actual quantities of crude oil, natural gas and NGLs recovered will be different than the reserve estimates, in part because they will not be produced under the same economic conditions as are used for the reserve calculations. +You should not assume that the present value of the estimated future net cash flows from our proved reserves is the current market value of those reserves. Pursuant to SEC rules, the estimated discounted future net cash flows from our proved reserves, and the estimated quantity of those reserves, are based on the average of the previous 12-months’ first day of the month prices and costs as of the date of the estimate. Actual future prices and costs may be materially different. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production and changes in governmental regulations or taxes. Significant variances could materially affect the estimated quantities and present value of reserves shown in this Annual Report on Form 10-K and cause potential impairment charges. Sensitivity of our proved reserves as of December 31, 2022, assuming specified decreases in crude oil prices, are disclosed in Oil and Gas Production and Operations section in Item 1 and 2. Business and Properties, included elsewhere in this report. In addition, the 10 percent discount factor we use when calculating discounted future net cash flows (the rate required by the SEC) may not be the most appropriate discount factor based on interest rates currently in effect and risks associated with our properties or the industry in general. +Unless reserves are replaced as they are produced, our reserves and production will decline, which would adversely affect our future business, financial condition and results of operations. We may not be able to develop our identified drilling locations as planned. +Producing crude oil, natural gas and NGL reservoirs are generally characterized by declining production rates that may vary over time and exceed our estimates depending upon reservoir characteristics and other factors. Our future reserves and production and, therefore, our cash flows and income, are highly dependent on our ability to efficiently develop and exploit our current reserves and to economically find or acquire additional recoverable reserves. We may not be able to develop, discover or acquire additional reserves to replace our current and future production at acceptable costs. Our failure to do so would adversely affect our future operations, financial condition and results of operations. +25 +Table of cont ents +We have identified a number of well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including: +• crude oil, natural gas and NGL prices; +• the availability and cost of capital; +• drilling and production costs; +• availability and cost of drilling rigs, and equipment, supplies, chemicals, personnel and oilfield services; +• drilling results; +• lease expirations or limitations as to depth; +• midstream constraints; +• access to and availability of water sourcing and distribution systems; +• regulatory approvals; and +• other factors. +Because of these factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce crude oil, natural gas or NGLs from these or any other potential well locations. In addition, the number of drilling locations available to us will depend in part on the spacing of wells in our operating areas. An increase in well density in an area could result in additional locations in that area, but a reduced production performance from the area on a per-well basis. Conversely, a decrease in well density could result in fewer locations in an area but possibly increased production performance on a per-well basis. For example, after examining well performance and other factors, we determined in 2021 that our Delaware Basin position supported fewer wells per unit than previously assumed. Accordingly, our estimated well locations for our Delaware Basin position decreased from 135 to 65 in 2021. +Further, certain of the horizontal wells we intend to drill in the future may require pooling of our lease interests with the interests of third parties. Some states, including Colorado, allow the involuntary pooling of tracts in a relatively broad number of circumstances to facilitate exploration, though Colorado now requires applicants to own or secure consent from the owners of more than 45 percent of the minerals to be pooled. Other states, notably Texas, restrict involuntary pooling to a much narrower set of circumstances that generally do not apply to our leases and consequently these states rely primarily on voluntary pooling of lands and leases. In states such as Texas where pooling is accomplished primarily on a voluntary basis, or in states such as Colorado if we cannot meet the minimum requirement for ownership and consent, it may be more difficult to form units and, therefore, more difficult to fully develop a project if we own less than all (or cannot secure the ownership or consent of the required minimum amount) of the leasehold in the proposed units or one or more of our leases in the proposed units does not provide the necessary pooling authority. If third parties in the proposed units are unwilling to pool their interests with ours, we may be unable to require such pooling on a timely basis or at all, which would limit the total horizontal wells we can drill. Further, the number of available locations will depend in part on the expected lateral lengths of the horizontal wells we drill. Because the intended lateral length of a horizontal well is subject to change for a variety of reasons, our estimated drilling locations will change over time. For this and numerous other reasons, our actual drilling activities may materially differ from those presently identified. +Our inventory of drilling projects includes locations in addition to those that we currently classify as proved, probable and possible. The development of and results from these additional projects are more uncertain than those relating to probable and possible locations, and significantly more uncertain than those relating to proved locations. We have generally continued a steady pace of development in the Wattenberg Field over the past several years, and while our business acquisitions have increased our inventory, continued development has reduced our inventory of drilling locations. We also anticipate that our remaining locations in the field will not, on average, be as productive or as economic as many of those we have drilled in recent years, due to lower anticipated overall production or higher gas-to-oil ratios. In the Delaware Basin, our inventory is subject to, among other things, potential lease expirations (as to acreage and/or depths) and our continued analysis of geologic challenges in certain areas. For example, as noted above, in 2021, we reduced our estimated number of locations in the Delaware Basin due to geological issues. +The wells we drill may not yield crude oil, natural gas or NGLs in commercially viable quantities and productive wells may be less successful than we expect. +A prospect is a property on which our geologists have identified what they believe, based on available information, to be indications of hydrocarbon-bearing rocks. However, given the limitations of available data and technology, our geologists +26 +Table of cont ents +cannot know conclusively prior to drilling and testing whether crude oil, natural gas or NGLs will be present in sufficient quantities to repay drilling or completion costs and generate a profit. Furthermore, even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques do not enable our geologists to be certain as to the quantity of the hydrocarbons in those structures. As a result, our drilling activities may not be successful or economical, and our overall drilling success rate or our drilling success rate for activities in a particular area could decline. If a well is determined to be dry or uneconomic, which can occur even though it contains some crude oil, natural gas or NGLs, it is classified as a dry hole and plugged and abandoned in accordance with applicable regulations. For example, in 2022, our drilling activity in the third Bone Spring formation resulted in an exploratory dry hole. This generally results in the loss of the entire cost of drilling and completion to that point. Even wells that are completed and placed into production may not produce sufficient crude oil, natural gas and NGLs to be profitable, or they may be less productive and/or profitable than we expected. For example, the data we use to model anticipated results from wells in a particular area may prove to be not representative of actual results from typical wells in the area, and this could result in production that falls short of estimates reflected in our internal business plans and/or guidance, “type curve” or other disclosures we make to the public. This risk is higher for us in certain areas in the Delaware Basin that have relatively complex geological characteristics and correspondingly greater variability in well results. In addition, initial results from a well are not necessarily indicative of its performance over a longer period. +Drilling for and producing crude oil, natural gas and NGLs are high risk activities with many uncertainties that could adversely affect our business, financial condition and results of operations. +Drilling activities are subject to many risks, including the risk that we will not discover commercially productive reservoirs. Drilling can be unprofitable, not only due to dry holes, but also due to curtailments, delays or cancellations as a result of other factors, including: +• pressures or irregularities in geological formations; +• fires; +• floods, winter storms and other natural disasters and adverse weather conditions; +• loss of well control; +• loss of drilling fluid circulation and other facility or equipment malfunctions; +• title problems; +• facility or equipment malfunctions; +• unexpected operational events; +• shortages or delays in the delivery of equipment and services; +• inflation in exploration, drilling, completion and production costs; +• unanticipated environmental liabilities; and +• compliance with environmental and other governmental requirements. +Any of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, loss of wells, pollution, environmental contamination and regulatory penalties. For example, a loss of containment of hydrocarbons during drilling activities could potentially subject us to civil and/or criminal liability and the possibility of substantial costs, including for environmental remediation. We maintain insurance against various losses and liabilities arising from our operations; however, insurance against certain operational risks may not be available or may be prohibitively expensive relative to the perceived risks presented. In addition, we may not have coverage with respect to a pollution event if we are unaware of the event while it is occurring and are therefore unable to report the occurrence of the event to our insurance company within the time frame required under our insurance policy. Thus, losses could occur for which we have no effective insurance coverage. The occurrence of an event that is not fully covered by insurance and/or governmental or third-party responses to an event could have a material adverse effect on our business activities, financial condition and results of operations. We are currently involved in various remedial and investigatory activities at some of our wells and related sites. +In addition, certain technical risks relating to the drilling of horizontal wells - including those relating to our ability to fracture stimulate the planned number of stages and to successfully run casing the length of the well bore - have increased in recent years because we have increased the average lateral length of the horizontal wells we drill. Longer-lateral wells are also typically more expensive and require more time for preparation. In addition, we use multi-well pads instead of single-well sites. The use of multi-well pad drilling increases some operational risks because problems affecting the pad or a single well could adversely affect production from all of the wells on the pad. Pad drilling can also make our overall production, and therefore our revenue and cash flows, more volatile, because production from multiple wells on a pad will typically commence +27 +Table of cont ents +simultaneously. While we believe that we will be better served by using multi-well pads with longer lateral wells, the risk component involved in such drilling will be increased in some respects, with the result that we might find it more difficult to achieve economic success in our drilling program. +Our customers, counterparties and lenders may be unable to satisfy their contractual or legal obligations. +We are exposed to certain risks associated with our customers, contractual counterparties and lenders. These risks include credit risks associated with (i) customers who purchase our oil, NGLs and natural gas production, (ii) the collection of receivables from our joint interest partners for their proportionate share of expenditures made on projects we operate, and (iii) counterparties to our derivative financial contracts. We are also subject to performance risks associated with the non-delivery, or delayed delivery, of contracted products or services, including the transportation and processing of our oil, NGLs and natural gas production and liquidity risk in the event one or more lenders under our existing credit facility are unable to perform their funding obligations. In the event a customer, contractual counterparty or lender fails to satisfy their obligations, our business, financial condition and results of operations could be materially and adversely affected. +Competition in our industry is intense, which may adversely affect our ability to succeed. +Our industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for and produce crude oil, natural gas and NGLs, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive properties and exploratory prospects, evaluate, bid for and purchase a greater number of properties and prospects than we can. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, larger companies may have a greater ability to continue exploration activities during periods of low commodity prices. Larger competitors may also be able to absorb the burden of present and future federal, state, local and other laws and regulations more easily than we can, which could adversely affect our competitive position. Additionally, larger competitors may have greater financial, technical and personnel resources that may provide technological advantages and may in the future allow them to implement new technologies before we can. These factors could adversely affect our operations and our profitability. +Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel. +Our future success depends to a large extent on the services of our key employees. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise. +Further, our operations require laborers, including contractors, skilled in multiple disciplines, such as heavy equipment operators, mechanics and engineers, among others. A shortage in skilled labor can increase the risk of safety issues, decrease our overall productivity and business results and increase the labor, health care and benefits costs we incur to attract and retain high quality employees with the right skill sets to meet our needs. For example, in 2022 we experienced an increase in contractor injuries at our worksites, many attributable to the labor conditions in the oilfield, including a greater number of short-service contractor employees. +Acquisitions of properties are subject to the uncertainties of evaluating recoverable reserves and potential environmental and other liabilities. +Acquisitions of producing and undeveloped properties have been an important part of our growth over time. We expect acquisitions will also contribute to our future growth. Successful acquisitions require an assessment of a number of factors, many of which are beyond our control. These factors include recoverable reserves, development potential, future commodity prices, operating costs, title issues and potential environmental and other liabilities. Such assessments are inexact and their accuracy is inherently uncertain. In connection with our assessments, we generally perform engineering, environmental, geological and geophysical reviews of the acquired properties that we believe are generally consistent with customary industry practices. However, such reviews are not likely to permit us to become sufficiently familiar with the properties to fully assess +28 +Table of cont ents +their deficiencies and capabilities. We do not typically inspect every well prior to an acquisition and our ability to evaluate undeveloped acreage is inherently imprecise. Even when we inspect a well, we may not always discover structural, subsurface and environmental problems that may exist or arise after the acquisition. In some cases, our review prior to signing a definitive purchase agreement may be even more limited. In addition, we often acquire acreage without any warranty of title except as to claims made by, through or under the transferor. +When we acquire properties, we will generally have potential exposure to liabilities and costs for environmental and other problems existing on the acquired properties, and these liabilities may exceed our estimates. We may not be entitled to contractual indemnification associated with acquired properties. We often acquire interests in properties on an “as is” basis with no or limited remedies for breaches of representations and warranties. Therefore, we could incur significant unknown liabilities, including environmental liabilities or losses due to title defects, in connection with acquisitions for which we have limited or no contractual remedies or insurance coverage. In addition, the acquisition of undeveloped acreage is subject to many inherent risks and we may not be able to realize efficiently, or at all, the assumed or expected economic benefits of acreage that we acquire. +Additionally, significant acquisitions can change the nature of our operations depending upon the character of the acquired properties, which may have substantially different operating and geological characteristics or may be in different geographic locations than our existing properties. These factors can increase the risks associated with an acquisition. Acquisitions also present risks associated with the additional indebtedness that may be required to finance the purchase price and any related increase in interest expense or other related charges. +Some of our acquisitions are structured as asset trades or exchanges. These transactions may give rise to any or all of the foregoing risks. In addition, transactions of this type create a risk that we will undervalue the properties we transfer to the counterparty in the trade or exchange or overvalue the properties we receive. Such an undervaluation or overvaluation would result in the transaction being less favorable to us than we expected. +We operate in a litigious environment. The cost of defending any suits brought against us, and any judgments or settlements resulting from such suits, could have an adverse effect on our results of operations and financial condition. +Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, employment litigation, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. For example, in January 2021, a purported class action lawsuit was filed against us by a royalty owner alleging we have been improperly deducting certain post-production costs from the owner’s oil royalty payments. While we intend to vigorously defend this suit, the outcome of legal proceedings is inherently uncertain. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management attention and other factors. In addition, the resolution of any such legal or other proceedings could result in penalties or sanctions, settlement costs and/or judgments, consent decrees or orders requiring a change in our business practices, any of which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties, sanctions or costs may be insufficient. Judgments and estimates to determine accruals or the anticipated range of potential losses related to legal and other proceedings could change from one period to the next, and such changes could be material. Information regarding legal proceedings can be found in Item 3. Legal Proceedings included elsewhere in this report. +Our business could be negatively impacted by security threats, including cybersecurity threats and other disruptions. +We face various security threats, including attempts by third parties to gain unauthorized access to, or control of, competitive information or to render data or systems corrupted or unusable; threats to the safety of our employees; threats to the security of our infrastructure or third-party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. There can be no assurance that the procedures and controls we use to monitor these threats and mitigate our exposure to them will be sufficient to prevent them from materializing. +Our industry has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain exploration, development and production activities. We depend on digital technology, including information systems and related infrastructure, as well as cloud applications and services, to store, transmit, process and record sensitive information (including but not limited to trade secrets, employee information and financial and operating data), communicate with our employees and business partners, and for many other activities related to our business. In addition, computer systems control +29 +Table of cont ents +the oil and gas production and processing equipment that are necessary to deliver our production to market. Critical infrastructure targets, such as energy-related assets and transportation assets, may be at greater risk of future cyber-attacks than other targets. A disruption or failure of these systems, or of the networks and infrastructure on which they rely, may cause damage to critical production, distribution and/or storage assets, delay or prevent delivery to markets, or make it difficult to accurately account for production and settle transactions. The various procedures, facilities, infrastructure and controls we utilize to monitor these threats and mitigate our exposure to such threats are costly and labor intensive. Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring. The continuing and evolving threat of cybersecurity attacks has resulted in increased regulatory focus on prevention, which could potentially elevate costs, and failure to comply with these regulations could result in penalties and potential legal liability. +As dependence on digital technologies has increased in our industry cyber incidents, including deliberate attacks and unintentional events, have also increased. Our systems and infrastructure are, and those of our business partners, including vendors, service providers, operating partners, purchasers of our production and financial institutions may be, subject to damage or interruption from a number of potential sources including natural disasters, software viruses or other malware, power failures, cyber-attacks and other events. We and our business partners also face various other cyber-security threats from criminal hackers, state-sponsored intrusion, industrial espionage and employee malfeasance, including threats to gain access to sensitive information or to render data or systems unusable. +Our technologies, systems and networks, and those of our business partners, may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, theft of property or other disruption of our business operations and planned business transactions. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period. To our knowledge, we have not suffered material losses related to cyber-attacks to date; however, there can be no assurance that we will not suffer material losses in the future either as a result of an interruption to or a breach of our systems or those of our third-party vendors and service providers. If we were successfully attacked, we could incur substantial remediation and other costs or suffer other negative consequences, such as a loss of competitive information, critical infrastructure, personnel or capabilities essential to our operations. Insurance may not provide adequate protection from these risks. Events of this nature could have a material adverse effect on our reputation, financial condition, results of operations or cash flows. Moreover, as the sophistication of cyber-attacks continues to evolve, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities. +Risks Relating to Financial Matters +Our development and exploration operations require substantial capital, and we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and a decline in our production and reserves, and ultimately our profitability. Lender hesitancy to offer financing to our industry may increase this risk. +Our industry is capital intensive. We expect to continue to make substantial capital expenditures for the exploration, development, production and acquisition of crude oil, natural gas and NGL reserves. To date, we have financed capital expenditures primarily with bank borrowings under our revolving credit facility, cash generated from operations and proceeds from capital markets transactions and the sale of properties. We intend to finance our future capital expenditures utilizing similar financing sources. Our cash flows from operations and access to capital are subject to a number of variables, including: +• our proved reserves; +• the amount of crude oil, natural gas and NGLs we are able to produce from existing wells; +• the prices at which crude oil, natural gas and NGLs are sold; +• the costs to produce crude oil, natural gas and NGLs; and +• our ability to acquire, locate and produce new reserves. +If our revenues or the borrowing base under our revolving credit facility decrease as a result of lower commodity prices, operating difficulties or for any other reason, our need for capital from other sources could increase, and there can be no assurance that such other sources of capital would be available at that time on reasonable terms or at all. If we raise funds by issuing additional equity securities, this would have a dilutive effect on existing shareholders. If we raise funds through the incurrence of debt, the risks we face with respect to our indebtedness would increase and we would incur additional interest expense. +30 +Table of cont ents +Additionally, due to increasing climate change awareness, some lenders have expressed a hesitancy to lend to oil and gas producers, and may require terms less favorable to the producers or, in some cases, may refuse to provide financing to the industry altogether. The number of lenders participating in our revolving credit facility decreased in connection with the amendment and restatement of the facility in 2021, and may decline further in the future. Our inability to obtain sufficient financing on acceptable terms would adversely affect our financial condition and profitability. +The cost of servicing, and risks related to refinancing, our debt could adversely affect our business. Those risks could increase if we incur more debt. +As of December 31, 2022, we had total long-term debt of $1.32 billion. Servicing our indebtedness and satisfying our other obligations will require a significant amount of cash, and cash flow from operating activities and other sources may not be sufficient to fund our liquidity needs. Our ability to pay interest and principal on our indebtedness and to satisfy our other obligations will depend on our future operating performance, our financial condition and the availability of refinancing indebtedness, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control. +A substantial decrease in our operating cash flow or an increase in our expenses could make it difficult for us to meet debt service requirements and could require us to modify our operations, including by curtailing our exploration and drilling programs, reducing our capital expenditures, selling assets, refinancing all or a portion of our existing debt or obtaining additional financing. We may not be able to complete any such steps on satisfactory terms. Any inability to generate sufficient cash flows to satisfy our debt obligations or contractual commitments, or to refinance our debt on commercially reasonable terms, could materially and adversely affect our financial condition and results of operations. In addition, our financing costs are affected by changing macroeconomic factors, including in particular interest rates. For example, under our revolving credit facility, one of the applicable interest rates on amounts borrowed at the end of 2021 was 0.1% and has since increased to 4.4% as of the end of 2022, resulting in higher costs on our outstanding debt. +Covenants in our debt agreements currently impose, and future financing agreements may impose, operating and financial restrictions. +Our current debt agreements contain restrictions, and future financing agreements may contain additional restrictions, on our activities, including covenants that restrict our and our restricted subsidiaries’ ability to: +• incur additional debt; +• pay dividends on, redeem or repurchase stock; +• create certain liens; +• make specified types of investments; +• apply net proceeds from certain asset sales; +• engage in transactions with our affiliates; +• engage in sales and leaseback transactions; +• merge or consolidate; and +• sell, assign, transfer, lease, convey or dispose of assets. +Our revolving credit facility is secured by substantially all of our oil and gas properties as well as a pledge of all ownership interests in our current operating subsidiaries. The restrictions contained in our current or future debt agreements, including the possible addition of ESG-related metrics pursuant to our existing amended and restated credit agreement, may prevent us from taking actions that we believe would be in the best interest of our business, or may increase cost of borrowings in the future. In addition, our ability to comply with covenants and restrictions in our debt agreements in the future is uncertain and will be affected by the levels of cash flows from operations and events or circumstances beyond our control. Our failure to comply with any of these restrictions and covenants could result in a default under our debt agreements. In the event of such a default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder, and under other agreements to which a cross-default or cross-acceleration provision applies, to be due and payable, together with accrued and unpaid interest; the lenders under our revolving credit facility could elect to terminate their commitments, cease making further loans and institute foreclosure proceedings against our assets; and we could be forced into bankruptcy or liquidation. +31 +Table of cont ents +Our lenders have sole discretion to set our borrowing availability based on anticipated commodity prices and corporate outlook. +The revolving credit facility limits the amounts we can borrow to a borrowing base amount, determined by the lenders in their sole discretion based upon projected revenues from the properties securing their loan. Decreases in the price of crude oil, natural gas or NGLs may have an adverse effect on the borrowing base. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under the revolving credit facility. Outstanding borrowings in excess of the borrowing base must be repaid immediately unless we pledge other crude oil and natural gas properties as additional collateral. We do not currently have any substantial unpledged properties, and we may not have the financial resources in the future to make any mandatory principal prepayments required under the revolving credit facility. Our inability to borrow additional funds under our revolving credit facility could adversely affect our operations and our financial results. +Our commodity derivative activities could result in financial losses or reduced income from failure to perform by our counterparties, could limit our potential gains from increases in prices and could result in volatility in our net income. +We use commodity derivatives for a portion of the production from our own wells to achieve more predictable cash flows, to reduce exposure to adverse fluctuations in commodity prices, and to allow our natural gas marketing company to offer pricing options to natural gas sellers and purchasers. These arrangements expose us to the risk of financial loss in some circumstances, including when purchases or sales are different than expected or the counterparty to the commodity derivative contract defaults on its contractual obligations. In addition, many of our commodity derivative contracts are based on WTI or another crude oil or natural gas index price. The risk that the differential between the index price and the price we receive for the relevant production may change unexpectedly makes it more difficult to hedge effectively and increases the risk of a hedging-related loss. Also, commodity derivative arrangements may limit the benefit we would otherwise receive from increases in the prices for the relevant commodity. +At December 31, 2022, we had hedged a total of 25.3 MMBbls crude oil for 2023 to 2025 and 214.8 BBtu of natural gas for 2023 to 2025. These hedges may be inadequate to protect us from continuing and prolonged declines in crude oil and natural gas prices. +Since we do not designate our commodity derivatives as cash flow hedges, we do not currently qualify for use of hedge accounting; therefore, changes in the fair value of commodity derivatives are recorded in our income statements and our net income is subject to greater volatility than it would be if our commodity derivative instruments qualified for hedge accounting. For instance, if commodity prices rise significantly, this could result in significant non-cash charges during the relevant period, which could have a material negative effect on our net income. +We may be unable to return capital to our stockholders, and there is no assurance we will pay any dividends on or repurchase shares of our common stock in the future or at levels anticipated by our stockholders. +Starting in 2022, we adopted a return of capital program with a quarterly base dividend and a return of approximately 60 percent or more of our post base dividend adjusted free cash flows, a non-U.S. GAAP financial measure, through stock repurchases and special dividends, as needed. Additionally, since the first quarter of 2022, our board of directors has approved the increases in quarterly base dividend from $0.12 per share to $0.40 per share. Our ability to pay cash dividends and to otherwise return capital to shareholders in the future depends on, among other things, our liquidity, financial condition, financial requirements, contractual restrictions, restrictions imposed by applicable law and other factors considered relevant by our board. Our board, based on this evaluation, may decide not to declare future dividends or otherwise return capital to shareholders, or may do so at levels that are less than anticipated. +Our capital return program may change from time to time, and we cannot guarantee we will continue to pay dividends or repurchase shares. Our announcement of capital return programs does not obligate us to pay any particular dividend amount (except with respect to dividends already declared) or repurchase any specific dollar amount or number of shares of common stock. A reduction, suspension or change in our capital return programs could have a negative effect on our stock price. +32 +Table of cont ents +The price of our common stock has been and may continue to be highly volatile, which may make it difficult for shareholders to sell our common stock when desired or at attractive prices. +The market price of our common stock is highly volatile and we expect it to continue to be volatile for the foreseeable future. Adverse events including changes in production volumes, worldwide demand and prices for crude oil and natural gas, regulatory developments, and changes in securities analysts’ estimates of our financial performance could negatively impact the market price of our common stock. General market conditions, including the level of, and fluctuations in, the trading prices of securities generally could also have a similar negative impact. The stock markets regularly experience price and volume volatility that affects many companies’ stock prices without regard to the operating performance of those companies. Volatility of this type may affect the trading price of our common stock. Similar factors could also affect the trading prices of our senior notes. +Tax law changes could have an adverse effect on our financial position, results of operations and cash flows. +As of December 31, 2022, we have fully released our tax valuation allowance and we anticipate incurring federal and state income taxes in 2023. In addition, substantive changes to existing federal income tax laws have been proposed that, if adopted, would repeal many tax incentives and deductions that are currently used by U.S. oil and gas companies and would impose new taxes. The proposals include: repeal of the percentage depletion allowance for oil and gas properties; elimination of the ability to fully deduct intangible drilling costs in the year incurred; and an increase in the geological and geophysical amortization period for independent producers. Additional proposed general tax law changes include raising tax rates on both domestic and foreign income and imposing a new alternative minimum tax on book income. Further, many states are currently in deficits, and have been enacting laws eliminating or limiting certain deductions, carryforwards and credits in order to increase tax revenue. Should the U.S. or any relevant state pass tax legislation limiting any currently allowed tax incentives or deductions, our taxes would increase, potentially significantly, which would have a negative impact on our net income and cash flows. This could also reduce our drilling activities. Since future changes to federal and state tax legislation and regulations are unknown, we cannot predict the ultimate impact such changes may have on our business. +ITEM 1B. UNRESOLVED STAFF COMMENTS +None. +ITEM 3. LEGAL PROCEEDINGS +Information regarding our legal proceedings can be found in Note 12 - Commitments and Contingencies - Litigation and Legal Items included in Item 8. Financial Statements and Supplementary Data to our consolidated financial statements included elsewhere in this report. +Environmental. Due to the nature of the natural gas and oil industry, we are exposed to environmental risks. We have various policies and procedures to minimize and mitigate the risks from environmental contamination. We conduct periodic reviews and simulated drills to identify changes in our environmental risk profile. Liabilities are recorded when environmental damages resulting from past events are probable and the costs can be reasonably estimated. Except as discussed herein, we are not aware of any material environmental claims existing as of the date of the filing of this report that have not been provided for or would otherwise have a material impact on our financial statements; however, there can be no assurance that current regulatory requirements will not change or that unknown potential past non-compliance with environmental laws or other environmental liabilities will not be discovered on our properties. Accrued environmental liabilities are recorded in other accrued expenses in the consolidated balance sheets. +Following a self-audit of final reclamation activities associated with site retirements, we formally disclosed identified deficiencies to the Colorado Oil and Gas Conservation Commission (“COGCC”) in December 2019. To resolve the alleged violations in July of 2021, the COGCC and PDC jointly agreed to an Administrative Order by Consent (“AOC”) which assessed penalties in the amount of approximately $500,000, with approximately $350,000 suspended pending PDC meeting certain conditions of the AOC. We are implementing programs to meet the requirements of the AOC and correct any identified deficiencies. +Commencing in early 2020, we conducted a comprehensive air quality compliance audit over the facilities acquired in +33 +Table of cont ents +the SRC Acquisition. Through the self-audit process, we identified certain deficiencies and disclosed them to CDPHE and the EPA in July 2021. We do not believe potential penalties and other expenditures associated with the deficiencies identified will have a material effect on our financial condition or results of operations, but such penalties may exceed $300,000. +In August 2021 and November 2021, the COGCC issued us a Notice of Alleged Violation (“NOAV”) related to the timing of wellhead pressure test reporting for certain wells in the Wattenberg Field. Pursuant to the NOAVs, we have conducted and submitted a comprehensive audit of our wellhead pressure testing and reporting processes. We have updated our processes to mitigate against the possibility of the alleged violations occurring in the future. We do not anticipate a material effect on our financial condition or results of operations. However, the potential penalties may exceed $300,000. +In June 2022, we received Compliance Advisories from the Colorado Air Pollution Control Division for alleged historical air quality violations over facilities acquired in the SRC Acquisition. In January 2023, we paid a total penalty of approximately $340,000 to resolve and settle the Compliance Advisories. +In July 2022, we received a Notice of Violation/Cease and Desist Order (“NOV”) from the CDPHE, pursuant to a Great Western Operating Company May 2021 Stormwater Permit Audit and subsequent Compliance Advisory. Having acquired the Great Western assets on May 6, 2022, we are working with the CDPHE to ensure ongoing compliance and resolve the NOV. We do not anticipate potential penalties and other expenditures associated with the NOV will have a material effect on our financial condition or results of operations, but such penalties will likely exceed $300,000. +Clean Air Act Agreement and Related Consent Decree. While we continue to implement the requirements of a consent decree entered into with the EPA and CDPHE in 2017, such consent decree was terminated with no further penalties as of December 15, 2022. +Further, we could be the subject of other enforcement actions by regulatory authorities in the future relating to our past, present or future operations. +ITEM 4. MINE SAFETY DISCLOSURES +Not applicable. +34 +Table of cont ents +PART II +ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES +Holders of Record +Our common stock, par value $0.01 per share, is traded on the NASDAQ Global Select Market under the symbol “PDCE”. As of February 14, 2023, we had approximately 363 stockholders of record. +Dividend Policy +Our board of directors have authority to declare dividends to the holders of our common stock. Our board of directors intent is to continue the payment of dividends to the holders of our common stock in the future. However, the dividend program and payment of any future dividends will be made at the discretion of our board of directors and will depend on our results of operations, cash flows, financial position and capital requirements, as well as general business conditions, legal, tax and regulatory factors deemed relevant at the time to declare such dividends. +Additionally, our revolving credit facility, as well as the indentures governing our 6.125% senior notes due 2024 (“2024 Senior Notes”) and our 5.75% senior notes due 2026 (the “2026 Senior Notes”), the terms of which are summarized in Note 9 - Long-term Debt in Item 8. Financial Statements and Supplementary Data included elsewhere in this report, include restrictions based on our leverage and certain other financial metrics that could impact our ability to pay cash dividends. As we declare dividends in the future, we will monitor compliance with such restrictions. +Repurchase of Equity Securities +The following table presents information about our purchases of our common stock during the year ended December 31, 2022: +Period +Total Number of Shares Purchased (1) (2) +Average Price Paid per Share +Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1) +Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans or Programs (in millions) +January 592,567 $ 55.54 501,000 $ 159.5 +February 71,735 56.73 4,340 1,250.0 +March 825,680 69.71 820,555 1,192.8 +April 714,091 74.22 613,658 1,147.4 +May 1,382,199 69.33 1,381,407 1,051.6 +June 970,777 75.74 970,777 978.1 +July 866,538 58.71 864,738 927.3 +August 2,187,393 63.38 2,187,240 788.7 +September 1,153,214 62.22 1,153,214 716.9 +October 718,215 67.82 714,088 668.5 +November 1,797,291 76.78 1,785,771 531.3 +December 1,148,300 66.69 1,148,300 454.7 +Total purchases 12,428,000 $ 67.71 12,145,088 $ 454.7 +_____________ +(1) We reinstated our stock repurchase program in February 2021 and in February 2023, our board of directors approved a $750 million increase in the size of the program which we currently anticipate fully utilizing by December 31, 2025. Our stock repurchase program does not require any specific number of shares to be acquired, and can be modified or discontinued by our board of directors at any time. +(2) Purchases outside of our stock repurchase program represent shares withheld from employees for the payment of their tax liabilities related to the vesting of securities issued pursuant to our stock-based compensation plans. The withheld shares are not considered common stock repurchased under the stock repurchase program. +35 +Table of cont ents +Stockholder Performance Graph +The following performance graph and related information shall deemed to be furnished, but not filed with the SEC. +The graph below matches the cumulative 5-Year total return of our common stock with the cumulative total returns of the Standard and Poor’s 500 Index (“S&P 500 Index”) and Standard and Poor’s Oil and Gas Exploration and Production ETF (“XOP”). The cumulative total stockholder return assumes that $100 was invested, including reinvestment of dividends, if any, in our common stock on December 31, 2017 and tracks it through December 31, 2022, in the S&P 500 Index and XOP on the same date. The results shown in the graph below are not necessarily indicative of future stock price performance. +COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN +Among PDC Energy, Inc., the S&P 500 Index, +and XOP +Year Ended December 31, +2017 2018 2019 2020 2021 2022 +PDC Energy 100.00 57.74 50.78 39.83 96.43 129.22 +S&P 500 100.00 95.62 125.72 148.85 191.58 156.89 +XOP 100.00 80.50 90.17 58.24 108.95 172.69 +36 +Table of cont ents +ITEM 6. [RESERVED] +This Item has been omitted as we are no longer required to provide five years of selected financial data. +ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +The following discussion and analysis should be read in conjunction with our consolidated financial statements and related notes included in Item 8. Financial Statements and Supplementary Data and also with Item 1A. Risk Factors of this report. A discussion of changes in our results of operations and liquidity from 2020 to 2021 has been omitted from this report but can be found in Item 7. Management’s Discussion and Analysis , of our Annual Report on Form 10-K for the year ended December 31, 2021, filed with the SEC on February 28, 2022. Further, we encourage you to review the Special Note Regarding Forward-Looking Statements in Part I of this report. +EXECUTIVE SUMMARY +2022 Financial Overview of Operations and Liquidity +Market Conditions +The crude oil and natural gas industry is cyclical and commodity prices are inherently volatile. Commodity prices reflect global supply and demand dynamics as well as the geopolitical and macroeconomic environment. During 2022, crude oil and natural gas prices experienced high levels of volatility. NYMEX WTI spot prices for crude oil reached a high of $130.50 per barrel in March and a low of $70.08 per barrel in December and NYMEX Henry Hub spot prices for natural gas reached a high of $9.85 per MMBtu in August and a low of $3.46 per MMBtu in November. By the end of 2022, crude oil and natural prices had declined significantly from the levels seen earlier in the year. +Crude Oil Markets +During the first half of 2022, crude oil pricing generally increased due to increased demand, restrained OPEC+ production and uncertainties resulting from the Russian invasion of Ukraine. However, throughout 2022, the U.S. has experienced the highest inflation rates since 1981 resulting mainly from the global recovery from COVID-19, supply chain disruptions, higher labor costs, and higher energy costs. To address the increasing inflation rates, the U.S. Federal Reserve started increasing the benchmark federal funds interest rate. The magnitude and overall effectiveness of these actions remains uncertain, but such monetary policy changes can increase the risk of economic slowdown and/or lead to a recession. A slowdown or recession can cause a decrease in short-term or long-term demand for commodities, resulting in industry oversupply and a potential for lower commodity prices, which would impact our drilling program and further increase the volatility of our common stock price. +Natural Gas and NGL Markets +In addition to the crude oil market drivers noted above, natural gas and NGL prices are also affected by structural changes in supply and demand, growth in levels of liquified natural gas and liquified petroleum gas exports and deviations from seasonally normal weather. Europe’s shift away from Russia’s natural gas has led to Europe becoming increasingly dependent on U.S. LNG exports, creating new sources of demand for U.S. natural gas. +Lower inventory levels and lack of reinvestment in supply growth led to higher natural gas and NGL prices in 2022. However, a warmer winter in some parts of the world and a weakened economy has driven down the price of natural gas in early 2023. +37 +Table of cont ents +Financial Matters +Year ended December 31, 2022 +• Production volumes increased to 85.0 MMboe in 2022, an increase of 19 percent compared to 71.3 MMboe in 2021, primarily driven by production volumes from the Great Western Acquisition and as a result of our turn-in-line activities in 2022. +• Crude oil, natural gas and NGLs sales increased to $4.3 billion in 2022 compared to $2.6 billion in 2021, primarily due to a 41 percent increase in weighted average realized commodity prices and a 19 percent increase in production volumes between periods. +• Negative net cash settlements from our commodity derivative contracts increased to $880 million in 2022 compared to $410 million in 2021 due to continued improvement in commodity pricing year over year and additional commodity derivatives assumed in the Great Western Acquisition. +• Combined revenue from crude oil, natural gas and NGLs sales and net settlements from our commodity derivative instruments increased 59 percent to $3.4 billion from $2.1 billion in 2021. +• Net income increased to $1,778 million, or $18.49 per diluted share, compared to $522 million, or $5.22 per diluted share, in 2021, primarily due to (i) an increase in crude oil, natural gas and NGLs sales of $1,744 million, (ii) a $238 million decrease in net commodity risk management loss and (iii) a gain on bargain purchase in the Great Western Acquisition of $90 million . These positive factors were partially offset by (i) a $428 million increase in income tax expense (ii) a $253 million increase in production costs and (iii) a $115 million increase in depreciation, depletion and amortization expense between periods. +• Adjusted EBITDAX, a non-U.S. GAAP financial measure, was $2.7 billion compared to $1.6 billion in 2021, primarily due to an increase in sales of $1.3 billion, net of negative net derivative settlements, and a $90 million gain on bargain purchase recognized in 2022, partially offset by an increase in costs experienced in operations between periods. +• Cash flows from operations increased to $2.8 billion compared to $1.5 billion in 2021 primarily due to an increase in sales of $1.3 billion, net of negative net derivative settlements, partially offset by an increase in costs experienced in operations between periods. Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased to $2.5 billion compared to $1.5 billion in 2021. Adjusted free cash flows, a non-U.S. GAAP financial measure, increased to $1,421 million from $949 million in 2021. +See Reconciliation of Non-U.S. GAAP Financial Measures below for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures. +Great Western Acquisition +On May 6, 2022, we completed the acquisition of Great Western for approximately $1.4 billion, inclusive of Great Western’s net debt. Great Western was an independent oil and gas company focused on the exploration, production and development of crude oil and natural gas in the Wattenberg Field of Colorado. The consideration paid was $542.5 million in cash and approximately 4.0 million shares of our common stock, valued at $293.3 million on the acquisition date. In addition, we paid off Great Western’s secured credit facility totaling $235.8 million, and paid $361.2 million to terminate Great Western’s 12 percent senior secured notes due 2025, inclusive of unpaid accrued interest and a premium for early termination. The cash portion of the purchase price and the termination of Great Western’s debt was funded through a combination of cash on hand and availability under our revolving credit facility. As a result of the Great Western Acquisition, we acquired approximately 54,000 net acres in the core Wattenberg Field and production of approximately 50,000 Boe per day. +38 +Table of cont ents +Drilling, Completion and Vertical Wells Abandonment Overview +In the Wattenberg Field, we operated one full-time drilling rig and one full-time completion crew during 2022, added a second full-time drilling rig in March 2022 and a third full-time drilling rig plus an intermittent completion crew in May 2022 upon closing the Great Western Acquisition . In addition, we operated one full-time drilling rig during 2022 and had one completion crew in the first half of 2022 in the Delaware Basin. Our total capital investments in crude oil and natural gas properties for the year ended December 31, 2022 were $1.1 billion. Pursuant to our plugging and abandonment program, we operated a full-time workover rig in the Wattenberg Field in 2022. The workover rig was focused on our legacy vertical wells to assist in our horizontal drilling program and to reduce our overall produced well emissions. Separate from our capital investments, we spent $21 million on this program in 2022. +The following table summarize our drilling, completion and vertical well abandonment activities for the year ended December 31, 2022: +Operated Wells +Wattenberg Field Delaware Basin Total +Gross Net Gross Net Gross Net +In-process as of December 31, 2021 +143 133 21 21 164 154 +Wells spud 174 161 13 13 187 174 +Wells acquired in-process (1) +48 41 — — 48 41 +Wells turned-in-line (164) (150) (19) (19) (183) (169) +Developmental and exploratory dry hole (1) (1) (3) (3) (4) (4) +In-process as of December 31, 2022 +200 185 12 12 212 197 +Plugged and abandoned - Vertical Wells 253 244 — — 253 244 +_____________ +(1) Represents in-process wells we obtained as part of the Great Western Acquisition. +Our in-process wells represent wells that are in the process of being drilled or have been drilled and are waiting to be fractured and/or for gas pipeline connection. Our in-process wells are generally completed and turned-in-line within two years of drilling. +Capital Returns +Stock Repurchase Program. In February 2022, our board of directors approved a new stock repurchase program that reset the total repurchase value to $1.3 billion, which we currently anticipate fully utilizing by December 31, 2023. We repurchased 12.1 million shares of outstanding common stock at a cost of $823 million for the year ended December 31, 2022. As of December 31, 2022, $455 million remained available for repurchase under the program. In February 2023, our board of directors approved a $750 million increase in the size of the program, which we currently anticipate fully utilizing by December 31, 2025. +Dividends . Our board of directors approved the declaration and payment of a quarterly cash dividend of $0.25 per share of common stock in the first quarter of 2022 and increased our base quarterly dividend to $0.35 per share of common stock in the second quarter of 2022. In December 2022, our board of directors declared and paid a special dividend of $0.65 per share of our common stock in addition to the regular fourth quarter dividend. For the year ended December 31, 2022, our dividends declared totaled $184 million or $1.95 per share of outstanding common stock. In February 2023, our board of directors approved an increase in the quarterly base dividend from $0.35 to $0.40 per share. +2023 Operational and Financial Outlook +We anticipate that our production for 2023 will range between 255,000 Boe to 265,000 Boe per day, of which approximately 82,000 Bbls to 86,000 Bbls is expected to be crude oil. Our planned 2023 capital investments in crude oil and natural gas properties, which we expect to be between $1,350 million and $1,500 million, are focused on continued execution of our development plans in the Wattenberg Field and the Delaware Basin. Our 2023 capital budget and operating costs may continue to be impacted by cost inflation, supply chain constraints and availability of labor services. +39 +Table of cont ents +We have operational flexibility to control the pace of our capital spending. As we execute our capital investment program, we continually monitor, among other things, expected rates of return, the political environment and our remaining inventory to best meet our short- and long-term corporate strategy. We may revise our 2023 capital investment program during the year as a result of, among other things, changes in commodity prices or our internal long-term outlook for commodity prices, the cost of services for drilling and well completion activities, drilling results, changes in our borrowing capacity, a significant change in cash flows, regulatory issues, requirements to maintain continuous activity on leaseholds and acquisition and divestiture opportunities. +Wattenberg Field. We are drilling in the horizontal Niobrara and Codell plays in the rural areas of the core Wattenberg Field. Our 2023 capital investment program for the Wattenberg Field represents approximately 80 percent of our expected total capital investments in crude oil and natural gas properties. Our plan includes spudding and turning-in-line 200 to 225 operated wells. To meet our development plan, we intend on running three full-time horizontal drilling rigs and one full-time completion crew plus an intermittent completion crew during the year. As of December 31, 2022, we have approximately 200 gross operated DUCs and 915 approved permitted or CAP locations (i.e., locations that are contemplated by an approved CAP but still require approval under an OGDP). +Delaware Basin. Total capital investments in crude oil and natural gas properties in the Delaware Basin for 2023 are expected to be approximately 20 percent of our total capital investments. In 2023, we anticipate spudding and turning-in-line 15 to 25 operated wells. +We are committed to our disciplined approach to managing our development plans. Based on our current production forecast for 2023, we expect 2023 cash flows from operations to exceed our capital investments in crude oil and natural gas properties. Our first priority is to pay our quarterly base dividend of $0.40 per share. Then we expect to use approximately 60 percent or more of our remaining adjusted free cash flow, a non-U.S. GAAP financial measure, for share repurchases and special dividends, as needed. Any remaining adjusted free cash flows will be used for reducing debt and other general corporate purposes. +Regulatory and Political Updates +Colorado law requires an operator to obtain an OGDP prior to initiating development work relating to a well. The OGDP process streamlines single pad locations or proximate multi-pad locations into a single permitting package. +Operators in Colorado also have an option to pursue a CAP. A CAP is designed to represent an overview of oil and gas development over a larger area over a longer period of time through means including a comprehensive cumulative impact analysis, an alternative location analysis, and extensive communication with both local elected officials and communities. A CAP will include multiple OGDPs within its boundaries. +In June 2022, the COGCC granted PDC unanimous approval for a 69-well OGDP and a 30-well OGDP acquired in the Great Western Acquisition, our second and third approvals under the new Colorado permitting process. Additionally, in December 2022, the COGCC unanimously approved our first CAP, filed in December 2021, which encompasses approximately 450 wells in Weld County, Colorado. Following the approval of the CAP, we will submit individual OGDP packages for each of the locations within the CAP. The CAP, along with our prior OGDPs, represent the majority of our projected Wattenberg Field turn-in-line activity into 2028 based on our current pace and drilling plan in 2023. +Environmental, Social and Governance +We are committed to a meaningful and measurable ESG strategy. Our mission of being a cleaner, safer and more socially responsible company begins with a sound strategy, is supported in the boardroom and is overseen by our Environmental, Social, Governance and Nominating Committee at the board of directors, our internal Steering Committee and is considered at every level of our business. +40 +Table of cont ents +We recognize the importance of reducing our environmental footprint and have created proactive programs and targets related to emission reduction. These initiatives, which include the plugging and abandonment of legacy vertical wells, retrofits of air pneumatics on older facilities, electrification of our facilities, transportation pipelines, technological innovations and other activities, require capital and operational investments which are proactively and regularly built into our annual budgeting process. In 2022, we spent approximately $80 million on ESG initiatives, which included (i) $20.5 million in plugging and abandonment costs for 243 vertical wells, (ii) approximately $20.0 million on emission reduction devices, such as electric drilling, air pneumatics and vapor recovery units on new and older wells, (iii) $10.5 million on the installment of water pipelines, and (iv) $5.0 million on giving, outreach and community relations. In 2023, additional environmental and compliance transition costs, such as emission reduction costs, are included in our budget. Some of our larger anticipated capital projects in 2023 include $10 million to $15 million for the installation of water pipelines primarily in Adams County, $20 million to $25 million for plugging and abandonment of approximately 250 legacy vertical wells and $15 million to $20 million for the continued increase of electrification in our operations. +As part of our ESG initiatives, we have set aggressive targets to (i) reduce greenhouse gas intensity by 60% from 2020 levels by 2025 and 74% by 2030, (ii) reduce methane emissions intensity by 50% from 2020 levels by 2025 and 70% by 2030, and (iii) eliminate routine flaring, as defined by World Bank, by 2025. In March 2022, we completed our EPA annual filing for 2021 emissions and reported an approximate 12% reduction in GHG emissions, an approximate 17% reduction in methane emissions intensity and an approximate 70% reduction in flared hydrocarbons from 2020 baseline levels (each on a per unit of production basis), putting us on track to meet our goals. +In May 2022, our board of directors approved quantitative metrics for GHG and methane emissions reductions for our 2022 short-term incentive program, including 15% GHG and 30% methane emissions reduction targets from 2021 to 2022. As noted above, this supports the Company’s previously announced sustainability goals. In total, over 25% of our short-term incentive program in 2022 was tied to ESG and other environmental, health and safety initiatives. Our 2022 initial results indicate a reduction of over 30% in GHG and 50% in methane emissions from our 2021 levels. +In 2022 our board of directors was significantly engaged in our Sustainability reporting process, as it and our senior management team underwent its first TCFD process. Additionally, we filed our first Carbon Disclosure Project (“CDP”) Climate Change Questionnaire, examining our future through a range of climate-focused scenarios. In September 2022, we issued our annual Sustainability reports. The reports include key metrics and data from 2021 operations and are aligned with Sustainable Accounting Standards Board (“SASB”) standards and TCFD. +Additional information on our ESG practices, including sustainability goals, key metrics and progress achieved, can be found on the Sustainability page of our website at www.pdce.com. The information on our website, including the Sustainability reports, is not incorporated by reference in this report. +41 +Table of cont ents +Results of Operations +Summary of Operating Results +The following table presents selected information regarding our operating results for the periods presented: +Year Ended December 31, +Percent Change +2022 2021 2020 +2022-2021 +2021-2020 +(dollars in millions, except per unit data) +Production: +Crude oil (MBbls) 27,486 22,682 23,720 21 % (4) % +Natural gas (MMcf) 199,362 175,747 165,637 13 % 6 % +NGLs (MBbls) 24,325 19,360 17,042 26 % 14 % +Crude oil equivalent (MBoe) 85,038 71,333 68,368 19 % 4 % +Average Boe per day (Boe) 232,981 195,433 186,798 19 % 5 % +Crude Oil, Natural Gas and NGLs Sales: +Crude oil $ 2,578.2 $ 1,530.8 $ 816.8 68 % 87 % +Natural gas 984.5 519.6 178.8 89 % 191 % +NGLs 734.0 502.2 157.0 46 % 220 % +Total crude oil, natural gas and NGLs sales $ 4,296.7 $ 2,552.6 $ 1,152.6 68 % 121 % +Net Settlements on Commodity Derivatives: +Crude oil $ (614.1) $ (289.1) $ 294.4 112 % (198) % +Natural gas (265.8) (121.1) (15.1) 119 % * +Total net settlements on derivatives $ (879.9) $ (410.2) $ 279.3 115 % (247) % +Average Sales Price (excluding net settlements on derivatives): +Crude oil (per Bbl) $ 93.80 $ 67.49 $ 34.44 39 % 96 % +Natural gas (per Mcf) 4.94 2.96 1.08 67 % 174 % +NGLs (per Bbl) 30.17 25.94 9.21 16 % 182 % +Crude oil equivalent (per Boe) 50.53 35.78 16.86 41 % 112 % +Average Costs and Expense (per Boe): +Lease operating expense $ 3.09 $ 2.53 $ 2.36 22 % 7 % +Production taxes 3.67 2.32 0.87 58 % 167 % +Transportation, gathering and processing expenses 1.46 1.41 1.14 4 % 24 % +General and administrative expense 1.84 1.79 2.36 3 % (24) % +Depreciation, depletion and amortization 8.82 8.90 9.06 (1) % (2) % +Lease Operating Expense by Operating Region (per Boe): +Wattenberg Field $ 2.57 $ 2.19 $ 2.15 17 % 2 % +Delaware Basin 6.63 4.76 3.48 39 % 37 % +____________ +* Percent change is not meaningful. +42 +Table of cont ents +Crude Oil, Natural Gas and NGLs Sales +Crude oil, natural gas and NGLs sales for the year ended December 31, 2022 increased compared to the year ended December 31, 2021 due to the following: +Year Ended December 31, 2022 +(in millions) +Change in: +Production $ 58.0 +Increase in production from acquisitions 464.8 +Average crude oil price 723.2 +Average natural gas price 395.0 +Average NGLs price 103.1 +Total change in crude oil, natural gas and NGLs sales revenue $ 1,744.1 +Crude Oil, Natural Gas and NGLs Production +The following table presents crude oil, natural gas and NGLs production for the periods presented: +Year Ended December 31, +Percent Change +Production by Operating Region 2022 2021 2020 +2022-2021 +2021-2020 +Crude oil (MBbls) +Wattenberg Field 23,082 18,901 19,552 22 % (3) % +Delaware Basin 4,404 3,781 4,168 16 % (9) % +Total 27,486 22,682 23,720 21 % (4) % +Natural gas (MMcf) +Wattenberg Field 175,040 154,150 140,845 14 % 9 % +Delaware Basin 24,322 21,597 24,792 13 % (13) % +Total 199,362 175,747 165,637 13 % 6 % +NGLs (MBbls) +Wattenberg Field 21,748 17,300 14,495 26 % 19 % +Delaware Basin 2,577 2,060 2,547 25 % (19) % +Total 24,325 19,360 17,042 26 % 14 % +Crude oil equivalent (MBoe) +Wattenberg Field 74,003 61,892 57,521 20 % 8 % +Delaware Basin 11,035 9,441 10,847 17 % (13) % +Total 85,038 71,333 68,368 19 % 4 % +Average crude oil equivalent per day (Boe) +Wattenberg Field 202,748 169,567 157,161 20 % 8 % +Delaware Basin 30,233 25,866 29,637 17 % (13) % +Total 232,981 195,433 186,798 19 % 5 % +Net production volumes for crude oil, natural gas and NGLs increased 19 percent during the year ended December 31, 2022 compared to 2021. The increase in production volume between periods was primarily due to approximately 11.5 MMboe of additional production volumes as a result of the Great Western Acquisition and the net impact of turn-in-line activities in both basins since the fourth quarter of 2021. The increase was partially offset by normal decline in production from our existing wells. +43 +Table of cont ents +The following table presents our crude oil, natural gas and NGLs production ratio by operating region for the periods presented: +Year Ended December 31, +Production Ratio by Operating Region 2022 2021 2020 +Wattenberg Field +Crude oil 31 % 31 % 34 % +Natural gas 40 % 41 % 41 % +NGLs 29 % 28 % 25 % +Total 100 % 100 % 100 % +Delaware Basin +Crude oil 40 % 40 % 38 % +Natural gas 37 % 38 % 38 % +NGLs 23 % 22 % 24 % +Total 100 % 100 % 100 % +Midstream Capacity +Our ability to market our production depends substantially on the availability, proximity and capacity of in-field gathering systems, compression and processing facilities, as well as transportation pipelines out of the basin, all of which are owned and operated by third parties. If adequate midstream facilities and services are not available on a timely basis and at acceptable costs, our production and results of operations could be adversely affected. +The ultimate timing and availability of adequate infrastructure remains out of our control. Weather, regulatory developments, preventative routine maintenance and other factors also affect the adequacy of midstream infrastructure. Like other producers, from time to time we enter into volume commitments with midstream providers in order to incentivize them to provide increased capacity to meet our projected volume growth from our areas of operation. If our production falls below the level required under these agreements, we could be subject to transportation charges or aid in construction payments for commitment shortfalls. +Our production from the Wattenberg Field and the Delaware Basin was not materially affected by midstream or downstream capacity constraints during the year ended December 31, 2022. We continuously monitor infrastructure capacities versus producer activity and production volume forecasts. Increases in crude oil and natural gas prices in 2022 have incentivized producers in the Permian Basin to increase the level of drilling and completion activities. The increase in production levels and continued increase in development may lead to natural gas transportation constraints out of the Permian Basin in 2023, which may result in lower realized Waha natural gas prices. However, approximately half of PDC’s gas production in the Delaware Basin is dedicated to the Permian Highway Pipeline and is exposed to Houston-based gas pricing. We believe that this reduces the risk of a decrease in realized natural gas prices related to transportation constraints. +Crude Oil, Natural Gas and NGLs Pricing +Our results of operations depend upon many factors. Key factors include market prices of crude oil, natural gas and NGLs and our ability to market our production effectively. Crude oil, natural gas and NGLs prices have a high degree of volatility and our realizations can change substantially. +44 +Table of cont ents +The following table presents weighted average sales prices of crude oil, natural gas and NGLs for the periods presented: +Weighted Average Realized Sales Price by Operating Region Year Ended December 31, Percent Change +(excluding net settlements on derivatives) 2022 2021 2020 +2022-2021 +2021-2020 +Crude oil (per Bbl) +Wattenberg Field $ 93.34 $ 67.49 $ 34.21 38 % 97 % +Delaware Basin 96.22 67.47 35.48 43 % 90 % +Weighted average price 93.80 67.49 34.44 39 % 96 % +Natural gas (per Mcf) +Wattenberg Field 4.97 2.98 1.22 67 % 144 % +Delaware Basin 4.68 2.81 0.28 67 % * +Weighted average price 4.94 2.96 1.08 67 % 174 % +NGLs (per Bbl) +Wattenberg Field 28.24 24.77 8.84 14 % 180 % +Delaware Basin 46.46 35.72 11.32 30 % 216 % +Weighted average price 30.17 25.94 9.21 16 % 182 % +Crude oil equivalent (per Boe) +Wattenberg Field 49.18 34.95 16.84 41 % 108 % +Delaware Basin 59.58 41.25 16.94 44 % 144 % +Weighted average price 50.53 35.78 16.86 41 % 112 % +____________ +* Percent change is not meaningful. +Crude oil, natural gas and NGLs revenues are recognized when we transfer control of crude oil, natural gas or NGLs production to the purchaser. We consider the transfer of control to occur when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. +Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or “gross” method of accounting, depending upon the related purchase agreement. We use the net-back method when control of the crude oil, natural gas or NGLs has been transferred to the purchasers of these commodities that are providing transportation, gathering or processing services. In these situations, the purchaser pays us based on a percent of proceeds or a sales price fixed at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index on which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. We use the gross method of accounting when control of the crude oil, natural gas or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transportation and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing (“TGP”) expense. +Information related to the components and classifications of TGP expense on the consolidated statements of operations is shown below. For crude oil, the average NYMEX prices shown below are based on average daily prices throughout each month and, for natural gas, the average NYMEX pricing is based on first-of-the-month index prices, as in each case this is the method used to sell the majority of these commodities pursuant to terms of the relevant sales agreements. For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. The average realized price both before and after TGP expense shown in the table below represents our approximate composite per barrel price for NGLs for the periods presented. +45 +Table of cont ents +2022 Average NYMEX Price Average Realized Price Before TGP Expense Average Realization Percentage Before TGP Expense +Average TGP Expense (1) +Average Realized Price After TGP Expense Average Realization Percentage After TGP Expense +Crude oil (per Bbl) $ 96.98 $ 96.72 100 % $ 2.58 $ 94.14 97 % +Natural gas (per MMBtu) 6.78 5.06 75 % 0.21 4.85 72 % +NGLs (per Bbl) 96.98 31.95 33 % — 31.95 33 % +Crude oil equivalent (per Boe) 74.98 52.23 70 % 1.32 50.91 68 % +2021 Average NYMEX Price Average Realized Price Before TGP Expense Average Realization Percentage Before TGP Expense +Average TGP Expense (1) +Average Realized Price After TGP Expense Average Realization Percentage After TGP Expense +Crude oil (per Bbl) $ 67.92 $ 67.49 99 % $ 3.10 $ 64.39 95 % +Natural gas (per MMBtu) 3.76 2.96 79 % 0.13 2.83 75 % +NGLs (per Bbl) 67.92 25.94 38 % — 25.94 38 % +Crude oil equivalent (per Boe) 49.29 35.78 73 % 1.30 34.48 70 % +2020 Average NYMEX Price Average Realized Price Before TGP Expense Average Realization Percentage Before TGP Expense +Average TGP Expense (1) +Average Realized Price After TGP Expense Average Realization Percentage After TGP Expense +Crude oil (per Bbl) $ 39.40 $ 34.44 87 % $ 2.34 $ 32.10 81 % +Natural gas (per MMBtu) 2.08 1.08 52 % 0.12 0.96 46 % +NGLs (per Bbl) 39.40 9.21 23 % — 9.21 23 % +Crude oil equivalent (per Boe) 28.52 16.86 59 % 1.10 15.76 55 % +____________ +(1) Average TGP expense excludes unutilized firm transportation fees of $0.14, $0.11, and $0.04 per Boe for the years ended December 31, 2022, 2021, and 2020, respectively. +Our average realization percentage for crude oil equivalent was relatively consistent in 2022 as compared to 2021 due to the overall increases in commodity prices between periods and realized improved differentials from our 2022 crude oil sales contracts. This was offset by a weakening Mont Belvieu price in the second half of 2022, impacting our realized price for NGLs and higher TGP rates for our natural gas production. +Commodity Price Risk Management +We use commodity derivative instruments to manage fluctuations in crude oil and natural gas prices, including collars, fixed-price exchanges, and basis protection exchanges on a portion of our estimated crude oil and natural gas production. For our commodity exchanges, we ultimately realize the fixed price value related to the swaps. See Note 6 - Commodity Derivative Financial Instruments in Item 8. Financial Statements and Supplementary Data included elsewhere in this report for a summary of our derivative positions as of December 31, 2022. +Commodity price risk management, net, includes cash settlements upon maturity of our derivative instruments, and the change in fair value of unsettled commodity derivatives related to our crude oil and natural gas production. +Net settlements of commodity derivative instruments are based on the difference between the crude oil and natural gas index prices at the settlement date of our commodity derivative instruments compared to the respective strike prices contracted for the settlement months that were established at the time we entered into the commodity derivative transaction. The net change in fair value of unsettled commodity derivatives is comprised of the net increase or decrease in the beginning-of-period fair value of commodity derivative instruments that settled during the period and the net change in fair value of unsettled commodity derivatives during the period or from inception of any new contracts entered into during the applicable period. The +46 +Table of cont ents +net change in fair value of unsettled commodity derivatives during the period is primarily related to shifts in the crude oil and natural gas forward price curves and changes in certain differentials. +The following table presents net settlements and net change in fair value of unsettled derivatives included in commodity price risk management, net: +Year Ended December 31, +2022 2021 2020 +(in millions) +Commodity price risk management gain (loss), net: +Net settlements of commodity derivative instruments: +Crude oil collars and fixed price exchanges $ (614.1) $ (289.1) $ 294.4 +Natural gas collars and fixed price exchanges (288.0) (120.1) (1.4) +Natural gas basis protection exchanges 22.2 (1.0) (13.7) +Total net settlements of commodity derivative instruments (879.9) (410.2) 279.3 +Change in fair value of unsettled commodity derivative instruments: +Reclassification of settlements included in prior period changes in fair value of commodity derivative instruments 287.0 49.3 (19.9) +Crude oil collars and fixed price exchanges 103.5 (269.3) (49.8) +Natural gas collars and fixed price exchanges 55.4 (61.7) (7.8) +Natural gas basis protection exchanges (29.6) (9.6) (21.5) +Net change in fair value of unsettled commodity derivative instruments 416.3 (291.3) (99.0) +Total commodity price risk management gain (loss), net $ (463.6) $ (701.5) $ 180.3 +The significant increase in commodity prices during 2022 had an overall unfavorable impact on the fair value and settlements of our commodity derivatives. +Lease Operating Expense +Lease operating (“LOE”) expense increased by 46 percent to $263.0 million in 2022 compared to $180.7 million in 2021. The period-over-period increase in LOE was primarily due to (i) an approximate $30.0 million increase from operated wells acquired in the Great Western Acquisition, (ii) an increase of $20.0 million from increased activity and the impact of inflation in the Wattenberg Field, (iii) a $15.2 million increase in workover expense relating to activities mainly in the Delaware Basin and (iv) a $12.5 million increase in chemical treatments, water disposal and well services in the Delaware Basin as a result of increased activity and the impact of inflation. LOE per Boe increased 22 percent to $3.09 in 2022 from $2.53 in 2021 primarily due to the additional costs outlined above. +Production Taxes +Production taxes are comprised mainly of severance tax and ad valorem tax, and are directly related to crude oil, natural gas and NGLs sales and are generally assessed as a percentage of net revenues. From time to time, there are adjustments to the statutory rates for these taxes based upon certain credits that are determined based upon activity levels and relative commodity prices. +Production taxes increased 89 percent to $311.8 million in 2022 compared to $165.2 million in 2021. The increase in production taxes was primarily due to an increase in crude oil, natural gas and NGLs sales between periods. Production taxes per Boe increased 58 percent to $3.67 in 2022 compared to $2.32 in 2021. +Transportation, Gathering and Processing Expense +TGP expense increased 24 percent to $124.6 million in 2022 compared to $100.4 million in 2021. The increase in TGP expense between periods was primarily due to an increase in gas processing volumes and higher rates in the Delaware Basin. TGP per Boe was $1.46 and $1.41 for 2022 and 2021, respectively. +47 +Table of cont ents +Exploration, Geologic, and Geophysical Expense +Exploration, geologic and geophysical expense increased to $13.1 million in 2022 compared to $1.1 million in 2021. In 2022, we drilled and turned-in-line an exploratory well in the Delaware Basin that was not economically viable. During 2022, we expensed the associated lease costs and related infrastructure assets of the exploratory dry hole at a cost of $12.0 million . +Impairment of Properties and Equipment +The following table sets forth the major components of our impairment of properties and equipment for the periods presented: +Year Ended December 31, +2022 2021 2020 +(in millions) +Impairment of proved and unproved properties $ 6.8 $ 0.4 $ 881.2 +Impairment of infrastructure and other — — 1.2 +Total impairment of properties and equipment $ 6.8 $ 0.4 $ 882.4 +There were no significant impairment charges recognized in relation to our proved and unproved oil and gas properties in 2022 or 2021. If crude oil prices were to decline, or we change other estimates impacting future net cash flows (e.g. reserves, price differentials, future operating and/or development costs), our proved and unproved oil and gas properties could be subject to additional impairments in future periods. +During the first quarter of 2020, we recorded impairment charges of $881.1 million to our proved and unproved properties in the Delaware Basin. These impairment charges were due to a significant decline in crude oil prices, which was considered a triggering event that required us to assess our crude oil and natural gas properties for possible impairment. +General and Administrative Expense +General and administrative expense increased to $156.3 million in 2022 compared to $127.7 million in 2021 primarily due to $18.2 million in transaction and transition costs relating to the Great Western Acquisition and a $6.4 million increase related to salaries, wages and benefits as a result of an increase in headcount from the Great Western Acquisition along with an increase in drilling activity. +Depreciation, Depletion and Amortization Expense +Crude oil and natural gas properties. During 2022 and 2021, we invested $1,107.7 million and $583.6 million, respectively, exclusive of changes in accounts payable related to capital expenditures, in the development of our crude oil and natural gas properties. Depreciation, depletion and amortization expense (“DD&A”) related to crude oil and natural gas properties is directly related to proved reserves and production volumes. DD&A expense related to crude oil and natural gas properties was $741.9 million and $627.5 million in 2022 and 2021, respectively. The increase in total DD&A expense was primarily due to a 19 percent increase in production volumes between periods driven by the Great Western Acquisition. The increase was partially offset by a decrease in weighted average depletion rate resulting from the improved reserve quantities as of December 31, 2022 as a result of increased commodity prices in 2022. +48 +Table of cont ents +The year-over-year change in DD&A expense for related to crude oil and natural gas properties was primarily due to the following: +Year Ended December 31, +2022 +(in millions) +Increase in production $ 120.3 +Decrease in weighted average depletion rate (5.9) +Total decrease in DD&A expense related to crude oil and natural gas properties $ 114.4 +The following table presents our per Boe DD&A expense rates for crude oil and natural gas properties for the periods presented: +Year Ended December 31, +2022 2021 2020 +(per Boe) +Operating Region/Area +Wattenberg Field $ 8.48 $ 8.68 $ 8.80 +Delaware Basin 10.39 9.59 9.68 +Total weighted average DD&A expense rate 8.72 8.80 8.94 +Non-crude oil and natural gas properties. Depreciation expense for non-crude oil and natural gas properties was $7.8 million for the year ended December 31, 2022, compared to $7.7 million for the year ended December 31, 2021. +Interest Expense, net +Interest expense, net decreased by $18.0 million to $64.7 million in 2022 compared to $82.7 million in 2021. The decrease was primarily due to (i) a $17.8 million decrease from a partial redemption of our 2024 Senior Notes and a full redemption of Convertible Notes and certain Senior Notes in the second half of 2021, (ii) a $6.9 million loss on extinguishment recognized in 2021 relating to the redemption of certain other Senior Notes and (iii) an $8.0 million decrease in debt issuance cost amortization as a result of debt expiration and redemptions in 2021. These decreases were partially offset by an $18.4 million increase relating to increased borrowings under our revolving credit facility in 2022 to finance the cash portion of the purchase price of the Great Western Acquisition as well as an overall increase in interest rates on our credit facility. +Gain on Bargain Purchase +We recognized a $90.1 million gain on the bargain purchase of the Great Western Acquisition, net of related income taxes of $28.4 million, in 2022. For additional information, see Note 3 - Business Combination in Item 8. Financial Statements and Supplementary Data included elsewhere in this report. +Provision for Income Taxes +We recorded income tax expense of $454.2 million and $26.6 million for 2022 and 2021, respectively, resulting in effective tax rates of 20.3 percent and 4.8 percent on the respective pre-tax income. The effective tax rates differ from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21 percent to the pre-tax income due to state income taxes and changes in the valuation allowance against our deferred income tax assets. +We consider whether a portion, or all, of our deferred tax assets (“DTAs”) will be realized based on a more likely than not standard of judgment. The ultimate realization of DTAs is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, management considers the available taxes in carryback periods, the future reversals of existing taxable temporary differences, tax planning strategies and projected future taxable income in making this assessment. Our oil and gas property impairments and cumulative pre-tax losses were key considerations that led us to provide a valuation allowance against our DTAs beginning January 1, 2020 since we previously could not conclude that it is more likely than not that our DTAs will be fully realized in future periods. +49 +Table of cont ents +As we previously disclosed, we maintained a valuation allowance on our net federal deferred tax assets and continued to do so until sufficient positive evidence existed to support a reversal of the allowance. In 2022, continued higher commodity prices increased our income, resulting in the reversal of objective negative evidence of cumulative loss in recent years, and we determined that we have sufficient positive evidence to release the valuation allowance. As a result, we released the full valuation allowance of $56.6 million against our deferred income tax assets and recognized a corresponding decrease to income tax expense. +Given recent improvements in oil and gas prices and assumptions based on our current production forecasts, we estimate that we will incur federal and state cash income taxes in 2023. +In August 2022, the IRA was signed into law. The IRA includes implementation of a new alternative minimum tax, an excise tax on stock buybacks, and significant tax incentives for energy and climate initiatives, among other provisions. The alternative minimum tax and excise tax on stock buyback provisions are effective for tax years beginning after December 31, 2022. We continue to monitor updates to the IRA and the impact of the IRA on our financial position, results of operations and liquidity. We do not believe the IRA will have a material impact on our stock buyback program or our financial position in 2023, however, we are still assessing the impact for subsequent years. +Net Income (Loss)/Adjusted Net Income (Loss) +The factors impacting net income of $1,778 million and $522 million in 2022 and 2021, respectively, are discussed above. +Adjusted net income, a non-U.S. GAAP financial measure, was $1,450 million and $800 million for the year ended December 31, 2022 and 2021, respectively. With the exception of the tax-affected (when applicable) net change in fair value of unsettled derivatives, the same factors impacted adjusted net income. See Reconciliation of Non-U.S. GAAP Financial Measures below for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures. +Financial Condition, Liquidity and Capital Resources +Overview +Our primary sources of liquidity are cash and cash equivalents, cash flows from operating activities, unused borrowing capacity from our revolving credit facility, proceeds raised in debt and equity capital market transactions and other sources, such as asset sales. +Our primary source of cash flows from operating activities is the sale of crude oil, natural gas and NGLs. Fluctuations in our operating cash flows are principally driven by commodity prices and changes in our production volumes. Commodity prices have historically been volatile, and we manage a portion of this volatility through our use of commodity derivative instruments. We enter into commodity derivative instruments with maturities of no greater than five years from the date of the instrument. Our revolving credit facility imposes limits on the amount of our production we can hedge, and we may choose not to hedge the maximum amounts permitted. Therefore, we may still have fluctuations in our cash flows from operating activities due to the remaining non-hedged portion of our future production. +We may use our available liquidity for operating activities, capital investments, working capital requirements, acquisitions, capital returns and for general corporate purposes. We maintain a significant capital investment program to execute our development plans, which requires capital expenditures to be made in periods prior to initial production from newly developed wells. These activities typically result in a working capital deficit; however, we do not believe that our working capital deficit as of December 31, 2022 is an indication of a lack of liquidity. We had working capital deficits of $826 million and $462 million at December 31, 2022 and 2021, respectively. The increase in working capital deficit since December 31, 2021 primarily was a result of the Great Western Acquisition and a significant increase in production taxes payable due to increase in sales between periods. We intend to continue to manage our liquidity position by a variety of means, including through the generation of cash flows from operations, investment in projects with favorable rates of return, protection of cash flows on a portion of our anticipated sales through the use of an active commodity derivative hedging program, utilization of the borrowing capacity under our revolving credit facility and, if warranted, capital markets transactions from time to time. +50 +Table of cont ents +From time to time, we may seek to pay down, retire or repurchase our outstanding debt using cash or through exchanges of other debt or equity securities, in open market purchases, privately negotiated transactions or otherwise. +Liquidity +Our cash and cash equivalents were $6.5 million at December 31, 2022 and availability under our revolving credit facility was $1.1 billion, providing for total liquidity of $1.1 billion as of December 31, 2022. The borrowing base is primarily based on the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. +Our material short-term and long-term cash requirements consist primarily of capital expenditures, payments of contractual obligations, dividends, share repurchases, income taxes and working capital obligations. If commodity prices increase, our working capital requirements may increase due to higher operating costs and negative settlements on our outstanding commodity derivative contracts. Funding for these requirements may be provided by any combination of our capital resources previously outlined. +As a result of the Great Western Acquisition, we paid $361 million on Great Western’s behalf to pay and discharge Great Western’s 12% senior secured notes due 2025, inclusive of unpaid accrued interest and a premium for early termination. Additionally, we paid $236 million on Great Western’s behalf to pay Great Western’s secured credit facility, inclusive of unpaid accrued interest. The termination of Great Western’s debt was funded through a combination of cash on hand and availability under our revolving credit facility. +Based on our current production forecast for 2023, we expect 2023 cash flows from operations to exceed our capital investments in crude oil and natural gas properties. In addition, based on our expected cash flows from operations, our cash and cash equivalents and availability under our revolving credit facility, we believe that we will have sufficient capital available to fund our planned activities through the 12-month period following the filing of this report. We also believe that we will have sufficient expected cash flows from operations to allow us to execute our capital return plan. Future repurchases of common stock or dividend payments will be subject to approval by our board of directors and will depend on our level of earnings, financial requirements, and other factors considered relevant by our board. +Our material long-term cash requirements relate to debt obligations and interest payments, commodity derivative contract liabilities, production taxes, operating and finance leases, asset retirement obligations and firm transportation and processing agreements included in Item 8. Financial Statements and Supplementary Data to our consolidated financial statements included elsewhere in this report. +In October 2022, as part of the semi-annual redetermination of the borrowing base under our credit facility, the borrowing base increased from $3.0 billion to $3.5 billion, primarily due to the addition of the reserves acquired from Great Western; however, we maintained our elected commitment level of $1.5 billion. The revolving credit facility contains covenants customary for agreements of this type, with the most restrictive being certain financial tests on a quarterly basis. The financial tests, as defined per the revolving credit facility, include requirements (a) to maintain a minimum current ratio of 1.0:1.0 and (b) not exceed a maximum leverage ratio of 3.5:1.0. For purposes of the current ratio covenant, the revolving credit facility’s definition of total current assets, in addition to current assets as presented under U.S. GAAP, includes, among other things, unused commitments under the revolving credit facility and excludes the fair value of commodity derivative assets. Additionally, the current ratio covenant calculation allows us to exclude the fair value of commodity derivative liabilities and the current portion of our long-term debt and other short-term loans from the U.S. GAAP total current liabilities amount. Accordingly, the existence of a working capital deficit under U.S. GAAP is not necessarily indicative of a violation of the current ratio covenant. At December 31, 2022, we were in compliance with all covenants in the revolving credit facility with a current ratio of 1.5:1.0 and a leverage ratio of 0.5:1.0. +We expect to remain in compliance with the covenants under our credit facility and our Senior Notes throughout the 12-month period following the filing of this report. +51 +Table of cont ents +Cash Flows +Our cash flows from operating, investing and financing activities are as follows: +Year ended December 31, +2022 2021 2020 +(in thousands) +Cash flows from operating activities $ 2,772,324 $ 1,547,796 $ 870,079 +Cash flows from investing activities (2,149,516) (578,804) (687,159) +Cash flows from financing activities (650,143) (937,786) (181,260) +Net increase (decrease) in cash and cash equivalents $ (27,335) $ 31,206 $ 1,660 +Operating Activities. Our net cash flows from operating activities are primarily impacted by commodity prices, production volumes, net settlements from our commodity derivative positions, operating costs and general and administrative expenses. Cash flows from operating activities increased by $1,225 million to $2,772 million in 2022 as compared to $1,548 million in 2021. The increase between periods was primarily due to a $1,744 million increase in crude oil, natural gas and NGLs sales and changes in the timing of receivable collections. These increases were partially offset by a $470 million increase in cash settlement losses on commodity derivatives, a $147 million increase in production taxes, an $82 million increase in lease operating expenses and changes in the timing of vendor and royalty owner payments between periods. +Adjusted cash flows from operations, a non-U.S. GAAP financial measure, increased by $1,006 million in 2022 to $2,538 million from $1,533 million in 2021. The increase was primarily due to the factors mentioned above for changes in cash flows provided by operating activities, without regard to timing of cash payments and receipts of assets and liabilities. Adjusted free cash flow, a non-U.S. GAAP financial measure, increased by $472 million in 2022 to $1,421 million from $949 million in 2021. The increase was primarily due to the increase in cash flows from operating activities, as discussed above, partially offset by an increase in capital investments in crude oil and natural gas properties as a result of our 2022 development plan. +See Reconciliation of Non-U.S. GAAP Financial Measures, below, for a more detailed discussion of these non-U.S. GAAP financial measures and a reconciliation of these measures to the most comparable U.S. GAAP measures. +Investing Activities. As crude oil and natural gas production from a well declines rapidly in the first few years of production, we need to continue to commit significant amounts of capital in order to maintain and grow our production and replace our crude oil and natural reserves. If capital is not available or is constrained in the future, we will be limited to our cash flows from operations and liquidity under our revolving credit facility as the sources for funding our capital investments. +Cash flows from investing activities in 2022 primarily consist of the acquisition, exploration and development of crude oil and natural gas properties, net of dispositions of crude oil and natural gas properties. Net cash used in investing activities of $2,150 million during 2022 was primarily due to $1,068 million utilized for the Great Western Acquisition and drilling and completion activities of $1,070 million, partially offset by $16 million in proceeds from the sale of certain properties and equipment. +Net cash used in investing activities of $579 million during 2021 was primarily related to our drilling and completion activities of $583 million, partially offset by $5 million in proceeds from the sale of certain properties and equipment. +Financing Activities. Net cash used in financing activities in 2022 of $650 million was primarily due to (i) the repurchase of 12.1 million shares of our common stock for $818 million pursuant to our stock repurchase program and (ii) dividend payments totaling $182 million, partially offset by net borrowings on our credit facility of $370 million to fund the cash portion of the purchase price of the Great Western Acquisition and to terminate Great Western’s debt. As of December 31, 2022, $455 million out of the approved $1.3 billion remained available for stock repurchases under the program. In February 2023, our board of directors approved a $750 million increase in the size of the program. Future repurchases of common stock or dividend payments will be subject to approval by our board of directors and will depend on our level of earnings, financial requirements, and other factors considered relevant by our board. +52 +Table of cont ents +Net cash used in financing activities in 2021 of $938 million was primarily due to (i) net repayments on our credit facility of $168 million, (ii) redemption and retirement of Convertible Notes and other Senior Notes totaling $509 million, (iii) the repurchase of 3.8 million shares of our common stock for $157 million pursuant to our stock repurchase program and (iv) dividend payments totaling $84 million. +Subsidiary Guarantors +PDC Permian, Inc., a Delaware corporation (“Permian”), and Pioneer Water Pipeline LLC, a Delaware limited liability company (“Pioneer” and together with Permian, the “Guarantors”), each a wholly-owned subsidiary, guarantees our obligations under our 2024 Senior Notes and 2026 Senior Notes (collectively, the “Senior Notes”). Permian holds our assets located in the Delaware Basin. Pioneer holds certain water midstream assets located in the Wattenberg Field. The Senior Notes are fully and unconditionally guaranteed on a joint and several basis by the Guarantors. The guarantees are subject to release in limited circumstances only upon the occurrence of certain customary conditions. +The indentures governing the Senior Notes contain customary restrictive covenants that, among other things, limit our ability and the ability of our restricted subsidiaries to: (i) incur additional debt including under our revolving credit facility, (ii) make certain investments or pay dividends or distributions on our capital stock or purchase, redeem or retire capital stock, (iii) sell assets, including capital stock of our restricted subsidiaries, (iv) restrict the payment of dividends or other payments by restricted subsidiaries to us, (v) create liens that secure debt, (vi) enter into transactions with affiliates and (vii) merge or consolidate with another company. +The following summarized subsidiary guarantor financial information has been prepared on the same basis of accounting as our consolidated financial statements. Investments in subsidiaries are accounted for under the equity method. +As of/Year Ended December 31, +2022 2021 +Issuer Guarantors Issuer Guarantor +(in millions) +Assets +Current assets $ 539.1 $ 54.7 $ 402.6 $ 56.0 +Intercompany accounts receivable, guarantor subsidiary — 334.2 — 40.8 +Investment in guarantor subsidiary 1,766.8 — 1,767.2 — +Properties and equipment, net 6,286.4 1,007.0 3,875.0 939.9 +Other non-current assets 88.0 7.7 58.5 4.8 +Liabilities +Current liabilities $ 1,361.5 $ 58.7 $ 862.5 $ 57.6 +Intercompany accounts payable 334.2 — 27.9 — +Long-term debt 1,314.0 — 942.1 — +Other non-current liabilities 1,101.7 164.1 392.3 172.0 +Statement of Operations +Crude oil, natural gas and NGLs sales $ 3,639.3 $ 657.4 $ 2,163.1 $ 389.5 +Commodity price risk management gain (loss), net (463.6) — (701.5) — +Total revenues 3,179.7 666.0 1,464.5 391.4 +Production costs 1,167.4 281.6 892.4 189.0 +Gross profit (1) +2,471.9 375.8 1,270.7 200.4 +Impairment of properties and equipment 0.8 5.9 0.4 — +Net income (loss) 1,419.5 358.6 327.7 194.9 +____________ +(1) Gross profit is calculated as crude oil, natural gas and NGLs sales less production costs. +53 +Table of cont ents +Critical Accounting Policies and Estimates +The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with U.S. GAAP. The preparation of these statements requires us to make certain assumptions, judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities and commitments as of the date of our financial statements. +Our significant accounting policies are described in Note 2 - Summary of Significant Accounting Policies in Item 8. Financial Statements and Supplementary Data included elsewhere in this report. The following discussion outlines the accounting policies and practices involving the use of estimates and application of significant judgment that are critical in determining our financial results. Changes in the estimates and assumptions discussed below could materially affect the amount or timing of our financial results. +Crude Oil and Natural Gas Reserve Quantities +We account for our crude oil and natural gas properties under the successful efforts method of accounting. Under this method, costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depleted by the unit-of-production method based on estimated proved developed producing reserves. The successful efforts method inherently relies on the estimation of proved crude oil, natural gas and NGL reserves. In determining the estimates of reserve and economic evaluations, management utilizes specialists, specifically petroleum engineers. Reserve quantities and the related estimates of future net cash flows are used as inputs in our calculation of depletion, evaluation of proved properties for impairment, assessment of expected realizability of our deferred income tax assets and calculation of the standardized measure of discounted future net cash flows. +The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. Significant inputs and engineering assumptions used in developing the estimates of proved crude oil and natural gas reserves include estimates of reserves volumes, future operating and development costs and historical commodity prices. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, we continually make revisions to reserve estimates as additional information becomes available. We cannot predict the amounts or timing of such future revisions. +If the estimates of proved reserve quantities decline, the rate at which we record depletion expense will increase, which would reduce future net income. Changes in depletion rate calculations caused by changes in reserve quantities are made prospectively. In addition, a decline in reserve estimates may impact the outcome of our assessment of proved and unproved properties for impairment. Impairments are recorded in the period in which they are identified. +We cannot predict future commodity prices. However, we performed a sensitivity analysis on our proved reserve estimates as of December 31, 2022, to present a decrease of approximately 20 percent in crude oil price (and holding all other factors constant), as the value of crude oil influences the value of our proved reserves most significantly. As a result, our proved reserve quantities would decrease by 7.8 MMBoe or 1 percent. The decrease would have increased our DD&A rate by $0.03 per Boe and decreased our pre-tax income by $2.2 million for the year ended December 31, 2022. This estimated impact is based on available data as of December 31, 2022, and future events could require different adjustments to our DD&A rate. During 2022 and 2021, we had positive revisions to our proved reserve quantities of 29.8 MMBoe and 52.9 MMBoe, respectively, as a result of higher average prices for crude oil, natural gas and NGLs. During 2020 we had a negative revision of 39.5 MMBoe as a result of lower average prices for crude oil, natural gas and NGLs. For more information regarding reserve estimations, including additional crude oil sensitives and descriptions over historical reserve revisions, see Items 1 and 2. Business and Properties - Oil and Gas Production and Operations and Supplemental Oil and Gas Information within our consolidated financial statements included in Item 8. Financial Statements and Supplementary Data included elsewhere in this report. +54 +Table of cont ents +Impairment of Crude Oil and Natural Gas Properties +Upon a triggering event, we assess the valuation of our proved crude oil and natural gas properties for possible impairment by comparing the carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production and prices at which we estimate the commodity will be sold. If carrying values exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a discounted future cash flows analysis. We estimate the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount. +Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices, and a discount factor. Future commodity prices are estimated by using a combination of assumptions management uses in its budgeting and forecasting process, historical and future prices adjusted for geographical location and quality differentials, and other factors that management believes will impact realizable prices. The discount factor used is the market based weighted average cost of capital which is based on rates utilized by market participants that are commensurate with the risks inherent in the development and production of the underlying crude oil and natural gas. +Unproved properties with individually significant acquisition costs are periodically assessed for impairment and reduced to fair value based on a review over our future development plans, estimated future cash flows for probable well locations and remaining average lease terms. Items that can impact our future development plans can be driven by drilling results, reservoir performance, capital resources and seismic interpretations. Changes in our assumptions of the estimated nonproductive portion of our undeveloped leases could result in additional impairment expense. +Although our cash flow estimates are based on the relevant information available at the time the estimates are made, estimates of future cash flows are, by their nature, highly uncertain and may vary significantly from actual results. We cannot predict when or if future impairment charges will be recorded because of the uncertainty in the factors discussed above. +There were no significant impairment charges recognized related to our proved and unproved properties during the years ended December 31, 2022 or 2021. We recorded impairment charges of $881.1 million to our proved and unproved properties to our Delaware Basin properties in 2020 as a result of a significant decline in crude oil prices. +Valuation of Business Combinations +We follow the acquisition method of accounting for business combinations. Assets acquired and liabilities assumed are recognized at the date of acquisition at their respective estimated fair values. Any excess of the purchase price over the fair value amounts assigned to assets and liabilities is recorded as goodwill. Any deficiency of the purchase price over the estimated fair values of the net assets acquired is recorded as a gain in statements of operations. +In connection with the Great Western Acquisition in 2022, we allocated $1.5 billion of purchase price consideration to the assets acquired and liabilities assumed based on estimated fair values as of the acquisition date. In estimating the fair values of assets acquired and liabilities assumed the most significant assumptions relate to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. To estimate the fair values of these properties as part of acquisition accounting, we estimate the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices , and a market-based weighted average cost of capital rate. The Great Western Acquisition resulted in a gain on bargain purchase due to the estimated fair value of the identifiable net assets acquired exceeding the purchase consideration transferred by $90.1 million, net of related income taxes of $28.4 million. The bargain purchase was primarily attributable to the increase in commodity price forecasts from the date we entered into the definitive purchase agreement, February 26, 2022, to the closing date of the acquisition, May 6, 2022, when the fair value of the crude oil and natural gas reserves acquired was determined. Additionally, the majority of the acquisition consideration was fixed and therefore did not fluctuate as a result of market increases or decreases between the date of entry into the agreement through the closing date. Assuming all factors are held constant, an approximate 10 percent decrease in future commodity prices used in the valuation of the proved crude oil and natural gas properties would reduce the fair value by approximately $400 million, recognition of approximately $300 million of goodwill and no gain on bargain purchase. +55 +Table of cont ents +Additionally, for acquisitions with significant unproved properties, we may also review comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value as such sales represent the amount at which a willing buyer and seller would enter into an exchange for such properties to determine an estimation of fair value. +Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. A higher fair value assigned to a property results in a higher depletion expense, which results in lower net earnings. This increases the likelihood of impairment if future commodity prices or reserves quantities are lower than those originally used to determine fair value or if future operating expenses or development costs are higher than those originally used to determine fair value. +Recent Accounting Pronouncements +There were no significant new accounting standards adopted or new accounting pronouncements that would have potential effect on us as of December 31, 2022. +Reconciliation of Non-U.S. GAAP Financial Measures +We use “adjusted cash flows from operations”, “adjusted free cash flow (deficit)”, “adjusted net income (loss)” and “adjusted EBITDAX”, non-U.S. GAAP financial measures, for internal management reporting, when evaluating period-to-period changes and, in some cases, in providing public guidance on possible future results. In addition, we believe these are measures of our fundamental business and can be useful to us, investors, lenders and other parties in the evaluation of our performance relative to our peers and in assessing acquisition opportunities and capital expenditure projects. These supplemental measures are not measures of financial performance under U.S. GAAP and should be considered in addition to, not as a substitute for, net income (loss) or cash flows from operations, investing or financing activities and should not be viewed as liquidity measures or indicators of cash flows reported in accordance with U.S. GAAP. The non-U.S. GAAP financial measures that we use may not be comparable to similarly titled measures reported by other companies. In the future, we may disclose different non-U.S. GAAP financial measures in order to help us and our investors more meaningfully evaluate and compare our future results of operations to our previously reported results of operations. We strongly encourage investors to review our financial statements and publicly filed reports in their entirety and to not rely on any single financial measure. +Adjusted cash flows from operations and adjusted free cash flow (deficit). We believe adjusted cash flows from operations can provide additional transparency into the drivers of trends in our operating cash flows, such as production, realized sales prices and operating costs, as it disregards the timing of settlement of operating assets and liabilities. We believe adjusted free cash flow (deficit) provides additional information that may be useful in an investor analysis of our ability to generate cash from operating activities from our existing oil and gas asset base to fund exploration and development activities and to return capital to stockholders in the period in which the related transactions occurred. We exclude from this measure cash receipts and expenditures related to acquisitions and divestitures of oil and gas properties and capital expenditures for other properties and equipment, which are not reflective of the cash generated or used by ongoing activities on our existing producing properties and, in the case of acquisitions and divestitures, may be evaluated separately in terms of their impact on our performance and liquidity. Adjusted free cash flow is a supplemental measure of liquidity and should not be viewed as a substitute for cash flows from operations because it excludes certain required cash expenditures. For example, we may have mandatory debt service requirements or other non-discretionary expenditures which are not deducted from the adjusted free cash flow measure. +We are unable to present a reconciliation of forward-looking adjusted cash flow because components of the calculation, including fluctuations in working capital accounts, are inherently unpredictable. Moreover, estimating the most directly comparable GAAP measure with the required precision necessary to provide a meaningful reconciliation is extremely difficult and could not be accomplished without unreasonable effort. We believe that forward-looking estimates of adjusted cash flow are important to investors because they assist in the analysis of our ability to generate cash from our operations. +Adjusted net income (loss). We believe that adjusted net income (loss) provides additional transparency into operating trends, such as production, realized sales prices, operating costs and net settlements on commodity derivative contracts, because it disregards changes in our net income (loss) from mark-to-market adjustments resulting from net changes in the fair value of our unsettled commodity derivative contracts, and these changes are not directly reflective of our operating performance. +56 +Table of cont ents +Adjusted EBITDAX. We believe that adjusted EBITDAX provides additional transparency into operating trends because it reflects the financial performance of our assets without regard to financing methods, capital structure, accounting methods or historical cost basis. In addition, because adjusted EBITDAX excludes certain non-cash expenses, we believe it is not a measure of income, but rather a measure of our liquidity and ability to generate sufficient cash for exploration, development, and acquisitions and to service our debt obligations. +PV-10. We define PV-10 as the estimated present value of the future net cash flows from our proved reserves before income taxes, discounted using a 10 percent discount rate. We believe that PV-10 provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating oil and gas companies. We believe that PV-10 is relevant and useful for evaluating the relative monetary significance of our reserves. Professional analysts, investors and other users of our financial statements may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies’ reserves. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable in evaluating us and our reserves. PV-10 is not intended to represent the current market value of our estimated reserves. +The following table presents a reconciliation of each of our non-U.S. GAAP financial measures to its most comparable U.S. GAAP measure for the periods presented: +Year Ended December 31, +2022 2021 2020 +(thousands) +Cash flows from operations to adjusted cash flows from operations and adjusted free cash flow: +Net cash from operating activities $ 2,772.3 $ 1,547.8 $ 870.1 +Changes in assets and liabilities (233.9) (15.2) 51.5 +Adjusted cash flows from operations 2,538.4 1,532.6 921.6 +Capital expenditures for development of crude oil and natural gas properties (1,069.5) (583.1) (551.0) +Capital expenditures for midstream assets (10.1) — — +Change in accounts payable related to capital expenditures for oil and gas development activities and midstream assets (38.2) (0.5) 28.7 +Adjusted free cash flow $ 1,420.6 $ 949.0 $ 399.3 +Net income (loss) to adjusted net income (loss): +Net income (loss) $ 1,778.1 $ 522.3 $ (724.3) +Loss (gain) on commodity derivative instruments 463.6 701.5 (180.3) +Net settlements on commodity derivative instruments (879.9) (410.2) 279.3 +Tax effect of above adjustments (1) +88.3 (14.0) — +Adjusted net income (loss) $ 1,450.1 $ 799.6 $ (625.3) +Net income (loss) to adjusted EBITDAX: +Net income (loss) $ 1,778.1 $ 522.3 $ (724.3) +Loss (gain) on commodity derivative instruments 463.6 701.5 (180.3) +Net settlements on commodity derivative instruments (879.9) (410.2) 279.3 +Non-cash stock-based compensation 26.8 23.0 22.2 +Interest expense, net 64.7 82.7 88.7 +Income tax expense (benefit) 454.2 26.6 (7.9) +Impairment of properties and equipment 6.8 0.4 882.4 +Exploration, geologic and geophysical expense 13.1 1.1 1.4 +Depreciation, depletion and amortization 749.7 635.2 619.7 +Accretion of asset retirement obligations 13.4 12.1 10.1 +Loss (gain) on sale of properties and equipment 0.2 (0.9) (0.7) +Adjusted EBITDAX $ 2,690.7 $ 1,593.8 $ 990.6 +57 +Table of cont ents +Year Ended December 31, +2022 2021 2020 +(thousands) +Cash from operating activities to adjusted EBITDAX: +Net cash from operating activities $ 2,772.3 $ 1,547.8 $ 870.1 +Gain on bargain purchase 90.1 — — +Interest expense, net (2) +64.7 75.8 88.7 +Amortization and write-off of debt discount, premium and issuance costs (5.4) (13.5) (16.8) +Exploration, geologic and geophysical expense (3) +1.1 1.1 1.4 +Other 1.8 (2.2) (4.3) +Changes in assets and liabilities (233.9) (15.2) 51.5 +Adjusted EBITDAX $ 2,690.7 $ 1,593.8 $ 990.6 +PV-10: +Standardized measure of discounted future net cash flows $ 14,987.4 $ 7,908.2 $ 3,282.2 +Present value of estimated future income tax discounted at 10% 4,065.6 1,800.6 172.4 +PV-10 $ 19,053.0 $ 9,708.8 $ 3,454.6 +_____________ +(1) Due to the full valuation allowance recorded against our net deferred tax assets, there is no tax effect for the year ended December 31, 2020. +(2) Excludes loss on extinguishment from early retirement of our senior notes amounting to $6.9 million for the year ended December 31, 2021. +(3) Excludes exploratory dry hole costs of $12.0 million for the year ended December 31, 2022 . +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Market-Sensitive Instruments and Risk Management +We are exposed to market risks associated with interest rate risks, commodity price risk and credit risk. Recent inflationary trends and the possibility of a recession could impact each of these market risks. We have established risk management processes to monitor and manage these market risks. +Interest Rate Risk +Changes in interest rates affect the amount of interest we earn on our interest bearing cash, cash equivalents and restricted cash accounts and the interest we pay on borrowings under our revolving credit facility. Our 2024 Senior Notes and 2026 Senior Notes have fixed rates, and therefore, near-term changes in interest rates do not expose us to risk of earnings or cash flow loss; however, near-term changes in interest rates may affect the fair value of our fixed-rate debt. +As of December 31, 2022, we had $370.0 million of outstanding borrowings under our revolving credit facility. If market interest rates had increased or decreased one percent, our interest expense for the year ended December 31, 2022 would have been changed by approximately $4.3 million. +Commodity Price Risk +We are exposed to the potential risk of loss from adverse changes in the market price of crude oil, natural gas, natural gas basis and NGLs. Pricing for oil and natural gas production has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for production depend on many factors outside of our control. Pursuant to established policies and procedures, we manage a portion of the risks associated with these market fluctuations using commodity derivative instruments. These instruments help us predict with greater certainty the effective crude oil and natural gas prices we will receive for our hedged production. We believe that our commodity derivative policies and procedures are effective in achieving our risk management objectives. +As of December 31, 2022, we had a net liability derivative position of $270.3 million related to our commodity price risk derivatives. Based on a sensitivity analysis as of December 31, 2022, we estimate that a 10 percent increase in +crude oil prices and natural gas prices, inclusive of basis, over the entire period for which we have commodity derivatives in place would have resulted in an increase in the fair value of our net derivative liabilities of $144.4 million, whereas a 10 percent decrease in prices would have resulted in a decrease in the fair value of our net derivative liabilities of $143.2 million. The +58 +Table of cont ents +potential increase in the fair value of our net derivative liabilities would be recorded in our statements of operations as a loss. We are currently unable to estimate the effects on the earnings of future periods resulting from changes in the market value of our commodity derivative contracts. +Credit Risk +Credit risk represents the loss that we would incur if a counterparty fails to perform its contractual obligations. We attempt to reduce credit risk by diversifying our counterparty exposure. When exposed to significant credit risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish credit limits and monitor the appropriateness of those limits on an ongoing basis. We monitor the creditworthiness of significant counterparties through our credit committee, which utilizes a number of qualitative and quantitative tools to assess credit risk and takes mitigative actions if deemed necessary. While we believe that our credit risk analysis and monitoring procedures are reasonable, no amount of analysis can assure performance by our counterparties. +We primarily use financial institutions which are lenders in our revolving credit facility as counterparties for our derivative financial instruments. Disruption in the credit markets, changes in commodity prices and other factors may have a significant adverse impact on a number of financial institutions. To date, we have had no material counterparty default losses from our commodity derivative financial instruments. +Our crude oil, natural gas and NGLs sales are concentrated with a few predominately large customers. This concentrates our credit risk exposure with a small number of large customers. We do not require our customers to post collateral, and the inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. For the year ended December 31, 2022, one customer accounted for more than 10% of our sales. For the years ended December 31, 2021 and 2020, three and four customers, respectively, accounted for more than 10% of our sales. Our allowances for credit losses were insignificant as of December 31, 2022. +Disclosure of Limitations +Because the information above included only those exposures that existed at December 31, 2022, it does not consider those exposures or positions which could arise after that date. As a result, our ultimate realized gain or loss with respect to interest rate and commodity price fluctuations will depend on the exposures that arise during the period, our commodity price risk management strategies at the time and interest rates and commodity prices at the time. +59 +Table of cont ents +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Index to Consolidated Financial Statements, Financial Statement Schedule and Supplemental Information +Financial Statements: +Report of Independent Registered Public Accounting Firm (PCAOB ID 238 ) +61 +Consolidated Balance Sheets +64 +Consolidated Statements of Operations +65 +Consolidated Statements of Cash Flows +66 +Consolidated Statements of Stockholders’ Equity +67 +Notes to Consolidated Financial Statements +68 +Supplemental Information - Unaudited: +Crude Oil and Natural Gas Information +93 +Financial Statement Schedule: +Schedule II - Valuation and Qualifying Accounts - Years Ended December 31, 2022, 2021 and 2020 +100 +60 +Table of cont ents +Report of Independent Registered Public Accounting Firm +To the Board of Directors and Stockholders of PDC Energy, Inc. +Opinions on the Financial Statements and Internal Control over Financial Reporting +We have audited the accompanying consolidated balance sheets of PDC Energy, Inc. and its subsidiaries (the “Company”) as of December 31, 2022 and 2021, and the related consolidated statements of operations, of stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 2022, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO. +Basis for Opinions +The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. +Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. +Definition and Limitations of Internal Control over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +61 +Table of cont ents +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Critical Audit Matters +The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. +The Impact of Proved Crude Oil and Natural Gas Reserves on Proved Crude Oil and Natural Gas Properties, Net +As described in Notes 2 and 7 to the consolidated financial statements, the Company’s proved crude oil and natural gas properties, net balance was $11.3 billion as of December 31, 2022, and depreciation, depletion and amortization (DD&A) expense for the year ended December 31, 2022 was $749.7 million. The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. As disclosed by management, significant inputs and engineering assumptions used in developing the estimates of proved crude oil and natural gas reserves include estimates of reserves volumes, future operating and development costs and historical commodity prices. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. The Company accounts for crude oil and natural gas properties under the successful efforts method of accounting. Costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depleted by the unit-of-production method based on estimated proved developed producing reserves. In determining the estimates of reserve and economic evaluations, management utilizes specialists, specifically petroleum engineers. +The principal considerations for our determination that performing procedures relating to the impact of proved crude oil and natural gas reserves on proved crude oil and natural gas properties, net is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the estimates of proved crude oil and natural gas reserves, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the audit evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved crude oil and natural gas reserves. +Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved crude oil and natural gas reserves. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved crude oil and natural gas reserves. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluating the methods and assumptions used by the specialists, testing the completeness and accuracy of the data used by the specialists and evaluating the specialists’ findings. +Acquisition of Great Western Petroleum, LLC - Valuation of Proved Crude Oil and Natural Gas Properties, Net +As described in Notes 2 and 3 to the consolidated financial statements, on May 6, 2022, the Company completed the acquisition of Great Western Petroleum, LLC for $1.4 billion. The acquisition resulted in the recognition of $2.1 billion in proved crude oil and natural gas properties, net. Management utilizes the acquisition method to account for acquisitions of businesses and pursuant to the acquisition method, allocates the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Management estimates the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices, and a market based weighted average cost of capital rate. In determining the estimates of reserve and economic evaluations, management utilizes specialists, specifically petroleum engineers. +62 +Table of cont ents +The principal considerations for our determination that performing procedures relating to the valuation of proved crude oil and natural gas properties, net acquired in the acquisition of Great Western Petroleum, LLC is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the fair value estimate of the proved crude oil and natural gas properties acquired, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s inputs and assumptions related to reserves volumes, future operating and development costs, future commodity prices, and the market based weighted average cost of capital rate, and (iii) the audit effort involved the use of professionals with specialized skill and knowledge. +Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the acquisition accounting, including controls over the fair value estimate of proved crude oil and natural gas properties acquired. These procedures also included, among others (i) reading the purchase agreement, (ii) testing management’s process for developing the fair value estimate of proved crude oil and natural gas properties acquired, (iii) evaluating the appropriateness of the discounted cash flow models, (iv) testing the completeness and accuracy of the underlying data used in the discounted cash flow models, and (v) evaluating the reasonableness of the significant inputs and assumptions used by management related to reserves volumes, future operating and development costs, future commodity prices, and the market based weighted average cost of capital rate. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the reserves volumes used in the discounted cash flow models. As a basis for using this work, the specialists’ qualifications were understood and the Company’s relationship with the specialists was assessed. The procedures performed also included evaluating the methods and assumptions used by the specialists, testing of the completeness and accuracy of the data used by the specialists and evaluating the specialists’ findings. Evaluating the reasonableness of management’s inputs and assumptions related to future operating and development costs and future commodity prices involved evaluating whether the inputs and assumptions used by management were reasonable considering past and anticipated performance of the Company and Great Western Petroleum, LLC and observable market data. Professionals with specialized skill and knowledge were used to assist in evaluating the appropriateness of the discounted cash flow models and the reasonableness of the market based weighted average cost of capital rate assumption. +/s/ PricewaterhouseCoopers LLP +Denver, Colorado +February 22, 2023 +We have served as the Company’s auditor since 2007. +63 +Table of cont ents +PDC ENERGY, INC. +Consolidated Balance Sheets +(in thousands, except share and per share data) +December 31, +2022 2021 +Assets +Current assets: +Cash and cash equivalents $ 6,494 $ 33,829 +Accounts receivable, net 546,311 398,605 +Fair value of derivatives 31,963 17,909 +Prepaid expenses and other current assets 8,987 8,230 +Total current assets 593,755 458,573 +Properties and equipment, net 7,293,355 4,814,865 +Fair value of derivatives 25,562 15,177 +Other assets 70,093 48,051 +Total Assets $ 7,982,765 $ 5,336,666 +Liabilities and Stockholders’ Equity +Liabilities +Current liabilities: +Accounts payable $ 244,406 $ 127,891 +Production tax liability 244,737 99,583 +Fair value of derivatives 274,218 304,870 +Funds held for distribution 539,094 285,861 +Accrued interest payable 11,655 10,482 +Other accrued expenses 106,082 91,409 +Total current liabilities 1,420,192 920,096 +Long-term debt 1,314,010 942,084 +Asset retirement obligations 171,665 127,526 +Fair value of derivatives 53,600 95,561 +Deferred income taxes 507,683 26,383 +Other liabilities 532,870 314,769 +Total liabilities 4,000,020 2,426,419 +Commitments and contingent liabilities +Stockholders’ equity +Common shares - par value $ 0.01 per share, 150,000,000 authorized, 89,224,353 and 96,468,071 issued as of December 31, 2022 and 2021, respectively +892 965 +Additional paid-in capital 2,823,364 3,161,941 +Retained earnings (accumulated deficit) 1,165,816 ( 249,954 ) +Treasury shares - at cost, 119,336 and 54,960 as of December 31, 2022 and 2021, respectively +( 7,327 ) ( 2,705 ) +Total stockholders’ equity 3,982,745 2,910,247 +Total Liabilities and Stockholders’ Equity $ 7,982,765 $ 5,336,666 +See accompanying Notes to Consolidated Financial Statements +64 +Table of cont ents +PDC ENERGY, INC. +Consolidated Statements of Operations +(in thousands, except per share data) +Year Ended December 31, +2022 2021 2020 +Revenues +Crude oil, natural gas and NGLs sales $ 4,296,681 $ 2,552,558 $ 1,152,555 +Commodity price risk management gain (loss), net ( 463,611 ) ( 701,456 ) 180,270 +Other income 12,663 4,808 6,401 +Total revenues 3,845,733 1,855,910 1,339,226 +Costs, expenses and other +Lease operating expense 262,986 180,659 161,346 +Production taxes 311,778 165,209 59,368 +Transportation, gathering and processing expense 124,577 100,403 77,835 +Exploration, geologic and geophysical expense 13,079 1,064 1,376 +General and administrative expense 156,276 127,733 161,087 +Depreciation, depletion and amortization 749,657 635,184 619,739 +Accretion of asset retirement obligations 13,408 12,086 10,072 +Impairment of properties and equipment 6,762 402 882,393 +Loss (gain) on sale of properties and equipment 212 ( 912 ) ( 724 ) +Other expense — 2,490 10,272 +Total costs, expenses and other 1,638,735 1,224,318 1,982,764 +Income (loss) from operations 2,206,998 631,592 ( 643,538 ) +Interest expense, net ( 64,734 ) ( 82,698 ) ( 88,684 ) +Gain on bargain purchase 90,057 — — +Income (loss) before income taxes 2,232,321 548,894 ( 732,222 ) +Income tax benefit (expense) ( 454,200 ) ( 26,583 ) 7,902 +Net income (loss) $ 1,778,121 $ 522,311 $ ( 724,320 ) +Earnings (loss) per share +Basic $ 18.76 $ 5.30 $ ( 7.37 ) +Diluted 18.49 5.22 ( 7.37 ) +Weighted average common shares outstanding +Basic 94,796 98,546 98,251 +Diluted 96,174 100,154 98,251 +See accompanying Notes to Consolidated Financial Statements +65 +Table of contents +PDC ENERGY, INC. +Consolidated Statements of Cash Flows +(in thousands) +Year Ended December 31, +2022 2021 2020 +Cash flows from operating activities: +Net income (loss) $ 1,778,121 $ 522,311 $ ( 724,320 ) +Adjustments to net income (loss) to reconcile to net cash from operating activities: +Net change in fair value of unsettled commodity derivatives ( 416,278 ) 291,268 99,001 +Depreciation, depletion and amortization 749,657 635,184 619,739 +Impairment of properties and equipment 6,762 402 882,393 +Exploratory dry hole costs 11,970 — — +Accretion of asset retirement obligations 13,408 12,086 10,072 +Non-cash stock-based compensation 26,846 23,023 22,200 +Amortization and write-off of debt discount, premium and issuance costs 5,436 13,468 16,772 +Loss from extinguishment of debt — 6,927 — +Deferred income taxes 452,900 26,383 ( 6,530 ) +Gain on bargain purchase ( 90,057 ) — — +Other ( 374 ) 1,539 2,280 +Changes in assets and liabilities: +Accounts receivable 19,228 ( 153,717 ) 139,664 +Other assets 16,364 24,678 ( 5,341 ) +Production tax liability 191,175 41,381 ( 50,803 ) +Accounts payable and accrued expenses ( 44,677 ) 40,183 ( 66,183 ) +Funds held for distribution 80,670 108,729 ( 23,621 ) +Asset retirement obligations ( 19,880 ) ( 28,595 ) ( 27,491 ) +Other liabilities ( 8,947 ) ( 17,454 ) ( 17,753 ) +Net cash from operating activities 2,772,324 1,547,796 870,079 +Cash flows from investing activities: +Capital expenditures for development of crude oil and natural gas properties ( 1,069,543 ) ( 583,108 ) ( 550,964 ) +Capital expenditures for midstream assets ( 10,069 ) — — +Capital expenditures for other properties and equipment ( 18,159 ) ( 894 ) ( 1,634 ) +Cash paid for acquisition of an exploration and production business ( 1,068,241 ) — ( 139,812 ) +Proceeds from sale of properties and equipment 717 5,073 1,641 +Proceeds from divestitures 15,779 125 3,610 +Net cash from investing activities ( 2,149,516 ) ( 578,804 ) ( 687,159 ) +Cash flows from financing activities: +Proceeds from revolving credit facility and other borrowings 2,683,200 802,800 1,799,350 +Repayment of revolving credit facility and other borrowings ( 2,313,200 ) ( 970,800 ) ( 1,635,350 ) +Proceeds from senior notes — — 148,500 +Redemption of senior notes — ( 308,584 ) ( 452,153 ) +Repayment of convertible notes — ( 200,000 ) — +Payment of debt issuance costs ( 101 ) ( 13,066 ) ( 6,538 ) +Purchase of treasury shares for employee stock-based compensation tax withholding obligations ( 18,105 ) ( 6,038 ) ( 9,345 ) +Purchase of treasury shares under stock repurchase program ( 818,325 ) ( 156,795 ) ( 23,819 ) +Dividends paid ( 181,573 ) ( 83,615 ) — +Principal payments under financing lease obligations ( 2,039 ) ( 1,688 ) ( 1,905 ) +Net cash from financing activities ( 650,143 ) ( 937,786 ) ( 181,260 ) +Net change in cash and cash equivalents ( 27,335 ) 31,206 1,660 +Cash and cash equivalents, beginning of year 33,829 2,623 963 +Cash and cash equivalents, end of year $ 6,494 $ 33,829 $ 2,623 +See accompanying Notes to Consolidated Financial Statements +66 +Table of contents +PDC ENERGY, INC. +Consolidated Statements of Stockholders’ Equity +(in thousands, except dividends per share) +Common Stock Additional Paid-in Capital Treasury Stock Retained Earnings (Accumulated Deficit) Total Stockholders’ Equity +Shares Amount Shares Amount +Balance at January 1, 2020 61,652 $ 617 $ 2,384,309 ( 35 ) $ ( 1,474 ) $ ( 47,945 ) $ 2,335,507 +Net income (loss) — — — — — ( 724,320 ) ( 724,320 ) +Issuance pursuant to acquisition 39,182 391 1,014,921 — — — 1,015,312 +Stock-based compensation 530 5 19,738 — 2,457 — 22,200 +Purchase of treasury shares for employee stock-based compensation tax withholding obligations — — — ( 457 ) ( 9,345 ) — ( 9,345 ) +Retirement of treasury shares for employee stock-based compensation tax withholding obligations ( 339 ) ( 3 ) ( 7,407 ) 339 7,413 — 3 +Retirement of treasury shares ( 1,266 ) ( 12 ) ( 23,807 ) 1,266 23,819 — — +Issuance of treasury shares — — — 115 — — — +Purchase of treasury shares under stock repurchase program — — — ( 1,266 ) ( 23,819 ) — ( 23,819 ) +Balance at December 31, 2020 99,759 998 3,387,754 ( 38 ) ( 949 ) ( 772,265 ) 2,615,538 +Net income (loss) — — — — — 522,311 522,311 +Stock-based compensation 531 5 20,831 — 2,187 — 23,023 +Purchase of treasury shares for employee stock-based compensation tax withholding obligations — — — ( 181 ) ( 6,038 ) — ( 6,038 ) +Retirement of treasury shares for employee stock-based compensation tax withholding obligations ( 117 ) ( 1 ) ( 4,156 ) 117 4,157 — — +Retirement of treasury shares ( 3,705 ) ( 37 ) ( 157,058 ) 3,711 157,401 — 306 +Issuance of treasury shares — — — 89 — — — +Purchase of treasury shares under stock repurchase program — — — ( 3,753 ) ( 159,463 ) — ( 159,463 ) +Dividends declared ($ 0.86 per share) +— — ( 85,430 ) — — — ( 85,430 ) +Balance at December 31, 2021 96,468 965 3,161,941 ( 55 ) ( 2,705 ) ( 249,954 ) 2,910,247 +Net income (loss) — — — — — 1,778,121 1,778,121 +Issuance pursuant to acquisition 4,007 40 293,274 — — — 293,314 +Stock-based compensation 1,038 10 22,673 — 4,163 — 26,846 +Purchase of treasury shares for employee stock-based compensation tax withholding obligations — — — ( 283 ) ( 18,105 ) — ( 18,105 ) +Retirement of treasury shares for employee stock-based compensation tax withholding obligations ( 170 ) ( 2 ) ( 11,199 ) 170 11,684 ( 483 ) — +Retirement of treasury shares ( 12,119 ) ( 121 ) ( 584,199 ) 12,119 820,993 ( 236,673 ) — +Issuance of treasury shares — — — 75 — — — +Purchase of treasury shares under stock repurchase program — — — ( 12,145 ) ( 823,357 ) — ( 823,357 ) +Dividends declared ($ 1.95 per share) +— — ( 59,126 ) — — ( 125,195 ) ( 184,321 ) +Balance at December 31, 2022 89,224 $ 892 $ 2,823,364 ( 119 ) $ ( 7,327 ) $ 1,165,816 $ 3,982,745 +See accompanying Notes to Consolidated Financial Statements +67 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +NOTE 1 - NATURE OF OPERATIONS AND BASIS OF PRESENTATION +PDC Energy, Inc. is a domestic independent exploration and production company that acquires, explores and develops properties for the production of crude oil, natural gas and NGLs, with operations in the Wattenberg Field in Colorado and the Delaware Basin in west Texas. Our operations in the Wattenberg Field are focused in the horizontal Niobrara and Codell plays and our Delaware Basin operations are primarily focused in the horizontal Wolfcamp zones. As of December 31, 2022, we owned an interest in approximately 4,100 gross productive wells. +The accompanying audited consolidated financial statements include the accounts of PDC and our wholly-owned subsidiaries. Pursuant to the proportionate consolidation method, our accompanying consolidated financial statements include our pro rata share of assets, liabilities, revenues and expenses of the entities which we proportionately consolidate. All material intercompany accounts and transactions have been eliminated in consolidation. +NOTE 2 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Use of Estimates in the Preparation of Financial Statements. The preparation of our consolidated financial statements in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”) requires us to make estimates and assumptions that affect the amounts reported on our consolidated financial statements and accompanying notes. Actual results could differ from those estimates. Estimates which are particularly significant to our consolidated financial statements include estimates of proved oil and natural gas reserves used in calculating depletion; estimates of unpaid revenues and unbilled costs; future cash flows from proved oil and natural gas reserves on proved oil and natural gas properties used in impairment assessment; valuation of commodity derivative instruments; the estimation of future abandonment obligations used in asset retirement obligations; valuation of proved and unproved crude oil and natural gas properties from purchased and exchanged businesses and assets; and valuation of deferred income tax assets. +Cash and Cash Equivalents. The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. Cash and cash equivalents potentially subject us to a concentration of credit risk as substantially all of our deposits held in financial institutions were in excess of federal deposit insurance limits as of December 31, 2022 and 2021. We maintain our cash and cash equivalents in the form of money market and checking accounts with financial institutions that we believe are creditworthy and are also lenders under our revolving credit facility. +Commodity Derivative Financial Instruments. Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas we enter into commodity derivative contracts to protect against price declines in future periods. We have elected not to designate any of our commodity derivative instruments as cash flow hedges; therefore, these instruments do not qualify for hedge accounting. Accordingly, realized gains and losses from the settlement of commodity derivatives and unrealized gains and losses from changes in the fair value of remaining unsettled commodity derivatives are presented as a component of revenues in the consolidated statements of operations. Under applicable accounting standards, the fair value of each derivative instrument is recorded as either an asset or liability on the consolidated balance sheet. We measure the fair value of our commodity derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates, volatility factors and nonperformance risk. +Properties and Equipment. +Crude Oil and Natural Gas Properties. We account for our crude oil and natural gas properties under the successful efforts method of accounting. Under this method, costs of proved developed producing properties, successful exploratory wells and developmental dry hole costs are capitalized and depleted by the unit-of-production method based on estimated proved developed producing reserves. We have determined that we have two unit-of-production fields: the Wattenberg Field and the Delaware Basin. In making these conclusions we consider the geographic concentration, operating similarities within the areas, geologic considerations and common cost environments in these areas. We calculate quarterly depletion expense by using our estimated prior period-end reserves as the denominator, adjusted as necessary, with the exception of our fourth quarter where we use the year-end reserve estimate adjusted for fourth quarter production. The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring significant decisions in the evaluation of available geological, geophysical, engineering and economic data. The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of +68 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +production under changing economic conditions. As a result, revisions in existing reserve estimates occur. Capitalized development costs of producing oil and natural gas properties are depleted over proved developed reserves and leasehold costs are depleted over total proved reserves. Upon the sale or retirement of significant portions of or complete fields of depreciable or depletable property, the net book value thereof, less proceeds or salvage value, is recognized as a gain or loss on the consolidated statements of operations. +Exploration costs, including geological and geophysical expenses, seismic costs on unproved leaseholds and delay rentals are expensed as incurred. Exploratory well drilling costs, including the cost of stratigraphic test wells, are initially capitalized, but charged to expense if the well is determined to be economically nonproductive. The status of each in-progress well is reviewed quarterly to determine the proper accounting treatment under the successful efforts method of accounting. Exploratory well costs continue to be capitalized as long as we have identified a sufficient quantity of reserves to justify completion as a producing well, we are making sufficient progress assessing our reserves and economic and operating viability or we have not made sufficient progress to allow for final determination of productivity. If an in-progress exploratory well is found to be economically unsuccessful prior to the issuance of the financial statements, the costs incurred prior to the end of the reporting period are charged to exploration expen se. If we are unable to make a final determination about the productive status of a well prior to issuance of the financial statements, the costs associated with the well are classified as suspended well costs until we have had sufficient time to conduct additional completion or testing operations to evaluate the pertinent geological and engineering data obtained. At the time we are able to make a final determination of a well’s productive status, the well is removed from suspended well status and the resulting accounting treatment is recorded. +Unproved property costs not subject to depletion primarily include leasehold costs, broker and legal expenses and capitalized internal costs associated with developing oil and natural gas prospects on these properties. Leasehold costs are transferred into costs subject to depletion on an ongoing basis as these properties are evaluated and proved reserves are established. Additional costs not subject to depletion include costs associated with development wells in progress or awaiting completion at year-end. These costs are transferred into costs subject to depletion on an ongoing basis as these wells are completed and proved reserves are established or confirmed. +Proved Property Impairment. Upon a triggering event, we assess the valuation of our proved crude oil and natural gas properties for possible impairment by comparing the carrying value to estimated undiscounted future net cash flows on a field-by-field basis using estimated production and prices at which we estimate the commodity will be sold. If carrying values exceed undiscounted future net cash flows, the measurement of impairment is based on estimated fair value utilizing a discounted future cash flows analysis. The impairment recorded is the amount by which the carrying values exceed the fair value. In the impairment assessment we estimate the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices, and a market based weighted average cost of capital rate. Certain events, including but not limited to downward revisions in estimates of our reserve quantities, expectations of falling commodity prices or rising capital and operating costs, could result in a triggering event, and may result to a possible impairment of our proved crude oil and natural gas properties. +Unproved Property Impairment. Acquisition costs of unproved properties are capitalized when incurred, until such properties are transferred to proved properties or charged to impairment expense. Unproved crude oil and natural gas properties with individually significant acquisition costs are assessed for impairment periodically, or if a triggering event is identified. We evaluate significant unproved properties for impairment based on future drilling plans and expected future lease expirations, primarily in areas where we have no development plans. +Other Property and Equipment. Other property and equipment such as vehicles, facilities, midstream pipeline, office furniture and equipment, buildings, computer hardware and software and leasehold improvements is carried at cost. Depreciation is provided principally on the straight-line method over the assets’ estimated useful lives, which range from two to 35 years. Leasehold improvements are depreciated over the lesser of their useful lives or the term of the lease . Total depreciation expense related to other property and equipment was $ 7.8 million, $ 7.7 million and $ 8.7 million for the years ended December 31, 2022, 2021 and 2020, respectively. +We review other property and equipment for impairment whenever events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying value of the asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying value of the asset exceeds the estimated future cash flows, an impairment charge is recognized for the amount by which the carrying value of the asset exceeds its fair value. +69 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Internal-Use Software. Internal-use software costs incurred during the development stage of our enterprise resource planning software are capitalized. The development stage generally includes software design, configuration, testing and installation activities. Training and maintenance costs are expensed as incurred, while upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Capitalized internal-use software costs are depreciated over the estimated useful life of the underlying project on a straight-line basis upon completion of the project. +Capitalized Interest. We capitalize interest on expenditures made in connection with exploration and development projects that are not subject to current depletion. Interest is capitalized only for the period that activities are in progress to bring unevaluated properties to its intended use. Interest capitalized may not exceed gross interest expense for the period. Capitalized interest totaled $ 21.5 million, $ 17.8 million and $ 19.7 million during the year ended December 31, 2022, 2021 and 2020, respectively. +Income Taxes. We account for income taxes under the asset and liability method. We recognize deferred income tax assets and liabilities for the future tax consequences attributable to operating loss and credit carryforwards and differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred income tax assets and liabilities are measured using enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect on deferred income tax assets and liabilities of a change in tax rate is recognized in income in the period that includes the enactment date. If we determine that it is more likely than not that some portion or all of the deferred income tax assets will not be realized, we record a valuation allowance, thereby reducing the deferred income tax assets to what we consider realizable. +We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. Our policy is to recognize interest and penalties related to uncertain tax positions in interest expense. +Debt Issuance Costs and Discounts. Debt issuance costs and discounts are capitalized and amortized over the life of the respective borrowings using the effective interest method. Debt issuance costs for the Senior Notes are included in long-term debt and the debt issuance costs for the revolving credit facility are included in other assets. +Asset Retirement Obligations. We recognize the estimated liability for future costs associated with the plugging and abandonment of our oil and gas properties resulting from acquisition, construction or normal operation. We account for asset retirement obligations by recording the fair value of our plugging and abandonment obligations when incurred, which is at the time the related well is completed. Upon initial recognition of an asset retirement obligation, we increase the carrying amount of the associated long-lived asset by the same amount as the liability. Over time, the liability is accreted for the change in the present value and recognized as accretion expense. The initial capitalized cost, net of salvage value, is depleted over the useful life of the related asset through a charge to DD&A expense. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the asset retirement cost (presented as part of properties and equipment). Revisions in estimated liabilities can result from, among other things, changes in retirement costs or the estimated timing of settling asset retirement obligations. +Treasury Shares. We record treasury share purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as a reduction in shareholders’ equity. When we retire treasury shares, we charge any excess of cost over the par value to additional paid-in-capital (“APIC”), to the extent we have amounts in APIC, with any remaining excess cost being charged to retained earnings. +Revenue Recognition. Crude oil, natural gas and NGLs revenues are recognized when we have transferred control of our production to the purchaser. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the crude oil, natural gas or NGLs production. We record revenues based on an estimate of the volumes delivered at estimated prices as determined by the applicable sales agreement. We estimate our sales volumes based on company-measured volume readings. We then adjust our crude oil, natural gas and NGLs sales in subsequent periods based on the data received from our purchasers that reflects actual volumes delivered and prices received. We receive payment for sales one to two months after actual delivery has occurred. The differences in sales estimates and actual sales are recorded one to two months later. Historically, these differences have not been material. We account for natural gas imbalances using the sales method. For the years ending December 31, 2022, 2021 and 2020, the impact of any natural gas imbalances was not significant. +70 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Our crude oil, natural gas and NGLs sales are recorded using either the “net-back” or “gross” method of accounting, depending upon the related agreement. We use the net-back method when control of our commodity product has been transferred to the purchasers that are providing transportation, gathering or processing services. In these situations, the purchaser pays us proceeds based on a percent of the proceeds or have fixed our sales price at index less specified deductions. The net-back method results in the recognition of a net sales price that is lower than the index for which the production is based because the operating costs and profit of the midstream facilities are embedded in the net price we are paid. +We use the gross method of accounting when control of the crude oil, natural gas or NGLs is not transferred to the purchaser and the purchaser does not provide transportation, gathering or processing services as a function of the price we receive. Rather, we contract separately with midstream providers for the applicable transport and processing on a per unit basis. Under this method, we recognize revenues based on the gross selling price and recognize transportation, gathering and processing expenses. +For our product sales that have a contract term greater than one year, we utilized the practical expedient in ASC Topic 606 which states that we are not required to disclose the transaction price allocated to the remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, monthly sales of a product generally represent a separate performance obligation; therefore, future commodity volumes to be delivered and sold are wholly unsatisfied and disclosure of the transaction price allocated to such unsatisfied performance obligations is not required. +Business Combinations. We utilize the acquisition method to account for acquisitions of businesses. Pursuant to the acquisition method, we allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. The purchase price allocations are based upon appraisals, discounted cash flows and estimates by management, which are Level 3 inputs. When appropriate, we review recent comparable purchases and sales of crude oil and natural gas properties within the same regions and use that data as a basis for fair market value; for example, the amount at which a willing buyer and seller would enter into an exchange for such properties. +In estimating the fair values of assets acquired and liabilities assumed, we make various assumptions. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped and unproved crude oil and natural gas properties. To estimate the fair value of these properties as part of acquisition accounting, we estimate the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of reserves volumes, future operating and development costs, future commodity prices, and a market based weighted average cost of capital rate. The market based weighted average cost of capital rate is subject to additional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved properties, we reduce the discounted future net revenues of probable and possible reserves by additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, we complete an analysis of recent comparable purchased properties to determine an estimation of fair value. +If applicable, we record deferred taxes for any differences between the assigned values and tax basis of assets and liabilities. Estimated deferred taxes are based on available information concerning the tax basis of assets acquired and liabilities assumed and loss carryforwards at the acquisition date, although such estimates may change in the future as additional information becomes known. +Acreage Exchanges . From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and provide us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges in accordance with the guidance prescribed by Accounting Standards Codification 845, Nonmonetary Transactions . For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized in earnings, in accordance with Accounting Standards Codification 820, Fair Value Measurement . +Stock-Based Compensation. Stock-based compensation is recognized within our financial statements based on the grant-date fair value of the equity instrument awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the requisite service period for the entire award and we account for forfeitures of stock-based compensation awards as they occur. +71 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Fair Value of Assets and Liabilities. The Company follows the authoritative accounting guidance for measuring fair value of assets and liabilities in its financial statements. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Our fair value measurements are estimated pursuant to a fair value hierarchy that requires us to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date, giving the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability, and may affect the valuation of the assets and liabilities and their placement within the fair value hierarchy levels. The three levels of inputs that may be used to measure fair value are defined as: +Level 1 – Quoted prices (unadjusted) for identical assets or liabilities in active markets. +Level 2 – Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means. +Level 3 – Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity. +Leases. We determine if an arrangement is representative of a lease at contract inception. Right-of-use (“ROU”) assets represent our right to use the underlying assets for the lease term and the corresponding lease liabilities represent our obligations to make lease payments arising from the leases. Operating and finance lease ROU assets and liabilities are recognized at the commencement date based on the present value of the expected lease payments over the lease term. As most of our leases do not provide an implicit interest rate, we utilize our incremental borrowing rate based on information available at the commencement date in determining the present value of lease payments. Subsequent measurement, as well as presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. Terms of our leases include options to extend or terminate the lease only when we can ascertain that it is reasonably certain we will exercise that option. Leases with an initial term of one year or less are not recorded on the consolidated balance sheets. +We apply the practical expedient that permits combining lease and non-lease components in a contract and accounting for the combination as a single lease component (applied by asset class). +NOTE 3 - BUSINESS COMBINATION +On May 6, 2022, we completed the acquisition of Great Western Petroleum, LLC (“Great Western”) for approximately $ 1.4 billion, inclusive of Great Western’s net debt (the “Great Western Acquisition”). Great Western was an independent oil and gas company focused on the exploration, production and development of crude oil and natural gas in the Wattenberg Field of Colorado. The consideration paid included $ 542.5 million in cash and approximately 4.0 million shares of our common stock, valued at $ 293.3 million on the acquisition date. In addition, we paid off the Great Western secured credit facility totaling $ 235.8 million and irrevocably deposited $ 361.2 million on Great Western’s behalf to pay and discharge on May 20, 2022 Great Western’s 12 percent senior secured notes due 2025, inclusive of unpaid accrued interest and a premium for early termination. The cash portion of the purchase price and the termination of Great Western’s debt were funded through a combination of cash on hand and availability under our revolving credit facility. +Purchase Price Allocation +The Great Western Acquisition has been accounted for using the acquisition method under Accounting Standards Codification (“ASC”) 805, Business Combinations , with PDC being treated as the accounting acquirer. Accordingly, we conducted assessments of the net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values, while transaction and integration costs associated with the acquisition were expensed as incurred. +72 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table details our final purchase price, valuation and allocation of the purchase price to the assets acquired and liabilities assumed as a result of the Great Western Acquisition: +(in thousands, except share and per share data) +Consideration: +Cash $ 542,500 +Retirement of Great Western’s credit facility 235,822 +Extinguishment of Great Western’s secured senior notes 361,231 +Total cash consideration $ 1,139,553 +Common stock issued 4,007,018 +Fair value of PDC common stock on May 6, 2022 $ 73.20 +Total fair value of common stock issued 293,314 +Total consideration $ 1,432,867 +Assets acquired: +Cash $ 63,183 +Accounts receivable 164,026 +Other current assets 3,129 +Properties and equipment, net - proved 2,091,301 +Properties and equipment, net - other 7,035 +Other noncurrent assets 20,345 +Total assets acquired $ 2,349,019 +Liabilities assumed: +Accounts payable $ ( 119,142 ) +Production tax liability ( 110,940 ) +Funds held for distribution ( 170,708 ) +Other current liabilities ( 19,203 ) +Fair value of derivatives ( 319,600 ) +Asset retirement obligations ( 25,300 ) +Deferred tax liabilities ( 28,400 ) +Other liabilities ( 32,802 ) +Total liabilities assumed $ ( 826,095 ) +Total identifiable net assets acquired $ 1,522,924 +Gain on bargain purchase 90,057 +Purchase price consideration $ 1,432,867 +Determining the fair values of the assets and liabilities of Great Western requires judgement and certain assumptions to be made, the most significant of these being related to the valuation of crude oil and natural gas properties. The majority of the measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market, and therefore represent Level 3 inputs. The fair values of crude oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs and assumptions to the valuation of proved and unproved crude oil and natural gas properties include estimates of reserve volumes, future operating and development costs, future commodity prices and a market-based weighted-average cost of capital rate of 14.25 percent. These inputs require significant judgments and estimates by management at the time of the valuation. The fair value of derivative instruments was based on observable inputs, including forward commodity-price curves which are considered Level 2 inputs, and based on volatility factors which are considered Level 3 inputs. We completed our purchase price allocation analysis as of December 31, 2022, with immaterial adjustments made to the previous allocation. +73 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +ASC 805, Business Combinations , requires that any excess of purchase price over the fair value of assets acquired, including identifiable intangibles and liabilities assumed, be recognized as goodwill and any excess of fair value of acquired net assets, including identifiable intangible assets over the acquisition consideration, results in a gain from bargain purchase. Prior to recording a gain, the acquiring entity must reassess whether all assets acquired and assumed liabilities have been identified and recognized and perform re-measurements to verify that the consideration paid, assets acquired and liabilities assumed have been properly valued. The Great Western Acquisition resulted in a gain on bargain purchase due to the estimated fair value of the identifiable net assets acquired exceeding the purchase consideration transferred by $ 90.1 million and is shown as a gain on bargain purchase on our consolidated statement of operations, net of related income taxes of $ 28.4 million . Upon completion of our assessment, we concluded that recording a gain on bargain purchase was appropriate and required under ASC 805. The bargain purchase was primarily attributable to the increase in commodity price forecasts from the date we entered into the definitive purchase agreement with Great Western, February 26, 2022, to the closing date of the acquisition, May 6, 2022, when the fair value of crude oil and natural gas reserves acquired were determined. Additionally, the majority of the acquisition consideration was fixed and therefore did not fluctuate as a result of market increases or decreases between the date of entry into the agreement through the closing date. +The results of operations for the Great Western Acquisition since the closing date have been included on our consolidated financial statements for the year ended December 31, 2022 and include approximately $ 631.0 million of total revenues and $ 387.8 million of income from operations, respectively. During the year ended December 31, 2022, we recognized total transaction costs of $ 11.7 million, which are included in general and administrative expense on the consolidated statement of operations. +Pro Forma Information . The following unaudited pro forma financial information represents a summary of the condensed consolidated results of operations for the year ended December 31, 2022 and 2021, assuming the acquisition had been completed as of January 1, 2021. The pro forma financial information is not necessarily indicative of the results of operations that would have been achieved if the acquisition had been effective as of these dates, or of future results. +The information below reflects certain nonrecurring pro forma adjustments that were directly related to the business combination based on available information and certain assumptions that we believe are reasonable, including (i) our common stock issued to the owners of Great Western, (ii) the increase in depletion reflecting the relative fair values and production volumes attributable to Great Western’s properties and the revision to the depletion rate reflecting the reserve volumes acquired, (iii) adjustments to interest expense as a result of payoff of Great Western’s credit facility and secured senior notes, (iv) the adjustment to reflect the gain on bargain purchase, and (v) the estimated tax impacts of the pro forma adjustments. In addition, pro forma earnings were adjusted to exclude acquisition-related costs incurred by us and Great Western totaling approximately $ 33.6 million for the year ended December 31, 2022, and included the total costs of $ 33.6 million for the year ended December 31, 2021. +Year Ended December 31, +2022 2021 +(in thousands, except per share data) +Total revenue $ 3,897,361 $ 2,277,463 +Net income (loss) 1,651,029 563,855 +Earnings (loss) per share: +Basic $ 17.42 $ 5.50 +Diluted 17.17 5.41 +74 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 4 - REVENUE RECOGNITION +Disaggregated Revenue. The following table presents crude oil, natural gas and NGLs sales disaggregated by commodity and operating region for the periods presented: +Year Ended December 31, +Revenue by Commodity and Operating Region 2022 2021 2020 +(in thousands) +Crude oil +Wattenberg Field $ 2,154,435 $ 1,275,666 $ 668,948 +Delaware Basin 423,784 255,135 147,902 +Total 2,578,219 1,530,801 816,850 +Natural gas +Wattenberg Field 870,560 458,870 171,755 +Delaware Basin 113,909 60,733 6,997 +Total 984,469 519,603 178,752 +NGLs +Wattenberg Field 614,260 428,570 128,126 +Delaware Basin 119,733 73,584 28,827 +Total 733,993 502,154 156,953 +Crude oil, natural gas and NGLs +Wattenberg Field 3,639,255 2,163,106 968,829 +Delaware Basin 657,426 389,452 183,726 +Total $ 4,296,681 $ 2,552,558 $ 1,152,555 +NOTE 5 - FAIR VALUE MEASUREMENTS +Recurring Fair Value Measurements +Derivative Financial Instruments. We measure the fair value of our commodity derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, the contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, interest rates, volatility factors and nonperformance risk. Non-performance risk considers the effect of our credit standing on the fair value of derivative liabilities and the effect of our counterparties’ credit standings on the fair value of derivative assets. Both inputs to the model are based on published credit default exchange rates and the duration of each outstanding derivative position. We use our counterparties’ valuations to assess reasonableness of our fair value measurement. +75 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Our crude oil and natural gas fixed-price exchanges and basis exchanges are included in Level 2. Our collars are included in Level 3. The following table presents, for each applicable level within the fair value hierarchy, our derivative assets and liabilities, including both current and non-current portions, measured at fair value on a recurring basis as of the dates indicated: +December 31, 2022 December 31, 2021 +Consolidated Balance Sheet Line Item Significant Other +Observable +Inputs +(Level 2) Significant +Unobservable +Inputs +(Level 3) Total Significant Other +Observable +Inputs +(Level 2) Significant +Unobservable +Inputs +(Level 3) Total +(in thousands) +Derivative assets +Current Fair value of derivatives $ 9,178 $ 22,785 $ 31,963 $ — $ 17,909 $ 17,909 +Non-current Fair value of derivatives 20,439 5,123 25,562 605 14,572 15,177 +Total $ 29,617 $ 27,908 $ 57,525 $ 605 $ 32,481 $ 33,086 +Derivative liabilities +Current Fair value of derivatives $ ( 214,171 ) $ ( 60,047 ) $ ( 274,218 ) $ ( 230,695 ) $ ( 74,175 ) $ ( 304,870 ) +Non-current Fair value of derivatives ( 49,749 ) ( 3,851 ) ( 53,600 ) ( 74,715 ) ( 20,846 ) ( 95,561 ) +Total $ ( 263,920 ) $ ( 63,898 ) $ ( 327,818 ) $ ( 305,410 ) $ ( 95,021 ) $ ( 400,431 ) +The following table presents a reconciliation of our Level 3 commodity derivative assets and liabilities measured at fair value for the periods presented: +Year Ended December 31, +2022 2021 2020 +(in thousands) +Fair value of Level 3 instruments, net asset (liability) beginning of period $ ( 62,540 ) $ ( 8,427 ) $ 8,414 +Commodity derivatives acquired from acquisition of business ( 22,716 ) — — +Changes in fair value included in consolidated statements of operations line item: +Commodity price risk management gain (loss), net ( 192,694 ) ( 206,109 ) 37,821 +Settlements included in consolidated statements of operations line items: +Commodity price risk management gain (loss), net 241,960 151,996 ( 54,662 ) +Fair value of Level 3 instruments, net asset (liability) end of period $ ( 35,990 ) $ ( 62,540 ) $ ( 8,427 ) +Net change in fair value of Level 3 unsettled derivatives included in consolidated statements of operations line item: +Commodity price risk management gain (loss), net $ ( 31,367 ) $ ( 35,108 ) $ — +Total $ ( 31,367 ) $ ( 35,108 ) $ — +The significant unobservable input used in the fair value measurement of our derivative contracts is the implied volatility curve. A significant increase or decrease in the implied volatility, in isolation, would have a directionally similar effect resulting in a significantly higher or lower fair value measurement of our Level 3 derivative contracts. There has been no change in the methodology we apply to measure the fair value of our Level 3 derivative contracts during the periods covered by the financial statements. +Nonrecurring Fair Value Measurements +Acquisitions and Impairment of Long-lived Assets. We measure fair value using inputs that are not observable in the market, and are therefore designated as Level 3 within the valuation hierarchy, on a nonrecurring basis for any acquired assets or businesses and to review our proved and unproved crude oil and natural gas properties for possible impairment. The most significant fair value determinations for non-financial assets and liabilities are related to crude oil and gas properties acquired. See Note 3 - Business Combination for additional information . +76 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Asset Retirement Obligations. We measure the fair value of asset retirement obligations as of the date a well begins drilling or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 within the valuation hierarchy. +Other Financial Instruments +The carrying value of the financial instruments included in current assets and current liabilities approximates fair value due to the short-term maturities of these instruments. +Long-term Debt. The portion of our long-term debt related to our revolving credit facility approximates fair value, as the applicable interest rates are variable and reflective of market rates. We have elected not to account for the portion of our debt related to our senior notes under the fair value option; however, we have determined an estimate of the fair values based on measurements of trading activity and broker or dealer quotes, which are published market prices, and therefore are Level 2 inputs. The table below presents these estimates of the fair value of the portion of our long-term debt related to our senior notes as of the dates indicated: +December 31, +2022 2021 +Nominal Interest Estimated Fair Value Percent of Par Estimated Fair Value Percent of Par +(in millions) (in millions) +2024 Senior Notes 6.125 % 198.4 99.2 % 202.8 101.4 % +2026 Senior Notes 5.75 % 716.0 95.5 % 775.5 103.4 % +NOTE 6 - COMMODITY DERIVATIVE FINANCIAL INSTRUMENTS +Objective and Strategy. Our results of operations and operating cash flows are affected by changes in market prices for crude oil, natural gas and NGLs. To manage a portion of our exposure to price volatility from producing crude oil and natural gas we enter into commodity derivative contracts such as collars, fixed-price exchanges and basis protection exchanges, to protect against price declines in future periods. We do not enter into derivative contracts for speculative or trading purposes. +We believe our commodity derivative instruments continue to be effective in achieving the risk management objectives for which they were intended. Depending on changes in crude oil and natural gas futures markets and management’s view of underlying supply and demand trends, we may increase or decrease our derivative positions from current levels. As of December 31, 2022, we had derivative instruments in place for a portion of our anticipated production in 2023 through 2025. Our commodity derivative contracts have been entered into at no upfront cost to us as we hedge our anticipated production at the then-prevailing commodity market prices, without adjustment for premium or discount. +As of December 31, 2022 and 2021, our derivative instruments were comprised of fixed-price swaps, collars and basis protection swaps. +• Fixed-price swaps are arrangements that guarantee a fixed price. If the index price is below the fixed contract price, we receive the market price from the purchaser and receive the difference between the index price and the fixed contract price from the counterparty. If the index price is above the fixed contract price, we receive the market price from the purchaser and pay the difference between the index price and the fixed contract price to the counterparty. +• Collars contain a fixed floor price (put) and ceiling price (call). If the index price falls below the fixed put strike price, we receive the market price from the purchaser and receive the difference between the put strike price and index price from the counterparty. If the index price exceeds the fixed call strike price, we receive the market price from the purchaser and pay the difference between the call strike price and index price to the counterparty. If the index price is between the put and call strike price, no payments are due to or from the counterparty. +• Basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified delivery point. For basis protection swaps, we receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract. +77 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Effect of Derivative Instruments on the Consolidated Statements of Operations. The following table presents the impact of our derivative instruments on our consolidated statements of operations for the periods presented: +Year Ended December 31, +Consolidated Statements of Operations Line Item 2022 2021 2020 +(in thousands) +Commodity price risk management gain (loss), net +Net settlements $ ( 879,889 ) $ ( 410,188 ) $ 279,271 +Net change in fair value of unsettled derivatives 416,278 ( 291,268 ) ( 99,001 ) +Total commodity price risk management gain (loss), net $ ( 463,611 ) $ ( 701,456 ) $ 180,270 +Commodity Derivative Contracts. As of December 31, 2022, we had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is presented: +Collars Fixed-Price Swaps +Commodity/ Index/ +Maturity Period +Quantity (Crude oil - MBbls Natural Gas - BBtu) +Weighted Average Contract Price +Quantity (Crude Oil - MBbls Gas and Basis- BBtu) +Weighted Average Contract Price +Fair Value December 31, 2022 (in thousands) +Floors Ceilings +Crude Oil +NYMEX +2023 5,937 $ 61.27 $ 83.11 9,804 $ 66.42 $ ( 156,820 ) +2024 825 65.91 89.58 6,126 70.59 ( 17,042 ) +2025 — — — 2,640 75.10 12,262 +Total Crude Oil 6,762 18,570 ( 161,600 ) +Natural Gas +NYMEX +2023 26,864 3.48 6.03 41,825 3.05 ( 51,443 ) +2024 — — — 26,160 3.54 ( 17,511 ) +2025 — — — 6,225 4.87 2,640 +26,864 74,210 ( 66,314 ) +CIG +2023 — — — 8,760 3.39 ( 7,657 ) +2025 — — — 4,800 3.10 ( 4,370 ) +— 13,560 ( 12,027 ) +Total Natural Gas 26,864 87,770 ( 78,341 ) +Basis Protection - Natural Gas +CIG +2023 — — — 67,742 ( 0.26 ) ( 26,335 ) +2024 — — — 26,160 ( 0.39 ) ( 3,329 ) +2025 — — — 6,225 ( 0.37 ) ( 688 ) +Total Basis Protection - Natural Gas — 100,127 ( 30,352 ) +Commodity Derivatives Fair Value $ ( 270,293 ) +Effect of Derivative Instruments on the Consolidated Balance Sheet. The balance sheet line items and fair value amounts of our derivative instruments are disclosed in Note 5 - Fair Value Measurements . +78 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Our financial derivative agreements contain master netting provisions that provide for the net settlement of contracts through a single payment in the event of early termination. We have elected not to offset the fair value positions recorded on our consolidated balance sheets. +The following table reflects the impact of netting agreements on gross derivative assets and liabilities: +Total Gross Amount Presented on the Balance Sheet Effect of Master Netting Agreements Total Net Amount +As of December 31, 2022 (in thousands) +Derivative asset instruments, at fair value $ 57,525 $ ( 57,525 ) $ — +Derivative liability instruments, at fair value $ 327,818 $ ( 57,525 ) $ 270,293 +As of December 31, 2021 +Derivative asset instruments, at fair value $ 33,086 $ ( 33,086 ) $ — +Derivative liability instruments, at fair value $ 400,431 $ ( 33,086 ) $ 367,345 +Derivative Counterparties. Our commodity derivative instruments expose us to the risk of non-performance by our counterparties. We use financial institutions who are also lenders under our revolving credit facility as counterparties to our commodity derivative contracts. To date, we have had no derivative counterparty default losses. We have evaluated the credit risk of our derivative assets from our counterparties using relevant credit market default rates, giving consideration to amounts outstanding for each counterparty and the duration of each outstanding derivative position. Based on our evaluation, we have determined that the potential impact of non-performance of our current counterparties on the fair value of our derivative instruments is not significant at December 31, 2022; however, this determination may change. +NOTE 7 - PROPERTIES AND EQUIPMENT, NET +The following table presents the components of properties and equipment, net of accumulated depreciation, depletion and amortization (“DD&A”), as of the dates indicated: +December 31, +2022 2021 +(in thousands) +Properties and equipment, net: +Crude oil and natural gas properties +Proved $ 11,324,756 $ 8,310,018 +Unproved 156,418 306,181 +Total crude oil and natural gas properties 11,481,174 8,616,199 +Equipment and other 72,151 63,099 +Land and buildings 25,406 19,928 +Construction in progress 716,302 371,968 +Properties and equipment, at cost 12,295,033 9,071,194 +Accumulated DD&A ( 5,001,678 ) ( 4,256,329 ) +Properties and equipment, net $ 7,293,355 $ 4,814,865 +79 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Suspended Well Costs. The following table presents the changes in ca pitalized exploratory well cost pending determination of proved reserves and included in properties and equipment for the periods presented: +Year Ended December 31, +2022 2021 2020 +(in thousands, except for number of wells) +Beginning balance $ — $ 7,459 $ 16,078 +Additions to capitalized exploratory well costs pending the determination of proved reserves — 5,902 11,770 +Reclassifications to proved properties — ( 13,361 ) ( 20,389 ) +Ending balance $ — $ — $ 7,459 +Number of wells pending determination at period-end — — 2 +During the year ended December 31, 2022, we drilled and turned-in-line an exploratory well in the Delaware Basin that did not yield sufficient projected returns for it to be deemed economically viable. Therefore, in 2022, we expensed the associated lease costs and related infrastructure assets of the exploratory dry hole at a cost of $ 12.0 million, an amount which was recognized on the consolidated statements of operations as exploration, geologic and geophysical expense. +As of December 31, 2020, our net capitalized exploratory well costs that had been capitalized for a period greater than one year was $ 7.5 million, which comprised the entire balance of our suspended well costs and related to two gross suspended wells associated with two projects. During the year ended December 31, 2021, both exploratory wells were determined to be successful producing wells and were reclassified into proved properties. We had no capitalized exploratory well costs pending determination as of December 31, 2022 and 2021. +Impairment of Oil and Gas Properties. The following table presents impairment charges recorded for properties and equipment for the periods presented: +Year Ended December 31, +2022 2021 2020 +(in thousands) +Impairment of proved and unproved properties $ 6,762 $ 402 $ 881,238 +Impairment of infrastructure and other — — 1,155 +Total impairment of properties and equipment $ 6,762 $ 402 $ 882,393 +Oil and Gas Properties. +In the first quarter of 2020, the significant decline in crude oil prices in addition to the ongoing effects of the COVID-19 pandemic were considered a triggering event that required us to assess our crude oil and natural gas properties for possible impairment. As a result of our assessment, we recorded impairment expense of $ 881.1 million to our proved and unproved properties. During the years ended December 31, 2022 and 2021, there were no significant impairments recognized. +Proved Properties. Of the total impairment expense recognized in 2020, approximately $ 753.0 million was related to our Delaware Basin proved properties. These impairment charges represented the amount by which the carrying value of the crude oil and natural gas properties exceeded the estimated fair value. We estimated the fair value of proved crude oil and natural gas properties using valuation techniques that convert future cash flows to a single discounted amount, a Level 3 input. Significant inputs and assumptions to the valuation of proved crude oil and natural gas properties include estimates of future production volumes, future operating and development costs, future commodity prices, and a discount rate of 17 percent, which was based on a weighted average cost of capital for the area where the assets are located. +Unproved Properties. We recognized approximately $ 127.3 million of impairment charges for our unproved properties in the Delaware Basin in 2020. These impairment charges were recognized based on the fair value of the properties, a Level 3 input. The fair value was estimated based on a review of our drilling plans, estimated future cash flows for probable well locations and expected lease expirations, primarily in areas where we had no development plans. +80 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 8 - ACCOUNTS RECEIVABLE, OTHER ACCRUED EXPENSES AND OTHER LIABILITIES +Accounts Receivable. The following table presents the components of accounts receivable, net of allowance for doubtful accounts as of the dates indicated: +December 31, +2022 2021 +(in thousands) +Crude oil, natural gas and NGLs sales $ 491,327 $ 368,991 +Joint interest billings 46,633 24,860 +Other 13,796 10,809 +Allowance for doubtful accounts ( 5,445 ) ( 6,055 ) +Accounts receivable, net $ 546,311 $ 398,605 +The Company’s accounts receivable consist mainly of receivables from (i) crude oil, natural gas and NGLs purchasers, (ii) joint interest owners in the properties we operate and (iii) derivative counterparties. Most payments for production are received within two months after the production date. For receivables from joint interest owners, we typically have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. +Credit and Concentration Risk. Inherent to our industry is the concentration of crude oil, natural gas and NGLs sales to a limited number of customers. This concentration has the potential to impact our overall exposure to credit risk in that our customers may be similarly affected by changes in economic and financial conditions, commodity prices or other conditions. +Given the liquidity in the market for the sale of hydrocarbons, we believe that the loss of any single purchaser, or the aggregate loss of several purchasers, could be managed by selling to alternative purchasers in our operating areas. The following major customers accounted for 10 percent or more of our total crude oil, natural gas, and NGLs sales for at least one of the periods presented: +Year Ended December 31, +2022 2021 2020 +Major customer #1 27 % 32 % 31 % +Major customer #2 9 % 9 % 16 % +Major customer #3 7 % 11 % 13 % +Major customer #4 5 % 10 % 17 % +Other Accrued Expenses. The following table presents the components of other accrued expenses as of the dates indicated: +December 31, +2022 2021 +(in thousands) +Employee benefits $ 29,288 $ 29,319 +Asset retirement obligations 25,986 32,146 +Environmental expenses 25,666 11,942 +Operating and finance leases 5,987 7,197 +Other 19,155 10,805 +Other accrued expenses $ 106,082 $ 91,409 +81 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Other Liabilities. The following table presents the components of other liabilities as of the dates indicated: +December 31, +2022 2021 +(in thousands) +Deferred midstream gathering credits $ 145,937 $ 159,788 +Production taxes 315,758 131,865 +Operating and finance leases 41,815 6,274 +Other 29,360 16,842 +Other liabilities $ 532,870 $ 314,769 +Deferred Midstream Gathering Credits. In 2019, we entered into agreements pursuant to which we dedicated the gathering of some of our production and all water gathering and disposal volumes in the Delaware Basin. The terms of these agreements range from 15 to 22 years. The acreage dedication agreements resulted in initial cash receipts and are being amortized on a units-of-production basis. The amortization rates are assessed on an annual basis for changes in estimated future production. +The following table presents the amortization charges related to our deferred credits recognized on the consolidated statements of operations for the periods indicated: +Year Ended December 31, +2022 2021 +(in thousands) +Transportation, gathering and processing expense $ 11,037 $ 7,317 +Lease operating expense 3,753 2,422 +NOTE 9 - LONG-TERM DEBT +Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $ 6.0 million and $ 7.9 million as of December 31, 2022 and December 31, 2021, respectively, consists of the following: +December 31, +2022 2021 +(in thousands) +Revolving credit facility due November 2026 $ 370,000 $ — +6.125% Senior Notes due September 2024 199,163 198,674 +5.75% Senior Notes due May 2026 744,847 743,410 +Total debt, net of unamortized discount, premium and debt issuance costs $ 1,314,010 $ 942,084 +Revolving Credit Facility +In November 2021, we entered into a Fifth Amended and Restated Credit Agreement (the “Restated Credit Agreement”), which provides for a maximum credit amount of $ 2.5 billion , subject to certain limitations, an initial borrowing base of $ 2.4 billion and an elected commitment of $ 1.5 billion . The Restated Credit Agreement matures on the earlier to occur of (i) the end of the five year term on November 2, 2026 or (ii) the date that is 91 days prior to the scheduled maturity of the 2026 Senior Notes if the aggregate outstanding principal amount of those notes exceeds $500 million and our commitment utilization exceeds 50%. In the semi-annual redetermination that occurred in 2022, the borrowing base increased from $ 3.0 billion to $ 3.5 billion as a result of the reserves acquired in the Great Western Acquisition; however, we maintained our elected commitment amount of $ 1.5 billion . +The revolving credit facility is available for working capital requirements, capital investments, acquisitions, to support letters of credit and for general business purposes. The borrowing base is based on, among other things, the loan value assigned to the proved reserves attributable to our crude oil and natural gas interests. The borrowing base is subject to a semi-annual redetermination on November 1 and May 1 based upon quantification of our reserves at June 30 and December 31, and is also +82 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +subject to a redetermination upon the occurrence of certain events. Substantially all of our crude oil and natural gas properties have been mortgaged or pledged as security for our revolving credit facility. The Restated Credit Agreement includes an investment grade period election pursuant to which we have an option to remove our borrowing base limitations and terminate the liens securing the Restated Credit Agreement when certain debt ratings are achieved. +As of December 31, 2022, we had a borrowing base of $ 3.5 billion, an elected commitment of $ 1.5 billion and availability under our revolving credit facility of $ 1.1 billion, net of $ 20.4 million of letters of credit outstanding. +The outstanding principal amount under the revolving credit facility accrues interest at a varying interest rate that fluctuates with an alternate base rate (equal to the greatest of the administrative agent's prime rate, the federal funds rate plus a premium and the rate for dollar deposits in the Secured Overnight Financing Rate (“SOFR”) for one month, plus a premium) or, at our election, a rate equal to SOFR for certain time periods. Additionally, commitment fees, interest margin and other bank fees, charged as a component of interest, vary with our utilization of the facility. As of December 31, 2022, the applicable interest margin is 0.75 percent for the alternate base rate option or 1.75 percent for the SOFR option, and the unused commitment fee is 0.375 percent. Principal payments are generally not required until the maturity date of the revolving credit facility, unless the borrowing base falls below the outstanding balance. The Restated Credit Agreement also includes the ability to add certain sustainability-linked key performance indicators to be agreed upon between us, the administrative agent and a majority of the lenders and that may impact the applicable margin and commitment fee rate. +The revolving credit facility contains various restrictive covenants and compliance requirements, which include, among other things: (i) maintenance of certain financial ratios, as defined per the revolving credit facility, including a minimum current ratio of 1.0:1.0 and a maximum leverage ratio of 3.5:1.0; (ii) restrictions on the payment of cash dividends; (iii) limits on the incurrence of additional indebtedness; (iv) prohibition on the entry into commodity hedges exceeding a specified percentage of our expected production; and (v) restrictions on mergers and dispositions of assets. As of December 31, 2022, we were in compliance with all covenants related to our revolving credit facility. +As of December 31, 2022 and 2021, debt issuance costs related to our revolving credit facility were $ 13.5 million and $ 16.9 million, respectively, and are included in other assets on our consolidated balance sheets. +Senior Notes +The following table summarizes the face values, interest rates, maturity dates, semi-annual interest payment dates, and optional redemption periods related to our outstanding senior note obligations as of December 31, 2022: +2024 Senior Notes 2026 Senior Notes +Outstanding principal amounts (in thousands) $ 200,000 $ 750,000 +Interest rate 6.125 % 5.75 % +Maturity date September 15, 2024 May 15, 2026 +Interest payment dates March 15, September 15 May 15, November 15 +Redemption periods (1) +September 15, 2022 May 15, 2024 +_____________ +(1) At any time prior to the indicated dates, we have the option to redeem all or a portion of our senior notes of the applicable series at the redemption amounts specified in the respective senior note indenture plus accrued and unpaid interest to the date of redemption. On or after the indicated dates, we may redeem all or a portion of the senior notes at a redemption amount equal to 100% of the principal amount of the senior notes being redeemed plus accrued and unpaid interest to the date of redemption. +The 2024 Senior Notes and the 2026 Senior Notes (collectively, the “Senior Notes”) are senior unsecured obligations and rank senior in right of payment to our future indebtedness that is expressly subordinated to the notes; equal in right of payment to our existing and future indebtedness that is not so subordinated; effectively junior in right of payment to all of our secured indebtedness to the extent of the value of the assets securing such indebtedness; and structurally junior to all existing and future indebtedness (including trade payables) incurred by our non-guarantor subsidiaries. +Upon the occurrence of a “change of control”, as defined in the indentures for the Senior Notes, holders will have the right to require us to repurchase all or a portion of the notes at a price equal to 101 percent of the aggregate principal amount of the notes repurchased, together with accrued and unpaid interest to the date of purchase. In connection with certain asset sales, we may, under certain circumstances, be required to use the net cash proceeds of such asset sale to make an offer to purchase the notes at 100 percent of the principal amount, together with accrued and unpaid interest to the date of purchase. +83 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The indentures governing the Senior Notes contain covenants and restricted payment provisions that, among other things, limit our ability and the ability of our subsidiaries to incur additional indebtedness; pay dividends or make distributions on our stock; purchase or redeem stock or subordinated indebtedness; make investments; create certain liens; enter into agreements that restrict distributions or other payments by restricted subsidiaries to us; enter into transactions with affiliates; sell assets; consolidate or merge with or into other companies or transfer all or substantially of our assets; and create unrestricted subsidiaries. As of December 31, 2022, we were in compliance with all covenants and all restricted payment provisions related to our Senior Notes. +Our wholly-owned subsidiaries PDC Permian, Inc. and Pioneer Water Pipeline LLC (acquired in connection with the Great Western Acquisition), are each a guarantor of our obligations under our Senior Notes and our credit facility. +NOTE 10 - LEASES +We have operating leases for office space and well equipment, and finance leases for vehicles. Our leases have remaining lease terms ranging from one month to ten years . The vehicle leases include an option to renew on a month-to-month basis after the primary term. Lease payments associated with vehicle leases also include a contractually stated residual value guarantee. +The following table presents the components of lease costs for the periods presented: +Year Ended December 31, +2022 2021 +(in thousands) +Operating lease costs (1) +$ 6,743 $ 6,125 +Finance lease costs: +Amortization of ROU assets 2,100 1,752 +Interest on lease liabilities 270 164 +Total finance lease costs 2,370 1,916 +Short-term lease costs (1) +338,404 203,361 +Total lease costs $ 347,517 $ 211,402 +_______________ +(1) The lease costs presented in the table above represent the total gross costs we incur, which are not comparable to our net costs recorded to the consolidated statements of operations, consolidated statements of cash flows or capitalized in the consolidated balance sheets, as amounts therein are reflected net of amounts billed to working interest partners. +Our operating lease costs are recorded in lease operating expenses or general and administrative expense and our finance lease costs are recorded in DD&A expense and interest expense. Our short-term lease costs include amounts that are capitalized as part of the cost of assets and are recorded as properties and equipment or recognized as expense. +The following table presents the balance sheet classification and other information regarding our leases as of the dates indicated: +December 31, +Leases Consolidated Balance Sheet Line Item 2022 2021 +(in thousands) +Operating lease ROU assets Other assets $ 19,577 $ 7,630 +Finance lease ROU assets Properties and equipment, net 6,184 3,483 +Total ROU assets $ 25,761 $ 11,113 +Operating lease obligation - short-term Other accrued expenses $ 3,825 $ 5,937 +Operating lease obligation - long-term Other liabilities 37,720 4,044 +Finance lease obligation - short-term Other accrued expenses 2,162 1,260 +Finance lease obligation - long-term Other liabilities 4,095 2,230 +Total lease liabilities $ 47,802 $ 13,471 +84 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +December 31, +Leases Consolidated Balance Sheet Line Item 2022 2021 +(in thousands) +Weighted average remaining lease term (years) 7.9 2.8 +Weighted average discount rate 5.1 % 4.8 % +Maturity of lease liabilities by year and in the aggregate, under operating and financing leases with terms of one year or more, as of December 31, 2022 consist of the following: +Operating Leases Finance Leases Total +(in thousands) +2023 $ 4,063 $ 2,404 $ 6,467 +2024 3,101 1,891 4,992 +2025 6,682 1,698 8,380 +2026 6,754 649 7,403 +2027 5,821 73 5,894 +Thereafter 27,512 — 27,512 +Total lease payments 53,933 6,715 60,648 +Less: Interest and discount ( 12,388 ) ( 458 ) ( 12,846 ) +Present value of lease liabilities $ 41,545 $ 6,257 $ 47,802 +In September 2022, we entered into a three-year drilling rig agreement with total gross lease payments of approximately $ 34 million which we expect to commence and be recognized on our balance sheet in the first quarter of 2023. +NOTE 11 - ASSET RETIREMENT OBLIGATIONS +The following table presents the changes in carrying amounts of the asset retirement obligations associated with our working interests in crude oil and natural gas properties for the periods presented: +Year Ended December 31, +2022 2021 +(in thousands) +Beginning balance $ 159,672 $ 166,570 +Obligations incurred with development activities and other 5,332 4,750 +Obligations incurred with acquisition 25,300 — +Accretion expense 13,408 12,086 +Revisions in estimated cash flows 19,606 10,609 +Obligations discharged with asset retirements and divestitures ( 25,667 ) ( 34,343 ) +Asset retirement obligations at end of period 197,651 159,672 +Current portion (1) +( 25,986 ) ( 32,146 ) +Long-term portion $ 171,665 $ 127,526 +_______________ +(1) The current portion of the asset retirement obligation is included in other accrued expenses on our consolidated balance sheets. +Our estimated asset retirement obligations liability is based on historical experience in plugging and abandoning wells, estimated economic lives and estimated plugging, abandonment and surface reclamation costs considering federal and state regulatory requirements in effect at the time that the obligation is incurred. The liability is discounted using the credit-adjusted risk-free rate estimated at the time the liability is incurred or revised. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations liability, a corresponding adjustment is made to the properties and equipment balance. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as accretion expense. +85 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +NOTE 12 - COMMITMENTS AND CONTINGENCIES +The following table presents our firm transportation, sales and processing, water delivery and disposal and purchase commitments: +Year Ending December 31, +(in thousands) 2023 2024 2025 2026 2027 Thereafter Total +Firm transportation $ 96,567 $ 64,403 $ 49,187 $ 36,692 $ 10,388 $ 28,364 $ 285,601 +Gas gathering and processing agreements 117,828 117,509 101,553 61,633 35,608 43,801 477,932 +$ 214,395 $ 181,912 $ 150,740 $ 98,325 $ 45,996 $ 72,165 $ 763,533 +Firm Transportation and Processing Agreements. We enter into certain contracts that provide firm transportation and processing on pipeline systems through which we transport or sell crude oil and natural gas. Under certain of these agreements, we are obligated to ship minimum daily quantities of crude oil or natural gas or pay for any deficiencies at a specified rate or incremental charges. Satisfaction of the volume requirements includes volumes produced by us and purchased from third parties and produced by other third-party working, royalty and overriding royalty interest owners, whose volumes we market on their behalf. We may from time to time find ourselves unable to market our commodities at prices acceptable to us, or at all, which could cause us to be unable to meet these obligations. In such cases, we may be subject to fees, minimum margins or other payments. Our consolidated statements of operations reflect our share of these firm transportation and processing costs. Payments related to our long-term transportation and processing agreements, net of interests, were $ 64.1 million, $ 31.3 million, and $ 21.4 million for the years ended December 31, 2022, 2021, and 2020, respectively. For the years ended December 31, 2022 and 2021, we did not incur material transportation reservation charges under these agreements. +Gas Gathering and Processing Agreements. We entered into certain long-term gas gathering and processing agreements pursuant to which we are obligated to deliver minimum daily quantities of natural gas to certain gas gathering and processing plants for processing or pay for any deficiencies at a specified rate or margin. If we ceased operations in the areas subject to these agreements at December 31, 2022, the total deficiencies required to be paid by the Company under these agreements are reflected in the table presented above. Our consolidated statements of operations reflect our share of these processing costs. +Firm sales agreement . As of December 31, 2022 we had a firm sales agreement with an integrated marketing company for our crude oil production in the Delaware Basin through 2023. This agreement is expected to provide price diversification through realization of export market pricing via a Corpus Christi terminal and exposure to Brent-weighted prices. This agreement does not require physical delivery of the minimum volumes of crude oil over the contractual term. However, if we do not sell and deliver at least the minimum contract volume pursuant to the agreement, we are required to pay transportation reservation charges related to the undelivered volume. For the years ended December 31, 2022 and 2021, we did not incur material transportation reservation charges under this agreement. +Litigation and Legal Items. We are involved in various legal proceedings. We review the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in our best interests. We have provided the necessary estimated accruals in the accompanying consolidated balance sheets where deemed appropriate for litigation and legal related items that are ongoing and not yet concluded. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our financial position, results of operations or liquidity. +NOTE 13 - COMMON STOCK +Stock-Based Compensation Plans +2018 Equity Incentive Plan . In 2020, our stockholders approved an amendment to increase the number of shares of our common stock reserved for issuance pursuant to our long-term equity compensation plan for employees and non-employee directors (the “2018 Plan”) to 7,050,000 shares. The 2018 Plan expires in March 2028. The capital stock available for issuance under the 2018 Plan consists of shares of the Company’s authorized but unissued common stock or previously issued common stock that has been reacquired by the Company. Additionally, to the extent that an award under the 2018 Plan, in whole or in part, is canceled, expired, forfeited, settled in cash or otherwise terminated without delivery of shares, such shares remain +86 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +available for issuance. Any shares withheld for taxes cannot be recycled under this plan. Awards may be issued in the form of stock options, stock appreciation rights (“SARs”), restricted stock, restricted stock units (“RSUs”), performance stock units (“PSUs”) and other stock-based awards. Awards may vest over periods of continued service or upon the satisfaction of performance conditions set at the discretion of the Compensation Committee of our board of directors (the “Compensation Committee”), with a minimum one-year vesting period applicable to most awards. With regard to SARs and stock options, awards have a maximum exercisable period of ten years. As of December 31, 2022, there were 3,840,404 shares available for grant under the 2018 Plan. +2010 Long-Term Equity Compensation Plan . Our Amended and Restated 2010 Long-Term Equity Compensation Plan, approved in 2013 (the “2010 Plan”), remains outstanding and we may continue to use the 2010 Plan to grant awards. No awards may be granted under the 2010 Plan on or after June 5, 2023. As of December 31, 2022, there were 245,156 shares available for grant under the 2010 Plan. +2015 SRC Equity Incentive Plan . Pursuant to the closing of the SRC Acquisition, SRC granted PSUs to certain SRC executives (the “SRC PSUs”) under the 2015 SRC Equity Incentive Plan (the “2015 SRC Plan”). The SRC PSUs were converted into 155,928 PDC PSUs and remained subject to the same terms and conditions (including performance-vesting terms) that applied immediately prior to the closing of the SRC Acquisition. As of December 31, 2021, all converted SRC PSUs vested and in 2022, the 2015 SRC Plan was closed and retired. +The following table provides a summary of the impact of our outstanding stock-based compensation plans on the results of operations for the periods presented: +Year Ended December 31, +2022 2021 2020 +(in thousands) +General and administrative expense $ 25,257 $ 21,830 $ 21,182 +Lease operating expense 1,589 1,193 1,018 +Total stock-based compensation expense $ 26,846 $ 23,023 $ 22,200 +Restricted Stock Units +The Company grants to executive officers and employees time-based RSUs, which vest ratably over a three-year service period. The fair value of these time-based RSUs is based on the closing market price of our common stock on the grant date and is recognized ratably over the requisite service period. The time-based RSUs generally vest ratably on each anniversary following the grant date provided that a participant is continuously employed. +The following table presents the changes in non-vested time-based RSUs to eligible employees, including executive officers, during the year ended December 31, 2022: +Shares Weighted Average Grant-Date Fair Value per Share +Non-vested at beginning of period 1,165,187 $ 25.33 +Granted 363,395 70.01 +Vested ( 581,343 ) 26.15 +Forfeited ( 50,728 ) 40.58 +Non-vested at end of period 896,511 42.05 +The weighted average grant-date fair value of restricted stock units was $ 70.01 , $ 33.64 and $ 11.98 for the years ended December 31, 2022, 2021 and 2020, respectively. The total grant-date fair value of restricted stock units that vested for the years ended December 31, 2022, 2021 and 2020 was $ 15.2 million, $ 13.6 million and $ 20.4 million, respectively. Total compensation cost related to non-vested time-based awards and not yet recognized on the consolidated statements of operations as of December 31, 2022 was $ 24.7 million. This cost is expected to be recognized over a weighted average period of 1.3 years. +87 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Performance Stock Units +The Company grants to certain executive officers PSUs, which are subject to market-based vesting criteria as well as a three-year service period. The market-based shares vest if the participant is continuously employed throughout the performance period and the market-based performance measure is achieved. The fair value of the market-based PSUs is amortized ratably over the requisite service period. All compensation cost related to the market-based awards will be recognized if the requisite service period is fulfilled, even if the market condition is not achieved. +The Compensation Committee awarded a total of 102,098 market-based PSUs to our executive officers during 2022. In addition to continuous employment, the vesting of these PSUs is contingent on a combination of absolute stock performance and our total stockholder return (“TSR”), which is essentially our stock price change including any dividends over a three-year period ending on December 31, 2024, as compared to the TSR of a group of peer companies over the same period. The PSUs will result in a payout between zero and 250 percent of the target PSUs awarded. +The grant-date fair value was estimated using a Monte Carlo valuation model. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. The expected term of the awards was based on the requisite service period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant and extrapolated to approximate the life of the award. The expected volatility was based on our common stock historical volatility, as well as that of our peer group. +The following table summarizes the key assumptions and related information used to determine the grant-date fair value of performance stock units awarded during the periods presented: +Year Ended December 31, +2022 2021 2020 +Expected term of award (in years) 2.9 3.0 3.0 +Risk-free interest rate 1.7 % 0.2 % 1.4 % +Expected volatility 86.3 % 84.6 % 46.6 % +Weighted average grant-date fair value per share $ 107.85 $ 54.01 $ 33.52 +The expected term of the awards is based on the number of years from the grant date through the end of the performance period. The risk-free interest rate was based on the U.S. Treasury yields in effect at the time of grant, extrapolated to approximate the life of the awards. The expected volatility was based on our common stock historical volatility, as well as that of our peer group. +The following table presents the change in non-vested market-based awards during the year ended December 31, 2022: +Shares Weighted Average Grant-Date Fair Value per Share +Non-vested at December 31, 2021 439,229 $ 43.21 +Granted 102,098 107.85 +Granted for performance multiple (1) +347,363 33.52 +Vested ( 578,937 ) 33.52 +Non-vested at December 31, 2022 309,753 71.76 +_______________ +(1) Upon completion of the performance period for the PSUs granted in 2020, a performance multiple of 250% was applied to each of the grants resulting in additional grants of PSUs in December 2022. +The total grant-date fair value of performance stock units that vested in the years ended December 31, 2022, 2021 and 2020 was $ 19.4 million, $ 11.6 million and $ 4.7 million, respectively. Total compensation cost related to non-vested market-based awards not yet recognized on the consolidated statements of operations as of December 31, 2022 was $ 11.6 million. This cost is expected to be recognized over a weighted average period of 1.3 years. +88 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +Preferred Stock +We are authorized to issue 50,000,000 shares of preferred stock, par value $ 0.01 per share, which may be issued in one or more series, with such rights, preferences, privileges and restrictions as shall be fixed by our board of directors from time to time. Through December 31, 2022, no shares of preferred stock have been issued. +Stock Repurchase Program +In 2019, our board of directors approved a program pursuant to which we may acquire shares of our common stock from time to time. At December 31, 2021, $ 187.3 million of the approved $ 525.0 million remained available for repurchase under the stock repurchase program. In February 2022, our board of directors approved a new stock repurchase program that reset the total repurchase value to $1.25 billion. The stock repurchase program does not require any specific number of shares to be acquired and can be modified or discontinued by our board of directors at any time. Repurchases under the program can be made in open markets at our discretion and in compliance with safe harbor provisions, or in privately negotiated transactions. Pursuant to the program, we repurchased 12.1 million and 3.8 million shares of outstanding common stock at a cost of $ 823.4 million and $ 159.5 million during the years ended December 31, 2022 and 2021, respectively. As of December 31, 2022, $ 454.7 million remained available under the program for repurchases of our outstanding common stock. In February 2023, our board of directors approved a $750 million increase in the size of our stock repurchase program. +Dividends +In the second quarter of 2021, our board of directors approved the declaration and payment of quarterly cash dividends of common stock. For the years ended December 31, 2022 and 2021, our dividends declared totaled $ 1.95 per share of outstanding common stock or $ 184.3 million and $ 0.86 per share of outstanding common stock or $ 83.6 million, respectively. All RSUs and PSUs receive a dividend equivalent per unit, recognized as a liability included in other liabilities on our consolidated balance sheets, until the recipients receive the equivalents upon vesting. Dividends declared were recorded as a reduction of retained earnings, however, if there were no retained earnings as of the date of declaration, dividends declared were recorded as a reduction of additional paid-in capital. Future dividend payments must be approved by our board of directors and will depend on our liquidity, financial requirements, and other factors considered relevant by our board. In February 2023, our board of directors approved an increase in the quarterly base dividend from $0.35 to $0.40 per share. +NOTE 14 - INCOME TAXES +The table below presents the components of our provision for income tax (expense) benefit for the periods presented: +Year Ended December 31, +2022 2021 2020 +(in thousands) +Current: +Federal $ ( 400 ) $ — $ 1,592 +State ( 900 ) ( 200 ) ( 220 ) +Total current income tax benefit ( 1,300 ) ( 200 ) 1,372 +Deferred: +Federal ( 385,300 ) ( 23,790 ) 5,460 +State ( 67,600 ) ( 2,593 ) 1,070 +Total deferred income tax (expense) benefit ( 452,900 ) ( 26,383 ) 6,530 +Income tax (expense) benefit $ ( 454,200 ) $ ( 26,583 ) $ 7,902 +89 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents a reconciliation of the federal statutory rate to the effective tax rate related to our (expense) benefit for income taxes for the periods presented: +Year Ended December 31, +2022 2021 2020 +Federal statutory tax rate 21.0 % 21.0 % 21.0 % +State income tax, net 2.4 3.2 3.0 +Change in valuation allowance ( 2.0 ) ( 19.8 ) ( 22.1 ) +Other ( 1.1 ) 0.4 ( 0.8 ) +Effective tax rate 20.3 % 4.8 % 1.1 % +The effective income tax rates for 2022, 2021 and 2020 were 20.3 percent, 4.8 percent and 1.1 percent on the respective pre-tax income or loss. The effective tax rates differ from the amount that would be provided by applying the statutory U.S. federal income tax rate of 21 percent to the pre-tax income or loss due to state income taxes and changes in the valuation allowance against our deferred income tax asset. +Tax effects of temporary differences that give rise to significant portions of deferred tax assets and deferred tax liabilities as of the dates indicated: +December 31, +2022 2021 +(in thousands) +Deferred tax assets: +Fair value of unsettled commodity derivatives $ 64,622 $ 88,053 +Asset retirement obligations 47,919 38,274 +Federal NOL carryforward 84,323 97,555 +State NOL and tax credit carryforwards, net 16,190 20,266 +Federal tax - credit carryforwards 3,555 3,059 +Deferred compensation 7,985 9,949 +Other 8,407 8,308 +Valuation allowance — ( 56,634 ) +Total gross deferred tax assets 233,001 208,830 +Deferred tax liabilities: +Properties and equipment 740,684 235,213 +Net deferred tax liability $ 507,683 $ 26,383 +We consider whether a portion, or all, of our deferred tax assets (“DTAs”) will be realized based on a more likely than not standard of judgment. The ultimate realization of DTAs is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. At each reporting period, management considers the available taxes in carryback periods, the future reversals of existing taxable temporary differences, tax planning strategies and projected future taxable income in making this assessment. The oil and gas property impairments and cumulative pre-tax losses were key considerations that led us to provide a valuation allowance against our DTAs beginning January 1, 2020 since we previously could not conclude that it is more likely than not that our DTAs will be fully realized in future periods. +As we previously disclosed, we maintained a valuation allowance on our federal deferred tax assets and continued to do so until sufficient positive evidence existed to support a reversal of the allowance. In 2022, continued higher commodity prices increased our income, resulting in the reversal of objective negative evidence of cumulative loss in recent years, and we determined that we had sufficient positive evidence to release the valuation allowance. As a result, we released in full the valuation allowance against our deferred income tax assets of $56.6 million and recognized a corresponding decrease to income tax expense. +As of December 31, 2022, we have estimated net operating loss carryforwards (“NOLs”) for federal income tax purposes of $ 401.5 million, of which $ 201.3 million was generated before January 1, 2018 and will begin to expire in 2037. In +90 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +2020, we acquired a federal NOL of $ 232.5 million as a component of the SRC Acquisition. This NOL is subject to an annual limitation of $ 16.1 million, as the acquisition constituted a change of ownership for SRC as defined under Internal Revenue Service (“IRS”) Code Section 382. +As of December 31, 2022, we have state NOL carryforwards of $ 331.2 million that begin to expire in 2029 and state credit carryforwards of $ 4.5 million that begin to expire in 2023. +Unrecognized tax benefits and related accrued interest and penalties were immaterial for the three-year period ended December 31, 2022. As of December 31, 2022, there is no liability for unrecognized income tax benefits. +We are subject to the following material taxing jurisdictions: U.S., Colorado and Texas. As of December 31, 2022, we are current with our income tax filings in all applicable state jurisdictions and are not currently under any state income tax examinations. We are open to federal and state tax audits until the applicable statutes of limitations expire, however, the ability for the tax authority to adjust the NOL will continue until three years after the NOL is utilized. The statute of limitations has expired for all federal and state returns filed for periods ending before 2017. The IRS has accepted our 2020 and 2021 federal income tax returns with no tax adjustments. We continue to voluntarily participate in the IRS CAP Program. For 2022, we are in the Bridge Phase of the CAP, which means that the IRS will not be examining the 2022 tax year. Participation in the IRS CAP Program has enabled us to have minimal uncertain tax benefits associated with our federal tax return filings. The statutes of limitations for most of our state tax jurisdictions are open for tax years after 2017. +In August 2022, the Inflation Reduction Act (“IRA”) was signed into law. The IRA includes implementation of a new alternative minimum tax, an excise tax on stock buybacks, and significant tax incentives for energy and climate initiatives, among other provisions. The alternative minimum tax and excise tax on stock buyback provisions are effective for tax years beginning after December 31, 2022. We continue to monitor updates to the IRA and the impact to our financial position, results of operations and liquidity. We do not believe it will have a material impact on our stock buyback program or our financial position in 2023, however, we are still assessing the impact for subsequent years. +NOTE 15 - EARNINGS PER SHARE +Basic earnings per share is computed by dividing net earnings by the weighted average number of common shares outstanding for the period. Diluted earnings per share is similarly computed except that the denominator includes the effect, using the treasury stock method, of unvested stock-based employee awards, convertible notes (if applicable) and shares held pursuant to our non-employee director deferred compensation plan, if including such potential shares of common stock is dilutive. +The following table presents our weighted average basic and diluted shares outstanding for the periods presented: +Year Ended December 31, +2022 2021 2020 +(in thousands) +Weighted average common shares outstanding - basic 94,796 98,546 98,251 +Dilutive effect of: +RSUs and PSUs 1,352 1,596 — +Other equity-based awards 26 12 — +Weighted average common shares and equivalents outstanding - diluted 96,174 100,154 98,251 +We reported a net loss for the year ended December 31, 2020, and as a result, our basic and diluted weighted average common shares outstanding were the same for the period because the effect of the common share equivalents were anti-dilutive. +91 +Table of contents +PDC ENERGY, INC. +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued +The following table presents the weighted average common share equivalents excluded from the calculation of diluted earnings per share due to their anti-dilutive effect for the periods presented: +Year Ended December 31, +2022 2021 2020 +(in thousands) +Weighted average common share equivalents excluded from diluted earnings per share due to their anti-dilutive effect: +RSUs and PSUs 144 28 1,707 +Other equity-based awards 32 116 229 +Total anti-dilutive common share equivalents 176 144 1,936 +NOTE 16 - SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION +Year Ended December 31, +2022 2021 2020 +(in thousands) +Supplemental cash flow information +Cash payments (receipts) for +Interest, net of capitalized interest $ 58,143 $ 66,647 $ 75,506 +Income taxes 58 ( 1,057 ) 9 +Non-cash investing and financing activities +Change in accounts payable related to capital expenditures 38,384 519 ( 28,676 ) +Change in asset retirement obligations, with a corresponding change to crude oil and natural gas properties, net of disposals 21,778 11,673 54,984 +Issuance of common stock for acquisition of an exploration and production business 293,314 — 1,009,015 +Cash paid for amounts included in the measurement of lease liabilities +Operating cash flows from operating leases $ 7,230 $ 7,603 $ 9,246 +Operating cash flows from finance leases 254 117 156 +Right-of-use assets recognized (derecognized) with offsetting lease liabilities +Operating leases (1) +$ 17,247 $ 1,457 $ 4,305 +Finance leases 4,919 2,109 703 +_____________ +(1) Includes $ 1.5 million operating lease acquired from Great Western. +92 +Table of contents +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +CRUDE OIL AND NATURAL GAS INFORMATION - UNAUDITED +Net Proved Reserves +All of our crude oil, natural gas and NGLs reserves are located in the United States. We utilize the services of specialists, specifically petroleum engineers, to estimate our crude oil, natural gas and NGLs reserves. As of December 31, 2022, 2021 and 2020 (as applicable), all of our estimates of proved reserves for the Wattenberg Field were based on reserve reports prepared by Ryder Scott and all of our estimates for proved reserves for the Delaware Basin were based on reserve reports prepared by NSAI. These reserve estimates have been prepared in compliance with guidelines established by the SEC and FASB. All of our proved undeveloped reserves conform to the SEC five-year rule requirement that they be scheduled to be drilled within five years of each location’s initial booking date. +Reserve estimates are based on an unweighted arithmetic average of commodity prices during the preceding 12-month period, using the closing prices on the first day of each month, as required by the SEC. The table below presents the index prices for our estimated reserves, by commodity, as of the dates indicated: +Average Benchmark Prices +December 31, +Crude Oil +(per Bbl) (1) +Natural Gas +(per MMBtu) (1) +NGLs +(per Bbl) (2) +2022 $ 93.67 $ 6.36 $ 93.67 +2021 66.56 3.60 66.56 +2020 39.57 1.99 39.57 +____________ +(1) Our benchmark indexes for crude oil and natural gas are WTI and Henry Hub, respectively. +(2) For NGLs, we use the NYMEX crude oil price as a reference for presentation purposes. +The netted back price used to estimate our reserves, by commodity, are presented below: +Price Used to Estimate Reserves (1) +December 31, Crude Oil +(per Bbl) Natural Gas +(per Mcf) +NGLs +(per Bbl) +2022 $ 94.23 $ 4.82 $ 31.60 +2021 65.37 2.85 24.96 +2020 37.52 1.26 10.55 +____________ +(1) These prices are based on the index prices and are net of basin differentials, transportation fees, contractual adjustments and Btu adjustments we experienced for the respective commodity, including consideration for contracts that are effective as of December 31, 2022. +93 +Table of contents +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +The following tables present the changes in our estimated quantities of proved reserves: +Crude Oil, Condensate (MBbls) Natural Gas +(MMcf) NGLs +(MBbls) Total +(MBoe) +Proved reserves, January 1, 2020 197,255 1,557,797 153,976 610,864 +Revisions of previous estimates (41,089) (272,243) (14,774) (101,237) +Extensions, discoveries and other additions 812 2,991 324 1,635 +Acquisition of reserves 80,590 795,977 81,770 295,023 +Dispositions (2,116) (17,711) (1,776) (6,844) +Production (23,720) (165,637) (17,042) (68,368) +Proved reserves, December 31, 2020 211,732 1,901,174 202,478 731,073 +Revisions of previous estimates 22,651 408,540 54,634 145,375 +Extensions, discoveries and other additions 528 1,584 168 960 +Acquisition of reserves 1,616 24,174 2,469 8,113 +Dispositions — — — — +Production (22,682) (175,747) (19,360) (71,333) +Proved reserves, December 31, 2021 213,845 2,159,725 240,389 814,188 +Revisions of previous estimates 15,607 506,220 74,317 174,294 +Extensions, discoveries and other additions — — — — +Acquisition of reserves 68,064 425,870 57,344 196,387 +Dispositions (10) (195) (22) (65) +Production (27,486) (199,362) (24,325) (85,038) +Proved reserves, December 31, 2022 270,020 2,892,258 347,703 1,099,766 +Proved developed reserves, as of: +December 31, 2020 86,330 860,877 91,702 321,512 +December 31, 2021 97,420 1,088,700 120,132 399,002 +December 31, 2022 123,783 1,355,169 168,638 518,283 +Proved undeveloped reserves, as of: +December 31, 2020 125,402 1,040,297 110,776 409,561 +December 31, 2021 116,425 1,071,025 120,257 415,186 +December 31, 2022 146,237 1,537,089 179,065 581,483 +Developed Undeveloped Total +(MBoe) +Proved reserves, January 1, 2020 213,994 396,870 610,864 +Revisions of previous estimates (8,634) (92,603) (101,237) +Extensions, discoveries and other additions 1,635 — 1,635 +Acquisition of reserves 125,180 169,843 295,023 +Dispositions (2,487) (4,357) (6,844) +Production (68,368) — (68,368) +Undeveloped reserves converted to developed 60,192 (60,192) — +Proved reserves, December 31, 2020 321,512 409,561 731,073 +Revisions of previous estimates 75,005 70,370 145,375 +Extensions, discoveries and other additions 960 — 960 +Acquisition of reserves 519 7,594 8,113 +Dispositions — — — +Production (71,333) — (71,333) +Undeveloped reserves converted to developed 72,339 (72,339) — +Proved reserves, December 31, 2021 399,002 415,186 814,188 +94 +Table of contents +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Developed Undeveloped Total +(MBoe) +Revisions of previous estimates 14,223 160,071 174,294 +Extensions, discoveries and other additions — — — +Acquisition of reserves 95,227 101,160 196,387 +Dispositions (65) — (65) +Production (85,038) — (85,038) +Undeveloped reserves converted to developed 94,934 (94,934) — +Proved reserves, December 31, 2022 518,283 581,483 1,099,766 +2022 Activity. During 2022, we increased proved reserves by 285.6 MMBoe, or 35 percent, relative to December 31, 2021. The increase in proved reserves was primarily due to (i) the reserves acquired in the Great Western Acquisition, (ii) positive revisions resulting from our development activities and (iii) upward revisions as a result of significant improvements in commodity prices during 2022, resulting in better economics. In 2022, we produced 85.0 MMBoe. +Revisions of Previous Estimates - Proved Developed Reserves. Proved developed reserves experienced a net positive revision of 14.2 MMBoe primarily due to an increase of 25.4 MMBoe as a result of extended well lives directly correlated with the improved average prices for crude oil, natural gas and NGLs in 2022 and a 15.0 MMBoe increase related to our operated and non-operated current year drilling activities not included within our five year development plan in the prior year. The positive revisions were partially offset by a 14.7 MMBoe decrease associated with higher operating costs and a decrease of 11.5 MMBoe related to performance revisions and other factors. +Revisions of Previous Estimates - PUDs. Net upward revisions to our previous PUD reserves estimates of 160.1 MMBoe were due to a 360.9 MMBoe increase related to changes to our drilling schedule, additional locations from denser spacing units and additional locations on proved acreage resulting from our 2022 development activities and a 4.3 MMBoe increase related to extended well lives directly correlated with the improved average prices for crude oil, natural gas and NGLs in 2022. The positive revisions were partially offset by decreases of (i) a 157.8 MMBoe related to PUD locations that were reclassified to unproven reserves due to changes in our drilling schedule, (ii) 38.7 MMBoe related to performance revisions, degradation for denser spacing units and other items and (iii) 8.6 MMBoe relating to locations no longer expected to be developed within five years of their initial recording in accordance with SEC rules. Drilling schedule changes mainly resulted from PUD downgrades associated with revised drilling plans following the completion of the Great Western Acquisition. +Acquisitions of Reserves - Proved Developed Reserves and PUDs. Proved developed and PUD reserves acquired primarily pertain to the Great Western Acquisition completed in May 2022. +During 2022, our conversion rate was 18 percent and we converted 94.9 MMBoe of PUD reserves at December 31, 2021 to proved developed reserves as of December 31, 2022. +Based on economic conditions on December 31, 2022, our approved development plan provides for the development of our remaining PUD locations within five years of the date such reserves were initially recorded. The level of capital spending, including any capital needed for any settlement of our asset retirement obligations, necessary to execute our development plan is consistent with our recent performance and updated drilling program. +2021 Activity. During 2021, we increased proved reserves by 83.1 MMBoe, or 11 percent, relative to December 31, 2020. The increase in proved reserves was primarily due to positive revisions resulting from our development activities and significant improvements in commodity prices during 2021, resulting in better economics. In 2021, we produced 71.3 MMBoe. +Revisions of Previous Estimates - Proved Developed Reserves. Proved developed reserves experienced a net positive revision of 75.0 MMBoe primarily due to (i) an increase of 44.3 MMBoe as a result of extended well lives directly correlated with the higher average prices for crude oil, natural gas and NGLs in 2021, (ii) a 24.9 MMBoe increase related to our operated and non-operated current year drilling activities not included within our five year development plan in the prior year, and (iii) an increase of 8.9 MMBoe related to performance revisions and other factors. The positive revisions were partially offset by a 3.1 MMBoe decrease associated with higher operating costs. +95 +Table of contents +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Revisions of Previous Estimates - PUDs. Net upward revisions to our previous PUD reserves estimates of 70.4 MMBoe were due to (i) a 166.5 MMBoe increase related to additional locations on proved acreage resulting from our 2021 development activities and changes to our drilling schedule resulting from state regulatory permitting process changes passed in 2021, (ii) a 8.6 MMBoe increase related to extended well lives directly correlated with the upward pricing adjustments due to improved average prices for crude oil, natural gas and NGLs in 2021, and (iii) 3.5 MMBoe related to performance revisions and other items. The positive revisions were partially offset by a 96.4 MMBoe downward revision primarily related to PUD locations that were reclassified to unproven reserves in our Wattenberg Field due to changes to our drilling schedule mainly resulting from state regulatory permitting process changes passed in 2021. Finally, a reduction of 11.8 MMBoe was recognized for locations no longer expected to be developed within five years of their initial recording in accordance with SEC rules. +Extensions, Discoveries and Other Additions - Proved Developed Reserves. Developed activity for 2021 included the addition of 1.0 MMBoe of developed reserves related to two gross newly turned-in-line wells in the Delaware Basin. +Acquisitions of Reserves - Proved Developed Reserves and PUDs. Proved developed and PUD reserves acquired primarily pertains to certain nonmonetary exchanges during 2021. +2020 Activity. During 2020, we increased proved reserves by 120.2 MMBoe, or 20 percent, relative to December 31, 2019. The increase in proved reserves was primarily a result of the SRC Acquisition, partially offset by downward revisions of previous estimates. In 2020, we produced 68.4 MMBoe. +Revisions of Previous Estimates- Proved Developed Reserves. Proved developed reserves experienced a negative revision of 8.6 MMBoe primarily due to a decrease of 28.2 MMBoe as a result of lower average prices for crude oil, natural gas and NGLs for 2020. The negative revisions were partially offset by a 14.3 MMBoe increase associated with lower operating costs and a 5.3 MMBoe increase related to performance revisions and other items. +Revisions of Previous Estimates- PUDs. Net downward revisions to our previous PUD reserves estimates of 92.6 MMBoe were due to (i) 266.7 MMBoe related to PUD locations that were reclassified to unproven reserves due to drilling schedule changes, (ii) a reduction of 25.5 MMBoe was recognized for locations no longer expected to be developed within five years of their initial recording in accordance with SEC rules, and (iii) 11.3 MMBoe related to downward pricing adjustments due to lower average prices for crude oil, natural gas and NGLs for 2020. Drilling schedule changes resulted from PUD downgrades associated with lower realized prices and revised drilling plans following the completion of the SRC Acquisition. The negative revisions were partially offset by a 199.9 MMBoe increase related to additional locations on proved acreage resulting from our drilling plan and 11.0 MMBoe related to performance revisions and other items. +Extensions, Discoveries and Other Additions- Proved Developed Reserves. Developed activity for 2020 included the addition of 1.6 MMBoe of developed reserves related to two gross newly-drilled wells in the Delaware Basin. +Extensions, Discoveries and Other Additions- PUDs. There were no extensions, discoveries or other additions for PUD reserves during 2020. +Acquisitions of Reserves- Proved Developed Reserves. Proved developed reserves acquired primarily pertain to the SRC Acquisition completed in January 2020. +Acquisitions of Reserves- PUDs. Proved undeveloped reserves acquired primarily pertain to the SRC Acquisition completed in January 2020. +Dispositions- Proved Developed Reserves . Dispositions of 2.5 MMBoe were related to a divestiture and acreage surrendered in various acreage exchanges. +Dispositions- PUDs. Dispositions of 4.4 MMBoe were related to a divestiture and acreage surrendered in various acreage exchanges. +96 +Table of contents +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Results of Operations for Crude Oil and Natural Gas Producing Activities +The results of operations for crude oil and natural gas producing activities for the periods presented below: +Year Ended December 31, +2022 2021 2020 +(in thousands) +Revenues: +Crude oil, natural gas and NGLs sales $ 4,296,681 $ 2,552,558 $ 1,152,555 +Commodity price risk management gain (loss), net (463,611) (701,456) 180,270 +3,833,070 1,851,102 1,332,825 +Expenses: +Lease operating expenses 262,986 180,659 161,346 +Production taxes 311,778 165,209 59,368 +Transportation, gathering and processing expenses 124,577 100,403 77,835 +Exploration expense 13,079 1,064 1,376 +Depreciation, depletion and amortization 741,906 627,466 611,003 +Accretion of asset retirement obligations 13,408 12,086 10,072 +Impairment of properties and equipment 6,762 402 882,393 +(Gain) loss on sale of properties and equipment 212 (912) (724) +1,474,708 1,086,377 1,802,669 +Results of operations for crude oil and natural gas producing +activities before provision for income taxes 2,358,362 764,725 (469,844) +Income tax (expense) benefit (499,973) (37,013) 5,168 +Results of operations for crude oil and natural gas producing activities, excluding corporate overhead and interest costs $ 1,858,389 $ 727,712 $ (464,676) +Production costs include those costs incurred to operate and maintain productive wells and related equipment, including costs such as labor, repairs, maintenance, materials, supplies, fuel consumed, insurance, production and severance taxes and associated administrative expenses. DD&A expense includes those costs associated with capitalized acquisition, exploration and development costs, but does not include the depreciation applicable to support equipment. The provision for income taxes is computed using effective statutory tax rates. +97 +Table of contents +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +Costs Incurred in Crude Oil and Natural Gas Activities +Costs incurred in crude oil and natural gas property acquisition, exploration and development for the periods presented: +Year Ended December 31, +2022 2021 2020 +(in thousands) +Acquisition of properties: (1) +Proved properties $ 2,093,993 $ 1 $ 1,618,000 +Unproved properties 9,547 3,151 114,202 +Development costs (2) +1,092,985 583,488 528,686 +Exploration costs: (3) +Exploratory drilling 24,861 6,902 12,892 +Geological and geophysical 17 64 253 +Total costs incurred $ 3,221,403 $ 593,606 $ 2,274,033 +____________ +(1) Property acquisition costs represent costs incurred to purchase, lease or otherwise acquire a property. +(2) Development costs represent costs incurred to gain access to and prepare development well locations for drilling, drill and equip development wells, recomplete wells and provide facilities to extract, treat, gather and store crude oil, natural gas and NGLs. Of these costs incurred for the years ended December 31, 2022, 2021 and 2020, $356.0 million, $227.8 million and $270.7 million, respectively, were incurred to convert proved undeveloped reserves to proved developed reserves from the prior year end. +(3) Exploration costs represent costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing crude oil, natural gas and NGLs. These costs include, but are not limited to, dry hole contributions and costs of drilling and equipping exploratory wells. +Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities +Aggregate capitalized costs related to crude oil and natural gas exploration and production activities with applicable accumulated DD&A are presented below as of the dates indicated: +December 31, +2022 2021 +(in thousands) +Proved crude oil and natural gas properties $ 11,324,756 $ 8,310,018 +Unproved crude oil and natural gas properties 156,418 306,181 +Uncompleted wells, equipment and facilities 686,779 371,360 +Capitalized costs 12,167,953 8,987,559 +Accumulated DD&A (4,957,848) (4,218,330) +Capitalized costs, net $ 7,210,105 $ 4,769,229 +Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Reserves +The standardized measure below has been prepared in accordance with U.S. GAAP. Future estimated cash flows were based on a 12-month average price calculated as the unweighted arithmetic average of the prices on the first day of each month, January through December, applied to our year-end estimated proved reserves. Prices for each of the three years were adjusted by field for Btu content, transportation and regional price differences; however, they were not adjusted to reflect the value of our commodity derivatives. Production and development costs were based on prices as of December 31 for each of the respective years presented. The amounts shown do not give effect to non-property related expenses, such as corporate general and administrative expenses, debt service or to depreciation, depletion and amortization expense. Production and development costs include those cash flows associated with the expected ultimate settlement of our asset retirement obligations. Future estimated income tax expense is computed by applying the statutory rate in effect at the end of each year to the projected future pre-tax net cash flows, less the tax basis of the properties and gives effect to permanent differences, tax credits and allowances related to the properties. +98 +Table of contents +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +The following table presents information with respect to the standardized measure of discounted future net cash flows relating to proved reserves as of the dates indicated. Changes in the demand for crude oil, natural gas and NGLs, inflation and other factors make such estimates inherently imprecise and subject to substantial revision. This table should not be construed to be an estimate of the current market value of our proved reserves. +December 31, +2022 2021 2020 +(in thousands) +Future estimated cash flows $ 50,387,091 $ 26,143,031 $ 12,481,830 +Future estimated production costs (1) +(11,124,864) (6,325,129) (4,209,459) +Future estimated development costs (5,275,657) (2,857,951) (2,337,806) +Future estimated income tax expense (7,070,756) (3,088,187) (301,507) +Future net cash flows 26,915,814 13,871,764 5,633,058 +10% annual discount for estimated timing of cash flows (11,928,425) (5,963,592) (2,350,879) +Standardized measure of discounted future estimated net cash flows $ 14,987,389 $ 7,908,172 $ 3,282,179 +____________ +(1) Represents future estimated lease operating expenses, production taxes and transportation, gathering and processing expenses. +The following table presents the principal sources of change in the standardized measure of discounted future estimated net cash flows for the periods presented: +Year Ended December 31, +2022 2021 2020 +(in thousands) +Beginning of period $ 7,908,172 $ 3,282,179 $ 3,310,334 +Sales of crude oil, natural gas and NGLs production, net of production costs (3,596,783) (2,106,287) (854,006) +Net changes in prices and production costs (1) +6,057,774 5,312,870 (1,771,019) +Extensions, discoveries and improved recovery, less related costs — 20,201 14,110 +Sales of reserves (302) — (26,771) +Purchases of reserves 2,896,083 76,440 1,969,846 +Development costs incurred during the period 558,477 338,098 329,495 +Revisions of previous quantity estimates 2,794,615 2,645,379 (775,009) +Changes in estimated income taxes (2,265,261) (1,628,304) 354,369 +Net changes in future development costs (451,433) (168,332) 367,630 +Accretion of discount 1,163,956 345,454 572,483 +Timing and other (77,909) (209,526) (209,283) +End of period $ 14,987,389 $ 7,908,172 $ 3,282,179 +____________ +(1) Our weighted average price, net of production costs per Boe, in our 2022 reserve report increased to $35.70 as compared to $24.34 for 2021 and $11.32 for 2020. +The data presented should not be viewed as representing the expected cash flows from, or current value of, existing proved reserves since the computations are based on a large number of estimates and arbitrary assumptions. Reserve quantities cannot be measured with precision and their estimation requires many judgmental determinations and frequent revisions. The required projection of production and related expenditures over time requires further estimates with respect to pipeline availability, rates of demand and governmental control. Actual future prices and costs are likely to be substantially different from the recent average prices and current costs utilized in the computation of reported amounts. Any analysis or evaluation of the reported amounts should give specific recognition to the computational methods utilized and the limitations inherent therein. +99 +Table of contents +PDC ENERGY, INC. +SUPPLEMENTAL INFORMATION +(Unaudited) +FINANCIAL STATEMENT SCHEDULE +Schedule II -VALUATION AND QUALIFYING ACCOUNTS +Description Beginning +Balance +January 1, Charged to +Costs and +Expenses +Deductions (1) +Ending +Balance +December 31, +(in thousands) +2022: +Allowance for doubtful accounts $ 6,055 $ (446) $ (164) $ 5,445 +Allowance for expirations of unproved crude oil and natural gas properties 206,328 864 (127,185) 80,007 +2021: +Allowance for doubtful accounts $ 6,763 $ (359) $ (349) $ 6,055 +Allowance for expirations of unproved crude oil and natural gas properties 224,019 — (17,691) 206,328 +2020: +Allowance for doubtful accounts $ 7,476 $ 3,179 $ (3,892) $ 6,763 +Allowance for expirations of unproved crude oil and natural gas properties 6,881 223,895 (6,757) 224,019 +____________ +(1) For allowance for doubtful accounts, deductions represent the write-off of accounts receivable deemed uncollectible. For allowance for expirations of unproved crude oil and natural gas properties, deductions represent actual expired or abandoned unproved crude oil and natural gas properties, with a corresponding decrease to the historical cost of the associated asset. +100 +Table of contents +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE +None. +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +As of December 31, 2022, we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Based on the results of this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2022. +Management’s Report on Internal Control over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Internal control over financial reporting is a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer, or persons performing similar functions, and effected by our board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate. +Management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2022, based upon the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on this evaluation, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2022. +The effectiveness of our internal control over financial reporting as of December 31, 2022 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears under Item 8. +Changes in Internal Control over Financial Reporting +There were no changes in our internal control over financial reporting during the quarter ended December 31, 2022 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. +ITEM 9B. OTHER INFORMATION +None. +ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS +Not applicable. +101 +Table of contents +PART III +ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2023 Annual Stockholders’ meeting and is incorporated by reference in this report. +ITEM 11. EXECUTIVE COMPENSATION +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2023 Annual Stockholders’ meeting and is incorporated by reference in this report. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2023 Annual Stockholders’ meeting and is incorporated by reference in this report. +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2023 Annual Stockholders’ meeting and is incorporated by reference in this report. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2023 Annual Stockholders’ meeting and is incorporated by reference in this report. +PART IV +ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES +(a) (1) Exhibits: +See Exhibits Index on the following page. +ITEM 16. FORM 10-K SUMMARY +None. +Exhibits Index +Incorporated by Reference +Exhibit Number Exhibit Description Form SEC File Number Exhibit Filing Date Filed Herewith +2.1 +Membership Interest Purchase Agreement, dated as of February 26, 2022, by and among PDC Energy, Inc., Great Western Petroleum, LLC, and the members of Great Western Petroleum, LLC. +8-K 001-37419 2.1 2/28/2022 +3.1 +Certificate of Incorporation of PDC Energy, Inc., as amended. +8-K12B 001-37419 3.1 5/27/2020 +3.2 +Bylaws of PDC Energy, Inc. +8-K12B 001-37419 3.2 6/8/2015 +4.1 +Description of Capital Stock +X +4.2 +Form of Common Stock Certificate of PDC Energy, Inc. +10-K 001-37419 4.1.1 2/26/2020 +102 +Table of contents +Incorporated by Reference +Exhibit Number Exhibit Description Form SEC File Number Exhibit Filing Date Filed Herewith +4.3 +Base Indenture, dated as of September 14, 2016, by and between PDC Energy, Inc. and U.S. Bank Trust National Association, as Trustee. +8-K 001-37419 4.1 9/14/2016 +4.4 +Indenture, dated as of September 15, 2016, by and between PDC Energy, Inc. and U.S. Bank Trust National Association, as Trustee, relating to the 6.125% Senior Notes due 2024. +8-K 001-37419 4.1 9/15/2016 +10.1 +Form of Indemnification Agreement. +8-K 000-07246 10.1 6/8/2015 +10.2 +Amended and Restated 2010 Long-Term Equity Compensation Plan, as amended. +10-K 001-37419 10.5 2/22/2016 +10.3 +Executive Severance Compensation Plan, as amended and restated. +10-Q 001-37419 10.1 8/6/2020 +10.4 +Form of 2013 Restricted Stock/Stock Appreciation Rights Agreement. +10-K 000-07246 10.10 2/27/2013 +10.5 +Form of 2014 Restricted Stock/Stock Appreciation Rights Agreement. +10-K 000-07246 10.5.5 2/19/2015 +10.6 +Form of 2015 Stock Appreciation Rights Agreement. +10-K 000-07246 10.5.8 2/19/2015 +10.7 +Form of 2020 Performance Share Agreement. +10-Q 001-37419 99.1 5/7/2020 +10.8 +Form of 2020 Restricted Stock Unit Agreement (Executives). +10-Q 001-37419 99.3 5/7/2020 +10.9 +Form of 2021 Performance Share Agreement. +10-Q 001-37419 99.1 5/6/2021 +10.10 +Form of 2021 Restricted Stock Unit Agreement (Directors). +10-Q 001-37419 99.2 5/6/2021 +10.11 +Form of 2021 Restricted Stock Unit Agreement (Executives). +10-Q 001-37419 99.3 5/6/2021 +10.12 +Form of 2022 Performance Share Agreement. +10-Q 001-37419 99.1 5/4/2022 +10.13 +Form of 2022 Restricted Stock Unit Agreement (Directors). +10-Q 001-37419 99.2 5/4/2022 +10.14 +Form of 2022 Restricted Stock Unit Agreement (Executives). +10-Q 001-37419 99.3 5/4/2022 +10.15 +Employment Agreement with Lance A. Lauck, as amended. +10-Q 001-37419 10.2 8/6/2020 +10.16 +2018 Equity Incentive Plan. +8-K 001-37419 10.1 5/31/2018 +10.17 +Amendment No. 1 to PDC Energy, Inc. 2018 Equity Incentive Plan. +8-K 001-37419 +10.1 5/27/2020 +10.18 +SRC Energy Inc. 2015 Equity Incentive Plan. +8-K 001-37419 10.1 1/14/2020 +10.19 +Fifth Amended and Restated Credit Agreement, dated as of November 2, 2021 among PDC Energy, Inc., as Borrower, JPMorgan Chase Bank, N.A., as Administrative Agent and The Lenders Party Hereto +10-Q 001-37419 10.1 11/3/2021 +21.1 +Subsidiaries. +10-K 001-37419 21.1 2/26/2020 +23.1 +Consent of PricewaterhouseCoopers LLP. +X +23.2 +Consent of Ryder Scott Company, L.P., Petroleum Consultants. +X +23.3 +Consent of Netherland, Sewell & Associates, Inc., Petroleum Consultants. +X +31.1 +Certification by Chief Executive Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +31.2 +Certification by Chief Financial Officer pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act Rules, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. +X +103 +Table of contents +Incorporated by Reference +Exhibit Number Exhibit Description Form SEC File Number Exhibit Filing Date Filed Herewith +32.1* +Certifications by Chief Executive Officer and Chief Financial Officer pursuant to Title 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of Sarbanes-Oxley Act of 2002. +99.1 +Report of Independent Petroleum Consultants - Ryder Scott Company, L.P. +X +99.2 +Report of Independent Petroleum Consultants - Netherland, Sewell & Associates, Inc. +X +101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document X +101.SCH XBRL Taxonomy Extension Schema Document X +101.CAL XBRL Taxonomy Extension Calculation Linkbase Document X +101.DEF XBRL Taxonomy Extension Definition Linkbase Document X +101.LAB XBRL Taxonomy Extension Label Linkbase Document X +101.PRE XBRL Taxonomy Extension Presentation Linkbase Document X +104 Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101) X +* Furnished herewith. +104 +Table of contents +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +PDC ENERGY, INC. +By: /s/ Barton Brookman +Barton Brookman +President and Chief Executive Officer +February 22, 2023 +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated: +Signature Title Date +/s/ Barton Brookman President, Chief Executive Officer and Director February 22, 2023 +Barton Brookman (principal executive officer) +/s/ R. Scott Meyers Senior Vice President and Chief Financial Officer February 22, 2023 +R. Scott Meyers (principal financial officer) +/s/ Troy M. Welling Chief Accounting Officer February 22, 2023 +Troy Welling (principal accounting officer) +/s/ Mark E. Ellis Non-Executive Chairman of the Board of Directors February 22, 2023 +Mark E. Ellis +/s/ Pamela R. Butcher Director February 22, 2023 +Pamela R. Butcher +/s/ Paul J. Korus Director February 22, 2023 +Paul J. Korus +/s/ Lynn A. Peterson Director February 22, 2023 +Lynn A. Peterson +/s/ Carlos A. Sabater Director February 22, 2023 +Carlos A. Sabater +/s/ Diana L. Sands Director February 22, 2023 +Diana L. Sands +105 +Table of contents +GLOSSARY OF UNITS OF MEASUREMENT AND INDUSTRY TERMS +UNITS OF MEASUREMENT +The following presents a list of units of measurement used throughout the document. +Bbl – One barrel of crude oil or NGL or 42 gallons of liquid volume. +Bcf – One billion cubic feet of natural gas volume. +Boe – One barrel of crude oil equivalent. +Btu – British thermal unit. +BBtu – One billion British thermal units. +MBoe – One thousand barrels of crude oil equivalent. +MBbls – One thousand barrels of crude oil. +Mcf – One thousand cubic feet of natural gas volume. +MMBoe – One million barrels of crude oil equivalent. +MMBbls – One million barrels of crude oil. +MMBtu – One million British thermal units. +MMcf – One million cubic feet of natural gas volume. +MMcfd – One million cubic feet of natural gas volume per day. +GLOSSARY OF INDUSTRY TERMS +The following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report: +Brent - Brent sweet light crude oil. +CIG - Colorado Interstate Gas. +Completion - Refers to the installation of permanent equipment for the production of crude oil and natural gas from a recently drilled well or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned. +Condensate - Liquid hydrocarbons associated with the production that is primarily natural gas. +Developed acreage - Acreage assignable to productive wells. +Development well - A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. +Differentials - The difference between the crude oil and natural gas index spot price and the corresponding cash spot price in a specified location. +Dry well or dry hole - A well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion as an oil or gas well. +Exploratory well - A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. +Extensions, discoveries and other additions - As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties or revisions of previous estimates. +Fracture or Fracturing - Procedure to stimulate production by forcing a mixture of fluid and proppant into the formation under high pressure. Fracturing creates artificial fractures in the reservoir rock to increase permeability and porosity, thereby allowing the release of trapped hydrocarbons. +Gross acres or wells - Refers to the total acres or wells in which we have a working interest. +106 +Table of contents +Henry Hub - Refers to the pricing point for natural gas futures contracts traded on NYMEX. +Horizontal drilling - A drilling technique that permits the operator to drill a horizontal well shaft from the bottom of a vertical well and thereby to contact and intersect a larger portion of the producing horizon than conventional vertical drilling techniques and may, depending on the horizon, result in increased production rates and greater ultimate recoveries of hydrocarbons. +Intensity - Greenhouse gas and methane intensity is reported as total metric tons of methane emissions divided by gross annual production in MBOE. +Joint interest billing - Process of billing/invoicing the costs related to well drilling, completions and production operations among working interest partners. +Natural gas liquid(s) or NGL(s) - Hydrocarbons which can be extracted from natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs include ethane, propane, butane and other natural gasolines. +Net acres or wells - Refers to gross acres or wells we own multiplied, in each case, by our percentage working interest. +Net production - Crude oil and natural gas production that we own, less royalties and production due to others. +Non-operated - A project in which we are not the operator. +NYMEX - New York Mercantile Exchange. +Operator - The individual or company responsible for the exploration, development and/or production of an oil or gas well or lease. +Overriding royalty - An interest which is created out of the operating or working interest. Its term is coextensive with that of the operating interest. +Possible reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than probable reserves. When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability to exceed the sum of proved, probable and possible reserves. When probabilistic methods are used, there must be at least a 10 percent probability that the actual quantities recovered will equal or exceed the sum of proved, probable and possible estimates. +Present value of future net revenues or (PV-10) - The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, of proved reserves calculated in accordance with Financial Accounting Standards Board guidelines, net of estimated production and future development costs, using pricing and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization and discounted using an annual discount rate of 10 percent. PV-10 is pre-tax and therefore a non-U.S. GAAP financial measure. +Probable reserves - This term is defined in the SEC Regulation S-X Section 4-10(a) and refers to those reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. Similarly, when probabilistic methods are used, there must be at least a 50 percent probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates. +Productive well - An exploratory or developmental well that is not a dry well or dry hole, as defined above. +Proved developed non-producing reserves - Reserves that consist of (i) proved reserves from wells which have been completed and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and/or (ii) proved reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics and analogous production in the immediate vicinity of the wells. +107 +Table of contents +Proved developed producing reserves or PDPs - Proved reserves that can be expected to be recovered from currently producing zones under the continuation of present operating methods. +Proved developed reserves - The combination of proved developed producing and proved developed non-producing reserves. +Proved reserves - This term means “proved oil and gas reserves” as defined in SEC Regulation S-X Section 4-10(a) and refers to those quantities of crude oil and condensate, natural gas and NGLs, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible - from a given date forward, from known reservoirs, and under existing conditions, operating methods and government regulations - prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. +Proved undeveloped reserves or PUDs - Proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. +Recomplete or Recompletion - The modification of an existing well for the purpose of producing crude oil and natural gas from a different producing formation. +Reserves - Estimated remaining quantities of crude oil, natural gas, NGLs and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering crude oil, natural gas and NGLs or related substances to market, and all permits and financing required to implement the project. +Royalty - An interest in a crude oil and natural gas lease or mineral interest that gives the owner of the royalty the right to receive a portion of the production from the leased acreage or mineral interest (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner. +Spud - To begin drilling; the act of beginning a hole. +Standardized measure of discounted future net cash flows or standardized measure - Future net cash flows discounted at a rate of 10 percent. Future net cash flows represent the estimated future revenues to be generated from the production of proved reserves determined in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation, giving effect to (i) estimated future abandonment costs, net of the estimated salvage value of related equipment and (ii) future income tax expense. +Stratigraphic test well - A drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. +Undeveloped acreage - Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and natural gas, regardless of whether such acreage contains proved reserves. +Waha - Waha West Texas natural gas prices +Working interest - An interest in a crude oil and natural gas lease that gives the owner of the interest the right to drill and produce crude oil and natural gas on the leased acreage. It requires the owner to pay its share of the costs of drilling and production operations. +Workover - Major remedial operations on a producing well to restore, maintain, or improve the well’s production. +108 \ No newline at end of file diff --git a/raw/filings/0000077877/2022/0000077877-23-000012/filing_metadata.csv b/raw/filings/0000077877/2022/0000077877-23-000012/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..83f4c50dbe4d71b5dff6d23736dbec6e4d5b5765 --- /dev/null +++ b/raw/filings/0000077877/2022/0000077877-23-000012/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000077877,PDCE,"PDC ENERGY, INC.",10-K,2023-02-22,2022-12-31,2023-02-22T21:39:13.000Z,0000077877-23-000012,pdce-20221231.htm,10-K,14121550,1,1,https://www.sec.gov/Archives/edgar/data/77877/000007787723000012/pdce-20221231.htm,https://www.sec.gov/Archives/edgar/data/77877/000007787723000012/,2022,2022,1 diff --git a/raw/filings/0000077877/2022/0000077877-23-000012/item1.txt b/raw/filings/0000077877/2022/0000077877-23-000012/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2022/0000077877-23-000012/item13.txt b/raw/filings/0000077877/2022/0000077877-23-000012/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..8d9b5112afaa707e85517e2d526230b96a121d01 --- /dev/null +++ b/raw/filings/0000077877/2022/0000077877-23-000012/item13.txt @@ -0,0 +1,2 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE +Information relating to this Item will be included in an amendment to this report or the proxy statement to be filed pursuant to Regulation 14A for our 2023 Annual Stockholders’ meeting and is incorporated by reference in this report. \ No newline at end of file diff --git a/raw/filings/0000077877/2022/0000077877-23-000012/item9a.txt b/raw/filings/0000077877/2022/0000077877-23-000012/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..ab78c279e09322bfacf05dc26372ac015bbada3d --- /dev/null +++ b/raw/filings/0000077877/2022/0000077877-23-000012/item9a.txt @@ -0,0 +1,10 @@ +ITEM 9A. CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +As of December 31, 2022, we carried out an evaluation under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures defined in Rules 13a-15(e) and 15d-15(e) of the Exchange Act. Based on the results of this evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2022. +Management’s Report on Internal Control over Financial Reporting +Management is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. Internal control over financial reporting is a process designed by, or under the supervision of, our Chief Executive Officer and Chief Financial Officer, or persons performing similar functions, and effected by our board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may deteriorate. +Management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2022, based upon the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Based on this evaluation, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2022. +The effectiveness of our internal control over financial reporting as of December 31, 2022 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears under Item 8. +Changes in Internal Control over Financial Reporting +There were no changes in our internal control over financial reporting during the quarter ended December 31, 2022 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. \ No newline at end of file diff --git a/raw/filings/0000077877/2022/0000077877-23-000012/rp_note.txt b/raw/filings/0000077877/2022/0000077877-23-000012/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000077877/2022/0000077877-23-000012/rpt_disclosure.txt b/raw/filings/0000077877/2022/0000077877-23-000012/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..d95674288f5e8b8f8218b40467858b2ca9c4818d --- /dev/null +++ b/raw/filings/0000077877/2022/0000077877-23-000012/rpt_disclosure.txt @@ -0,0 +1,2 @@ +TRANSACTIONS WITH RELATED PARTIES +During 2022, there was no transaction or series of transactions, nor is there any currently proposed transaction, involving an amount exceeding $120,000 in which the Company is or was a participant and in which any Director, executive officer, known holder of more than 5% of the Company’s voting securities, or any member of the immediate family of any of the foregoing persons, had or has a direct or indirect material interest for which disclosure is required under Item 404 of Regulation S-K. \ No newline at end of file diff --git a/raw/filings/0000719733/2014/0000719733-14-000028/filing.txt b/raw/filings/0000719733/2014/0000719733-14-000028/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..98ec1c4ca07713d24063413c952d5026445a2da6 --- /dev/null +++ b/raw/filings/0000719733/2014/0000719733-14-000028/filing.txt @@ -0,0 +1,3117 @@ +10-K +1 +ktcc-06282014x10k.htm +10-K +KTCC - 06.28.2014 - 10K +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +____________________________________________________________ +FORM 10-K +____________________________________________________________ +x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE FISCAL YEAR ENDED JUNE 28, 2014 +OR +¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE PERIOD FROM TO +Commission File Number 0-11559 +____________________________________________________________ +KEY TRONIC CORPORATION +(Exact name of registrant as specified in its charter) +____________________________________________________________ +Washington +91-0849125 +(State or other jurisdiction of +Incorporation or organization) +(I.R.S. Employer +Identification No.) +N. 4424 Sullivan Road, Spokane Valley, +Washington +99216 +(Address of principal executive offices) +(Zip Code) +(509) 928-8000 +(Registrant’s telephone number, including area code) +N/A +(Former name, former address and former fiscal year, if changed since last report) +____________________________________________________________ +Securities Registered Pursuant to Section 12(b) of the Act: None +Title of each class +Name of each exchange on which registered +Common stock, no par value +The NASDAQ Stock Market LLC +Securities Registered Pursuant to Section 12(g) of the Act: None +____________________________________________________________ +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ¨ No x +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulations S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. +(Check one): +Large accelerated filer +¨ +Accelerated filer +x +Non-accelerated filer +¨ (Do not check if a smaller reporting company) +Smaller reporting company +¨ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x +State the aggregate market value of the voting and non-voting common equity held by non affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. +As of December 28, 2013, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $110.6 million based on the closing price as reported on the NASDAQ. +Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: 10,551,680 shares of common stock were outstanding as of September 3, 2014 . +____________________________________________________________ +Documents Incorporated by Reference: +The following documents are incorporated by reference to the extent specified herein: +Document Description +Part of Form 10-K +Proxy Statement dated September 19, 2014 +Part III +KEY TRONIC CORPORATION +2014 FORM 10-K +TABLE OF CONTENTS +Page No. +PART I +Item 1. +Business +4 +Item 1A. +Risk Factors +8 +Item 1B. +Unresolved Staff Comments +13 +Item 2. +Properties +14 +Item 3. +Legal Proceedings +14 +Item 4. +Mine Safety Disclosures +15 +PART II +Item 5. +Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities +15 +Item 6. +Selected Financial Data +17 +Item 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +18 +Item 7A. +Quantitative and Qualitative Disclosures about Market Risk +28 +Item 8. +Financial Statements and Supplementary Data +29-50 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +51 +Item 9A. +Controls and Procedures +51 +Item 9B. +Other Information +53 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +53 +Item 11. +Executive Compensation +53 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +53 +Item 13. +Certain Relationships and Related Transactions, and Director Independence +54 +Item 14. +Principal Accounting Fees and Services +54 +PART IV +Item 15. +Exhibits and Financial Statement Schedule +54 +Signatures +59 +3 +FORWARD-LOOKING STATEMENTS +References in this report to “the Company”, “Key Tronic”, “KeyTronicEMS”, “we”, “our”, or “us” mean Key Tronic Corporation together with its subsidiaries, except where the context otherwise requires. +This Annual Report on Form 10-K contains forward-looking statements in addition to historical information. Forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those reflected in the forward-looking statements. Risks and uncertainties that might cause such differences include, but are not limited to those outlined in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risks and Uncertainties that May Affect Future Results.” Readers are cautioned not to place undue reliance on forward-looking statements, which reflect management’s opinions only as of the date hereof. The Company undertakes no obligation to update forward-looking statements to reflect developments or information obtained after the date hereof and disclaims any obligation to do so. Readers should carefully review the risk factors described in periodic reports the Company files from time to time with the Securities and Exchange Commission, including Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. +PART I +Item 1. +BUSINESS +Background +Key Tronic Corporation (dba: KeyTronicEMS Co.), was organized in 1969 as a Washington corporation that locally manufactured computer keyboards. The ability to design, build and deliver a quality product led us to become a leading independent manufacturer of keyboards for computers in the United States. Our fully integrated design, tooling, and automated manufacturing capabilities enabled us to rapidly respond to customers’ needs for keyboards in production quantities worldwide. We supported our sales growth through the development and purchase of international manufacturing facilities. As the computer keyboard market matured with increasing competition from other international providers, we determined that our business could no longer solely rely on keyboard sales. +After assessing market conditions and our strengths and capabilities, we shifted focus from keyboard manufacturing to contract manufacturing for a wide range of products. Our unique strategic attributes are based on our core strengths of innovative design and engineering expertise in electronics, mechanical engineering, sheet metal fabrication and stamping, and precision plastics combined with high-quality, low cost production, and assembly on an international basis while providing exceptional customer service. These strengths have made our company a strong competitor in the electronic manufacturing services (EMS) market. +Our Industry and Strategy +The expansion of the EMS industry has allowed us to continue to expand our customer base and the industries that we serve. The challenging global macroeconomic environment had a negative impact on previously held customer programs during the past fiscal year, as we saw a significant decrease in revenue generated from two of our largest customer programs. However, we are successfully confronting the challenging global macroeconomic environment by controlling our costs and winning new customer programs, which allowed us to maintain our profitability and a strong balance sheet. The increase in new programs represents a growing portion of our revenue and a promising foundation for our future. In keeping with our long-term strategic objectives, we have been successfully building a more diversified customer portfolio, spanning a wider range of industries. We currently offer our customers the following services: integrated electronic and mechanical engineering, precision plastic molding, sheet metal fabrication, assembly, component selection, sourcing and procurement, worldwide logistics, and new product testing and production all at competitive pricing due to our global footprint. +We believe that we are well positioned in the EMS industry to continue the expansion of our customer base and achieve long term growth. Our unique blend of multinational facilities, centralized management, and core strengths continue to support our growth and our customers’ needs. We continue to focus on controlling operating expenses and leveraging the synergistic capabilities of our world-class facilities in the United States, Mexico, and China. This international production capability provides our customers with the benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs, and reduced product fulfillment time. Given our competitive advantages and the growing pressure for new potential customers to move forward with their outsourcing strategies, we are strongly positioned to win new business in coming periods and grow our revenue and profits. +4 +The EMS industry is intensely competitive. Although our customer base is growing we still have less than 1% of the potential global market and our revenue can fluctuate significantly due to reliance on a concentrated base of customers. We are planning for new customer growth in the coming quarters by securing new programs with new and existing customers, increasing our worldwide manufacturing capacity, and continuing to improve our manufacturing and procurement processes. Ongoing challenges that we face include the following: Continuing to win programs from new and existing customers, balancing production capacity and key personnel in support of new customer programs, improving operating efficiencies, controlling costs while developing competitive pricing strategies, and successfully transitioning new program wins to full production during a time of macroeconomic uncertainty. +Customers and Marketing +We provide a mix of manufacturing services for outsourced Original Equipment Manufacturing (OEM) products. We provide the following EMS services: Product design, surface mount technologies (SMT) and pin through hole capability for printed circuit board assembly, tool making, precision plastic molding, sheet metal fabrication, liquid injection molding, complex assembly, automated tape winding, prototype design and full product assembly. +Sales of the majority of our products have not historically been seasonal in nature, but may be seasonal in the future if there are changes in the types of products manufactured. Sales can, however, fluctuate significantly between quarters from changes in customers and customer demand due to the concentration of sales generated by our largest customers. +For the fiscal years 2014 , 2013 and 2012 , the five largest customers in each year accounted for 62%, 71% and 73% of combined total net sales, respectively. At the end of fiscal year 2014 , we were generating revenue from 196 separate programs and 59 distinct customers as compared to 183 programs and 56 customers at the end of fiscal year 2013 . As these new customers’ sales ramp up and new programs are won our concentration of revenue should continue to decrease in the future. +The following table represents all customers that represented 10% or more of total net sales during the last three fiscal years: +Percentage of Net Sales by Fiscal Year +2014 +2013 +2012 +Customer A +20% +19% +16% +Customer B +15% +23% +29% +Customer C +15% +21% +17% +Although keyboard manufacturing is still included in our product offerings, we do not expect annual keyboard sales to be a material component of our business. We realized revenues of approximately $2.3 million , $2.4 million and $2.8 million in fiscal years 2014 , 2013 and 2012 , respectively, from the sale of keyboards. In order to accommodate the demand for standard keyboard layouts, we maintain a purchase-from-stock program. The more popular standard layouts are built and stocked for immediate availability. +We market our products and services primarily through our direct sales department aided by strategically located field sales people and distributors. Although we maintain relationships with several independent sales organizations to assist in marketing our EMS product lines, commissions earned and paid are not material to the consolidated financial statements. +Manufacturing +We have continually made investments in developing and expanding a capital equipment base to achieve vertical integration and efficiencies in our manufacturing processes. We have invested significant capital into SMT for volume manufacturing of complex printed circuit board assemblies and in our metal shop providing precision metal stamping, fabricating, and finishing. We also design and develop tooling for injection molding and manufacture the majority of plastic parts used in the products we manufacture. Additionally, we have equipment to maintain a controlled clean environment for manufacturing processes that require a high level of precise control. +We use a variety of manual and automated assembly processes in our facilities, depending upon product complexity and degree of customization. Some examples of automated processes include component insertion, SMT, selective soldering, flexible robotic assembly, automated storage tape winding, computerized vision system quality inspection, laser turrets, automated switch and key top installation, and automated functional testing. +Our engineering expertise and automated manufacturing processes enable us to work closely with our customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. We use computer-aided design techniques and software to assist in preparation of the tool design layout and component placement, to reduce tooling and production costs, improve component and product quality, and enhance turnaround time during product development. +5 +We purchase materials and components for our products from many different suppliers, including both domestic and international sources. We develop close working relationships with our suppliers, many of whom have been supplying products to us for several years. +Research, Development, and Engineering +As part of our long-term strategy, we are committed to supporting our customers by providing research, development, and engineering services. These services allow us to facilitate in optimizing new product designs, and the production processes of our customers programs. +Research, development, and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials costs, depreciation, and allocated information technology and facilities costs. +Competition +The market for the products and services we provide is highly competitive. There are numerous competitors in the EMS industry, many of which have substantially more resources and are more geographically diverse than we are. Some of our competitors have similar international production capabilities, large financial resources and some have substantially greater manufacturing, research and development, and marketing resources. There is also competition from the manufacturing operations of our current and potential customers, who are continually evaluating the merits of manufacturing their products internally versus the advantages of outsourcing. We believe that we can currently compete favorably in these areas primarily on the basis of our international footprint, responsiveness, creativity, vertical production capability, quality, and cost. +Trademarks and Patents +Our name and logo are federally registered trademarks, and we believe they are valuable assets of our business. We operate under the trade name “KeyTronicEMS” to better identify our primary business concentration in contract manufacturing in the EMS industry. We also own several keyboard patents; however, since our focus is EMS, management believes that these patents will not have a significant impact on future revenues. +Employees +We consider our employees to be our primary strength and we make considerable efforts to maintain a well-qualified workforce. Our employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. We regularly provide transportation, medical services, and meals to all of our employees in foreign locations. We maintain a 401(k) plan for U.S. employees, which provides a discretionary matching company contribution of up to 4% of an employee’s salary. We provide group health, life, and disability insurance plans. We also maintain stock option plans and other long term incentive plans for certain employees and outside directors. +As of June 28, 2014 we had 3,343 employees compared to 2,584 on June 29, 2013 , and 2,700 on June 30, 2012 . Since we can have significant fluctuations in product demand, we seek to maintain flexibility in our workforce by utilizing skilled temporary and short-term contract labor in our manufacturing facilities in addition to full-time employees. +Backlog +On July 26, 2014 our order backlog was valued at approximately $103.1 million, compared to approximately $60.0 million on July 27, 2013. Even though our order backlog is comprised of firm purchase orders, the amount of backlog is not necessarily indicative of future sales but can be indicative of trends in expected future sales revenue. Due to the relationships with our customers, we will occasionally allow orders to be canceled or rescheduled and as a result it is not a meaningful indicator of future financial results. If there are canceled or rescheduled orders, we typically negotiate fees to cover the costs we have incurred. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change due to design modifications, customer forecast changes, or other customer requirements. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in Note 12, “Enterprise-Wide Disclosures” of the consolidated financial statements of this Annual Report on Form 10-K and that information is incorporated herein. +6 +Executive Officers of the Registrant +The table below sets forth the name, current age and current position of our executive officers and other significant employees: +Name +Age +Positions Held +Executive Officers +Craig D. Gates +55 +President and Chief Executive Officer +Ronald F. Klawitter +62 +Executive Vice President of Administration, Chief Financial Officer and Treasurer +Douglas G. Burkhardt +56 +Executive Vice President of Worldwide Operations +Philip S. Hochberg +52 +Executive Vice President of Business Development +Lawrence J. Bostwick +62 +Vice President of Engineering and Quality +Brett R. Larsen +41 +Vice President of Finance and Controller +Frank Crispigna III +53 +Vice President of Materials +Duane D. Mackleit +46 +Vice President of Program Management +Executive Officers +CRAIG D. GATES – President and Chief Executive Officer +Mr. Gates, age 55 , has been President and Chief Executive officer of the Company since April 2009. Previously he was Executive Vice President and General Manager from August 2002 to April 2009. He served as Executive Vice President of Marketing, Engineering and Sales from July 1997 to August 2002 and served as Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of 1994. From 1982 to 1991 he held various engineering and management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. Mr. Gates has a Bachelor of Science Degree in Mechanical Engineering and a Masters in Business Administration from the University of Illinois, Urbana. +RONALD F. KLAWITTER – Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Mr. Klawitter, age 62 , has been Executive Vice President of Administration, CFO, and Treasurer since July 1997. Previously he was Vice President of Finance, Secretary, and Treasurer of the Company from October 1995 to July 1997. He was Acting Secretary from November 1994 to October 1995 and Vice President of Finance and Treasurer from 1992 to October 1995. From 1987 to 1992, Mr. Klawitter was Vice President of Finance at Baker Hughes Tubular Service, a subsidiary of Baker Hughes, Inc. Mr. Klawitter has a BA degree from Wittenberg University and is a Certified Public Accountant. +DOUGLAS G. BURKHARDT – Executive Vice President of Worldwide Operations +Mr. Burkhardt, age 56 , has been Executive Vice President of Worldwide Operations of the Company since July 2010. Previously Mr. Burkhardt was Vice President of Worldwide Operations from July 2008 to July 2010 and Director of China Operations and Program Management from January 2006 to July 2008. Mr. Burkhardt also served as Director of Northwest and China Operations from November of 1998 to January of 2006. Mr. Burkhardt also served as Director of Customer Satisfaction from March 1997 to November 1998 and Director of Molding from September of 1995 to March of 1997. Prior to this, Mr. Burkhardt served in other various senior management positions within the Company. Mr. Burkhardt has been with the Company since May of 1989. Prior to joining Key Tronic, Mr. Burkhardt worked for House of Aluminum and Glass for 12 years where he was the plant manager. +PHILIP S. HOCHBERG – Executive Vice President of Business Development +Mr. Hochberg, age 52 , has been Executive Vice President of Business Development since July 2012. Prior this, Mr. Hochberg served as Vice President of Business Development from October 2009 through June 2012. He was Director of Business Development and Program Management from July 2008 to October 2009. Mr. Hochberg served as Director of Business Development from October 2004 to July 2008 and as Director of EMS Sales and Marketing from July 2000 to October 2004. Prior to joining Key Tronic, Mr. Hochberg worked for Quinton Instrument Company as their Director of Marketing and Product Management from 1992 to 2000. From 1988 to 1992, he was employed by SpaceLabs Medical as their Business Development Marketing Manager. Mr. Hochberg has an MBA from the University of British Columbia, a BA Psychology, with a minor in Business from Washington University in St. Louis. +7 +LAWRENCE J. BOSTWICK – Vice President of Engineering and Quality +Mr. Bostwick, age 62 , has been Vice President of Engineering and Quality since July 2008. Previously he was Director of Engineering and Quality from February 2007 to July 2008 and served as Corporate Director of Quality from February 2006 to February 2007. From 2003 to 2006 he was Director of Supply Chain Management and Quality for the Lancer Corporation and from 1998 to 2003 he was Vice President of Operations for Thermacore International. He is a graduate of the Westinghouse and General Electric – Engineering and Manufacturing Professional Development Programs. He is certified in both Quality and Industrial Engineering and is a Lean – Six Sigma Master Black Belt. Mr. Bostwick has a combined B.S. degree in Production and Operation and Industrial Engineering from Bowling Green State University and a Masters degree in Industrial Engineering and Business Administration from Syracuse University. +BRETT R. LARSEN – Vice President of Finance, and Controller +Mr. Larsen, age 41 , has served as Vice President of Finance and Controller since February 2010. He was Chief Financial Officer of FLSmidth Spokane, Inc. from December 2008 to February 2010. From October 2005 through November 2008, Mr. Larsen served as Controller of Key Tronic Corporation. From May 2004 to October 2005, Mr. Larsen served as Manager of Financial Reporting of Key Tronic Corporation. From 2002 to May 2004, Mr. Larsen was an audit manager for the public accounting firm BDO Seidman, LLP. He also held various auditing and supervisory positions with Grant Thornton LLP from 1997 to 2002. Mr. Larsen has a Bachelor of Science degree in Accounting and a Masters degree in Accounting from Brigham Young University and is a Certified Public Accountant. +FRANK CRISPIGNA III – Vice President of Materials +Mr. Crispigna, age 53 , has been Vice President of Materials of the company since October 2011. Prior to this, Mr. Crispigna held a variety of Materials and Supply Chain positions at Plexus Corporation since 1997, most recently serving as the Director – Supply Chain Solutions from 2005 - 2011. He has a Masters degree in Business Administration, and a Bachelor of Business Administration Degree in Marketing from the University of Wisconsin – Oshkosh. Mr. Crispigna also is a C.P.M., and received his certification in Supply Chain Leadership from the University of Wisconsin. +DUANE D. MACKLEIT – Vice President of Program Management +Mr. Mackleit, age 46 , has been Vice President of Program Management of the company since July 2012. He served as Director of Program Management from July 2008 through June 2012. From May 2006 to July 2008 he served as Principal Program Manager. Prior to that, he served as Program Manager from March 2002 to May 2006 and Associate Program Manager from August 2000 to March 2002. Mr. Mackleit has also held several other positions with Key Tronic Corporation. Mr. Mackleit has an AA in Business from Spokane Falls Community College and a BA in Business/Marketing from Eastern Washington University. He also holds a MBA from Gonzaga University. +Available Information +Our principal executive offices are located at N. 4424 Sullivan Road, Spokane Valley, Washington 99216, and our telephone number is (509) 928-8000. Our website is located at http://www.keytronicems.com where filings of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or current reports on Form 8-K are available after they have been filed with the Securities and Exchange Commission. The information presented on our website currently and in the future is not considered to be part of this document or any document incorporated by reference in this document. +Item 1A. +RISK FACTORS +There are risks and uncertainties that could affect our business. These risks and uncertainties include but are not limited to, the risk factors described below, in Item 7A: “Quantitative and Qualitative Disclosures about Market Risk” and elsewhere in this Form 10-K. +RISKS AND UNCERTAINTIES THAT MAY AFFECT FUTURE RESULTS +The following risks and uncertainties could affect our actual results and could cause results to differ materially from past results or those contemplated by our forward-looking statements. When used herein, the words “expects,” “believes,” “anticipates” and other similar expressions are intended to identify forward-looking statements. +8 +We may experience fluctuations in quarterly results of operations. +Our quarterly operating results have varied in the past and may vary in the future due to a variety of factors, including adverse changes in the U.S. and global macroeconomic environment, volatility in overall demand for our customers' products, success of customers' programs, timing of new programs, new product introductions or technological advances by us, our customers and our competitors, and changes in pricing policies by us, our customers, our suppliers, and our competitors. Our customer base is diverse in the markets they serve, however, decreases in demand, particularly from customers that supply the education, consumer products, and gambling industries, could affect future quarterly results. Additionally, our customers could be impacted by the illiquidity of the credit markets which could directly impact our operating results. +Component procurement, production schedules, personnel and other resource requirements are based on estimates of customer requirements. Occasionally, our customers may request accelerated production that can stress resources and reduce operating margins. In addition, because many of our operating expenses are relatively fixed, a reduction in customer demand can harm our gross profit and operating results. The products which we manufacture for our customers have relatively short product lifecycles. Therefore, our business, operating results and financial condition are dependent in a significant way on our ability to obtain orders from new customers and new product programs from existing customers. +Operating results can also fluctuate if changes are made to significant estimates and assumptions. Significant estimates and assumptions include the allowance for doubtful receivables, provision for obsolete and non-saleable inventory, stock-based compensation, the valuation allowance on deferred tax assets, valuation of goodwill, impairment of long-lived assets, long-term incentive compensation accrual, the provision for warranty costs, and the impact of hedging activities. +We are exposed to general economic conditions, which could have a material adverse impact on our business, operating results and financial condition. +Recently there have been adverse conditions and uncertainty in the global economy as the result of unstable global financial and credit markets, inflation, and recession. These unfavorable economic conditions and the weakness of the credit market could affect the demand for our customers' products. The current global macroeconomic environment may affect some of our customers that could reduce orders and change forecasts which could adversely affect our sales in future periods. Additionally, the financial strength of our customers and suppliers and their ability to obtain and rely on credit financing may affect their ability to fulfill their obligations to us and have an adverse effect on our financial results. +The majority of our sales come from a small number of customers and a decline in sales to any of these customers could adversely affect our business. +At present, our customer base is concentrated and could become more or less concentrated. There can be no assurance that our principal customers will continue to purchase products from us at current levels. Moreover, we typically do not enter into long-term volume purchase contracts with our customers, and our customers have certain rights to extend or delay the shipment of their orders. We, however, typically require that our customers contractually agree to buy back inventory purchased within specified lead times to build their products if not used. +The loss of one or more of our major customers, or the reduction, delay or cancellation of orders from such customers, due to economic conditions or other forces, could materially and adversely affect our business, operating results and financial condition. Specifically, some of our major customers provide products to the banking and gambling industries which have been adversely affected by the unfavorable economic environment. The contraction in demand from our customers in these industries could continue to impact our customer orders and continue to have a negative impact on our operations over the foreseeable future. Additionally, if one or more of our customers were to become insolvent or otherwise unable to pay for the manufacturing services provided by us, our operating results and financial condition would be adversely affected. +We depend on a limited number of suppliers for certain components that are critical to our manufacturing processes. A shortage of these components or an increase in their price could interrupt our operations and result in a significant change in our results of operations. +We are dependent on many suppliers, including sole source suppliers, to provide key components and raw materials used in manufacturing customers' products. We have seen supply shortages in certain electronic components. This can result in longer lead times and the inability to meet our customers request for flexible production and extended shipment dates. If demand for components outpaces supply, capacity delays could affect future operations. Delays in deliveries from suppliers or the inability to obtain sufficient quantities of components and raw materials could cause delays or reductions in shipment of products to our customers which could adversely affect our operating results and damage customer relationships. +9 +We operate in a highly competitive industry; if we are not able to compete effectively in the EMS industry, our business could be adversely affected. +Competitors may offer customers lower prices on certain high volume programs. This could result in price reductions, reduced margins and loss of market share, all of which would materially and adversely affect our business, operating results, and financial condition. If we were unable to provide comparable or better manufacturing services at a lower cost than our competitors, it could cause sales to decline. In addition, competitors can copy our non-proprietary designs and processes after we have invested in development of products for customers, thereby enabling such competitors to offer lower prices on such products due to savings in development costs. +Cash and cash equivalents are exposed to concentrations of credit risk. +We place our cash with high credit quality institutions. At times, such balances may be in excess of the federal depository insurance limit or may be on deposit at institutions which are not covered by insurance. If such institutions were to become insolvent during which time it held our cash and cash equivalents in excess of the insurance limit, it could be necessary to obtain other credit financing to operate our facilities. +Our ability to secure and maintain sufficient credit arrangements is key to its continued operations . +There is no assurance that we will be able to retain or renew our credit agreements in the future. In the event the business grows rapidly or the uncertain macroeconomic climate continues, additional financing resources could be necessary in the current or future fiscal years. There is no assurance that we will be able to obtain equity or debt financing at acceptable terms, or at all in the future. For a summary of our banking arrangements, see Note 4 Long-Term Debt of the “Notes to Consolidated Financial Statements.” +Our international operations may be subject to certain risks. +Most of the products we manufacture are in facilities located in Mexico and China. These international operations may be subject to a number of risks, including: +• +difficulties in staffing and managing foreign operations; +• +political and economic instability (including acts of terrorism, pandemics, civil unrest, forms of violence and outbreaks of war), which could impact our ability to ship, manufacture, and/or receive product; +• +unexpected changes in regulatory requirements and laws; +• +longer customer payment cycles and difficulty collecting accounts receivable; +• +export duties, import controls and trade barriers (including quotas); +• +governmental restrictions on the transfer of funds; +• +burdens of complying with a wide variety of foreign laws and labor practices; +• +fluctuations in currency exchange rates, which could affect component costs, local payroll, utility and other expenses; +• +our foreign locations may be impacted by hurricanes, earthquakes, water shortages, tsunamis, floods, typhoons, fires, extreme weather conditions and other natural or man-made disasters. +Our operations in certain foreign locations receive favorable income tax treatment in the form of tax credits or other incentives. In the event that such tax incentives are not extended, are repealed, or we no longer qualify for such programs, our taxes may increase, which would reduce our net income. +A significant portion of our operations are in foreign locations. As a result, transactions occur in currencies other than the U.S. dollar. Exchange rate fluctuations among other currencies used by us could directly or indirectly affect our financial results. Future currency fluctuations are dependent upon a number of factors and cannot be easily predicted. We currently use Mexican peso forward contracts to hedge foreign currency fluctuations for a portion of our Mexican peso denominated expenses. However, unexpected losses could occur from future fluctuations in exchange rates. +Additionally, certain foreign jurisdictions restrict the amount of cash that can be transferred to the U.S or impose taxes and penalties on such transfers of cash. To the extent we have excess cash in foreign locations that could be used in, or is needed by, our operations in the United States, we may incur significant penalties and/or taxes to repatriate these funds. +10 +Our success will continue to depend to a significant extent on our key personnel. +Our future success depends in large part on the continued service of our key technical, marketing and management personnel and on our ability to continue to attract and retain qualified employees. There can be no assurance that we will be successful in attracting and retaining such personnel. The loss of key employees could have a material adverse effect on our business, operating results and financial condition. +If we are unable to maintain our technological and manufacturing process expertise, our business could be adversely affected. +The markets for our customers' products is characterized by rapidly changing technology, evolving industry standards, frequent new product introductions and short product life cycles. The introduction of products embodying new technologies or the emergence of new industry standards can render existing products obsolete or unmarketable. Our success will depend upon our customers' ability to enhance existing products and to develop and introduce, on a timely and cost-effective basis, new products that keep pace with technological developments and emerging industry standards and address evolving and increasingly sophisticated customer requirements. Failure of our customers to do so could substantially harm our customers' competitive positions. There can be no assurance that our customers will be successful in identifying, developing and marketing products that respond to technological change, emerging industry standards or evolving customer requirements. +Start-up costs and inefficiencies related to new or transferred programs can adversely affect our operating results and such costs may not be recoverable if such new programs or transferred programs are canceled. +Start-up costs, the management of labor and equipment resources in connection with the establishment of new programs and new customer relationships, and the need to obtain required resources in advance can adversely affect our gross margins and operating results. These factors are particularly evident in the ramping stages of new programs. These factors also affect our ability to efficiently use labor and equipment. We are currently managing a number of new programs. Consequently, our exposure to these factors has increased. In addition, if any of these new programs or new customer relationships were terminated, our operating results could be harmed, particularly in the short term. We may not be able to recoup these start-up costs or replace anticipated new program revenues. +An adverse change in the interest rates for our borrowings could adversely affect our financial condition. +We are exposed to interest rate risk under our revolving line of credit with interest rates based on various levels of margin added to published prime rate and LIBOR rates depending on the calculation of a certain financial covenant. We have not historically hedged the interest rate on our credit facility; therefore, unless we do so significant changes in interest rates could adversely affect our results of operations. +Compliance or the failure to comply with current and future environmental laws or regulations could cause us significant expense. +We are subject to a variety of domestic and foreign environmental regulations relating to the use, storage, and disposal of materials used in our manufacturing processes. If we fail to comply with any present or future regulations, we could be subject to future liabilities or the suspension of current manufacturing operations. In addition, such regulations could restrict our ability to expand our operations or could require us to acquire costly equipment, substitute materials, or incur other significant expenses to comply with government regulations. +Our stock price is volatile. +Holders of the common stock will suffer immediate dilution to the extent outstanding equity awards are exercised to purchase common stock. Our stock price may be subject to wide fluctuations and possible rapid increases or declines over a short time period. These fluctuations may be due to factors specific to us such as variations in quarterly operating results or changes in earnings estimates, or to factors relating to the EMS industry or to the securities markets in general, which, in recent years, have experienced significant price fluctuations. These fluctuations often have been unrelated to the operating performance of the specific companies whose stocks are traded. +Due to inherent limitations, there can be no assurance that our system of disclosure and internal controls and procedures will be successful in preventing all errors, theft and fraud, or in informing management of all material information in a timely manner. +Management does not expect that our disclosure controls and internal controls and procedures will prevent all errors or fraud. A control system is designed to give reasonable, but not absolute, assurance that the objectives of the control system are met. In addition, any control system reflects resource constraints and the benefits of controls must be considered relative to their costs. Inherent limitations of a control system may include: judgments in decision making may be faulty, breakdowns can occur simply because of error or mistake and controls can be circumvented by collusion or management override. Due to the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and may not be detected. +11 +If we do not manage our growth effectively, our profitability could decline. +Our business is experiencing rapid growth which can place considerable additional demands upon our management team and our operational, financial and management information systems. Our ability to manage growth effectively requires us to continue to implement and improve these systems; avoid cost overruns; maintain customer, supplier and other favorable business relationships during possible transition periods; continue to develop the management skills of our managers and supervisors; and continue to train, motivate and manage our employees. Our failure to effectively manage growth could have a material adverse effect on our results of operations. +If our manufacturing processes and services do not comply with applicable statutory and regulatory requirements, or if we manufacture products containing design or manufacturing defects, demand for our services may decline and we may be subject to liability claims. +We manufacture and design products to our customers' specifications, and, in some cases, our manufacturing processes and facilities may need to comply with applicable statutory and regulatory requirements. For example, medical devices that we manufacture or design, as well as the facilities and manufacturing processes that we use to produce them, are regulated by the Food and Drug Administration and non-U.S. counterparts of this agency. In addition, our customers' products and the manufacturing processes that we use to produce them often are highly complex. As a result, products that we manufacture may at times contain manufacturing or design defects, and our manufacturing processes may be subject to errors or not be in compliance with applicable statutory and regulatory requirements. Defects in the products we manufacture or design, whether caused by a design, manufacturing or component failure or error, or deficiencies in our manufacturing processes, may result in delayed shipments to customers or reduced or canceled customer orders. If these defects or deficiencies are significant, our business reputation may also be damaged. The failure of the products that we manufacture or our manufacturing processes and facilities to comply with applicable statutory and regulatory requirements may subject us to legal fines or penalties and, in some cases, require us to shut down or incur considerable expense to correct a manufacturing process or facility. Our customers are required to indemnify us against liability associated with designing products to meet their specifications. However, if our customers are responsible for the defects, they may not, or may not have resources to, assume responsibility for any costs or liabilities arising from these defects, which could expose us to additional liability claims. +Energy price increases may negatively impact our results of operations. +Certain components that we use in our manufacturing process are petroleum-based. In addition, we, along with our suppliers and customers, rely on various energy sources in our transportation activities. While significant uncertainty currently exists about the future levels of energy prices, a significant increase is possible. Increased energy prices could cause an increase to our raw material costs and transportation costs. In addition, increased transportation costs of certain of our suppliers and customers could be passed along to us. We may not be able to increase our product prices enough to offset these increased costs. In addition, any increase in our product prices may reduce our future customer orders and profitability. +Disruptions to our information systems, including security breaches, losses of data or outages, could adversely affect our operations. +We rely on information technology networks and systems to process, transmit and store electronic information. In particular, we depend on our information technology infrastructure for a variety of functions, including worldwide financial reporting, inventory management, procurement, invoicing and email communications. Any of these systems may be susceptible to outages due to fire, floods, power loss, telecommunications failures, terrorist attacks and similar events. Despite the implementation of network security measures, our systems and those of third parties on which we rely may also be vulnerable to computer viruses, break-ins and similar disruptions. If we or our vendors are unable to prevent such outages and breaches, our operations could be disrupted. +We are involved in various legal proceedings. +In the past, we have been notified of claims relating to various matters including contractual matters, intellectual property rights or other issues arising in the ordinary course of business. In the event of such a claim, we may be required to spend a significant amount of money to defend or otherwise address the claim. Any litigation, even where a claim is without merit, could result in substantial costs and diversion of resources. Accordingly, the resolution or adjudication of such disputes, even those encountered in the ordinary course of business, could have a material adverse effect on our business, consolidated financial conditions and results of operations. +12 +Increases in our own market capitalization and changes in securities laws and regulations will increase our costs and risk of noncompliance. +As a result of our increased market capitalization as of the end of our second quarter of fiscal year 2013, we are required to file as an accelerated filer. As such, we are subject to additional requirements contained in the Sarbanes-Oxley Act of 2002 (the Sarbanes-Oxley Act) and more recently the Dodd-Frank Act. The Sarbanes-Oxley and Dodd-Frank Acts required or will require changes in some of our corporate governance, securities disclosure and compliance practices. In response to the requirements of the Sarbanes-Oxley and Dodd-Frank Acts, the SEC and NASDAQ promulgated new rules and additional rulemaking is expected in the future. Compliance with these new rules and future rules has increased and may increase further our legal, financial and accounting costs as well as a potential risk of noncompliance. Absent significant changes in related rules, which we cannot assure, we anticipate some level of increased costs related to these new regulations to continue indefinitely. We also expect these developments to make it more difficult and more expensive to obtain director and officer liability insurance, and we may be forced to accept reduced coverage or incur substantially higher costs to obtain coverage. Likewise, these developments may make it more difficult for us to attract and retain qualified members of our Board of Directors or qualified management personnel. Further, the costs associated with the compliance with and implementation of procedures under these and future laws and related rules could have a material impact on our results of operations. In addition, the costs associated with noncompliance with additional securities laws and regulations could also impact our business. +We may encounter complications with acquisitions, which could potentially harm our business. +Any current or future acquisitions may require additional equity financing, which could be dilutive to our existing shareholders, or additional debt financing, which could potentially affect our credit ratings. Any downgrades in our credit ratings associated with an acquisition could adversely affect our ability to borrow by resulting in more restrictive borrowing terms. To integrate acquired businesses, we must implement our management information systems, operating systems and internal controls, and assimilate and manage the personnel of the acquired operations. The integration of acquired businesses may be further complicated by difficulties managing operations in geographically dispersed locations. The integration of acquired businesses may not be successful and could result in disruption by diverting management's attention from the core business. In addition, the integration of acquired businesses may require that we incur significant restructuring charges or other increases in our expenses and working capital requirements, which reduce our return on invested capital. +Acquisitions may involve numerous other risks and challenges including but not limited to: potential loss of key employees and customers of the acquired companies; the potential for deficiencies in internal controls at acquired companies; lack of experience operating in the geographic market or industry sector of the acquired business; constraints on available liquidity, and exposure to unanticipated liabilities of acquired companies. These and other factors could harm our ability to achieve anticipated levels of profitability at acquired operations or realize other anticipated benefits of an acquisition, and could adversely affect our consolidated business and operating results. +Our goodwill and identifiable intangible assets could become impaired, which could reduce the value of our assets and reduce net income in the year in which the write-off occurs. +Goodwill represents the excess of the cost of an acquisition over the fair value of the net assets acquired. The Company also ascribes value to certain identifiable intangible assets, which consists of customer relationships and non-compete agreements, as a result of the acquisition of Sabre. The Company may incur impairment charges on goodwill or identifiable intangible assets if it determines that the fair values of goodwill or identifiable intangible assets are less than their current carrying values. The Company evaluates, on a regular basis, whether events or circumstances have occurred that indicate all, or a portion, of the carrying amount of goodwill may no longer be recoverable, in which case an impairment charge to earnings would become necessary. +Refer to Notes 1 and 15 to the consolidated financial statements and 'critical accounting policies' in management's discussion and analysis of financial condition and results of operations for further discussion regarding the impairment testing of goodwill and identifiable intangible assets. +A decline in general economic conditions or global equity valuations could impact the judgments and assumptions about the fair value of the Company's businesses and the Company could be required to record impairment charges on its goodwill or other identifiable intangible assets in the future, which could impact the Company's consolidated balance sheet, as well as the Company's consolidated statement of operations. If the Company was required to recognize an impairment charge in the future, the charge would not impact the Company's consolidated cash flows, current liquidity, capital resources, and covenants under its existing credit facilities. +Item 1B. +UNRESOLVED STAFF COMMENTS +None +13 +Item 2. +PROPERTIES +We have manufacturing and sales operations located in the United States, Mexico, and China. The table below lists the locations and square footage of our operating facilities: +Location +Approx. +Sq. Ft. +Type of Interest +(Leased/Owned) +Description of Use +Spokane Valley, Washington (1) +95,000 +Leased +Sales, research, administration and manufacturing +Spokane Valley, Washington +36,000 +Leased +Manufacturing +El Paso, Texas +80,000 +Leased +Shipping and warehouse +Total USA +211,000 +Juarez, Mexico +174,000 +Owned +Manufacturing +Juarez, Mexico +60,000 +Owned +Manufacturing and warehouse +Juarez, Mexico +66,000 +Owned +Manufacturing and warehouse +Juarez, Mexico +115,000 +Owned +Manufacturing and warehouse +Juarez, Mexico (2) +103,000 +Owned +Manufacturing and warehouse +Juarez, Mexico (3) +193,000 +Leased +Warehouse +Juarez, Mexico (4) +66,000 +Leased +Manufacturing +Total Mexico +777,000 +Shanghai, China (5) +115,000 +Leased +Manufacturing and warehouse +Shanghai, China +36,000 +Leased +Manufacturing +Total China +151,000 +Grand Total +1,139,000 +(1) +During fiscal year 2014, we amended the lease agreement whereby increasing our leased space to 95,000 square feet. +(2) +During fiscal year 2012, we purchased an additional 103,000 square feet of manufacturing and warehouse space. +(3) +During fiscal year 2014, we amended the lease agreement whereby increasing our leased space to 193,000 square feet to accommodate additional warehouse space. +(4) +During fiscal year 2014, we completed our acquisition of Sabre Manufacturing resulting in an additional 66,000 square feet of leased manufacturing space. +(5) +During fiscal year 2014, we amended the lease of our China facility whereby increasing our leased space to 115,000 square feet to accommodate additional manufacturing and warehouse space. +On September 3, 2014, the Company acquired CDR Manufacturing resulting in an increase in our manufacturing and warehouse space; however, the amount is yet to be determined. +The geographic diversity of these locations allows us to offer services near certain of our customers and major electronics markets with the additional benefit of reduced labor costs. We consider the productive capacity of our current facilities sufficient to carry on our current business. In addition, in Juarez, Mexico one of our buildings includes adjacent vacant land that could be developed into additional manufacturing and warehouse space. +All of our facilities are ISO certified to ISO 9001:2008 standards, ISO-14001 environmental standards, ISO-13485:2003 medical devices standards, AS9100C aviation, space and defense standards, ISO/TS 16949 automotive standards, ANSI/ESD S20.20-2007 Electrostatic Discharge Control Program and to Customs Trade Partnership against Terrorism (CTPAT). The Spokane, Washington facilities are additionally registered ISO/IEC 80079-34 explosive atmospheres and by the US State Department for International Traffic in Arms Regulations (ITAR). +Item 3. +LEGAL PROCEEDINGS +We are a party to certain lawsuits or claims in the ordinary course of business. We do not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on our financial position, results of operations or cash flow. +14 +Item 4. +MINE SAFETY DISCLOSURES +Not Applicable +PART II +Item 5: +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES +Market Information +Our common stock is traded on the NASDAQ Global Market, formerly the NASDAQ National Market System under the symbol “KTCC”. Quarterly high and low sales prices for our common stock for fiscal years 2014 and 2013 were as follows: +2014 +2013 +High +Low +High +Low +First Quarter +$ +12.19 +$ +9.60 +$ +11.35 +$ +7.15 +Second Quarter +11.36 +9.83 +11.62 +8.69 +Third Quarter +11.44 +9.81 +12.28 +9.36 +Fourth Quarter +10.99 +10.00 +12.12 +10.16 +High and low stock prices are based on the daily sales prices reported by the NASDAQ Stock Market. These quotations represent prices between dealers without adjustment for markups, markdowns, and commissions, and may not represent actual transactions. +Holders and Dividends +As of June 28, 2014 , we had 721 shareholders of common stock on record. As a result of our credit agreement with Wells Fargo Bank, N.A. we are restricted from declaring or paying dividends in cash or stock without the Bank's prior written consent. We have not paid a cash dividend and do not anticipate payment of dividends in the foreseeable future. +15 +Equity Compensation Plan Information +Information concerning securities authorized for issuance under our equity compensation plans is set forth in Part III, Item 12 of this Annual Report, under the caption “Securities Authorized for Issuance under Equity Compensation Plans”, and that information is incorporated herein by reference. +Performance Graph +Set forth below is a line graph comparing the cumulative total shareholder return on our common stock with the cumulative total return of the NASDAQ Stock Market (U.S. & Foreign) Index and the NASDAQ Electronic Components Index in fiscal 2014 . +6/27/2009 +7/3/2010 +7/2/2011 +6/30/2012 +6/29/2013 +6/28/2014 +Key Tronic Corporation +100.00 +295.76 +273.94 +499.39 +627.27 +650.30 +NASDAQ Composite +100.00 +117.06 +154.79 +167.05 +197.48 +259.41 +NASDAQ Electronic Components +100.00 +119.12 +151.74 +143.59 +160.15 +222.48 +16 +Item 6: +SELECTED FINANCIAL DATA +The following selected data is derived from our audited consolidated financial statements and should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the consolidated financial statements and related notes, and other information included in this report. +Financial Highlights +(In thousands, except for Supplemental Data and Per Share Amounts) +Fiscal Year Ended +June 28, 2014 +June 29, 2013 +June 30, 2012 +July 2, 2011 +July 3, 2010 +Consolidated Statements of Operations Data : +Net sales +$ +305,394 +$ +361,033 +$ +346,475 +$ +253,846 +$ +199,620 +Gross profit +26,854 +34,512 +29,836 +20,648 +19,250 +Gross margin percentage +8.8 +% +9.6 +% +8.6 +% +8.1 +% +9.6 +% +Operating income +9,304 +18,126 +14,351 +6,939 +7,388 +Operating margin percentage +3.0 +% +5.0 +% +4.1 +% +2.7 +% +3.7 +% +Net income +7,613 +12,583 +11,626 +5,736 +8,690 +Earnings per share – diluted +0.67 +1.12 +1.07 +0.55 +0.85 +Consolidated Cash Flow Data : +Cash flows provided by (used in) operations +1,458 +29,282 +(5,066 +) +(2,569 +) +3,534 +Capital expenditures +7,763 +3,470 +4,654 +3,818 +3,378 +Consolidated Balance Sheet Data : +Net working capital (1) +71,049 +73,827 +76,236 +58,307 +44,708 +Total assets +156,660 +135,130 +150,912 +112,364 +101,642 +Long-term liabilities +848 +3,030 +19,050 +11,063 +4,236 +Shareholders’ equity +103,645 +94,160 +78,608 +68,023 +59,417 +Book value per share (2) +$ +9.83 +$ +8.97 +$ +7.50 +$ +6.54 +$ +5.79 +Supplemental Data : +Number of shares outstanding at year-end +10,546,750 +10,502,188 +10,481,356 +10,399,187 +10,264,390 +Number of employees at year-end +3,343 +2,584 +2,700 +1,997 +2,036 +Approximate square footage of operational facilities +1,139,000 +1,011,000 +945,000 +796,000 +987,000 +(1) +Net working capital is defined as total current assets less total current liabilities. Net working capital measures the portion of current assets that are financed by long term funds and is an indicator of short term financial management. +(2) +Book value per share is defined as total shareholders’ equity divided by the number of shares outstanding at the end of the fiscal year. +17 +Item 7: +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +Overview +KeyTronicEMS is a leader in electronic manufacturing services and solutions to original equipment manufacturers of a broad range of products. We provide engineering services, worldwide procurement and distribution, materials management, world-class manufacturing and assembly services, in-house testing, and unparalleled customer service. Our international production capability provides our customers with benefits of improved supply-chain management, reduced inventories, lower transportation costs, and reduced product fulfillment time. We continue to make investments in all of our operating facilities to give us the production capacity, capabilities and logistical advantages to continue to win new business. The following information should be read in conjunction with the consolidated financial statements included herein and with Item 1A, Risk Factors included as part of this filing. +Our mission is to provide our customers with superior manufacturing and engineering services at the lowest total cost for the highest quality products, and create long-term mutually beneficial business relationships by employing our “Trust, Commitment, Results” philosophy. +Executive Summary +While fiscal year 2014 was a challenging year with respect to our total revenue, we continued to make significant progress in ramping up our new programs, expanding our customer base and extending our capabilities. Throughout the year, our revenue was impacted by slowdowns and delays from certain longstanding customers. At the same time, we saw the continued ramp up of our new programs, while maintaining operating efficiencies and a strong balance sheet. +Net sales of $305.4 million for fiscal year 2014 decreased by 15.4 percent as compared to net sales of $361.0 million in fiscal year 2013 . The decrease in net sales was primarily driven by the overall decrease in demand related to current customer programs. At the end of fiscal year 2014 , we were generating revenue from 196 separate programs and 59 distinct customers as compared to 183 programs and 56 customers at the end of fiscal year 2013 . These new customers have programs that represent small annual sales while others have multi-million-dollar potential. Moving into the first quarter of fiscal 2015, our new customer programs continue to steadily ramp up and we expect to see renewed sequential growth. Furthermore, our acquisition of CDR Manufacturing on September 3, 2014, represents a major step forward for Key Tronic, significantly growing our revenue and extending capabilities and customer base worldwide. Excluding the potential impact of the acquisition of CDR manufacturing in fiscal year 2015, the Company expects to report revenue in the range of $76 million to $82 million for the first quarter of fiscal year 2015 . Future results will depend on actual levels of customers’ orders, the timing of the start-up of production of new product programs and the potential impact of the macroeconomic uncertainty. We believe that we are well positioned in the EMS industry to continue expansion of our customer base and continue long-term growth. +The concentration of our largest customers decreased during fiscal year 2014 with the top five customers’ sales decreasing to 62 percent of total sales in 2014 from 71 percent in 2013 , and 73 percent in 2012 . Our current customer relationships involve a variety of products, including consumer electronics, electronic storage devices, plastics, household products, gaming devices, specialty printers, telecommunications, industrial equipment, military supplies, computer accessories, electronic whiteboards, medical, educational, irrigation, automotive, transportation management, robotics, RFID, power supply, off-road vehicle equipment, fitness equipment, HVAC controls, and consumer products. +Gross profit as a percent of sales was 8.8 percent in fiscal year 2014 compared to 9.6 percent for the prior fiscal year. This 0.8 percentage point decrease in gross profit as a percentage of net sales during fiscal year 2014 as compared to fiscal year 2013 is primarily related to a 5.1 percentage point increase in certain overhead costs as we brought on additional headcount and equipment to support new customer programs, partially offset by a 4.3 percentage point improvement in material costs. The level of gross margin is impacted by product mix, timing of the startup of new programs, facility utilization, pricing within the electronics industry and material costs, which can fluctuate significantly from quarter to quarter and year to year. +Operating income as a percentage of sales for fiscal year 2014 was 3.0 percent compared to 5.0 percent for fiscal year 2013 . The decrease in operating income as a percentage of net sales was primarily due to a decrease in gross margin and a slight increase in headcount in program management and engineering to support new program wins and anticipated future growth. +Net income for fiscal year 2014 was $7.6 million or $0.67 per diluted share, as compared to net income of $12.6 million or $1.12 per diluted share for fiscal year 2013 . The decrease in net income for fiscal year 2014 as compared to fiscal year 2013 was primarily due to a decrease in demand from some of our large, longstanding customers as well as an increase in certain overhead costs as a percentage of net sales, partially offset by a decrease in material-related costs as a percentage of net sales. +18 +We maintain a strong balance sheet with a current ratio of 2.4 and currently have no bank debt apart from $7.9 million outstanding under a factoring agreement described in Note 5. Total cash provided by operating activities as defined on our cash flow statement was $1.5 million during fiscal year 2014 . We maintain sufficient liquidity for our expected future operations. We did not have an outstanding balance on our revolving line of credit with Wells Fargo Bank, N.A. as of June 28, 2014 . As a result, $30.0 million remained available to borrow as of June 28, 2014 . We believe cash flow from operations, our borrowing capacity, our accounts receivable sale program, and equipment lease financing should provide adequate capital for planned growth over the long term. +RESULTS OF OPERATIONS +Comparison of the Fiscal Year Ended June 28, 2014 with the Fiscal Year Ended June 29, 2013 +The following table sets forth for the periods indicated certain items of the consolidated statements of income expressed as a percentage of net sales. The financial information and discussion below should be read in conjunction with the consolidated financial statements and notes contained in this Annual Report. +Fiscal Year Ended +June 28, 2014 +% of +net sales +June 29, 2013 +% of +net sales +$ change +% point +change +Net sales +$ +305,394 +100.0% +$ +361,033 +100.0% +$ +(55,639 +) +— +Cost of sales +278,540 +91.2 +326,521 +90.4 +(47,981 +) +0.8 +Gross profit +26,854 +8.8 +34,512 +9.6 +(7,658 +) +(0.8) +Operating expenses: +Research, development and engineering +5,586 +1.8 +5,156 +1.4 +430 +0.4 +Selling, general and administrative +11,964 +3.9 +11,230 +3.1 +734 +0.8 +Total operating expenses +17,550 +5.7 +16,386 +4.5 +1,164 +1.2 +Operating income +9,304 +3.0 +18,126 +5.0 +(8,822 +) +(2.0) +Interest expense, net +81 +— +271 +0.1 +(190 +) +(0.1) +Income before income taxes +9,223 +3.0 +17,855 +4.9 +(8,632 +) +(1.9) +Income tax provision +1,610 +0.5 +5,272 +1.5 +(3,662 +) +(1.0) +Net income +$ +7,613 +2.5% +$ +12,583 +3.5% +$ +(4,970 +) +(1.0) +Effective income tax rate +17.5 +% +29.5 +% +Net Sales +The decrease in net sales from prior year was primarily driven by an approximate $67.4 million decrease in revenues related to decreased demand from current customer programs, an approximate $5.2 million decrease in revenues related to program losses, partially offset by a $17.0 million increase in revenues related to new program wins and the revenue generated from the acquisition of Sabre. +The following table shows the revenue by industry sectors as a percentage of revenue for fiscal years 2014 and 2013 : +Fiscal Year Ended +June 28, 2014 +June 29, 2013 +Consumer +30% +24% +Communication +23 +29 +Industrial and Commercial Printer +17 +8 +Gaming +15 +22 +Transaction Printer +11 +11 +Computer and Peripheral +4 +6 +Total +100% +100% +We provide services to customers in a number of industries and produce a variety of products for our customers in each industry. As we continue to diversify our customer base and win new customers we will continue to see a change in the industry concentrations of our revenue. +Sales to foreign locations outside the United States represented 35.3 percent, and 31.8 percent of our total net sales in fiscal years 2014 , and 2013 , respectively. +19 +Cost of Sales +Total cost of sales as a percentage of net sales was 91.2 percent and 90.4 percent in fiscal years 2014 , and 2013 , respectively. +Total cost of materials as a percentage of net sales was approximately 64.5 percent and 68.5 percent in fiscal years 2014 and 2013 , respectively. The change from year-to-year is primarily the result of a change in product mix and to a lesser degree improved pricing of certain raw materials. +Production and support costs as a percentage of net sales were 26.7 percent and 21.9 percent in fiscal years 2014 and 2013 , respectively. The increase in fiscal year 2014 is primarily related to adding headcount and manufacturing capacity to support new programs. +We provide a reserve for obsolete and non-saleable inventories based on specific identification of inventory against current demand and recent usage. The amounts charged to expense for these inventories were approximately $0.3 million, and $0.5 million in fiscal years 2014 and 2013 , respectively. +We provide warranties on certain products we sell and estimate warranty costs based on historical experience and anticipated product returns. Warranty expense is related to workmanship claims on keyboards and EMS products. The amounts charged to expense are determined based on an estimate of warranty exposure. The net warranty expense was approximately $35,000 and $26,000 in fiscal years 2014 and 2013 , respectively. +Gross Profit +Gross profit as a percentage of net sales was 8.8 percent and 9.6 percent in fiscal years 2014 , and 2013 , respectively. The 0.8 percentage point decrease in gross profit as a percentage of net sales during fiscal year 2014 as compared to fiscal year 2013 is primarily related to a 5.1 percentage point increase in certain overhead costs, partially offset by a 4.3 percentage point improvement in material costs. +Changes in gross profit margins reflect the impact of a number of factors that can vary from period to period, including product mix, start-up costs and efficiencies associated with new programs, product life cycles, sales volumes, capacity utilization of our resources, management of inventories, component pricing and shortages, end market demand for customers’ products, fluctuations in and timing of customer orders, and competition within the EMS industry. These and other factors can cause variations in operating results. There can be no assurance that gross margins will not decrease in future periods. +We took early pay discounts to suppliers that totaled approximately $1.1 million and $0.9 million in fiscal years 2014 and 2013 , respectively. Early pay discounts will fluctuate based on our liquidity and changes in the discounts and terms offered by our suppliers. +Research, Development and Engineering +Research, development and engineering expenses (RD&E) consists principally of employee related costs, third party development costs, program materials, depreciation and allocated information technology and facilities costs. Total RD&E expense was $5.6 million and $5.2 million in fiscal years 2014 and 2013 , respectively. This $0.4 million increase is primarily the result of an increase in payroll related expenses as additional headcount was necessary to support new program wins and anticipated future growth. +Total RD&E expenses as a percent of net sales were 1.8 percent and 1.4 percent in fiscal years 2014 and 2013 , respectively. This 0.4 percentage point increase in RD&E is primarily related to a slight increase in headcount in program management and engineering to support new program wins and anticipated future growth coupled with the decline in revenue. +Selling, General and Administrative +Selling, general and administrative expenses (SG&A) consist principally of salaries and benefits, advertising and marketing programs, sales commissions, travel expenses, provision for doubtful accounts, facilities costs, and professional services. Total SG&A expenses were $12.0 million and $11.2 million in fiscal years 2014 and 2013 , respectively. This $0.7 million increase is primarily related to an increase in payroll related expenses due to increased headcount. In addition, SG&A expenses for fiscal year 2013, included a positive impact of a non-recurring adjustment of approximately $0.5 million related to the reversal of a deferred compensation liability. +Total SG&A expenses as a percent of net sales were 3.9 percent and 3.1 percent in fiscal years 2014 and 2013 , respectively. This 0.8 percent percentage point increase in SG&A is primarily related to an increase in labor related expenses and the decrease in net sales. +20 +Interest Expense +We had net interest expense of $0.1 million and $0.3 million in fiscal years 2014 and 2013 , respectively. This decrease in interest expense is primarily related to a decrease in the average balance outstanding on our line of credit and to a lesser extent paying down existing capital leases. +Income Tax Provision +We had an income tax expense of $1.6 million during fiscal year 2014 as compared to an income tax expense of $5.3 million in fiscal year 2013 . The income tax expense recognized during both fiscal years 2014 and 2013 was primarily a function of U.S. and foreign taxes recognized at the statutory rates offset by the net benefit associated with federal research and development tax credits, changes in potential foreign tax credits and changes in foreign tax regimes. The impact of this offset was greater in 2014 because the Company recognized a one-time benefit related to the repeal of the IETU tax regime in Mexico during fiscal year 2014. +We continually review our requirements for liquidity domestically to fund revenue growth and to look for potential future acquisitions. We continue to anticipate repatriating a portion of our unremitted foreign earnings. The associated taxes and potential foreign tax credits are included in the income tax calculation. For further information on taxes please review footnote 6 of the “Notes to Consolidated Financial Statements.” +International Subsidiaries +We offer customers a complete global manufacturing solution. Our facilities provide our customers the opportunity to have their products manufactured in the facility that best serves specific cost, product manufacturing and distribution needs. The locations of active foreign subsidiaries are as follows: +• +Key Tronic Juarez, SA de CV owns an SMT, assembly and molding facility, newly acquired sheet metal fabrication, and five assembly and storage facilities in Juarez, Mexico. This subsidiary is primarily used to support our U.S. operations. +• +Key Tronic Computer Peripherals (Shanghai) Co., Ltd. leases two facilities with SMT, assembly, global purchasing and warehouse capabilities in Shanghai, China, which began operations in 1999. Its primary function is to provide EMS services for export; however, it is also currently manufacturing certain electronic keyboards. +Foreign sales (based on shipping instructions) from our worldwide operations, including domestic exports, were $107.7 million , $115.0 million and $140.8 million in fiscal years 2014 , 2013 and 2012 , respectively. Products and manufacturing services provided by our subsidiary operations are primarily sold to customers directly by the parent company. Key Tronic Computer Peripherals (Shanghai) Co., Ltd., our subsidiary in Shanghai, China, had only minimal direct sales to customers in China during the past two fiscal years. +21 +RESULTS OF OPERATIONS +Comparison of the Fiscal Year Ended June 29, 2013 with the Fiscal Year Ended June 30, 2012 +The following table sets forth for the periods indicated certain items of the consolidated statements of income expressed as a percentage of net sales. The financial information and discussion below should be read in conjunction with the consolidated financial statements and notes contained in this Annual Report. +Fiscal Year Ended +June 29, 2013 +% of +net sales +June 30, 2012 +% of +net sales +$ change +% point +change +Net sales +$ +361,033 +100.0% +$ +346,475 +100.0% +$ +14,558 +— +Cost of sales +326,521 +90.4 +316,639 +91.4 +9,882 +(1.0) +Gross profit +34,512 +9.6 +29,836 +8.6 +4,676 +1.0 +Operating expenses: +Research, development and engineering +5,156 +1.4 +4,444 +1.3 +712 +0.1 +Selling, general and administrative +11,230 +3.1 +11,041 +3.2 +189 +(0.1) +Total operating expenses +16,386 +4.5 +15,485 +4.5 +901 +— +Operating income +18,126 +5.0 +14,351 +4.1 +3,775 +0.9 +Interest expense, net +271 +0.1 +510 +0.1 +(239 +) +— +Income before income taxes +17,855 +4.9 +13,841 +4.0 +4,014 +0.9 +Income tax provision +5,272 +1.5 +2,215 +0.6 +3,057 +0.9 +Net income +$ +12,583 +3.5% +$ +11,626 +3.4% +$ +957 +0.1 +Effective income tax rate +29.5 +% +16.0 +% +Net Sales +The increase in net sales from prior year was primarily driven by an approximate $11.7 million increase in revenues related to new programs for both new and longstanding customers and to a lesser extent a net $5.5 million increase related to increased demand from current customer programs, which was partially offset by the slowdown from the large customer that began to reduce production levels in the second quarter of fiscal year 2013. In addition, the increases were negatively impacted by $2.6 million related to customer program losses. The negative impact resulting from the previously discussed slowdown of demand from one of our larger customers is reflected in the analysis above. +The following table shows the revenue by industry sectors as a percentage of revenue for fiscal years 2013 and 2012: +Fiscal Year Ended +June 29, 2013 +June 30, 2012 +Communication +29% +36% +Consumer +24 +20 +Gaming +22 +18 +Transaction Printer +11 +12 +Industrial and Commercial Printer +8 +7 +Computer and Peripheral +6 +7 +Total +100% +100% +We provide services to customers in a number of industries and produce a variety of products for our customers in each industry. As we continue to diversify our customer base and win new customers we may continue to see a change in the industry concentrations of our revenue. +Sales to foreign locations outside the United States represented 31.8 percent, and 40.6 percent of our total net sales in fiscal years 2013, and 2012, respectively. +22 +Cost of Sales +Total cost of sales as a percentage of net sales was 90.4 percent and 91.4 percent in fiscal years 2013, and 2012, respectively. +Total cost of materials as a percentage of net sales was approximately 68.5 percent and 70.4 percent in fiscal years 2013 and 2012, respectively. The change from year-to-year is primarily the result of a change in product mix and to a lesser degree improved pricing of certain raw materials. +Production and support costs as a percentage of net sales were 21.9 percent, and 21.0 percent in fiscal years 2013 and 2012, respectively. The increase in fiscal year 2013 is primarily related to adding headcount and manufacturing capacity to support new programs. +We provide a reserve for obsolete and non-saleable inventories based on specific identification of inventory against current demand and recent usage. The amounts charged to expense for these inventories were approximately $0.5 million, and $0.8 million in fiscal years 2013 and 2012, respectively. +We provide warranties on certain products we sell and estimate warranty costs based on historical experience and anticipated product returns. Warranty expense is related to workmanship claims on keyboards and EMS products. The amounts charged to expense are determined based on an estimate of warranty exposure. The net warranty expense was approximately $26,000 and $65,000 in fiscal years 2013 and 2012, respectively. +Gross Profit +Gross profit as a percentage of net sales was 9.6 percent and 8.6 percent in fiscal years 2013, and 2012, respectively. The 1.0 percentage point increase in gross profit as a percentage of net sales during fiscal year 2013 as compared to fiscal year 2012 is primarily related to a 1.9 percentage point improvement in material costs, as a percent of sales, partially offset by a 0.9 percentage point increase in certain overhead costs. +Changes in gross profit margins reflect the impact of a number of factors that can vary from period to period, including product mix, start-up costs and efficiencies associated with new programs, product life cycles, sales volumes, capacity utilization of our resources, management of inventories, component pricing and shortages, end market demand for customers’ products, fluctuations in and timing of customer orders, and competition within the EMS industry. These and other factors can cause variations in operating results. There can be no assurance that gross margins will not decrease in future periods. +We took early pay discounts to suppliers that totaled approximately $946,000 and $932,000 in fiscal years 2013 and 2012, respectively. Early pay discounts will fluctuate based on our liquidity and changes in the discounts and terms offered by our suppliers. +Research, Development and Engineering +Research, development and engineering expenses (RD&E) consists principally of employee related costs, third party development costs, program materials, depreciation and allocated information technology and facilities costs. Total RD&E expense was $5.2 million and $4.4 million in fiscal years 2013 and 2012, respectively. This $0.7 million increase is primarily the result of an increase in payroll related expenses as additional headcount was necessary to support new programs as they ramp up. +Total RD&E expenses as a percent of net sales were 1.4 percent and 1.3 percent in fiscal years 2013 and 2012, respectively. This 0.1 percentage point increase in RD&E is primarily related to our deleveraging of operating expenses as a percent of net sales. +Selling, General and Administrative +Selling, general and administrative expenses (SG&A) consist principally of salaries and benefits, advertising and marketing programs, sales commissions, travel expenses, provision for doubtful accounts, facilities costs, and professional services. Total SG&A expenses were $11.2 million and $11.0 million in fiscal years 2013 and 2012, respectively. This $0.2 million increase is primarily related to an increase in payroll related expenses due to increased headcount and higher incentive compensation as compared to the prior year. This increase is partially offset by the positive impact of a non-recurring adjustment of approximately $0.5 million related to the elimination of a deferred compensation liability. +Total SG&A expenses as a percent of net sales were 3.1 percent and 3.2 percent in fiscal years 2013 and 2012, respectively. This 0.1 percent percentage point improvement in SG&A is primarily related to our continued success in leveraging operating expenses as a percent of net sales. +Interest Expense +We had net interest expense of $0.3 million and $0.5 million in fiscal years 2013 and 2012, respectively. This decrease is primarily related to a decrease in the average balance outstanding on our line of credit during the year and the impact of not having an outstanding balance on our line of credit at fiscal year end 2013. +23 +Income Tax Provision +We had an income tax expense of $5.3 million during fiscal year 2013 as compared to an income tax expense of $2.2 million in fiscal year 2012. The income tax expense recognized during both fiscal 2013 and 2012 was primarily a function of U.S. and foreign taxes recognized at the statutory rates offset by the net benefit associated with federal research and development tax credits and changes in potential foreign tax credits. The impact of this offset was greater in 2012 because the Company recognized a benefit related to federal research and development tax credits during fiscal 2012, due to the results of a multi-year tax credit study performed during that year. Fiscal 2013 recognized credits were related to expenses incurred during the current year. +Due to increased profitability, revenue growth, and new customer programs, we utilized all remaining domestic and foreign net operating loss carryforwards (NOLs) during fiscal year 2012. As a result, there was no remaining deferred tax asset as of June 30, 2012 related to NOLs. In addition, we continually review our requirements for liquidity domestically to fund revenue growth and to look for potential future acquisitions. We continue to anticipate repatriating a portion of our unremitted foreign earnings. The associated taxes and potential foreign tax credits are included in the income tax calculation. For further information on taxes please review footnote 6 of the “Notes to Consolidated Financial Statements.” +Capital Resources and Liquidity +Operating Cash Flow +Net cash provided by operating activities for fiscal year 2014 was $1.5 million compared to net cash provided by operating activities of $29.3 million and net cash used in operating activities of $5.1 million in fiscal years 2013 and 2012 , respectively. +The working capital year-over-year change is primarily related to a $10.5 million increase in inventory, a $2.7 million increase in accounts receivable, partially offset by a $6.1 million increase in accounts payable. The working capital changes during fiscal year 2013 are primarily due to a $13.3 million decrease in inventory and a $13.6 million decrease in accounts receivable, which were partially offset by a $16.6 million decrease in accounts payable. +Accounts receivable fluctuates based on the timing of shipments, terms offered and collections. Accounts payable fluctuates with changes in inventory levels, volume of inventory purchases, negotiated supplier terms, and taking advantage of early pay discounts. We purchase inventory based on customer forecasts and orders, and when those forecasts and orders change, the amount of inventory may also fluctuate. +Investing Cash Flow +Cash flows used in investing activities were $13.8 million , $3.3 million , and $4.6 million in fiscal years 2014 , 2013 and 2012 , respectively. Our primary investing activity during fiscal year 2014 was the acquisition of Sabre as discussed in further detail in Footnote 14 of the "Notes to Consolidated Financial Statements." In addition, investing cash flows consists of capital expenditures to purchase sheet metal and plastic injection molding equipment to support production. +Operating and capital leases are often utilized when potential technical obsolescence and funding requirement advantages outweigh the benefits of equipment ownership. Capital expenditures and periodic lease payments are expected to be financed with internally generated funds and available borrowing capacities. +Financing Cash Flow +Cash flows provided by financing activities were $7.3 million in fiscal year 2014 as compared to cash flows used in financing activities of $15.7 million and cash flows provided by financing activities of $9.0 million in fiscal years 2013 and 2012 , respectively. Our primary financing activities in fiscal years 2014 , 2013 , and 2012 was borrowing and repayment under our revolving line of credit facility and principal payments on our capital lease obligations. Our credit agreement with Wells Fargo Bank, N.A. provides a revolving line of credit facility of up to $30.0 million. The agreement specifies that the proceeds of the revolving line of credit be used primarily for working capital and general corporate purposes of the Company and its subsidiaries. The Company did not have an outstanding balance on the line of credit as of June 28, 2014 . We had availability to borrow $30.0 million under the Wells Fargo line of credit and we were in compliance with our loan covenants. During fiscal year 2014 , cash provided by financing activities also reflected payments of $0.6 million on capital leases. Additionally, the Company received $7.9 million in cash as a result of our accounts receivable purchase program with Wells Fargo Bank, N.A. during fiscal year 2014. The Company did not receive any cash related to the accounts receivable purchase program during fiscal years 2013 and 2012. +Our cash requirements are affected by the level of current operations and new EMS programs. We believe that projected cash from operations, funds available under the revolving credit facility and leasing capabilities will be sufficient to meet our working and fixed capital requirements for the foreseeable future. +24 +As of June 28, 2014 , we had approximately $0.8 million of cash held by foreign subsidiaries. If cash is to be repatriated in the future from these foreign subsidiaries, the Company could be subject to additional income taxes payable in the U.S. The total amount of U.S. taxes required to be paid for the amount of foreign subsidiary cash on hand as of June 28, 2014 would approximate $82,000. The Company also has approximately $23.8 million of foreign earnings that has not been repatriated back to the U.S. Of that amount, the Company estimates that $10.5 million is to be repatriated in the future, requiring U.S. taxes of $1.5 million that is currently accrued in our deferred tax liabilities. The remaining $13.3 million is considered to be permanently reinvested in Mexico and China. If these amounts were required to be repatriated it would create an additional $2.8 million U.S. tax liability. +Contractual Obligations and Commitments +In the normal course of business, we enter into contracts which obligate us to make payments in the future. The table below sets forth our significant future obligations by fiscal year: +Payments Due by Fiscal Year (in thousands) +Total +2015 +2016 +2017 +2018 +2019 +Thereafter +Wells Fargo Bank N.A. revolving loan (1) +$ +— +$ +— +$ +— +$ +— +$ +— +$ +— +$ +— +Operating leases (2) +8,169 +2,806 +1,776 +900 +755 +757 +1,175 +Purchase orders (3) +(1) +The terms of the Wells Fargo Bank N.A. revolving loan are discussed in the consolidated financial statements at Note 4, “Long-Term Debt.” As of June 28, 2014 , we were in compliance with our loan covenants. Breaching these covenants could have resulted in a material impact on our operations or financial condition and could impact our ability to borrow under this facility in the future. +(2) +We maintain vertically integrated manufacturing operations in Mexico and China. We lease some of our administrative and manufacturing facilities. A complete discussion of properties can be found in Part 1, Item 2 at “Properties.” Leases have proven to be an acceptable method for us to acquire new or replacement equipment and to maintain facilities with a minimum impact on our short term cash flows for operations. In addition, such operations are heavily dependent upon technically superior manufacturing equipment including molding machines in various tonnages, Surface Mount Technology (SMT) lines, clean rooms, and automated insertion, and test equipment for the various products we are capable of producing. +(3) +As of June 28, 2014 , we had open purchase order commitments for materials and other supplies of approximately $47.7 million. Included in the open purchase orders are various blanket orders for annual requirements. Actual needs under these blanket purchase orders fluctuate with our manufacturing levels. In addition, we have contracts with our customers that minimize our exposure to losses for material purchased within lead-times necessary to meet customer forecasts. Purchase orders generally can be cancelled without penalty within specified ranges that are determined in negotiations with our suppliers. These agreements depend in part on the type of materials purchased as well as the circumstances surrounding any requested cancellations. +On September 3, 2014, the Company acquired CDR Manufacturing resulting in an increase in our operating leases; however, the amount is yet to be determined. +In addition to the cash requirements presented above, we have various other accruals which are not included in the table above. For example, we owe our suppliers approximately $32.5 million for accounts payable and shipments in transit at the end of the fiscal year. We generally pay our suppliers in a range from 30 to 120 days depending on terms offered. These payments are financed by operating cash flows and our revolving line of credit. Also, the Company had a net liability of $7.9 million to WFB for accounts receivables transferred as of June 28, 2014. +We believe that cash flows generated from operations, leasing facilities, and funds available under the revolving credit facility will satisfy cash requirements for a period in excess of 12 months and into the foreseeable future. +Critical Accounting Policies and Estimates +Preparation of our consolidated financial statements requires management to make estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses. Note 1 to our consolidated financial statements describes the significant accounting policies used in the preparation of our consolidated financial statements. Management believes the most complex and sensitive judgments, because of their significance to our consolidated financial statements, result primarily from the need to make estimates about effects of matters that are inherently uncertain. The most significant areas involving management judgments are described below. Actual results in these areas could differ from management’s estimates. +25 +Revenue +Sales revenue from manufacturing is recognized upon shipment of the manufactured product per contractual terms. Upon shipment, title transfers and the customer assumes risks and rewards of ownership of the product. The price to the buyer is fixed or determinable and recoverability is reasonably assured. Unless specifically stated in contractual terms, there are no formal customer acceptance requirements or further obligations related to the manufacturing services; if any such requirements exist, then sales revenue is recognized at the time when such requirements are completed and such obligations are fulfilled. Revenue is recorded net of estimated returns of manufactured product based on management’s analysis of historical returns. +Revenues and associated costs from engineering design, development services and tooling, which are performed under contract of short term durations, are recognized only after the completed performance of the service. +Inactive, Obsolete, and Surplus Inventory Reserve +We reserve for inventories that we deem inactive, obsolete or surplus. This reserve is calculated based upon the demand for the products that we produce. Demand is determined by expected sales, customer purchase orders, or customer forecasts. If expected sales do not materialize, then we would have inventory in excess of our reserves and would have to charge the excess against future earnings. In the case where we have purchased material based upon a customer’s forecast or purchase orders, we are usually covered by lead-time assurance agreements or purchase orders with each customer. These contracts state that the financial liability for material purchased within agreed upon lead-time and based upon the customer’s forecasts, lies with the customer. If we purchase material outside the lead-time assurance agreement and the customer’s forecasts do not materialize or if we have no lead-time assurance agreement for a specific program, we would have the financial liability and may have to charge inactive, obsolete or surplus inventory against earnings. +Allowance for Doubtful Accounts +We value our accounts receivable net of an allowance for doubtful accounts. As of June 28, 2014 , we deemed that no allowance was necessary. The allowance for doubtful accounts was $40,000 as of June 29, 2013 . This allowance is based on estimates of the portion of accounts receivable that may not be collected in the future. The estimates used are based primarily on specific identification of potentially uncollectible accounts. Such accounts are identified using publicly available information in conjunction with evaluations of current payment activity. However, if any of our customers were to develop unexpected and immediate financial problems that would prevent payment of open invoices, we could incur additional and possibly material expenses that would negatively impact earnings. +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. We review the adequacy of this accrual quarterly based on historical analysis and anticipated product returns and rework costs. As we have made the transition from manufacturing primarily keyboards to primarily EMS products, our exposure to warranty claims has declined significantly. Our warranty period for keyboards is generally longer than that for EMS products. We only warrant materials and workmanship on EMS products, and we do not warrant design defects for EMS customers. +Income Taxes +Income tax expense includes U.S. and international income taxes and the provision for U.S. taxes on undistributed earnings of foreign subsidiaries not deemed to be permanently invested. We do not record U.S. tax liabilities on undistributed earnings of international subsidiaries that are deemed to be permanently reinvested. Certain income and expenses are not reported in tax returns and financial statements in the same year. The tax effect of such temporary differences is reported as deferred income taxes. The deferred income taxes are classified as current or long-term based on the classification of the related asset or liability. The most significant areas involving management judgments include deferred income tax assets and liabilities, uncertain tax positions, and research and development tax credits. Our estimates of the realization of the deferred tax assets related to our tax credits are based upon our estimates of future taxable income which may change. +Stock-Based Compensation +Stock-based compensation is accounted for according to Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 718, Compensation—Stock Compensation . ASC 718 requires us to expense the fair value of employee stock options, stock appreciation rights and other forms of stock-based compensation. Under the fair value recognition provisions of ASC 718, share-based compensation cost is estimated at the grant date based upon the fair value of the award and is recognized as expense ratably over the requisite service period of the award (generally the vesting period). Determining the appropriate fair value model and calculating the fair value of share-based awards requires judgment, including estimating the expected life of the share-based award, the expected stock price volatility over the expected life of the share-based award and forfeitures. +26 +To determine the fair value of stock based awards on the date of grant we use the Black-Scholes option-pricing model. Inherent in this model are assumptions related to expected stock price volatility, option life, risk-free interest rate and dividend yield. The risk-free interest rate is a less-subjective assumption as it is based on factual data derived from public sources. We use a dividend yield of zero as we have never paid cash dividends and have no intention to pay cash dividends in the foreseeable future. The expected stock price volatility and option life assumptions require a greater level of judgment. Our expected stock-price volatility assumption is based upon the historical volatility of our stock which is obtained from public data sources. The expected life represents the weighted average period of time that share-based awards are expected to be outstanding, giving consideration to vesting schedules and historical exercise patterns. We determine the expected life assumption based upon the exercise and post-vesting behavior that has been exhibited historically, adjusted for specific factors that may influence future exercise patterns. If expected volatility or expected life were to increase, that would result in an increase in the fair value of our stock options which would result in higher compensation charges, while a decrease in volatility or the expected life would result in a lower fair value of our stock option awards resulting in lower compensation charges. +We estimate forfeitures for all of our awards based upon historical experience of stock-based pre-vesting forfeitures. We believe that our estimates are based upon outcomes that are reasonably likely to occur. If actual forfeitures are higher than our estimates it would result in lower compensation expense and to the extent the actual forfeitures are lower than our estimate we would record higher compensation expense. +Impairment of Long-Lived Assets +Long-lived assets, such as property, plant, and equipment are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment charge would be recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. +Derivatives and Hedging Activity +Derivatives are recognized on the balance sheet at their estimated fair value. On the date a derivative contract is entered into, the Company designates the derivative as a hedge of a forecasted transaction or of the variability of cash flows to be received or paid related to a recognized asset or liability (a “cash flow” hedge). The Company does not enter into derivatives for speculative purposes. Changes in the fair value of a derivative that qualifies as a cash flow hedge are recorded in “Accumulated Other Comprehensive Income”, until earnings are affected by the variability of cash flows. See Note 11 of the Company’s consolidated financial statements for additional information. +Long-Term Incentive Compensation Accrual +Long-term incentive compensation is recognized as expense ratably over the requisite service period of the award which is generally three years. The Board of Directors approve target performance measures for the three year period for each of the Company’s officers and non-employee Directors. Performance measures are based on a combination of sales growth targets and return on invested capital targets. No cash awards will be made to participants if actual Company performance does not exceed the minimum target performance measures. The calculation used to determine the necessary accrual uses a combination of actual results and projected results. We believe that our estimates are based upon outcomes that are reasonably likely to occur. These estimates and assumptions are based on historical results as well as future expectations. Actual results could vary from our estimates and assumptions. +Impairment of Goodwill +In accordance with ASC 350, Goodwill and Other Intangible Assets , goodwill is not amortized but is required to be reviewed for impairment at least annually or when events or circumstances indicate that carrying value may exceed fair value. The Company is permitted the option to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the fair value of any reporting unit is less than its corresponding carrying value. If, after assessing the totality of events and circumstances, the Company concludes that it is not more likely than not that the fair value of any reporting unit is less than its corresponding carrying value then the Company is not required to take further action. However, if the Company concludes otherwise, then it is required to perform a quantitative impairment test, including computing the fair value of the reporting unit and comparing that value to its carrying value. If the fair value is less than its carrying value, a second step of the test is required to determine if recorded goodwill is impaired. In the event that goodwill is impaired, an impairment charge to earnings would become necessary. The Company also has the option to bypass the qualitative assessment for goodwill in any period and proceed directly to performing the quantitative impairment test. +27 +New and Future Accounting Pronouncements +See Note 1 to our consolidated financial statements. +Item 7A: +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Interest Rate Risk +We are subject to the risk of fluctuating interest rates in the normal course of business. Our major market risk relates to our secured debt. Our revolving credit facility is secured by substantially all of our assets. The interest rates applicable to our revolving credit facility fluctuate with the Wells Fargo Bank, N.A. prime rate and LIBOR rates. The Company did not have an outstanding balance on the line of credit as of June 28, 2014 . See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity” and Note 4 – “Long-Term Debt” to the Consolidated Financial Statements for additional information regarding our revolving credit facility. +In addition, we are subject to market risk related to our trade accounts receivable transfer program. The interest rates applicable to our trade accounts receivable transfer program fluctuate with the Wells Fargo Bank, N.A. LIBOR rates. As of June 28, 2014 , the Company had a net liability to WFB of $7.9 million. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity” and Note 5 – “Trade Accounts Receivable Transfer Program” to the Consolidated Financial Statements for additional information. +Foreign Currency Exchange Risk +A significant portion of our operations are in foreign locations. As a result, transactions occur in currencies other than the U.S. dollar. Exchange rate fluctuations among other currencies used by us would directly or indirectly affect our financial results. We currently use Mexican peso forward contracts to hedge foreign currency fluctuations for a portion of our Mexican peso denominated expenses. There was $62.4 million of foreign currency forward contracts outstanding as of June 28, 2014 . The fair value of these contracts was approximately $3.6 million . See Note 11 – “Derivative Financial Instruments” to the Consolidated Financial Statements for additional information regarding our derivative instruments. +28 +Item 8: +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Key Tronic Corporation +Spokane Valley, Washington +We have audited the accompanying consolidated balance sheets of Key Tronic Corporation as of June 28, 2014 and June 29, 2013 and the related consolidated statements of income, comprehensive income, shareholders' equity, and cash flows for each of the three years in the period ended June 28, 2014. In connection with our audits of the financial statements, we have also audited the financial statement schedule listed in the accompanying index. These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. +We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Key Tronic Corporation at June 28, 2014 and June 29, 2013, and the results of its operations and its cash flows for each of the three years in the period ended June 28, 2014 , in conformity with accounting principles generally accepted in the United States of America. +Also, in our opinion, the financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Key Tronic Corporation's internal control over financial reporting as of June 28, 2014, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated September 5, 2014 expressed an unqualified opinion thereon. +/s/ BDO USA, LLP +Spokane, Washington +September 5, 2014 +29 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED BALANCE SHEETS +(In thousands) +June 28, 2014 +June 29, 2013 +ASSETS +Current assets: +Cash and cash equivalents +$ +5,803 +$ +10,819 +Trade receivables, net +49,658 +47,009 +Inventories +55,634 +44,664 +Deferred income tax asset +935 +1,767 +Other +11,186 +7,508 +Total current assets +123,216 +111,767 +Property, plant and equipment, net +23,596 +17,911 +Other assets: +Deferred income tax asset +3,325 +3,179 +Other +2,712 +2,273 +Goodwill +1,740 +— +Other intangible assets +2,071 +— +Total other assets +9,848 +5,452 +Total assets +$ +156,660 +$ +135,130 +LIABILITIES AND SHAREHOLDERS' EQUITY +Current liabilities: +Accounts payable +$ +32,459 +$ +26,400 +Accrued compensation and vacation +7,562 +7,413 +Current portion of debt +7,853 +576 +Other +4,293 +3,551 +Total current liabilities +52,167 +37,940 +Long-term liabilities: +Deferred income tax liability +270 +1,585 +Other long-term obligations +578 +1,445 +Total long-term liabilities +848 +3,030 +Total liabilities +53,015 +40,970 +Commitments and contingencies (Note 4 and 9) +Shareholders’ equity: +Common stock, no par value—shares authorized 25,000; issued and outstanding 10,547 and 10,502 shares, respectively +44,151 +43,369 +Retained earnings +57,091 +49,478 +Accumulated other comprehensive income +2,403 +1,313 +Total shareholders’ equity +103,645 +94,160 +Total liabilities and shareholders’ equity +$ +156,660 +$ +135,130 +See accompanying notes to consolidated financial statements. +30 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF INCOME +(In thousands, except per share amounts) +Fiscal Year Ended +June 28, 2014 +June 29, 2013 +June 30, 2012 +Net sales +$ +305,394 +$ +361,033 +$ +346,475 +Cost of sales +278,540 +326,521 +316,639 +Gross profit +26,854 +34,512 +29,836 +Research, development and engineering expenses +5,586 +5,156 +4,444 +Selling, general and administrative expenses +11,964 +11,230 +11,041 +Total operating expenses +17,550 +16,386 +15,485 +Operating income +9,304 +18,126 +14,351 +Interest expense, net +81 +271 +510 +Income before income taxes +9,223 +17,855 +13,841 +Income tax provision +1,610 +5,272 +2,215 +Net income +$ +7,613 +$ +12,583 +$ +11,626 +Net income per share — Basic +$ +0.72 +$ +1.20 +$ +1.11 +Weighted average shares outstanding — Basic +10,528 +10,490 +10,447 +Net income per share — Diluted +$ +0.67 +$ +1.12 +$ +1.07 +Weighted average shares outstanding — Diluted +11,358 +11,252 +10,838 +See accompanying notes to consolidated financial statements. +31 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME +(In thousands) +Fiscal Year Ended +June 28, 2014 +June 29, 2013 +June 30, 2012 +Comprehensive income: +Net income +$ +7,613 +$ +12,583 +$ +11,626 +Other comprehensive income: +Unrealized gain (loss) on foreign exchange contracts, net of tax +1,090 +1,972 +(2,399 +) +Comprehensive income +$ +8,703 +$ +14,555 +$ +9,227 +Other comprehensive income for fiscal years 2014 , 2013 , and 2012 is reflected net of tax expense (benefit) of approximately $0.6 million , $1.0 million and $(1.2) million , respectively. +See accompanying notes to consolidated financial statements. +32 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Fiscal Year Ended +June 28, 2014 +June 29, 2013 +June 30, 2012 +Operating activities: +Net income +$ +7,613 +$ +12,583 +$ +11,626 +Adjustments to reconcile net income to cash provided by (used in) operating activities: +Depreciation and amortization +3,829 +2,965 +2,333 +Excess tax benefit from exercise of stock options +(73 +) +(103 +) +(509 +) +Provision for obsolete inventory +257 +525 +762 +Provision for warranty +35 +26 +60 +Provision for (recovery of) doubtful accounts +37 +62 +(111 +) +Loss on disposal of fixed assets +12 +27 +5 +Share-based compensation expense +659 +848 +624 +Deferred income taxes +(687 +) +2,493 +221 +Deferred compensation +— +(546 +) +— +Changes in operating assets and liabilities, net of acquisition: +Trade receivables +(2,686 +) +13,638 +(20,268 +) +Inventories +(10,450 +) +13,250 +(17,647 +) +Other assets +(3,145 +) +(2,381 +) +(1,732 +) +Accounts payable +6,059 +(16,625 +) +16,876 +Accrued compensation and vacation +149 +1,148 +1,829 +Other liabilities +(151 +) +1,372 +865 +Cash provided by (used in) operating activities +1,458 +29,282 +(5,066 +) +Investing activities: +Payment for acquisition +(6,027 +) +— +— +Purchase of property and equipment +(7,763 +) +(3,470 +) +(4,654 +) +Proceeds from sale of fixed assets +— +27 +9 +Proceeds from life insurance +— +144 +— +Cash used in investing activities +(13,790 +) +(3,299 +) +(4,645 +) +Financing activities: +Payment of financing costs +(84 +) +(75 +) +(75 +) +Principal payments on capital lease obligations +(576 +) +(729 +) +(689 +) +Borrowings under revolving credit agreement +8,212 +66,528 +114,591 +Repayment of revolving credit agreement +(8,212 +) +(81,539 +) +(105,580 +) +Proceeds from accounts receivable purchase agreement +7,853 +— +— +Excess tax benefit from exercise of stock options +73 +103 +509 +Proceeds from exercise of stock options +50 +46 +225 +Cash (used in) provided by financing activities +7,316 +(15,666 +) +8,981 +Net (decrease) increase in cash and cash equivalents +(5,016 +) +10,317 +(730 +) +Cash and cash equivalents, beginning of period +10,819 +502 +1,232 +Cash and cash equivalents, end of period +$ +5,803 +$ +10,819 +$ +502 +Supplemental cash flow information: +Interest payments +$ +90 +$ +317 +$ +443 +Income tax payments, net of refunds +$ +2,184 +$ +2,708 +$ +1,412 +See accompanying notes to consolidated financial statements. +33 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY +(In thousands) +Shares +Common +Stock +Retained +Earnings +Accumulated +Other +Comprehensive +Income (Loss) +Total +Shareholders’ +Equity +Balances, July 2, 2011 +10,399 +$ +41,014 +$ +25,269 +$ +1,740 +$ +68,023 +Net Income +— +— +11,626 +— +11,626 +Unrealized loss on foreign exchange contracts, net +— +— +— +(2,399 +) +(2,399 +) +Exercise of stock options +82 +225 +— +— +225 +Share-based compensation +— +624 +— +— +624 +Tax benefit from exercise of stock options +— +509 +— +— +509 +Balances, June 30, 2012 +10,481 +$ +42,372 +$ +36,895 +$ +(659 +) +$ +78,608 +Net Income +— +— +12,583 +— +12,583 +Unrealized gain on foreign exchange contracts, net +— +— +— +1,972 +1,972 +Exercise of stock options +21 +46 +— +— +46 +Share-based compensation +— +848 +— +— +848 +Tax benefit from exercise of stock options +— +103 +— +— +103 +Balances, June 29, 2013 +10,502 +$ +43,369 +$ +49,478 +$ +1,313 +$ +94,160 +Net income +— +— +7,613 +— +7,613 +Unrealized gain on foreign exchange contracts, net +— +— +— +1,090 +1,090 +Exercise of stock options +45 +50 +— +— +50 +Share-based compensation +— +659 +— +— +659 +Tax benefit from exercise of stock options +— +73 +— +— +73 +Balances, June 28, 2014 +10,547 +$ +44,151 +$ +57,091 +$ +2,403 +$ +103,645 +See accompanying notes to consolidated financial statements. +34 +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. SIGNIFICANT ACCOUNTING POLICIES +Business +Key Tronic Corporation and subsidiaries (the Company) is engaged in electronic manufacturing services (EMS) for original equipment manufacturers (OEMs), and also manufactures keyboards and other input devices. The Company’s headquarters are located in Spokane Valley, Washington with manufacturing operations in Spokane Valley; Juarez, Mexico; and Shanghai, China. +Principles of Consolidation +The consolidated financial statements include the Company and its wholly owned subsidiaries in Mexico and China. Intercompany balances and transactions have been eliminated in consolidation. +Reclassifications +Certain prior period reclassifications were made to conform with the current period presentation. These reclassifications had no effect on reported income, comprehensive income, cash flows, total assets, or shareholders' equity as previously reported. +Use of Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates include the allowance for doubtful receivables, the provision for obsolete and non-saleable inventories, deferred tax assets and liabilities, uncertain tax positions, valuation of goodwill, impairment of long-lived assets, medical self-funded insurance liability, long-term incentive compensation accrual, the provision for warranty costs, and the fair values of options and stock appreciation rights granted under the Company’s stock-based compensation plans. Due to uncertainties with respect to the assumptions and estimates, actual results could differ from those estimates. +Cash and Cash Equivalents +The Company considers investments with an original maturity of three months or less to be cash equivalents. Cash equivalents are carried at cost, which approximates fair value. The Company may have cash and cash equivalents at financial institutions that are in excess of federally insured limits from time to time. +Allowance for Doubtful Accounts +The Company evaluates the collectability of accounts receivable and records an allowance for doubtful accounts, which reduces the receivables to an amount that management reasonably estimates will be collected. A specific allowance is recorded against receivables considered to be impaired based on the Company’s knowledge of the financial condition of the customer. In determining the amount of the allowance, the Company considers several factors including the aging of the receivables, the current business environment, and historical experience. After all attempts to collect a receivable have failed, the receivable is written off against the allowance. +Inventories +Inventories are stated at the lower of cost or market. Cost is determined principally using the first-in, first-out (FIFO) method. Customer orders are based upon forecasted quantities of product manufactured for shipment over defined periods. Raw material inventories are purchased to fulfill these customer requirements. Within these arrangements, customer demands for products frequently change, sometimes creating excess and obsolete inventories. The Company regularly reviews raw material inventories by customer for both excess and obsolete quantities. Wherever possible, the Company attempts to recover its full cost of excess and obsolete inventories from customers or, in some cases, through other markets. When it is determined that the Company's carrying cost of such excess and obsolete inventories cannot be recovered in full, a charge is taken against income for the difference between the carrying cost and the estimated realizable amount. +Property, Plant and Equipment +Property, plant and equipment are carried at cost and depreciated using straight-line methods over the expected useful lives of the assets. Internally constructed molds and dies are depreciated over the expected useful lives of one to two years. Repairs and maintenance costs are expensed as incurred. +35 +Impairment of Goodwill +The Company records intangible assets that are acquired individually or with a group of other assets in the financial statements at acquisition. In accordance with ASC 350, Goodwill and Other Intangible Assets , goodwill is not amortized but is required to be reviewed for impairment at least annually or when events or circumstances indicate that carrying value may exceed fair value. +Impairment of Long-lived Assets +The Company, using its best estimates based on reasonable and supportable assumptions and projections, reviews assets for impairment whenever events or changes in circumstances have indicated that the carrying amount of its assets might not be recoverable. Impaired assets are reported at the lower of cost or fair value. +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. Management reviews the adequacy of this accrual quarterly based on historical analyses and anticipated product returns. +Self-funded Insurance +The Company self-funds its domestic employee health plan. The Company contracted with a separate administrative service company to supervise and administer the program and act as its representative. The Company reduces its risk under this self-funded platform by purchasing stop-loss insurance coverage for individual claims. In addition, if the aggregate annual claims amount to more than 125 percent of expected claims for the plan year this insurance will also pay those claims amounts exceeding that level. +The Company estimates its exposure for claims incurred but not paid at the end of each reporting period and uses historical claims data supplied by the Company’s broker to estimate its self-funded insurance liability. This liability is subject to a total limitation that varies based on employee enrollment and factors that are established at each annual contract renewal. Actual claims experience may differ from the Company’s estimates. Costs related to the administration of the plan and related claims are expensed as incurred. +Revenue Recognition +Sales revenue from manufacturing is recognized upon shipment of the manufactured product per contractual terms. Upon shipment, title transfers and the customer assumes risks and rewards of ownership of the product. The price to the buyer is fixed or determinable and recoverability is reasonably assured. Unless specifically stated in contractual terms, there are no formal customer acceptance requirements or further obligations related to the manufacturing services; if any such requirements exist, then sales revenue is recognized at the time when such requirements are completed and such obligations are fulfilled. Revenue is recorded net of estimated returns of manufactured product based on management’s analysis of historical returns. +Revenues and associated costs from engineering design, development services and tooling, which are performed under contract of short term durations, are recognized only after the completed performance of the service. Revenue from engineering design, development services and tooling represented approximately 3.4 percent , 2.5 percent and 2.1 percent of total revenue in fiscal years 2014 , 2013 , and 2012 , respectively. +Shipping and Handling Fees +The Company classifies costs associated with shipping and handling fees as a component of cost of goods sold. Customer billings related to shipping and handling fees are reported as revenue. +Research, Development and Engineering +Research, development and engineering expenses include unreimbursed EMS costs as well as design and engineering costs associated with the production of EMS programs. Research, development and engineering costs are expensed as incurred. +Income Taxes +Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the estimated future tax consequences and benefits attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis, as well as operating losses and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities for a change in tax rates is recognized in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amount that is more likely than not to be realized. +36 +We utilize a two-step approach to recognizing and measuring uncertain tax positions. The first step is to evaluate the tax position for recognition by determining if the weight of available evidence indicates it is more likely than not that the position will be sustained on audit, including resolution of related appeals or litigation processes, if any. The second step is to measure the tax benefit as the largest amount which is more than 50% likely of being realized upon ultimate settlement. We consider many factors when evaluating and estimating our tax positions and tax benefits, which may require periodic adjustments based on new assessments and changes in estimates and which may not accurately forecast actual outcomes. Our policy is to recognize interest and penalties related to the underpayment of income taxes as a component of income tax provision. To date, we have not incurred charges for interest or penalties in relation to the underpayment of income taxes. The tax years 1997 through the present remain open to examination by the major U.S. taxing jurisdictions to which we are subject. Refer to Note 6 for further discussions. +Derivative Instruments and Hedging Activities +The Company has entered into foreign currency forward contracts which are accounted for as cash flow hedges in accordance with ASC 815, Derivatives and Hedging . The effective portion of the gain or loss on the derivative is reported as a component of accumulated other comprehensive income (AOCI) and is reclassified into earnings in the same period in which the underlying hedged transaction affects earnings. The derivative’s effectiveness represents the change in fair value of the hedge that offsets the change in fair value of the hedged item. +The Company transacts business in Mexico and is subject to the risk of foreign currency exchange rate fluctuations. The Company enters into foreign currency forward contracts to manage the foreign currency fluctuations for Mexican peso denominated payroll, utility, tax, and accounts payable expenses. The foreign currency forward contracts have terms that are matched to the underlying transactions being hedged. As a result, these transactions fully offset the hedged risk and no ineffectiveness has been recorded. +The Company's foreign currency forward contracts potentially expose the Company to credit risk to the extent the counterparties may be unable to meet the terms of the agreement. The Company minimizes such risk by seeking high quality counterparties. The Company’s counterparties to the foreign currency forward contracts are major banking institutions. These institutions do not require collateral for the contracts, and the Company believes that the risk of the counterparties failing to meet their contractual obligations is remote. The Company does not enter into derivative instruments for trading or speculative purposes. +Earnings Per Common Share +Basic earnings per common share is computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is computed by dividing net income by the combination of other potentially dilutive weighted average common shares and the weighted average number of common shares outstanding during the period using the treasury stock method. The computation assumes the proceeds from the exercise of stock options were used to repurchase common shares at the average market price during the period. The computation of diluted earnings per common share does not assume conversion, exercise, or contingent issuance of common stock equivalent shares that would have an anti-dilutive effect on earnings per share. +Foreign Currency Transactions +The functional currency of the Company’s subsidiaries in Mexico and China is the U.S. dollar. Realized foreign currency transaction gains and losses for local currency denominated assets and liabilities are included in cost of goods sold. +Fair Value of Financial Instruments +The carrying values of cash and cash equivalents, accounts receivable and current liabilities reflected on the balance sheets at June 28, 2014 and June 29, 2013 , reasonably approximate their fair value. As of June 28, 2014 and June 29, 2013 , the Company did not have an outstanding balance on the line of credit. +Share-based Compensation +The Company’s incentive plan may provide for equity and liability awards to employees in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, stock units, performance shares, performance units, and other stock-based or cash-based awards. Compensation cost is recognized on a straight-line basis over the requisite employee service period, which is generally the vesting period, and is included in cost of goods sold and selling, general, and administrative expenses. +37 +Newly Adopted and Recent Accounting Pronouncements +In December 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update 2011-11 (ASU 2011-11), Disclosures about Offsetting Assets and Liabilities . The amendments in this Update will enhance disclosures required by U.S. GAAP by requiring improved information about financial instruments and derivative instruments that are either (1) offset in accordance with either Section 210-20-45 or Section 815-10-45 or (2) subject to an enforceable master netting arrangement or similar agreement. The amendments are effective for fiscal years beginning after January 1, 2013 and for interim periods within those fiscal years. The amendments of ASU 2011-11 did not have a material impact on the Company’s consolidated financial statements. +In January 2013, the FASB issued Accounting Standards Update 2013-01 (ASU 2013-01), Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities . The main objective in developing this Update is to address implementation issues about the scope of Accounting Standards Update No. 2011-11, Balance Sheet Topic 210: Disclosures about Offsetting Assets and Liabilities. The amendments are effective for fiscal years beginning on or after January 1, 2013, and interim periods within those annual periods. The amendments of ASU 2013-01 did not have a material impact on the Company’s consolidated financial statements. +In February 2013, the FASB issued Accounting Standards Update 2013-02 (ASU 2013-02), Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income . The objective of this Update is to improve the reporting of reclassifications out of accumulated other comprehensive income. The amendments in this Update seek to attain that objective by requiring an entity to report the effect of significant reclassifications out of accumulated other comprehensive income on the respective line items in net income if the amount being reclassified is required under U.S. GAAP to be reclassified in its entirety to net income. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income in the same reporting period, an entity is required to cross-reference other disclosures required under U.S. GAAP that provide additional detail about those amounts. The amendments are effective prospectively for annual reporting periods beginning after December 15, 2012 and interim periods within those annual periods. The amendments of ASU 2013-02 did not have a material impact on the Company’s consolidated financial statements. +In July 2013, the FASB issued Accounting Standards Update 2013-11 (ASU 2013-11), Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists a consensus of the FASB Emerging Issues Task Force . The objective of this Update is to eliminate the diversities that exist in financial statement presentation. The amendments aim at attaining this objective by giving explicit guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss carryforward, a similar tax loss, or a tax credit carryforward exists. The amendments in this Update are effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The amendments of ASU 2013-11 did not have a material impact on the Company's consolidated financial statements. +In May 2014, the FASB issued Accounting Standards Update 2014-09 (ASU 2014-09), Revenue from Contracts with Customers. The guidance in this Update affects any entity that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (for example, insurance contracts or lease contracts). The standard's core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In doing so, companies will need to use more judgment and make more estimates than under current guidance. This may include identifying performance obligations in the contract, estimating the amount of variable consideration to include in the transaction price and allocating the transaction price to each separate performance obligation. The amendments in this Update are effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. Early adoption is not permitted. Companies have the option of using either a full or modified retrospective approach in applying this standard. The Company is in the process of assessing the impact of ASU 2014-09 on its consolidated financial statements. +Management has assessed the potential impact of recently issued, but not yet effective, accounting standards and determined that the provisions are either not applicable to the Company, or are not anticipated to have a material impact on the consolidated financial statements. +Fiscal Year +The Company operates on a 52/53 week fiscal year. Fiscal years end on the Saturday nearest June 30. As such, fiscal years 2014 , 2013 , and 2012 , ended on June 28, 2014 , June 29, 2013 , and June 30, 2012 , respectively and each year was a 52 week year. +38 +2. INVENTORIES +The components of inventories consist of the following (in thousands): +June 28, 2014 +June 29, 2013 +Finished goods +$ +5,826 +$ +7,097 +Work-in-process +7,068 +5,098 +Raw materials and supplies +42,740 +32,469 +$ +55,634 +$ +44,664 +3. PROPERTY, PLANT AND EQUIPMENT +Property, plant and equipment consists of the following: +Life +June 28, 2014 +June 29, 2013 +(in years) +(in thousands) +Land +— +$ +2,670 +$ +2,629 +Buildings and improvements +3 to 30 +19,839 +18,919 +Equipment +1 to 10 +44,257 +37,317 +Furniture and fixtures +3 to 5 +3,029 +2,730 +69,795 +61,595 +Accumulated depreciation +(46,199 +) +(43,684 +) +$ +23,596 +$ +17,911 +4. LONG-TERM DEBT +Note Payable - Bank +On October 15, 2010, the Company entered into an amended credit agreement with Wells Fargo Bank, N.A. thereby increasing its revolving line of credit for up to $30.0 million . On November 8, 2013, the Company entered into a third amendment to the credit agreement extending the term to October 15, 2018. The agreement specifies that the proceeds of the revolving line of credit be used primarily for working capital and general corporate purposes of the Company and its subsidiaries. Borrowings under this revolving line of credit bear interest at either a “Base Rate” or a “Fixed Rate,” as elected by the Company. The base rate is the higher of the Wells Fargo Bank prime rate, daily one month London Interbank Offered Rate (LIBOR) plus 1.5% , or the Federal Funds rate plus 1.5% . The fixed rate is LIBOR plus 1.75% , LIBOR plus 2.0% or LIBOR plus 2.25% depending on the level of the Company’s trailing four quarters Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA). The revolving line of credit is secured by substantially all of the assets of the Company. +The Company must comply with certain financial covenants, including a cash flow leverage ratio and an asset coverage ratio. The credit agreement requires the Company to maintain a minimum profit threshold, limits the maximum lease expenditures and restricts the Company from declaring or paying dividends in cash or stock. The Company is in compliance with all financial covenants for all periods presented. +As of June 28, 2014 , the Company had availability to borrow $30.0 million under the line of credit. The Company did not have an outstanding balance on the line of credit as of June 28, 2014 or June 29, 2013 . +5. TRADE ACCOUNTS RECEIVABLE PURCHASE PROGRAM +On June 25, 2014, the Company entered into an Account Purchase Agreement with Wells Fargo Bank, N.A. ("WFB") which provides that the Company may sell and assign to WFB and WFB may purchase from Company the accounts receivable of certain Company customers in a maximum aggregate amount of $50.0 million . The initial term of the agreement is 36 months with successive 12 month renewal terms. For the year ended June 28, 2014, total accounts receivables transferred was approximately $9.0 million . The receivables that were transferred remain on our consolidated balance sheet and the cash received was reflected as cash provided by financing activities in the consolidated statements of cash flows. As of June 28, 2014, the Company's net liability to WFB for accounts receivables transferred was $7.9 million classified as current portion of debt. +39 +6. INCOME TAXES +Income tax provision consists of the following: +Fiscal Year Ended +June 28, 2014 +June 29, 2013 +June 30, 2012 +(in thousands) +Current income tax provision: +United States +$ +1,220 +$ +1,729 +$ +1,483 +Foreign +1,017 +1,050 +511 +2,237 +2,779 +1,994 +Deferred income tax provision: +United States +1,566 +2,049 +(85 +) +Foreign +(2,193 +) +444 +306 +(627 +) +2,493 +221 +Total income tax provision +$ +1,610 +$ +5,272 +$ +2,215 +The Company has total tax credit carryforwards of approximately $9.3 million at June 28, 2014 . Included in total tax credits carryforwards is approximately $5.1 million in research and development (R&D) tax credits. +Management also has reviewed its other deferred tax assets for purposes of determining whether or not a valuation allowance may be required. A valuation allowance against these deferred tax assets is required if it is more likely than not that some of the deferred tax assets will not be realized. Based on the Company’s increased profitability and estimated future repatriations from foreign subsidiaries, it has been determined that it is more likely than not that the deferred tax assets will be realized. +Management has reviewed and updated as necessary estimates of future repatriations of the undistributed earnings of its foreign subsidiaries. Based on this analysis, management expects to repatriate a portion of the foreign undistributed earnings based on increased sales growth driving additional U.S. capital requirements, cash requirements for potential acquisitions and to potentially implement certain tax strategies. No foreign earnings were repatriated from either foreign subsidiary during fiscal 2014 or 2013 . The Company currently estimates that future repatriations from foreign subsidiaries will approximate $10.5 million . As such, as earnings are recognized in the United States, the Company would be subject to U.S. federal and state income taxes and potential withholding taxes estimated to be approximately $4.9 million . Both the domestic tax and estimated withholding tax have been recorded as part of deferred taxes as of June 28, 2014 . Included in tax credits is $3.4 million related to foreign tax credits that can be used to offset future domestic income tax. All other unremitted foreign earnings are expected to remain permanently reinvested for planned fixed asset purchases in foreign locations. +The Company has not provided for U.S. income taxes or foreign withholding taxes on approximately $13.3 million of earnings from foreign subsidiaries which are permanently reinvested outside the U.S. The unrecognized net tax provision, after netting U.S. federal and state income tax and any related foreign tax credits, would be approximately $2.8 million associated with these earnings. +In recent years, the Company's wholly owned foreign subsidiary in Mexico has been subject to a Mexican business flat tax called Impuesto Empresarial a Tasa Unica (IETU). However, effective January 1, 2014, IETU was repealed as part of a larger reform of the Mexican tax system and the impact of the repeal was recognized as a discrete tax benefit of $1.5 million during the second quarter of fiscal year 2014. The Company is now subject to the general Mexican tax regime (ISR). The effects of IETU and ISR have been included in the effective tax rate for the year ended June 28, 2014 . +40 +The Company’s effective tax rate differs from the federal tax rate as follows: +Fiscal Year Ended +June 28, 2014 +June 29, 2013 +June 30, 2012 +(in thousands) +Federal income tax provision at statutory rates +$ +3,136 +$ +6,071 +$ +4,706 +Foreign tax rate differences +(439 +) +(625 +) +(361 +) +Effect of income tax credits +(202 +) +(340 +) +(2,104 +) +Effect of repatriation of foreign earnings, net +287 +188 +— +Other +330 +235 +436 +Change in valuation allowance +— +(257 +) +(462 +) +Effect of IETU repeal +(1,502 +) +— +— +Income tax provision +$ +1,610 +$ +5,272 +$ +2,215 +The domestic and foreign components of income before income taxes were: +Fiscal Year Ended +June 28, 2014 +June 29, 2013 +June 30, 2012 +(in thousands) +Domestic +$ +4,687 +$ +12,863 +$ +10,666 +Foreign +4,536 +4,992 +3,175 +Income before income taxes +$ +9,223 +$ +17,855 +$ +13,841 +Deferred income tax assets and liabilities consist of the following at: +June 28, 2014 +June 29, 2013 +(in thousands) +Deferred tax assets: +Tax credit carryforwards, net +$ +2,795 +$ +3,414 +Foreign subsidiaries – future tax credits +2,767 +3,389 +Inventory +— +131 +Accruals +2,855 +1,925 +Fixed Assets +602 +755 +Other +75 +185 +Deferred income tax assets +$ +9,094 +$ +9,799 +Deferred tax liabilities: +Foreign subsidiaries – unremitted earnings +(4,240 +) +(4,115 +) +Fixed assets +— +(1,617 +) +Mark-to-market adjustments +(1,237 +) +(678 +) +Other +(185 +) +(28 +) +Deferred income tax liabilities +$ +(5,662 +) +$ +(6,438 +) +Net deferred income tax assets +$ +3,432 +$ +3,361 +Balance sheet caption reported in: +Current deferred income tax asset +$ +935 +$ +1,767 +Long-term deferred income tax asset +3,325 +3,179 +Current deferred income tax liability (classified as Other current liabilities) +(558 +) +— +Long-term deferred income tax liability +(270 +) +(1,585 +) +Net deferred income tax asset +$ +3,432 +$ +3,361 +The Company has R&D tax credits that approximate $5.1 million that have 20 year carryforwards before expiring. The Company’s R&D tax credits expire in various fiscal years from 2019 to 2033. The Company also has alternative minimum tax credits, which do not expire, approximating $726,000 . +41 +Uncertain Tax Positions +As of June 28, 2014 , the Company had unrecognized tax benefits of $3.1 million related to its gross R&D tax credits. The unrecognized tax benefits relate to certain R&D tax credits generated from 1999 to 2013. +A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: +Fiscal Year Ended +June 28, 2014 +June 29, 2013 +June 30, 2012 +(in thousands) +Beginning Balance +$ +3,031 +$ +3,003 +$ +781 +Additions based on tax positions related to the current year +41 +97 +2,222 +Reductions for tax provisions of the prior years +— +(69 +) +— +Ending Balance +$ +3,072 +$ +3,031 +$ +3,003 +The increase from the prior year is due to additional R&D credits that were recorded in 2014 as discussed above. Management does not anticipate any material changes to this amount during the next 12 months. +The Company recognizes interest accrued related to unrecognized tax benefits and penalties in its income tax provision. The Company has not recognized any interest or penalties in the fiscal years presented in these financial statements. The Company is subject to income tax in the U.S. federal jurisdiction, Mexico and China. Certain years remain subject to examination but there are currently no ongoing exams in any taxing jurisdictions. +7. EARNINGS PER SHARE +Basic earnings per share (EPS) is calculated by dividing net income (the numerator) by the weighted-average number of common shares outstanding (the denominator) during the period. Diluted EPS is computed by including both the weighted-average number of shares outstanding and any dilutive common share equivalents in the denominator. The following table presents a reconciliation of the denominator and the number of antidilutive common share awards that were not included in the diluted earnings per share calculation. These antidilutive securities occur when equity awards outstanding have an option price greater than the average market price for the period: +Fiscal Year Ended +(in thousands, except per share information) +June 28, 2014 +June 29, 2013 +June 30, 2012 +Net income +$ +7,613 +$ +12,583 +$ +11,626 +Weighted average shares outstanding– basic +10,528 +10,490 +10,447 +Effect of dilutive common stock options and awards +830 +762 +391 +Weighted average shares outstanding – diluted +11,358 +11,252 +10,838 +Earnings per share – basic +$ +0.72 +$ +1.20 +$ +1.11 +Earnings per share – diluted +$ +0.67 +$ +1.12 +$ +1.07 +Antidilutive options not included in diluted earnings per share +208 +— +— +8. STOCK OPTION AND BENEFIT PLANS +The Company’s incentive plan provides for equity and liability awards to employees and non-employee directors in the form of stock options, stock appreciation rights (SARs), restricted stock, restricted stock units, stock awards, stock units, performance shares, performance units, and other stock-based or cash-based awards. Compensation cost is recognized on a straight-line basis over the requisite employee service period, which is generally the vesting period, and is recorded as employee compensation expense in cost of goods sold and selling general and administrative expenses. Share-based compensation is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on historical experience and future expectations. +In addition to service conditions, these SARs contain a performance condition. The additional performance condition is based upon the achievement of Return on Invested Capital (ROIC) goals relative to a peer group. All awards with performance conditions are measured over the vesting period and are charged to compensation expense over the requisite service period based on the number of shares expected to vest. The SARs cliff vest after a three-year period from date of grant and expire five years from date of grant. +42 +On July 31, 2013, the Company granted 213,166 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $11.34 and a grant date fair value of $4.67 , as of June 28, 2014 , 208,166 remain outstanding. The grant date fair value for the awards granted during fiscal year 2014 were estimated using the Black Scholes option valuation method with the following weighted average assumptions as July 31, 2013: +Fiscal Year 2014 +July 31, 2013 +Expected dividend yield +—% +Risk – free interest rate +1.16% +Expected volatility +52.12% +Expected life +4.00 +On July 25, 2012, the Company granted 210,666 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $7.44 and a grant date fair value of $3.71 , as of June 28, 2014 , 203,166 remain outstanding. The grant date fair value for the awards granted during fiscal year 2013 were estimated using the Black Scholes option valuation method with the following weighted average assumptions as July 25, 2012: +Fiscal Year 2013 +July 25, 2012 +Expected dividend yield +—% +Risk – free interest rate +0.46% +Expected volatility +66.50% +Expected life +4.00 +On July 27, 2011, the Company granted 184,666 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $4.40 and a grant date weighted average fair market value of $2.20 , as of June 28, 2014 , 172,666 remain outstanding. On January 26, 2012, the Company granted 32,000 SARs under the 2010 Incentive Plan to certain key employees at a strike price of $6.30 and grant date weighted average fair market value of $3.08 , as of June 28, 2014 , 25,000 remain outstanding. The grant date fair value for the awards granted during fiscal year 2012 were estimated using the Black Scholes option valuation method with the following weighted average assumptions at each of the respective grant dates: +Fiscal Year 2012 +January 26, 2012 +July 27, 2011 +Expected dividend yield +—% +—% +Risk – free interest rate +0.52% +1.16% +Expected volatility +64.90% +65.50% +Expected life +4.00 +4.00 +Share-based compensation expense is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on the Company’s historical experience and future expectations. This forfeiture rate will be revised, if necessary, in subsequent periods if actual forfeitures differ from the amount estimated. Share-based compensation expense for fiscal years ended June 28, 2014 , June 29, 2013 and June 30, 2012 was $0.7 million , $0.8 million and $0.6 million , respectively. +The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options, which differ significantly from the SARs, as traded options have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions, particularly for the expected term and expected stock price volatility. Changes in these assumptions can materially affect the fair value estimates. +The intrinsic value for options exercised in fiscal years 2014 , 2013 and 2012 was $0.4 million , $0.2 million and $0.3 million , respectively. +As of June 28, 2014 , total unrecognized compensation expense related to nonvested share-based compensation arrangements was approximately $0.9 million . This expense is expected to be recognized over a weighted-average period of 1.77 years . +43 +The following table summarizes the Company's stock options and SARs activity for all plans from June 29, 2013 through June 28, 2014 : +Shares +Available +For Grant +Options/SARs +Outstanding +Aggregate +Intrinsic +Value (in +thousands) +Weighted +Average +Exercise +Price +Weighted +Average +Remaining +Contractual +Life (in +years) +Balances, June 29, 2013 +263,168 +961,692 +$ +4,309 +$ +5.87 +2.6 +Shares authorized +— +— +— +— +— +Options/SARs granted +(213,166 +) +213,166 +— +11.34 +— +Options forfeited +19,000 +(19,000 +) +— +6.93 +— +Options exercised +— +(89,930 +) +406 +5.14 +— +Balances, June 28, 2014 +69,002 +1,065,928 +$ +4,096 +$ +7.01 +1.8 +Exercisable at June 28, 2014 +456,930 +$ +2,679 +$ +5.86 +0.9 +Additional information regarding stock options and SARs outstanding and exercisable as of June 28, 2014 , is as follows: +Range of +Exercise Prices +Number Outstanding +Weighted Avg. +Remaining +Contractual Life (yrs.) +Weighted Avg. +Exercise Price +Number +Exercisable +Weighted +Avg. Exercise +Price +$3.40 – $5.40 +177,596 +0.1 +$ +4.37 +4,930 +$ +3.40 +5.41 – 7.41 +477,000 +1.0 +5.91 +452,000 +5.89 +7.42 – 9.42 +203,166 +3.1 +7.44 +— +— +9.43 – 11.34 +208,166 +4.1 +11.34 +— +— +$3.40 to $11.34 +1,065,928 +1.8 +$ +7.01 +456,930 +$ +5.86 +The Company also has a defined contribution plan (401(k)) available to U.S. employees who have attained age 21. The Company contributes an amount equal to 100% of the employee’s contribution on the first 3% of the employee’s compensation and an additional 50% of the employee’s contribution on the following 2% of the employee’s compensation. Company contributions to the plan were approximately $0.6 million , $0.5 million , and $0.5 million during fiscal years 2014 , 2013 , and 2012 , respectively. +9. COMMITMENTS AND CONTINGENCIES +Leases : As of June 28, 2014 , the Company did not have any property and equipment financed under capital leases. The Company had equipment financed through capital leases with a net book value of $1.7 million and $1.9 million during fiscal years 2013 and 2012 , respectively. The related depreciation expense was $0.3 million for fiscal years 2014, 2013 and 2012. As of June 28, 2014 , the Company has operating leases for certain equipment and production facilities, which expire at various dates during the next ten years . +Future minimum payments under non-cancelable operating leases with initial or remaining terms of one year or more at June 28, 2014 , are summarized as follows (in thousands): +Fiscal Years Ending +Operating Leases +2015 +$ +2,806 +2016 +1,776 +2017 +900 +2018 +755 +2019 +757 +Thereafter +1,175 +Total minimum lease payments +$ +8,169 +On September 3, 2014, the Company acquired CDR Manufacturing resulting in an increase in our operating leases; however, the amount is yet to be determined. +Rental expense under operating leases was approximately $1.8 million , $1.5 million , and $1.5 million during fiscal years 2014 , 2013 , and 2012 , respectively. +44 +Warranty Costs : The Company provides warranties on certain product sales, and allowances for estimated warranty costs are recorded during the period of sale. The determination of such allowances requires the Company to make estimates of product return rates and expected costs to repair or to replace the products under warranty. The Company establishes warranty reserves based on historical warranty costs for each product line combined with liability estimates based on the prior twelve months’ sales activities. As of June 28, 2014 , the reserve for warranty costs was approximately $11,000 . +If actual return rates and/or repair and replacement costs differ significantly from estimates, adjustments to recognize additional cost of sales may be required in future periods. Warranty expense for fiscal years 2014 , 2013 and 2012 was related to workmanship claims on keyboards and certain EMS products. +Litigation : The Company is party to certain lawsuits or claims in the ordinary course of business. The Company does not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on the financial position, results of operations or cash flow of the Company. +Indemnification Rights : Under the Company’s bylaws, the Company’s directors and officers have certain rights to indemnification by the Company against certain liabilities that may arise by reason of their status or service as directors or officers. The Company maintains director and officer insurance, which may cover certain liabilities arising from its obligation to indemnify its directors and officers and former directors in certain circumstances. +10. FAIR VALUE MEASUREMENTS +The Company has adopted ASC 820, Fair Value Measurements, which defines fair value, establishes a framework for assets and liabilities being measured and reported at fair value and expands disclosures about fair value measurements. There are three levels of fair value hierarchy inputs used to value assets and liabilities which include: Level 1 – inputs are quoted market prices for identical assets or liabilities; Level 2 – inputs other than quoted market prices included in Level 1 that are observable for the asset or liability, either directly or indirectly; and Level 3 – inputs are unobservable inputs for the asset or liability. There have been no changes in the fair value methodologies used at June 28, 2014 and June 29, 2013 . +The following table summarizes the Company’s financial assets and liabilities (only those required to be measured at fair value on a recurring basis) at fair value as of June 28, 2014 and June 29, 2013 (in thousands): +June 28, 2014 +Level 1 +Level 2 +Level 3 +Total +Fair Value +Financial Assets: +Foreign currency forward contracts +$ +— +$ +3,641 +$ +— +$ +3,641 +June 29, 2013 +Level 1 +Level 2 +Level 3 +Total +Fair Value +Financial Assets: +Foreign currency forward contracts +$ +— +$ +2,429 +$ +— +$ +2,429 +Financial Liabilities: +Foreign currency forward contracts +$ +— +$ +(434 +) +$ +— +$ +(434 +) +The Company currently has forward contracts to hedge known future cash outflows for expenses denominated in the Mexican peso. These contracts are measured on a recurring basis based on the foreign currency spot rates and forward rates quoted by banks or foreign currency dealers. These contracts are marked to market using level 2 input criteria every period with the unrealized gain or loss, net of tax, reported as a component of shareholders’ equity in accumulated other comprehensive income, as they qualify for hedge accounting. +45 +The carrying values of cash and cash equivalents, accounts receivable and current liabilities reflected on the balance sheets at June 28, 2014 and June 29, 2013 , reasonably approximate their fair value. The Company’s long-term debt primarily consists of a revolving line of credit. Borrowings under this revolving line of credit bear interest at either a “Base Rate” or a “Fixed Rate,” as elected by the Company. The base rate is the higher of the Wells Fargo Bank prime rate, daily one month London Interbank Offered Rate (LIBOR) plus 1.5% , or the Federal Funds rate plus 1.5% . The fixed rate is LIBOR plus 1.75% , LIBOR plus 2.0% or LIBOR plus 2.25% depending on the level of the Company’s trailing four quarters Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA). Each of these rates is a variable floating rate dependent upon current market conditions and the Company’s current credit risk. As a result of the determinable market rate for our revolving credit debt it is classified within Level 2 of the fair value hierarchy. The Company did not have an outstanding balance on the line of credit as of June 28, 2014 or June 29, 2013 . Additionally, the Company has current debt related to its accounts receivable purchase program. Borrowings under this purchase program bear interest at daily one month LIBOR plus 2.25% . As a result of the determinable market rate for our accounts receivable purchase program it is classified within Level 2 of the fair value hierarchy. As of June 28, 2014, the Company had a net liability to WFB of $7.9 million , which reasonably approximates its fair value. +11. DERIVATIVE FINANCIAL INSTRUMENTS +As of June 28, 2014 , the Company had outstanding foreign currency forward contracts of $62.4 million . These contract maturity dates extend through June 2017 . As of June 28, 2014 , the net amount of existing gains expected to be reclassified into earnings within the next 12 months is $1.4 million . During the fiscal year ended June 28, 2014 , the Company entered into $15.2 million of foreign currency forward contracts and settled $22.5 million of such contracts. During the fiscal year ended June 29, 2013 , the Company entered into $34.7 million of foreign currency forward contracts and settled $22.7 million of such contracts. During the fiscal year ended June 30, 2012 , the Company entered into $41.1 million of foreign currency forward contracts and settled $21.2 million of such contracts. +Subsequent to June 28, 2014 , the Company entered into $5.4 million of additional foreign currency forward contracts that extended our hedge position through September 2017. +The following table summarizes the fair value of derivative instruments in the Consolidated Balance Sheets as of June 28, 2014 and June 29, 2013 (in thousands): +June 28, 2014 +June 29, 2013 +Derivatives Designated as Hedging Instruments +Balance Sheet Location +Fair Value +Fair Value +Foreign currency forward contracts +Other current assets +$ +2,034 +$ +760 +Foreign currency forward contracts +Other long-term assets +$ +1,607 +$ +1,669 +Foreign currency forward contracts +Other current liabilities +$ +— +$ +(145 +) +Foreign currency forward contracts +Other long-term liabilities +$ +— +$ +(289 +) +The following table summarizes the gain (loss) of derivative instruments on the Consolidated Statement of Operations for the fiscal year 2014 (in thousands): +Derivatives Designated as Hedging Instruments +AOCI Balance +as of +June 29, 2013 +Effective +Portion +Recorded In +AOCI +Effective Portion +Reclassified From +AOCI Into Cost +of Sales +AOCI Balance +as of +June 28, 2014 +Settled foreign currency forward contracts +$ +404 +$ +421 +$ +(825 +) +$ +— +Unsettled foreign currency forward contracts +909 +1,494 +— +2,403 +Total +$ +1,313 +$ +1,915 +$ +(825 +) +$ +2,403 +The following table summarizes the gain (loss) of derivative instruments on the Consolidated Statement of Operations for the fiscal year 2013 (in thousands): +Derivatives Designated as Hedging Instruments +AOCI Balance +as of +June 30, 2012 +Effective +Portion +Recorded In +AOCI +Effective Portion +Reclassified From +AOCI Into +Cost of Sales +AOCI Balance +as of +June 29, 2013 +Settled foreign currency forward contracts +$ +(479 +) +$ +1,060 +$ +(581 +) +$ +— +Unsettled foreign currency forward contracts +(180 +) +1,493 +— +1,313 +Total +$ +(659 +) +$ +2,553 +$ +(581 +) +$ +1,313 +46 +The following table summarizes the gain (loss) of derivative instruments on the Consolidated Statement of Operations for the fiscal year 2012 (in thousands): +Derivatives Designated as Hedging Instruments +AOCI Balance +as of +July 2, 2011 +Effective +Portion +Recorded In +AOCI +Effective Portion +Reclassified From +AOCI Into +Cost of Sales +AOCI Balance +as of +June 30, 2012 +Settled foreign currency forward contracts +$ +1,035 +$ +(1,119 +) +$ +84 +$ +— +Unsettled foreign currency forward contracts +705 +(1,364 +) +— +(659 +) +Total +$ +1,740 +$ +(2,483 +) +$ +84 +$ +(659 +) +As of June 28, 2014 , the Company does not have any foreign exchange contracts with credit-risk-related contingent features. The Company is subject to the risk of fluctuating interest rates from our line of credit and foreign currency risk resulting from our China operations. The Company does not currently manage these risk exposures by using derivative instruments. +12. ENTERPRISE-WIDE DISCLOSURES +Operating segments are defined as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker, or decision making group, in deciding how to allocate resources and in assessing performance. The Company’s chief operating decision maker is its Chief Executive Officer. As of June 28, 2014 , the Company operates and internally manages a single operating segment, Electronics Manufacturing Services. +Products and Services +Of the revenues for the years ended June 28, 2014 , June 29, 2013 , and June 30, 2012 , EMS sales and services were $303.1 million , $358.6 million and $343.7 million , respectively. Keyboard sales for the years ended June 28, 2014 , June 29, 2013 , and June 30, 2012 were $2.3 million , $2.4 million and $2.8 million , respectively. +Geographic Areas +Net sales and long-lived assets (property, plant, and equipment) by geographic area as of and for the years ended June 28, 2014 , June 29, 2013 and June 30, 2012 are summarized in the following table. Net sales set forth below are based on the shipping destination. Long-lived assets information is based on the physical location of the asset. +Fiscal Year Ended +(in thousands) +2014 +2013 +2012 +Geographic net sales: +Domestic (U.S.) +$ +197,700 +$ +246,059 +$ +205,668 +Foreign +107,694 +114,974 +140,807 +Total +$ +305,394 +$ +361,033 +$ +346,475 +Long-lived assets: +United States +$ +2,888 +$ +2,045 +$ +1,660 +Mexico +19,577 +14,539 +14,111 +China +1,131 +1,327 +1,535 +Total +$ +23,596 +$ +17,911 +$ +17,306 +Percentage of net sales made to customers located in the following countries: +Fiscal Year Ended +2014 +2013 +2012 +United States +64.7% +68.2% +59.4% +Canada +16.5 +22.4 +28.8 +Other foreign countries (a) +18.8 +9.4 +11.8 +Total +100.0% +100.0% +100.0% +(a) No other individual foreign country accounted for 10% or more of the foreign sales in fiscal years 2014, 2013, or 2012. +47 +Significant Customers +The percentage of net sales to and trade accounts receivables from significant customers were as follows: +Percentage of Net +Sales Fiscal Year +Percentage of +Trade Accounts Receivable +Fiscal Year +2014 +2013 +2012 +2014 +2013 +Customer A +20% +19% +16% +24% +24% +Customer B +15% +23% +29% +12% +21% +Customer C +15% +21% +17% +14% +13% +There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +13. QUARTERLY FINANCIAL DATA (Unaudited) +Fiscal Year Ended June 28, 2014 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +(in thousands, except per share amounts) +Net sales +$ +77,974 +$ +78,250 +$ +77,043 +$ +72,127 +Gross profit +6,622 +6,950 +6,607 +6,675 +Income before income taxes +2,438 +2,350 +2,196 +2,239 +Net income +1,705 +3,114 +1,414 +1,380 +Earnings per common share-basic +$ +0.16 +$ +0.30 +$ +0.13 +$ +0.13 +Earnings per common share-diluted +$ +0.15 +$ +0.27 +$ +0.12 +$ +0.12 +Weighted average shares outstanding +Basic +10,507 +10,530 +10,533 +10,541 +Diluted +11,336 +11,354 +11,350 +11,346 +Fiscal Year Ended June 29, 2013 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +(in thousands, except per share amounts) +Net sales +$ +97,508 +$ +94,567 +$ +84,343 +$ +84,615 +Gross profit +9,475 +9,496 +7,860 +7,681 +Income before income taxes +5,580 +5,240 +3,555 +3,480 +Net income +3,744 +3,579 +2,863 +2,397 +Earnings per common share-basic +$ +0.36 +$ +0.34 +$ +0.27 +$ +0.23 +Earnings per common share-diluted +$ +0.33 +$ +0.32 +$ +0.25 +$ +0.21 +Weighted average shares outstanding +Basic +10,846 +10,489 +10,489 +10,495 +Diluted +11,210 +11,303 +11,319 +11,323 +48 +14. ACQUISITION +On July 1, 2013, the Company acquired substantially all of the assets of Sabre Assembly & Manufacturing Co. of Texas (“Sabre”), a sheet metal fabrication company with facilities located in Juarez, Mexico. The acquisition of Sabre enables the Company to offer metal fabrication directly to its customers, in combination with plastic molding, PCB assembly, complete product assembly, design engineering and testing engineering services. Under the terms of the transaction, the assets acquired included manufacturing equipment, inventory, customer relationships and non-compete agreements with key employees. No debt or liabilities were assumed. The total cash payment of $6.0 million was funded through existing cash. The Company incurred approximately $50,000 of costs related to due diligence and closing this acquisition. +The following table summarizes the fair values of the assets acquired as of the date of acquisition (in thousands): +Fair Values +At July 1, 2013 +Current Assets +$ +777 +Fixed Assets +1,168 +Non-Compete Agreements +372 +Customer Relationships +1,970 +Goodwill +1,740 +Fair value of assets acquired +$ +6,027 +The Sabre acquisition is accounted for using the acquisition method of accounting whereby the total purchase price is allocated to tangible and intangible assets and liabilities based on their fair values on the date of acquisition. The Company determines the purchase price allocations on the acquisition based on estimates of the fair values of the assets acquired. Goodwill recorded in connection with the above acquisition is primarily attributable to the synergies expected to arise after the Company’s acquisition of the business and the assembled workforce of the acquired business. +15. GOODWILL AND OTHER INTANGIBLE ASSETS +In accordance with ASC 350 Intangibles – Goodwill and Other Intangibles , goodwill is not amortized, but must be analyzed for impairment at least annually. The Company recorded goodwill in connection with the Sabre acquisition resulting primarily from the synergies that resulted from the Company’s acquisition and the assembled workforce of Sabre. The goodwill is not amortized for financial accounting purposes but is deductible for tax purposes over a 15-year period. +On March 30, 2014, the Company completed its annual impairment test. The Company concluded that it is more likely than not that the fair value of goodwill is greater than the carrying value. As of June 28, 2014 , goodwill was recorded at $1.7 million . As of June 29, 2013 , there was no goodwill recorded in the Company’s Consolidated Balance Sheet. +The components of acquired intangible assets are as follows (in thousands): +June 28, 2014 +Amortization Period +in Years +Gross Carrying +Amount +Accumulated +Amortization +Net Carrying +Amount +Intangible assets: +Non-Compete Agreements +5 +$ +372 +$ +(74 +) +$ +298 +Customer Relationships +10 +1,970 +(197 +) +1,773 +Total +$ +2,342 +$ +(271 +) +$ +2,071 +Amortization expense for the year ended June 28, 2014 was approximately $0.3 million . No amortization expense related to intangible assets was recorded for the fiscal years ended June 29, 2013 or June 30, 2012. +49 +Aggregate amortization expense relative to existing intangible assets by fiscal year is currently estimated to be as follows (in thousands): +Fiscal Years Ending +Amount +2015 +$ +271 +2016 +271 +2017 +271 +2018 +271 +2019 +197 +Thereafter +790 +Total amortization expense +$ +2,071 +16. SUBSEQUENT EVENT +On September 3, 2014, the Company acquired CDR Manufacturing, Inc. (dba Ayrshire Electronics), who provide printed circuit board assembly and other EMS services to a diversified customer base, including a number of large multi-national companies. The total cash payment of $46.9 million was funded through a term loan and our existing line of credit. The Company will incur costs related to due diligence and closing this acquisition that are yet to be determined. The Company has not yet determined the initial purchase price allocation in connection with the CDR Manufacturing acquisition. +50 +Item 9: +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES +None +Item 9A: +CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +It is the responsibility of our management to establish, maintain, and monitor disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 are recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Additionally, these disclosure controls include controls and procedures that are designed to accumulate and communicate the information required to be disclosed to our Company’s Chief Executive Officer and Chief Financial Officer, allowing for timely decisions regarding required disclosures. As of the end of the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(f). Based on our assessment, we believe that as of June 28, 2014 , the Company’s disclosure controls and procedures are effective based on that criteria. +Management’s Report on Internal Control over Financial Reporting +Our management has the responsibility to establish and maintain adequate internal controls over our financial reporting, as defined in Rule 13a-15(f) under the Securities and Exchange Act of 1934. Our internal controls are designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our external financial statements in accordance with generally accepted accounting principles (GAAP). +Due to inherent limitations of any internal control system, management acknowledges that there are limitations as to the effectiveness of internal controls over financial reporting and therefore recognize that only reasonable assurance can be gained from any internal control system. Accordingly, our internal control system may not detect or prevent material misstatements in our financial statements and projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, we have performed an assessment of the effectiveness of our internal controls over financial reporting as of June 28, 2014 . This assessment was based on the criteria established in Internal Control-Integrated Framework (1992), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that as of June 28, 2014 , the Company’s internal control over financial reporting is effective based on that criteria. +The effectiveness of the Company's internal control over financial reporting as of June 29, 2013 has been audited by BDO USA LLP, an independent registered public accounting firm, as stated in their report which is included herein. +Changes in Internal Control over Financial Reporting +There have been no significant changes in our internal controls over financial reporting during our fourth fiscal quarter ended June 28, 2014 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)). +51 +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Key Tronic Corporation +Spokane Valley, Washington +We have audited Key Tronic Corporation's internal control over financial reporting as of June 28, 2014, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Key Tronic Corporation's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Item 9A “Management's Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, Key Tronic Corporation maintained, in all material respects, effective internal control over financial reporting as of June 28, 2014, based on the COSO criteria . +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Key Tronic Corporation as of June 28, 2014 and June 29, 2013, and the related consolidated statements of income, comprehensive income, shareholders' equity, and cash flows for each of the three years in the period ended June 28, 2014 and our report dated September 5, 2014, expressed an unqualified opinion thereon. +/s/ BDO USA, LLP +Spokane, Washington +September 5, 2014 +52 +Item 9B: +OTHER INFORMATION +None +PART III +Item 10: +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Directors of the Registrant +Information on the nominees for election as Directors of the Company is incorporated by reference from the Company’s definitive proxy statement for the 2014 Annual Meeting of Shareholders to be filed pursuant to Regulation 14A under the Exchange Act no later than 120 days after the end of the Company’s 2014 fiscal year. +Executive Officers of the Registrant +This information is included in a separate item captioned “Executive Officers of the Registrant” in Item 1 of Part 1 of this report pursuant to Instruction G(3) of Form 10-K and Instruction 3 to Item 401(b) of Regulation S-K. +Compliance with Section 16(a) of the Exchange Act: +Incorporated by reference to Key Tronic Corporation’s 2014 Proxy Statement to Shareholders. +Code of Conduct +The Board of Directors has adopted a written Code of Conduct which applies to its directors and employees, including its executive officers. The Code of Conduct is available on the Company’s website at www.keytronic.com . The Company intends to disclose on its website any amendments to or waivers of the Code of Conduct. +Item 11: +EXECUTIVE COMPENSATION +Information appearing under the caption “Executive Compensation” in the Company’s 2014 Proxy Statement is incorporated herein by this reference. +Item 12: +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The following table sets forth the aggregate information for the Company’s equity compensation plans in effect as of June 28, 2014 . +EQUITY COMPENSATION PLAN INFORMATION +Plan category +Number of securities to +be issued upon exercise +of outstanding options, +warrants, and rights +(a) +Weighted-average +exercise price of +outstanding options, +warrants, and rights +(b) +Number of securities +remaining available for +future issuance under +equity compensation +plans (excluding +securities reflected in +column (a) +(c) +Equity compensation plans approved by security holders (1) +1,065,928 +$ +7.01 +— +Equity compensation plans not approved by security holders +— +$ +— +— +Total +1,065,928 +$ +7.01 +— +(1) +Included are the 1,200,000 shares subject to the 2010 Plan, the issuance of which were approved by the shareholders at the 2010 Annual Meeting. As a result of the shareholder approval, the Company made the decision to amend the cash-settled SARs granted during fiscal year 2010 to stock-settled SARs effective October 21, 2011. Also included are the shares subject to the 1990 Stock Option Plan for Non-Employee Directors. +Information under the caption “Beneficial Ownership of Securities” in the Company’s 2014 Proxy Statement is incorporated herein by this reference. +53 +Item 13: +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions”, “Compensation Committee Interlocks and Insider Participation”, and “Directors’ Independence” in the Company’s 2014 Proxy Statement is incorporated herein by this reference. +Item 14: +PRINCIPAL ACCOUNTING FEES AND SERVICES +Information appearing under the caption “Principal Accountant Fees and Services” in the Company’s 2014 Proxy Statement is incorporated herein by this reference. +PART IV +Item 15: +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +(a) 1. FINANCIAL STATEMENTS +Page in Form 10-K +FINANCIAL STATEMENTS +Report of Independent Registered Public Accounting Firm +29 +Consolidated Balance Sheets +30 +Consolidated Statements of Income +31 +Consolidated Statements of Comprehensive Income +32 +Consolidated Statements of Cash Flows +33 +Consolidated Statements of Shareholders’ Equity +34 +Notes to Consolidated Financial Statements +29-50 +54 +2. SCHEDULES +II. Consolidated Valuation and Qualifying Accounts +58 +Other schedules are omitted because of the absence of conditions under which they are required, or because required information is given in the financial statements or notes thereto. +3. EXHIBITS +Exhibit No. +Description +3.1 +Articles of Incorporation, incorporated by reference to the Exhibits to the Company’s form 10-K for the year ended June 30, 1986 +3.2 +Bylaws, as amended, incorporated by reference to the Exhibits to the Company’s Form 10-K for the year ended June 30, 1986 +10.1* +Executive Stock Option Plan, incorporated by reference to Exhibits to the Company’s Form 10-K for the year ended June 30, 1986 +10.2* +Amended and Restated 1990 Stock Option Plan for Non-Employee Directors, as amended, incorporated by reference to the Company’s 1997 Proxy Statement (dated October 10, 1997), pages 14-17 +10.3* +1995 Executive Stock Option Plan, incorporated by reference to the Company’s 1995 Proxy Statement, pages 19-22 +10.4* +2000 Employee Stock Option Plan, incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.5* +Officers’ Employment Contracts, incorporated by reference to the Company’s 1998 Proxy Statement, pages 10 and 11 +10.6* +Addenda to Officers’ Employment Contracts, incorporated by reference to Exhibits to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.7* +Description of Retention Bonus Plan, incorporated by reference to the Exhibits to the Company’s 10-Q for the quarter ended December 28, 2002 +10.8* +Addenda to Officers’ Employment Contracts, incorporated by reference to Exhibits to the Company’s Form 10-K for the year ended June 29, 2002 +10.9 +Promise to execute a Purchase and Sale Agreement with Key Safety Systems de Mexico, S.A. de C.V., incorporated by reference to the Exhibit to the Company’s Form 8-K filed April 26, 2005 +10.10 +Summary of material terms and conditions of the Purchase and Sale Agreement with Key Safety Systems de Mexico, S.A. de C.V., incorporated by reference to the Exhibit to the Company’s Form 8-K filed June 6, 2005 +10.11* +Summary of Key Tronic Corporation Incentive Compensation Plan, incorporated by reference to Exhibit 10.23 to the Company’s Form 10-K for the year ended July 2, 2005 +55 +10.12* +Summary of Incentive Compensation Plan Performance goals and Target Payments for fiscal year 2007, incorporated by reference to the Company’s Form 8-K filed July 28, 2006 +10.13* +Summary of Fiscal Years 2007 – 2009 Long Term Incentive Plan Performance Measures and Awards, incorporated by reference to the Company’s Form 8-K filed July 28, 2006 +10.14* +Summary of Key Tronic Corporation Long Term Incentive Compensation Plan, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed September 27, 2005 +10.15 +Summary of material terms and conditions of the Purchase and Sale Agreement with Todenko Mexico S.A. de C.V., incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed October 12, 2006 +10.16 +Summary of material terms and conditions of the Purchase and Sale Agreement with Todenko Mexico S.A. de C.V., incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed November 20, 2006 +10.17 +Summary of material terms and conditions of the Sale and Purchase Agreement with Adevco Corporation, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed January 5, 2007 +10.18 +Summary of Second Amendment to Agreement of Sale and Purchase Agreement with Adevco Corporation, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed April 11, 2007 +10.19* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2008 and Fiscal Years 2008-2010 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 27, 2007 +10.20* +Summary of Incentive Compensation Plan Performance Goals and Target payments for Fiscal Year 2009 and Fiscal Years 2009 – 2011 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 24, 2008 +10.21* +Summary of Incentive Compensation Plan Performance Goals and Target payments for Fiscal Year 2010 and Fiscal Years 2010 – 2012 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 23, 2009 +10.22 +Financing Agreement with Wells Fargo Bank, N.A., incorporated by reference to the Exhibits to the Company’s Form 8-K filed on August 24, 2009 +10.23* +2010 Incentive Plan, incorporated by reference to Exhibit 10.36 to the Company’s Form 10-K for the year ended July 3, 2010 +10.24* +Employment Contract with Douglas G. Burkhardt, incorporated by reference to Exhibit 10.37 to the Company’s Form 10-K for the year ended July 3, 2010 +10.25 +Summary of material terms and conditions of the Purchase and Sale Agreement with Autopartes Y Arneses de Mexico S.A. de C.V., incorporated by reference to Exhibit 10.38 to the Company’s Form 10-K for the year ended July 3, 2010 +10.26* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2011 and Fiscal Years 2011 – 2013 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 27, 2011 +56 +10.27* +Amendment to Employment Contract of Craig D. Gates, dated August 23, 2011; of Ronald F. Klawitter, dated August 23, 2011 and of Douglas G. Burkhardt dated September 6, 2011; incorporated by reference to the Exhibits to the Company’s Form 10-K for the year ended July 2, 2011 +10.28 +Second Loan Modification Agreement to the Credit Agreement with Wells Fargo Bank, N.A., incorporated by reference to the Exhibits to the Company’s Form 8-K filed on January 30, 2012 +10.29* +Amendment to Employment Contract of Craig D. Gates, dated May 10, 2012, and of Douglas G. Burkhardt dated May 10, 2012; incorporated by reference to the Exhibits to the Company’s Form 10-Q filed on May 14, 2012 +10.30* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2013 and Fiscal Years 2013 – 2015 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 7, 2012 +10.31* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2014 and Fiscal Years 2014 – 2016 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 6, 2013 +21. +Subsidiaries of Registrant, submitted herewith +23.1 +Consent of Independent Registered Public Accounting Firm, submitted herewith +31.1 +Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer, submitted herewith +31.2 +Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer, submitted herewith +32.1 +Section 1350 Certification of Chief Executive Officer, submitted herewith +32.2 +Section 1350 Certification of Chief Financial Officer, submitted herewith +101.INS +XBRL Instance Document ** +101.SCH +XBRL Taxonomy Extension Schema Document ** +101.CAL +XBRL Taxonomy Extension Calculation Linkbase Document ** +101.DEF +XBRL Taxonomy Extension Definition Linkbase Document ** +101.LAB +XBRL Taxonomy Extension Label Linkbase Document ** +101.PRE +XBRL Taxonomy Extension Presentation Linkbase Document ** +* +Management contract or compensatory plan or arrangement +** +Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities and Exchange Act of 1934, as amended and otherwise are not subject to liability under those sections. +57 +SCHEDULE II +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS +FISCAL YEARS ENDED JUNE 28, 2014 , JUNE 29, 2013 , AND JUNE 30, 2012 +Fiscal Year Ended +2014 +2013 +2012 +(in thousands) +Allowance for Obsolete Inventory +Balance at beginning of year +$ +381 +$ +1,146 +$ +732 +Provisions +257 +525 +762 +Dispositions +(306 +) +(1,290 +) +(348 +) +Balance at end of year +$ +332 +$ +381 +$ +1,146 +Allowance for Doubtful Accounts +Balance at beginning of year +$ +40 +$ +— +$ +111 +Provisions +37 +60 +— +Write-offs +(77 +) +(20 +) +(111 +) +Balance at end of year +$ +— +$ +40 +$ +— +58 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +Dated: September 5, 2014 +KEY TRONIC CORPORATION +By: +/s/ Craig D. Gates +Craig D. Gates, President and Chief +Executive Officer +(Principal Executive Officer) +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated: +/s/ Craig D. Gates +September 5, 2014 +Craig D. Gates +Date +Director and President and Chief Executive Officer +(Principal Executive Officer) +/s/ Ronald F. Klawitter +September 5, 2014 +Ronald F. Klawitter +Date +Director and Executive Vice President of Administration, Chief Financial Officer and Treasurer +(Principal Financial Officer) +/s/ Brett R. Larsen +September 5, 2014 +Brett R. Larsen +Date +Vice President of Finance and Controller +(Principal Accounting Officer) +/s/ James R. Bean +September 5, 2014 +James R. Bean, Director +Date +/s/ Yacov A. Shamash +September 5, 2014 +Yacov A. Shamash, Director +Date +/s/ Patrick Sweeney +September 5, 2014 +Patrick Sweeney, Director and Chairman of the Board +Date +59 \ No newline at end of file diff --git a/raw/filings/0000719733/2014/0000719733-14-000028/filing_metadata.csv b/raw/filings/0000719733/2014/0000719733-14-000028/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..cd20ad82056dca15ac487f81b2b53e73bb0c0512 --- /dev/null +++ b/raw/filings/0000719733/2014/0000719733-14-000028/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000719733,KTCC,KEY TRONIC CORP,10-K,2014-09-05,2014-06-28,2014-09-05T17:51:51.000Z,0000719733-14-000028,ktcc-06282014x10k.htm,10-K,10199891,1,0,https://www.sec.gov/Archives/edgar/data/719733/000071973314000028/ktcc-06282014x10k.htm,https://www.sec.gov/Archives/edgar/data/719733/000071973314000028/,2014,2014,1 diff --git a/raw/filings/0000719733/2014/0000719733-14-000028/item1.txt b/raw/filings/0000719733/2014/0000719733-14-000028/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..bf3d96a5c37c0d9fd8c2826094ff2500db2f3cbb --- /dev/null +++ b/raw/filings/0000719733/2014/0000719733-14-000028/item1.txt @@ -0,0 +1,104 @@ +Item 1. +BUSINESS +Background +Key Tronic Corporation (dba: KeyTronicEMS Co.), was organized in 1969 as a Washington corporation that locally manufactured computer keyboards. The ability to design, build and deliver a quality product led us to become a leading independent manufacturer of keyboards for computers in the United States. Our fully integrated design, tooling, and automated manufacturing capabilities enabled us to rapidly respond to customers’ needs for keyboards in production quantities worldwide. We supported our sales growth through the development and purchase of international manufacturing facilities. As the computer keyboard market matured with increasing competition from other international providers, we determined that our business could no longer solely rely on keyboard sales. +After assessing market conditions and our strengths and capabilities, we shifted focus from keyboard manufacturing to contract manufacturing for a wide range of products. Our unique strategic attributes are based on our core strengths of innovative design and engineering expertise in electronics, mechanical engineering, sheet metal fabrication and stamping, and precision plastics combined with high-quality, low cost production, and assembly on an international basis while providing exceptional customer service. These strengths have made our company a strong competitor in the electronic manufacturing services (EMS) market. +Our Industry and Strategy +The expansion of the EMS industry has allowed us to continue to expand our customer base and the industries that we serve. The challenging global macroeconomic environment had a negative impact on previously held customer programs during the past fiscal year, as we saw a significant decrease in revenue generated from two of our largest customer programs. However, we are successfully confronting the challenging global macroeconomic environment by controlling our costs and winning new customer programs, which allowed us to maintain our profitability and a strong balance sheet. The increase in new programs represents a growing portion of our revenue and a promising foundation for our future. In keeping with our long-term strategic objectives, we have been successfully building a more diversified customer portfolio, spanning a wider range of industries. We currently offer our customers the following services: integrated electronic and mechanical engineering, precision plastic molding, sheet metal fabrication, assembly, component selection, sourcing and procurement, worldwide logistics, and new product testing and production all at competitive pricing due to our global footprint. +We believe that we are well positioned in the EMS industry to continue the expansion of our customer base and achieve long term growth. Our unique blend of multinational facilities, centralized management, and core strengths continue to support our growth and our customers’ needs. We continue to focus on controlling operating expenses and leveraging the synergistic capabilities of our world-class facilities in the United States, Mexico, and China. This international production capability provides our customers with the benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs, and reduced product fulfillment time. Given our competitive advantages and the growing pressure for new potential customers to move forward with their outsourcing strategies, we are strongly positioned to win new business in coming periods and grow our revenue and profits. +4 +The EMS industry is intensely competitive. Although our customer base is growing we still have less than 1% of the potential global market and our revenue can fluctuate significantly due to reliance on a concentrated base of customers. We are planning for new customer growth in the coming quarters by securing new programs with new and existing customers, increasing our worldwide manufacturing capacity, and continuing to improve our manufacturing and procurement processes. Ongoing challenges that we face include the following: Continuing to win programs from new and existing customers, balancing production capacity and key personnel in support of new customer programs, improving operating efficiencies, controlling costs while developing competitive pricing strategies, and successfully transitioning new program wins to full production during a time of macroeconomic uncertainty. +Customers and Marketing +We provide a mix of manufacturing services for outsourced Original Equipment Manufacturing (OEM) products. We provide the following EMS services: Product design, surface mount technologies (SMT) and pin through hole capability for printed circuit board assembly, tool making, precision plastic molding, sheet metal fabrication, liquid injection molding, complex assembly, automated tape winding, prototype design and full product assembly. +Sales of the majority of our products have not historically been seasonal in nature, but may be seasonal in the future if there are changes in the types of products manufactured. Sales can, however, fluctuate significantly between quarters from changes in customers and customer demand due to the concentration of sales generated by our largest customers. +For the fiscal years 2014 , 2013 and 2012 , the five largest customers in each year accounted for 62%, 71% and 73% of combined total net sales, respectively. At the end of fiscal year 2014 , we were generating revenue from 196 separate programs and 59 distinct customers as compared to 183 programs and 56 customers at the end of fiscal year 2013 . As these new customers’ sales ramp up and new programs are won our concentration of revenue should continue to decrease in the future. +The following table represents all customers that represented 10% or more of total net sales during the last three fiscal years: +Percentage of Net Sales by Fiscal Year +2014 +2013 +2012 +Customer A +20% +19% +16% +Customer B +15% +23% +29% +Customer C +15% +21% +17% +Although keyboard manufacturing is still included in our product offerings, we do not expect annual keyboard sales to be a material component of our business. We realized revenues of approximately $2.3 million , $2.4 million and $2.8 million in fiscal years 2014 , 2013 and 2012 , respectively, from the sale of keyboards. In order to accommodate the demand for standard keyboard layouts, we maintain a purchase-from-stock program. The more popular standard layouts are built and stocked for immediate availability. +We market our products and services primarily through our direct sales department aided by strategically located field sales people and distributors. Although we maintain relationships with several independent sales organizations to assist in marketing our EMS product lines, commissions earned and paid are not material to the consolidated financial statements. +Manufacturing +We have continually made investments in developing and expanding a capital equipment base to achieve vertical integration and efficiencies in our manufacturing processes. We have invested significant capital into SMT for volume manufacturing of complex printed circuit board assemblies and in our metal shop providing precision metal stamping, fabricating, and finishing. We also design and develop tooling for injection molding and manufacture the majority of plastic parts used in the products we manufacture. Additionally, we have equipment to maintain a controlled clean environment for manufacturing processes that require a high level of precise control. +We use a variety of manual and automated assembly processes in our facilities, depending upon product complexity and degree of customization. Some examples of automated processes include component insertion, SMT, selective soldering, flexible robotic assembly, automated storage tape winding, computerized vision system quality inspection, laser turrets, automated switch and key top installation, and automated functional testing. +Our engineering expertise and automated manufacturing processes enable us to work closely with our customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. We use computer-aided design techniques and software to assist in preparation of the tool design layout and component placement, to reduce tooling and production costs, improve component and product quality, and enhance turnaround time during product development. +5 +We purchase materials and components for our products from many different suppliers, including both domestic and international sources. We develop close working relationships with our suppliers, many of whom have been supplying products to us for several years. +Research, Development, and Engineering +As part of our long-term strategy, we are committed to supporting our customers by providing research, development, and engineering services. These services allow us to facilitate in optimizing new product designs, and the production processes of our customers programs. +Research, development, and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials costs, depreciation, and allocated information technology and facilities costs. +Competition +The market for the products and services we provide is highly competitive. There are numerous competitors in the EMS industry, many of which have substantially more resources and are more geographically diverse than we are. Some of our competitors have similar international production capabilities, large financial resources and some have substantially greater manufacturing, research and development, and marketing resources. There is also competition from the manufacturing operations of our current and potential customers, who are continually evaluating the merits of manufacturing their products internally versus the advantages of outsourcing. We believe that we can currently compete favorably in these areas primarily on the basis of our international footprint, responsiveness, creativity, vertical production capability, quality, and cost. +Trademarks and Patents +Our name and logo are federally registered trademarks, and we believe they are valuable assets of our business. We operate under the trade name “KeyTronicEMS” to better identify our primary business concentration in contract manufacturing in the EMS industry. We also own several keyboard patents; however, since our focus is EMS, management believes that these patents will not have a significant impact on future revenues. +Employees +We consider our employees to be our primary strength and we make considerable efforts to maintain a well-qualified workforce. Our employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. We regularly provide transportation, medical services, and meals to all of our employees in foreign locations. We maintain a 401(k) plan for U.S. employees, which provides a discretionary matching company contribution of up to 4% of an employee’s salary. We provide group health, life, and disability insurance plans. We also maintain stock option plans and other long term incentive plans for certain employees and outside directors. +As of June 28, 2014 we had 3,343 employees compared to 2,584 on June 29, 2013 , and 2,700 on June 30, 2012 . Since we can have significant fluctuations in product demand, we seek to maintain flexibility in our workforce by utilizing skilled temporary and short-term contract labor in our manufacturing facilities in addition to full-time employees. +Backlog +On July 26, 2014 our order backlog was valued at approximately $103.1 million, compared to approximately $60.0 million on July 27, 2013. Even though our order backlog is comprised of firm purchase orders, the amount of backlog is not necessarily indicative of future sales but can be indicative of trends in expected future sales revenue. Due to the relationships with our customers, we will occasionally allow orders to be canceled or rescheduled and as a result it is not a meaningful indicator of future financial results. If there are canceled or rescheduled orders, we typically negotiate fees to cover the costs we have incurred. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change due to design modifications, customer forecast changes, or other customer requirements. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in Note 12, “Enterprise-Wide Disclosures” of the consolidated financial statements of this Annual Report on Form 10-K and that information is incorporated herein. +6 +Executive Officers of the Registrant +The table below sets forth the name, current age and current position of our executive officers and other significant employees: +Name +Age +Positions Held +Executive Officers +Craig D. Gates +55 +President and Chief Executive Officer +Ronald F. Klawitter +62 +Executive Vice President of Administration, Chief Financial Officer and Treasurer +Douglas G. Burkhardt +56 +Executive Vice President of Worldwide Operations +Philip S. Hochberg +52 +Executive Vice President of Business Development +Lawrence J. Bostwick +62 +Vice President of Engineering and Quality +Brett R. Larsen +41 +Vice President of Finance and Controller +Frank Crispigna III +53 +Vice President of Materials +Duane D. Mackleit +46 +Vice President of Program Management +Executive Officers +CRAIG D. GATES – President and Chief Executive Officer +Mr. Gates, age 55 , has been President and Chief Executive officer of the Company since April 2009. Previously he was Executive Vice President and General Manager from August 2002 to April 2009. He served as Executive Vice President of Marketing, Engineering and Sales from July 1997 to August 2002 and served as Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of 1994. From 1982 to 1991 he held various engineering and management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. Mr. Gates has a Bachelor of Science Degree in Mechanical Engineering and a Masters in Business Administration from the University of Illinois, Urbana. +RONALD F. KLAWITTER – Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Mr. Klawitter, age 62 , has been Executive Vice President of Administration, CFO, and Treasurer since July 1997. Previously he was Vice President of Finance, Secretary, and Treasurer of the Company from October 1995 to July 1997. He was Acting Secretary from November 1994 to October 1995 and Vice President of Finance and Treasurer from 1992 to October 1995. From 1987 to 1992, Mr. Klawitter was Vice President of Finance at Baker Hughes Tubular Service, a subsidiary of Baker Hughes, Inc. Mr. Klawitter has a BA degree from Wittenberg University and is a Certified Public Accountant. +DOUGLAS G. BURKHARDT – Executive Vice President of Worldwide Operations +Mr. Burkhardt, age 56 , has been Executive Vice President of Worldwide Operations of the Company since July 2010. Previously Mr. Burkhardt was Vice President of Worldwide Operations from July 2008 to July 2010 and Director of China Operations and Program Management from January 2006 to July 2008. Mr. Burkhardt also served as Director of Northwest and China Operations from November of 1998 to January of 2006. Mr. Burkhardt also served as Director of Customer Satisfaction from March 1997 to November 1998 and Director of Molding from September of 1995 to March of 1997. Prior to this, Mr. Burkhardt served in other various senior management positions within the Company. Mr. Burkhardt has been with the Company since May of 1989. Prior to joining Key Tronic, Mr. Burkhardt worked for House of Aluminum and Glass for 12 years where he was the plant manager. +PHILIP S. HOCHBERG – Executive Vice President of Business Development +Mr. Hochberg, age 52 , has been Executive Vice President of Business Development since July 2012. Prior this, Mr. Hochberg served as Vice President of Business Development from October 2009 through June 2012. He was Director of Business Development and Program Management from July 2008 to October 2009. Mr. Hochberg served as Director of Business Development from October 2004 to July 2008 and as Director of EMS Sales and Marketing from July 2000 to October 2004. Prior to joining Key Tronic, Mr. Hochberg worked for Quinton Instrument Company as their Director of Marketing and Product Management from 1992 to 2000. From 1988 to 1992, he was employed by SpaceLabs Medical as their Business Development Marketing Manager. Mr. Hochberg has an MBA from the University of British Columbia, a BA Psychology, with a minor in Business from Washington University in St. Louis. +7 +LAWRENCE J. BOSTWICK – Vice President of Engineering and Quality +Mr. Bostwick, age 62 , has been Vice President of Engineering and Quality since July 2008. Previously he was Director of Engineering and Quality from February 2007 to July 2008 and served as Corporate Director of Quality from February 2006 to February 2007. From 2003 to 2006 he was Director of Supply Chain Management and Quality for the Lancer Corporation and from 1998 to 2003 he was Vice President of Operations for Thermacore International. He is a graduate of the Westinghouse and General Electric – Engineering and Manufacturing Professional Development Programs. He is certified in both Quality and Industrial Engineering and is a Lean – Six Sigma Master Black Belt. Mr. Bostwick has a combined B.S. degree in Production and Operation and Industrial Engineering from Bowling Green State University and a Masters degree in Industrial Engineering and Business Administration from Syracuse University. +BRETT R. LARSEN – Vice President of Finance, and Controller +Mr. Larsen, age 41 , has served as Vice President of Finance and Controller since February 2010. He was Chief Financial Officer of FLSmidth Spokane, Inc. from December 2008 to February 2010. From October 2005 through November 2008, Mr. Larsen served as Controller of Key Tronic Corporation. From May 2004 to October 2005, Mr. Larsen served as Manager of Financial Reporting of Key Tronic Corporation. From 2002 to May 2004, Mr. Larsen was an audit manager for the public accounting firm BDO Seidman, LLP. He also held various auditing and supervisory positions with Grant Thornton LLP from 1997 to 2002. Mr. Larsen has a Bachelor of Science degree in Accounting and a Masters degree in Accounting from Brigham Young University and is a Certified Public Accountant. +FRANK CRISPIGNA III – Vice President of Materials +Mr. Crispigna, age 53 , has been Vice President of Materials of the company since October 2011. Prior to this, Mr. Crispigna held a variety of Materials and Supply Chain positions at Plexus Corporation since 1997, most recently serving as the Director – Supply Chain Solutions from 2005 - 2011. He has a Masters degree in Business Administration, and a Bachelor of Business Administration Degree in Marketing from the University of Wisconsin – Oshkosh. Mr. Crispigna also is a C.P.M., and received his certification in Supply Chain Leadership from the University of Wisconsin. +DUANE D. MACKLEIT – Vice President of Program Management +Mr. Mackleit, age 46 , has been Vice President of Program Management of the company since July 2012. He served as Director of Program Management from July 2008 through June 2012. From May 2006 to July 2008 he served as Principal Program Manager. Prior to that, he served as Program Manager from March 2002 to May 2006 and Associate Program Manager from August 2000 to March 2002. Mr. Mackleit has also held several other positions with Key Tronic Corporation. Mr. Mackleit has an AA in Business from Spokane Falls Community College and a BA in Business/Marketing from Eastern Washington University. He also holds a MBA from Gonzaga University. +Available Information +Our principal executive offices are located at N. 4424 Sullivan Road, Spokane Valley, Washington 99216, and our telephone number is (509) 928-8000. Our website is located at http://www.keytronicems.com where filings of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or current reports on Form 8-K are available after they have been filed with the Securities and Exchange Commission. The information presented on our website currently and in the future is not considered to be part of this document or any document incorporated by reference in this document. \ No newline at end of file diff --git a/raw/filings/0000719733/2014/0000719733-14-000028/item13.txt b/raw/filings/0000719733/2014/0000719733-14-000028/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..0db04b3970611122d95162b8f53c3c4048f415df --- /dev/null +++ b/raw/filings/0000719733/2014/0000719733-14-000028/item13.txt @@ -0,0 +1,3 @@ +Item 13: +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions”, “Compensation Committee Interlocks and Insider Participation”, and “Directors’ Independence” in the Company’s 2014 Proxy Statement is incorporated herein by this reference. \ No newline at end of file diff --git a/raw/filings/0000719733/2014/0000719733-14-000028/item9a.txt b/raw/filings/0000719733/2014/0000719733-14-000028/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..19f58af150f892f857d4ff757756a23fd8a658fb --- /dev/null +++ b/raw/filings/0000719733/2014/0000719733-14-000028/item9a.txt @@ -0,0 +1,26 @@ +Item 9A: +CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +It is the responsibility of our management to establish, maintain, and monitor disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 are recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Additionally, these disclosure controls include controls and procedures that are designed to accumulate and communicate the information required to be disclosed to our Company’s Chief Executive Officer and Chief Financial Officer, allowing for timely decisions regarding required disclosures. As of the end of the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(f). Based on our assessment, we believe that as of June 28, 2014 , the Company’s disclosure controls and procedures are effective based on that criteria. +Management’s Report on Internal Control over Financial Reporting +Our management has the responsibility to establish and maintain adequate internal controls over our financial reporting, as defined in Rule 13a-15(f) under the Securities and Exchange Act of 1934. Our internal controls are designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our external financial statements in accordance with generally accepted accounting principles (GAAP). +Due to inherent limitations of any internal control system, management acknowledges that there are limitations as to the effectiveness of internal controls over financial reporting and therefore recognize that only reasonable assurance can be gained from any internal control system. Accordingly, our internal control system may not detect or prevent material misstatements in our financial statements and projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, we have performed an assessment of the effectiveness of our internal controls over financial reporting as of June 28, 2014 . This assessment was based on the criteria established in Internal Control-Integrated Framework (1992), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that as of June 28, 2014 , the Company’s internal control over financial reporting is effective based on that criteria. +The effectiveness of the Company's internal control over financial reporting as of June 29, 2013 has been audited by BDO USA LLP, an independent registered public accounting firm, as stated in their report which is included herein. +Changes in Internal Control over Financial Reporting +There have been no significant changes in our internal controls over financial reporting during our fourth fiscal quarter ended June 28, 2014 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)). +51 +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Key Tronic Corporation +Spokane Valley, Washington +We have audited Key Tronic Corporation's internal control over financial reporting as of June 28, 2014, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Key Tronic Corporation's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Item 9A “Management's Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, Key Tronic Corporation maintained, in all material respects, effective internal control over financial reporting as of June 28, 2014, based on the COSO criteria . +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Key Tronic Corporation as of June 28, 2014 and June 29, 2013, and the related consolidated statements of income, comprehensive income, shareholders' equity, and cash flows for each of the three years in the period ended June 28, 2014 and our report dated September 5, 2014, expressed an unqualified opinion thereon. +/s/ BDO USA, LLP +Spokane, Washington +September 5, 2014 +52 \ No newline at end of file diff --git a/raw/filings/0000719733/2014/0000719733-14-000028/rp_note.txt b/raw/filings/0000719733/2014/0000719733-14-000028/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000719733/2014/0000719733-14-000028/rpt_disclosure.txt b/raw/filings/0000719733/2014/0000719733-14-000028/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..0109d8991d1fb5400548678fca7ea73cc3e4274b --- /dev/null +++ b/raw/filings/0000719733/2014/0000719733-14-000028/rpt_disclosure.txt @@ -0,0 +1,14 @@ +Related Person Transactions +In April +2007, the Board of Directors adopted a written policy and procedures for the approval or ratification of Interested Transactions with Related Parties. The policy and procedures supplement the Company’s Code of Conduct. The policy defines an +“Interested Transaction” as any transaction, arrangement or relationship or series of similar transactions, arrangements or relationships (including any indebtedness or guarantee of indebtedness) in which (1) the aggregate amount +involved will or may be expected to exceed $120,000 in any calendar year, (2) the Company is a participant, and (3) any Related Party has or will have a direct or indirect interest (other than solely as a result of being a director or a +less than 10 percent beneficial owner of another entity). +The policy defines a “Related Party” as any (a) person who is or was +(since the beginning of the last fiscal year for which the Company has filed a Form 10-K and proxy statement, even if they do not presently serve in that role) an executive officer, director or nominee for election as a director, (b) greater +than 5 percent beneficial owner of the Company’s common stock, or (c) immediate family member of any of the foregoing. Immediate family member includes a person’s spouse, parents, stepparents, children, stepchildren, siblings, +mothers- and fathers-in-law, sons- and daughters-in-law, and brothers- and sisters-in-law and anyone residing in such person’s home (other than a tenant or employee). +The Audit Committee is responsible for review, approval, ratification or disapproval of Interested Transactions. In determining whether to approve or ratify an Interested Transaction, the Committee will +take into account, among other factors it deems appropriate, whether the Interested Transaction is on terms no less favorable than terms generally available to an unaffiliated third party under the same or similar circumstances and the extent of the +Related Party’s interest in the Transaction. +-6- \ No newline at end of file diff --git a/raw/filings/0000719733/2015/0000719733-15-000070/filing.txt b/raw/filings/0000719733/2015/0000719733-15-000070/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..fb3816d0a026179cc6744fd4d230be39edb0890a --- /dev/null +++ b/raw/filings/0000719733/2015/0000719733-15-000070/filing.txt @@ -0,0 +1,3381 @@ +10-K +1 +ktcc-06272015x10k.htm +10-K +10-K +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +____________________________________________________________ +FORM 10-K +____________________________________________________________ +x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE FISCAL YEAR ENDED JUNE 27, 2015 +OR +¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE PERIOD FROM TO +Commission File Number 0-11559 +____________________________________________________________ +KEY TRONIC CORPORATION +(Exact name of registrant as specified in its charter) +____________________________________________________________ +Washington +91-0849125 +(State or other jurisdiction of +Incorporation or organization) +(I.R.S. Employer +Identification No.) +N. 4424 Sullivan Road, Spokane Valley, +Washington +99216 +(Address of principal executive offices) +(Zip Code) +(509) 928-8000 +(Registrant’s telephone number, including area code) +N/A +(Former name, former address and former fiscal year, if changed since last report) +____________________________________________________________ +Securities Registered Pursuant to Section 12(b) of the Act: None +Title of each class +Name of each exchange on which registered +Common stock, no par value +The NASDAQ Stock Market LLC +Securities Registered Pursuant to Section 12(g) of the Act: None +____________________________________________________________ +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ¨ No x +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulations S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. +(Check one): +Large accelerated filer +¨ +Accelerated filer +x +Non-accelerated filer +¨ (Do not check if a smaller reporting company) +Smaller reporting company +¨ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x +State the aggregate market value of the voting and non-voting common equity held by non affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. +As of December 27, 2014, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $81.0 million based on the closing price as reported on the NASDAQ. +Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: 10,706,706 shares of common stock were outstanding as of September 2, 2015 . +____________________________________________________________ +Documents Incorporated by Reference: +The following documents are incorporated by reference to the extent specified herein: +Document Description +Part of Form 10-K +Proxy Statement dated September 14, 2015 +Part III +KEY TRONIC CORPORATION +2015 FORM 10-K +TABLE OF CONTENTS +Page No. +PART I +Item 1. +Business +4 +Item 1A. +Risk Factors +9 +Item 1B. +Unresolved Staff Comments +14 +Item 2. +Properties +15 +Item 3. +Legal Proceedings +16 +Item 4. +Mine Safety Disclosures +16 +PART II +Item 5. +Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities +16 +Item 6. +Selected Financial Data +18 +Item 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +19 +Item 7A. +Quantitative and Qualitative Disclosures about Market Risk +30 +Item 8. +Financial Statements and Supplementary Data +31-54 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +55 +Item 9A. +Controls and Procedures +55 +Item 9B. +Other Information +57 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +57 +Item 11. +Executive Compensation +57 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +57 +Item 13. +Certain Relationships and Related Transactions, and Director Independence +58 +Item 14. +Principal Accounting Fees and Services +58 +PART IV +Item 15. +Exhibits and Financial Statement Schedule +58 +Signatures +63 +3 +FORWARD-LOOKING STATEMENTS +References in this report to “the Company,” “Key Tronic,” “KeyTronicEMS,” “we,” “our,” or “us” mean Key Tronic Corporation together with its subsidiaries, except where the context otherwise requires. +This Annual Report on Form 10-K contains forward-looking statements in addition to historical information. Forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those reflected in the forward-looking statements. Risks and uncertainties that might cause such differences include, but are not limited to those outlined in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risks and Uncertainties that May Affect Future Results.” Readers are cautioned not to place undue reliance on forward-looking statements, which reflect management’s opinions only as of the date hereof. The Company undertakes no obligation to update forward-looking statements to reflect developments or information obtained after the date hereof and disclaims any obligation to do so. Readers should carefully review the risk factors described in periodic reports the Company files from time to time with the Securities and Exchange Commission, including Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. +PART I +Item 1. +BUSINESS +Background +Key Tronic Corporation (dba: KeyTronicEMS Co.) was organized in 1969, as a Washington corporation that locally manufactured computer keyboards. The ability to design, build and deliver a quality product led us to become a leading independent manufacturer of keyboards for computers in the United States. Our fully integrated design, tooling, and automated manufacturing capabilities enabled us to rapidly respond to customers’ needs for keyboards in production quantities worldwide. We supported our sales growth through the development and purchase of international manufacturing facilities. As the computer keyboard market matured with increasing competition from other international providers, we determined that our business could no longer solely rely on keyboard sales. +After assessing market conditions and our strengths and capabilities, we shifted focus from keyboard manufacturing to contract manufacturing for a wide range of products. Our unique strategic attributes are based on our core strengths of innovative design and engineering expertise in electronics, mechanical engineering, sheet metal fabrication and stamping, and precision plastics combined with high-quality, low cost production, and assembly on an international basis while providing exceptional customer service. These strengths have made our company a strong competitor in the electronic manufacturing services (EMS) market. +Acquisitions +On September 3, 2014, we completed the acquisition of all of the outstanding shares of CDR Manufacturing, Inc. (dba Ayrshire Electronics), which added five locations (four in North America and one in Mexico). Subsequent to the acquisition, the Reynosa, Mexico operations were transferred to the Company’s existing Juarez, Mexico facilities. This acquisition expands our printed circuit board assembly capacity, total revenue, and adds to and diversifies our customer base with the addition of many new multi-national companies. +On July 1, 2013, the Company acquired substantially all of the assets of Sabre Assembly & Manufacturing Co. of Texas (“Sabre”), a sheet metal fabrication company with facilities located in Juarez, Mexico. The acquisition of Sabre enables the Company to offer metal fabrication directly to its customers, in combination with plastic molding, PCB assembly, complete product assembly, design engineering and testing engineering services. +Our Industry and Strategy +The expansion of the EMS industry and recent acquisition has allowed us to continue to expand our customer base and the industries that we serve. The increase in new programs represents a growing portion of our revenue and a promising foundation for our future. In keeping with our long-term strategic objectives, we have been successfully building a more diversified customer portfolio, spanning a wider range of industries. We currently offer our customers the following services: integrated electronic and mechanical engineering, precision plastic molding, sheet metal fabrication, PCB and complete product assembly, component selection, sourcing and procurement, worldwide logistics, and new product testing and production all at competitive pricing due to our global footprint. +4 +We believe that we are well positioned in the EMS industry to continue the expansion of our customer base and achieve long term growth. Our unique blend of multinational facilities, vertical integration, centralized management, and core strengths continue to support our growth and our customers’ needs. We continue to focus on controlling operating expenses and leveraging the synergistic capabilities of our world-class facilities in the United States, Mexico, and China. This international production capability provides our customers with the benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs, and reduced product fulfillment time. Given our competitive advantages and the growing pressure for new potential customers to move forward with their outsourcing strategies, we are strongly positioned to win new business in coming periods and grow our revenue and profits. +The EMS industry is intensely competitive. Although our customer base is growing, we still have less than 1% of the potential global market and our revenue can fluctuate significantly due to reliance on a concentrated base of customers. We are planning for new customer growth in the coming quarters by securing new programs with new and existing customers, increasing our worldwide manufacturing capacity, and continuing to improve our manufacturing and procurement processes. Ongoing challenges that we face include but are not limited to the following: Continuing to win programs from new and existing customers, balancing production capacity and key personnel in support of new customer programs, improving operating efficiencies, controlling costs while developing competitive pricing strategies, and successfully transitioning new program wins to full production. +Customers and Marketing +We provide a mix of manufacturing services for outsourced Original Equipment Manufacturing (OEM) products. We provide the following EMS services: Product design, surface mount technologies (SMT) and pin through hole capability for printed circuit board assembly, tool making, precision plastic molding, sheet metal fabrication, liquid injection molding, complex assembly, automated tape winding, prototype design and full product assembly. +Sales of the majority of our products have not historically been seasonal in nature, but may be seasonal in the future if there are changes in the types of products manufactured. Sales can, however, fluctuate significantly between quarters from changes in customers and customer demand due to the concentration of sales generated by our largest customers. +For the fiscal years 2015 , 2014 and 2013 , the five largest customers in each year accounted for 42%, 62% and 71% of combined total net sales, respectively. This decrease was primarily the result of the acquisition of Ayrshire as well as the impact of the reduction in production levels for certain longstanding customers. We continue to diversify our customer base by adding additional programs and customers. As these new customers’ sales ramp up and new programs are won, our concentration of revenue should continue to decrease in the future. +The following table represents all customers that represented 10% or more of total net sales during the last three fiscal years: +Percentage of Net Sales by Fiscal Year +2015 +2014 +2013 +Customer A +17% +20% +19% +Customer B +* +15% +23% +Customer C +* +15% +21% +* Current customer amount represents less than 10%. +There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +Although keyboard manufacturing is still included in our product offerings, we do not expect annual keyboard sales to be a material component of our business. We recognized keyboard revenue of approximately $1.9 million , $2.3 million and $2.4 million in fiscal years 2015 , 2014 and 2013 , respectively. In order to accommodate the demand for standard keyboard layouts, we maintain a purchase-from-stock program. The more popular standard layouts are built and stocked for immediate availability. +We market our products and services primarily through our direct sales department aided by strategically located field sales people and distributors. We also maintain relationships with several independent sales organizations to assist in marketing our EMS product lines. +5 +Manufacturing +We have continually made investments in developing and expanding a capital equipment base to achieve vertical integration and efficiencies in our manufacturing processes. We have invested significant capital into SMT for volume manufacturing of complex printed circuit board assemblies and in our metal shop providing precision metal stamping, fabricating, and finishing. We also design and develop tooling for injection molding and manufacture the majority of plastic parts used in the products we manufacture. Additionally, we have equipment to maintain a controlled clean environment for manufacturing processes that require a high level of precise control. +We use a variety of manual and automated assembly processes in our facilities, depending upon product complexity and degree of customization. Some examples of automated processes include component insertion, SMT, selective soldering, flexible robotic assembly, automated storage tape winding, computerized vision system quality inspection, laser turrets, automated switch and key top installation, and automated functional testing. +Our engineering expertise and automated manufacturing processes enable us to work closely with our customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. We use computer-aided design techniques and software to assist in preparation of the tool design layout and component placement, to reduce tooling and production costs, improve component and product quality, and enhance turnaround time during product development. +We purchase materials and components for our products from many different suppliers, including both domestic and international sources. We develop close working relationships with our suppliers, many of whom have been supplying products to us for several years. +Research, Development, and Engineering +As part of our long-term strategy, we are committed to supporting our customers by providing research, development, and engineering services. These services allow us to facilitate in optimizing new product designs, and the production processes of our customers programs. +Research, development, and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials costs, depreciation, and allocated information technology and facilities costs. +Competition +The market for the products and services we provide is highly competitive. There are numerous competitors in the EMS industry, many of which have substantially more resources and are more geographically diverse than we are. Some of our competitors have similar international production capabilities, large financial resources and some have substantially greater manufacturing, research and development, and marketing resources. There is also competition from the manufacturing operations of our current and potential customers, who are continually evaluating the merits of manufacturing their products internally versus the advantages of outsourcing. We believe that we can currently compete favorably in these areas primarily on the basis of our international footprint, responsiveness, creativity, vertical production capability, quality, and cost. +Trademarks +Our name and logo are federally registered trademarks, and we believe they are valuable assets of our business. We operate under the trade name “KeyTronicEMS” to better identify our primary business concentration in contract manufacturing in the EMS industry. +Employees +We consider our employees to be our primary strength and we make considerable efforts to maintain a well-qualified workforce. Our employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. We regularly provide transportation, medical services, and meals to all of our employees in foreign locations. The Company also has defined contribution plans available to U.S. employees who have attained age 21 and provide group health, life, and disability insurance plans. We also maintain share based compensation plans and other long term incentive plans for certain employees and outside directors. +As of June 27, 2015 we had 4,866 employees compared to 3,343 on June 28, 2014 , and 2,584 on June 29, 2013 . Since we can have significant fluctuations in product demand, we seek to maintain flexibility in our workforce by utilizing skilled temporary and short-term contract labor in our manufacturing facilities in addition to full-time employees. +6 +Backlog +On July 24, 2015 our order backlog was valued at approximately $115.2 million, compared to approximately $103.1 million on July 26, 2014. The amount of backlog is not necessarily indicative of future sales but can be indicative of trends in expected future sales revenue. Due to the relationships with our customers, we will occasionally allow orders to be canceled or rescheduled and as a result it is not a meaningful indicator of future financial results. If there are canceled or rescheduled orders, we typically negotiate fees to cover the costs we have incurred. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change due to design modifications, customer forecast changes, or other customer requirements. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in Note 12, “Enterprise-Wide Disclosures” of the consolidated financial statements of this Annual Report on Form 10-K and that information is incorporated herein. +Executive Officers of the Registrant +The table below sets forth the name, current age and current position of our executive officers and other significant employees: +Name +Age +Positions Held +Executive Officers +Craig D. Gates +56 +President and Chief Executive Officer +Brett R. Larsen +42 +Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Douglas G. Burkhardt +57 +Executive Vice President of Worldwide Operations +Philip S. Hochberg +53 +Executive Vice President of Business Development +Lawrence J. Bostwick +63 +Vice President of Engineering and Quality +Frank Crispigna III +54 +Vice President of Materials +Duane D. Mackleit +47 +Vice President of Program Management +Executive Officers +CRAIG D. GATES – President and Chief Executive Officer +Mr. Gates, age 56 , has been President and Chief Executive officer of the Company since April 2009. Previously, he was Executive Vice President and General Manager from August 2002 to April 2009. He served as Executive Vice President of Marketing, Engineering and Sales from July 1997 to August 2002 and served as Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of 1994. From 1982 to 1991 he held various engineering and management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. Mr. Gates has a Bachelor of Science Degree in Mechanical Engineering and a Masters in Business Administration from the University of Illinois, Urbana. +BRETT R. LARSEN – Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Mr. Larsen, age 42 , has served as Executive Vice President of Administration, Chief Financial Officer, and Treasurer since July 2015. Previously, he was Vice President of Finance and Controller from February 2010 to July 2015. He was Chief Financial Officer of FLSmidth Spokane, Inc. from December 2008 to February 2010. From October 2005 through November 2008, Mr. Larsen served as Controller of Key Tronic Corporation. From May 2004 to October 2005, Mr. Larsen served as Manager of Financial Reporting of Key Tronic Corporation. From 2002 to May 2004, Mr. Larsen was an audit manager for the public accounting firm BDO Seidman, LLP. He also held various auditing and supervisory positions with Grant Thornton LLP from 1997 to 2002. Mr. Larsen has a Bachelor of Science degree in Accounting and a Masters degree in Accounting from Brigham Young University and is a Certified Public Accountant. +7 +DOUGLAS G. BURKHARDT – Executive Vice President of Worldwide Operations +Mr. Burkhardt, age 57 , has been Executive Vice President of Worldwide Operations of the Company since July 2010. Previously Mr. Burkhardt was Vice President of Worldwide Operations from July 2008 to July 2010 and Director of China Operations and Program Management from January 2006 to July 2008. Mr. Burkhardt also served as Director of Northwest and China Operations from November of 1998 to January of 2006. Mr. Burkhardt also served as Director of Customer Satisfaction from March 1997 to November 1998 and Director of Molding from September of 1995 to March of 1997. Prior to this, Mr. Burkhardt served in other various senior management positions within the Company. Mr. Burkhardt has been with the Company since May of 1989. Prior to joining Key Tronic, Mr. Burkhardt worked for House of Aluminum and Glass for 12 years where he was the plant manager. +PHILIP S. HOCHBERG – Executive Vice President of Business Development +Mr. Hochberg, age 53 , has been Executive Vice President of Business Development since July 2012. Prior this, Mr. Hochberg served as Vice President of Business Development from October 2009 through June 2012. He was Director of Business Development and Program Management from July 2008 to October 2009. Mr. Hochberg served as Director of Business Development from October 2004 to July 2008 and as Director of EMS Sales and Marketing from July 2000 to October 2004. Prior to joining Key Tronic, Mr. Hochberg worked for Quinton Instrument Company as their Director of Marketing and Product Management from 1992 to 2000. From 1988 to 1992, he was employed by SpaceLabs Medical as their Business Development Marketing Manager. Mr. Hochberg has an MBA from the University of British Columbia, a BA Psychology, with a minor in Business from Washington University in St. Louis. +LAWRENCE J. BOSTWICK – Vice President of Engineering and Quality +Mr. Bostwick, age 63 , has been Vice President of Engineering and Quality since July 2008. Previously he was Director of Engineering and Quality from February 2007 to July 2008 and served as Corporate Director of Quality from February 2006 to February 2007. From 2003 to 2006 he was Director of Supply Chain Management and Quality for the Lancer Corporation and from 1998 to 2003 he was Vice President of Operations for Thermacore International. He is a graduate of the Westinghouse and General Electric – Engineering and Manufacturing Professional Development Programs. He is certified in both Quality and Industrial Engineering and is a Lean – Six Sigma Master Black Belt. Mr. Bostwick has a combined B.S. degree in Production and Operation and Industrial Engineering from Bowling Green State University and a Masters degree in Industrial Engineering and Business Administration from Syracuse University. +FRANK CRISPIGNA III – Vice President of Materials +Mr. Crispigna, age 54 , has been Vice President of Materials of the company since October 2011. Prior to this, Mr. Crispigna held a variety of Materials and Supply Chain positions at Plexus Corporation since 1997, most recently serving as the Director – Supply Chain Solutions from 2005 - 2011. He has a Masters degree in Business Administration, and a Bachelor of Business Administration Degree in Marketing from the University of Wisconsin – Oshkosh. Mr. Crispigna also is a C.P.M., and received his certification in Supply Chain Leadership from the University of Wisconsin. +DUANE D. MACKLEIT – Vice President of Program Management +Mr. Mackleit, age 47 , has been Vice President of Program Management of the company since July 2012. He served as Director of Program Management from July 2008 through June 2012. From May 2006 to July 2008 he served as Principal Program Manager. Prior to that, he served as Program Manager from March 2002 to May 2006 and Associate Program Manager from August 2000 to March 2002. Mr. Mackleit has also held several other positions with Key Tronic Corporation. Mr. Mackleit has an AA in Business from Spokane Falls Community College and a BA in Business/Marketing from Eastern Washington University. He also holds a MBA from Gonzaga University. +Available Information +Our principal executive offices are located at 4424 North Sullivan Road, Spokane Valley, Washington 99216, and our telephone number is (509) 928-8000. Our website is located at http://www.keytronicems.com where filings of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or current reports on Form 8-K are available after they have been filed with the Securities and Exchange Commission. The information presented on our website currently and in the future is not considered to be part of this document or any document incorporated by reference in this document. +8 +Item 1A. +RISK FACTORS +There are risks and uncertainties that could affect our business. These risks and uncertainties include but are not limited to, the risk factors described below, in Item 7A: “Quantitative and Qualitative Disclosures about Market Risk” and elsewhere in this Form 10-K. +RISKS AND UNCERTAINTIES THAT MAY AFFECT FUTURE RESULTS +The following risks and uncertainties could affect our actual results and could cause results to differ materially from past results or those contemplated by our forward-looking statements. When used herein, the words “expects,” “believes,” “anticipates” and other similar expressions are intended to identify forward-looking statements. +We may experience fluctuations in quarterly results of operations. +Our quarterly operating results have varied in the past and may vary in the future due to a variety of factors, including adverse changes in the U.S. and global macroeconomic environment, volatility in overall demand for our customers’ products, success of customers’ programs, timing of new programs, new product introductions or technological advances by us, our customers and our competitors, and changes in pricing policies by us, our customers, our suppliers, and our competitors. Our customer base is diverse in the markets they serve, however, decreases in demand, particularly from customers that supply the education, consumer products, and gambling industries, could affect future quarterly results. Additionally, our customers could be impacted by the illiquidity of the credit markets which could directly impact our operating results. +Component procurement, production schedules, personnel and other resource requirements are based on estimates of customer requirements. Occasionally, our customers may request accelerated production that can stress resources and reduce operating margins. In addition, because many of our operating expenses are relatively fixed, a reduction in customer demand can harm our gross profit and operating results. The products which we manufacture for our customers have relatively short product lifecycles. Therefore, our business, operating results and financial condition are dependent in a significant way on our ability to obtain orders from new customers and new product programs from existing customers. +Operating results can also fluctuate if changes are made to significant estimates and assumptions. Significant estimates and assumptions include the allowance for doubtful receivables, provision for obsolete and non-saleable inventory, stock-based compensation, the valuation allowance on deferred tax assets, valuation of goodwill, impairment of long-lived assets, long-term incentive compensation accrual, the provision for warranty costs, the impact of hedging activities and purchase price allocation. +We are exposed to general economic conditions, which could have a material adverse impact on our business, operating results and financial condition. +Recently there have been adverse conditions and uncertainty in the global economy as the result of unstable global financial and credit markets, inflation, and recession. These unfavorable economic conditions and the weakness of the credit market could affect the demand for our customers’ products. The current global macroeconomic environment may affect some of our customers that could reduce orders and change forecasts which could adversely affect our sales in future periods. Additionally, the financial strength of our customers and suppliers and their ability to obtain and rely on credit financing may affect their ability to fulfill their obligations to us and have an adverse effect on our financial results. +The majority of our sales come from a small number of customers and a decline in sales to any of these customers could adversely affect our business. +At present, our customer base is concentrated and could become more or less concentrated. There can be no assurance that our principal customers will continue to purchase products from us at current levels. Moreover, we typically do not enter into long-term volume purchase contracts with our customers, and our customers have certain rights to extend or delay the shipment of their orders. We, however, typically require that our customers contractually agree to buy back inventory purchased within specified lead times to build their products if not used. +The loss of one or more of our major customers, or the reduction, delay or cancellation of orders from such customers, due to economic conditions or other forces, could materially and adversely affect our business, operating results and financial condition. Specifically, some of our major customers provide products to the banking and gambling industries which have been adversely affected by the unfavorable economic environment. The contraction in demand from our customers in these industries could impact our customer orders and have a negative impact on our operations over the foreseeable future. Additionally, if one or more of our customers were to become insolvent or otherwise unable to pay for the manufacturing services provided by us, our operating results and financial condition would be adversely affected. +9 +We depend on a limited number of suppliers for certain components that are critical to our manufacturing processes. A shortage of these components or an increase in their price could interrupt our operations and result in a significant change in our results of operations. +We are dependent on many suppliers, including sole source suppliers, to provide key components and raw materials used in manufacturing customers’ products. We have seen supply shortages in certain electronic components. This can result in longer lead times and the inability to meet our customers request for flexible production and extended shipment dates. If demand for components outpaces supply, capacity delays could affect future operations. Delays in deliveries from suppliers or the inability to obtain sufficient quantities of components and raw materials could cause delays or reductions in shipment of products to our customers which could adversely affect our operating results and damage customer relationships. +We operate in a highly competitive industry; if we are not able to compete effectively in the EMS industry, our business could be adversely affected. +Competitors may offer customers lower prices on certain high volume programs. This could result in price reductions, reduced margins and loss of market share, all of which would materially and adversely affect our business, operating results, and financial condition. If we were unable to provide comparable or better manufacturing services at a lower cost than our competitors, it could cause sales to decline. In addition, competitors can copy our non-proprietary designs and processes after we have invested in development of products for customers, thereby enabling such competitors to offer lower prices on such products due to savings in development costs. +Cash and cash equivalents are exposed to concentrations of credit risk. +We place our cash with high credit quality institutions. At times, such balances may be in excess of the federal depository insurance limit or may be on deposit at institutions which are not covered by insurance. If such institutions were to become insolvent during which time it held our cash and cash equivalents in excess of the insurance limit, it could be necessary to obtain other credit financing to operate our facilities. +Our ability to secure and maintain sufficient credit arrangements is key to our continued operations. +There is no assurance that we will be able to retain or renew our credit agreements in the future. In the event the business grows rapidly or the uncertain macroeconomic climate continues, additional financing resources could be necessary in the current or future fiscal years. There is no assurance that we will be able to obtain equity or debt financing at acceptable terms, or at all in the future. For a summary of our banking arrangements, see Note 4 Long-Term Debt of the “Notes to Consolidated Financial Statements.” +Our operations may be subject to certain risks. +We manufacture product in facilities located in Mexico, China and the United States. These operations may be subject to a number of risks, including: +• +difficulties in staffing and managing onshore and offshore operations; +• +political and economic instability (including acts of terrorism, pandemics, civil unrest, forms of violence and outbreaks of war), which could impact our ability to ship, manufacture, and/or receive product; +• +unexpected changes in regulatory requirements and laws; +• +longer customer payment cycles and difficulty collecting accounts receivable; +• +export duties, import controls and trade barriers (including quotas); +• +governmental restrictions on the transfer of funds; +• +burdens of complying with a wide variety of foreign laws and labor practices; +• +our locations may be impacted by hurricanes, tornadoes, earthquakes, water shortages, tsunamis, floods, typhoons, fires, extreme weather conditions and other natural or man-made disasters. +Our operations in certain foreign locations receive favorable income tax treatment in the form of tax credits or other incentives. In the event that such tax incentives are not extended, are repealed, or we no longer qualify for such programs, our taxes may increase, which would reduce our net income. +Additionally, certain foreign jurisdictions restrict the amount of cash that can be transferred to the U.S or impose taxes and penalties on such transfers of cash. To the extent we have excess cash in foreign locations that could be used in, or is needed by, our operations in the United States, we may incur significant penalties and/or taxes to repatriate these funds. +10 +Fluctuations in foreign currency exchange rates could increase our operating costs. +We have manufacturing operations located in Mexico and China. A significant portion of our operations are denominated in the Mexican peso and the Chinese currency, the renminbi ("RMB"). Currency exchange rates fluctuate daily as a result of a number of factors, including changes in a country's political and economic policies. Volatility in the currencies of our entities and the United States dollar could seriously harm our business, operating results and financial condition. The primary impact of currency exchange fluctuations is on the cash, receivables, payables and expenses of our operating entities. As part of our hedging strategy, we currently use Mexican peso forward contracts to hedge foreign currency fluctuations for a portion of our Mexican peso denominated expenses. We currently do not hedge expenses denominated in RMB. Unexpected losses could occur from increases in the value of these currencies relative to the United States dollar. +Our success will continue to depend to a significant extent on our key personnel. +Our future success depends in large part on the continued service of our key technical, marketing and management personnel and on our ability to continue to attract and retain qualified employees. There can be no assurance that we will be successful in attracting and retaining such personnel. The loss of key employees could have a material adverse effect on our business, operating results and financial condition. +If we are unable to maintain our technological and manufacturing process expertise, our business could be adversely affected. +The markets for our customers’ products is characterized by rapidly changing technology, evolving industry standards, frequent new product introductions and short product life cycles. The introduction of products embodying new technologies or the emergence of new industry standards can render existing products obsolete or unmarketable. Our success will depend upon our customers’ ability to enhance existing products and to develop and introduce, on a timely and cost-effective basis, new products that keep pace with technological developments and emerging industry standards and address evolving and increasingly sophisticated customer requirements. Failure of our customers to do so could substantially harm our customers’ competitive positions. There can be no assurance that our customers will be successful in identifying, developing and marketing products that respond to technological change, emerging industry standards or evolving customer requirements. +Start-up costs and inefficiencies related to new or transferred programs can adversely affect our operating results and such costs may not be recoverable if such new programs or transferred programs are canceled. +Start-up costs, the management of labor and equipment resources in connection with the establishment of new programs and new customer relationships, and the need to obtain required resources in advance can adversely affect our gross margins and operating results. These factors are particularly evident in the ramping stages of new programs. These factors also affect our ability to efficiently use labor and equipment. We are currently managing a number of new programs. Consequently, our exposure to these factors has increased. In addition, if any of these new programs or new customer relationships were terminated, our operating results could be harmed, particularly in the short term. We may not be able to recoup these start-up costs or replace anticipated new program revenues. +Customers may change production timing and demand schedules which makes it difficult for us to schedule production and capital expenditures and to maximize the efficiency of our manufacturing capacity. +Changes in demand for customer products reduce our ability to accurately estimate the future requirements of our customers. This makes it difficult to schedule production and maximize utilization of our manufacturing capacity. We must determine the levels of business that we will seek and accept from customers, set production schedules, commit to procuring inventory, and allocate personnel and resources, based on our estimates of our customers' requirements. Customers can require sudden increases and decreases in production which can put added stress on resources and reduce margins. +Continued growth could further lead to capacity constraints. We may need to transfer production to other facilities, acquire new facilities, or outsource production which could negatively impact gross margin. +An adverse change in the interest rates for our borrowings could adversely affect our financial condition. +We are exposed to interest rate risk under our revolving line of credit and term loan. We currently hedge a portion of our term loan with an interest rate swap. We have not historically hedged the interest rate on our credit facility; therefore, unless we do so, significant changes in interest rates could adversely affect our results of operations. Refer to the discussion in note 4, "Long-Term Debt" to the consolidated financial statements for further details of our debt obligations. We are also exposed to interest rate risk on our factoring activities. +11 +Compliance or the failure to comply with current and future environmental laws or regulations could cause us significant expense. +We are subject to a variety of domestic and foreign environmental regulations relating to the use, storage, and disposal of materials used in our manufacturing processes. If we fail to comply with any present or future regulations, we could be subject to future liabilities or the suspension of current manufacturing operations. In addition, such regulations could restrict our ability to expand our operations or could require us to acquire costly equipment, substitute materials, or incur other significant expenses to comply with government regulations. +Our stock price is volatile. +Holders of the common stock will suffer immediate dilution to the extent outstanding equity awards are exercised to purchase common stock. Our stock price may be subject to wide fluctuations and possible rapid increases or declines over a short time period. These fluctuations may be due to factors specific to us such as variations in quarterly operating results or changes in earnings estimates, or to factors relating to the EMS industry or to the securities markets in general, which, in recent years, have experienced significant price fluctuations. These fluctuations often have been unrelated to the operating performance of the specific companies whose stocks are traded. +Due to inherent limitations, there can be no assurance that our system of disclosure and internal controls and procedures will be successful in preventing all errors, theft and fraud, or in informing management of all material information in a timely manner. +Management does not expect that our disclosure controls and internal controls and procedures will prevent all errors or fraud. A control system is designed to give reasonable, but not absolute, assurance that the objectives of the control system are met. In addition, any control system reflects resource constraints and the benefits of controls must be considered relative to their costs. Inherent limitations of a control system may include: judgments in decision making may be faulty, breakdowns can occur simply because of error or mistake and controls can be circumvented by collusion or management override. Due to the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and may not be detected. +If we do not manage our growth effectively, our profitability could decline. +Our business is experiencing rapid growth which can place considerable additional demands upon our management team and our operational, financial and management information systems. Our ability to manage growth effectively requires us to continue to implement and improve these systems; avoid cost overruns; maintain customer, supplier and other favorable business relationships during possible transition periods; continue to develop the management skills of our managers and supervisors; and continue to train, motivate and manage our employees. Our failure to effectively manage growth could have a material adverse effect on our results of operations. +If our manufacturing processes and services do not comply with applicable statutory and regulatory requirements, or if we manufacture products containing design or manufacturing defects, demand for our services may decline and we may be subject to liability claims. +We manufacture and design products to our customers’ specifications, and, in some cases, our manufacturing processes and facilities may need to comply with applicable statutory and regulatory requirements. For example, medical devices that we manufacture or design, as well as the facilities and manufacturing processes that we use to produce them, are regulated by the Food and Drug Administration and non-U.S. counterparts of this agency. In addition, our customers’ products and the manufacturing processes that we use to produce them often are highly complex. As a result, products that we manufacture may at times contain manufacturing or design defects, and our manufacturing processes may be subject to errors or not be in compliance with applicable statutory and regulatory requirements. Defects in the products we manufacture or design, whether caused by a design, manufacturing or component failure or error, or deficiencies in our manufacturing processes, may result in delayed shipments to customers or reduced or canceled customer orders. If these defects or deficiencies are significant, our business reputation may also be damaged. The failure of the products that we manufacture or our manufacturing processes and facilities to comply with applicable statutory and regulatory requirements may subject us to legal fines or penalties and, in some cases, require us to shut down or incur considerable expense to correct a manufacturing process or facility. Our customers are required to indemnify us against liability associated with designing products to meet their specifications. However, if our customers are responsible for the defects, they may not, or may not have resources to, assume responsibility for any costs or liabilities arising from these defects, which could expose us to additional liability claims. +12 +Energy price increases may negatively impact our results of operations. +Certain components that we use in our manufacturing process are petroleum-based. In addition, we, along with our suppliers and customers, rely on various energy sources in our transportation activities. While significant uncertainty currently exists about the future levels of energy prices, a significant increase is possible. Increased energy prices could cause an increase to our raw material costs and transportation costs. In addition, increased transportation costs of certain of our suppliers and customers could be passed along to us. We may not be able to increase our product prices enough to offset these increased costs. In addition, any increase in our product prices may reduce our future customer orders and profitability. +Disruptions to our information systems, including security breaches, losses of data or outages, could adversely affect our operations. +We rely on information technology networks and systems to process, transmit and store electronic information. In particular, we depend on our information technology infrastructure for a variety of functions, including worldwide financial reporting, inventory management, procurement, invoicing and email communications. Any of these systems may be susceptible to outages due to fire, floods, power loss, telecommunications failures, terrorist attacks and similar events. Despite the implementation of network security measures, our systems and those of third parties on which we rely may also be vulnerable to computer viruses, break-ins and similar disruptions. If we or our vendors are unable to prevent such outages and breaches, our operations could be disrupted. +We are involved in various legal proceedings. +In the past, we have been notified of claims relating to various matters including contractual matters, intellectual property rights or other issues arising in the ordinary course of business. In the event of such a claim, we may be required to spend a significant amount of money to defend or otherwise address the claim. Any litigation, even where a claim is without merit, could result in substantial costs and diversion of resources. Accordingly, the resolution or adjudication of such disputes, even those encountered in the ordinary course of business, could have a material adverse effect on our business, consolidated financial conditions and results of operations. +Increases in our own market capitalization and changes in securities laws and regulations will increase our costs and risk of noncompliance. +As a result of our increased market capitalization as of the end of our second quarter of fiscal year 2013, we are required to file as an accelerated filer. As such, we are subject to additional requirements contained in the Sarbanes-Oxley Act of 2002 (the Sarbanes-Oxley Act) and more recently the Dodd-Frank Act. The Sarbanes-Oxley and Dodd-Frank Acts required or will require changes in some of our corporate governance, securities disclosure and compliance practices. In response to the requirements of the Sarbanes-Oxley and Dodd-Frank Acts, the SEC and NASDAQ promulgated new rules and additional rulemaking is expected in the future. Compliance with these new rules and future rules has increased and may increase further our legal, financial and accounting costs as well as a potential risk of noncompliance. Absent significant changes in related rules, which we cannot assure, we anticipate some level of increased costs related to these new regulations to continue indefinitely. We also expect these developments to make it more difficult and more expensive to obtain director and officer liability insurance, and we may be forced to accept reduced coverage or incur substantially higher costs to obtain coverage. Likewise, these developments may make it more difficult for us to attract and retain qualified members of our Board of Directors or qualified management personnel. Further, the costs associated with the compliance with and implementation of procedures under these and future laws and related rules could have a material impact on our results of operations. In addition, the costs associated with noncompliance with additional securities laws and regulations could also impact our business. +We may encounter complications with acquisitions, which could potentially harm our business. +Any current or future acquisitions may require additional equity financing, which could be dilutive to our existing shareholders, or additional debt financing, which could potentially affect our credit ratings. Any downgrades in our credit ratings associated with an acquisition could adversely affect our ability to borrow by resulting in more restrictive borrowing terms. To integrate acquired businesses, we must implement our management information systems, operating systems and internal controls, and assimilate and manage the personnel of the acquired operations. The integration of acquired businesses may be further complicated by difficulties managing operations in geographically dispersed locations. The integration of acquired businesses may not be successful and could result in disruption by diverting management’s attention from the core business. In addition, the integration of acquired businesses may require that we incur significant restructuring charges or other increases in our expenses and working capital requirements, which reduce our return on invested capital. +13 +Acquisitions may involve numerous other risks and challenges including but not limited to: potential loss of key employees and customers of the acquired companies; the potential for deficiencies in internal controls at acquired companies; lack of experience operating in the geographic market or industry sector of the acquired business; constraints on available liquidity, and exposure to unanticipated liabilities of acquired companies. These and other factors could harm our ability to achieve anticipated levels of profitability at acquired operations or realize other anticipated benefits of an acquisition, and could adversely affect our consolidated business and operating results. +Our goodwill and identifiable intangible assets could become impaired, which could reduce the value of our assets and reduce net income in the year in which the write-off occurs. +Goodwill represents the excess of the cost of an acquisition over the fair value of the net assets acquired. The Company also ascribes value to certain identifiable intangible assets, which consists of customer relationships, non-compete agreements, and favorable leases, as a result of the acquisitions of Sabre and Ayrshire. The Company may incur impairment charges on goodwill or identifiable intangible assets if it determines that the fair values of goodwill or identifiable intangible assets are less than their current carrying values. The Company evaluates, on a regular basis, whether events or circumstances have occurred that indicate all, or a portion, of the carrying amount of goodwill may no longer be recoverable, in which case an impairment charge to earnings would become necessary. +Refer to Notes 1 and 15 to the consolidated financial statements and 'critical accounting policies and estimates' in management’s discussion and analysis of financial condition and results of operations for further discussion regarding the impairment testing of goodwill and identifiable intangible assets. +A decline in general economic conditions or global equity valuations could impact the judgments and assumptions about the fair value of the Company’s businesses and the Company could be required to record impairment charges on its goodwill or other identifiable intangible assets in the future, which could impact the Company’s consolidated balance sheet, as well as the Company’s consolidated statement of operations. If the Company was required to recognize an impairment charge in the future, the charge would not impact the Company's consolidated cash flows, current liquidity, capital resources, and covenants under its existing credit facilities. +Item 1B. +UNRESOLVED STAFF COMMENTS +None +14 +Item 2. +PROPERTIES AS OF DATE OF FILING +We have manufacturing and sales operations located in the United States, Mexico, and China. The table below lists the locations and square footage of our operating facilities: +Location +Approx. +Sq. Ft. +Type of Interest +(Leased/Owned) +Description of Use +Spokane Valley, Washington +95,000 +Leased +Sales, research, administration and manufacturing +Spokane Valley, Washington +36,000 +Leased +Manufacturing +Oakdale, Minnesota (1) +124,000 +Leased +Manufacturing and warehouse +Louisville, Kentucky (1) +4,000 +Leased +Administration +Harrodsburg, Kentucky (1) +22,000 +Owned +Manufacturing and warehouse +Corinth, Mississippi (1) +350,000 +Leased +Manufacturing and warehouse +Fayetteville, Arkansas (1) +175,000 +Leased +Manufacturing and warehouse +El Paso, Texas +80,000 +Leased +Shipping and warehouse +Total USA +886,000 +Juarez, Mexico +174,000 +Owned +Manufacturing +Juarez, Mexico +60,000 +Owned +Manufacturing and warehouse +Juarez, Mexico +66,000 +Owned +Manufacturing and warehouse +Juarez, Mexico +115,000 +Owned +Manufacturing and warehouse +Juarez, Mexico +103,000 +Owned +Manufacturing and warehouse +Juarez, Mexico (2) +193,000 +Leased +Warehouse +Juarez, Mexico (3) +66,000 +Leased +Manufacturing +Juarez, Mexico (4) +72,000 +Leased +Manufacturing +Total Mexico +849,000 +Shanghai, China (5) +121,000 +Leased +Manufacturing and warehouse +Shanghai, China +36,000 +Leased +Manufacturing +Total China +157,000 +Grand Total +1,892,000 +(1) +During fiscal year 2015, we completed our acquisition of Ayrshire which resulted primarily in additional manufacturing and warehouse space. +(2) +During fiscal year 2014, we amended the lease agreement whereby increasing our leased space to approximately 193,000 square feet to accommodate additional warehouse space. +(3) +During fiscal year 2014, we completed our acquisition of Sabre Manufacturing resulting in an additional 66,000 square feet of leased manufacturing space. +(4) +During fiscal year 2015, we entered into a lease agreement to expand our manufacturing space by approximately 72,000 square feet. +(5) +During fiscal year 2015, we amended the lease of our China facility whereby increasing our leased space to 121,000 square feet to accommodate additional manufacturing and warehouse space. +The geographic diversity of these locations allows us to offer services near certain of our customers and major electronics markets with the additional benefit of reduced labor costs. We consider the productive capacity of our current facilities sufficient to carry on our current business. In addition, in Juarez, Mexico one of our buildings includes adjacent vacant land that could be developed into additional manufacturing and warehouse space. +15 +All of our facilities are ISO certified to ISO 9001:2008 standards, ISO-14001 environmental standards, ISO-13485:2003 medical devices standards, AS9100C aviation, space and defense standards, ISO/TS 16949 automotive standards, ANSI/ESD S20.20-2007 Electrostatic Discharge Control Program and to Customs Trade Partnership against Terrorism (CTPAT). The Spokane, Washington facilities are additionally registered ISO/IEC 80079-34 explosive atmospheres and by the US State Department for International Traffic in Arms Regulations (ITAR). The Shanghai, China facilities are registered/certified to IS/TS 16949 automotive standard, ISO 13485 medical devices and ISO 14001 environmental. Additionally, Juarez, Mexico is registered by the NSF for water products. The Oakdale, Minnesota; Corinth, Mississippi; Fayetteville, Arkansas and Harrodsburg, Kentucky facilities are all registered by the U.S. State Department for International Traffic in Arms Regulations (ITAR). +Item 3. +LEGAL PROCEEDINGS +We are a party to certain lawsuits or claims in the ordinary course of business. We do not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on our financial position, results of operations or cash flow. +Item 4. +MINE SAFETY DISCLOSURES +Not Applicable +PART II +Item 5: +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES +Market Information +Our common stock is traded on the NASDAQ Global Market, formerly the NASDAQ National Market System under the symbol “KTCC.” Quarterly high and low sales prices for our common stock for fiscal years 2015 and 2014 were as follows: +2015 +2014 +High +Low +High +Low +First Quarter +$ +11.50 +$ +9.90 +$ +12.19 +$ +9.60 +Second Quarter +10.75 +7.50 +11.36 +9.83 +Third Quarter +10.75 +7.85 +11.44 +9.81 +Fourth Quarter +12.49 +10.39 +10.99 +10.00 +High and low stock prices are based on the daily sales prices reported by the NASDAQ Stock Market. These quotations represent prices between dealers without adjustment for markups, markdowns, and commissions, and may not represent actual transactions. +Holders and Dividends +As of June 27, 2015 , we had 715 shareholders of common stock on record. As a result of our credit agreement with Wells Fargo Bank, N.A. we are restricted from declaring or paying dividends in cash or stock without the Bank’s prior written consent. We have not paid a cash dividend and do not anticipate payment of dividends in the foreseeable future. +Equity Compensation Plan Information +Information concerning securities authorized for issuance under our equity compensation plans is set forth in Part III, Item 12 of this Annual Report, under the caption “Securities Authorized for Issuance under Equity Compensation Plans”, and that information is incorporated herein by reference. +16 +Performance Graph +Set forth below is a line graph comparing the cumulative total shareholder return on our common stock with the cumulative total return of the NASDAQ Stock Market (U.S. & Foreign) Index and the NASDAQ Electronic Components Index in fiscal 2015 . +7/3/2010 +7/2/2011 +6/30/2012 +6/29/2013 +6/28/2014 +6/27/2015 +Key Tronic Corporation +100.00 +92.62 +168.85 +212.09 +219.88 +218.44 +NASDAQ Composite +100.00 +132.14 +142.90 +169.55 +223.20 +253.21 +NASDAQ Electronic Components +100.00 +126.13 +120.00 +133.59 +184.37 +198.81 +17 +Item 6: +SELECTED FINANCIAL DATA +The following selected data is derived from our audited consolidated financial statements and should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the consolidated financial statements and related notes, and other information included in this report. +Financial Highlights +(In thousands, except for Supplemental Data and Per Share Amounts) +Fiscal Year Ended +June 27, 2015 (3) +June 28, 2014 (3) +June 29, 2013 +June 30, 2012 +July 2, 2011 +Consolidated Statements of Operations Data : +Net sales +$ +433,997 +$ +305,394 +$ +361,033 +$ +346,475 +$ +253,846 +Gross profit +33,305 +26,854 +34,512 +29,836 +20,648 +Gross margin percentage +7.7 +% +8.8 +% +9.6 +% +8.6 +% +8.1 +% +Operating income +6,653 +9,304 +18,126 +14,351 +6,939 +Operating margin percentage +1.5 +% +3.0 +% +5.0 +% +4.1 +% +2.7 +% +Net income +4,304 +7,613 +12,583 +11,626 +5,736 +Earnings per share – diluted +0.38 +0.67 +1.12 +1.07 +0.55 +Consolidated Cash Flow Data : +Cash flows provided by (used in) operations +7,667 +1,458 +29,282 +(5,066 +) +(2,569 +) +Capital expenditures +8,808 +7,763 +3,470 +4,654 +3,818 +Consolidated Balance Sheet Data : +Net working capital (1) +98,318 +71,049 +73,827 +76,236 +58,307 +Total assets +230,794 +156,660 +135,130 +150,912 +112,364 +Long-term liabilities +43,237 +848 +3,030 +19,050 +11,063 +Shareholders’ equity +100,768 +103,645 +94,160 +78,608 +68,023 +Book value per share (2) +$ +9.42 +$ +9.83 +$ +8.97 +$ +7.50 +$ +6.54 +Supplemental Data : +Number of shares outstanding at year-end +10,706,136 +10,546,750 +10,502,188 +10,481,356 +10,399,187 +Number of employees at year-end +4,866 +3,343 +2,584 +2,700 +1,997 +Approximate square footage of operational facilities +1,892,000 +1,139,000 +1,011,000 +945,000 +796,000 +(1) +Net working capital is defined as total current assets less total current liabilities. Net working capital measures the portion of current assets that are financed by long term funds and is an indicator of short term financial management. +(2) +Book value per share is defined as total shareholders’ equity divided by the number of shares outstanding at the end of the fiscal year. +(3) +Reflects the acquisition of Ayrshire on September 3, 2014 in fiscal year 2015 and Sabre on July 1, 2013 in fiscal year 2014. +18 +Item 7: +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +Overview +KeyTronicEMS is a leader in electronic manufacturing services and solutions to original equipment manufacturers of a broad range of products. We provide engineering services, worldwide procurement and distribution, materials management, world-class manufacturing and assembly services, in-house testing, and unparalleled customer service. Our international production capability provides our customers with benefits of improved supply-chain management, reduced inventories, lower transportation costs, and reduced product fulfillment time. We continue to make investments in all of our operating facilities to give us the production capacity, capabilities and logistical advantages to continue to win new business. The following information should be read in conjunction with the consolidated financial statements included herein and with Item 1A, Risk Factors included as part of this filing. +Our mission is to provide our customers with superior manufacturing and engineering services at the lowest total cost for the highest quality products, and create long-term mutually beneficial business relationships by employing our “Trust, Commitment, Results” philosophy. +Executive Summary +During fiscal year 2015, despite slowdowns by some longstanding customers, we made significant progress ramping up new programs, expanding our customer base and extending our worldwide capabilities. The major event of the year was our acquisition and successful integration of Ayrshire Electronics, which significantly increased our combined annual revenue and more than doubled our number of customers, giving us a much stronger and more diverse foundation for growth. +Net sales of $434.0 million for fiscal year 2015 increased by 42.1 percent as compared to net sales of $305.4 million in fiscal year 2014 . The increase in net sales was primarily driven by the addition of Ayrshire. Moving into the first quarter of fiscal year 2016, our new customer programs continue to steadily ramp up and we expect to see renewed sequential growth. For the first quarter of fiscal year 2016 , the Company expects to report revenue in the range of $122 million to $130 million. Future results will depend on actual levels of customers’ orders, the timing of the start-up of production of new product programs and the potential impact of the macroeconomic uncertainty. We believe that we are well positioned in the EMS industry to continue expansion of our customer base and continue long-term growth. +The concentration of our largest customers decreased during fiscal year 2015 with the top five customers’ sales decreasing to 42 percent of total sales in 2015 from 62 percent in 2014 , and 71 percent in 2013 . This decrease was primarily the result of the acquisition of Ayrshire as well as the impact of the reduction in production levels for certain longstanding customers. We continue to diversify our customer base by adding additional programs and customers. Our current customer relationships involve a variety of products, including consumer electronics, electronic storage devices, plastics, household products, gaming devices, specialty printers, telecommunications, industrial equipment, military supplies, computer accessories, electronic whiteboards, medical, educational, irrigation, automotive, transportation management, robotics, RFID, power supply, off-road vehicle equipment, fitness equipment, HVAC controls, consumer products, home building products, material handling systems and lighting equipment. +Gross profit as a percent of sales was 7.7 percent in fiscal year 2015 compared to 8.8 percent for the prior fiscal year. The decrease in gross profit as a percentage of net sales was primarily due to an unfavorable product mix and an increase in certain overhead costs partially offset by the positive impact of the Ayrshire acquisition. The level of gross margin is impacted by product mix, timing of the startup of new programs, facility utilization, pricing within the electronics industry and material costs, which can fluctuate significantly from quarter to quarter and year to year. +Operating income as a percentage of sales for fiscal year 2015 was 1.5 percent compared to 3.0 percent for fiscal year 2014 . The decrease in operating income as a percentage of net sales was primarily due to a decrease in gross profit as discussed above. +Net income for fiscal year 2015 was $4.3 million or $0.38 per diluted share, as compared to net income of $7.6 million or $0.67 per diluted share for fiscal year 2014 . The decrease in net income for fiscal year 2015 as compared to fiscal year 2014 was primarily due to a decrease in sales from longstanding customers and an increase in interest expense, partially offset by the positive impact of the Ayrshire acquisition. +19 +We maintain a strong balance sheet with a current ratio of 2.1 and a debt to equity ratio of 0.43 . Total cash provided by operating activities as defined on our cash flow statement was $7.7 million during fiscal year 2015 . We maintain sufficient liquidity for our expected future operations. As of June 27, 2015 , we had $11.6 million outstanding on our revolving line of credit with Wells Fargo Bank, N.A. As a result, $18.0 million remained available to borrow as of June 27, 2015 . We believe cash flow from operations, our borrowing capacity, our accounts receivable sale program, and equipment lease financing should provide adequate capital for planned growth over the long term. +RESULTS OF OPERATIONS +Comparison of the Fiscal Year Ended June 27, 2015 with the Fiscal Year Ended June 28, 2014 +The following table sets forth for the periods indicated certain items of the consolidated statements of income expressed as a percentage of net sales. The financial information and discussion below should be read in conjunction with the consolidated financial statements and notes contained in this Annual Report. +Fiscal Year Ended +June 27, 2015 +% of +net sales +June 28, 2014 +% of +net sales +$ change +% point +change +Net sales +$ +433,997 +100.0% +$ +305,394 +100.0% +$ +128,603 +— +Cost of sales +400,692 +92.3 +278,540 +91.2 +122,152 +1.1 +Gross profit +33,305 +7.7 +26,854 +8.8 +6,451 +(1.1) +Operating expenses: +Research, development and engineering +5,784 +1.3 +5,586 +1.8 +198 +(0.5) +Selling, general and administrative +20,868 +4.8 +11,964 +3.9 +8,904 +0.9 +Total operating expenses +26,652 +6.1 +17,550 +5.7 +9,102 +0.4 +Operating income +6,653 +1.5 +9,304 +3.0 +(2,651 +) +(1.5) +Interest expense, net +1,353 +0.3 +81 +— +1,272 +0.3 +Income before income taxes +5,300 +1.2 +9,223 +3.0 +(3,923 +) +(1.8) +Income tax provision +996 +0.2 +1,610 +0.5 +(614 +) +(0.3) +Net income +$ +4,304 +1.0% +$ +7,613 +2.5% +$ +(3,309 +) +(1.5) +Effective income tax rate +18.8 +% +17.5 +% +Net Sales +The increase in net sales from prior year was primarily driven by an approximate $124.6 million increase in revenue related to Ayrshire and by an approximate $17.3 million increase in revenues related to new program wins, partially offset by an approximate $7.0 million decrease in revenue related to decreased demand from current customer programs and an approximate $6.3 million decrease in revenue related to program losses. +The following table shows the revenue by industry sectors as a percentage of revenue for fiscal years 2015 and 2014 : +Fiscal Year Ended +June 27, 2015 +June 28, 2014 +Industrial and Commercial Printer +34% +17% +Consumer +28 +30 +Communication +16 +23 +Transportation +8 +— +Gaming +6 +15 +Transaction Printer +6 +11 +Computer and Peripheral +2 +4 +Total +100% +100% +We provide services to customers in a number of industries and produce a variety of products for our customers in each industry. As we continue to diversify our customer base and win new customers, we will continue to see a change in the industry concentrations of our revenue. +Sales to foreign locations outside the United States represented 30.4 percent and 35.3 percent of our total net sales in fiscal years 2015 and 2014 , respectively. +20 +Cost of Sales +Total cost of sales as a percentage of net sales was 92.3 percent and 91.2 percent in fiscal years 2015 and 2014 , respectively. +Total cost of materials as a percentage of net sales was approximately 64.6 percent and 64.5 percent in fiscal years 2015 and 2014 , respectively. The change from year-to-year was relatively flat and resulted from an increase in material cost as a percentage of net sales from certain customers which were partially offset by the lower material costs as a percentage of net sales from Ayrshire customers. +Production and support costs as a percentage of net sales were 27.7 percent and 26.7 percent in fiscal years 2015 and 2014 , respectively. The increase in fiscal year 2015 is primarily related to inefficiencies associated with ramping production of new products that resulted in higher than expected operating expenses during the first quarter of fiscal year 2015. +We provide a reserve for obsolete and non-saleable inventories based on specific identification of inventory against current demand and recent usage. The amounts charged to expense for these inventories were approximately $0.5 million and $0.3 million in fiscal years 2015 and 2014 , respectively. +We provide warranties on certain products we sell and estimate warranty costs based on historical experience and anticipated product returns. Warranty expense is related to workmanship claims on keyboards and EMS products. The amounts charged to expense are determined based on an estimate of warranty exposure. The net warranty expense was approximately $115,000 and $35,000 in fiscal years 2015 and 2014 , respectively. +Gross Profit +Gross profit as a percentage of net sales was 7.7 percent and 8.8 percent in fiscal years 2015 , and 2014 , respectively. The 1.1 percentage point decrease in gross profit as a percentage of net sales during fiscal year 2015 as compared to fiscal year 2014 is primarily related to a 1.0 percentage point increase in certain overhead costs and a 0.1 percentage point increase in material costs. +Changes in gross profit margins reflect the impact of a number of factors that can vary from period to period, including product mix, start-up costs and efficiencies associated with new programs, product life cycles, sales volumes, capacity utilization of our resources, management of inventories, component pricing and shortages, end market demand for customers’ products, fluctuations in and timing of customer orders, and competition within the EMS industry. These and other factors can cause variations in operating results. There can be no assurance that gross margins will not decrease in future periods. +We took early pay discounts to suppliers that totaled approximately $1.5 million and $1.1 million in fiscal years 2015 and 2014 , respectively. Early pay discounts will fluctuate based on our liquidity and changes in the discounts and terms offered by our suppliers. +Research, Development and Engineering +Research, development and engineering expenses (RD&E) consists principally of employee related costs, third party development costs, program materials, depreciation and allocated information technology and facilities costs. Total RD&E expense was $5.8 million and $5.6 million in fiscal years 2015 and 2014 , respectively. Total RD&E expenses as a percent of net sales were 1.3 percent and 1.8 percent in fiscal years 2015 and 2014 , respectively. This 0.5 percentage point decrease in RD&E as a percentage of net sales is primarily related to the increase in revenue as a result of the Ayrshire acquisition as well as a slight decrease in certain overhead expenses. +Selling, General and Administrative +Selling, general and administrative expenses (SG&A) consist principally of salaries and benefits, advertising and marketing programs, sales commissions, travel expenses, provision for doubtful accounts, facilities costs, and professional services. Total SG&A expenses were $20.9 million and $12.0 million in fiscal years 2015 and 2014 , respectively. Total SG&A expenses as a percent of net sales were 4.8 percent and 3.9 percent in fiscal years 2015 and 2014 , respectively. This 0.9 percentage point increase in SG&A as a percentage of net sales is primarily related to the inclusion of Ayrshire’s SG&A costs, non-recurring closing costs associated with the Ayrshire acquisition, and an increase in payroll related costs. +21 +Interest Expense +We had net interest expense of $1.4 million and $0.1 million in fiscal years 2015 and 2014 , respectively. This increase in interest expense is primarily related to an increase in the average balance outstanding on our line of credit, term loan and factored receivables that were primarily used for the acquisition of Ayrshire. +Income Tax Provision +We had an income tax expense of $1.0 million during fiscal year 2015 as compared to an income tax expense of $1.6 million in fiscal year 2014 . The income tax expense recognized during both fiscal years 2015 and 2014 was primarily a function of U.S. and foreign taxes recognized at the statutory rates offset by the net benefit associated with federal research and development tax credits, changes in potential foreign tax credits and changes in foreign tax regimes. The impact of this offset was greater in 2014 because the Company recognized a one-time benefit related to the repeal of the IETU tax regime in Mexico during fiscal year 2014. +We continually review our requirements for liquidity domestically to fund current operations, revenue growth and to look for potential future acquisitions. We anticipate repatriating a portion of our unremitted foreign earnings. The associated taxes and potential foreign tax credits are included in the income tax calculation. For further information on taxes please review footnote 6 of the “Notes to Consolidated Financial Statements.” +International Subsidiaries +We offer customers a complete global manufacturing solution. Our facilities provide our customers the opportunity to have their products manufactured in the facility that best serves specific cost, product manufacturing and distribution needs. The locations of active foreign subsidiaries are as follows: +• +Key Tronic Juarez, SA de CV owns five facilities and leases three facilities in Juarez, Mexico. These facilities include an SMT facility, an assembly and molding facility, a sheet metal fabrication facility, and assembly and storage facilities. This subsidiary is primarily used to support our U.S. operations. +• +Key Tronic Computer Peripherals (Shanghai) Co., Ltd. leases two facilities with SMT, assembly, global purchasing and warehouse capabilities in Shanghai, China, which began operations in 1999. Its primary function is to provide EMS services for export; however, it is also currently manufacturing certain electronic keyboards. +Foreign sales (based on shipping instructions) from our worldwide operations, including domestic exports, were $132.1 million , $107.7 million and $115.0 million in fiscal years 2015 , 2014 and 2013 , respectively. Products and manufacturing services provided by our subsidiary operations are primarily sold to customers directly by the parent company. Key Tronic Computer Peripherals (Shanghai) Co., Ltd., our subsidiary in Shanghai, China, had an immaterial amount of direct sales to customers in China during the past three fiscal years. +22 +RESULTS OF OPERATIONS +Comparison of the Fiscal Year Ended June 28, 2014 with the Fiscal Year Ended June 29, 2013 +The following table sets forth for the periods indicated certain items of the consolidated statements of income expressed as a percentage of net sales. The financial information and discussion below should be read in conjunction with the consolidated financial statements and notes contained in this Annual Report. +Fiscal Year Ended +June 28, 2014 +% of +net sales +June 29, 2013 +% of +net sales +$ change +% point +change +Net sales +$ +305,394 +100.0% +$ +361,033 +100.0% +$ +(55,639 +) +— +Cost of sales +278,540 +91.2 +326,521 +90.4 +(47,981 +) +0.8 +Gross profit +26,854 +8.8 +34,512 +9.6 +(7,658 +) +(0.8) +Operating expenses: +Research, development and engineering +5,586 +1.8 +5,156 +1.4 +430 +0.4 +Selling, general and administrative +11,964 +3.9 +11,230 +3.1 +734 +0.8 +Total operating expenses +17,550 +5.7 +16,386 +4.5 +1,164 +1.2 +Operating income +9,304 +3.0 +18,126 +5.0 +(8,822 +) +(2.0) +Interest expense, net +81 +— +271 +0.1 +(190 +) +(0.1) +Income before income taxes +9,223 +3.0 +17,855 +4.9 +(8,632 +) +(1.9) +Income tax provision +1,610 +0.5 +5,272 +1.5 +(3,662 +) +(1.0) +Net income +$ +7,613 +2.5% +$ +12,583 +3.5% +$ +(4,970 +) +(1.0) +Effective income tax rate +17.5 +% +29.5 +% +Net Sales +The decrease in net sales from prior year was primarily driven by an approximate $67.4 million decrease in revenues related to decreased demand from current customer programs, an approximate $5.2 million decrease in revenues related to program losses, partially offset by a $17.0 million increase in revenues related to new program wins and the revenue generated from the acquisition of Sabre. +The following table shows the revenue by industry sectors as a percentage of revenue for fiscal years 2014 and 2013: +Fiscal Year Ended +June 28, 2014 +June 29, 2013 +Consumer +30% +24% +Communication +23 +29 +Industrial and Commercial Printer +17 +8 +Gaming +15 +22 +Transaction Printer +11 +11 +Computer and Peripheral +4 +6 +Total +100% +100% +We provide services to customers in a number of industries and produce a variety of products for our customers in each industry. As we continue to diversify our customer base and win new customers we may continue to see a change in the industry concentrations of our revenue. +Sales to foreign locations outside the United States represented 35.3 percent, and 31.8 percent of our total net sales in fiscal years 2014, and 2013, respectively. +23 +Cost of Sales +Total cost of sales as a percentage of net sales was 91.2 percent and 90.4 percent in fiscal years 2014, and 2013, respectively. +Total cost of materials as a percentage of net sales was approximately 64.5 percent and 68.5 percent in fiscal years 2014 and 2013, respectively. The change from year-to-year is primarily the result of a change in product mix and to a lesser degree improved pricing of certain raw materials. +Production and support costs as a percentage of net sales were 26.7 percent and 21.9 percent in fiscal years 2014 and 2013, respectively. The increase in fiscal year 2014 is primarily related to adding headcount and manufacturing capacity to support new programs. +We provide a reserve for obsolete and non-saleable inventories based on specific identification of inventory against current demand and recent usage. The amounts charged to expense for these inventories were approximately $0.3 million, and $0.5 million in fiscal years 2014 and 2013, respectively. +We provide warranties on certain products we sell and estimate warranty costs based on historical experience and anticipated product returns. Warranty expense is related to workmanship claims on keyboards and EMS products. The amounts charged to expense are determined based on an estimate of warranty exposure. The net warranty expense was approximately $35,000 and $26,000 in fiscal years 2014 and 2013, respectively. +Gross Profit +Gross profit as a percentage of net sales was 8.8 percent and 9.6 percent in fiscal years 2014, and 2013, respectively. The 0.8 percentage point decrease in gross profit as a percentage of net sales during fiscal year 2014 as compared to fiscal year 2013 is primarily related to a 5.1 percentage point increase in certain overhead costs, partially offset by a 4.3 percentage point improvement in material costs. +Changes in gross profit margins reflect the impact of a number of factors that can vary from period to period, including product mix, start-up costs and efficiencies associated with new programs, product life cycles, sales volumes, capacity utilization of our resources, management of inventories, component pricing and shortages, end market demand for customers’ products, fluctuations in and timing of customer orders, and competition within the EMS industry. These and other factors can cause variations in operating results. There can be no assurance that gross margins will not decrease in future periods. +We took early pay discounts to suppliers that totaled approximately $1.1 million and $0.9 million in fiscal years 2014 and 2013, respectively. Early pay discounts will fluctuate based on our liquidity and changes in the discounts and terms offered by our suppliers. +Research, Development and Engineering +Research, development and engineering expenses (RD&E) consists principally of employee related costs, third party development costs, program materials, depreciation and allocated information technology and facilities costs. Total RD&E expense was $5.6 million and $5.2 million in fiscal years 2014 and 2013, respectively. This $0.4 million increase is primarily the result of an increase in payroll related expenses as additional headcount was necessary to support new program wins and anticipated future growth. +Total RD&E expenses as a percent of net sales were 1.8 percent and 1.4 percent in fiscal years 2014 and 2013, respectively. This 0.4 percentage point increase in RD&E is primarily related to a slight increase in headcount in program management and engineering to support new program wins and anticipated future growth coupled with the decline in revenue. +Selling, General and Administrative +Selling, general and administrative expenses (SG&A) consist principally of salaries and benefits, advertising and marketing programs, sales commissions, travel expenses, provision for doubtful accounts, facilities costs, and professional services. Total SG&A expenses were $12.0 million and $11.2 million in fiscal years 2014 and 2013, respectively. This $0.7 million increase is primarily related to an increase in payroll related expenses due to increased headcount. In addition, SG&A expenses for fiscal year 2013, included a positive impact of a non-recurring adjustment of approximately $0.5 million related to the reversal of a deferred compensation liability. +Total SG&A expenses as a percent of net sales were 3.9 percent and 3.1 percent in fiscal years 2014 and 2013, respectively. This 0.8 percent percentage point increase in SG&A is primarily related to an increase in labor related expenses and the decrease in net sales. +24 +Interest Expense +We had net interest expense of $0.1 million and $0.3 million in fiscal years 2014 and 2013, respectively. This decrease in interest expense is primarily related to a decrease in the average balance outstanding on our line of credit and to a lesser extent paying down existing capital leases. +Income Tax Provision +We had an income tax expense of $1.6 million during fiscal year 2014 as compared to an income tax expense of $5.3 million in fiscal year 2013. The income tax expense recognized during both fiscal years 2014 and 2013 was primarily a function of U.S. and foreign taxes recognized at the statutory rates offset by the net benefit associated with federal research and development tax credits, changes in potential foreign tax credits and changes in foreign tax regimes. The impact of this offset was greater in 2014 because the Company recognized a one-time benefit related to the repeal of the IETU tax regime in Mexico during fiscal year 2014. +We continually review our requirements for liquidity domestically to fund current operations, revenue growth and to look for potential future acquisitions. We continue to anticipate repatriating a portion of our unremitted foreign earnings. The associated taxes and potential foreign tax credits are included in the income tax calculation. For further information on taxes please review footnote 6 of the “Notes to Consolidated Financial Statements.” +Capital Resources and Liquidity +Operating Cash Flow +Net cash provided by operating activities for fiscal year 2015 was $7.7 million compared to net cash provided by operating activities of $1.5 million and $29.3 million in fiscal years 2014 and 2013 , respectively. +The working capital year-over-year change is primarily related to an $18.0 million increase in accounts payable, offset by a $14.7 million increase in inventory and a $2.1 million increase in accounts receivable after the $7.3 million impact of factoring. The working capital changes during fiscal year 2014 were primarily due to a $10.5 million increase in inventory, a $2.7 million increase in accounts receivable, partially offset by a $6.1 million increase in accounts payable. The working capital changes during fiscal year 2013 are primarily due to a $13.3 million decrease in inventory and a $13.6 million decrease in accounts receivable, which were partially offset by a $16.6 million decrease in accounts payable. +Accounts receivable fluctuates based on the timing of shipments, terms offered and collections. In addition, accounts receivable will fluctuate based upon the amount of accounts receivable sold under our Trade Accounts Receivable Purchase Program. During fiscal year 2015 , we received cash proceeds of $7.3 million from accounts receivable sold to WFB, which are not included on our Consolidated Balance Sheet. The Company did not have the Trade Accounts Receivable Purchase Program during fiscal year 2014 . We purchase inventory based on customer forecasts and orders, and when those forecasts and orders change, the amount of inventory may also fluctuate. Accounts payable fluctuates with changes in inventory levels, volume of inventory purchases, negotiated supplier terms, and taking advantage of early pay discounts. +Investing Cash Flow +Cash flows used in investing activities were $48.1 million , $13.8 million , and $3.3 million in fiscal years 2015 , 2014 and 2013 , respectively. Our primary investing activity during fiscal year 2015 , was the acquisition of Ayrshire as discussed in further detail in footnote 14 of the “Notes to Consolidated Financial Statements.” Our primary investing activity during fiscal year 2014, was the acquisition of Sabre as discussed in further detail in footnote 14 of the “Notes to Consolidated Financial Statements.” Our primary investing activity during fiscal year 2013 related to the purchase of property and equipment. +Operating and capital leases are often utilized when potential technical obsolescence and funding requirement advantages outweigh the benefits of equipment ownership. Capital expenditures and periodic lease payments are expected to be financed with internally generated funds and available borrowing capacities. During fiscal year 2015 , we received $8.6 million of cash resulting from the sale and leaseback of equipment under operating leases. We did not enter into sale and leaseback transactions during fiscal year 2014 or fiscal year 2013. +Financing Cash Flow +On September 3, 2014, we entered into an amended credit agreement which provided the Company with a term loan in the amount of $35.0 million. As of June 27, 2015, our credit agreement with Wells Fargo Bank N.A. provided a revolving line of credit facility of up to $30 million, subject to availability. +25 +Cash flows provided by financing activities was $35.0 million in fiscal year 2015 as compared to cash flows provided by financing activities of $7.3 million and cash flows used in financing activities of $15.7 million in fiscal years 2014 and 2013 , respectively. Our primary financing activities during fiscal year 2015 , was borrowings on our term loan of $31.3 million , net of repayments, related to the Ayrshire acquisition as well as borrowings and repayments under our revolving line of credit facility. Our primary financing activities in fiscal years 2014 and 2013 , were borrowings and repayments under our revolving line of credit facility and principal payments on our capital lease obligations. Additionally, the Company received $7.9 million in cash as a result of our accounts receivable transfer program with Wells Fargo Bank N.A. during fiscal year 2014. The Company did not receive any cash related to the accounts receivable purchase program during fiscal year 2013. +As of June 27, 2015 , the Company had an outstanding balance on the line of credit of $11.6 million . We had availability to borrow an additional $18.0 million under the Wells Fargo line of credit and we were in compliance with our loan covenants. Our cash requirements are affected by the level of current operations and new EMS programs. We believe that projected cash from operations, funds available under the revolving credit facility and leasing capabilities will be sufficient to meet our working and fixed capital requirements for the foreseeable future. Subsequent to June 27, 2015, the Company entered into a first amendment to the amended and restated credit agreement extending the limit on our line of credit facility to $45 million from $30 million. The agreement specifies that the proceeds of the revolving line of credit be used primarily for working capital and general corporate purposes of the Company and its subsidiaries. +As of June 27, 2015 , we had approximately $0.4 million of cash held by foreign subsidiaries. If cash is to be repatriated in the future from these foreign subsidiaries, the Company could be subject to additional income taxes payable in the U.S. The total amount of U.S. taxes required to be paid for the amount of foreign subsidiary cash on hand as of June 27, 2015 would approximate $37,000. The Company also has approximately $23.3 million of foreign earnings that have not been repatriated to the U.S. Of that amount, the Company estimates that $10.6 million is to be repatriated in the future, requiring U.S. taxes of $1.4 million that is currently accrued in our deferred tax liabilities. The remaining $12.7 million is considered to be permanently reinvested in Mexico and China. If these amounts were required to be repatriated it would create an additional $2.5 million U.S. tax liability. +Contractual Obligations and Commitments +In the normal course of business, we enter into contracts which obligate us to make payments in the future. The table below sets forth our significant future obligations by fiscal year: +Payments Due by Fiscal Year (in thousands) +Total +2016 +2017 +2018 +2019 +2020 +Thereafter +Term loan (1) +$ +31,250 +$ +5,000 +$ +5,000 +$ +5,000 +$ +5,000 +$ +11,250 +$ +— +Wells Fargo Bank N.A. revolving loan (2) +$ +11,631 +$ +— +$ +— +$ +— +$ +— +$ +11,631 +$ +— +Operating leases (3) +$ +16,064 +$ +5,552 +$ +4,245 +$ +3,099 +$ +1,297 +$ +1,225 +$ +646 +Purchase orders (4) +(1) +The terms of the Wells Fargo Bank N.A. term loan are discussed in the consolidated financial statements at Note 4, “Long-Term Debt.” Principal on the term loan is payable in equal quarterly installments of $1.25 million commencing on December 15, 2014 and continuing through June 15, 2019, with final installment of all remaining unpaid principal due on August 31, 2019. +(2) +The terms of the Wells Fargo Bank N.A. revolving loan are discussed in the consolidated financial statements at Note 4, “Long-Term Debt.” As of June 27, 2015 , we were in compliance with our loan covenants. Breaching these covenants could have resulted in a material impact on our operations or financial condition and could impact our ability to borrow under this facility in the future. +(3) +We maintain vertically integrated manufacturing operations in the United States, Mexico and China. We lease some of our administrative and manufacturing facilities and equipment. A complete discussion of properties can be found in Part 1, Item 2 at “Properties.” Leases have proven to be an acceptable method for us to acquire new or replacement equipment and to maintain facilities with a minimum impact on our short term cash flows for operations. In addition, such operations are heavily dependent upon technically superior manufacturing equipment including molding machines in various tonnages, Surface Mount Technology (SMT) lines, sheet metal fabrication and stamping machines, clean rooms, and automated insertion, and test equipment for the various products we are capable of producing. +26 +(4) +As of June 27, 2015 , we had open purchase order commitments for materials and other supplies of approximately $74.0 million. Included in the open purchase orders are various blanket orders for annual requirements. Actual needs under these blanket purchase orders fluctuate with our manufacturing levels and as such cannot be broken out between fiscal years. In addition, we have contracts with many of our customers that minimize our exposure to losses for material purchased within lead-times necessary to meet customer forecasts. Purchase orders generally can be cancelled without penalty within specified ranges that are determined in negotiations with our suppliers. These agreements depend in part on the type of materials purchased as well as the circumstances surrounding any requested cancellations. +In addition to the cash requirements presented above, we have various other accruals which are not included in the table above. For example, we owe our suppliers approximately $61.5 million for accounts payable and shipments in transit at the end of the fiscal year. We generally pay our suppliers in a range from 30 to 120 days depending on terms offered. These payments are financed by operating cash flows and our revolving line of credit. +We believe that cash flows generated from operations, factoring, leasing facilities, and funds available under the revolving credit facility will satisfy cash requirements for a period in excess of 12 months and into the foreseeable future. +Critical Accounting Policies and Estimates +Preparation of our consolidated financial statements requires management to make estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses. Note 1 to our consolidated financial statements describes the significant accounting policies used in the preparation of our consolidated financial statements. Management believes the most complex and sensitive judgments, because of their significance to our consolidated financial statements, result primarily from the need to make estimates about effects of matters that are inherently uncertain. The most significant areas involving management judgments are described below. Actual results in these areas could differ from management’s estimates. +Revenue +Sales revenue from manufacturing is recognized upon shipment of the manufactured product per contractual terms. Upon shipment, title transfers and the customer assumes risks and rewards of ownership of the product. The price to the buyer is fixed or determinable and recoverability is reasonably assured. Unless specifically stated in contractual terms, there are no formal customer acceptance requirements or further obligations related to the manufacturing services; if any such requirements exist, then sales revenue is recognized at the time when such requirements are completed and such obligations are fulfilled. Revenue is recorded net of estimated returns of manufactured product based on management’s analysis of historical returns. +Revenues and associated costs from engineering design, development services and tooling, which are performed under contract of short term durations, are recognized only after the completed performance of the service. +Inactive, Obsolete, and Surplus Inventory Reserve +We reserve for inventories that we deem inactive, obsolete or surplus. This reserve is calculated based upon the demand for the products that we produce. Demand is determined by expected sales, customer purchase orders, or customer forecasts. If expected sales do not materialize, then we would have inventory in excess of our reserves and would have to charge the excess against future earnings. In the case where we have purchased material based upon a customer’s forecast or purchase orders, we are usually covered by lead-time assurance agreements or purchase orders with each customer. These contracts state that the financial liability for material purchased within agreed upon lead-time and based upon the customer’s forecasts, lies with the customer. If we purchase material outside the lead-time assurance agreement and the customer’s forecasts do not materialize or if we have no lead-time assurance agreement for a specific program, we would have the financial liability and may have to charge inactive, obsolete or surplus inventory against earnings. +Allowance for Doubtful Accounts +We value our accounts receivable net of an allowance for doubtful accounts. As of June 27, 2015 , the allowance for doubtful accounts was $0.1 million . As of June 28, 2014 , no allowance was deemed necessary. This allowance is based on estimates of the portion of accounts receivable that may not be collected in the future. The estimates used are based primarily on specific identification of potentially uncollectible accounts. Such accounts are identified using publicly available information in conjunction with evaluations of current payment activity. However, if any of our customers were to develop unexpected and immediate financial problems that would prevent payment of open invoices, we could incur additional and possibly material expenses that would negatively impact earnings. +27 +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. We review the adequacy of this accrual quarterly based on historical analysis and anticipated product returns and rework costs. As we have made the transition from manufacturing primarily keyboards to primarily EMS products, our exposure to warranty claims has declined significantly. Our warranty period for keyboards is generally longer than that for EMS products. We only warrant materials and workmanship on EMS products, and we do not warrant design defects for EMS customers. +Income Taxes +Income tax expense includes U.S. and international income taxes and the provision for U.S. taxes on undistributed earnings of foreign subsidiaries not deemed to be permanently invested. We do not record U.S. tax liabilities on undistributed earnings of international subsidiaries that are deemed to be permanently reinvested. Certain income and expenses are not reported in tax returns and financial statements in the same year. The tax effect of such temporary differences is reported as deferred income taxes. The deferred income taxes are classified as current or long-term based on the classification of the related asset or liability. The most significant areas involving management judgments include deferred income tax assets and liabilities, uncertain tax positions, and research and development tax credits. Our estimates of the realization of the deferred tax assets related to our tax credits are based upon our estimates of future taxable income which may change. +Stock-Based Compensation +Stock-based compensation is accounted for according to Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 718, Compensation—Stock Compensation . ASC 718 requires us to expense the fair value of employee stock options, stock appreciation rights and other forms of stock-based compensation. Under the fair value recognition provisions of ASC 718, share-based compensation cost is estimated at the grant date based upon the fair value of the award and is recognized as expense ratably over the requisite service period of the award (generally the vesting period). Determining the appropriate fair value model and calculating the fair value of share-based awards requires judgment, including estimating the expected life of the share-based award, the expected stock price volatility over the expected life of the share-based award and forfeitures. +To determine the fair value of stock based awards on the date of grant we use the Black-Scholes option-pricing model. Inherent in this model are assumptions related to expected stock price volatility, option life, risk-free interest rate and dividend yield. The risk-free interest rate is a less-subjective assumption as it is based on factual data derived from public sources. We use a dividend yield of zero as we have never paid cash dividends and have no intention to pay cash dividends in the foreseeable future. The expected stock price volatility and option life assumptions require a greater level of judgment. Our expected stock-price volatility assumption is based upon the historical volatility of our stock which is obtained from public data sources. The expected life represents the weighted average period of time that share-based awards are expected to be outstanding, giving consideration to vesting schedules and historical exercise patterns. We determine the expected life assumption based upon the exercise and post-vesting behavior that has been exhibited historically, adjusted for specific factors that may influence future exercise patterns. If expected volatility or expected life were to increase, that would result in an increase in the fair value of our stock options which would result in higher compensation charges, while a decrease in volatility or the expected life would result in a lower fair value of our stock option awards resulting in lower compensation charges. +We estimate forfeitures for all of our awards based upon historical experience of stock-based pre-vesting forfeitures. We believe that our estimates are based upon outcomes that are reasonably likely to occur. If actual forfeitures are higher than our estimates it would result in lower compensation expense and to the extent the actual forfeitures are lower than our estimate we would record higher compensation expense. +Impairment of Long-Lived Assets +Long-lived assets, such as property, plant, and equipment are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment charge would be recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. +28 +Derivatives and Hedging Activity +Derivatives are recognized on the balance sheet at their estimated fair value. On the date a derivative contract is entered into, the Company designates the derivative as a hedge of a forecasted transaction or of the variability of cash flows to be received or paid related to a recognized asset or liability (a “cash flow” hedge). The Company does not enter into derivatives for speculative purposes. Changes in the fair value of a derivative that qualifies as a cash flow hedge are recorded in “Accumulated Other Comprehensive Income”, until earnings are affected by the variability of cash flows. See Note 11 of the Company’s consolidated financial statements for additional information. +Long-Term Incentive Compensation Accrual +Long-term incentive compensation is recognized as expense ratably over the requisite service period of the award which is generally three years. The Board of Directors approve target performance measures for the three year period for each of the Company’s officers and non-employee Directors. Performance measures are based on a combination of sales growth targets and return on invested capital targets. No cash awards will be made to participants if actual Company performance does not exceed the minimum target performance measures. The calculation used to determine the necessary accrual uses a combination of actual results and projected results. We believe that our estimates are based upon outcomes that are reasonably likely to occur. These estimates and assumptions are based on historical results as well as future expectations. Actual results could vary from our estimates and assumptions. +Impairment of Goodwill +In accordance with ASC 350, Goodwill and Other Intangible Assets , goodwill is not amortized but is required to be reviewed for impairment at least annually or when events or circumstances indicate that carrying value may exceed fair value. The Company is permitted the option to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the fair value of any reporting unit is less than its corresponding carrying value. If, after assessing the totality of events and circumstances, the Company concludes that it is not more likely than not that the fair value of any reporting unit is less than its corresponding carrying value then the Company is not required to take further action. However, if the Company concludes otherwise, then it is required to perform a quantitative impairment test, including computing the fair value of the reporting unit and comparing that value to its carrying value. If the fair value is less than its carrying value, a second step of the test is required to determine if recorded goodwill is impaired. In the event that goodwill is impaired, an impairment charge to earnings would become necessary. The Company also has the option to bypass the qualitative assessment for goodwill in any period and proceed directly to performing the quantitative impairment test. +Business Combinations +The Company recognizes the assets acquired and liabilities assumed in business combinations on the basis of their fair values at the date of acquisition. We assess the fair value of assets, including intangible assets, using a variety of methods and each asset is measured at fair value from the perspective of a market participant. The method used to estimate the fair values of intangible assets incorporates significant assumptions regarding the estimates a market participant would make in order to evaluate an asset, including a market participant’s use of the asset and the appropriate discount rates for a market participant. Assets recorded from the perspective of a market participant that are determined to not have economic use for us are expensed immediately. Any excess purchase price over the fair value of the net tangible and intangible assets acquired is allocated to goodwill. Transaction costs and restructuring costs associated with a business combination are expensed as incurred. +New and Future Accounting Pronouncements +See Note 1 to our consolidated financial statements. +29 +Item 7A: +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Interest Rate Risk +We are subject to the risk of fluctuating interest rates in the normal course of business. Our major market risk relates to our secured debt. Our revolving credit facility and term loan are secured by substantially all of our assets. The interest rates applicable to our revolving credit facility and term loan fluctuate with the Wells Fargo Bank N.A. prime rate and LIBOR rates. There was outstanding $11.6 million in borrowings under our revolving credit facility and $31.3 million outstanding on our term loan as of June 27, 2015 . See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity” and Note 4 – “Long-Term Debt” to the Consolidated Financial Statements for additional information regarding our revolving credit facility and term loan. +During the second quarter of fiscal year 2015, we entered into an interest rate swap contract with a notional amount of $25.0 million related to the borrowings outstanding under the term loan and revolving credit facility. As of June 27, 2015 , our only material interest rate risk is associated with our revolving credit facility and term loan. Through the use of the interest rate swap, as described above, we fixed the basis on which we pay interest, thus eliminating much of our interest rate risk. See Note 11 – “Derivative Financial Instruments” to the Consolidated Financial Statements for additional information regarding our derivative instruments. +Foreign Currency Exchange Risk +A significant portion of our operations are in foreign locations. As a result, transactions occur in currencies other than the U.S. dollar. Exchange rate fluctuations among other currencies used by us would directly or indirectly affect our financial results. We currently use Mexican peso forward contracts to hedge foreign currency fluctuations for a portion of our Mexican peso denominated expenses. There was $65.0 million of foreign currency forward contracts outstanding as of June 27, 2015 . The fair value of these contracts was approximately $(7.2) million . See Note 11 – “Derivative Financial Instruments” to the Consolidated Financial Statements for additional information regarding our derivative instruments. +30 +Item 8: +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Key Tronic Corporation +Spokane Valley, Washington +We have audited the accompanying consolidated balance sheets of Key Tronic Corporation as of June 27, 2015 and June 28, 2014 and the related consolidated statements of income, comprehensive (loss) income, shareholders' equity, and cash flows for each of the three years in the period ended June 27, 2015. In connection with our audits of the financial statements, we have also audited the financial statement schedule listed in the accompanying index. These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. +We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Key Tronic Corporation at June 27, 2015 and June 28, 2014, and the results of its operations and its cash flows for each of the three years in the period ended June 27, 2015 , in conformity with accounting principles generally accepted in the United States of America. +Also, in our opinion, the financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Key Tronic Corporation's internal control over financial reporting as of June 27, 2015, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated September 4, 2015 expressed an unqualified opinion thereon. +/s/ BDO USA, LLP +Spokane, Washington +September 4, 2015 +31 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED BALANCE SHEETS +(In thousands) +June 27, 2015 +June 28, 2014 +ASSETS +Current assets: +Cash and cash equivalents +$ +372 +$ +5,803 +Trade receivables, net of allowance for doubtful accounts of $97 and $0 +72,852 +49,658 +Inventories +91,594 +55,634 +Deferred income tax asset +6,643 +935 +Other +13,646 +11,186 +Total current assets +185,107 +123,216 +Property, plant and equipment, net +26,974 +23,596 +Other assets: +Deferred income tax asset +80 +3,325 +Other +1,621 +2,712 +Goodwill +9,957 +1,740 +Other intangible assets, net +7,055 +2,071 +Total other assets +18,713 +9,848 +Total assets +$ +230,794 +$ +156,660 +LIABILITIES AND SHAREHOLDERS ’ EQUITY +Current liabilities: +Accounts payable +$ +61,528 +$ +32,459 +Accrued compensation and vacation +9,467 +7,562 +Current portion of debt +5,000 +7,853 +Other +10,794 +4,293 +Total current liabilities +86,789 +52,167 +Long-term liabilities: +Term loan +26,250 +— +Revolving loan +11,631 +— +Deferred income tax liability +501 +270 +Other long-term obligations +4,855 +578 +Total long-term liabilities +43,237 +848 +Total liabilities +130,026 +53,015 +Commitments and contingencies (Note 4 and 9) +Shareholders’ equity: +Common stock, no par value—shares authorized 25,000; issued and outstanding 10,706 and 10,547 shares, respectively +44,136 +44,151 +Retained earnings +61,395 +57,091 +Accumulated other comprehensive (loss) income +(4,763 +) +2,403 +Total shareholders’ equity +100,768 +103,645 +Total liabilities and shareholders’ equity +$ +230,794 +$ +156,660 +See accompanying notes to consolidated financial statements. +32 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF INCOME +(In thousands, except per share amounts) +Fiscal Year Ended +June 27, 2015 +June 28, 2014 +June 29, 2013 +Net sales +$ +433,997 +$ +305,394 +$ +361,033 +Cost of sales +400,692 +278,540 +326,521 +Gross profit +33,305 +26,854 +34,512 +Research, development and engineering expenses +5,784 +5,586 +5,156 +Selling, general and administrative expenses +20,868 +11,964 +11,230 +Total operating expenses +26,652 +17,550 +16,386 +Operating income +6,653 +9,304 +18,126 +Interest expense, net +1,353 +81 +271 +Income before income taxes +5,300 +9,223 +17,855 +Income tax provision +996 +1,610 +5,272 +Net income +$ +4,304 +$ +7,613 +$ +12,583 +Net income per share — Basic +$ +0.41 +$ +0.72 +$ +1.20 +Weighted average shares outstanding — Basic +10,572 +10,528 +10,490 +Net income per share — Diluted +$ +0.38 +$ +0.67 +$ +1.12 +Weighted average shares outstanding — Diluted +11,286 +11,358 +11,252 +See accompanying notes to consolidated financial statements. +33 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME +(In thousands) +Fiscal Year Ended +June 27, 2015 +June 28, 2014 +June 29, 2013 +Comprehensive (loss) income: +Net income +$ +4,304 +$ +7,613 +$ +12,583 +Other comprehensive (loss) income: +Unrealized (loss) gain on derivatives, net of tax +(7,166 +) +1,090 +1,972 +Comprehensive (loss) income +$ +(2,862 +) +$ +8,703 +$ +14,555 +Other comprehensive (loss) income for fiscal years 2015 , 2014 , and 2013 is reflected net of tax (benefit) provision of approximately $(3.7) million , $0.6 million and $1.0 million , respectively. +See accompanying notes to consolidated financial statements. +34 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Fiscal Year Ended +June 27, 2015 +June 28, 2014 +June 29, 2013 +Operating activities: +Net income +$ +4,304 +$ +7,613 +$ +12,583 +Adjustments to reconcile net income to cash provided by operating activities: +Depreciation and amortization +5,910 +3,829 +2,965 +Excess tax benefit from exercise of stock options +(50 +) +(73 +) +(103 +) +Provision for obsolete inventory +520 +257 +525 +Provision for warranty +115 +35 +26 +Provision for doubtful accounts +97 +37 +62 +Loss on disposal of property, plant and equipment +70 +12 +27 +Share-based compensation expense +732 +659 +848 +Deferred income taxes +(1,517 +) +(687 +) +2,493 +Deferred compensation +— +— +(546 +) +Changes in operating assets and liabilities, net of acquisition: +Trade receivables +(2,080 +) +(2,686 +) +13,638 +Inventories +(14,708 +) +(10,450 +) +13,250 +Other assets +(4,249 +) +(3,145 +) +(2,381 +) +Accounts payable +17,999 +6,059 +(16,625 +) +Accrued compensation and vacation +(283 +) +149 +1,148 +Other liabilities +807 +(151 +) +1,372 +Cash provided by operating activities +7,667 +1,458 +29,282 +Investing activities: +Payment for acquisition, net of cash acquired +(47,964 +) +(6,027 +) +— +Purchase of property and equipment +(8,808 +) +(7,763 +) +(3,470 +) +Proceeds from sale of fixed assets +8,641 +— +27 +Proceeds from life insurance +— +— +144 +Cash used in investing activities +(48,131 +) +(13,790 +) +(3,299 +) +Financing activities: +Payment of financing costs +(62 +) +(84 +) +(75 +) +Proceeds from issuance of long term debt +35,000 +— +— +Repayments of long term debt and capital lease obligations +(3,750 +) +(576 +) +(729 +) +Borrowings under revolving credit agreement +137,987 +8,212 +66,528 +Repayment of revolving credit agreement +(126,356 +) +(8,212 +) +(81,539 +) +Proceeds from accounts receivable transfer agreement +1,116 +7,853 +— +Payments towards accounts receivable transfer agreement +(8,969 +) +— +— +Excess tax benefit from exercise of stock options +50 +73 +103 +Proceeds from exercise of stock options +17 +50 +46 +Cash provided by (used in) financing activities +35,033 +7,316 +(15,666 +) +Net (decrease) increase in cash and cash equivalents +(5,431 +) +(5,016 +) +10,317 +Cash and cash equivalents, beginning of period +5,803 +10,819 +502 +Cash and cash equivalents, end of period +$ +372 +$ +5,803 +$ +10,819 +Supplemental cash flow information: +Interest payments +$ +1,221 +$ +90 +$ +317 +Income tax payments, net of refunds +$ +3,274 +$ +2,184 +$ +2,708 +See accompanying notes to consolidated financial statements. +35 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY +(In thousands) +Shares +Common +Stock +Retained +Earnings +Accumulated +Other +Comprehensive +Income (Loss) +Total +Shareholders’ +Equity +Balances, June 30, 2012 +10,481 +$ +42,372 +$ +36,895 +$ +(659 +) +$ +78,608 +Net income +— +— +12,583 +— +12,583 +Unrealized gain on foreign exchange contracts, net +— +— +— +1,972 +1,972 +Exercise of stock options +21 +46 +— +— +46 +Share-based compensation +— +848 +— +— +848 +Tax benefit from exercise of stock options +— +103 +— +— +103 +Balances, June 29, 2013 +10,502 +$ +43,369 +$ +49,478 +$ +1,313 +$ +94,160 +Net income +— +— +7,613 +— +7,613 +Unrealized gain on foreign exchange contracts, net +— +— +— +1,090 +1,090 +Exercise of stock options +45 +50 +— +— +50 +Share-based compensation +— +659 +— +— +659 +Tax benefit from exercise of stock options +— +73 +— +— +73 +Balances, June 28, 2014 +10,547 +$ +44,151 +$ +57,091 +$ +2,403 +$ +103,645 +Net income +— +— +4,304 +— +4,304 +Unrealized loss on derivatives, net +— +— +— +(7,166 +) +(7,166 +) +Exercise of stock options +5 +17 +— +— +17 +Exercise of stock appreciation rights +223 +— +— +— +— +Shares withheld for taxes +(69 +) +(814 +) +— +— +(814 +) +Share-based compensation +— +732 +— +— +732 +Tax benefit from exercise of stock options +— +50 +— +— +50 +Balances, June 27, 2015 +10,706 +$ +44,136 +$ +61,395 +$ +(4,763 +) +$ +100,768 +See accompanying notes to consolidated financial statements. +36 +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. SIGNIFICANT ACCOUNTING POLICIES +Business +Key Tronic Corporation and subsidiaries (the Company) is engaged in electronic manufacturing services (EMS) for original equipment manufacturers (OEMs) and also manufactures keyboards and other input devices. The Company’s headquarters are located in Spokane Valley, Washington with manufacturing operations in Oakdale, Minnesota; Fayetteville, Arkansas; Corinth, Mississippi; Harrodsburg, Kentucky; and foreign manufacturing operations in Juarez, Mexico; and Shanghai, China. +Principles of Consolidation +The consolidated financial statements include the Company and its wholly owned subsidiaries in the United States, Mexico and China. Intercompany balances and transactions have been eliminated during consolidation. +Reclassifications +Certain prior period reclassifications were made to conform with the current period presentation. These reclassifications had no effect on reported income, comprehensive income, cash flows, total assets, or shareholders' equity as previously reported. +Use of Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates include the allowance for doubtful receivables, the provision for obsolete and non-saleable inventories, deferred tax assets and liabilities, uncertain tax positions, valuation of goodwill, impairment of long-lived assets, medical self-funded insurance liability, long-term incentive compensation accrual, the provision for warranty costs, the fair value of stock appreciation rights granted under the Company’s share-based compensation plan and purchase price allocation of acquired businesses. Due to uncertainties with respect to the assumptions and estimates, actual results could differ from those estimates. +Cash and Cash Equivalents +The Company considers investments with an original maturity of three months or less to be cash equivalents. Cash equivalents are carried at cost, which approximates fair value. The Company may have cash and cash equivalents at financial institutions that are in excess of federally insured limits from time to time. +Allowance for Doubtful Accounts +The Company evaluates the collectability of accounts receivable and records an allowance for doubtful accounts, which reduces the receivables to an amount that management reasonably estimates will be collected. A specific allowance is recorded against receivables considered to be impaired based on the Company’s knowledge of the financial condition of the customer. In determining the amount of the allowance, the Company considers several factors including the aging of the receivables, the current business environment and historical experience. After all attempts to collect a receivable have failed, the receivable is written off against the allowance. +Inventories +Inventories are stated at the lower of cost or market. Cost is determined principally using the first-in, first-out (FIFO) method. Customer orders are based upon forecasted quantities of product manufactured for shipment over defined periods. Raw material inventories are purchased to fulfill these customer requirements. Within these arrangements, customer demands for products frequently change, sometimes creating excess and obsolete inventories. The Company regularly reviews raw material inventories by customer for both excess and obsolete quantities. Wherever possible, the Company attempts to recover its full cost of excess and obsolete inventories from customers or, in some cases, through other markets. When it is determined that the Company’s carrying cost of such excess and obsolete inventories cannot be recovered in full, a charge is taken against income for the difference between the carrying cost and the estimated realizable amount. +Property, Plant and Equipment +Property, plant and equipment are carried at cost and depreciated using straight-line methods over the expected useful lives of the assets. Internally constructed molds and dies are depreciated over the expected useful lives of one to two years. Repairs and maintenance costs are expensed as incurred. +37 +Business Combinations +The Company recognizes the assets acquired and liabilities assumed in business combinations on the basis of their fair values at the date of acquisition. We assess the fair value of assets, including intangible assets, using a variety of methods and each asset is measured at fair value from the perspective of a market participant. The method used to estimate the fair values of intangible assets incorporates significant assumptions regarding the estimates a market participant would make in order to evaluate an asset, including a market participant’s use of the asset and the appropriate discount rates for a market participant. Assets recorded from the perspective of a market participant that are determined to not have economic use for us are expensed immediately. Any excess purchase price over the fair value of the net tangible and intangible assets acquired is allocated to goodwill. Transaction costs and restructuring costs associated with a business combination are expensed as incurred. +Impairment of Goodwill +The Company records intangible assets that are acquired individually or with a group of other assets in the financial statements at acquisition. In accordance with ASC 350, Goodwill and Other Intangible Assets , goodwill is not amortized but is required to be reviewed for impairment at least annually or when events or circumstances indicate that carrying value may exceed fair value. +Impairment of Long-lived Assets +The Company, using its best estimates based on reasonable and supportable assumptions and projections, reviews assets for impairment whenever events or changes in circumstances have indicated that the carrying amount of its assets might not be recoverable. Impaired assets are reported at the lower of cost or fair value. +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. Management reviews the adequacy of this accrual quarterly based on historical analyses and anticipated product returns. +Self-funded Insurance +The Company self-funds one of its domestic employee health plans. The Company contracted with a separate administrative service company to supervise and administer the program and act as its representative. The Company reduces its risk under this self-funded platform by purchasing stop-loss insurance coverage for individual claims. In addition, if the aggregate annual claims amount to more than 125 percent of expected claims for the plan year this insurance will also pay those claims amounts exceeding that level. +The Company estimates its exposure for claims incurred but not paid at the end of each reporting period and uses historical claims data supplied by the Company’s broker to estimate its self-funded insurance liability. This liability is subject to a total limitation that varies based on employee enrollment and factors that are established at each annual contract renewal. Actual claims experience may differ from the Company’s estimates. Costs related to the administration of the plan and related claims are expensed as incurred. +Revenue Recognition +Sales revenue from manufacturing is recognized upon shipment of the manufactured product per contractual terms. Upon shipment, title transfers and the customer assumes risks and rewards of ownership of the product. The price to the buyer is fixed or determinable and recoverability is reasonably assured. Unless specifically stated in contractual terms, there are no formal customer acceptance requirements or further obligations related to the manufacturing services; if any such requirements exist, then sales revenue is recognized at the time when such requirements are completed and such obligations are fulfilled. Revenue is recorded net of estimated returns of manufactured product based on management’s analysis of historical returns. +Revenues and associated costs from engineering design, development services and tooling, which are performed under contract of short term durations, are recognized only after the completed performance of the service. Revenue from engineering design, development services and tooling represented approximately 2.5 percent , 3.4 percent and 2.5 percent of total revenue in fiscal years 2015 , 2014 , and 2013 , respectively. +Shipping and Handling Fees +The Company classifies costs associated with shipping and handling fees as a component of cost of goods sold. Customer billings related to shipping and handling fees are reported as revenue. +Research, Development and Engineering +Research, development and engineering expenses include unreimbursed EMS costs as well as design and engineering costs associated with the production of EMS programs. Research, development and engineering costs are expensed as incurred. +38 +Income Taxes +Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the estimated future tax consequences and benefits attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis, as well as operating losses and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities for a change in tax rates is recognized in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amount that is more likely than not to be realized. +We utilize a two-step approach to recognizing and measuring uncertain tax positions. The first step is to evaluate the tax position for recognition by determining if the weight of available evidence indicates it is more likely than not that the position will be sustained on audit, including resolution of related appeals or litigation processes, if any. The second step is to measure the tax benefit as the largest amount which is more than 50% likely of being realized upon ultimate settlement. We consider many factors when evaluating and estimating our tax positions and tax benefits, which may require periodic adjustments based on new assessments and changes in estimates and which may not accurately forecast actual outcomes. Our policy is to recognize interest and penalties related to the underpayment of income taxes as a component of income tax provision. To date, we have not incurred charges for interest or penalties in relation to the underpayment of income taxes. The tax years 1997 through the present remain open to examination by the major U.S. taxing jurisdictions to which we are subject. Refer to Note 6 for further discussions. +Derivative Instruments and Hedging Activities +The Company has entered into foreign currency forward contracts and an interest rate swap which are accounted for as cash flow hedges in accordance with ASC 815, Derivatives and Hedging . The effective portion of the gain or loss on the derivative is reported as a component of accumulated other comprehensive income (AOCI) and is reclassified into earnings in the same period in which the underlying hedged transaction affects earnings. The derivative’s effectiveness represents the change in fair value of the hedge that offsets the change in fair value of the hedged item. +The Company uses derivatives to manage the variability of foreign currency fluctuations of expenses in our Mexico facilities and interest rate risk associated with certain borrowings under the Company’s debt arrangement. The foreign currency forward contracts and interest rate swaps have terms that are matched to the underlying transactions being hedged. As a result, these transactions fully offset the hedged risk and no ineffectiveness has been recorded. +The Company’s foreign currency forward contracts and interest rate swaps potentially expose the Company to credit risk to the extent the counterparties may be unable to meet the terms of the agreement. The Company minimizes such risk by seeking high quality counterparties. The Company’s counterparties to the foreign currency forward contracts and interest rate swaps are major banking institutions. These institutions do not require collateral for the contracts, and the Company believes that the risk of the counterparties failing to meet their contractual obligations is remote. The Company does not enter into derivative instruments for trading or speculative purposes. +Earnings Per Common Share +Basic earnings per common share is computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is computed by dividing net income by the combination of other potentially dilutive weighted average common shares and the weighted average number of common shares outstanding during the period using the treasury stock method. The computation assumes the proceeds from the exercise of stock options were used to repurchase common shares at the average market price during the period. The computation of diluted earnings per common share does not assume conversion, exercise, or contingent issuance of common stock equivalent shares that would have an anti-dilutive effect on earnings per share. +Foreign Currency Transactions +The functional currency of the Company’s subsidiaries in Mexico and China is the U.S. dollar. Realized foreign currency transaction gains and losses for local currency denominated assets and liabilities are included in cost of goods sold. +Fair Value of Financial Instruments +The carrying values of cash and cash equivalents, accounts receivable and current liabilities reflected on the balance sheets at June 27, 2015 and June 28, 2014 , reasonably approximate their fair value. As of June 27, 2015 , the Company had an outstanding balance on the line of credit of $11.6 million and term loan of $31.3 million . The carrying value of debt approximates fair value. As of June 28, 2014 , the Company did not have an outstanding balance on the line of credit or term loan. +39 +Share-based Compensation +The Company’s incentive plan may provide for equity and liability awards to employees in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, stock units, performance shares, performance units, and other stock-based or cash-based awards. Compensation cost is recognized on a straight-line basis over the requisite employee service period, which is generally the vesting period, and is included in cost of goods sold, research, development and engineering, and selling, general, and administrative expenses. +Newly Adopted and Recent Accounting Pronouncements +In May 2014, FASB issued Accounting Standards Update 2014-09 (ASU 2014-09), Revenue from Contracts with Customers. The guidance in this Update affects any entity that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (for example, insurance contracts or lease contracts). The standard's core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In doing so, companies will need to use more judgment and make more estimates than under current guidance. This may include identifying performance obligations in the contract, estimating the amount of variable consideration to include in the transaction price and allocating the transaction price to each separate performance obligation. The amendments in this Update are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is not permitted. Companies have the option of using either a full or modified retrospective approach in applying this standard. The Company is in the process of assessing the impact of ASU 2014-09 on its consolidated financial statements. +In August 2014, the FASB issued Accounting Standards Update 2014-15 (ASU 2014-15), Presentation of Financial Statements - Going Concern . The guidance in this Update applies to all entities. The amendments require management to assess an entity’s ability to continue as a going concern by incorporating and expanding upon certain principles that are currently in U.S. auditing standards. Specifically, the amendments (1) provide a definition of the term substantial doubt, (2) require an evaluation every reporting period including interim periods, (3) provide principles for considering the mitigating effect of management’s plans, (4) require certain disclosures when substantial doubt is alleviated as a result of consideration of management’s plans, (5) require an express statement and other disclosures when substantial doubt is not alleviated, and (6) require an assessment for a period of one year after the date that the financial statements are issued (or available to be issued). The amendments in this Update are effective for the annual period ending after December 15, 2016, and for annual periods and interim periods thereafter. Early application is permitted. The amendments of ASU 2014-15, when adopted, are not expected to have a material impact on the Company’s consolidated financial statements. +In April 2015, the FASB issued Accounting Standards Update 2015-03 (ASU 2015-03), Simplifying the Presentation of Debt Issuance Costs . The guidance in this Update changes the presentation of debt issuance costs in financial statements. Under the new guidance, an entity presents such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. Amortization of the costs is reported as interest expense. This guidance is effective for the Company beginning in the first quarter of fiscal year 2017 and early adoption is permitted in an interim period with any adjustments reflected as of the beginning of the fiscal year that includes that interim period. The guidance is not expected to have a significant impact to the Company’s consolidated financial statements. +In July 2015, the Financial Accounting Standards Board (FASB) issued final guidance that simplifies the subsequent measurement of inventory for which cost is determined by methods other than last-in first-out (“LIFO”) and the retail inventory method. For inventory within the scope of the new guidance, entities will be required to compare the cost of inventory to only one measure, its net realizable value, and not the three measures required by the existing guidance. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The new guidance should not change how entities initially measure the cost of inventory. The guidance will be effective for the Company in the fiscal year beginning July 3, 2017. Early adoption is permitted. We have not yet determined the impact this new guidance may have on our financial statements. +Management has assessed the potential impact of recently issued, but not yet effective, accounting standards and determined that the provisions are either not applicable to the Company, or are not anticipated to have a material impact on the consolidated financial statements. +Fiscal Year +The Company operates on a 52/53 week fiscal year. Fiscal years end on the Saturday nearest June 30. As such, fiscal years 2015 , 2014 , and 2013 , ended on June 27, 2015 , June 28, 2014 , and June 29, 2013 , respectively and each year was a 52 week year. +40 +2. INVENTORIES +The components of inventories consist of the following (in thousands): +June 27, 2015 +June 28, 2014 +Finished goods +$ +8,019 +$ +5,826 +Work-in-process +15,220 +7,068 +Raw materials and supplies +68,355 +42,740 +$ +91,594 +$ +55,634 +3. PROPERTY, PLANT AND EQUIPMENT +Property, plant and equipment consists of the following: +Life +June 27, 2015 +June 28, 2014 +(in years) +(in thousands) +Land +— +$ +2,940 +$ +2,670 +Buildings and improvements +3 to 30 +23,134 +19,839 +Equipment +1 to 10 +48,126 +44,257 +Furniture and fixtures +3 to 5 +3,065 +3,029 +77,265 +69,795 +Accumulated depreciation +(50,291 +) +(46,199 +) +$ +26,974 +$ +23,596 +4. LONG-TERM DEBT +On September 3, 2014, the Company entered into an amended and restated credit agreement extending the agreement term on our $30.0 million revolving line of credit facility to August 31, 2019. In addition, the Company added a five-year term loan in the amount of $35.0 million used to acquire all of the outstanding shares of CDR Manufacturing, Inc. (dba Ayrshire Electronics). For further information on the acquisition of Ayrshire see footnote 14 of the “Notes to Consolidated Financial Statements.” +On August 6, 2015, the Company entered into a First Amendment to the amended and restated credit agreement extending the limit on our line of credit facility to $45.0 million as evidenced by the Second Replacement Revolving Note. +The agreement specifies that the proceeds of the revolving line of credit be used primarily for working capital and general corporate purposes of the Company and its subsidiaries. Borrowings under this revolving line of credit bear interest at either a “Base Rate” or a “Fixed Rate,” as elected by the Company. The base rate is the higher of the Wells Fargo Bank prime rate, daily one month London Interbank Offered Rate (LIBOR) plus 1.5% , or the Federal Funds rate plus 1.5% . The fixed rate is LIBOR plus 1.75% , LIBOR plus 2.0% or LIBOR plus 2.25% depending on the level of the Company’s trailing four quarters Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA). The revolving line of credit is secured by substantially all of the assets of the Company. +As of June 27, 2015 , the Company had an outstanding balance under the credit facility of $11.6 million , $0.3 million in outstanding letters of credit and $18.0 million available for future borrowings. The interest rate on the outstanding line of credit balance was in the range of 2.28% - 3.25% . The Company did not have an outstanding balance on the line of credit as of June 28, 2014 . +The outstanding principal balance of the term loan bears interest at a fixed rate per annum of the daily one month LIBOR plus 1.75% , 2.00% or 2.25% depending on the ratio of the Company’s funded debt to EBITDA, except that the term loan bore interest at LIBOR plus 2.00% from September 3, 2014 through December 14, 2014 regardless of the Company’s cash flow leverage ratio. Principal on the term loan is payable in equal quarterly installments of $1.25 million commencing December 15, 2014 and continuing through June 15, 2019, with a final installment of all remaining unpaid principal due on August 31, 2019. The company had an outstanding balance of $31.3 million under the term loan as of June 27, 2015 . +The Company must comply with certain financial covenants, including a cash flow leverage ratio, an asset coverage ratio and a fixed charge coverage ratio. The credit agreement requires the Company to maintain a minimum profit threshold, limits the maximum capital lease expenditures and restricts the Company from declaring or paying dividends in cash or stock without prior bank approval. The Company is in compliance with all financial covenants for all periods presented. +41 +5. TRADE ACCOUNTS RECEIVABLE PURCHASE PROGRAM +Transfer Program +On June 25, 2014, the Company entered into an Account Purchase Agreement with Wells Fargo Bank, N.A. ("WFB") which provides that the Company may sell and assign to WFB and WFB may purchase from Company the accounts receivable of certain Company customers in a maximum aggregate amount of $50.0 million . The initial term of the agreement is 36 months with successive 12 month renewal terms. For the year ended June 27, 2015 , no accounts receivables were transferred under this original transfer agreement. For the year ended June 28, 2014, total accounts receivables transferred was approximately $9.0 million . The receivables that were transferred under the transfer purchase program remained on our consolidated balance sheet. +As of June 27, 2015 , the Company had no remaining liability to WFB for transferred accounts receivables. As of June 28, 2014, the Company’s net liability to WFB for accounts receivables transferred was approximately $7.9 million classified as current portion of debt. +Sale Program +On December 18, 2014, the Company modified the original Account Purchase Agreement with WFB to allow the Company to account for the factored receivables as a true-sale. The Company also has an Account Purchase Agreement with Orbian Financial Services ("Orbian") which allows the Company to account for factored receivables as a true-sale. As of June 27, 2015 , total accounts receivables sold was approximately $8.2 million with cash proceeds of approximately $7.3 million . The remaining outstanding balance of accounts receivables sold and not yet collected was approximately $0.9 million as of June 27, 2015 and is recorded on the Consolidated Balance Sheet in other current assets. No accounts receivables were sold during the twelve months ended June 28, 2014 . The receivables that were sold during the twelve months ended June 27, 2015 , were removed from the Consolidated Balance Sheet and the cash received is reflected as cash provided by operating activities in the Consolidated Statements of Cash Flows. +Subsequent to June 27, 2015 , the Company modified the Account Purchase Agreement with WFB to decrease the maximum aggregate amount of receivables available to factor from $50.0 million to $20.0 million . The decrease in the aggregate amount available was due to a change in customer mix and to reduce fees related to the program. +6. INCOME TAXES +Income tax provision consists of the following: +Fiscal Year Ended +June 27, 2015 +June 28, 2014 +June 29, 2013 +(in thousands) +Current income tax provision: +United States +$ +1,701 +$ +1,220 +$ +1,729 +Foreign +975 +1,017 +1,050 +2,676 +2,237 +2,779 +Deferred income tax provision: +United States +(1,486 +) +1,566 +2,049 +Foreign +(194 +) +(2,193 +) +444 +(1,680 +) +(627 +) +2,493 +Total income tax provision +$ +996 +$ +1,610 +$ +5,272 +The Company has total tax credit carryforwards of approximately $7.1 million at June 27, 2015 . Included in total tax credits carryforwards is approximately $5.6 million in research and development (R&D) tax credits. +Management also has reviewed its other deferred tax assets for purposes of determining whether or not a valuation allowance may be required. A valuation allowance against these deferred tax assets is required if it is more likely than not that some of the deferred tax assets will not be realized. Based on the Company’s increased profitability and estimated future repatriations from foreign subsidiaries, it has been determined that it is more likely than not that the deferred tax assets will be realized. +42 +Management has reviewed and updated as necessary estimates of future repatriations of the undistributed earnings of its foreign subsidiaries. Based on this analysis, management expects to repatriate a portion of the foreign undistributed earnings based on increased sales growth driving additional U.S. capital requirements, cash requirements for potential acquisitions and to potentially implement certain tax strategies. No foreign earnings were repatriated from either foreign subsidiary during fiscal 2015 or 2014 . The Company currently estimates that future repatriations from foreign subsidiaries will approximate $10.6 million . As such, as earnings are recognized in the United States, the Company would be subject to U.S. federal and state income taxes and potential withholding taxes are estimated to be approximately $5.0 million . Both the domestic tax and estimated withholding tax have been recorded as part of deferred taxes as of June 27, 2015 . All other unremitted foreign earnings are expected to remain permanently reinvested for planned fixed asset purchases in foreign locations. +The Company has not provided for U.S. income taxes or foreign withholding taxes on approximately $12.7 million of earnings from foreign subsidiaries which are permanently reinvested outside the U.S. The unrecognized net tax provision, after netting U.S. federal and state income tax and any related foreign tax credits, would be approximately $2.5 million associated with these earnings. +In recent years, the Company's wholly owned foreign subsidiary in Mexico has been subject to a Mexican business flat tax called Impuesto Empresarial a Tasa Unica (IETU). However, effective January 1, 2014, IETU was repealed as part of a larger reform of the Mexican tax system and the impact of the repeal was recognized as a discrete tax benefit of $1.5 million during the second quarter of fiscal year 2014. The Company is now subject to the general Mexican tax regime (ISR). The effects of IETU and ISR have been included in the effective tax rate for the year ended June 28, 2014. +The Company’s effective tax rate differs from the federal tax rate as follows: +Fiscal Year Ended +June 27, 2015 +June 28, 2014 +June 29, 2013 +(in thousands) +Federal income tax provision at statutory rates +$ +1,802 +$ +3,136 +$ +6,071 +Foreign tax rate differences +(80 +) +(439 +) +(625 +) +Effect of income tax credits +(1,085 +) +(202 +) +(340 +) +Effect of repatriation of foreign earnings, net +(80 +) +287 +188 +Other +257 +330 +235 +Transaction costs +182 +— +— +Change in valuation allowance +— +— +(257 +) +Effect of IETU repeal +— +(1,502 +) +— +Income tax provision +$ +996 +$ +1,610 +$ +5,272 +The domestic and foreign components of income before income taxes were: +Fiscal Year Ended +June 27, 2015 +June 28, 2014 +June 29, 2013 +(in thousands) +Domestic +$ +3,395 +$ +4,687 +$ +12,863 +Foreign +1,905 +4,536 +4,992 +Income before income taxes +$ +5,300 +$ +9,223 +$ +17,855 +43 +Deferred income tax assets and liabilities consist of the following at: +June 27, 2015 +June 28, 2014 +(in thousands) +Deferred tax assets: +Tax credit carryforwards, net +$ +2,843 +$ +2,795 +Foreign subsidiaries – future tax credits +2,985 +2,767 +Inventory +559 +— +Accruals +4,579 +2,855 +Mark-to-market adjustments +2,498 +— +Fixed assets +— +602 +Other +138 +75 +Deferred income tax assets +$ +13,602 +$ +9,094 +Deferred tax liabilities: +Foreign subsidiaries – unremitted earnings +(4,403 +) +(4,240 +) +Fixed assets +(941 +) +— +Identifiable intangibles +(1,866 +) +— +Mark-to-market adjustments +— +(1,237 +) +Other +(170 +) +(185 +) +Deferred income tax liabilities +$ +(7,380 +) +$ +(5,662 +) +Net deferred income tax assets +$ +6,222 +$ +3,432 +Balance sheet caption reported in: +Current deferred income tax asset +$ +6,643 +$ +935 +Long-term deferred income tax asset +80 +3,325 +Current deferred income tax liability (classified as Other current liabilities) +— +(558 +) +Long-term deferred income tax liability +(501 +) +(270 +) +Net deferred income tax asset +$ +6,222 +$ +3,432 +Uncertain Tax Positions +The Company has R&D tax credits that approximate $5.6 million that have 20 year carryforwards before expiring. The Company’s R&D tax credits expire in various fiscal years from 2021 to 2034. The Company also has alternative minimum tax credits, which do not expire, approximating $726,000 . +As of June 27, 2015 , the Company had unrecognized tax benefits of $3.4 million related to its gross R&D tax credits. The unrecognized tax benefits relate to certain R&D tax credits generated from 1999 to 2015. +A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: +Fiscal Year Ended +June 27, 2015 +June 28, 2014 +June 29, 2013 +(in thousands) +Beginning Balance +$ +3,072 +$ +3,031 +$ +3,003 +Additions based on tax positions related to the current year +374 +41 +97 +Reductions for tax provisions of the prior years +— +— +(69 +) +Ending Balance +$ +3,446 +$ +3,072 +$ +3,031 +The increase from the prior year is due to additional R&D credits that were recorded in 2015 as discussed above. Management does not anticipate any material changes to this amount during the next 12 months. +The Company recognizes interest accrued related to unrecognized tax benefits and penalties in its income tax provision. The Company has not recognized any interest or penalties in the fiscal years presented in these financial statements. The Company is subject to income tax in the U.S. federal jurisdiction, Mexico and China. Certain years remain subject to examination but there are currently no ongoing exams in any taxing jurisdictions. +44 +7. EARNINGS PER SHARE +Basic earnings per share (EPS) is calculated by dividing net income (the numerator) by the weighted-average number of common shares outstanding (the denominator) during the period. Diluted EPS is computed by including both the weighted-average number of shares outstanding and any dilutive common share equivalents in the denominator. The following table presents a reconciliation of the denominator and the number of antidilutive common share awards that were not included in the diluted earnings per share calculation. These antidilutive securities occur when equity awards outstanding have an option price greater than the average market price for the period: +Fiscal Year Ended +(in thousands, except per share information) +June 27, 2015 +June 28, 2014 +June 29, 2013 +Net income +$ +4,304 +$ +7,613 +$ +12,583 +Weighted average shares outstanding– basic +10,572 +10,528 +10,490 +Effect of dilutive common stock awards +714 +830 +762 +Weighted average shares outstanding – diluted +11,286 +11,358 +11,252 +Earnings per share – basic +$ +0.41 +$ +0.72 +$ +1.20 +Earnings per share – diluted +$ +0.38 +$ +0.67 +$ +1.12 +Antidilutive SARs not included in diluted earnings per share +208 +208 +— +8. STOCK OPTION AND BENEFIT PLANS +The Company’s incentive plan provides for equity and liability awards to employees and non-employee directors in the form of stock options, stock appreciation rights (SARs), restricted stock, restricted stock units, stock awards, stock units, performance shares, performance units, and other stock-based or cash-based awards. Compensation cost is recognized on a straight-line basis over the requisite employee service period, which is generally the vesting period, and is recorded as employee compensation expense in cost of goods sold, research, development and engineering, and selling general and administrative expenses. Share-based compensation is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on historical experience and future expectations. +In addition to service conditions, these SARs contain a performance condition. The additional performance condition is based upon the achievement of Return on Invested Capital (ROIC) goals relative to a peer group. All awards with performance conditions are measured over the vesting period and are charged to compensation expense over the requisite service period based on the number of shares expected to vest. The SARs cliff vest after a three-year period from date of grant and expire five years from date of grant. +On October 31, 2014, the Company granted 213,166 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $8.22 and a grant date fair value of $3.04 , as of June 27, 2015 , 213,166 remain outstanding. The grant date fair value for the awards granted during fiscal year 2015 were estimated using the Black Scholes option valuation method with the following weighted average assumptions as of October 31, 2014: +Fiscal Year 2015 +October 31, 2014 +Expected dividend yield +—% +Risk – free interest rate +1.39% +Expected volatility +45.67% +Expected life +4.00 +45 +On July 31, 2013, the Company granted 213,166 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $11.34 and a grant date fair value of $4.67 , as of June 27, 2015 , 208,166 remain outstanding. The grant date fair value for the awards granted during fiscal year 2014 were estimated using the Black Scholes option valuation method with the following weighted average assumptions as July 31, 2013: +Fiscal Year 2014 +July 31, 2013 +Expected dividend yield +—% +Risk – free interest rate +1.16% +Expected volatility +52.12% +Expected life +4.00 +On July 25, 2012, the Company granted 210,666 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $7.44 and a grant date fair value of $3.71 , as of June 27, 2015 , 203,166 remain outstanding. The grant date fair value for the awards granted during fiscal year 2013 were estimated using the Black Scholes option valuation method with the following weighted average assumptions as July 25, 2012: +Fiscal Year 2013 +July 25, 2012 +Expected dividend yield +—% +Risk – free interest rate +0.46% +Expected volatility +66.50% +Expected life +4.00 +Subsequent to June 27, 2015 , the Company granted 248,166 SARs with a strike price of $ 10.26 and a grant date fair value of $3.65 . +Share-based compensation expense is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on the Company’s historical experience and future expectations. This forfeiture rate will be revised, if necessary, in subsequent periods if actual forfeitures differ from the amount estimated. Share-based compensation expense for fiscal years ended June 27, 2015 , June 28, 2014 and June 29, 2013 was $0.7 million , $0.7 million and $0.8 million , respectively. +The Black-Scholes option valuation model was developed for use in estimating the fair value of traded options, which differ significantly from the SARs, as traded options have no vesting restrictions and are fully transferable. In addition, option valuation models require the input of highly subjective assumptions, particularly for the expected term and expected stock price volatility. Changes in these assumptions can materially affect the fair value estimates. +The intrinsic value for options exercised in fiscal years 2015 , 2014 and 2013 was $1.9 million , $0.4 million and $0.2 million , respectively. +As of June 27, 2015 , total unrecognized compensation expense related to nonvested share-based compensation arrangements was approximately $0.8 million . This expense is expected to be recognized over a weighted-average period of 1.80 years . +The following table summarizes the Company’s stock options and SARs activity for all plans from June 28, 2014 through June 27, 2015 : +SARs +Available +For Grant +Options/SARs +Outstanding +Aggregate +Intrinsic +Value (in +thousands) +Weighted +Average +Exercise +Price +Weighted +Average +Remaining +Contractual +Life (in +years) +Balances, June 28, 2014 +69,002 +1,065,928 +$ +4,096 +$ +7.01 +1.8 +Shares authorized +1,000,000 +— +— +— +— +SARs granted +(213,166 +) +213,166 +— +8.22 +— +SARs forfeited +— +— +— +— +— +Options/SARs exercised +— +(465,263 +) +1,877 +5.84 +— +Balances, June 27, 2015 +855,836 +813,831 +$ +2,312 +$ +7.99 +2.5 +Exercisable at June 27, 2015 +189,333 +$ +881 +$ +4.65 +1.2 +46 +Additional information regarding stock options and SARs outstanding and exercisable as of June 27, 2015 , is as follows: +Range of +Exercise Prices +Number Outstanding +Weighted Avg. +Remaining +Contractual Life (yrs.) +Weighted Avg. +Exercise Price +Number +Exercisable +Weighted +Avg. Exercise +Price +$3.40 – $5.40 +164,333 +1.1 +$ +4.40 +164,333 +$ +4.40 +5.41 – 7.41 +25,000 +1.6 +6.30 +25,000 +6.30 +7.42 – 9.42 +416,332 +3.2 +7.84 +— +— +9.43 – 11.34 +208,166 +3.1 +11.34 +— +— +$3.40 to $11.34 +813,831 +2.5 +$ +7.99 +189,333 +$ +4.65 +The Company has defined contribution plans available to U.S. employees who have attained age 21. Company contributions to the plans were approximately $0.6 million , $0.6 million , and $0.5 million during fiscal years 2015 , 2014 and 2013 , respectively. +9. COMMITMENTS AND CONTINGENCIES +Leases : As of June 27, 2015 , the Company did not have any property and equipment financed under capital leases. The Company had equipment financed through capital leases with a net book value of $1.7 million and $1.9 million during fiscal years 2014 and 2013 , respectively. The related depreciation expense was $0.3 million for fiscal years 2014 and 2013. As of June 27, 2015 , the Company has operating leases for certain equipment and production facilities, which expire at various dates during the next seven years . +Future minimum payments under non-cancelable operating leases with initial or remaining terms of one year or more at June 27, 2015 , are summarized as follows (in thousands): +Fiscal Years Ending +Operating Leases +2016 +$ +5,552 +2017 +4,245 +2018 +3,099 +2019 +1,297 +2020 +1,225 +Thereafter +646 +Total minimum lease payments +$ +16,064 +Rental expense under operating leases was approximately $3.8 million , $1.8 million , and $1.5 million during fiscal years 2015 , 2014 and 2013 , respectively. +Warranty Costs : The Company provides warranties on certain product sales, and allowances for estimated warranty costs are recorded during the period of sale. The determination of such allowances requires the Company to make estimates of product return rates and expected costs to repair or to replace the products under warranty. The Company establishes warranty reserves based on historical warranty costs for each product line combined with liability estimates based on the prior twelve months’ sales activities. As of June 27, 2015 , the reserve for warranty costs was approximately $115,000 . +If actual return rates and/or repair and replacement costs differ significantly from estimates, adjustments to recognize additional cost of sales may be required in future periods. Warranty expense for fiscal years 2015 , 2014 and 2013 was related to workmanship claims on keyboards and certain EMS products. +Litigation : The Company is party to certain lawsuits or claims in the ordinary course of business. The Company does not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on the financial position, results of operations or cash flow of the Company. +Indemnification Rights : Under the Company’s bylaws, the Company’s directors and officers have certain rights to indemnification by the Company against certain liabilities that may arise by reason of their status or service as directors or officers. The Company maintains director and officer insurance, which may cover certain liabilities arising from its obligation to indemnify its directors and officers and former directors in certain circumstances. +47 +10. FAIR VALUE MEASUREMENTS +The Company has adopted ASC 820, Fair Value Measurements, which defines fair value, establishes a framework for assets and liabilities being measured and reported at fair value and expands disclosures about fair value measurements. There are three levels of fair value hierarchy inputs used to value assets and liabilities which include: Level 1 – inputs are quoted market prices for identical assets or liabilities; Level 2 – inputs other than quoted market prices included in Level 1 that are observable for the asset or liability, either directly or indirectly; and Level 3 – inputs are unobservable inputs for the asset or liability. There have been no changes in the fair value methodologies used at June 27, 2015 and June 28, 2014 . +The following table summarizes the fair value of assets (liabilities) of the Company’s derivatives that are required to be measured on a recurring basis as of June 27, 2015 and June 28, 2014 (in thousands): +June 27, 2015 +Level 1 +Level 2 +Level 3 +Total +Fair Value +Financial Assets: +Interest rate swaps +$ +— +$ +25 +$ +— +$ +25 +Financial Liabilities: +Interest rate swaps +$ +— +$ +(443 +) +$ +— +$ +(443 +) +Foreign currency forward contracts +$ +— +$ +(6,799 +) +$ +— +$ +(6,799 +) +June 28, 2014 +Level 1 +Level 2 +Level 3 +Total +Fair Value +Financial Assets: +Foreign currency forward contracts +$ +— +$ +3,641 +$ +— +$ +3,641 +The Company currently has forward contracts to hedge known future cash outflows for expenses denominated in the Mexican peso and an interest rate swap to mitigate risk associated with certain borrowings under the Company’s debt arrangement. These contracts are measured on a recurring basis based on the foreign currency spot rates and forward rates quoted by banks or foreign currency dealers. These contracts are marked to market using level 2 input criteria every period with the unrealized gain or loss, net of tax, reported as a component of shareholders’ equity in accumulated other comprehensive income (loss), as they qualify for hedge accounting. +The carrying values of cash and cash equivalents, accounts receivable and current liabilities reflected on the balance sheets at June 27, 2015 and June 28, 2014 , reasonably approximate their fair value. The Company’s long-term debt primarily consists of a revolving line of credit and a term loan. Borrowings under this revolving line of credit bear interest at either a “Base Rate” or a “Fixed Rate,” as elected by the Company. The base rate is the higher of the Wells Fargo Bank prime rate, daily one month London Interbank Offered Rate (LIBOR) plus 1.5% , or the Federal Funds rate plus 1.5% . The fixed rate is LIBOR plus 1.75% , LIBOR plus 2.0% or LIBOR plus 2.25% depending on the level of the Company’s trailing four quarters Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA). Borrowings under the term loan bear interest at a fixed rate per annum of the daily one month LIBOR plus 1.75% , 2.00% or 2.25% depending on the ratio of the Company’s funded debt to EBITDA. Each of these rates is a variable floating rate dependent upon current market conditions and the Company’s current credit risk. +As a result of the determinable market rate for our revolving credit and term debt it is classified within Level 2 of the fair value hierarchy. The discounted cash flow of the revolving line of credit is estimated to be $11.6 million as of June 27, 2015 , with a carrying value that reasonably approximates the fair value. The Company did not have an outstanding balance on the line of credit as of June 28, 2014 . The discounted cash flow of the term loan is estimated to be $31.3 million as of June 27, 2015 , with a carrying value that reasonably approximates the fair value. The Company did not have an outstanding balance on the term loan as of June 28, 2014. +Additionally, borrowings under the accounts receivable purchase program bear interest at daily one month LIBOR plus 2.25% . As a result of the determinable market rate for our accounts receivable purchase program, it is classified within Level 2 of the fair value hierarchy. As of June 27, 2015 , the Company had no remaining liability to WFB for transferred accounts receivables. As of June 28, 2014, the Company had a net liability to WFB of $7.9 million , which reasonably approximates its fair value. The outstanding balance of accounts receivable sold and not yet collected under the trade accounts receivable program are recorded initially at fair value as other current assets on the Consolidated Balance Sheet and valued using unobservable inputs (level 3) primarily discounted cash flows, due to their credit quality and short-term maturity. The fair value reasonably approximates the carrying value. The unobservable inputs consist of estimated credit losses and estimated discount rates, both of which have an immaterial impact on the fair value calculations of the account receivables sold and not yet collected. +48 +11. DERIVATIVE FINANCIAL INSTRUMENTS +As of June 27, 2015 , the Company had outstanding foreign currency forward contracts of $65.0 million . These contract maturity dates extend through June 2018 . As of June 27, 2015 , the net amount of unrealized loss expected to be reclassified into earnings within the next 12 months is approximately $1.8 million . During the fiscal year ended June 27, 2015 , the Company entered into $23.1 million of foreign currency forward contracts and settled $20.5 million of such contracts. During the fiscal year ended June 28, 2014 , the Company entered into $15.2 million of foreign currency forward contracts and settled $22.5 million of such contracts. During the fiscal year ended June 29, 2013 , the Company entered into $34.7 million of foreign currency forward contracts and settled $22.7 million of such contracts. +Subsequent to June 27, 2015 , the Company entered into $5.3 million of additional foreign currency forward contracts that extended our hedge position through September 2018. +On October 1, 2014, the Company entered into an interest rate swap contract with an effective date of September 1, 2015 and a termination date of September 3, 2019, with a notional amount of $25.0 million related to the borrowings outstanding under the term loan and line of credit. This interest rate swap pays the Company variable interest at the one month LIBOR rate, and the Company pays the counter party a fixed interest rate. The fixed interest rate for the contract is 1.97% that replaces the one month LIBOR rate component of our contractual interest to be paid to WFB as part of our debt facilities. Based on the terms of the interest rate swap contract and the underlying borrowings outstanding under the term loan, the interest rate contract was determined to be effective, and thus qualifies as a cash flow hedge. +The following table summarizes the fair value of derivative instruments in the Consolidated Balance Sheets as of June 27, 2015 and June 28, 2014 (in thousands): +June 27, 2015 +June 28, 2014 +Derivatives Designated as Hedging Instruments +Balance Sheet Location +Fair Value +Fair Value +Foreign currency forward contracts +Other current assets +$ +— +$ +2,034 +Foreign currency forward contracts +Other long-term assets +$ +— +$ +1,607 +Foreign currency forward contracts +Other current liabilities +$ +(2,517 +) +$ +— +Foreign currency forward contracts +Other long-term liabilities +$ +(4,282 +) +$ +— +Interest rate swaps +Other long-term assets +$ +25 +$ +— +Interest rate swaps +Other current liabilities +$ +(271 +) +$ +— +Interest rate swaps +Other long-term liabilities +$ +(172 +) +$ +— +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2015 (in thousands): +Derivatives Designated as Hedging Instruments +AOCI Balance +as of +June 28, 2014 +Effective +Portion +Recorded In +AOCI +Effective Portion +Reclassified From +AOCI Into Cost +of Sales +AOCI Balance +as of +June 27, 2015 +Settled foreign currency forward contracts +$ +1,343 +$ +(1,661 +) +$ +318 +$ +— +Unsettled foreign currency forward contracts +1,060 +(5,547 +) +— +(4,487 +) +Unsettled interest rate swaps +— +(276 +) +— +(276 +) +Total +$ +2,403 +$ +(7,484 +) +$ +318 +$ +(4,763 +) +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2014 (in thousands): +Derivatives Designated as Hedging Instruments +AOCI Balance +as of +June 29, 2013 +Effective +Portion +Recorded In +AOCI +Effective Portion +Reclassified From +AOCI Into +Cost of Sales +AOCI Balance +as of +June 28, 2014 +Settled foreign currency forward contracts +$ +404 +$ +421 +$ +(825 +) +$ +— +Unsettled foreign currency forward contracts +909 +1,494 +— +2,403 +Total +$ +1,313 +$ +1,915 +$ +(825 +) +$ +2,403 +49 +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2013 (in thousands): +Derivatives Designated as Hedging Instruments +AOCI Balance +as of +June 30, 2012 +Effective +Portion +Recorded In +AOCI +Effective Portion +Reclassified From +AOCI Into +Cost of Sales +AOCI Balance +as of +June 29, 2013 +Settled foreign currency forward contracts +$ +(479 +) +$ +1,060 +$ +(581 +) +$ +— +Unsettled foreign currency forward contracts +(180 +) +1,493 +— +1,313 +Total +$ +(659 +) +$ +2,553 +$ +(581 +) +$ +1,313 +As of June 27, 2015 , the Company does not have any foreign exchange contracts with credit-risk-related contingent features. The Company is subject to the risk of fluctuating interest rates from our line of credit and foreign currency risk resulting from our China operations. The Company does not currently manage these risk exposures by using derivative instruments. +12. ENTERPRISE-WIDE DISCLOSURES +Operating segments are defined in ASC Topic 280, Segment Reporting as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker, or decision making group, in deciding how to allocate resources and in assessing performance. The Company’s chief operating decision maker is its Chief Executive Officer. As of June 27, 2015 , the Company operates and internally manages a single operating segment, Electronics Manufacturing Services as this is the only discrete financial information that is regularly reviewed by the chief operating decision maker. This segment provides integrated electronic and mechanical engineering, assembly, sourcing and procurement, logistics, and new product testing for our customers. +Products and Services +Of the revenues for the years ended June 27, 2015 , June 28, 2014 , and June 29, 2013 , EMS sales and services were $432.1 million , $303.1 million and $358.6 million , respectively. Keyboard sales for the years ended June 27, 2015 , June 28, 2014 , and June 29, 2013 were $1.9 million , $2.3 million and $2.4 million , respectively. +Geographic Areas +Net sales and long-lived assets (property, plant, and equipment) by geographic area for the years ended and as of June 27, 2015 , June 28, 2014 and June 29, 2013 are summarized in the following table. Net sales set forth below are based on the shipping destination. Long-lived assets information is based on the physical location of the asset. +Fiscal Year Ended +(in thousands) +2015 +2014 +2013 +Geographic net sales: +Domestic (U.S.) +$ +301,891 +$ +197,700 +$ +246,059 +Foreign +132,106 +107,694 +114,974 +Total +$ +433,997 +$ +305,394 +$ +361,033 +Long-lived assets: +United States +$ +8,969 +$ +2,888 +$ +2,045 +Mexico +17,156 +19,577 +14,539 +China +849 +1,131 +1,327 +Total +$ +26,974 +$ +23,596 +$ +17,911 +50 +Percentage of net sales made to customers located in the following countries: +Fiscal Year Ended +2015 +2014 +2013 +United States +69.6% +64.7% +68.2% +Canada +10.5 +16.5 +22.4 +Other foreign countries (a) +19.9 +18.8 +9.4 +Total +100.0% +100.0% +100.0% +(a) No other individual foreign country accounted for 10% or more of the foreign sales in fiscal years 2015, 2014, or 2013. +Significant Customers +The percentage of net sales to and trade accounts receivables from significant customers were as follows: +Percentage of Net +Sales Fiscal Year +Percentage of +Trade Accounts Receivable +Fiscal Year +2015 +2014 +2013 +2015 +2014 +Customer A +17% +20% +19% +18% +24% +Customer B +* +15% +23% +* +12% +Customer C +* +15% +21% +* +14% +* Current customer amount represents less than 10%. +13. QUARTERLY FINANCIAL DATA (Unaudited) +Fiscal Year Ended June 27, 2015 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +(in thousands, except per share amounts) +Net sales +$ +86,342 +$ +114,311 +$ +112,915 +$ +120,429 +Gross profit +4,238 +9,239 +9,436 +10,392 +(Loss) income before income taxes +(1,894 +) +2,113 +2,234 +2,847 +Net (loss) income +(1,523 +) +1,626 +1,861 +2,340 +(Loss) earnings per common share-basic +$ +(0.14 +) +$ +0.15 +$ +0.18 +$ +0.22 +(Loss) earnings per common share-diluted +$ +(0.14 +) +$ +0.14 +$ +0.16 +$ +0.21 +Weighted average shares outstanding +Basic +10,548 +10,552 +10,552 +10,636 +Diluted +10,548 +11,471 +11,556 +11,414 +Fiscal Year Ended June 28, 2014 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +(in thousands, except per share amounts) +Net sales +$ +77,974 +$ +78,250 +$ +77,043 +$ +72,127 +Gross profit +6,622 +6,950 +6,607 +6,675 +Income before income taxes +2,438 +2,350 +2,196 +2,239 +Net income +1,705 +3,114 +1,414 +1,380 +Earnings per common share-basic +$ +0.16 +$ +0.30 +$ +0.13 +$ +0.13 +Earnings per common share-diluted +$ +0.15 +$ +0.27 +$ +0.12 +$ +0.12 +Weighted average shares outstanding +Basic +10,507 +10,530 +10,533 +10,541 +Diluted +11,336 +11,354 +11,350 +11,346 +51 +14. ACQUISITIONS +On July 1, 2013, the Company acquired substantially all of the assets of Sabre Assembly & Manufacturing Co. of Texas (“Sabre”), a sheet metal fabrication company with facilities located in Juarez, Mexico. The acquisition of Sabre enables the Company to offer metal fabrication directly to its customers, in combination with plastic molding, PCB assembly, complete product assembly, design engineering and testing engineering services. Under the terms of the transaction, the assets acquired included manufacturing equipment, inventory, customer relationships and non-compete agreements with key employees. No debt or liabilities were assumed. The total cash payment of $6.0 million was funded through existing cash. The Company incurred approximately $50,000 of costs related to due diligence and closing this acquisition. +The following table summarizes the fair values of the assets acquired as of the date of acquisition (in thousands): +Fair Values +At July 1, 2013 +Current Assets +$ +777 +Fixed Assets +1,168 +Non-Compete Agreements +372 +Customer Relationships +1,970 +Goodwill +1,740 +Fair value of assets acquired +$ +6,027 +The Sabre acquisition was accounted for using the acquisition method of accounting whereby the total purchase price is allocated to tangible and intangible assets and liabilities based on their fair values on the date of acquisition. The Company determined the purchase price allocations on the acquisition based on estimates of the fair values of the assets acquired. +On September 3, 2014, the Company acquired all of the outstanding stock of Ayrshire, resulting in Ayrshire becoming a wholly owned subsidiary of the Company. Ayrshire provides printed circuit board assembly and other electronic manufacturing services to a diversified customer base through manufacturing facilities operated by Ayrshire or its subsidiaries in Minnesota, Arkansas, Mississippi, and Kentucky and through a sheltered maquiladora facility in Reynosa, Mexico. The Reynosa, Mexico operations were moved to the Company's existing facility in Juarez, Mexico. This acquisition expands our printed circuit board assembly capacity, total revenue, and adds to and diversifies our customer base with the addition of many new multi-national companies. The total cash payment of approximately $48.0 million was funded through borrowings on our term loan, revolving line of credit, and cash on hand. The Company incurred approximately $775,000 of costs related to due diligence. +52 +The following table summarizes the purchase price paid for Ayrshire and the fair value of the assets acquired and liabilities assumed as of the date of acquisition (in thousands): +Estimated Fair Values +At September 3, 2014 +Purchase price paid +$ +48,010 +Cash acquired +(46 +) +Purchase price, net of cash received +$ +47,964 +Cash +$ +46 +Accounts Receivable +21,211 +Inventories +21,772 +Deferred Tax Asset +1,308 +Other Current Assets +1,013 +Property, plant and equipment +7,823 +Favorable Leases +2,941 +Customer Relationships +2,833 +Non-Compete Agreements +196 +Goodwill +8,217 +Other Assets +42 +Accounts Payable +(11,070 +) +Accrued Salaries and Wages +(2,188 +) +Other Current Liabilities +(2,408 +) +Deferred Tax Liability +(3,726 +) +Fair Value of Assets Acquired +$ +48,010 +The Ayrshire acquisition was accounted for using the acquisition method of accounting whereby the total purchase price is allocated to tangible and intangible assets and liabilities based on their fair values on the date of acquisition. The Company determined the purchase price allocations on the acquisition based on estimates of the fair values of the assets acquired and liabilities assumed. +Revenue and net income included in the Consolidated Statements of Income related to Ayrshire for fiscal year 2015 were $124.6 million and $5.0 million, respectively. +The following summary pro forma condensed consolidated financial information reflects the Ayrshire acquisition as if it had occurred on June 30, 2013 for purposes of the statements of income. This summary pro forma information is not necessarily representative of what the Company’s results of operations would have been had this acquisition in fact occurred on June 30, 2013 and is not intended to project the Company’s results of operations for any future period. +Pro forma condensed consolidated financial information for the years ended June 27, 2015 and June 28, 2014 (in thousands): +Fiscal Year Ended +(unaudited) +June 27, 2015 +June 28, 2014 +Net sales +$ +457,475 +$ +431,274 +Net income +$ +4,136 +$ +9,476 +53 +15. GOODWILL AND OTHER INTANGIBLE ASSETS +In accordance with ASC 350 Intangibles – Goodwill and Other Intangibles , goodwill is not amortized, but must be analyzed for impairment at least annually. The Company recorded goodwill in connection with the Ayrshire and Sabre acquisitions resulting primarily from the synergies that resulted from the Company’s acquisitions and the assembled workforce. The goodwill is not amortized for financial accounting purposes. The goodwill from the acquisitions is not deductible for tax purposes. +On March 30, 2015, the Company completed its annual impairment test. The Company concluded that it is more likely than not that the fair value of goodwill is greater than the carrying value. As of June 27, 2015 , goodwill was recorded at $10.0 million . As of June 28, 2014 , goodwill was recorded at $1.7 million . +The components of acquired intangible assets are as follows (in thousands): +June 27, 2015 +Amortization Period +in Years +Gross Carrying +Amount +Accumulated +Amortization +Net Carrying +Amount +Intangible assets: +Non-Compete Agreements +3 - 5 +$ +568 +$ +(204 +) +$ +364 +Customer Relationships +10 +4,803 +(630 +) +4,173 +Favorable Lease Agreements +4 - 7 +2,941 +(423 +) +2,518 +Total +$ +8,312 +$ +(1,257 +) +$ +7,055 +June 28, 2014 +Amortization Period +in Years +Gross Carrying +Amount +Accumulated +Amortization +Net Carrying +Amount +Intangible assets: +Non-Compete Agreements +5 +$ +372 +$ +(74 +) +$ +298 +Customer Relationships +10 +1,970 +(197 +) +1,773 +Total +$ +2,342 +$ +(271 +) +$ +2,071 +Amortization expense was approximately $1.0 million and $0.3 million for the years ended June 27, 2015 and June 28, 2014 , respectively. +Aggregate amortization expense relative to existing intangible assets by fiscal year is currently estimated to be as follows (in thousands): +Fiscal Years Ending +Amount +2016 +$ +1,128 +2017 +1,128 +2018 +1,073 +2019 +818 +2020 +783 +Thereafter +2,125 +Total amortization expense +$ +7,055 +54 +Item 9: +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES +None +Item 9A: +CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +It is the responsibility of our management to establish, maintain, and monitor disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 are recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Additionally, these disclosure controls include controls and procedures that are designed to accumulate and communicate the information required to be disclosed to our Company’s Chief Executive Officer and Chief Financial Officer, allowing for timely decisions regarding required disclosures. As of the end of the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(f). Based on our assessment, we believe that as of June 27, 2015 , the Company’s disclosure controls and procedures are effective based on that criteria. +Management’s Report on Internal Control over Financial Reporting +Our management has the responsibility to establish and maintain adequate internal controls over our financial reporting, as defined in Rule 13a-15(f) under the Securities and Exchange Act of 1934. Our internal controls are designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our external financial statements in accordance with generally accepted accounting principles (GAAP). +Due to inherent limitations of any internal control system, management acknowledges that there are limitations as to the effectiveness of internal controls over financial reporting and therefore recognize that only reasonable assurance can be gained from any internal control system. Accordingly, our internal control system may not detect or prevent material misstatements in our financial statements and projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, we have performed an assessment of the effectiveness of our internal controls over financial reporting as of June 27, 2015 . This assessment was based on the criteria established in Internal Control-Integrated Framework (1992), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that as of June 27, 2015 , the Company’s internal control over financial reporting is effective based on that criteria. +The effectiveness of the Company's internal control over financial reporting as of June 27, 2015 has been audited by BDO USA LLP, an independent registered public accounting firm, as stated in their report which is included herein. +Changes in Internal Control over Financial Reporting +There have been no significant changes in our internal controls over financial reporting during our fourth fiscal quarter ended June 27, 2015 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)). +55 +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Key Tronic Corporation +Spokane Valley, Washington +We have audited Key Tronic Corporation's internal control over financial reporting as of June 27, 2015, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Key Tronic Corporation's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Item 9A “Management's Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, Key Tronic Corporation maintained, in all material respects, effective internal control over financial reporting as of June 27, 2015, based on the COSO criteria . +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Key Tronic Corporation as of June 27, 2015 and June 28, 2014, and the related consolidated statements of income, comprehensive (loss) income, shareholders' equity, and cash flows for each of the three years in the period ended June 27, 2015 and our report dated September 4, 2015, expressed an unqualified opinion thereon. +/s/ BDO USA, LLP +Spokane, Washington +September 4, 2015 +56 +Item 9B: +OTHER INFORMATION +None +PART III +Item 10: +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Directors of the Registrant +Information on the nominees for election as Directors of the Company is incorporated by reference from the Company’s definitive proxy statement for the 2015 Annual Meeting of Shareholders to be filed pursuant to Regulation 14A under the Exchange Act no later than 120 days after the end of the Company’s 2015 fiscal year. +Executive Officers of the Registrant +This information is included in a separate item captioned “Executive Officers of the Registrant” in Item 1 of Part 1 of this report pursuant to Instruction G(3) of Form 10-K and Instruction 3 to Item 401(b) of Regulation S-K. +Compliance with Section 16(a) of the Exchange Act: +Incorporated by reference to Key Tronic Corporation’s 2015 Proxy Statement to Shareholders. +Code of Conduct +The Board of Directors has adopted a written Code of Conduct which applies to its directors and employees, including its executive officers. The Code of Conduct is available on the Company’s website at www.keytronic.com . The Company intends to disclose on its website any amendments to or waivers of the Code of Conduct. +Item 11: +EXECUTIVE COMPENSATION +Information appearing under the caption “Executive Compensation” in the Company’s 2015 Proxy Statement is incorporated herein by this reference. +Item 12: +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The following table sets forth the aggregate information for the Company’s equity compensation plans in effect as of June 27, 2015 . +EQUITY COMPENSATION PLAN INFORMATION +Plan category +Number of securities to +be issued upon exercise +of outstanding options, +warrants, and rights +(a) +Weighted-average +exercise price of +outstanding options, +warrants, and rights +(b) +Number of securities +remaining available for +future issuance under +equity compensation +plans (excluding +securities reflected in +column (a) +(c) +Equity compensation plans approved by security holders (1) +813,831 +$ +7.99 +855,836 +Equity compensation plans not approved by security holders +— +$ +— +— +Total +813,831 +$ +7.99 +855,836 +(1) +Included are the 1,200,000 shares subject to the 2010 Plan, the issuance of which were approved by the shareholders at the 2010 Annual Meeting. During the 2015 Annual Meeting, an additional 1,000,000 shares were approved. As a result of the shareholder approval, the Company made the decision to amend the cash-settled SARs granted during fiscal year 2010 to stock-settled SARs effective October 21, 2011. +Information under the caption “Beneficial Ownership of Securities” in the Company’s 2015 Proxy Statement is incorporated herein by this reference. +57 +Item 13: +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions”, “Compensation Committee Interlocks and Insider Participation”, and “Directors’ Independence” in the Company’s 2015 Proxy Statement is incorporated herein by this reference. +Item 14: +PRINCIPAL ACCOUNTING FEES AND SERVICES +Information appearing under the caption “Principal Accountant Fees and Services” in the Company’s 2015 Proxy Statement is incorporated herein by this reference. +PART IV +Item 15: +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +(a) 1. FINANCIAL STATEMENTS +Page in Form 10-K +FINANCIAL STATEMENTS +Report of Independent Registered Public Accounting Firm +31 +Consolidated Balance Sheets +32 +Consolidated Statements of Income +33 +Consolidated Statements of Comprehensive (Loss) Income +34 +Consolidated Statements of Cash Flows +35 +Consolidated Statements of Shareholders’ Equity +36 +Notes to Consolidated Financial Statements +37-54 +2. SCHEDULES +II. Consolidated Valuation and Qualifying Accounts +62 +Other schedules are omitted because of the absence of conditions under which they are required, or because required information is given in the financial statements or notes thereto. +58 +3. EXHIBITS +Exhibit No. +Description +3.1 +Articles of Incorporation, incorporated by reference to the Exhibits to the Company’s form 10-K for the year ended June 30, 1986 +3.2 +Bylaws, as amended, incorporated by reference to the Exhibits to the Company’s Form 10-K for the year ended June 30, 1986 +10.1* +Executive Stock Option Plan, incorporated by reference to Exhibits to the Company’s Form 10-K for the year ended June 30, 1986 +10.2* +Amended and Restated 1990 Stock Option Plan for Non-Employee Directors, as amended, incorporated by reference to the Company’s 1997 Proxy Statement (dated October 10, 1997), pages 14-17 +10.3* +1995 Executive Stock Option Plan, incorporated by reference to the Company’s 1995 Proxy Statement, pages 19-22 +10.4* +2000 Employee Stock Option Plan, incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.5* +Officers’ Employment Contracts, incorporated by reference to the Company’s 1998 Proxy Statement, pages 10 and 11 +10.6* +Addenda to Officers’ Employment Contracts, incorporated by reference to Exhibits to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.7* +Description of Retention Bonus Plan, incorporated by reference to the Exhibits to the Company’s 10-Q for the quarter ended December 28, 2002 +10.8* +Addenda to Officers’ Employment Contracts, incorporated by reference to Exhibits to the Company’s Form 10-K for the year ended June 29, 2002 +10.9 +Promise to execute a Purchase and Sale Agreement with Key Safety Systems de Mexico, S.A. de C.V., incorporated by reference to the Exhibit to the Company’s Form 8-K filed April 26, 2005 +10.10 +Summary of material terms and conditions of the Purchase and Sale Agreement with Key Safety Systems de Mexico, S.A. de C.V., incorporated by reference to the Exhibit to the Company’s Form 8-K filed June 6, 2005 +10.11* +Summary of Key Tronic Corporation Incentive Compensation Plan, incorporated by reference to Exhibit 10.23 to the Company’s Form 10-K for the year ended July 2, 2005 +59 +10.12* +Summary of Incentive Compensation Plan Performance goals and Target Payments for fiscal year 2007, incorporated by reference to the Company’s Form 8-K filed July 28, 2006 +10.13* +Summary of Fiscal Years 2007 – 2009 Long Term Incentive Plan Performance Measures and Awards, incorporated by reference to the Company’s Form 8-K filed July 28, 2006 +10.14* +Summary of Key Tronic Corporation Long Term Incentive Compensation Plan, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed September 27, 2005 +10.15 +Summary of material terms and conditions of the Purchase and Sale Agreement with Todenko Mexico S.A. de C.V., incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed October 12, 2006 +10.16 +Summary of material terms and conditions of the Purchase and Sale Agreement with Todenko Mexico S.A. de C.V., incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed November 20, 2006 +10.17 +Summary of material terms and conditions of the Sale and Purchase Agreement with Adevco Corporation, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed January 5, 2007 +10.18 +Summary of Second Amendment to Agreement of Sale and Purchase Agreement with Adevco Corporation, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed April 11, 2007 +10.19* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2008 and Fiscal Years 2008-2010 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 27, 2007 +10.20* +Summary of Incentive Compensation Plan Performance Goals and Target payments for Fiscal Year 2009 and Fiscal Years 2009 – 2011 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 24, 2008 +10.21* +Summary of Incentive Compensation Plan Performance Goals and Target payments for Fiscal Year 2010 and Fiscal Years 2010 – 2012 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 23, 2009 +10.22 +Financing Agreement with Wells Fargo Bank, N.A., incorporated by reference to the Exhibits to the Company’s Form 8-K filed on August 24, 2009 +10.23* +2010 Incentive Plan, incorporated by reference to Exhibit 10.36 to the Company’s Form 10-K for the year ended July 3, 2010 +10.24* +Employment Contract with Douglas G. Burkhardt, incorporated by reference to Exhibit 10.37 to the Company’s Form 10-K for the year ended July 3, 2010 +10.25 +Summary of material terms and conditions of the Purchase and Sale Agreement with Autopartes Y Arneses de Mexico S.A. de C.V., incorporated by reference to Exhibit 10.38 to the Company’s Form 10-K for the year ended July 3, 2010 +10.26* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2011 and Fiscal Years 2011 – 2013 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 27, 2011 +60 +10.27* +Amendment to Employment Contract of Craig D. Gates, dated August 23, 2011; of Ronald F. Klawitter, dated August 23, 2011 and of Douglas G. Burkhardt dated September 6, 2011; incorporated by reference to the Exhibits to the Company’s Form 10-K for the year ended July 2, 2011 +10.28 +Second Loan Modification Agreement to the Credit Agreement with Wells Fargo Bank, N.A., incorporated by reference to the Exhibits to the Company’s Form 8-K filed on January 30, 2012 +10.29* +Amendment to Employment Contract of Craig D. Gates, dated May 10, 2012, and of Douglas G. Burkhardt dated May 10, 2012; incorporated by reference to the Exhibits to the Company’s Form 10-Q filed on May 14, 2012 +10.30* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2013 and Fiscal Years 2013 – 2015 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 7, 2012 +10.31* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2014 and Fiscal Years 2014 – 2016 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 6, 2013 +10.32* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2015 and Fiscal Years 2015 – 2017 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 1, 2014 +10.33 +Summary of material terms and conditions of the Stock Purchase Agreement with CDR Manufacturing and Amended and Restated Credit Agreement with Wells Fargo Bank, N. A. incorporated by reference to the Company’s Form 8-K filed September 9, 2014 +10.34* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2016 and Fiscal Years 2016 – 2018 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 30, 2015 +10.35 +First Amendment to Amended and Restated Credit Agreement and Second Replacement Revolving Line of Credit Note with Wells Fargo Bank, National Association, incorporated by reference to the Company's Form 8-K filed August 11, 2015 +21. +Subsidiaries of Registrant, submitted herewith +23.1 +Consent of Independent Registered Public Accounting Firm, submitted herewith +31.1 +Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer, submitted herewith +31.2 +Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer, submitted herewith +32.1 +Section 1350 Certification of Chief Executive Officer, submitted herewith +32.2 +Section 1350 Certification of Chief Financial Officer, submitted herewith +101.INS +XBRL Instance Document ** +101.SCH +XBRL Taxonomy Extension Schema Document ** +61 +101.CAL +XBRL Taxonomy Extension Calculation Linkbase Document ** +101.DEF +XBRL Taxonomy Extension Definition Linkbase Document ** +101.LAB +XBRL Taxonomy Extension Label Linkbase Document ** +101.PRE +XBRL Taxonomy Extension Presentation Linkbase Document ** +* +Management contract or compensatory plan or arrangement +** +Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities and Exchange Act of 1934, as amended and otherwise are not subject to liability under those sections. +SCHEDULE II +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS +FISCAL YEARS ENDED JUNE 27, 2015 , JUNE 28, 2014 , AND JUNE 29, 2013 +Fiscal Year Ended +2015 +2014 +2013 +(in thousands) +Allowance for Obsolete Inventory +Balance at beginning of year +$ +332 +$ +381 +$ +1,146 +Provisions +520 +257 +525 +Dispositions +(435 +) +(306 +) +(1,290 +) +Balance at end of year +$ +417 +$ +332 +$ +381 +Allowance for Doubtful Accounts +Balance at beginning of year +$ +— +$ +40 +$ +— +Provisions +97 +37 +60 +Write-offs +— +(77 +) +(20 +) +Balance at end of year +$ +97 +$ +— +$ +40 +62 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +Dated: September 4, 2015 +KEY TRONIC CORPORATION +By: +/s/ Craig D. Gates +Craig D. Gates, President and Chief Executive Officer +(Principal Executive Officer) +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated: +/s/ Craig D. Gates +September 4, 2015 +Craig D. Gates +Date +Director and President and Chief Executive Officer +(Principal Executive Officer) +/s/ Brett R. Larsen +September 4, 2015 +Brett R. Larsen +Date +Director and Executive Vice President of Administration, Chief Financial Officer and Treasurer +(Principal Financial Officer) +/s/ Ronald F. Klawitter +September 4, 2015 +Ronald F. Klawitter, Director +Date +/s/ James R. Bean +September 4, 2015 +James R. Bean, Director +Date +/s/ Yacov A. Shamash +September 4, 2015 +Yacov A. Shamash, Director +Date +/s/ Patrick Sweeney +September 4, 2015 +Patrick Sweeney, Director and Chairman of the Board +Date +63 \ No newline at end of file diff --git a/raw/filings/0000719733/2015/0000719733-15-000070/filing_metadata.csv b/raw/filings/0000719733/2015/0000719733-15-000070/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..d4e2544bf5dca7d59bf39f6d8188b837085b1081 --- /dev/null +++ b/raw/filings/0000719733/2015/0000719733-15-000070/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000719733,KTCC,KEY TRONIC CORP,10-K,2015-09-04,2015-06-27,2015-09-04T17:27:56.000Z,0000719733-15-000070,ktcc-06272015x10k.htm,10-K,8498693,1,0,https://www.sec.gov/Archives/edgar/data/719733/000071973315000070/ktcc-06272015x10k.htm,https://www.sec.gov/Archives/edgar/data/719733/000071973315000070/,2015,2015,1 diff --git a/raw/filings/0000719733/2015/0000719733-15-000070/item1.txt b/raw/filings/0000719733/2015/0000719733-15-000070/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..ee07adae542518603c7ab095725e1c47b3306334 --- /dev/null +++ b/raw/filings/0000719733/2015/0000719733-15-000070/item1.txt @@ -0,0 +1,105 @@ +Item 1. +BUSINESS +Background +Key Tronic Corporation (dba: KeyTronicEMS Co.) was organized in 1969, as a Washington corporation that locally manufactured computer keyboards. The ability to design, build and deliver a quality product led us to become a leading independent manufacturer of keyboards for computers in the United States. Our fully integrated design, tooling, and automated manufacturing capabilities enabled us to rapidly respond to customers’ needs for keyboards in production quantities worldwide. We supported our sales growth through the development and purchase of international manufacturing facilities. As the computer keyboard market matured with increasing competition from other international providers, we determined that our business could no longer solely rely on keyboard sales. +After assessing market conditions and our strengths and capabilities, we shifted focus from keyboard manufacturing to contract manufacturing for a wide range of products. Our unique strategic attributes are based on our core strengths of innovative design and engineering expertise in electronics, mechanical engineering, sheet metal fabrication and stamping, and precision plastics combined with high-quality, low cost production, and assembly on an international basis while providing exceptional customer service. These strengths have made our company a strong competitor in the electronic manufacturing services (EMS) market. +Acquisitions +On September 3, 2014, we completed the acquisition of all of the outstanding shares of CDR Manufacturing, Inc. (dba Ayrshire Electronics), which added five locations (four in North America and one in Mexico). Subsequent to the acquisition, the Reynosa, Mexico operations were transferred to the Company’s existing Juarez, Mexico facilities. This acquisition expands our printed circuit board assembly capacity, total revenue, and adds to and diversifies our customer base with the addition of many new multi-national companies. +On July 1, 2013, the Company acquired substantially all of the assets of Sabre Assembly & Manufacturing Co. of Texas (“Sabre”), a sheet metal fabrication company with facilities located in Juarez, Mexico. The acquisition of Sabre enables the Company to offer metal fabrication directly to its customers, in combination with plastic molding, PCB assembly, complete product assembly, design engineering and testing engineering services. +Our Industry and Strategy +The expansion of the EMS industry and recent acquisition has allowed us to continue to expand our customer base and the industries that we serve. The increase in new programs represents a growing portion of our revenue and a promising foundation for our future. In keeping with our long-term strategic objectives, we have been successfully building a more diversified customer portfolio, spanning a wider range of industries. We currently offer our customers the following services: integrated electronic and mechanical engineering, precision plastic molding, sheet metal fabrication, PCB and complete product assembly, component selection, sourcing and procurement, worldwide logistics, and new product testing and production all at competitive pricing due to our global footprint. +4 +We believe that we are well positioned in the EMS industry to continue the expansion of our customer base and achieve long term growth. Our unique blend of multinational facilities, vertical integration, centralized management, and core strengths continue to support our growth and our customers’ needs. We continue to focus on controlling operating expenses and leveraging the synergistic capabilities of our world-class facilities in the United States, Mexico, and China. This international production capability provides our customers with the benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs, and reduced product fulfillment time. Given our competitive advantages and the growing pressure for new potential customers to move forward with their outsourcing strategies, we are strongly positioned to win new business in coming periods and grow our revenue and profits. +The EMS industry is intensely competitive. Although our customer base is growing, we still have less than 1% of the potential global market and our revenue can fluctuate significantly due to reliance on a concentrated base of customers. We are planning for new customer growth in the coming quarters by securing new programs with new and existing customers, increasing our worldwide manufacturing capacity, and continuing to improve our manufacturing and procurement processes. Ongoing challenges that we face include but are not limited to the following: Continuing to win programs from new and existing customers, balancing production capacity and key personnel in support of new customer programs, improving operating efficiencies, controlling costs while developing competitive pricing strategies, and successfully transitioning new program wins to full production. +Customers and Marketing +We provide a mix of manufacturing services for outsourced Original Equipment Manufacturing (OEM) products. We provide the following EMS services: Product design, surface mount technologies (SMT) and pin through hole capability for printed circuit board assembly, tool making, precision plastic molding, sheet metal fabrication, liquid injection molding, complex assembly, automated tape winding, prototype design and full product assembly. +Sales of the majority of our products have not historically been seasonal in nature, but may be seasonal in the future if there are changes in the types of products manufactured. Sales can, however, fluctuate significantly between quarters from changes in customers and customer demand due to the concentration of sales generated by our largest customers. +For the fiscal years 2015 , 2014 and 2013 , the five largest customers in each year accounted for 42%, 62% and 71% of combined total net sales, respectively. This decrease was primarily the result of the acquisition of Ayrshire as well as the impact of the reduction in production levels for certain longstanding customers. We continue to diversify our customer base by adding additional programs and customers. As these new customers’ sales ramp up and new programs are won, our concentration of revenue should continue to decrease in the future. +The following table represents all customers that represented 10% or more of total net sales during the last three fiscal years: +Percentage of Net Sales by Fiscal Year +2015 +2014 +2013 +Customer A +17% +20% +19% +Customer B +* +15% +23% +Customer C +* +15% +21% +* Current customer amount represents less than 10%. +There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +Although keyboard manufacturing is still included in our product offerings, we do not expect annual keyboard sales to be a material component of our business. We recognized keyboard revenue of approximately $1.9 million , $2.3 million and $2.4 million in fiscal years 2015 , 2014 and 2013 , respectively. In order to accommodate the demand for standard keyboard layouts, we maintain a purchase-from-stock program. The more popular standard layouts are built and stocked for immediate availability. +We market our products and services primarily through our direct sales department aided by strategically located field sales people and distributors. We also maintain relationships with several independent sales organizations to assist in marketing our EMS product lines. +5 +Manufacturing +We have continually made investments in developing and expanding a capital equipment base to achieve vertical integration and efficiencies in our manufacturing processes. We have invested significant capital into SMT for volume manufacturing of complex printed circuit board assemblies and in our metal shop providing precision metal stamping, fabricating, and finishing. We also design and develop tooling for injection molding and manufacture the majority of plastic parts used in the products we manufacture. Additionally, we have equipment to maintain a controlled clean environment for manufacturing processes that require a high level of precise control. +We use a variety of manual and automated assembly processes in our facilities, depending upon product complexity and degree of customization. Some examples of automated processes include component insertion, SMT, selective soldering, flexible robotic assembly, automated storage tape winding, computerized vision system quality inspection, laser turrets, automated switch and key top installation, and automated functional testing. +Our engineering expertise and automated manufacturing processes enable us to work closely with our customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. We use computer-aided design techniques and software to assist in preparation of the tool design layout and component placement, to reduce tooling and production costs, improve component and product quality, and enhance turnaround time during product development. +We purchase materials and components for our products from many different suppliers, including both domestic and international sources. We develop close working relationships with our suppliers, many of whom have been supplying products to us for several years. +Research, Development, and Engineering +As part of our long-term strategy, we are committed to supporting our customers by providing research, development, and engineering services. These services allow us to facilitate in optimizing new product designs, and the production processes of our customers programs. +Research, development, and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials costs, depreciation, and allocated information technology and facilities costs. +Competition +The market for the products and services we provide is highly competitive. There are numerous competitors in the EMS industry, many of which have substantially more resources and are more geographically diverse than we are. Some of our competitors have similar international production capabilities, large financial resources and some have substantially greater manufacturing, research and development, and marketing resources. There is also competition from the manufacturing operations of our current and potential customers, who are continually evaluating the merits of manufacturing their products internally versus the advantages of outsourcing. We believe that we can currently compete favorably in these areas primarily on the basis of our international footprint, responsiveness, creativity, vertical production capability, quality, and cost. +Trademarks +Our name and logo are federally registered trademarks, and we believe they are valuable assets of our business. We operate under the trade name “KeyTronicEMS” to better identify our primary business concentration in contract manufacturing in the EMS industry. +Employees +We consider our employees to be our primary strength and we make considerable efforts to maintain a well-qualified workforce. Our employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. We regularly provide transportation, medical services, and meals to all of our employees in foreign locations. The Company also has defined contribution plans available to U.S. employees who have attained age 21 and provide group health, life, and disability insurance plans. We also maintain share based compensation plans and other long term incentive plans for certain employees and outside directors. +As of June 27, 2015 we had 4,866 employees compared to 3,343 on June 28, 2014 , and 2,584 on June 29, 2013 . Since we can have significant fluctuations in product demand, we seek to maintain flexibility in our workforce by utilizing skilled temporary and short-term contract labor in our manufacturing facilities in addition to full-time employees. +6 +Backlog +On July 24, 2015 our order backlog was valued at approximately $115.2 million, compared to approximately $103.1 million on July 26, 2014. The amount of backlog is not necessarily indicative of future sales but can be indicative of trends in expected future sales revenue. Due to the relationships with our customers, we will occasionally allow orders to be canceled or rescheduled and as a result it is not a meaningful indicator of future financial results. If there are canceled or rescheduled orders, we typically negotiate fees to cover the costs we have incurred. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change due to design modifications, customer forecast changes, or other customer requirements. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in Note 12, “Enterprise-Wide Disclosures” of the consolidated financial statements of this Annual Report on Form 10-K and that information is incorporated herein. +Executive Officers of the Registrant +The table below sets forth the name, current age and current position of our executive officers and other significant employees: +Name +Age +Positions Held +Executive Officers +Craig D. Gates +56 +President and Chief Executive Officer +Brett R. Larsen +42 +Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Douglas G. Burkhardt +57 +Executive Vice President of Worldwide Operations +Philip S. Hochberg +53 +Executive Vice President of Business Development +Lawrence J. Bostwick +63 +Vice President of Engineering and Quality +Frank Crispigna III +54 +Vice President of Materials +Duane D. Mackleit +47 +Vice President of Program Management +Executive Officers +CRAIG D. GATES – President and Chief Executive Officer +Mr. Gates, age 56 , has been President and Chief Executive officer of the Company since April 2009. Previously, he was Executive Vice President and General Manager from August 2002 to April 2009. He served as Executive Vice President of Marketing, Engineering and Sales from July 1997 to August 2002 and served as Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of 1994. From 1982 to 1991 he held various engineering and management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. Mr. Gates has a Bachelor of Science Degree in Mechanical Engineering and a Masters in Business Administration from the University of Illinois, Urbana. +BRETT R. LARSEN – Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Mr. Larsen, age 42 , has served as Executive Vice President of Administration, Chief Financial Officer, and Treasurer since July 2015. Previously, he was Vice President of Finance and Controller from February 2010 to July 2015. He was Chief Financial Officer of FLSmidth Spokane, Inc. from December 2008 to February 2010. From October 2005 through November 2008, Mr. Larsen served as Controller of Key Tronic Corporation. From May 2004 to October 2005, Mr. Larsen served as Manager of Financial Reporting of Key Tronic Corporation. From 2002 to May 2004, Mr. Larsen was an audit manager for the public accounting firm BDO Seidman, LLP. He also held various auditing and supervisory positions with Grant Thornton LLP from 1997 to 2002. Mr. Larsen has a Bachelor of Science degree in Accounting and a Masters degree in Accounting from Brigham Young University and is a Certified Public Accountant. +7 +DOUGLAS G. BURKHARDT – Executive Vice President of Worldwide Operations +Mr. Burkhardt, age 57 , has been Executive Vice President of Worldwide Operations of the Company since July 2010. Previously Mr. Burkhardt was Vice President of Worldwide Operations from July 2008 to July 2010 and Director of China Operations and Program Management from January 2006 to July 2008. Mr. Burkhardt also served as Director of Northwest and China Operations from November of 1998 to January of 2006. Mr. Burkhardt also served as Director of Customer Satisfaction from March 1997 to November 1998 and Director of Molding from September of 1995 to March of 1997. Prior to this, Mr. Burkhardt served in other various senior management positions within the Company. Mr. Burkhardt has been with the Company since May of 1989. Prior to joining Key Tronic, Mr. Burkhardt worked for House of Aluminum and Glass for 12 years where he was the plant manager. +PHILIP S. HOCHBERG – Executive Vice President of Business Development +Mr. Hochberg, age 53 , has been Executive Vice President of Business Development since July 2012. Prior this, Mr. Hochberg served as Vice President of Business Development from October 2009 through June 2012. He was Director of Business Development and Program Management from July 2008 to October 2009. Mr. Hochberg served as Director of Business Development from October 2004 to July 2008 and as Director of EMS Sales and Marketing from July 2000 to October 2004. Prior to joining Key Tronic, Mr. Hochberg worked for Quinton Instrument Company as their Director of Marketing and Product Management from 1992 to 2000. From 1988 to 1992, he was employed by SpaceLabs Medical as their Business Development Marketing Manager. Mr. Hochberg has an MBA from the University of British Columbia, a BA Psychology, with a minor in Business from Washington University in St. Louis. +LAWRENCE J. BOSTWICK – Vice President of Engineering and Quality +Mr. Bostwick, age 63 , has been Vice President of Engineering and Quality since July 2008. Previously he was Director of Engineering and Quality from February 2007 to July 2008 and served as Corporate Director of Quality from February 2006 to February 2007. From 2003 to 2006 he was Director of Supply Chain Management and Quality for the Lancer Corporation and from 1998 to 2003 he was Vice President of Operations for Thermacore International. He is a graduate of the Westinghouse and General Electric – Engineering and Manufacturing Professional Development Programs. He is certified in both Quality and Industrial Engineering and is a Lean – Six Sigma Master Black Belt. Mr. Bostwick has a combined B.S. degree in Production and Operation and Industrial Engineering from Bowling Green State University and a Masters degree in Industrial Engineering and Business Administration from Syracuse University. +FRANK CRISPIGNA III – Vice President of Materials +Mr. Crispigna, age 54 , has been Vice President of Materials of the company since October 2011. Prior to this, Mr. Crispigna held a variety of Materials and Supply Chain positions at Plexus Corporation since 1997, most recently serving as the Director – Supply Chain Solutions from 2005 - 2011. He has a Masters degree in Business Administration, and a Bachelor of Business Administration Degree in Marketing from the University of Wisconsin – Oshkosh. Mr. Crispigna also is a C.P.M., and received his certification in Supply Chain Leadership from the University of Wisconsin. +DUANE D. MACKLEIT – Vice President of Program Management +Mr. Mackleit, age 47 , has been Vice President of Program Management of the company since July 2012. He served as Director of Program Management from July 2008 through June 2012. From May 2006 to July 2008 he served as Principal Program Manager. Prior to that, he served as Program Manager from March 2002 to May 2006 and Associate Program Manager from August 2000 to March 2002. Mr. Mackleit has also held several other positions with Key Tronic Corporation. Mr. Mackleit has an AA in Business from Spokane Falls Community College and a BA in Business/Marketing from Eastern Washington University. He also holds a MBA from Gonzaga University. +Available Information +Our principal executive offices are located at 4424 North Sullivan Road, Spokane Valley, Washington 99216, and our telephone number is (509) 928-8000. Our website is located at http://www.keytronicems.com where filings of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or current reports on Form 8-K are available after they have been filed with the Securities and Exchange Commission. The information presented on our website currently and in the future is not considered to be part of this document or any document incorporated by reference in this document. +8 \ No newline at end of file diff --git a/raw/filings/0000719733/2015/0000719733-15-000070/item13.txt b/raw/filings/0000719733/2015/0000719733-15-000070/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..8097716277e700911ab83986cdcf5ada6de86e23 --- /dev/null +++ b/raw/filings/0000719733/2015/0000719733-15-000070/item13.txt @@ -0,0 +1,3 @@ +Item 13: +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions”, “Compensation Committee Interlocks and Insider Participation”, and “Directors’ Independence” in the Company’s 2015 Proxy Statement is incorporated herein by this reference. \ No newline at end of file diff --git a/raw/filings/0000719733/2015/0000719733-15-000070/item9a.txt b/raw/filings/0000719733/2015/0000719733-15-000070/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..5602f93f862184d48eeba220813fc462756075cf --- /dev/null +++ b/raw/filings/0000719733/2015/0000719733-15-000070/item9a.txt @@ -0,0 +1,26 @@ +Item 9A: +CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +It is the responsibility of our management to establish, maintain, and monitor disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 are recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Additionally, these disclosure controls include controls and procedures that are designed to accumulate and communicate the information required to be disclosed to our Company’s Chief Executive Officer and Chief Financial Officer, allowing for timely decisions regarding required disclosures. As of the end of the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(f). Based on our assessment, we believe that as of June 27, 2015 , the Company’s disclosure controls and procedures are effective based on that criteria. +Management’s Report on Internal Control over Financial Reporting +Our management has the responsibility to establish and maintain adequate internal controls over our financial reporting, as defined in Rule 13a-15(f) under the Securities and Exchange Act of 1934. Our internal controls are designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our external financial statements in accordance with generally accepted accounting principles (GAAP). +Due to inherent limitations of any internal control system, management acknowledges that there are limitations as to the effectiveness of internal controls over financial reporting and therefore recognize that only reasonable assurance can be gained from any internal control system. Accordingly, our internal control system may not detect or prevent material misstatements in our financial statements and projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, we have performed an assessment of the effectiveness of our internal controls over financial reporting as of June 27, 2015 . This assessment was based on the criteria established in Internal Control-Integrated Framework (1992), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that as of June 27, 2015 , the Company’s internal control over financial reporting is effective based on that criteria. +The effectiveness of the Company's internal control over financial reporting as of June 27, 2015 has been audited by BDO USA LLP, an independent registered public accounting firm, as stated in their report which is included herein. +Changes in Internal Control over Financial Reporting +There have been no significant changes in our internal controls over financial reporting during our fourth fiscal quarter ended June 27, 2015 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)). +55 +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Key Tronic Corporation +Spokane Valley, Washington +We have audited Key Tronic Corporation's internal control over financial reporting as of June 27, 2015, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Key Tronic Corporation's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Item 9A “Management's Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, Key Tronic Corporation maintained, in all material respects, effective internal control over financial reporting as of June 27, 2015, based on the COSO criteria . +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Key Tronic Corporation as of June 27, 2015 and June 28, 2014, and the related consolidated statements of income, comprehensive (loss) income, shareholders' equity, and cash flows for each of the three years in the period ended June 27, 2015 and our report dated September 4, 2015, expressed an unqualified opinion thereon. +/s/ BDO USA, LLP +Spokane, Washington +September 4, 2015 +56 \ No newline at end of file diff --git a/raw/filings/0000719733/2015/0000719733-15-000070/rp_note.txt b/raw/filings/0000719733/2015/0000719733-15-000070/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000719733/2015/0000719733-15-000070/rpt_disclosure.txt b/raw/filings/0000719733/2015/0000719733-15-000070/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..2d75a5ee4d4e2f50bd78cf893036b3892ad5787d --- /dev/null +++ b/raw/filings/0000719733/2015/0000719733-15-000070/rpt_disclosure.txt @@ -0,0 +1,5 @@ +Related Person Transactions +In April 2007, the Board of Directors adopted a written policy and procedures for the approval or ratification of Interested Transactions with Related Parties. The policy and procedures supplement the Company’s Code of Conduct. The policy defines an “Interested Transaction” as any transaction, arrangement or relationship or series of similar transactions, arrangements or relationships (including any indebtedness or guarantee of indebtedness) in which (1) the aggregate amount involved will or may be expected to exceed $120,000 in any calendar year, (2) the Company is a participant, and (3) any Related Party has or will have a direct or indirect interest (other than solely as a result of being a director or a less than 10 percent beneficial owner of another entity). +The policy defines a “Related Party” as any (a) person who is or was (since the beginning of the last fiscal year for which the Company has filed a Form 10-K and proxy statement, even if they do not presently serve in that role) an executive officer, director or nominee for election as a director, (b) greater than 5 percent beneficial owner of the Company’s common stock, or (c) immediate family member of any of the foregoing. Immediate family member includes a person’s spouse, parents, stepparents, children, stepchildren, siblings, mothers- and fathers-in-law, sons- and daughters-in-law, and brothers- and sisters-in-law and anyone residing in such person’s home (other than a tenant or employee). +The Audit Committee is responsible for review, approval, ratification or disapproval of Interested Transactions. In determining whether to approve or ratify an Interested Transaction, the Committee will take into account, among other factors it deems appropriate, whether the Interested Transaction is on terms no less favorable than terms generally available to an unaffiliated third party under the same or similar circumstances and the extent of the Related Party’s interest in the Transaction. +7 \ No newline at end of file diff --git a/raw/filings/0000719733/2016/0000719733-16-000164/filing.txt b/raw/filings/0000719733/2016/0000719733-16-000164/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..85df085db1e71b6131dd8fb76349125a4cc0a456 --- /dev/null +++ b/raw/filings/0000719733/2016/0000719733-16-000164/filing.txt @@ -0,0 +1,3418 @@ +10-K +1 +ktcc-07022016x10k.htm +10-K +Document +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +____________________________________________________________ +FORM 10-K +____________________________________________________________ +x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE FISCAL YEAR ENDED JULY 2, 2016 +OR +¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE PERIOD FROM TO +Commission File Number 0-11559 +____________________________________________________________ +KEY TRONIC CORPORATION +(Exact name of registrant as specified in its charter) +____________________________________________________________ +Washington +91-0849125 +(State or other jurisdiction of +Incorporation or organization) +(I.R.S. Employer +Identification No.) +N. 4424 Sullivan Road, Spokane Valley, +Washington +99216 +(Address of principal executive offices) +(Zip Code) +(509) 928-8000 +(Registrant’s telephone number, including area code) +N/A +(Former name, former address and former fiscal year, if changed since last report) +____________________________________________________________ +Securities Registered Pursuant to Section 12(b) of the Act: None +Title of each class +Name of each exchange on which registered +Common stock, no par value +The NASDAQ Stock Market LLC +Securities Registered Pursuant to Section 12(g) of the Act: None +____________________________________________________________ +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ¨ No x +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulations S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. +(Check one): +Large accelerated filer +¨ +Accelerated filer +x +Non-accelerated filer +¨ (Do not check if a smaller reporting company) +Smaller reporting company +¨ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x +State the aggregate market value of the voting and non-voting common equity held by non affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. +As of December 26, 2015, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $79.2 million based on the closing price as reported on the NASDAQ. +Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: 10,756,018 shares of common stock were outstanding as of September 7, 2016 . +____________________________________________________________ +Documents Incorporated by Reference: +Certain information is incorporated into Part III of this report by reference to the Proxy Statement for the registrant's 2017 annual meeting of stockholders to be filed with the Securities and Exchange Commission pursuant to Regulation 14A not later than 120 days after the end of the fiscal year covered by this Form 10-K. +KEY TRONIC CORPORATION +2016 FORM 10-K +TABLE OF CONTENTS +Page No. +PART I +Item 1. +Business +4 +Item 1A. +Risk Factors +9 +Item 1B. +Unresolved Staff Comments +14 +Item 2. +Properties +15 +Item 3. +Legal Proceedings +16 +Item 4. +Mine Safety Disclosures +16 +PART II +Item 5. +Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities +16 +Item 6. +Selected Financial Data +18 +Item 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +19 +Item 7A. +Quantitative and Qualitative Disclosures about Market Risk +29 +Item 8. +Financial Statements and Supplementary Data +30-54 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +55 +Item 9A. +Controls and Procedures +55 +Item 9B. +Other Information +57 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +57 +Item 11. +Executive Compensation +57 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +57 +Item 13. +Certain Relationships and Related Transactions, and Director Independence +58 +Item 14. +Principal Accounting Fees and Services +58 +PART IV +Item 15. +Exhibits and Financial Statement Schedule +58 +Signatures +63 +3 +FORWARD-LOOKING STATEMENTS +References in this report to “the Company,” “Key Tronic,” “KeyTronicEMS,” “we,” “our,” or “us” mean Key Tronic Corporation together with its subsidiaries, except where the context otherwise requires. +This Annual Report on Form 10-K contains forward-looking statements in addition to historical information. Forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those reflected in the forward-looking statements. Risks and uncertainties that might cause such differences include, but are not limited to those outlined in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risks and Uncertainties that May Affect Future Results.” Readers are cautioned not to place undue reliance on forward-looking statements, which reflect management’s opinions only as of the date hereof. The Company undertakes no obligation to update forward-looking statements to reflect developments or information obtained after the date hereof and disclaims any obligation to do so. Readers should carefully review the risk factors described in periodic reports the Company files from time to time with the Securities and Exchange Commission, including Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. +PART I +Item 1. +BUSINESS +Background +Key Tronic Corporation (dba: KeyTronicEMS Co.) was organized in 1969, as a Washington corporation that locally manufactured computer keyboards. The ability to design, build and deliver a quality product led us to become a leading independent manufacturer of keyboards for computers in the United States. Our fully integrated design, tooling, and automated manufacturing capabilities enabled us to rapidly respond to customers’ needs for keyboards in production quantities worldwide. We supported our sales growth through the development and purchase of international manufacturing facilities. As the computer keyboard market matured with increasing competition from other international providers, we determined that our business could no longer solely rely on keyboard sales. +After assessing market conditions and our strengths and capabilities, we shifted our focus from keyboard manufacturing to contract manufacturing for a wide range of products. Our unique strategic attributes are based on our core strengths of innovative design and engineering expertise in electronics, mechanical engineering, sheet metal fabrication and stamping, and precision plastics combined with high-quality, low cost production, and assembly on an international basis while providing exceptional customer service. These strengths have made our company a strong competitor in the electronic manufacturing services (EMS) market. +Acquisitions +On September 3, 2014, we completed the acquisition of all of the outstanding shares of CDR Manufacturing, Inc. (dba Ayrshire Electronics), which added five locations (four in North America and one in Mexico). This acquisition expanded our printed circuit board assembly capacity, total revenue, and adds to and diversifies our customer base with the addition of many new multi-national companies. Subsequent to the acquisition, the Reynosa, Mexico operations were transferred to the Company’s existing Juarez, Mexico facilities. During the fourth quarter of fiscal year 2016, we announced a plan to close the Harrodsburg, Kentucky facility which is expected to occur by the end of the first quarter of 2017. Most of our customer programs from the Harrodsburg, Kentucky facility are being transferred to other Key Tronic facilities. +On July 1, 2013, the Company acquired substantially all of the assets of Sabre Assembly & Manufacturing Co. of Texas (“Sabre”), a sheet metal fabrication company with facilities located in Juarez, Mexico. We have made substantial investments in our sheet metal fabrication capabilities and capacity and will continue to do so as customer demands increase and evolve. The significant investment in sheet metal capabilities enables the Company to offer metal fabrication directly to its customers, in combination with plastic molding, PCB assembly, complete product assembly, design engineering and testing engineering services. +Our Industry and Strategy +The expansion of the EMS industry and our acquisitions have allowed us to continue to expand our customer base and the industries that we serve. The increase in new programs represents a growing portion of our revenue and a promising foundation for our future. In keeping with our long-term strategic objectives, we have been successfully building a more diversified customer portfolio, spanning a wider range of industries. We currently offer our customers the following services: integrated electronic and mechanical engineering, precision plastic molding, sheet metal fabrication, printed circuit board (PCB) and complete product assembly, component selection, sourcing and procurement, worldwide logistics, and new product testing and production all at competitive pricing due to our global footprint. +4 +We believe that we are well positioned in the EMS industry to continue the expansion of our customer base and achieve long term growth. Our unique blend of multinational facilities, vertical integration, centralized management, and core strengths continue to support our growth and our customers’ needs. We continue to focus on controlling operating expenses and leveraging the synergistic capabilities of our world-class facilities in the United States, Mexico, and China. This international production capability provides our customers with the benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs, and reduced product fulfillment time. Given our competitive advantages and the growing pressure for new potential customers to move forward with their outsourcing strategies, we are strongly positioned to win new business in coming periods and grow our revenue and profits. +The EMS industry is intensely competitive. Although our customer base is growing, we still have less than 1% of the potential global market and our revenue can fluctuate significantly due to reliance on a concentrated base of customers. We are planning for new customer growth in the coming quarters by securing new programs with new and existing customers, increasing our worldwide manufacturing capacity, and continuing to improve our manufacturing and procurement processes. Ongoing challenges that we face include but are not limited to the following: Continuing to win programs from new and existing customers, balancing capital employed, production capacity and key personnel in support of new customer programs, improving operating efficiencies, controlling costs while developing competitive pricing strategies, and successfully transitioning new program wins to full production. +Customers and Marketing +We provide a mix of manufacturing services for outsourced Original Equipment Manufacturing (OEM) products. We provide the following EMS services: Product design, surface mount technologies (SMT) and pin through hole capability for printed circuit board assembly, tool making, precision plastic molding, sheet metal fabrication, liquid injection molding, complex assembly, automated tape winding, prototype design and full product assembly. +Sales of the majority of our products have not historically been seasonal in nature, but may be seasonal in the future if there are changes in the types of products manufactured. Sales can, however, fluctuate significantly between quarters from changes in customers and customer demand due to the concentration of sales generated by our largest customers. +For the fiscal years 2016 , 2015 and 2014 , the five largest customers in each year accounted for 41%, 42% and 62% of combined total net sales, respectively. The decrease in concentration compared to 2014 was primarily the result of the acquisition of Ayrshire as well as the impact of the reduction in production levels for a certain longstanding customer. We continue to diversify our customer base by adding additional programs and customers. We expect net sales to our five largest customers as a percentage of total net sales to approximate current levels going forward. +The following table represents all customers that represented 10% or more of total net sales during the last three fiscal years: +Percentage of Net Sales by Fiscal Year +2016 +2015 +2014 +Customer A +18% +17% +20% +Customer B +* +* +15% +Customer C +* +* +15% +* Current customer amount represents less than 10%. +There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +We market our products and services primarily through our direct sales department which is comprised of strategically located field sales people and distributors. We also maintain relationships with several independent sales organizations to assist in marketing our EMS product lines. +5 +Manufacturing +We have continually made investments in developing and expanding a capital equipment base to achieve vertical integration and efficiencies in our manufacturing processes. We have invested significant capital into SMT for volume manufacturing of complex printed circuit board assemblies and in our metal shop providing precision metal stamping, fabricating, and finishing. We also design and develop tooling for injection molding and sheet metal fabrication and manufacture the majority of plastic and sheet metal parts used in the products we manufacture. Additionally, we have equipment to maintain a controlled clean environment for manufacturing processes that require a high level of precise control. +We use a variety of manual and automated assembly processes in our facilities, depending upon product complexity and degree of customization. Some examples of automated processes include component insertion, SMT, selective soldering, flexible robotic assembly, automated storage tape winding, computerized vision system quality inspection, laser turrets, automated switch and key top installation, and automated functional testing. +Our engineering expertise and automated manufacturing processes enable us to work closely with our customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. We use computer-aided design techniques and software to assist in preparation of the tool design layout and component placement, to reduce tooling and production costs, improve component and product quality, and enhance turnaround time during product development. +We purchase materials and components for our products from many different suppliers, including both domestic and international sources. We develop close working relationships with our suppliers, many of whom have been supplying products to us for several years. +Research, Development, and Engineering +As part of our long-term strategy, we are committed to supporting our customers by providing research, development, and engineering services. These services allow us to facilitate in optimizing new product designs, and the production processes of our customers' programs. +Research, development, and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials costs, depreciation, and allocated information technology and facilities costs. +Competition +The market for the products and services we provide is highly competitive. There are numerous competitors in the EMS industry, many of which have substantially more resources and are more geographically diverse than we are. Some of our competitors have similar international production capabilities, large financial resources and some have substantially greater manufacturing, research and development, and marketing resources. There is also competition from the manufacturing operations of our current and potential customers, who are continually evaluating the merits of manufacturing their products internally versus the advantages of outsourcing. We believe that we can currently compete favorably in these areas primarily on the basis of our international footprint, responsiveness, creativity, vertical production capability, quality, and cost. +Trademarks +Our name and logo are federally registered trademarks, and we believe they are valuable assets of our business. We operate under the trade name “KeyTronicEMS” to better identify our primary business concentration in contract manufacturing in the EMS industry. +Employees +We consider our employees to be our primary strength and we make considerable efforts to maintain a well-qualified workforce. Our employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. We regularly provide transportation, medical services, and meals to all of our employees in foreign locations. The Company also has defined contribution plans available to U.S. employees who have attained age 21 and provide group health, life, and disability insurance plans. We also maintain share based compensation plans and other long term incentive plans for certain employees and outside directors. +As of July 2, 2016 we had 4,947 employees compared to 4,866 on June 27, 2015 , and 3,343 on June 28, 2014 . Since we can have significant fluctuations in product demand, we seek to maintain flexibility in our workforce by utilizing skilled temporary and short-term contract labor in our manufacturing facilities in addition to full-time employees. +6 +Backlog +On July 30, 2016 our order backlog was valued at approximately $122.2 million, compared to approximately $115.2 million on July 24, 2015. The amount of backlog is not necessarily indicative of future sales but can be indicative of trends in expected future sales revenue. Due to the relationships with our customers, we will occasionally allow orders to be canceled or rescheduled and as a result it is not a meaningful indicator of future financial results. If there are canceled or rescheduled orders, we typically negotiate fees to cover the costs we have incurred. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change due to design modifications, customer forecast changes, or other customer requirements. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in Note 12, “Enterprise-Wide Disclosures” of the consolidated financial statements of this Annual Report on Form 10-K and that information is incorporated herein. +Executive Officers of the Registrant +The table below sets forth the name, current age and current position of our executive officers and other significant employees: +Name +Age +Positions Held +Executive Officers +Craig D. Gates +57 +President and Chief Executive Officer +Brett R. Larsen +43 +Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Douglas G. Burkhardt +58 +Executive Vice President of Worldwide Operations +Philip S. Hochberg +54 +Executive Vice President of Business Development +Lawrence J. Bostwick +64 +Vice President of Engineering and Quality +Frank Crispigna III +55 +Vice President of Materials +Duane D. Mackleit +48 +Vice President of Program Management +Executive Officers +CRAIG D. GATES – President and Chief Executive Officer +Mr. Gates, age 57 , has been President and Chief Executive officer of the Company since April 2009. Previously, he was Executive Vice President and General Manager from August 2002 to April 2009. He served as Executive Vice President of Marketing, Engineering and Sales from July 1997 to August 2002 and served as Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of 1994. From 1982 to 1991 he held various engineering and management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. Mr. Gates has a Bachelor of Science Degree in Mechanical Engineering and a Masters in Business Administration from the University of Illinois, Urbana. +BRETT R. LARSEN – Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Mr. Larsen, age 43 , has served as Executive Vice President of Administration, Chief Financial Officer, and Treasurer since July 2015. Previously, he was Vice President of Finance and Controller from February 2010 to July 2015. He was Chief Financial Officer of FLSmidth Spokane, Inc. from December 2008 to February 2010. From October 2005 through November 2008, Mr. Larsen served as Controller of Key Tronic Corporation. From May 2004 to October 2005, Mr. Larsen served as Manager of Financial Reporting of Key Tronic Corporation. From 2002 to May 2004, Mr. Larsen was an audit manager for the public accounting firm BDO USA, LLP. He also held various auditing and supervisory positions with Grant Thornton LLP from 1997 to 2002. Mr. Larsen has a Bachelor of Science degree in Accounting and a Masters degree in Accounting from Brigham Young University and is a Certified Public Accountant. +7 +DOUGLAS G. BURKHARDT – Executive Vice President of Worldwide Operations +Mr. Burkhardt, age 58 , has been Executive Vice President of Worldwide Operations of the Company since July 2010. Previously Mr. Burkhardt was Vice President of Worldwide Operations from July 2008 to July 2010 and Director of China Operations and Program Management from January 2006 to July 2008. Mr. Burkhardt also served as Director of Northwest and China Operations from November of 1998 to January of 2006. Mr. Burkhardt also served as Director of Customer Satisfaction from March 1997 to November 1998 and Director of Molding from September of 1995 to March of 1997. Prior to this, Mr. Burkhardt served in other various senior management positions within the Company. Mr. Burkhardt has been with the Company since May of 1989. Prior to joining Key Tronic, Mr. Burkhardt worked for House of Aluminum and Glass for 12 years where he was the plant manager. +PHILIP S. HOCHBERG – Executive Vice President of Business Development +Mr. Hochberg, age 54 , has been Executive Vice President of Business Development since July 2012. Prior to this, Mr. Hochberg served as Vice President of Business Development from October 2009 through June 2012. He was Director of Business Development and Program Management from July 2008 to October 2009. Mr. Hochberg served as Director of Business Development from October 2004 to July 2008 and as Director of EMS Sales and Marketing from July 2000 to October 2004. Prior to joining Key Tronic, Mr. Hochberg worked for Quinton Instrument Company as their Director of Marketing and Product Management from 1992 to 2000. From 1988 to 1992, he was employed by SpaceLabs Medical as their Business Development Marketing Manager. Mr. Hochberg has an MBA from the University of British Columbia, a BA in Psychology, with a minor in Business from Washington University in St. Louis. +LAWRENCE J. BOSTWICK – Vice President of Engineering and Quality +Mr. Bostwick, age 64 , has been Vice President of Engineering and Quality since July 2008. Previously he was Director of Engineering and Quality from February 2007 to July 2008 and served as Corporate Director of Quality from February 2006 to February 2007. From 2003 to 2006 he was Director of Supply Chain Management and Quality for the Lancer Corporation and from 1998 to 2003 he was Vice President of Operations for Thermacore International. He is a graduate of the Westinghouse and General Electric – Engineering and Manufacturing Professional Development Programs. He is certified in both Quality and Industrial Engineering and is a Lean – Six Sigma Master Black Belt. Mr. Bostwick has a combined B.S. degree in Production and Operation and Industrial Engineering from Bowling Green State University and a Masters degree in Industrial Engineering and Business Administration from Syracuse University. +FRANK CRISPIGNA III – Vice President of Materials +Mr. Crispigna, age 55 , has been Vice President of Materials of the company since October 2011. Prior to this, Mr. Crispigna held a variety of Materials and Supply Chain positions at Plexus Corporation since 1997, most recently serving as the Director – Supply Chain Solutions from 2005 - 2011. He has a Masters degree in Business Administration, and a Bachelor of Business Administration Degree in Marketing from the University of Wisconsin – Oshkosh. Mr. Crispigna also is a C.P.M., and received his certification in Supply Chain Leadership from the University of Wisconsin. +DUANE D. MACKLEIT – Vice President of Program Management +Mr. Mackleit, age 48 , has been Vice President of Program Management of the company since July 2012. He served as Director of Program Management from July 2008 through June 2012. From May 2006 to July 2008 he served as Principal Program Manager. Prior to that, he served as Program Manager from March 2002 to May 2006 and Associate Program Manager from August 2000 to March 2002. Mr. Mackleit has also held several other positions with Key Tronic Corporation. Mr. Mackleit has an AA in Business from Spokane Falls Community College and a BA in Business/Marketing from Eastern Washington University. He also holds a MBA from Gonzaga University. +Available Information +Our principal executive offices are located at 4424 North Sullivan Road, Spokane Valley, Washington 99216, and our telephone number is (509) 928-8000. Our website is located at http://www.keytronic.com where filings of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or current reports on Form 8-K are available after they have been filed with the Securities and Exchange Commission. The information presented on our website currently and in the future is not considered to be part of this document or any document incorporated by reference in this document. +8 +Item 1A. +RISK FACTORS +There are risks and uncertainties that could affect our business. These risks and uncertainties include but are not limited to, the risk factors described below, in Item 7A: “Quantitative and Qualitative Disclosures about Market Risk” and elsewhere in this Form 10-K. +RISKS AND UNCERTAINTIES THAT MAY AFFECT FUTURE RESULTS +The following risks and uncertainties could affect our actual results and could cause results to differ materially from past results or those contemplated by our forward-looking statements. When used herein, the words “expects,” “believes,” “anticipates” and other similar expressions are intended to identify forward-looking statements. +We may experience fluctuations in quarterly results of operations. +Our quarterly operating results have varied in the past and may vary in the future due to a variety of factors, including adverse changes in the U.S. and global macroeconomic environment, volatility in overall demand for our customers’ products, success of customers’ programs, timing of new programs, new product introductions or technological advances by us, our customers and our competitors, and changes in pricing policies by us, our customers, our suppliers, and our competitors. Our customer base is diverse in the markets they serve, however, decreases in demand, particularly from customers that supply the education, consumer products, and gambling industries, could affect future quarterly results. Additionally, our customers could be impacted by the illiquidity of the credit markets which could directly impact our operating results. +Component procurement, production schedules, personnel and other resource requirements are based on estimates of customer requirements. Occasionally, our customers may request accelerated production that can stress resources and reduce operating margins. Conversely, our customers may abruptly lower or cancel production which may lead to a sudden, unexpected increase in inventory or accounts receivable for which we may not be reimbursed even when under contract with customers. In addition, because many of our operating expenses are relatively fixed, a reduction in customer demand can harm our gross profit and operating results. The products which we manufacture for our customers have relatively short product lifecycles. Therefore, our business, operating results and financial condition are dependent in a significant way on our ability to obtain orders from new customers and new product programs from existing customers. +Operating results can also fluctuate if changes are made to significant estimates and assumptions. Significant estimates and assumptions include the allowance for doubtful receivables, provision for obsolete and non-saleable inventory, stock-based compensation, the valuation allowance on deferred tax assets, valuation of goodwill, impairment of long-lived assets, long-term incentive compensation accrual, the provision for warranty costs, the impact of hedging activities and purchase price allocation. +We are exposed to general economic conditions, which could have a material adverse impact on our business, operating results and financial condition. +Adverse economic conditions and uncertainty in the global economy such as unstable global financial and credit markets, inflation, and recession can negatively impact our business. Unfavorable economic conditions could affect the demand for our customers’ products by triggering a reduction in orders as well as a decline in forecasts which could adversely affect our sales in future periods. Additionally, the financial strength of our customers and suppliers and their ability to obtain and rely on credit financing may affect their ability to fulfill their obligations to us and have an adverse effect on our financial results. +The majority of our sales come from a small number of customers and a decline in sales to any of these customers could adversely affect our business. +At present, our customer base is concentrated and could become more or less concentrated. There can be no assurance that our principal customers will continue to purchase products from us at current levels. Moreover, we typically do not enter into long-term volume purchase contracts with our customers, and our customers have certain rights to extend or delay the shipment of their orders. We, however, typically require that our customers contractually agree to buy back inventory purchased within specified lead times to build their products if not used. +The loss of one or more of our major customers, or the reduction, delay or cancellation of orders from such customers, due to economic conditions or other forces, could materially and adversely affect our business, operating results and financial condition. The contraction in demand from certain industries could impact our customer orders and have a negative impact on our operations over the foreseeable future. Additionally, if one or more of our customers were to become insolvent or otherwise unable to pay for the manufacturing services provided by us, our operating results and financial condition would be adversely affected. +9 +We depend on a limited number of suppliers for certain components that are critical to our manufacturing processes. A shortage of these components or an increase in their price could interrupt our operations and result in a significant change in our results of operations. +We are dependent on many suppliers, including sole source suppliers, to provide key components and raw materials used in manufacturing customers’ products. We have seen supply shortages in certain electronic components. In addition, our suppliers' facilities may also experience earthquakes, tsunamis and other natural disasters which may cause a shortage of components. This can result in longer lead times and the inability to meet our customers request for flexible production and extended shipment dates. If demand for components outpaces supply, capacity delays could affect future operations. Delays in deliveries from suppliers or the inability to obtain sufficient quantities of components and raw materials could cause delays or reductions in shipment of products to our customers which could adversely affect our operating results and damage customer relationships. +We operate in a highly competitive industry; if we are not able to compete effectively in the EMS industry, our business could be adversely affected. +Competitors may offer customers lower prices on certain high volume programs. This could result in price reductions, reduced margins and loss of market share, all of which would materially and adversely affect our business, operating results, and financial condition. If we were unable to provide comparable or better manufacturing services at a lower cost than our competitors, it could cause sales to decline. In addition, competitors can copy our non-proprietary designs and processes after we have invested in development of products for customers, thereby enabling such competitors to offer lower prices on such products due to savings in development costs. +Cash and cash equivalents are exposed to concentrations of credit risk. +We place our cash with high credit quality institutions. At times, such balances may be in excess of the federal depository insurance limit or may be on deposit at institutions which are not covered by insurance. If such institutions were to become insolvent during which time it held our cash and cash equivalents in excess of the insurance limit, it could be necessary to obtain other credit financing to operate our facilities. +Our ability to secure and maintain sufficient credit arrangements is key to our continued operations. +There is no assurance that we will be able to retain or renew our credit agreements in the future. In the event the business grows rapidly or the uncertain macroeconomic climate continues, additional financing resources could be necessary in the current or future fiscal years. There is no assurance that we will be able to obtain equity or debt financing at acceptable terms, or at all in the future. For a summary of our banking arrangements, see Note 4 Long-Term Debt of the “Notes to Consolidated Financial Statements.” +Our operations may be subject to certain risks. +We manufacture product in facilities located in Mexico, China and the United States. These operations may be subject to a number of risks, including: +• +difficulties in staffing, turnover and managing onshore and offshore operations; +• +political and economic instability (including acts of terrorism, pandemics, civil unrest, forms of violence and outbreaks of war), which could impact our ability to ship, manufacture, and/or receive product; +• +unexpected changes in regulatory requirements and laws; +• +longer customer payment cycles and difficulty collecting accounts receivable; +• +export duties, import controls and trade barriers (including quotas); +• +governmental restrictions on the transfer of funds; +• +burdens of complying with a wide variety of foreign laws and labor practices; +• +our locations may be impacted by hurricanes, tornadoes, earthquakes, water shortages, tsunamis, floods, typhoons, fires, extreme weather conditions and other natural or man-made disasters. +Our operations in certain foreign locations receive favorable income tax treatment in the form of tax credits or other incentives. In the event that such tax incentives are not extended, are repealed, or we no longer qualify for such programs, our taxes may increase, which would reduce our net income. +Additionally, certain foreign jurisdictions restrict the amount of cash that can be transferred to the U.S or impose taxes and penalties on such transfers of cash. To the extent we have excess cash in foreign locations that could be used in, or is needed by, our operations in the United States, we may incur significant penalties and/or taxes to repatriate these funds. +10 +Fluctuations in foreign currency exchange rates could increase our operating costs. +We have manufacturing operations located in Mexico and China. A significant portion of our operations are denominated in the Mexican peso and the Chinese currency, the renminbi ("RMB"). Currency exchange rates fluctuate daily as a result of a number of factors, including changes in a country's political and economic policies. Volatility in the currencies of our entities and the United States dollar could seriously harm our business, operating results and financial condition. The primary impact of currency exchange fluctuations is on the cash, receivables, payables and expenses of our operating entities. As part of our hedging strategy, we currently use Mexican peso forward contracts to hedge foreign currency fluctuations for a portion of our Mexican peso denominated expenses. We currently do not hedge expenses denominated in RMB. Unexpected losses could occur from increases in the value of these currencies relative to the United States dollar. +Our success will continue to depend to a significant extent on our key personnel. +Our future success depends in large part on the continued service of our key technical, marketing and management personnel and on our ability to continue to attract and retain qualified production employees. There can be no assurance that we will be successful in attracting and retaining such personnel, particularly in our manufacturing locales that may be experiencing high demand for similar key personnel. The loss of key employees could have a material adverse effect on our business, operating results and financial condition. +If we are unable to maintain our technological and manufacturing process expertise, our business could be adversely affected. +The markets for our customers’ products is characterized by rapidly changing technology, evolving industry standards, frequent new product introductions and short product life cycles. The introduction of products embodying new technologies or the emergence of new industry standards can render existing products obsolete or unmarketable. Our success will depend upon our customers’ ability to enhance existing products and to develop and introduce, on a timely and cost-effective basis, new products that keep pace with technological developments and emerging industry standards and address evolving and increasingly sophisticated customer requirements. Failure of our customers to do so could substantially harm our customers’ competitive positions. There can be no assurance that our customers will be successful in identifying, developing and marketing products that respond to technological change, emerging industry standards or evolving customer requirements. +Start-up costs and inefficiencies related to new or transferred programs can adversely affect our operating results and such costs may not be recoverable if such new programs or transferred programs are canceled. +Start-up costs, the management of labor and equipment resources in connection with the establishment of new programs and new customer relationships, and the need to obtain required resources in advance can adversely affect our gross margins and operating results. These factors are particularly evident in the ramping stages of new programs. These factors also affect our ability to efficiently use labor and equipment. We are currently managing a number of new programs. Consequently, our exposure to these factors has increased. In addition, if any of these new programs or new customer relationships were terminated, our operating results could be harmed, particularly in the short term. We may not be able to recoup these start-up costs or replace anticipated new program revenues. +Customers may change production timing and demand schedules which makes it difficult for us to schedule production and capital expenditures and to maximize the efficiency of our manufacturing capacity. +Changes in demand for customer products reduce our ability to accurately estimate the future requirements of our customers. This makes it difficult to schedule production and maximize utilization of our manufacturing capacity. We must determine the levels of business that we will seek and accept from customers, set production schedules, commit to procuring inventory, and allocate personnel and resources, based on our estimates of our customers' requirements. Customers can require sudden increases and decreases in production which can put added stress on resources and reduce margins. Sudden decreases in production can lead to excess inventory on hand which may or may not be reimbursed by our customers even when under contract. +Continued growth could further lead to capacity constraints. We may need to transfer production to other facilities, acquire new facilities, or outsource production which could negatively impact gross margin. +An adverse change in the interest rates for our borrowings could adversely affect our financial condition. +We are exposed to interest rate risk under our revolving line of credit and term loan. We currently hedge a portion of our term loan with an interest rate swap. We have not historically hedged the interest rate on our credit facility; therefore, unless we do so, significant changes in interest rates could adversely affect our results of operations. Refer to the discussion in note 4, "Long-Term Debt" to the consolidated financial statements for further details of our debt obligations. We are also exposed to interest rate risk on our factoring activities. +11 +Compliance or the failure to comply with current and future environmental laws or regulations could cause us significant expense. +We are subject to a variety of domestic and foreign environmental regulations relating to the use, storage, and disposal of materials used in our manufacturing processes. If we fail to comply with any present or future regulations, we could be subject to future liabilities or the suspension of current manufacturing operations. In addition, such regulations could restrict our ability to expand our operations or could require us to acquire costly equipment, substitute materials, or incur other significant expenses to comply with government regulations. +Our stock price is volatile. +Holders of the common stock will suffer immediate dilution to the extent outstanding equity awards are exercised to purchase common stock. Our stock price may be subject to wide fluctuations and possible rapid increases or declines over a short time period. These fluctuations may be due to factors specific to us such as variations in quarterly operating results or changes in earnings estimates, or to factors relating to the EMS industry or to the securities markets in general, which, in recent years, have experienced significant price fluctuations. These fluctuations often have been unrelated to the operating performance of the specific companies whose stocks are traded. +Due to inherent limitations, there can be no assurance that our system of disclosure and internal controls and procedures will be successful in preventing all errors, theft and fraud, or in informing management of all material information in a timely manner. +Management does not expect that our disclosure controls and internal controls and procedures will prevent all errors or fraud. A control system is designed to give reasonable, but not absolute, assurance that the objectives of the control system are met. In addition, any control system reflects resource constraints and the benefits of controls must be considered relative to their costs. Inherent limitations of a control system may include: judgments in decision making may be faulty, breakdowns can occur simply because of error or mistake and controls can be circumvented by collusion or management override. Due to the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and may not be detected. +If we do not manage our growth effectively, our profitability could decline. +Our business is experiencing rapid growth which can place considerable additional demands upon our management team and our operational, financial and management information systems. Our ability to manage growth effectively requires us to continue to implement and improve these systems; avoid cost overruns; maintain customer, supplier and other favorable business relationships during possible transition periods; continue to develop the management skills of our managers and supervisors; and continue to train, motivate and manage our employees. Our failure to effectively manage growth could have a material adverse effect on our results of operations. +If our manufacturing processes and services do not comply with applicable statutory and regulatory requirements, or if we manufacture products containing design or manufacturing defects, demand for our services may decline and we may be subject to liability claims. +We manufacture and design products to our customers’ specifications, and, in some cases, our manufacturing processes and facilities may need to comply with applicable statutory and regulatory requirements. For example, medical devices that we manufacture or design, as well as the facilities and manufacturing processes that we use to produce them, are regulated by the Food and Drug Administration and non-U.S. counterparts of this agency. In addition, our customers’ products and the manufacturing processes that we use to produce them often are highly complex. As a result, products that we manufacture may at times contain manufacturing or design defects, and our manufacturing processes may be subject to errors or not be in compliance with applicable statutory and regulatory requirements. Defects in the products we manufacture or design, whether caused by a design, manufacturing or component failure or error, or deficiencies in our manufacturing processes, may result in delayed shipments to customers or reduced or canceled customer orders. If these defects or deficiencies are significant, our business reputation may also be damaged. The failure of the products that we manufacture or our manufacturing processes and facilities to comply with applicable statutory and regulatory requirements may subject us to legal fines or penalties and, in some cases, require us to shut down or incur considerable expense to correct a manufacturing process or facility. Our customers are required to indemnify us against liability associated with designing products to meet their specifications. However, if our customers are responsible for the defects, they may not, or may not have resources to, assume responsibility for any costs or liabilities arising from these defects, which could expose us to additional liability claims. +12 +Energy price increases may negatively impact our results of operations. +Certain components that we use in our manufacturing process are petroleum-based. In addition, we, along with our suppliers and customers, rely on various energy sources in our transportation activities. While significant uncertainty currently exists about the future levels of energy prices, a significant increase is possible. Increased energy prices could cause an increase to our raw material costs and transportation costs. In addition, increased transportation costs of certain of our suppliers and customers could be passed along to us. We may not be able to increase our product prices enough to offset these increased costs. In addition, any increase in our product prices may reduce our future customer orders and profitability. +Disruptions to our information systems, including security breaches, losses of data or outages, could adversely affect our operations. +We rely on information technology networks and systems to process, transmit and store electronic information. In particular, we depend on our information technology infrastructure for a variety of functions, including worldwide financial reporting, inventory management, procurement, invoicing and email communications. Any of these systems may be susceptible to outages due to fire, floods, power loss, telecommunications failures, terrorist attacks and similar events. Despite the implementation of network security measures, our systems and those of third parties on which we rely may also be vulnerable to computer viruses, break-ins and similar disruptions. If we or our vendors are unable to prevent such outages and breaches, our operations could be disrupted. +We are involved in various legal proceedings. +In the past, we have been notified of claims relating to various matters including contractual matters, intellectual property rights or other issues arising in the ordinary course of business. In the event of such a claim, we may be required to spend a significant amount of money to defend or otherwise address the claim. Any litigation, even where a claim is without merit, could result in substantial costs and diversion of resources. Accordingly, the resolution or adjudication of such disputes, even those encountered in the ordinary course of business, could have a material adverse effect on our business, consolidated financial conditions and results of operations. +Increases in our own market capitalization and changes in securities laws and regulations will increase our costs and risk of noncompliance. +As a result of our increased market capitalization as of the end of our second quarter of fiscal year 2013, we are required to file as an accelerated filer. As such, we are subject to additional requirements contained in the Sarbanes-Oxley Act of 2002 (the Sarbanes-Oxley Act) and more recently the Dodd-Frank Act. The Sarbanes-Oxley and Dodd-Frank Acts required or will require changes in some of our corporate governance, securities disclosure and compliance practices. In response to the requirements of the Sarbanes-Oxley and Dodd-Frank Acts, the SEC and NASDAQ promulgated new rules and additional rulemaking is expected in the future. Compliance with these new rules and future rules has increased and may increase further our legal, financial and accounting costs as well as a potential risk of noncompliance. Absent significant changes in related rules, which we cannot assure, we anticipate some level of increased costs related to these new regulations to continue indefinitely. We also expect these developments to make it more difficult and more expensive to obtain director and officer liability insurance, and we may be forced to accept reduced coverage or incur substantially higher costs to obtain coverage. Likewise, these developments may make it more difficult for us to attract and retain qualified members of our Board of Directors or qualified management personnel. Further, the costs associated with the compliance with and implementation of procedures under these and future laws and related rules could have a material impact on our results of operations. In addition, the costs associated with noncompliance with additional securities laws and regulations could also impact our business. +We may encounter complications with acquisitions, which could potentially harm our business. +Any current or future acquisitions may require additional equity financing, which could be dilutive to our existing shareholders, or additional debt financing, which could potentially affect our credit ratings. Any downgrades in our credit ratings associated with an acquisition could adversely affect our ability to borrow by resulting in more restrictive borrowing terms. To integrate acquired businesses, we must implement our management information systems, operating systems and internal controls, and assimilate and manage the personnel of the acquired operations. The integration of acquired businesses may be further complicated by difficulties managing operations in geographically dispersed locations. The integration of acquired businesses may not be successful and could result in disruption by diverting management’s attention from the core business. In addition, the integration of acquired businesses may require that we incur significant restructuring charges or other increases in our expenses and working capital requirements, which reduce our return on invested capital. +13 +Acquisitions may involve numerous other risks and challenges including but not limited to: potential loss of key employees and customers of the acquired companies; the potential for deficiencies in internal controls at acquired companies; lack of experience operating in the geographic market or industry sector of the acquired business; constraints on available liquidity, and exposure to unanticipated liabilities of acquired companies. These and other factors could harm our ability to achieve anticipated levels of profitability at acquired operations or realize other anticipated benefits of an acquisition, and could adversely affect our consolidated business and operating results. +Our goodwill and identifiable intangible assets could become impaired, which could reduce the value of our assets and reduce net income in the year in which the write-off occurs. +Goodwill represents the excess of the cost of an acquisition over the fair value of the net assets acquired. The Company also ascribes value to certain identifiable intangible assets, which consists of customer relationships, non-compete agreements, and favorable leases, as a result of the acquisitions of Sabre and Ayrshire. The Company may incur impairment charges on goodwill or identifiable intangible assets if it determines that the fair values of goodwill or identifiable intangible assets are less than their current carrying values. The Company evaluates, on a regular basis, whether events or circumstances have occurred that indicate all, or a portion, of the carrying amount of goodwill may no longer be recoverable, in which case an impairment charge to earnings would become necessary. +Refer to Notes 1 and 15 to the consolidated financial statements and critical accounting policies and estimates' in management’s discussion and analysis of financial condition and results of operations for further discussion regarding the impairment testing of goodwill and identifiable intangible assets. +A decline in general economic conditions or global equity valuations could impact the judgments and assumptions about the fair value of the Company’s businesses and the Company could be required to record impairment charges on its goodwill or other identifiable intangible assets in the future, which could impact the Company’s consolidated balance sheet, as well as the Company’s consolidated statement of operations. If the Company was required to recognize an impairment charge in the future, the charge would not impact the Company's consolidated cash flows, current liquidity, capital resources, and covenants under its existing credit facilities. +Item 1B. +UNRESOLVED STAFF COMMENTS +None +14 +Item 2. +PROPERTIES AS OF DATE OF FILING +We have manufacturing and sales operations located in the United States, Mexico, and China. The table below lists the locations and square footage of our operating facilities: +Location +Approx. +Sq. Ft. +Type of Interest +(Leased/Owned) +Description of Use +Spokane Valley, Washington +95,000 +Leased +Sales, research, administration and manufacturing +Spokane Valley, Washington +36,000 +Leased +Manufacturing +Oakdale, Minnesota +60,000 +Leased +Manufacturing and warehouse +Louisville, Kentucky +4,000 +Leased +Administration +Harrodsburg, Kentucky (1) +22,000 +Owned +Manufacturing and warehouse +Corinth, Mississippi +350,000 +Leased +Manufacturing and warehouse +Fayetteville, Arkansas +175,000 +Leased +Manufacturing and warehouse +El Paso, Texas +80,000 +Leased +Shipping and warehouse +Total USA +822,000 +Juarez, Mexico +174,000 +Owned +Manufacturing +Juarez, Mexico +60,000 +Owned +Manufacturing and warehouse +Juarez, Mexico +66,000 +Owned +Manufacturing and warehouse +Juarez, Mexico +115,000 +Owned +Manufacturing and warehouse +Juarez, Mexico +103,000 +Owned +Manufacturing and warehouse +Juarez, Mexico +193,000 +Leased +Warehouse +Juarez, Mexico +66,000 +Leased +Manufacturing +Juarez, Mexico +72,000 +Leased +Manufacturing +Total Mexico +849,000 +Shanghai, China +121,000 +Leased +Manufacturing and warehouse +Shanghai, China +36,000 +Leased +Manufacturing +Total China +157,000 +Grand Total +1,828,000 +(1) +During fiscal year 2016, we announced the closing of the Harrodsburg, Kentucky location which is expected to be completed by the first quarter of fiscal year 2017. We plan to list the facility for sale during fiscal year 2017. +The geographic diversity of these locations allows us to offer services near certain of our customers and major electronics markets with the additional benefit of reduced labor costs. We consider the productive capacity of our current facilities sufficient to carry on our current business. In addition, in Juarez, Mexico one of our buildings includes adjacent vacant land that could be developed into additional manufacturing and warehouse space. +15 +All of our facilities are ISO certified to ISO 9001:2008 standards, ISO-14001 environmental standards, ISO-13485:2003 medical devices standards, AS9100C aviation, space and defense standards, ISO/TS 16949 automotive standards, ANSI/ESD S20.20-2007 Electrostatic Discharge Control Program and to Customs Trade Partnership against Terrorism (CTPAT). The Spokane, Washington facilities are additionally registered ISO/IEC 80079-34 explosive atmospheres and by the US State Department for International Traffic in Arms Regulations (ITAR). The Shanghai, China facilities are registered/certified to IS/TS 16949 automotive standard, ISO 13485 medical devices and ISO 14001 environmental. Additionally, Juarez, Mexico is registered by the NSF for water products. The Oakdale, Minnesota; Corinth, Mississippi; Fayetteville, Arkansas and Harrodsburg, Kentucky facilities are all registered by the U.S. State Department for International Traffic in Arms Regulations (ITAR). +Item 3. +LEGAL PROCEEDINGS +We are a party to certain lawsuits or claims in the ordinary course of business. We do not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on our financial position, results of operations or cash flow. +Item 4. +MINE SAFETY DISCLOSURES +Not Applicable +PART II +Item 5: +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES +Market Information +Our common stock is traded on the NASDAQ Global Market, formerly the NASDAQ National Market System under the symbol “KTCC.” Quarterly high and low sales prices for our common stock for fiscal years 2016 and 2015 were as follows: +2016 +2015 +High +Low +High +Low +First Quarter +$ +11.15 +$ +9.75 +$ +11.50 +$ +9.90 +Second Quarter +10.39 +7.50 +10.75 +7.50 +Third Quarter +8.47 +6.09 +10.75 +7.85 +Fourth Quarter +8.97 +6.99 +12.49 +10.39 +High and low stock prices are based on the daily sales prices reported by the NASDAQ Stock Market. These quotations represent prices between dealers without adjustment for markups, markdowns, and commissions, and may not represent actual transactions. +Holders and Dividends +As of July 2, 2016 , we had 706 shareholders of common stock on record. As a result of our credit agreement with Wells Fargo Bank, N.A. we are restricted from declaring or paying dividends in cash or stock without the Bank’s prior written consent. We have not paid a cash dividend and do not anticipate payment of dividends in the foreseeable future. +Equity Compensation Plan Information +Information concerning securities authorized for issuance under our equity compensation plans is set forth in Part III, Item 12 of this Annual Report, under the caption “Securities Authorized for Issuance under Equity Compensation Plans”, and that information is incorporated herein by reference. +16 +Performance Graph +Set forth below is a line graph comparing the cumulative total shareholder return on our common stock with the cumulative total return of the NASDAQ Stock Market (U.S. & Foreign) Index and the NASDAQ Electronic Components Index in fiscal 2016 . +7/2/2011 +6/30/2012 +6/29/2013 +6/28/2014 +6/27/2015 +7/2/2016 +Key Tronic Corporation +100.00 +182.30 +228.98 +237.39 +235.84 +163.50 +NASDAQ Composite +100.00 +108.58 +128.19 +169.08 +192.10 +187.57 +NASDAQ Electronic Components +100.00 +97.46 +109.01 +152.85 +161.74 +170.59 +17 +Item 6: +SELECTED FINANCIAL DATA +The following selected data is derived from our audited consolidated financial statements and should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the consolidated financial statements and related notes, and other information included in this report. +Financial Highlights +(In thousands, except for Supplemental Data and Per Share Amounts) +Fiscal Year Ended +July 2, 2016 +June 27, 2015 (3) +June 28, 2014 (3) +June 29, 2013 +June 30, 2012 +Consolidated Statements of Operations Data : +Net sales +$ +484,965 +$ +433,997 +$ +305,394 +$ +361,033 +$ +346,475 +Gross profit +38,825 +33,305 +26,854 +34,512 +29,836 +Gross margin percentage +8.0 +% +7.7 +% +8.8 +% +9.6 +% +8.6 +% +Operating income +10,416 +6,653 +9,304 +18,126 +14,351 +Operating margin percentage +2.1 +% +1.5 +% +3.0 +% +5.0 +% +4.1 +% +Net income +6,533 +4,304 +7,613 +12,583 +11,626 +Earnings per share – diluted +0.58 +0.38 +0.67 +1.12 +1.07 +Consolidated Cash Flow Data : +Cash flows provided by (used in) operations +4,580 +7,667 +1,458 +29,282 +(5,066 +) +Capital expenditures +13,277 +8,808 +7,763 +3,470 +4,654 +Consolidated Balance Sheet Data : +Net working capital (1) +97,349 +98,318 +71,049 +73,827 +76,236 +Total assets +235,924 +230,794 +156,660 +135,130 +150,912 +Long-term liabilities +46,232 +43,237 +848 +3,030 +19,050 +Shareholders’ equity +105,582 +100,768 +103,645 +94,160 +78,608 +Book value per share (2) +$ +9.84 +$ +9.42 +$ +9.83 +$ +8.97 +$ +7.50 +Supplemental Data : +Number of shares outstanding at year-end +10,725,349 +10,706,136 +10,546,750 +10,502,188 +10,481,356 +Number of employees at year-end +4,947 +4,866 +3,343 +2,584 +2,700 +Approximate square footage of operational facilities +1,828,000 +1,892,000 +1,139,000 +1,011,000 +945,000 +(1) +Net working capital is defined as total current assets less total current liabilities. Net working capital measures the portion of current assets that are financed by long term funds and is an indicator of short term financial management. +(2) +Book value per share is defined as total shareholders’ equity divided by the number of shares outstanding at the end of the fiscal year. +(3) +Reflects the acquisition of Ayrshire on September 3, 2014 in fiscal year 2015 and Sabre on July 1, 2013 in fiscal year 2014. +18 +Item 7: +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +Overview +KeyTronicEMS is a leader in electronic manufacturing services and solutions to original equipment manufacturers of a broad range of products. We provide engineering services, worldwide procurement and distribution, materials management, world-class manufacturing and assembly services, in-house testing, and unparalleled customer service. Our international production capability provides our customers with benefits of improved supply-chain management, reduced inventories, lower transportation costs, and reduced product fulfillment time. We continue to make investments in all of our operating facilities to give us the production capacity, capabilities and logistical advantages to continue to win new business. The following information should be read in conjunction with the consolidated financial statements included herein and with Item 1A, Risk Factors included as part of this filing. +Our mission is to provide our customers with superior manufacturing and engineering services at the lowest total cost for the highest quality products, and create long-term mutually beneficial business relationships by employing our “Trust, Commitment, Results” philosophy. +Executive Summary +We’re pleased with how our business rebounded from several unusual challenges in the first two quarters and finished with strong revenue and earnings growth for fiscal year 2016. The continued ramp of new programs and our investment in improving our operations to accommodate a more diversified customer base drove the overall improvement in fiscal 2016. At the same time, we won a number of new significant programs throughout the year, including new programs involving home automation, industrial metering, industrial lighting, consumer products, telecommunications and security equipment. +Net sales of $485.0 million for fiscal year 2016 increased by 11.7 percent as compared to net sales of $434.0 million in fiscal year 2015 . The increase in net sales was primarily driven by an increase in revenue related to new program wins as well as the inclusion of Ayrshire for the entire fiscal year 2016 , partially offset by a decrease in demand from a single longstanding customer. Moving into the first quarter of fiscal year 2017, we expect to see a slight decline in revenue due to the disengagement from a few small programs and our decision to disengage completely from a longstanding customer that adversely impacted our business throughout the year. For the first quarter of fiscal year 2017 , the Company expects to report revenue in the range of $117 million to $122 million. Future results will depend on actual levels of customers’ orders, the timing of the start-up of production of new product programs and the potential impact of the macroeconomic uncertainty. We believe that we are well positioned in the EMS industry to continue expansion of our customer base and continue long-term growth. +We continue to diversify our customer base by adding additional programs and customers. Our current customer relationships involve a variety of products, including consumer electronics, electronic storage devices, plastics, household products, gaming devices, specialty printers, telecommunications, industrial equipment, military supplies, computer accessories, medical, educational, irrigation, automotive, transportation management, robotics, RFID, power supply, off-road vehicle equipment, fitness equipment, HVAC controls, consumer products, home building products, material handling systems and lighting equipment. +Gross profit as a percent of net sales was 8.0 percent in fiscal year 2016 compared to 7.7 percent for the prior fiscal year. The increase in gross profit as a percentage of net sales was primarily related to a decrease in material related costs partially offset by an increase in certain overhead costs. The level of gross margin is impacted by product mix, timing of the startup of new programs, facility utilization, pricing within the electronics industry and material costs, which can fluctuate significantly from quarter to quarter and year to year. +Operating income as a percentage of net sales for fiscal year 2016 was 2.1 percent compared to 1.5 percent for fiscal year 2015 . The increase in operating income as a percentage of net sales was primarily due to an increase in gross profit as discussed above. +Net income for fiscal year 2016 was $6.5 million or $0.58 per diluted share, as compared to net income of $4.3 million or $0.38 per diluted share for fiscal year 2015 . The increase in net income for fiscal year 2016 as compared to fiscal year 2015 was primarily driven by an increase in net revenue and gross margin as described above. +19 +We maintain a strong balance sheet with a current ratio of 2.2 and a debt to equity ratio of 0.42 . Total cash provided by operating activities as defined on our cash flow statement was $4.6 million during fiscal year 2016 . We maintain sufficient liquidity for our expected future operations. As of July 2, 2016 , we had $18.1 million outstanding on our revolving line of credit with Wells Fargo Bank, N.A. As a result, $26.5 million remained available to borrow as of July 2, 2016 . We believe cash flow from operations, our borrowing capacity, our accounts receivable sale program, and equipment financing should provide adequate capital for planned growth over the long term. +RESULTS OF OPERATIONS +Comparison of the Fiscal Year Ended July 2, 2016 with the Fiscal Year Ended June 27, 2015 +The following table sets forth for the periods indicated certain items of the consolidated statements of income expressed as a percentage of net sales. The financial information and discussion below should be read in conjunction with the consolidated financial statements and notes contained in this Annual Report. +Fiscal Year Ended +July 2, 2016 +% of +net sales +June 27, 2015 +% of +net sales +$ change +% point +change +Net sales +$ +484,965 +100.0% +$ +433,997 +100.0% +$ +50,968 +— +Cost of sales +446,140 +92.0 +400,692 +92.3 +45,448 +(0.3) +Gross profit +38,825 +8.0 +33,305 +7.7 +5,520 +0.3 +Operating expenses: +Research, development and engineering +6,397 +1.3 +5,784 +1.3 +613 +— +Selling, general and administrative +22,012 +4.5 +20,868 +4.8 +1,144 +(0.3) +Total operating expenses +28,409 +5.8 +26,652 +6.1 +1,757 +(0.3) +Operating income +10,416 +2.1 +6,653 +1.5 +3,763 +0.6 +Interest expense, net +2,265 +0.4 +1,353 +0.3 +912 +0.1 +Income before income taxes +8,151 +1.7 +5,300 +1.2 +2,851 +0.5 +Income tax provision +1,618 +0.4 +996 +0.2 +622 +0.2 +Net income +$ +6,533 +1.3% +$ +4,304 +1.0% +$ +2,229 +0.3 +Effective income tax rate +19.9 +% +18.8 +% +Net Sales +The increase in net sales of $51.0 million from prior year was primarily driven by new program wins and to a lesser degree an increase in demand from current customers and the inclusion of Ayrshire for a full year of operations. +The following table shows the revenue by industry sectors as a percentage of revenue for fiscal years 2016 and 2015 : +Fiscal Year Ended +July 2, 2016 +June 27, 2015 +Industrial +39% +34% +Consumer +31 +28 +Communication +13 +16 +Gaming +7 +6 +Printers +6 +6 +Transportation +3 +8 +Computer and Peripheral +1 +2 +Total +100% +100% +We provide services to customers in a number of industries and produce a variety of products for our customers in each industry. Key Tronic does not target any particular industry, but rather seeks to find programs that strategically fit our vertical manufacturing capabilities. As we continue to diversify our customer base and win new customers, we will continue to see a change in the industry concentrations of our revenue. +Sales to foreign locations represented 28.3 percent and 30.4 percent of our total net sales in fiscal years 2016 and 2015 , respectively. +20 +Cost of Sales +Total cost of sales as a percentage of net sales was 92.0 percent and 92.3 percent in fiscal years 2016 and 2015 , respectively. +Total cost of materials as a percentage of net sales was approximately 63.9 percent and 64.6 percent in fiscal years 2016 and 2015 , respectively. The change from year-to-year is primarily a result of improved pricing of certain raw materials as well as a more favorable product mix. +Production and support costs as a percentage of net sales were 28.1 percent and 27.7 percent in fiscal years 2016 and 2015 , respectively. The increase in fiscal year 2016 is primarily related to inefficiencies associated with ramping production of new products that resulted in higher than expected operating expenses during the first half of fiscal year 2016. +We provide a reserve for obsolete and non-saleable inventories based on specific identification of inventory against current demand and recent usage. We also consider our customers' ability to pay for inventory whether or not there is a lead-time assurance agreement for a specific program. The amounts charged to expense for these inventories were approximately $0.8 million and $0.5 million in fiscal years 2016 and 2015 , respectively. +We provide warranties on certain products we sell and estimate warranty costs based on historical experience and anticipated product returns. Warranty expense is related to workmanship claims on keyboards and EMS products. The amounts charged to expense are determined based on an estimate of warranty exposure. The net warranty expense was approximately $95,000 and $115,000 in fiscal years 2016 and 2015 , respectively. +Gross Profit +Gross profit as a percentage of net sales was 8.0 percent and 7.7 percent in fiscal years 2016 , and 2015 , respectively. The 0.3 percentage point increase in gross profit as a percentage of net sales during fiscal year 2016 as compared to fiscal year 2015 is primarily related to a 1.2 percentage point decrease in material related costs partially offset by a 0.9 percentage point increase in certain overhead costs. +Changes in gross profit margins reflect the impact of a number of factors that can vary from period to period, including product mix, start-up costs and efficiencies associated with new programs, product life cycles, sales volumes, capacity utilization of our resources, management of inventories, component pricing and shortages, end market demand for customers’ products, fluctuations in and timing of customer orders, and competition within the EMS industry. These and other factors can cause variations in operating results. There can be no assurance that gross margins will not decrease in future periods. +We took early pay discounts to suppliers that totaled approximately $1.9 million and $1.5 million in fiscal years 2016 and 2015 , respectively. Early pay discounts will fluctuate based on our liquidity and changes in the discounts and terms offered by our suppliers. +Research, Development and Engineering +Research, development and engineering expenses (RD&E) consists principally of employee related costs, third party development costs, program materials, depreciation and allocated information technology and facilities costs. Total RD&E expenses were $6.4 million and $5.8 million in fiscal years 2016 and 2015 , respectively. Total RD&E expenses as a percent of net sales were 1.3 percent in fiscal years 2016 and 2015 , respectively. +Selling, General and Administrative +Selling, general and administrative expenses (SG&A) consist principally of salaries and benefits, advertising and marketing programs, sales commissions, travel expenses, provision for doubtful accounts, facilities costs, and professional services. Total SG&A expenses were $22.0 million and $20.9 million in fiscal years 2016 and 2015 , respectively. Total SG&A expenses as a percent of net sales were 4.5 percent and 4.8 percent in fiscal years 2016 and 2015 , respectively. This 0.3 percentage point decrease in SG&A as a percentage of net sales is primarily related to approximately $0.8 million of non-recurring closing costs associated with the Ayrshire acquisition incurred during fiscal year 2015 . +21 +Interest Expense +We had net interest expense of $2.3 million and $1.4 million in fiscal years 2016 and 2015 , respectively. The increase in interest expense is primarily related to the inclusion of a full year of the term loan balance outstanding and an increase in the average balance outstanding on our line of credit which was primarily used to fund growth in operations. +Income Tax Provision +We had an income tax expense of $1.6 million during fiscal year 2016 as compared to an income tax expense of $1.0 million in fiscal year 2015 . The income tax expense recognized during both fiscal years 2016 and 2015 , was primarily a function of U.S., federal, state and foreign taxes recognized at the statutory rates offset by the net benefit associated with federal research and development tax credits and changes in potential foreign tax credits. +We continually review our requirements for liquidity domestically to fund current operations, revenue growth and to look for potential future acquisitions. We anticipate repatriating a portion of our unremitted foreign earnings. The estimated taxes and associated foreign tax credits are included in the income tax calculation. For further information on taxes please review footnote 6 of the “Notes to Consolidated Financial Statements.” +International Subsidiaries +We offer customers a complete global manufacturing solution. Our facilities provide our customers the opportunity to have their products manufactured in the facility that best serves specific cost, product manufacturing and distribution needs. The locations of active foreign subsidiaries are as follows: +• +Key Tronic Juarez, SA de CV owns five facilities and leases three facilities in Juarez, Mexico. These facilities include an SMT facility, an assembly and molding facility, a sheet metal fabrication facility, and assembly and storage facilities. This subsidiary is primarily used to support our U.S. operations. +• +Key Tronic Computer Peripherals (Shanghai) Co., Ltd. leases two facilities with SMT, assembly, global purchasing and warehouse capabilities in Shanghai, China, which began operations in 1999. Its primary function is to provide EMS services for export; however, it is also currently manufacturing certain electronic keyboards. +Foreign sales (based on shipping instructions) from our worldwide operations, including domestic exports, were $137.4 million and $132.1 million in fiscal years 2016 and 2015 , respectively. Products and manufacturing services provided by our subsidiary operations are often shipped to customers directly by the parent company. +22 +RESULTS OF OPERATIONS +Comparison of the Fiscal Year Ended June 27, 2015 with the Fiscal Year Ended June 28, 2014 +The following table sets forth for the periods indicated certain items of the consolidated statements of income expressed as a percentage of net sales. The financial information and discussion below should be read in conjunction with the consolidated financial statements and notes contained in this Annual Report. +Fiscal Year Ended +June 27, 2015 +% of +net sales +June 28, 2014 +% of +net sales +$ change +% point +change +Net sales +$ +433,997 +100.0% +$ +305,394 +100.0% +$ +128,603 +— +Cost of sales +400,692 +92.3 +278,540 +91.2 +122,152 +1.1 +Gross profit +33,305 +7.7 +26,854 +8.8 +6,451 +(1.1) +Operating expenses: +Research, development and engineering +5,784 +1.3 +5,586 +1.8 +198 +(0.5) +Selling, general and administrative +20,868 +4.8 +11,964 +3.9 +8,904 +0.9 +Total operating expenses +26,652 +6.1 +17,550 +5.7 +9,102 +0.4 +Operating income +6,653 +1.5 +9,304 +3.0 +(2,651 +) +(1.5) +Interest expense, net +1,353 +0.3 +81 +— +1,272 +0.3 +Income before income taxes +5,300 +1.2 +9,223 +3.0 +(3,923 +) +(1.8) +Income tax provision +996 +0.2 +1,610 +0.5 +(614 +) +(0.3) +Net income +$ +4,304 +1.0% +$ +7,613 +2.5% +$ +(3,309 +) +(1.5) +Effective income tax rate +18.8 +% +17.5 +% +Net Sales +The increase in net sales from prior year was primarily driven by an approximate $124.6 million increase in revenue related to Ayrshire and by an approximate $17.3 million increase in revenues related to new program wins, partially offset by an approximate $7.0 million decrease in revenue related to decreased demand from current customer programs and an approximate $6.3 million decrease in revenue related to program losses. +The following table shows the revenue by industry sectors as a percentage of revenue for fiscal years 2015 and 2014: +Fiscal Year Ended +June 27, 2015 +June 28, 2014 +Industrial and Commercial Printer +34% +17% +Consumer +28 +30 +Communication +16 +23 +Transportation +8 +— +Gaming +6 +15 +Transaction Printer +6 +11 +Computer and Peripheral +2 +4 +Total +100% +100% +We provide services to customers in a number of industries and produce a variety of products for our customers in each industry. As we continue to diversify our customer base and win new customers we may continue to see a change in the industry concentrations of our revenue. +Sales to foreign locations outside the United States represented 30.4 percent and 35.3 percent of our total net sales in fiscal years 2015 and 2014, respectively. +Cost of Sales +Total cost of sales as a percentage of net sales was 92.3 percent and 91.2 percent in fiscal years 2015 and 2014, respectively. +Total cost of materials as a percentage of net sales was approximately 64.6 percent and 64.5 percent in fiscal years 2015 and 2014, respectively. The change from year-to-year was relatively flat and resulted from an increase in material cost as a percentage of net sales from certain customers which were partially offset by the lower material costs as a percentage of net sales from Ayrshire customers. +23 +Production and support costs as a percentage of net sales were 27.7 percent and 26.7 percent in fiscal years 2015 and 2014, respectively. The increase in fiscal year 2015 is primarily related to inefficiencies associated with ramping production of new products that resulted in higher than expected operating expenses during the first quarter of fiscal year 2015. +We provide a reserve for obsolete and non-saleable inventories based on specific identification of inventory against current demand and recent usage. We also consider our customers' ability to pay for inventory whether or not there is a lead-time assurance agreement for a specific program. The amounts charged to expense for these inventories were approximately $0.5 million and $0.3 million in fiscal years 2015 and 2014, respectively. +We provide warranties on certain products we sell and estimate warranty costs based on historical experience and anticipated product returns. Warranty expense is related to workmanship claims on keyboards and EMS products. The amounts charged to expense are determined based on an estimate of warranty exposure. The net warranty expense was approximately $115,000 and $35,000 in fiscal years 2015 and 2014, respectively. +Gross Profit +Gross profit as a percentage of net sales was 7.7 percent and 8.8 percent in fiscal years 2015, and 2014, respectively. The 1.1 percentage point decrease in gross profit as a percentage of net sales during fiscal year 2015 as compared to fiscal year 2014 is primarily related to a 1.0 percentage point increase in certain overhead costs and a 0.1 percentage point increase in material costs. +Changes in gross profit margins reflect the impact of a number of factors that can vary from period to period, including product mix, start-up costs and efficiencies associated with new programs, product life cycles, sales volumes, capacity utilization of our resources, management of inventories, component pricing and shortages, end market demand for customers’ products, fluctuations in and timing of customer orders, and competition within the EMS industry. These and other factors can cause variations in operating results. There can be no assurance that gross margins will not decrease in future periods. +We took early pay discounts to suppliers that totaled approximately $1.5 million and $1.1 million in fiscal years 2015 and 2014, respectively. Early pay discounts will fluctuate based on our liquidity and changes in the discounts and terms offered by our suppliers. +Research, Development and Engineering +Research, development and engineering expenses (RD&E) consists principally of employee related costs, third party development costs, program materials, depreciation and allocated information technology and facilities costs. Total RD&E expense was $5.8 million and $5.6 million in fiscal years 2015 and 2014, respectively. Total RD&E expenses as a percent of net sales were 1.3 percent and 1.8 percent in fiscal years 2015 and 2014, respectively. This 0.5 percentage point decrease in RD&E as a percentage of net sales is primarily related to the increase in revenue as a result of the Ayrshire acquisition as well as a slight decrease in certain overhead expenses. +Selling, General and Administrative +Selling, general and administrative expenses (SG&A) consist principally of salaries and benefits, advertising and marketing programs, sales commissions, travel expenses, provision for doubtful accounts, facilities costs, and professional services. Total SG&A expenses were $20.9 million and $12.0 million in fiscal years 2015 and 2014, respectively. Total SG&A expenses as a percent of net sales were 4.8 percent and 3.9 percent in fiscal years 2015 and 2014, respectively. This 0.9 percentage point increase in SG&A as a percentage of net sales is primarily related to the inclusion of Ayrshire’s SG&A costs, non-recurring closing costs associated with the Ayrshire acquisition, and an increase in payroll related costs. +Interest Expense +We had net interest expense of $1.4 million and $0.1 million in fiscal years 2015 and 2014, respectively. This increase in interest expense is primarily related to an increase in the average balance outstanding on our line of credit, term loan and factored receivables that were primarily used for the acquisition of Ayrshire. +Income Tax Provision +We had an income tax expense of $1.0 million during fiscal year 2015 as compared to an income tax expense of $1.6 million in fiscal year 2014. The income tax expense recognized during both fiscal years 2015 and 2014 was primarily a function of U.S. and foreign taxes recognized at the statutory rates offset by the net benefit associated with federal research and development tax credits, changes in potential foreign tax credits and changes in foreign tax regimes. The impact of this offset was greater in 2014 because the Company recognized a one-time benefit related to the repeal of the IETU tax regime in Mexico during fiscal year 2014. +24 +We continually review our requirements for liquidity domestically to fund current operations, revenue growth and to look for potential future acquisitions. We anticipate repatriating a portion of our unremitted foreign earnings. The estimated taxes and associated foreign tax credits are included in the income tax calculation. For further information on taxes please review footnote 6 of the “Notes to Consolidated Financial Statements.” +Capital Resources and Liquidity +Operating Cash Flow +Net cash provided by operating activities for fiscal year 2016 was $4.6 million compared to net cash provided by operating activities of $7.7 million and $1.5 million in fiscal years 2015 and 2014 , respectively. +The $4.6 million of net cash provided by operating activities during fiscal year 2016 is primarily related to $6.5 million of net income, $6.2 million of depreciation and amortization and an $11.1 million decrease in accounts receivable offset by a $16.2 million increase in inventory and a $2.6 million decrease in accounts payable. The $7.7 million of net cash provided by operating activities during fiscal year 2015 was primarily due to $4.3 million of net income, $5.9 million of depreciation and amortization and an $18.0 million increase in accounts payable partially offset by a $14.7 million increase in inventory, a $2.1 million increase in accounts receivable and a $4.2 million increase in other assets. The $1.5 million of cash provided by operating activities during fiscal year 2014 was primarily due to $7.6 million of net income, $3.8 million of depreciation and amortization and a $6.1 million increase in accounts payable partially offset by a $10.5 million increase in inventory, a $2.7 million increase in accounts receivable and a $3.1 million increase in other assets. +Accounts receivable fluctuates based on the timing of shipments, terms offered and collections. In addition, accounts receivable will fluctuate based upon the amount of accounts receivable sold under our Trade Accounts Receivable Purchase Program. During fiscal year 2016 and fiscal year 2015 we factored receivables of $78.0 million and $12.1 million , respectively, from accounts receivable sold to financial institutions, which are not included on our Consolidated Balance Sheets. We did not have our Trade Accounts Receivable Purchase Program during fiscal year 2014. We purchase inventory based on customer forecasts and orders, and when those forecasts and orders change, the amount of inventory may also fluctuate. Accounts payable fluctuates with changes in inventory levels, volume of inventory purchases, negotiated supplier terms, and taking advantage of early pay discounts. +Investing Cash Flow +Cash flows used in investing activities were $5.7 million , $48.1 million , and $13.8 million in fiscal years 2016 , 2015 and 2014 , respectively. Our primary investing activity during fiscal year 2016 was the purchase of property and equipment. Our primary investing activities during fiscal years 2015 and 2014 were the acquisitions of Ayrshire and Sabre, respectively, as discussed in further detail in footnote 14 of the “Notes to Consolidated Financial Statements.” +Operating and capital leases are often utilized when potential technical obsolescence and funding requirement advantages outweigh the benefits of equipment ownership. Capital expenditures and periodic lease payments are expected to be financed with internally generated funds and available borrowing capacities. During fiscal years 2016 and 2015 we received $13.3 million and $8.8 million of cash resulting from the sale and leaseback of equipment under operating leases, respectively. We did not enter into sale and leaseback transactions during fiscal year 2014. +Financing Cash Flow +On September 3, 2014, we entered into an amended credit agreement which provided the Company with a term loan in the amount of $35.0 million. As of July 2, 2016 , our credit agreement with Wells Fargo Bank N.A. provided a revolving line of credit facility of up to $45 million, subject to availability. +Cash flows provided by financing activities were $1.7 million in fiscal year 2016 as compared to cash flows provided by financing activities of $35.0 million and $7.3 million in fiscal years 2015 and 2014 , respectively. Our primary financing activities during fiscal year 2016 were repayments on our term loan of $5.0 million as well as borrowings and repayments under our revolving line of credit facility. Our primary financing activities during fiscal year 2015 were borrowings on our term loan of $31.3 million , net of repayments related to the Ayrshire acquisition, borrowings and repayments under our revolving line of credit facility and net repayments of $7.9 million related to the accounts receivable transfer program with Wells Fargo Bank N.A. Our primary financing activities in fiscal year 2014 were borrowings and repayments under our revolving line of credit facility, principal payments on our capital lease obligations and $7.9 million in cash as a result of our accounts receivable transfer program with Wells Fargo Bank N.A. +25 +As of July 2, 2016 , the Company had an outstanding balance on the line of credit of $18.1 million . We had availability to borrow an additional $26.5 million under the Wells Fargo line of credit and we were in compliance with our loan covenants. Our cash requirements are affected by the level of current operations and new EMS programs. We believe that projected cash from operations, funds available under the revolving credit facility and fixed asset financing will be sufficient to meet our working and fixed capital requirements for the foreseeable future. +As of July 2, 2016 , we had approximately $1.0 million of cash held by foreign subsidiaries. If cash is to be repatriated in the future from these foreign subsidiaries, the Company could be subject to additional income taxes payable in the U.S. The total amount of U.S. taxes required to be paid for the amount of foreign subsidiary cash on hand as of July 2, 2016 would approximate $100,000. The Company also has approximately $25.4 million of foreign earnings that have not been repatriated to the U.S. Of that amount, the Company estimates that $11.9 million is to be repatriated in the future, requiring U.S. taxes of $1.2 million that is currently accrued in our deferred tax liabilities. The remaining $13.5 million is considered to be permanently reinvested in Mexico and China. If these amounts were required to be repatriated it would create an additional $2.1 million in U.S. tax liability. +Contractual Obligations and Commitments +In the normal course of business, we enter into contracts which obligate us to make payments in the future. The table below sets forth our significant future obligations by fiscal year: +Payments Due by Fiscal Year (in thousands) +Total +2017 +2018 +2019 +2020 +2021 +Thereafter +Term loan (1) +$ +26,250 +$ +5,000 +$ +5,000 +$ +5,000 +$ +11,250 +$ +— +$ +— +Wells Fargo Bank N.A. revolving loan (2) +$ +18,073 +$ +— +$ +— +$ +— +$ +18,073 +$ +— +$ +— +Operating leases (3) +$ +18,385 +$ +7,666 +$ +5,831 +$ +2,805 +$ +1,261 +$ +732 +$ +90 +Purchase orders (4) +(1) +The terms of the Wells Fargo Bank N.A. term loan are discussed in the consolidated financial statements at Note 4, “Long-Term Debt.” Principal on the term loan is payable in equal quarterly installments of $1.25 million commencing on December 15, 2014 and continuing through June 15, 2019, with final installment of all remaining unpaid principal due on August 31, 2019. +(2) +The terms of the Wells Fargo Bank N.A. revolving loan are discussed in the consolidated financial statements at Note 4, “Long-Term Debt.” As of July 2, 2016 , we were in compliance with our loan covenants. Breaching these covenants could have resulted in a material impact on our operations or financial condition and could impact our ability to borrow under this facility in the future. +(3) +We maintain vertically integrated manufacturing operations in the United States, Mexico and China. We lease some of our administrative and manufacturing facilities and equipment. A complete discussion of properties can be found in Part 1, Item 2 at “Properties.” Leases have proven to be an acceptable method for us to acquire new or replacement equipment and to maintain facilities with a minimum impact on our short term cash flows for operations. In addition, such operations are heavily dependent upon technically superior manufacturing equipment including molding machines in various tonnages, Surface Mount Technology (SMT) lines, sheet metal fabrication and stamping machines, clean rooms, and automated insertion, and test equipment for the various products we are capable of producing. +(4) +As of July 2, 2016 , we had open purchase order commitments for materials and other supplies of approximately $42.3 million. Included in the open purchase orders are various blanket orders for annual requirements. Actual needs under these blanket purchase orders fluctuate with our manufacturing levels and as such cannot be broken out between fiscal years. In addition, we have contracts with many of our customers that minimize our exposure to losses for material purchased within lead-times necessary to meet customer forecasts. Purchase orders generally can be cancelled without penalty within specified ranges that are determined in negotiations with our suppliers. These agreements depend in part on the type of materials purchased as well as the circumstances surrounding any requested cancellations. +In addition to the cash requirements presented above, we have various other accruals which are not included in the table above. For example, we owe our suppliers approximately $59.0 million for accounts payable and shipments in transit at the end of the fiscal year. We generally pay our suppliers in a range from 30 to 120 days depending on terms offered. These payments are financed by operating cash flows and our revolving line of credit. +We believe that cash flows generated from operations, factoring, leasing facilities, and funds available under the revolving credit facility will satisfy cash requirements for a period in excess of 12 months and into the foreseeable future. +26 +Critical Accounting Policies and Estimates +Preparation of our consolidated financial statements requires management to make estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses. Note 1 to our consolidated financial statements describes the significant accounting policies used in the preparation of our consolidated financial statements. Management believes the most complex and sensitive judgments, because of their significance to our consolidated financial statements, result primarily from the need to make estimates about effects of matters that are inherently uncertain. The most significant areas involving management judgments are described below. Actual results in these areas could differ from management’s estimates. +Revenue +Sales revenue from manufacturing is recognized upon shipment of the manufactured product per contractual terms. Upon shipment, title transfers and the customer assumes risks and rewards of ownership of the product. The price to the buyer is fixed or determinable and recoverability is reasonably assured. Unless specifically stated in contractual terms, there are no formal customer acceptance requirements or further obligations related to the manufacturing services; if any such requirements exist, then sales revenue is recognized at the time when such requirements are completed and such obligations are fulfilled. Revenue is recorded net of estimated returns of manufactured product based on management’s analysis of historical returns. +Revenues and associated costs from engineering design, development services and tooling, which are performed under contract of short term durations, are recognized only after the completed performance of the service. +Inactive, Obsolete, and Surplus Inventory Reserve +Inventories are stated at the lower of cost or market. Cost is determined principally using the first-in, first-out (FIFO) method. We reserve for inventories that we deem inactive, obsolete or surplus. This reserve is calculated based upon the demand for the products that we produce. Demand is determined by expected sales, customer purchase orders, or customer forecasts. If expected sales do not materialize, then we would have inventory in excess of our reserves and would have to charge the excess against future earnings. In the case where we have purchased material based upon a customer’s forecast or purchase orders, we are usually covered by lead-time assurance agreements or purchase orders with each customer. These contracts state that the financial liability for material purchased within agreed upon lead-time and based upon the customer’s forecasts, lies with the customer. If we purchase material outside the lead-time assurance agreement and the customer’s forecasts do not materialize or if we have no lead-time assurance agreement for a specific program, we would have the financial liability and may have to charge inactive, obsolete or surplus inventory against earnings. We also reserve for inventory related to specific customers covered by lead-time assurance agreements when those customers are experiencing financial difficulties or reimbursement is not reasonably assured. +Allowance for Doubtful Accounts +We value our accounts receivable net of an allowance for doubtful accounts. As of July 2, 2016 and June 27, 2015 , the allowance for doubtful accounts was approximately $0.1 million , respectively. This allowance is based on estimates of the portion of accounts receivable that may not be collected in the future. The estimates used are based primarily on specific identification of potentially uncollectible accounts. Such accounts are identified using publicly available information in conjunction with evaluations of current payment activity. However, if any of our customers were to develop unexpected and immediate financial problems that would prevent payment of open invoices, we could incur additional and possibly material expenses that would negatively impact earnings. +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. We review the adequacy of this accrual quarterly based on historical analysis and anticipated product returns and rework costs. Our warranty period for keyboards is generally longer than that for EMS products. We only warrant materials and workmanship on EMS products, and we do not warrant design defects for EMS customers. +Income Taxes +Income tax expense includes U.S. and international income taxes and the provision for U.S. taxes on undistributed earnings of foreign subsidiaries not deemed to be permanently invested. We do not record U.S. tax liabilities on undistributed earnings of international subsidiaries that are deemed to be permanently reinvested. Certain income and expenses are not reported in tax returns and financial statements in the same year. The tax effect of such temporary differences is reported as deferred income taxes. The deferred income taxes are classified as long-term assets or liabilities. The most significant areas involving management judgments include deferred income tax assets and liabilities, uncertain tax positions, and research and development tax credits. Our estimates of the realization of the deferred tax assets related to our tax credits are based upon our estimates of future taxable income which may change. +27 +Stock-Based Compensation +Stock-based compensation is accounted for according to Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 718, Compensation—Stock Compensation . ASC 718 requires us to expense the fair value of employee stock options, stock appreciation rights and other forms of stock-based compensation. Under the fair value recognition provisions of ASC 718, share-based compensation cost is estimated at the grant date based upon the fair value of the award and is recognized as expense ratably over the requisite service period of the award (generally the vesting period). Determining the appropriate fair value model and calculating the fair value of share-based awards requires judgment, including estimating the expected life of the share-based award, the expected stock price volatility over the expected life of the share-based award and forfeitures. +To determine the fair value of stock based awards on the date of grant we use the Black-Scholes option-pricing model. Inherent in this model are assumptions related to expected stock price volatility, option life, risk-free interest rate and dividend yield. The risk-free interest rate is a less-subjective assumption as it is based on factual data derived from public sources. We use a dividend yield of zero as we have never paid cash dividends and have no intention to pay cash dividends in the foreseeable future. The expected stock price volatility and option life assumptions require a greater level of judgment. Our expected stock-price volatility assumption is based upon the historical volatility of our stock which is obtained from public data sources. The expected life represents the weighted average period of time that share-based awards are expected to be outstanding, giving consideration to vesting schedules and historical exercise patterns. We determine the expected life assumption based upon the exercise and post-vesting behavior that has been exhibited historically, adjusted for specific factors that may influence future exercise patterns. If expected volatility or expected life were to increase, that would result in an increase in the fair value of our stock options which would result in higher compensation charges, while a decrease in volatility or the expected life would result in a lower fair value of our stock option awards resulting in lower compensation charges. +We estimate forfeitures for all of our awards based upon historical experience of stock-based pre-vesting forfeitures. We believe that our estimates are based upon outcomes that are reasonably likely to occur. If actual forfeitures are higher than our estimates it would result in lower compensation expense and to the extent the actual forfeitures are lower than our estimate we would record higher compensation expense. +Impairment of Long-Lived Assets +Long-lived assets, such as property, plant, and equipment are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment charge would be recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. +Derivatives and Hedging Activity +Derivatives are recognized on the balance sheet at their estimated fair value. On the date a derivative contract is entered into, the Company designates the derivative as a hedge of a forecasted transaction or of the variability of cash flows to be received or paid related to a recognized asset or liability (a “cash flow” hedge). The Company does not enter into derivatives for speculative purposes. Changes in the fair value of a derivative that qualifies as a cash flow hedge are recorded in “Accumulated Other Comprehensive Income,” until earnings are affected by the variability of cash flows. See Note 11 of the Company’s consolidated financial statements for additional information. +Long-Term Incentive Compensation Accrual +Long-term incentive compensation is recognized as expense ratably over the requisite service period of the award which is generally three years. The Board of Directors approve target performance measures for the three year period for each of the Company’s officers and non-employee Directors. Performance measures are based on a combination of sales growth targets and return on invested capital targets. No cash awards will be made to participants if actual Company performance does not exceed the minimum target performance measures. The calculation used to determine the necessary accrual uses a combination of actual results and projected results. We believe that our estimates are based upon outcomes that are reasonably likely to occur. These estimates and assumptions are based on historical results as well as future expectations. Actual results could vary from our estimates and assumptions. +28 +Impairment of Goodwill +In accordance with ASC 350, Goodwill and Other Intangible Assets , goodwill is not amortized but is required to be reviewed for impairment at least annually or when events or circumstances indicate that carrying value may exceed fair value. The Company is permitted the option to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the fair value of any reporting unit is less than its corresponding carrying value. If, after assessing the totality of events and circumstances, the Company concludes that it is not more likely than not that the fair value of any reporting unit is less than its corresponding carrying value then the Company is not required to take further action. However, if the Company concludes otherwise, then it is required to perform a quantitative impairment test, including computing the fair value of the reporting unit and comparing that value to its carrying value. If the fair value is less than its carrying value, a second step of the test is required to determine if recorded goodwill is impaired. In the event that goodwill is impaired, an impairment charge to earnings would become necessary. The Company also has the option to bypass the qualitative assessment for goodwill in any period and proceed directly to performing the quantitative impairment test. +Business Combinations +The Company recognizes the assets acquired and liabilities assumed in business combinations on the basis of their fair values at the date of acquisition. We assess the fair value of assets, including intangible assets, using a variety of methods and each asset is measured at fair value from the perspective of a market participant. The method used to estimate the fair values of intangible assets incorporates significant assumptions regarding the estimates a market participant would make in order to evaluate an asset, including a market participant’s use of the asset and the appropriate discount rates for a market participant. Assets recorded from the perspective of a market participant that are determined to not have economic use for us are expensed immediately. Any excess purchase price over the fair value of the net tangible and intangible assets acquired is allocated to goodwill. Transaction costs and restructuring costs associated with a business combination are expensed as incurred. +New and Future Accounting Pronouncements +See Note 1 to our consolidated financial statements. +Item 7A: +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Interest Rate Risk +We are subject to the risk of fluctuating interest rates in the normal course of business. Our major market risk relates to our secured debt. Our revolving credit facility and term loan are secured by substantially all of our assets. The interest rates applicable to our revolving credit facility and term loan fluctuate with the Wells Fargo Bank N.A. prime rate and LIBOR rates. There was outstanding $18.1 million in borrowings under our revolving credit facility and $26.3 million outstanding on our term loan as of July 2, 2016 . See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity” and Note 4 – “Long-Term Debt” to the Consolidated Financial Statements for additional information regarding our revolving credit facility and term loan. +Our only material interest rate risk is associated with our revolving credit facility and term loan. During the second quarter of fiscal year 2015, we entered into an interest rate swap contract with a notional amount of $25.0 million related to the borrowings outstanding under the term loan and revolving credit facility. As of July 2, 2016 , the remaining notional amount of the interest rate swap contract was $20.5 million. Through the use of the interest rate swap, as described above, we fixed the basis on which we pay interest, thus eliminating much of our interest rate risk. See Note 11 – “Derivative Financial Instruments” to the Consolidated Financial Statements for additional information regarding our derivative instruments. +Foreign Currency Exchange Risk +A significant portion of our operations are in foreign locations. As a result, transactions occur in currencies other than the U.S. dollar. Exchange rate fluctuations among other currencies used by us would directly or indirectly affect our financial results. We currently use Mexican peso forward contracts to hedge foreign currency fluctuations for a portion of our Mexican peso denominated expenses. There was $69.4 million of foreign currency forward contracts outstanding as of July 2, 2016 . The fair value of these contracts was approximately $(11.0) million . See Note 11 – “Derivative Financial Instruments” to the Consolidated Financial Statements for additional information regarding our derivative instruments. +29 +Item 8: +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Key Tronic Corporation +Spokane Valley, Washington +We have audited the accompanying consolidated balance sheets of Key Tronic Corporation as of July 2, 2016 and June 27, 2015 and the related consolidated statements of income, comprehensive income (loss), shareholders' equity, and cash flows for each of the three years in the period ended July 2, 2016. In connection with our audits of the financial statements, we have also audited the financial statement schedule listed in the accompanying index. These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. +We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Key Tronic Corporation at July 2, 2016 and June 27, 2015, and the results of its operations and its cash flows for each of the three years in the period ended July 2, 2016 , in conformity with accounting principles generally accepted in the United States of America. +Also, in our opinion, the financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Key Tronic Corporation's internal control over financial reporting as of July 2, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated September 9, 2016 expressed an unqualified opinion thereon. +/s/ BDO USA, LLP +Spokane, Washington +September 9, 2016 +30 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED BALANCE SHEETS +(In thousands) +July 2, 2016 +June 27, 2015 +ASSETS +Current assets: +Cash and cash equivalents +$ +1,018 +$ +372 +Trade receivables, net of allowance for doubtful accounts of $135 and $97 +61,678 +72,852 +Inventories, net +107,006 +91,594 +Other +11,757 +13,646 +Total current assets +181,459 +178,464 +Property, plant and equipment, net +27,925 +26,974 +Other assets: +Deferred income tax asset +8,982 +6,723 +Other +1,673 +1,621 +Goodwill +9,957 +9,957 +Other intangible assets, net +5,928 +7,055 +Total other assets +26,540 +25,356 +Total assets +$ +235,924 +$ +230,794 +LIABILITIES AND SHAREHOLDERS ’ EQUITY +Current liabilities: +Accounts payable +$ +58,967 +$ +61,528 +Accrued compensation and vacation +9,571 +9,467 +Current portion of debt +5,000 +5,000 +Other +10,572 +10,794 +Total current liabilities +84,110 +86,789 +Long-term liabilities: +Term loan +21,250 +26,250 +Revolving loan +18,073 +11,631 +Deferred income tax liability +— +501 +Other long-term obligations +6,909 +4,855 +Total long-term liabilities +46,232 +43,237 +Total liabilities +130,342 +130,026 +Commitments and contingencies (Note 4 and 9) +Shareholders’ equity: +Common stock, no par value—shares authorized 25,000; issued and outstanding 10,725 and 10,706 shares, respectively +45,227 +44,136 +Retained earnings +67,928 +61,395 +Accumulated other comprehensive loss +(7,573 +) +(4,763 +) +Total shareholders’ equity +105,582 +100,768 +Total liabilities and shareholders’ equity +$ +235,924 +$ +230,794 +See accompanying notes to consolidated financial statements. +31 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF INCOME +(In thousands, except per share amounts) +Fiscal Year Ended +July 2, 2016 +June 27, 2015 +June 28, 2014 +Net sales +$ +484,965 +$ +433,997 +$ +305,394 +Cost of sales +446,140 +400,692 +278,540 +Gross profit +38,825 +33,305 +26,854 +Research, development and engineering expenses +6,397 +5,784 +5,586 +Selling, general and administrative expenses +22,012 +20,868 +11,964 +Total operating expenses +28,409 +26,652 +17,550 +Operating income +10,416 +6,653 +9,304 +Interest expense, net +2,265 +1,353 +81 +Income before income taxes +8,151 +5,300 +9,223 +Income tax provision +1,618 +996 +1,610 +Net income +$ +6,533 +$ +4,304 +$ +7,613 +Net income per share — Basic +$ +0.61 +$ +0.41 +$ +0.72 +Weighted average shares outstanding — Basic +10,710 +10,572 +10,528 +Net income per share — Diluted +$ +0.58 +$ +0.38 +$ +0.67 +Weighted average shares outstanding — Diluted +11,278 +11,286 +11,358 +See accompanying notes to consolidated financial statements. +32 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) +(In thousands) +Fiscal Year Ended +July 2, 2016 +June 27, 2015 +June 28, 2014 +Comprehensive income (loss): +Net income +$ +6,533 +$ +4,304 +$ +7,613 +Other comprehensive income (loss): +Unrealized (loss) gain on hedging instruments, net of tax +(2,810 +) +(7,166 +) +1,090 +Comprehensive income (loss) +$ +3,723 +$ +(2,862 +) +$ +8,703 +Other comprehensive income (loss) for fiscal years 2016 , 2015 , and 2014 is reflected net of tax (benefit) provision of approximately $(1.4) million , $(3.7) million and $0.6 million , respectively. +See accompanying notes to consolidated financial statements. +33 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Fiscal Year Ended +July 2, 2016 +June 27, 2015 +June 28, 2014 +Operating activities: +Net income +$ +6,533 +$ +4,304 +$ +7,613 +Adjustments to reconcile net income to cash provided by operating activities: +Depreciation and amortization +6,162 +5,910 +3,829 +Excess tax benefit from exercise of stock options +(402 +) +(50 +) +(73 +) +Provision for obsolete inventory +757 +520 +257 +Provision for warranty +95 +115 +35 +Provision for doubtful accounts +38 +97 +37 +Loss on disposal of property, plant and equipment +— +70 +12 +Share-based compensation expense +764 +732 +659 +Deferred income taxes +(1,313 +) +(1,517 +) +(687 +) +Changes in operating assets and liabilities, net of acquisition: +Trade receivables +11,136 +(2,080 +) +(2,686 +) +Inventories +(16,169 +) +(14,708 +) +(10,450 +) +Other assets +1,739 +(4,249 +) +(3,145 +) +Accounts payable +(2,561 +) +17,999 +6,059 +Accrued compensation and vacation +104 +(283 +) +149 +Other liabilities +(2,303 +) +807 +(151 +) +Cash provided by operating activities +4,580 +7,667 +1,458 +Investing activities: +Payment for acquisition, net of cash acquired +— +(47,964 +) +(6,027 +) +Purchases of property and equipment +(13,277 +) +(8,808 +) +(7,763 +) +Proceeds from sale of property and equipment +7,612 +8,641 +— +Cash used in investing activities +(5,665 +) +(48,131 +) +(13,790 +) +Financing activities: +Payment of financing costs +(113 +) +(62 +) +(84 +) +Proceeds from issuance of long term debt +— +35,000 +— +Repayments of long term debt and capital lease obligations +(5,000 +) +(3,750 +) +(576 +) +Borrowings under revolving credit agreement +197,568 +137,987 +8,212 +Repayment of revolving credit agreement +(191,126 +) +(126,356 +) +(8,212 +) +Proceeds from accounts receivable transfer agreement +— +1,116 +7,853 +Payments towards accounts receivable transfer agreement +— +(8,969 +) +— +Excess tax benefit from exercise of stock options +402 +50 +73 +Proceeds from exercise of stock options +— +17 +50 +Cash provided by financing activities +1,731 +35,033 +7,316 +Net increase (decrease) in cash and cash equivalents +646 +(5,431 +) +(5,016 +) +Cash and cash equivalents, beginning of period +372 +5,803 +10,819 +Cash and cash equivalents, end of period +$ +1,018 +$ +372 +$ +5,803 +Supplemental cash flow information: +Interest payments +$ +2,308 +$ +1,221 +$ +90 +Income tax payments, net of refunds +$ +813 +$ +3,274 +$ +2,184 +See accompanying notes to consolidated financial statements. +34 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY +(In thousands) +Shares +Common +Stock +Retained +Earnings +Accumulated +Other +Comprehensive +Income (Loss) +Total +Shareholders’ +Equity +Balances, June 29, 2013 +10,502 +$ +43,369 +$ +49,478 +$ +1,313 +$ +94,160 +Net income +— +— +7,613 +— +7,613 +Unrealized gain on hedging instruments, net +— +— +— +1,090 +1,090 +Exercise of stock options +45 +50 +— +— +50 +Share-based compensation +— +659 +— +— +659 +Excess tax benefit from share-based compensation +— +73 +— +— +73 +Balances, June 28, 2014 +10,547 +$ +44,151 +$ +57,091 +$ +2,403 +$ +103,645 +Net income +— +— +4,304 +— +4,304 +Unrealized loss on hedging instruments, net +— +— +— +(7,166 +) +(7,166 +) +Exercise of stock options +5 +17 +— +— +17 +Exercise of stock appreciation rights +223 +— +— +— +— +Shares withheld for taxes +(69 +) +(814 +) +— +— +(814 +) +Share-based compensation +— +732 +— +— +732 +Excess tax benefit from share-based compensation +— +50 +— +— +50 +Balances, June 27, 2015 +10,706 +$ +44,136 +$ +61,395 +$ +(4,763 +) +$ +100,768 +Net income +— +— +6,533 +— +6,533 +Unrealized loss on hedging instruments, net +— +— +— +(2,810 +) +(2,810 +) +Exercise of stock appreciation rights +28 +— +— +— +— +Shares withheld for taxes +(9 +) +(75 +) +— +— +(75 +) +Share-based compensation +— +764 +— +— +764 +Excess tax benefit from share-based compensation +— +402 +— +— +402 +Balances, July 2, 2016 +10,725 +$ +45,227 +$ +67,928 +$ +(7,573 +) +$ +105,582 +See accompanying notes to consolidated financial statements. +35 +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. SIGNIFICANT ACCOUNTING POLICIES +Business +Key Tronic Corporation and subsidiaries (the Company) is engaged in electronic manufacturing services (EMS) for original equipment manufacturers (OEMs) and also manufactures keyboards and other input devices. The Company’s headquarters are located in Spokane Valley, Washington with manufacturing operations in Oakdale, Minnesota; Fayetteville, Arkansas; Corinth, Mississippi; Harrodsburg, Kentucky; and foreign manufacturing operations in Juarez, Mexico; and Shanghai, China. +Principles of Consolidation +The consolidated financial statements include the Company and its wholly owned subsidiaries in the United States, Mexico and China. Intercompany balances and transactions have been eliminated during consolidation. +Reclassifications +Certain prior period reclassifications were made to conform with the current period presentation. These reclassifications had no effect on reported income, comprehensive income (loss), cash flows, total assets, or shareholders' equity as previously reported. +Use of Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates include the allowance for doubtful receivables, the provision for obsolete and non-saleable inventories, deferred tax assets and liabilities, uncertain tax positions, valuation of goodwill, impairment of long-lived assets, medical self-funded insurance liability, long-term incentive compensation accrual, the provision for warranty costs, the fair value of stock appreciation rights granted under the Company’s share-based compensation plan and purchase price allocation of acquired businesses. Due to uncertainties with respect to the assumptions and estimates, actual results could differ from those estimates. +Cash and Cash Equivalents +The Company considers investments with an original maturity of three months or less to be cash equivalents. Cash equivalents are carried at cost, which approximates fair value. The Company may have cash and cash equivalents at financial institutions that are in excess of federally insured limits from time to time. +Allowance for Doubtful Accounts +The Company evaluates the collectability of accounts receivable and records an allowance for doubtful accounts, which reduces the receivables to an amount that management reasonably estimates will be collected. A specific allowance is recorded against receivables considered to be impaired based on the Company’s knowledge of the financial condition of the customer. In determining the amount of the allowance, the Company considers several factors including the aging of the receivables, the current business environment and historical experience. After all attempts to collect a receivable have failed, the receivable is written off against the allowance. +Inventories +Inventories are stated at the lower of cost or market. Cost is determined principally using the first-in, first-out (FIFO) method. Customer orders are based upon forecasted quantities of product manufactured for shipment over defined periods. Raw material inventories are purchased to fulfill these customer requirements. Within these arrangements, customer demands for products frequently change, sometimes creating excess and obsolete inventories. The Company regularly reviews raw material inventories by customer for both excess and obsolete quantities. Wherever possible, the Company attempts to recover its full cost of excess and obsolete inventories from customers or, in some cases, through other markets. When it is determined that the Company’s carrying cost of such excess and obsolete inventories cannot be recovered in full, a charge is taken against income for the difference between the carrying cost and the estimated realizable amount. We also reserve for inventory related to specific customers covered by lead-time assurance agreements when those customers are experiencing financial difficulties or reimbursement is not reasonably assured. +Property, Plant and Equipment +Property, plant and equipment are carried at cost and depreciated using straight-line methods over the expected useful lives of the assets. Repairs and maintenance costs are expensed as incurred. +36 +Business Combinations +The Company recognizes the assets acquired and liabilities assumed in business combinations on the basis of their fair values at the date of acquisition. We assess the fair value of assets, including intangible assets, using a variety of methods and each asset is measured at fair value from the perspective of a market participant. The method used to estimate the fair values of intangible assets incorporates significant assumptions regarding the estimates a market participant would make in order to evaluate an asset, including a market participant’s use of the asset and the appropriate discount rates for a market participant. Assets recorded from the perspective of a market participant that are determined to not have economic use for us are expensed immediately. Any excess purchase price over the fair value of the net tangible and intangible assets acquired is allocated to goodwill. Transaction costs and restructuring costs associated with a business combination are expensed as incurred. +Impairment of Goodwill +The Company records intangible assets that are acquired individually or with a group of other assets in the financial statements at acquisition. In accordance with ASC 350, Goodwill and Other Intangible Assets , goodwill is not amortized but is required to be reviewed for impairment at least annually or when events or circumstances indicate that carrying value may exceed fair value. The Company tests goodwill by first performing a qualitative analysis (“Step 0”) to determine if it is more likely than not that the fair value of the reporting unit is greater than its carrying value. If the Company determines that it is not more likely than not that the fair value of the reporting unit is greater than its carrying value, the Company calculates the fair value of the reporting unit and compares the fair value of the reporting unit to its carrying value (“Step 1”). If the carrying value of the reporting unit exceeds the fair value, goodwill is potentially impaired and the second step (“Step 2”) of the impairment test must be performed. In the second step, the Company compares the implied fair value of the goodwill, as defined by ASC 350, to the carrying amount to determine the impairment loss, if any. +The Company performed its annual qualitative Step 0 analysis as of April 3, 2016 and determined a Step 1 analysis was necessary due to market conditions. Based on the results of the Step 1 analysis, the Company concluded that the fair value of the reporting unit was greater than the carrying value of the reporting unit based on a methodology that utilized both an income approach and a market approach. We considered valuation factors including the Company's market capitalization, future discounted cash flows and an estimated control premium based upon a review of comparable market transactions. We will continue to monitor our market capitalization and impairment indicators. +Impairment of Long-lived Assets +The Company, using its best estimates based on reasonable and supportable assumptions and projections, reviews assets for impairment whenever events or changes in circumstances have indicated that the carrying amount of its assets might not be recoverable. Impaired assets are reported at the lower of cost or fair value. +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. Management reviews the adequacy of this accrual quarterly based on historical analyses and anticipated product returns. +Self-funded Insurance +The Company self-funds its domestic employee health plans. The Company contracts with a separate administrative service company to supervise and administer the programs and act as its representative. The Company reduces its risk under this self-funded platform by purchasing stop-loss insurance coverage for high dollar individual claims. In addition, if the aggregate annual claims amount to more than 125 percent of expected claims for the plan year this insurance will also pay those claims amounts exceeding that level. +The Company estimates its exposure for claims incurred but not paid at the end of each reporting period and uses historical claims data supplied by the Company’s broker to estimate its self-funded insurance liability. This liability is subject to a total limitation that varies based on employee enrollment and factors that are established at each annual contract renewal. Actual claims experience may differ from the Company’s estimates. Costs related to the administration of the plan and related claims are expensed as incurred. +Revenue Recognition +Sales revenue from manufacturing is recognized upon shipment of the manufactured product per contractual terms. Upon shipment, title transfers and the customer assumes risks and rewards of ownership of the product. The price to the buyer is fixed or determinable and recoverability is reasonably assured. Unless specifically stated in contractual terms, there are no formal customer acceptance requirements or further obligations related to the manufacturing services; if any such requirements exist, then sales revenue is recognized at the time when such requirements are completed and such obligations are fulfilled. Revenue is recorded net of estimated returns of manufactured product based on management’s analysis of historical returns. +37 +Revenues and associated costs from engineering design, development services and tooling, which are performed under contract of short term durations, are recognized only after the completed performance of the service. Revenue from engineering design, development services and tooling represented approximately 1.7 percent , 2.5 percent and 3.4 percent of total revenue in fiscal years 2016 , 2015 , and 2014 , respectively. +Shipping and Handling Fees +The Company classifies costs associated with shipping and handling fees as a component of cost of goods sold. Customer billings related to shipping and handling fees are reported as revenue. +Research, Development and Engineering +Research, development and engineering expenses include unreimbursed EMS costs as well as design and engineering costs associated with the production of EMS programs. Research, development and engineering costs are expensed as incurred. +Income Taxes +Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the estimated future tax consequences and benefits attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis, as well as operating losses and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities for a change in tax rates is recognized in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amount that is more likely than not to be realized. +We utilize a two-step approach to recognizing and measuring uncertain tax positions. The first step is to evaluate the tax position for recognition by determining if the weight of available evidence indicates it is more likely than not that the position will be sustained on audit, including resolution of related appeals or litigation processes, if any. The second step is to measure the tax benefit as the largest amount which is more than 50% likely of being realized upon ultimate settlement. We consider many factors when evaluating and estimating our tax positions and tax benefits, which may require periodic adjustments based on new assessments and changes in estimates and which may not accurately forecast actual outcomes. Our policy is to recognize interest and penalties related to the underpayment of income taxes as a component of income tax provision. To date, we have not incurred charges for interest or penalties in relation to the underpayment of income taxes. The tax years 1997 through the present remain open to examination by the major U.S. taxing jurisdictions to which we are subject. Refer to Note 6 for further discussions. +Derivative Instruments and Hedging Activities +The Company has entered into foreign currency forward contracts and an interest rate swap which are accounted for as cash flow hedges in accordance with ASC 815, Derivatives and Hedging . The effective portion of the gain or loss on the derivative is reported as a component of accumulated other comprehensive income (AOCI) and is reclassified into earnings in the same period in which the underlying hedged transaction affects earnings. The derivative’s effectiveness represents the change in fair value of the hedge that offsets the change in fair value of the hedged item. +The Company uses derivatives to manage the variability of foreign currency fluctuations of expenses in our Mexico facilities and interest rate risk associated with certain borrowings under the Company’s debt arrangement. The foreign currency forward contracts and interest rate swaps have terms that are matched to the underlying transactions being hedged. As a result, these transactions fully offset the hedged risk and no ineffectiveness has been recorded. +The Company’s foreign currency forward contracts and interest rate swaps potentially expose the Company to credit risk to the extent the counterparties may be unable to meet the terms of the agreement. The Company minimizes such risk by seeking high quality counterparties. The Company’s counterparties to the foreign currency forward contracts and interest rate swaps are major banking institutions. These institutions do not require collateral for the contracts, and the Company believes that the risk of the counterparties failing to meet their contractual obligations is remote. The Company does not enter into derivative instruments for trading or speculative purposes. +Earnings Per Common Share +Basic earnings per common share is computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is computed by dividing net income by the combination of other potentially dilutive weighted average common shares and the weighted average number of common shares outstanding during the period using the treasury stock method. The computation assumes the proceeds from the exercise of stock options were used to repurchase common shares at the average market price during the period. The computation of diluted earnings per common share does not assume conversion, exercise, or contingent issuance of common stock equivalent shares that would have an anti-dilutive effect on earnings per share. +38 +Foreign Currency Transactions +The functional currency of the Company’s subsidiaries in Mexico and China is the U.S. dollar. Realized foreign currency transaction gains and losses for local currency denominated assets and liabilities are included in cost of goods sold. +Fair Value of Financial Instruments +The carrying values of cash and cash equivalents, accounts receivable and current liabilities reflected on the balance sheets at July 2, 2016 and June 27, 2015 , reasonably approximate their fair value. As of July 2, 2016 , the Company had an outstanding balance on the line of credit of $18.1 million and term loan of $26.3 million . The carrying value of debt approximates fair value. As of June 27, 2015 , the Company had an outstanding balance on the line of credit of $11.6 million and term loan of $31.3 million . +Share-based Compensation +The Company’s incentive plan may provide for equity and liability awards to employees in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, stock units, performance shares, performance units, and other stock-based or cash-based awards. Compensation cost is recognized on a straight-line basis over the requisite employee service period, which is generally the vesting period, and is included in cost of goods sold, research, development and engineering, and selling, general, and administrative expenses. Share-based compensation is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on historical experience and future expectations. +Restructuring +Periodically the Company may consolidate excess facilities in order to maximize efficiencies and reduce its costs. In connection with these activities, we recognize restructuring charges for employee termination costs, exit costs and long-lived asset impairment when applicable. +The recognition of these restructuring charges require that we make certain judgments and estimates regarding the nature, timing and amount of costs associated with the planned exit activity. To the extent our actual results differ from our estimates and assumptions, we may be required to revise the estimates of future liabilities, requiring the recognition of additional restructuring charges or the reduction of liabilities already recognized. Such changes to previously estimated amounts may be material to the consolidated financial statements. At the end of each reporting period, we evaluate the remaining accrued balances to ensure that no excess accruals are retained and the utilization of the provisions are for their intended purpose in accordance with developed exit plans. +Newly Adopted and Recent Accounting Pronouncements +In May 2014, Financial Accounting Standards Board (FASB) issued Accounting Standards Update 2014-09 (ASU 2014-09), Revenue from Contracts with Customers. The guidance in this Update affects any entity that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (for example, insurance contracts or lease contracts). The standard's core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In doing so, companies will need to use more judgment and make more estimates than under current guidance. This may include identifying performance obligations in the contract, estimating the amount of variable consideration to include in the transaction price and allocating the transaction price to each separate performance obligation. The amendments in this Update are effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is not permitted. Companies have the option of using either a full or modified retrospective approach in applying this standard. The Company is in the process of assessing the impact of ASU 2014-09 on its consolidated financial statements. +In July 2015, the FASB issued final guidance that simplifies the subsequent measurement of inventory for which cost is determined by methods other than last-in first-out (“LIFO”) and the retail inventory method. For inventory within the scope of the new guidance, entities will be required to compare the cost of inventory to only one measure, its net realizable value, and not the three measures required by the existing guidance. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The new guidance should not change how entities initially measure the cost of inventory. The guidance will be effective for the Company in the fiscal year beginning July 3, 2017. Early adoption is permitted. We have not yet determined the impact this new guidance may have on our financial statements. +39 +In September 2015, the FASB issued Accounting Standards Update 2015-16 (ASU 2015-16), Simplifying the Accounting for Measurement-Period Adjustments . The amendments in this Update require that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments in this Update require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments of ASU 2015-16 did not have a significant impact on the Company’s consolidated financial statements. +In November 2015, the FASB issued Accounting Standards Update 2015-17, Income Taxes . The amendments in this Update require that deferred tax liabilities and assets be classified as noncurrent in a classified statement of financial position. The guidance will be effective for the Company beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted for all entities. The Company retrospectively adopted this ASU during the second quarter of fiscal year 2016. The following table summarizes the adjustments made to conform prior period classifications with the new guidance (in thousands): +June 27, 2015 +As Filed +Reclass +As Adjusted +Current deferred income tax assets +$ +6,643 +$ +(6,643 +) +$ +— +Long-term deferred income tax assets +80 +6,643 +6,723 +Long-term deferred income tax liabilities +(501 +) +— +(501 +) +Net deferred tax assets +$ +6,222 +$ +— +$ +6,222 +In February 2016, the FASB issued Accounting Standards Update 2016-02 (ASU 2016-02), Leases which supersedes ASC 840 Leases and creates a new topic, ASC 842 Leases. This update requires lessees to recognize a lease asset and a lease liability for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. This update is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with earlier adoption permitted. This update will be applied using a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The Company is currently evaluating the effect of this update on its consolidated financial statements. +In March 2016, the FASB issued Accounting Standards Update 2016-09 (ASU 2016-09), Improvements to Employee Share-Based Payment Accounting . This update simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, with earlier adoption permitted. The Company is currently evaluating the effect of this update on its consolidated financial statements. +In August 2016, the FASB issued Accounting Standards Update 2016-15 (ASU 2016-15), Classification of Certain Cash Receipts and Cash Payments . This update provides guidance on how to record eight specific cash flow issues. This update is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted and a retrospective transition method to each period should be presented. The Company is currently evaluating the effect of this update on its consolidated financial statements. +Fiscal Year +The Company operates on a 52/53 week fiscal year. Fiscal years end on the Saturday nearest June 30. As such, fiscal years 2016 , 2015 , and 2014 , ended on July 2, 2016 , June 27, 2015 , and June 28, 2014 , respectively. Fiscal year 2016 is a 53 week year whereas fiscal years 2015 and 2014 were 52 week years. +40 +2. INVENTORIES +The components of inventories consist of the following (in thousands): +July 2, 2016 +June 27, 2015 +Finished goods +$ +13,384 +$ +8,019 +Work-in-process +18,988 +15,220 +Raw materials and supplies +74,634 +68,355 +$ +107,006 +$ +91,594 +3. PROPERTY, PLANT AND EQUIPMENT +Property, plant and equipment consists of the following: +Life +July 2, 2016 +June 27, 2015 +(in years) +(in thousands) +Land +— +$ +2,940 +$ +2,940 +Buildings and improvements +3 to 30 +23,737 +23,134 +Equipment +1 to 10 +53,095 +48,126 +Furniture and fixtures +3 to 5 +2,924 +3,065 +82,696 +77,265 +Accumulated depreciation +(54,771 +) +(50,291 +) +$ +27,925 +$ +26,974 +4. LONG-TERM DEBT +On September 3, 2014, the Company entered into an agreement with Wells Fargo Bank for a five-year term loan in the amount of $35.0 million which was used to acquire all of the outstanding shares of CDR Manufacturing, Inc. (dba Ayrshire Electronics). For further information on the acquisition of Ayrshire, see footnote 14 of the “Notes to Consolidated Financial Statements.” On August 6, 2015, the Company entered into a First Amendment to the amended and restated credit agreement extending the limit on our line of credit facility to $45.0 million as evidenced by the Second Replacement Revolving Note. +The agreement specifies that the proceeds of the revolving line of credit be used primarily for working capital and general corporate purposes of the Company and its subsidiaries. Borrowings under this revolving line of credit bear interest at either a “Base Rate” or a “Fixed Rate,” as elected by the Company. The base rate is the higher of the Wells Fargo Bank prime rate, daily one month London Interbank Offered Rate (LIBOR) plus 1.5% , or the Federal Funds rate plus 1.5% . The fixed rate is LIBOR plus 1.75% , LIBOR plus 2.0% or LIBOR plus 2.25% depending on the level of the Company’s trailing four quarters Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA). The revolving line of credit is secured by substantially all of the assets of the Company and expires on August 31, 2019. +As of July 2, 2016 , the Company had an outstanding balance under the credit facility of $18.1 million , $0.4 million in outstanding letters of credit and $26.5 million available for future borrowings. The interest rate on the outstanding line of credit balance was in the range of 2.45% - 3.50% . As of June 27, 2015 , the Company had an outstanding balance under the credit facility of $11.6 million , $0.3 million in outstanding letters of credit and $18.0 million available for future borrowings. The interest rate on the outstanding line of credit balance was in the range of 2.28% - 3.25% . +The outstanding principal balance of the term loan bears interest at a fixed rate per annum of the daily one month LIBOR plus 1.75% , 2.00% or 2.25% depending on the ratio of the Company’s funded debt to EBITDA, except that the term loan bore interest at LIBOR plus 2.00% from September 3, 2014 through December 14, 2014 regardless of the Company’s cash flow leverage ratio. Principal on the term loan is payable in equal quarterly installments of $1.25 million commencing December 15, 2014 and continuing through June 15, 2019, with a final installment of all remaining unpaid principal due on August 31, 2019. The Company had an outstanding balance of $26.3 million under the term loan as of July 2, 2016 . As of June 27, 2015 , the Company had an outstanding balance of $31.3 million under the term loan. +41 +Debt maturities as of July 2, 2016 for the next five years and thereafter are as follows (in thousands): +Fiscal Years Ending +Amount +2017 +$ +5,000 +2018 +5,000 +2019 +5,000 +2020 +29,323 +2021 +— +Thereafter +— +Total debt payments +$ +44,323 +The Company must comply with certain financial covenants, including a cash flow leverage ratio, an asset coverage ratio and a fixed charge coverage ratio. The credit agreement requires the Company to maintain a minimum profit threshold, limits the maximum capital lease expenditures and restricts the Company from declaring or paying dividends in cash or stock without prior bank approval. The Company is in compliance with all financial covenants for all periods presented. +5. TRADE ACCOUNTS RECEIVABLE PURCHASE PROGRAMS +Sale Programs +On June 25, 2014, the Company entered into an Account Purchase Agreement with Wells Fargo Bank, N.A. ("WFB") which provides that the Company may sell and assign to WFB and WFB may purchase from Company the accounts receivable of certain Company customers in a maximum aggregate amount outstanding of $50.0 million . The initial term of the agreement is 36 months with successive 12 month renewal terms. On December 18, 2014, the Company modified the original Account Purchase Agreement with WFB to allow the Company to account for the factored receivables as a true-sale. On July 16, 2015, the Company modified the Account Purchase Agreement with WFB to decrease the maximum aggregate amount of receivables available to factor from $50.0 million to $20.0 million . The decrease in the aggregate amount available was due to a change in customer mix and to reduce fees related to the program. The Company also has an Account Purchase Agreement with Orbian Financial Services (“Orbian”) which allows the Company to factor receivables from specific customers as a true-sale. This agreement may be canceled by either party at any time. +Total accounts receivables sold during the twelve months ended July 2, 2016 and June 27, 2015 was approximately $78.0 million and $12.1 million , respectively. Accounts receivables sold and not yet collected was approximately $1.7 million and $0.9 million as of July 2, 2016 and June 27, 2015 , respectively. The receivables that were sold were removed from the condensed consolidated balance sheets and the cash received is reflected as cash provided by operating activities in the condensed consolidated statements of cash flows. +42 +6. INCOME TAXES +Income tax provision consists of the following: +Fiscal Year Ended +July 2, 2016 +June 27, 2015 +June 28, 2014 +(in thousands) +Current income tax provision: +United States +$ +1,014 +$ +1,701 +$ +1,220 +Foreign +1,960 +975 +1,017 +2,974 +2,676 +2,237 +Deferred income tax benefit: +United States +(1,285 +) +(1,486 +) +1,566 +Foreign +(71 +) +(194 +) +(2,193 +) +(1,356 +) +(1,680 +) +(627 +) +Total income tax provision +$ +1,618 +$ +996 +$ +1,610 +The Company has gross tax credit carryforwards of approximately $7.9 million at July 2, 2016 . Included in total tax credits carryforwards is approximately $7.1 million in research and development (R&D) tax credits. +Management also has reviewed its other deferred tax assets for purposes of determining whether or not a valuation allowance may be required. A valuation allowance against these deferred tax assets is required if it is more likely than not that some of the deferred tax assets will not be realized. Based on the Company’s increased profitability and estimated future repatriations from foreign subsidiaries, it has been determined that it is more likely than not that the deferred tax assets will be realized. +Management has reviewed and updated as necessary estimates of future repatriations of the undistributed earnings of its foreign subsidiaries. Based on this analysis, management expects to repatriate a portion of the foreign undistributed earnings based on increased sales growth driving additional U.S. capital requirements, cash requirements for potential acquisitions and to potentially implement certain tax strategies. No foreign earnings were repatriated from either foreign subsidiary during fiscal 2016 or 2015 . The Company currently estimates that future repatriations from foreign subsidiaries will approximate $11.9 million . As such, as earnings are recognized in the United States, the Company would be subject to U.S. federal and state income taxes and potential withholding taxes are estimated to be approximately $5.9 million . Both the domestic tax and estimated withholding tax have been recorded as part of deferred taxes as of July 2, 2016 . All other unremitted foreign earnings are expected to remain permanently reinvested for planned fixed asset purchases in foreign locations. +The Company has not provided for U.S. income taxes or foreign withholding taxes on approximately $13.5 million of earnings from foreign subsidiaries which are permanently reinvested outside the U.S. The unrecognized net tax provision, after netting U.S. federal and state income tax and any related foreign tax credits, would be approximately $2.1 million associated with these earnings. +In recent years, the Company’s wholly owned foreign subsidiary in Mexico has been subject to a Mexican business flat tax called Impuesto Empresarial a Tasa Unica (IETU). However, effective January 1, 2014, IETU was repealed as part of a larger reform of the Mexican tax system and the impact of the repeal was recognized as a discrete tax benefit of $1.5 million during the second quarter of fiscal year 2014. The Company is now subject to the general Mexican tax regime (ISR). The effects of IETU and ISR have been included in the effective tax rate for the year ended June 28, 2014. +43 +The Company’s effective tax rate differs from the federal tax rate as follows: +Fiscal Year Ended +July 2, 2016 +June 27, 2015 +June 28, 2014 +(in thousands) +Federal income tax provision at statutory rates +$ +2,771 +$ +1,802 +$ +3,136 +State income taxes, net of federal tax effect +250 +133 +— +Foreign tax rate differences +(442 +) +(80 +) +(439 +) +Effect of income tax credits +(1,254 +) +(1,085 +) +(202 +) +Effect of repatriation of foreign earnings, net +(161 +) +(80 +) +287 +Other +454 +124 +330 +Transaction costs +— +182 +— +Effect of IETU repeal +— +— +(1,502 +) +Income tax provision +$ +1,618 +$ +996 +$ +1,610 +The domestic and foreign components of income before income taxes were: +Fiscal Year Ended +July 2, 2016 +June 27, 2015 +June 28, 2014 +(in thousands) +Domestic +$ +2,228 +$ +3,395 +$ +4,687 +Foreign +5,923 +1,905 +4,536 +Income before income taxes +$ +8,151 +$ +5,300 +$ +9,223 +Deferred income tax assets and liabilities consist of the following at: +July 2, 2016 +June 27, 2015 +(in thousands) +Deferred tax assets: +Tax credit carryforwards, net +$ +4,056 +$ +2,843 +Foreign subsidiaries - future tax credits +840 +840 +Inventory +508 +559 +Accruals +4,270 +4,579 +Mark-to-market adjustments +4,043 +2,498 +Other +86 +138 +Deferred income tax assets +$ +13,803 +$ +11,457 +Deferred tax liabilities: +Foreign subsidiaries – unremitted earnings +(2,098 +) +(2,258 +) +Fixed assets +(1,025 +) +(941 +) +Identifiable intangibles +(1,613 +) +(1,866 +) +Other +(85 +) +(170 +) +Deferred income tax liabilities +$ +(4,821 +) +$ +(5,235 +) +Net deferred income tax assets +$ +8,982 +$ +6,222 +Balance sheet caption reported in: +Long-term deferred income tax asset +$ +8,982 +$ +6,723 +Long-term deferred income tax liability +— +(501 +) +Net deferred income tax asset +$ +8,982 +$ +6,222 +As a result of retroactive application of ASU 2015-17 (Topic 740), Balance Sheet Classification of Deferred Taxes , we have reclassified our net current deferred tax assets and liabilities to net non-current deferred tax assets and liabilities in our Consolidated Balance Sheet as of July 2, 2016 and June 27, 2015 . +44 +Uncertain Tax Positions +The Company has R&D tax credits that approximate $7.1 million that have 20 year carryforwards before expiring. The Company’s R&D tax credits expire in various fiscal years from 2021 to 2035. The Company also has alternative minimum tax credits, which do not expire, approximating $726,000 . +As of July 2, 2016 , the Company had unrecognized tax benefits of $3.8 million related to its gross R&D tax credits. The unrecognized tax benefits relate to certain R&D tax credits generated from 1999 to 2015. +A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: +Fiscal Year Ended +July 2, 2016 +June 27, 2015 +June 28, 2014 +(in thousands) +Beginning Balance +$ +3,446 +$ +3,072 +$ +3,031 +Additions based on tax positions related to the current year +314 +374 +41 +Ending Balance +$ +3,760 +$ +3,446 +$ +3,072 +The increase from the prior year is due to additional R&D credits that were recorded in 2016 as discussed above. Management does not anticipate any material changes to this amount during the next 12 months. +The Company recognizes interest accrued related to unrecognized tax benefits and penalties in its income tax provision. The Company has not recognized any interest or penalties in the fiscal years presented in these financial statements. The Company is subject to income tax in the U.S. federal jurisdiction, various state jurisdictions, Mexico and China. Certain years remain subject to examination but there are currently no ongoing exams in any taxing jurisdictions. +7. EARNINGS PER SHARE +Basic earnings per share (EPS) is calculated by dividing net income (the numerator) by the weighted-average number of common shares outstanding (the denominator) during the period. Diluted EPS is computed by including both the weighted-average number of shares outstanding and any dilutive common share equivalents in the denominator. The following table presents a reconciliation of the denominator and the number of antidilutive common share awards that were not included in the diluted earnings per share calculation. These antidilutive securities occur when equity awards outstanding have an option price greater than the average market price for the period: +Fiscal Year Ended +(in thousands, except per share information) +July 2, 2016 +June 27, 2015 +June 28, 2014 +Net income +$ +6,533 +$ +4,304 +$ +7,613 +Weighted average shares outstanding– basic +10,710 +10,572 +10,528 +Effect of dilutive common stock awards +568 +714 +830 +Weighted average shares outstanding – diluted +11,278 +11,286 +11,358 +Earnings per share – basic +$ +0.61 +$ +0.41 +$ +0.72 +Earnings per share – diluted +$ +0.58 +$ +0.38 +$ +0.67 +Antidilutive SARs not included in diluted earnings per share +442 +208 +208 +8. STOCK OPTION AND BENEFIT PLANS +The Company’s incentive plan provides for equity and liability awards to employees and non-employee directors in the form of stock options, stock appreciation rights (SARs), restricted stock, restricted stock units, stock awards, stock units, performance shares, performance units, and other stock-based or cash-based awards. Compensation cost is recognized on a straight-line basis over the requisite employee service period, which is generally the vesting period, and is recorded as employee compensation expense in cost of goods sold, research, development and engineering, and selling, general and administrative expenses. Share-based compensation is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on historical experience and future expectations. +45 +In addition to service conditions, these SARs contain a performance condition. The additional performance condition is based upon the achievement of Return on Invested Capital (ROIC) goals relative to a peer group. All awards with performance conditions are measured over the vesting period and are charged to compensation expense over the requisite service period based on the number of shares expected to vest. The SARs cliff vest after a three-year period from date of grant and expire five years from date of grant. +On July 29, 2015, the Company granted 248,166 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $10.26 and a grant date fair value of $3.65 , as of July 2, 2016 , 240,833 remain outstanding. The grant date fair value for the awards granted during fiscal year 2016 were estimated using the Black Scholes option valuation method with the following weighted average assumptions as of July 29, 2015: +Fiscal Year 2016 +July 29, 2015 +Expected dividend yield +—% +Risk – free interest rate +1.39% +Expected volatility +43.66% +Expected life +4.00 +On October 31, 2014, the Company granted 213,166 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $8.22 and a grant date fair value of $3.04 , as of July 2, 2016 , 205,833 remain outstanding. The grant date fair value for the awards granted during fiscal year 2016 were estimated using the Black Scholes option valuation method with the following weighted average assumptions as of October 31, 2014: +Fiscal Year 2015 +October 31, 2014 +Expected dividend yield +—% +Risk – free interest rate +1.39% +Expected volatility +45.67% +Expected life +4.00 +On July 31, 2013, the Company granted 213,166 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $11.34 and a grant date fair value of $4.67 , as of July 2, 2016 , 200,833 remain outstanding. The grant date fair value for the awards granted during fiscal year 2014 were estimated using the Black Scholes option valuation method with the following weighted average assumptions as July 31, 2013: +Fiscal Year 2014 +July 31, 2013 +Expected dividend yield +—% +Risk – free interest rate +1.16% +Expected volatility +52.12% +Expected life +4.00 +Subsequent to July 2, 2016 , the Company granted 242,500 SARs with a strike price of $ 8.18 and a grant date fair value of $2.42 . +Share-based compensation expense is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on the Company’s historical experience and future expectations. This forfeiture rate will be revised, if necessary, in subsequent periods if actual forfeitures differ from the amount estimated. Share-based compensation expense for fiscal years ended July 2, 2016 , June 27, 2015 and June 28, 2014 was $0.8 million , $0.7 million and $0.7 million , respectively. +The Black-Scholes option valuation model is used by the Company for estimating the fair value of SARs. Option valuation models require the input of highly subjective assumptions, particularly for the expected term and expected stock price volatility. Changes in these assumptions can materially affect the fair value estimates. +The intrinsic value for stock options and SARs exercised in fiscal years 2016 , 2015 and 2014 was $0.2 million , $1.9 million and $0.4 million , respectively. +As of July 2, 2016 , total unrecognized compensation expense related to nonvested share-based compensation arrangements was approximately $0.9 million . This expense is expected to be recognized over a weighted-average period of 1.79 years . +46 +The following table summarizes the Company’s SARs activity for all plans from June 27, 2015 through July 2, 2016 : +SARs +Available +For Grant +SARs +Outstanding +Aggregate +Intrinsic +Value (in +thousands) +Weighted +Average +Exercise +Price +Weighted +Average +Remaining +Contractual +Life (in +years) +Balances, June 27, 2015 +855,836 +813,831 +$ +2,312 +$ +7.99 +2.5 +Shares authorized +— +SARs granted +(248,166 +) +248,166 +10.26 +SARs forfeited +26,999 +(26,999 +) +9.48 +SARs exercised +— +(63,333 +) +165 +4.56 +Balances, July 2, 2016 +634,669 +971,665 +$ +339 +$ +8.75 +2.4 +Exercisable at July 2, 2016 +324,166 +$ +339 +$ +6.37 +0.7 +Additional information regarding SARs outstanding and exercisable as of July 2, 2016 , is as follows: +Range of +Exercise Prices +Number Outstanding +Weighted Avg. +Remaining +Contractual Life (yrs.) +Weighted Avg. +Exercise Price +Number +Exercisable +Weighted +Avg. Exercise +Price +$4.40 – $6.40 +129,333 +0.0 +$ +4.77 +129,333 +$ +4.77 +6.41 – 8.41 +400,666 +1.1 +7.84 +194,833 +7.44 +8.42 – 10.42 +240,833 +3.7 +10.26 +— +— +10.43 – 11.34 +200,833 +2.1 +11.34 +— +— +$4.40 to $11.34 +971,665 +2.4 +$ +8.75 +324,166 +$ +6.37 +The Company has defined contribution plans available to U.S. employees who have attained age 21. Company contributions to the plans were approximately $0.6 million , $0.6 million , and $0.6 million during fiscal years 2016 , 2015 and 2014 , respectively. +9. COMMITMENTS AND CONTINGENCIES +Leases : As of July 2, 2016 and June 27, 2015 , the Company did not have any property and equipment financed under capital leases. The Company had equipment financed through capital leases with a net book value of $1.7 million during fiscal year 2014 . The related depreciation expense was $0.3 million for fiscal year 2014. As of July 2, 2016 , the Company has operating leases for certain equipment and production facilities, which expire at various dates during the next six years . +Future minimum payments under non-cancelable operating leases at July 2, 2016 , are summarized as follows (in thousands): +Fiscal Years Ending +Operating Leases +2017 +$ +7,666 +2018 +5,831 +2019 +2,805 +2020 +1,261 +2021 +732 +Thereafter +90 +Total minimum lease payments +$ +18,385 +Rental expense under operating leases was approximately $6.6 million , $3.8 million , and $1.8 million during fiscal years 2016 , 2015 and 2014 , respectively. +Warranty Costs : The Company provides warranties on certain product sales, and allowances for estimated warranty costs are recorded during the period of sale. The determination of such allowances requires the Company to make estimates of product return rates and expected costs to repair or to replace the products under warranty. The Company establishes warranty reserves based on historical warranty costs for each product line combined with liability estimates based on the prior twelve months’ sales activities. As of July 2, 2016 and June 27, 2015 , the reserve for warranty costs was approximately $30,000 and $115,000 , respectively. +47 +If actual return rates and/or repair and replacement costs differ significantly from estimates, adjustments to recognize additional cost of sales may be required in future periods. Warranty expense for fiscal years 2016 , 2015 and 2014 was related to workmanship claims on keyboards and certain EMS products. +Litigation : The Company is party to certain lawsuits or claims in the ordinary course of business. The Company does not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on the financial position, results of operations or cash flow of the Company. +Indemnification Rights : Under the Company’s bylaws, the Company’s directors and officers have certain rights to indemnification by the Company against certain liabilities that may arise by reason of their status or service as directors or officers. The Company maintains director and officer insurance, which may cover certain liabilities arising from its obligation to indemnify its directors and officers and former directors in certain circumstances. +10. FAIR VALUE MEASUREMENTS +The Company has adopted ASC 820, Fair Value Measurements, which defines fair value, establishes a framework for assets and liabilities being measured and reported at fair value and expands disclosures about fair value measurements. There are three levels of fair value hierarchy inputs used to value assets and liabilities which include: Level 1 – inputs are quoted market prices for identical assets or liabilities; Level 2 – inputs other than quoted market prices included in Level 1 that are observable for the asset or liability, either directly or indirectly; and Level 3 – inputs are unobservable inputs for the asset or liability. There have been no changes in the fair value methodologies used at July 2, 2016 and June 27, 2015 . +The following table summarizes the fair value of assets (liabilities) of the Company’s derivatives that are required to be measured on a recurring basis as of July 2, 2016 and June 27, 2015 (in thousands): +July 2, 2016 +Level 1 +Level 2 +Level 3 +Total +Fair Value +Financial Assets: +Foreign currency forward contracts +$ +— +$ +136 +$ +— +$ +136 +Financial Liabilities: +Interest rate swaps +$ +— +$ +(498 +) +$ +— +$ +(498 +) +Foreign currency forward contracts +$ +— +$ +(11,112 +) +$ +— +$ +(11,112 +) +June 27, 2015 +Level 1 +Level 2 +Level 3 +Total +Fair Value +Financial Assets: +Interest rate swaps +$ +— +$ +25 +$ +— +$ +25 +Financial Liabilities: +Interest rate swaps +$ +— +$ +(443 +) +$ +— +$ +(443 +) +Foreign currency forward contracts +$ +— +$ +(6,799 +) +$ +— +$ +(6,799 +) +The Company currently has forward contracts to hedge known future cash outflows for expenses denominated in the Mexican peso and an interest rate swap to mitigate risk associated with certain borrowings under the Company’s debt arrangement. These contracts are measured on a recurring basis based on the foreign currency spot rates and forward rates quoted by banks or foreign currency dealers. These contracts are marked to market using level 2 input criteria every period with the unrealized gain or loss, net of tax, reported as a component of shareholders’ equity in accumulated other comprehensive income (loss), as they qualify for hedge accounting. +The carrying values of cash and cash equivalents, accounts receivable and current liabilities reflected on the balance sheets at July 2, 2016 and June 27, 2015 reasonably approximate their fair value. The Company’s long-term debt primarily consists of a revolving line of credit and a term loan. Borrowings under the revolving line of credit bear interest at either a “Base Rate” or a “Fixed Rate,” as elected by the Company. Each of these rates is a variable floating rate dependent upon current market conditions and the Company’s current credit risk as discussed in footnote 4. +As a result of the determinable market rate for our revolving credit and term debt it is classified within Level 2 of the fair value hierarchy. As of July 2, 2016 , the discounted cash flows of the revolving line of credit and the term loan were estimated to be $18.1 million and $26.3 million , respectively, with carrying values that reasonably approximate their fair values. As of June 27, 2015 , the discounted cash flows of the revolving line of credit and the term loan were estimated to be $11.6 million and $31.3 million , respectively, with carrying values that reasonably approximate their fair values. +48 +11. DERIVATIVE FINANCIAL INSTRUMENTS +As of July 2, 2016 , the Company had outstanding foreign currency forward contracts of $69.4 million . These contract maturity dates extend through June 2019 . As of July 2, 2016 , the net amount of unrealized loss expected to be reclassified into earnings within the next 12 months is approximately $3.3 million . During the fiscal year ended July 2, 2016 , the Company entered into $25.9 million of foreign currency forward contracts and settled $21.5 million of such contracts. During the fiscal year ended June 27, 2015 , the Company entered into $23.1 million of foreign currency forward contracts and settled $20.5 million of such contracts. During the fiscal year ended June 28, 2014 , the Company entered into $15.2 million of foreign currency forward contracts and settled $22.5 million of such contracts. +On October 1, 2014, the Company entered into an interest rate swap contract with an effective date of September 1, 2015 and a termination date of September 3, 2019, with a notional amount of $25.0 million related to the borrowings outstanding under the term loan and line of credit. As of July 2, 2016 and June 27, 2015 , the remaining notional balance of this swap was $20.5 million and $25.0 million , respectively. This interest rate swap pays the Company variable interest at the one month LIBOR rate, and the Company pays the counter party a fixed interest rate. The fixed interest rate for the contract is 1.97% that replaces the one month LIBOR rate component of our contractual interest to be paid to WFB as part of our debt facilities. Based on the terms of the interest rate swap contract and the underlying borrowings outstanding under the term loan, the interest rate contract was determined to be effective, and thus qualifies as a cash flow hedge. +The following table summarizes the fair value of derivative instruments in the Consolidated Balance Sheets as of July 2, 2016 and June 27, 2015 (in thousands): +July 2, 2016 +June 27, 2015 +Derivatives Designated as Hedging Instruments +Balance Sheet Location +Fair Value +Fair Value +Foreign currency forward contracts +Other long-term assets +$ +136 +$ +— +Foreign currency forward contracts +Other current liabilities +$ +(4,670 +) +$ +(2,517 +) +Foreign currency forward contracts +Other long-term liabilities +$ +(6,442 +) +$ +(4,282 +) +Interest rate swaps +Other long-term assets +$ +— +$ +25 +Interest rate swaps +Other current liabilities +$ +(264 +) +$ +(271 +) +Interest rate swaps +Other long-term liabilities +$ +(234 +) +$ +(172 +) +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2016 (in thousands): +Derivatives Designated as Hedging Instruments +Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) +AOCI Balance +as of +June 27, 2015 +Effective +Portion +Recorded In +AOCI +Effective Portion +Reclassified From +AOCI Into Income +AOCI Balance +as of +July 2, 2016 +Forward contracts +Cost of sales +$ +(4,487 +) +$ +(6,939 +) +$ +4,181 +$ +(7,245 +) +Interest rate swap +Interest expense +(276 +) +(348 +) +296 +(328 +) +Total +$ +(4,763 +) +$ +(7,287 +) +$ +4,477 +$ +(7,573 +) +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2015 (in thousands): +Derivatives Designated as Hedging Instruments +Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) +AOCI Balance +as of +June 28, 2014 +Effective +Portion +Recorded In +AOCI +Effective Portion +Reclassified From +AOCI Into Income +AOCI Balance +as of +June 27, 2015 +Forward contracts +Cost of sales +$ +2,403 +$ +(7,208 +) +$ +318 +$ +(4,487 +) +Interest rate swap +Interest expense +— +(276 +) +— +(276 +) +Total +$ +2,403 +$ +(7,484 +) +$ +318 +$ +(4,763 +) +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2014 (in thousands): +Derivatives Designated as Hedging Instruments +Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) +AOCI Balance +as of +June 29, 2013 +Effective +Portion +Recorded In +AOCI +Effective Portion +Reclassified From +AOCI Into Income +AOCI Balance +as of +June 28, 2014 +Forward contracts +Cost of sales +$ +1,313 +$ +1,915 +$ +(825 +) +$ +2,403 +49 +As of July 2, 2016 , the Company does not have any foreign exchange contracts with credit-risk-related contingent features. The Company is subject to the risk of fluctuating interest rates from our line of credit and foreign currency risk resulting from our China operations. The Company does not currently manage these risk exposures by using derivative instruments. +12. ENTERPRISE-WIDE DISCLOSURES +Operating segments are defined in ASC Topic 280, Segment Reporting as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker, or decision making group, in deciding how to allocate resources and in assessing performance. The Company’s chief operating decision maker is its Chief Executive Officer. As of July 2, 2016 , the Company operates and internally manages a single operating segment, Electronics Manufacturing Services as this is the only discrete financial information that is regularly reviewed by the chief operating decision maker. This segment provides integrated electronic and mechanical engineering, assembly, sourcing and procurement, logistics, and new product testing for our customers. +Products and Services +Of the revenues for the years ended July 2, 2016 , June 27, 2015 , and June 28, 2014 , EMS sales and services were $483.3 million , $432.1 million and $303.1 million , respectively. Keyboard sales for the years ended July 2, 2016 , June 27, 2015 , and June 28, 2014 were $1.7 million , $1.9 million and $2.3 million , respectively. +Geographic Areas +Net sales and long-lived assets (property, plant, and equipment) by geographic area for the years ended and as of July 2, 2016 , June 27, 2015 and June 28, 2014 are summarized in the following table. Net sales set forth below are based on the shipping destination. Long-lived assets information is based on the physical location of the asset. +Fiscal Year Ended +(in thousands) +2016 +2015 +2014 +Geographic net sales: +Domestic (U.S.) +$ +347,552 +$ +301,891 +$ +197,700 +Foreign +137,413 +132,106 +107,694 +Total +$ +484,965 +$ +433,997 +$ +305,394 +Long-lived assets: +United States +$ +11,406 +$ +8,969 +$ +2,888 +Mexico +15,756 +17,156 +19,577 +China +763 +849 +1,131 +Total +$ +27,925 +$ +26,974 +$ +23,596 +50 +Percentage of net sales made to customers located in the following countries: +Fiscal Year Ended +2016 +2015 +2014 +United States +72% +70% +65% +Canada +7 +10 +16 +Other foreign countries (a) +21 +20 +19 +Total +100% +100% +100% +(a) No other individual foreign country accounted for 10% or more of the foreign sales in fiscal years 2016, 2015 or 2014. +Significant Customers +The percentage of net sales to and trade accounts receivables from significant customers were as follows: +Percentage of Net +Sales Fiscal Year +Percentage of +Trade Accounts Receivable +Fiscal Year +2016 +2015 +2014 +2016 +2015 +Customer A +18% +17% +20% +24% +18% +Customer B +* +* +15% +* +* +Customer C +* +* +15% +* +* +* Current customer amount represents less than 10%. +13. QUARTERLY FINANCIAL DATA (Unaudited) +Fiscal Year Ended July 2, 2016 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +(in thousands, except per share amounts) +Net sales +$ +126,209 +$ +116,403 +$ +118,448 +$ +123,905 +Gross profit +8,919 +9,110 +9,955 +10,841 +Income before income taxes +1,247 +1,882 +2,137 +2,885 +Net income +817 +1,787 +1,783 +2,146 +Earnings per common share-basic +$ +0.08 +$ +0.17 +$ +0.17 +$ +0.20 +Earnings per common share-diluted +$ +0.07 +$ +0.16 +$ +0.16 +$ +0.20 +Weighted average shares outstanding +Basic +10,706 +10,710 +10,711 +10,714 +Diluted +11,391 +11,418 +11,068 +10,966 +Fiscal Year Ended June 27, 2015 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +(in thousands, except per share amounts) +Net sales +$ +86,342 +$ +114,311 +$ +112,915 +$ +120,429 +Gross profit +4,238 +9,239 +9,436 +10,392 +(Loss) income before income taxes +(1,894 +) +2,113 +2,234 +2,847 +Net (loss) income +(1,523 +) +1,626 +1,861 +2,340 +(Loss) earnings per common share-basic +$ +(0.14 +) +$ +0.15 +$ +0.18 +$ +0.22 +(Loss) earnings per common share-diluted +$ +(0.14 +) +$ +0.14 +$ +0.16 +$ +0.21 +Weighted average shares outstanding +Basic +10,548 +10,552 +10,552 +10,636 +Diluted +10,548 +11,471 +11,556 +11,414 +51 +14. ACQUISITIONS +On July 1, 2013, the Company acquired substantially all of the assets of Sabre Assembly & Manufacturing Co. of Texas (“Sabre”), a sheet metal fabrication company with facilities located in Juarez, Mexico. The acquisition of Sabre enables the Company to offer metal fabrication directly to its customers, in combination with plastic molding, PCB assembly, complete product assembly, design engineering and testing engineering services. Under the terms of the transaction, the assets acquired included manufacturing equipment, inventory, customer relationships and non-compete agreements with key employees. No debt or liabilities were assumed. The total cash payment of $6.0 million was funded through existing cash. The Company incurred approximately $50,000 of costs related to due diligence and closing this acquisition. +The following table summarizes the fair values of the assets acquired as of the date of acquisition (in thousands): +Fair Values +At July 1, 2013 +Current Assets +$ +777 +Fixed Assets +1,168 +Non-Compete Agreements +372 +Customer Relationships +1,970 +Goodwill +1,740 +Fair value of assets acquired +$ +6,027 +The Sabre acquisition was accounted for using the acquisition method of accounting whereby the total purchase price is allocated to tangible and intangible assets and liabilities based on their fair values on the date of acquisition. The Company determined the purchase price allocations on the acquisition based on estimates of the fair values of the assets acquired. +On September 3, 2014, the Company acquired all of the outstanding stock of Ayrshire, resulting in Ayrshire becoming a wholly owned subsidiary of the Company. Ayrshire provides printed circuit board assembly and other electronic manufacturing services to a diversified customer base through manufacturing facilities operated by Ayrshire or its subsidiaries in Minnesota, Arkansas, Mississippi, and Kentucky and through a sheltered maquiladora facility in Reynosa, Mexico. The Reynosa, Mexico operations were moved to the Company's existing facility in Juarez, Mexico. This acquisition expands our printed circuit board assembly capacity, total revenue, and adds to and diversifies our customer base with the addition of many new multi-national companies. The total cash payment of approximately $48.0 million was funded through borrowings on our term loan, revolving line of credit, and cash on hand. The Company incurred approximately $775,000 of costs related to due diligence. +During the fourth quarter of 2016, management approved a plan for the closure of the Harrodsburg, Kentucky facility in order to reduce costs and further improve operating efficiencies. Customer programs from this location will be transferred to other manufacturing facilities primarily in the United States. The Company expects to incur approximately $250,000 in costs related to the closure of this facility as well as transferring customer programs to other locations. The Harrodsburg, Kentucky facility is expected to be shut down by the end of the first quarter of fiscal year 2017. +52 +The following table summarizes the purchase price paid for Ayrshire and the fair value of the assets acquired and liabilities assumed as of the date of acquisition (in thousands): +Estimated Fair Values +At September 3, 2014 +Purchase Price Paid +$ +48,010 +Cash Acquired +(46 +) +Purchase Price, Net of Cash Received +$ +47,964 +Cash +$ +46 +Accounts Receivable +21,211 +Inventories +21,772 +Other Current Assets +1,013 +Property, Plant and Equipment +7,823 +Favorable Leases +2,941 +Customer Relationships +2,833 +Non-Compete Agreements +196 +Goodwill +8,217 +Other Assets +42 +Accounts Payable +(11,070 +) +Accrued Salaries and Wages +(2,188 +) +Other Current Liabilities +(2,408 +) +Deferred Tax Liability +(2,418 +) +Fair Value of Assets Acquired +$ +48,010 +The Ayrshire acquisition was accounted for using the acquisition method of accounting whereby the total purchase price is allocated to tangible and intangible assets and liabilities based on their fair values on the date of acquisition. The Company determined the purchase price allocations on the acquisition based on estimates of the fair values of the assets acquired and liabilities assumed. +The following summary pro forma condensed consolidated financial information reflects the Ayrshire acquisition as if it had occurred on June 30, 2013 for purposes of the statements of income. This summary pro forma information is not necessarily representative of what the Company’s results of operations would have been had this acquisition in fact occurred on June 30, 2013 and is not intended to project the Company’s results of operations for any future period. +Pro forma condensed consolidated financial information for the years ended June 27, 2015 and June 28, 2014 (in thousands): +Fiscal Year Ended +(unaudited) +June 27, 2015 +June 28, 2014 +Net sales +$ +457,475 +$ +431,274 +Net income +$ +4,136 +$ +9,476 +It is impracticable to determine the revenue and net income related to the Ayrshire acquisition as certain customer programs have been transferred to the Company's Juarez facilities. +15. GOODWILL AND OTHER INTANGIBLE ASSETS +The Company recorded goodwill in connection with the Ayrshire and Sabre acquisitions resulting primarily from the synergies that resulted from the Company’s acquisitions and the assembled workforce. The goodwill is not amortized for financial accounting purposes. The goodwill from the acquisitions is not deductible for tax purposes. As of July 2, 2016 and June 27, 2015 , goodwill was recorded at $10.0 million . +53 +The changes in the carrying value of goodwill are as follows (in thousands): +July 2, 2016 +June 27, 2015 +Goodwill, beginning of period +$ +9,957 +$ +1,740 +Additions to goodwill during the period +— +8,217 +Goodwill, end of period +$ +9,957 +$ +9,957 +The components of acquired intangible assets are as follows (in thousands): +July 2, 2016 +Amortization Period +in Years +Gross Carrying +Amount +Accumulated +Amortization +Net Carrying +Amount +Other intangible assets: +Non-Compete Agreements +3 - 5 +$ +568 +$ +(343 +) +$ +225 +Customer Relationships +10 +4,803 +(1,110 +) +3,693 +Favorable Lease Agreements +4 - 7 +2,941 +(931 +) +2,010 +Total +$ +8,312 +$ +(2,384 +) +$ +5,928 +June 27, 2015 +Amortization Period +in Years +Gross Carrying +Amount +Accumulated +Amortization +Net Carrying +Amount +Other intangible assets: +Non-Compete Agreements +3 - 5 +$ +568 +$ +(204 +) +$ +364 +Customer Relationships +10 +4,803 +(630 +) +4,173 +Favorable Lease Agreements +4 - 7 +2,941 +(423 +) +2,518 +Total +$ +8,312 +$ +(1,257 +) +$ +7,055 +Amortization expense related to intangible assets was approximately $1.1 million and $1.0 million for the years ended July 2, 2016 and June 27, 2015 , respectively. +Aggregate amortization expense related to existing intangible assets by fiscal year is currently estimated to be as follows (in thousands): +Fiscal Years Ending +Amount +2017 +$ +1,128 +2018 +1,073 +2019 +818 +2020 +783 +2021 +784 +Thereafter +1,342 +Total amortization expense +$ +5,928 +54 +Item 9: +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES +None +Item 9A: +CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +It is the responsibility of our management to establish, maintain, and monitor disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 are recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Additionally, these disclosure controls include controls and procedures that are designed to accumulate and communicate the information required to be disclosed to our Company’s Chief Executive Officer and Chief Financial Officer, allowing for timely decisions regarding required disclosures. As of the end of the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(f). Based on our assessment, we believe that as of July 2, 2016 , the Company’s disclosure controls and procedures are effective based on that criteria. +Management’s Report on Internal Control over Financial Reporting +Our management has the responsibility to establish and maintain adequate internal controls over our financial reporting, as defined in Rule 13a-15(f) under the Securities and Exchange Act of 1934. Our internal controls are designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our external financial statements in accordance with generally accepted accounting principles (GAAP). +Due to inherent limitations of any internal control system, management acknowledges that there are limitations as to the effectiveness of internal controls over financial reporting and therefore recognize that only reasonable assurance can be gained from any internal control system. Accordingly, our internal control system may not detect or prevent material misstatements in our financial statements and projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, we have performed an assessment of the effectiveness of our internal controls over financial reporting as of July 2, 2016 . This assessment was based on the criteria established in Internal Control-Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that as of July 2, 2016 , the Company’s internal control over financial reporting is effective based on that criteria. +The effectiveness of the Company's internal control over financial reporting as of July 2, 2016 has been audited by BDO USA LLP, an independent registered public accounting firm, as stated in their report which is included herein. +Changes in Internal Control over Financial Reporting +There have been no significant changes in our internal controls over financial reporting during our fourth fiscal quarter ended July 2, 2016 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)). +55 +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Key Tronic Corporation +Spokane Valley, Washington +We have audited Key Tronic Corporation's internal control over financial reporting as of July 2, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Key Tronic Corporation's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Item 9A “Management's Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, Key Tronic Corporation maintained, in all material respects, effective internal control over financial reporting as of July 2, 2016, based on the COSO criteria . +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Key Tronic Corporation as of July 2, 2016 and June 27, 2015, and the related consolidated statements of income, comprehensive income (loss), shareholders' equity, and cash flows for each of the three years in the period ended July 2, 2016 and our report dated September 9, 2016, expressed an unqualified opinion thereon. +/s/ BDO USA, LLP +Spokane, Washington +September 9, 2016 +56 +Item 9B: +OTHER INFORMATION +None +PART III +Item 10: +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Directors of the Registrant +Information on the nominees for election as Directors of the Company is incorporated by reference from the Company’s definitive proxy statement for the 2016 Annual Meeting of Shareholders to be filed pursuant to Regulation 14A under the Exchange Act no later than 120 days after the end of the Company’s 2016 fiscal year. +Executive Officers of the Registrant +This information is included in a separate item captioned “Executive Officers of the Registrant” in Item 1 of Part 1 of this report pursuant to Instruction G(3) of Form 10-K and Instruction 3 to Item 401(b) of Regulation S-K. +Compliance with Section 16(a) of the Exchange Act: +Incorporated by reference to Key Tronic Corporation’s 2016 Proxy Statement to Shareholders. +Code of Conduct +The Board of Directors has adopted a written Code of Conduct which applies to its directors and employees, including its executive officers. The Code of Conduct is available on the Company’s website at www.keytronic.com . The Company intends to disclose on its website any amendments to or waivers of the Code of Conduct. +Item 11: +EXECUTIVE COMPENSATION +Information appearing under the caption “Executive Compensation” in the Company’s 2016 Proxy Statement is incorporated herein by this reference. +Item 12: +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The following table sets forth the aggregate information for the Company’s equity compensation plans in effect as of July 2, 2016 . +EQUITY COMPENSATION PLAN INFORMATION +Plan category +Number of securities to +be issued upon exercise +of outstanding options, +warrants, and rights +(a) +Weighted-average +exercise price of +outstanding options, +warrants, and rights +(b) +Number of securities +remaining available for +future issuance under +equity compensation +plans (excluding +securities reflected in +column (a) +(c) +Equity compensation plans approved by security holders (1) +971,665 +$ +8.75 +634,669 +Equity compensation plans not approved by security holders +— +$ +— +— +Total +971,665 +$ +8.75 +634,669 +(1) +Included are the 1,200,000 shares subject to the 2010 Plan, the issuance of which were approved by the shareholders at the 2010 Annual Meeting. During the 2015 Annual Meeting, an additional 1,000,000 shares were approved. As a result of the shareholder approval, the Company made the decision to amend the cash-settled SARs granted during fiscal year 2010 to stock-settled SARs effective October 21, 2011. +Information under the caption “Beneficial Ownership of Securities” in the Company’s 2016 Proxy Statement is incorporated herein by this reference. +57 +Item 13: +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions”, “Compensation Committee Interlocks and Insider Participation”, and “Directors’ Independence” in the Company’s 2016 Proxy Statement is incorporated herein by this reference. +Item 14: +PRINCIPAL ACCOUNTING FEES AND SERVICES +Information appearing under the caption “Principal Accountant Fees and Services” in the Company’s 2016 Proxy Statement is incorporated herein by this reference. +PART IV +Item 15: +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +(a) 1. FINANCIAL STATEMENTS +Page in Form 10-K +FINANCIAL STATEMENTS +Report of Independent Registered Public Accounting Firm +30 +Consolidated Balance Sheets +31 +Consolidated Statements of Income +32 +Consolidated Statements of Comprehensive Income (Loss) +33 +Consolidated Statements of Cash Flows +34 +Consolidated Statements of Shareholders’ Equity +35 +Notes to Consolidated Financial Statements +36-54 +2. SCHEDULES +II. Consolidated Valuation and Qualifying Accounts +62 +Other schedules are omitted because of the absence of conditions under which they are required, or because required information is given in the financial statements or notes thereto. +58 +3. EXHIBITS +Exhibit No. +Description +3.1 +Articles of Incorporation, incorporated by reference to the Exhibits to the Company’s form 10-K for the year ended June 30, 1986 +3.2 +Bylaws, as amended, incorporated by reference to the Exhibits to the Company’s Form 10-K for the year ended June 30, 1986 +10.1* +Executive Stock Option Plan, incorporated by reference to Exhibits to the Company’s Form 10-K for the year ended June 30, 1986 +10.2* +Amended and Restated 1990 Stock Option Plan for Non-Employee Directors, as amended, incorporated by reference to the Company’s 1997 Proxy Statement (dated October 10, 1997), pages 14-17 +10.3* +1995 Executive Stock Option Plan, incorporated by reference to the Company’s 1995 Proxy Statement, pages 19-22 +10.4* +2000 Employee Stock Option Plan, incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.5* +Officers’ Employment Contracts, incorporated by reference to the Company’s 1998 Proxy Statement, pages 10 and 11 +10.6* +Addenda to Officers’ Employment Contracts, incorporated by reference to Exhibits to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.7* +Description of Retention Bonus Plan, incorporated by reference to the Exhibits to the Company’s 10-Q for the quarter ended December 28, 2002 +10.8* +Addenda to Officers’ Employment Contracts, incorporated by reference to Exhibits to the Company’s Form 10-K for the year ended June 29, 2002 +10.9 +Promise to execute a Purchase and Sale Agreement with Key Safety Systems de Mexico, S.A. de C.V., incorporated by reference to the Exhibit to the Company’s Form 8-K filed April 26, 2005 +10.10 +Summary of material terms and conditions of the Purchase and Sale Agreement with Key Safety Systems de Mexico, S.A. de C.V., incorporated by reference to the Exhibit to the Company’s Form 8-K filed June 6, 2005 +10.11* +Summary of Key Tronic Corporation Incentive Compensation Plan, incorporated by reference to Exhibit 10.23 to the Company’s Form 10-K for the year ended July 2, 2005 +59 +10.12* +Summary of Incentive Compensation Plan Performance goals and Target Payments for fiscal year 2007, incorporated by reference to the Company’s Form 8-K filed July 28, 2006 +10.13* +Summary of Fiscal Years 2007 – 2009 Long Term Incentive Plan Performance Measures and Awards, incorporated by reference to the Company’s Form 8-K filed July 28, 2006 +10.14* +Summary of Key Tronic Corporation Long Term Incentive Compensation Plan, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed September 27, 2005 +10.15 +Summary of material terms and conditions of the Purchase and Sale Agreement with Todenko Mexico S.A. de C.V., incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed October 12, 2006 +10.16 +Summary of material terms and conditions of the Purchase and Sale Agreement with Todenko Mexico S.A. de C.V., incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed November 20, 2006 +10.17 +Summary of material terms and conditions of the Sale and Purchase Agreement with Adevco Corporation, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed January 5, 2007 +10.18 +Summary of Second Amendment to Agreement of Sale and Purchase Agreement with Adevco Corporation, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed April 11, 2007 +10.19* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2008 and Fiscal Years 2008-2010 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 27, 2007 +10.20* +Summary of Incentive Compensation Plan Performance Goals and Target payments for Fiscal Year 2009 and Fiscal Years 2009 – 2011 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 24, 2008 +10.21* +Summary of Incentive Compensation Plan Performance Goals and Target payments for Fiscal Year 2010 and Fiscal Years 2010 – 2012 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 23, 2009 +10.22 +Financing Agreement with Wells Fargo Bank, N.A., incorporated by reference to the Exhibits to the Company’s Form 8-K filed on August 24, 2009 +10.23* +2010 Incentive Plan, incorporated by reference to Exhibit 10.36 to the Company’s Form 10-K for the year ended July 3, 2010 +10.24* +Employment Contract with Douglas G. Burkhardt, incorporated by reference to Exhibit 10.37 to the Company’s Form 10-K for the year ended July 3, 2010 +10.25 +Summary of material terms and conditions of the Purchase and Sale Agreement with Autopartes Y Arneses de Mexico S.A. de C.V., incorporated by reference to Exhibit 10.38 to the Company’s Form 10-K for the year ended July 3, 2010 +10.26* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2011 and Fiscal Years 2011 – 2013 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 27, 2011 +60 +10.27* +Amendment to Employment Contract of Craig D. Gates, dated August 23, 2011; of Ronald F. Klawitter, dated August 23, 2011 and of Douglas G. Burkhardt dated September 6, 2011; incorporated by reference to the Exhibits to the Company’s Form 10-K for the year ended July 2, 2011 +10.28 +Second Loan Modification Agreement to the Credit Agreement with Wells Fargo Bank, N.A., incorporated by reference to the Exhibits to the Company’s Form 8-K filed on January 30, 2012 +10.29* +Amendment to Employment Contract of Craig D. Gates, dated May 10, 2012, and of Douglas G. Burkhardt dated May 10, 2012; incorporated by reference to the Exhibits to the Company’s Form 10-Q filed on May 14, 2012 +10.30* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2013 and Fiscal Years 2013 – 2015 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 7, 2012 +10.31* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2014 and Fiscal Years 2014 – 2016 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 6, 2013 +10.32* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2015 and Fiscal Years 2015 – 2017 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 1, 2014 +10.33 +Summary of material terms and conditions of the Stock Purchase Agreement with CDR Manufacturing and Amended and Restated Credit Agreement with Wells Fargo Bank, N. A. incorporated by reference to the Company’s Form 8-K filed September 9, 2014 +10.34* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2016 and Fiscal Years 2016 – 2018 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 30, 2015 +10.35 +First Amendment to Amended and Restated Credit Agreement and Second Replacement Revolving Line of Credit Note with Wells Fargo Bank, National Association, incorporated by reference to the Company's Form 8-K filed August 11, 2015 +10.36* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2017 and Fiscal Years 2017 – 2019 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 29, 2016 +21. +Subsidiaries of Registrant, submitted herewith +23.1 +Consent of Independent Registered Public Accounting Firm, submitted herewith +31.1 +Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer, submitted herewith +31.2 +Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer, submitted herewith +32.1 +Section 1350 Certification of Chief Executive Officer, submitted herewith +32.2 +Section 1350 Certification of Chief Financial Officer, submitted herewith +101.INS +XBRL Instance Document ** +61 +101.SCH +XBRL Taxonomy Extension Schema Document ** +101.CAL +XBRL Taxonomy Extension Calculation Linkbase Document ** +101.DEF +XBRL Taxonomy Extension Definition Linkbase Document ** +101.LAB +XBRL Taxonomy Extension Label Linkbase Document ** +101.PRE +XBRL Taxonomy Extension Presentation Linkbase Document ** +* +Management contract or compensatory plan or arrangement +** +Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities and Exchange Act of 1934, as amended and otherwise are not subject to liability under those sections. +SCHEDULE II +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS +FISCAL YEARS ENDED JULY 2, 2016 , JUNE 27, 2015 , AND JUNE 28, 2014 +Fiscal Year Ended +2016 +2015 +2014 +(in thousands) +Allowance for Obsolete Inventory +Balance at beginning of year +$ +417 +$ +332 +$ +381 +Provisions +757 +520 +257 +Dispositions +(61 +) +(435 +) +(306 +) +Balance at end of year +$ +1,113 +$ +417 +$ +332 +Allowance for Doubtful Accounts +Balance at beginning of year +$ +97 +$ +— +$ +40 +Provisions +38 +97 +37 +Write-offs +— +— +(77 +) +Balance at end of year +$ +135 +$ +97 +$ +— +62 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +Dated: September 9, 2016 +KEY TRONIC CORPORATION +By: +/s/ Craig D. Gates +Craig D. Gates, President and Chief Executive Officer +(Principal Executive Officer) +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated: +/s/ Craig D. Gates +September 9, 2016 +Craig D. Gates +Date +Director and President and Chief Executive Officer +(Principal Executive Officer) +/s/ Brett R. Larsen +September 9, 2016 +Brett R. Larsen +Date +Executive Vice President of Administration, Chief Financial Officer and Treasurer +(Principal Financial Officer) +/s/ Ronald F. Klawitter +September 9, 2016 +Ronald F. Klawitter, Director +Date +/s/ James R. Bean +September 9, 2016 +James R. Bean, Director +Date +/s/ Yacov A. Shamash +September 9, 2016 +Yacov A. Shamash, Director +Date +/s/ Patrick Sweeney +September 9, 2016 +Patrick Sweeney, Director and Chairman of the Board +Date +63 \ No newline at end of file diff --git a/raw/filings/0000719733/2016/0000719733-16-000164/filing_metadata.csv b/raw/filings/0000719733/2016/0000719733-16-000164/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..c0c920248423d2355cd66de6c645d24c563524ac --- /dev/null +++ b/raw/filings/0000719733/2016/0000719733-16-000164/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000719733,KTCC,KEY TRONIC CORP,10-K,2016-09-09,2016-07-02,2016-09-09T21:00:02.000Z,0000719733-16-000164,ktcc-07022016x10k.htm,10-K,8242236,1,0,https://www.sec.gov/Archives/edgar/data/719733/000071973316000164/ktcc-07022016x10k.htm,https://www.sec.gov/Archives/edgar/data/719733/000071973316000164/,2016,2016,1 diff --git a/raw/filings/0000719733/2016/0000719733-16-000164/item1.txt b/raw/filings/0000719733/2016/0000719733-16-000164/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..96f5a054735d824d72cdfe729b712016a81fee81 --- /dev/null +++ b/raw/filings/0000719733/2016/0000719733-16-000164/item1.txt @@ -0,0 +1,104 @@ +Item 1. +BUSINESS +Background +Key Tronic Corporation (dba: KeyTronicEMS Co.) was organized in 1969, as a Washington corporation that locally manufactured computer keyboards. The ability to design, build and deliver a quality product led us to become a leading independent manufacturer of keyboards for computers in the United States. Our fully integrated design, tooling, and automated manufacturing capabilities enabled us to rapidly respond to customers’ needs for keyboards in production quantities worldwide. We supported our sales growth through the development and purchase of international manufacturing facilities. As the computer keyboard market matured with increasing competition from other international providers, we determined that our business could no longer solely rely on keyboard sales. +After assessing market conditions and our strengths and capabilities, we shifted our focus from keyboard manufacturing to contract manufacturing for a wide range of products. Our unique strategic attributes are based on our core strengths of innovative design and engineering expertise in electronics, mechanical engineering, sheet metal fabrication and stamping, and precision plastics combined with high-quality, low cost production, and assembly on an international basis while providing exceptional customer service. These strengths have made our company a strong competitor in the electronic manufacturing services (EMS) market. +Acquisitions +On September 3, 2014, we completed the acquisition of all of the outstanding shares of CDR Manufacturing, Inc. (dba Ayrshire Electronics), which added five locations (four in North America and one in Mexico). This acquisition expanded our printed circuit board assembly capacity, total revenue, and adds to and diversifies our customer base with the addition of many new multi-national companies. Subsequent to the acquisition, the Reynosa, Mexico operations were transferred to the Company’s existing Juarez, Mexico facilities. During the fourth quarter of fiscal year 2016, we announced a plan to close the Harrodsburg, Kentucky facility which is expected to occur by the end of the first quarter of 2017. Most of our customer programs from the Harrodsburg, Kentucky facility are being transferred to other Key Tronic facilities. +On July 1, 2013, the Company acquired substantially all of the assets of Sabre Assembly & Manufacturing Co. of Texas (“Sabre”), a sheet metal fabrication company with facilities located in Juarez, Mexico. We have made substantial investments in our sheet metal fabrication capabilities and capacity and will continue to do so as customer demands increase and evolve. The significant investment in sheet metal capabilities enables the Company to offer metal fabrication directly to its customers, in combination with plastic molding, PCB assembly, complete product assembly, design engineering and testing engineering services. +Our Industry and Strategy +The expansion of the EMS industry and our acquisitions have allowed us to continue to expand our customer base and the industries that we serve. The increase in new programs represents a growing portion of our revenue and a promising foundation for our future. In keeping with our long-term strategic objectives, we have been successfully building a more diversified customer portfolio, spanning a wider range of industries. We currently offer our customers the following services: integrated electronic and mechanical engineering, precision plastic molding, sheet metal fabrication, printed circuit board (PCB) and complete product assembly, component selection, sourcing and procurement, worldwide logistics, and new product testing and production all at competitive pricing due to our global footprint. +4 +We believe that we are well positioned in the EMS industry to continue the expansion of our customer base and achieve long term growth. Our unique blend of multinational facilities, vertical integration, centralized management, and core strengths continue to support our growth and our customers’ needs. We continue to focus on controlling operating expenses and leveraging the synergistic capabilities of our world-class facilities in the United States, Mexico, and China. This international production capability provides our customers with the benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs, and reduced product fulfillment time. Given our competitive advantages and the growing pressure for new potential customers to move forward with their outsourcing strategies, we are strongly positioned to win new business in coming periods and grow our revenue and profits. +The EMS industry is intensely competitive. Although our customer base is growing, we still have less than 1% of the potential global market and our revenue can fluctuate significantly due to reliance on a concentrated base of customers. We are planning for new customer growth in the coming quarters by securing new programs with new and existing customers, increasing our worldwide manufacturing capacity, and continuing to improve our manufacturing and procurement processes. Ongoing challenges that we face include but are not limited to the following: Continuing to win programs from new and existing customers, balancing capital employed, production capacity and key personnel in support of new customer programs, improving operating efficiencies, controlling costs while developing competitive pricing strategies, and successfully transitioning new program wins to full production. +Customers and Marketing +We provide a mix of manufacturing services for outsourced Original Equipment Manufacturing (OEM) products. We provide the following EMS services: Product design, surface mount technologies (SMT) and pin through hole capability for printed circuit board assembly, tool making, precision plastic molding, sheet metal fabrication, liquid injection molding, complex assembly, automated tape winding, prototype design and full product assembly. +Sales of the majority of our products have not historically been seasonal in nature, but may be seasonal in the future if there are changes in the types of products manufactured. Sales can, however, fluctuate significantly between quarters from changes in customers and customer demand due to the concentration of sales generated by our largest customers. +For the fiscal years 2016 , 2015 and 2014 , the five largest customers in each year accounted for 41%, 42% and 62% of combined total net sales, respectively. The decrease in concentration compared to 2014 was primarily the result of the acquisition of Ayrshire as well as the impact of the reduction in production levels for a certain longstanding customer. We continue to diversify our customer base by adding additional programs and customers. We expect net sales to our five largest customers as a percentage of total net sales to approximate current levels going forward. +The following table represents all customers that represented 10% or more of total net sales during the last three fiscal years: +Percentage of Net Sales by Fiscal Year +2016 +2015 +2014 +Customer A +18% +17% +20% +Customer B +* +* +15% +Customer C +* +* +15% +* Current customer amount represents less than 10%. +There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +We market our products and services primarily through our direct sales department which is comprised of strategically located field sales people and distributors. We also maintain relationships with several independent sales organizations to assist in marketing our EMS product lines. +5 +Manufacturing +We have continually made investments in developing and expanding a capital equipment base to achieve vertical integration and efficiencies in our manufacturing processes. We have invested significant capital into SMT for volume manufacturing of complex printed circuit board assemblies and in our metal shop providing precision metal stamping, fabricating, and finishing. We also design and develop tooling for injection molding and sheet metal fabrication and manufacture the majority of plastic and sheet metal parts used in the products we manufacture. Additionally, we have equipment to maintain a controlled clean environment for manufacturing processes that require a high level of precise control. +We use a variety of manual and automated assembly processes in our facilities, depending upon product complexity and degree of customization. Some examples of automated processes include component insertion, SMT, selective soldering, flexible robotic assembly, automated storage tape winding, computerized vision system quality inspection, laser turrets, automated switch and key top installation, and automated functional testing. +Our engineering expertise and automated manufacturing processes enable us to work closely with our customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. We use computer-aided design techniques and software to assist in preparation of the tool design layout and component placement, to reduce tooling and production costs, improve component and product quality, and enhance turnaround time during product development. +We purchase materials and components for our products from many different suppliers, including both domestic and international sources. We develop close working relationships with our suppliers, many of whom have been supplying products to us for several years. +Research, Development, and Engineering +As part of our long-term strategy, we are committed to supporting our customers by providing research, development, and engineering services. These services allow us to facilitate in optimizing new product designs, and the production processes of our customers' programs. +Research, development, and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials costs, depreciation, and allocated information technology and facilities costs. +Competition +The market for the products and services we provide is highly competitive. There are numerous competitors in the EMS industry, many of which have substantially more resources and are more geographically diverse than we are. Some of our competitors have similar international production capabilities, large financial resources and some have substantially greater manufacturing, research and development, and marketing resources. There is also competition from the manufacturing operations of our current and potential customers, who are continually evaluating the merits of manufacturing their products internally versus the advantages of outsourcing. We believe that we can currently compete favorably in these areas primarily on the basis of our international footprint, responsiveness, creativity, vertical production capability, quality, and cost. +Trademarks +Our name and logo are federally registered trademarks, and we believe they are valuable assets of our business. We operate under the trade name “KeyTronicEMS” to better identify our primary business concentration in contract manufacturing in the EMS industry. +Employees +We consider our employees to be our primary strength and we make considerable efforts to maintain a well-qualified workforce. Our employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. We regularly provide transportation, medical services, and meals to all of our employees in foreign locations. The Company also has defined contribution plans available to U.S. employees who have attained age 21 and provide group health, life, and disability insurance plans. We also maintain share based compensation plans and other long term incentive plans for certain employees and outside directors. +As of July 2, 2016 we had 4,947 employees compared to 4,866 on June 27, 2015 , and 3,343 on June 28, 2014 . Since we can have significant fluctuations in product demand, we seek to maintain flexibility in our workforce by utilizing skilled temporary and short-term contract labor in our manufacturing facilities in addition to full-time employees. +6 +Backlog +On July 30, 2016 our order backlog was valued at approximately $122.2 million, compared to approximately $115.2 million on July 24, 2015. The amount of backlog is not necessarily indicative of future sales but can be indicative of trends in expected future sales revenue. Due to the relationships with our customers, we will occasionally allow orders to be canceled or rescheduled and as a result it is not a meaningful indicator of future financial results. If there are canceled or rescheduled orders, we typically negotiate fees to cover the costs we have incurred. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change due to design modifications, customer forecast changes, or other customer requirements. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in Note 12, “Enterprise-Wide Disclosures” of the consolidated financial statements of this Annual Report on Form 10-K and that information is incorporated herein. +Executive Officers of the Registrant +The table below sets forth the name, current age and current position of our executive officers and other significant employees: +Name +Age +Positions Held +Executive Officers +Craig D. Gates +57 +President and Chief Executive Officer +Brett R. Larsen +43 +Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Douglas G. Burkhardt +58 +Executive Vice President of Worldwide Operations +Philip S. Hochberg +54 +Executive Vice President of Business Development +Lawrence J. Bostwick +64 +Vice President of Engineering and Quality +Frank Crispigna III +55 +Vice President of Materials +Duane D. Mackleit +48 +Vice President of Program Management +Executive Officers +CRAIG D. GATES – President and Chief Executive Officer +Mr. Gates, age 57 , has been President and Chief Executive officer of the Company since April 2009. Previously, he was Executive Vice President and General Manager from August 2002 to April 2009. He served as Executive Vice President of Marketing, Engineering and Sales from July 1997 to August 2002 and served as Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of 1994. From 1982 to 1991 he held various engineering and management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. Mr. Gates has a Bachelor of Science Degree in Mechanical Engineering and a Masters in Business Administration from the University of Illinois, Urbana. +BRETT R. LARSEN – Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Mr. Larsen, age 43 , has served as Executive Vice President of Administration, Chief Financial Officer, and Treasurer since July 2015. Previously, he was Vice President of Finance and Controller from February 2010 to July 2015. He was Chief Financial Officer of FLSmidth Spokane, Inc. from December 2008 to February 2010. From October 2005 through November 2008, Mr. Larsen served as Controller of Key Tronic Corporation. From May 2004 to October 2005, Mr. Larsen served as Manager of Financial Reporting of Key Tronic Corporation. From 2002 to May 2004, Mr. Larsen was an audit manager for the public accounting firm BDO USA, LLP. He also held various auditing and supervisory positions with Grant Thornton LLP from 1997 to 2002. Mr. Larsen has a Bachelor of Science degree in Accounting and a Masters degree in Accounting from Brigham Young University and is a Certified Public Accountant. +7 +DOUGLAS G. BURKHARDT – Executive Vice President of Worldwide Operations +Mr. Burkhardt, age 58 , has been Executive Vice President of Worldwide Operations of the Company since July 2010. Previously Mr. Burkhardt was Vice President of Worldwide Operations from July 2008 to July 2010 and Director of China Operations and Program Management from January 2006 to July 2008. Mr. Burkhardt also served as Director of Northwest and China Operations from November of 1998 to January of 2006. Mr. Burkhardt also served as Director of Customer Satisfaction from March 1997 to November 1998 and Director of Molding from September of 1995 to March of 1997. Prior to this, Mr. Burkhardt served in other various senior management positions within the Company. Mr. Burkhardt has been with the Company since May of 1989. Prior to joining Key Tronic, Mr. Burkhardt worked for House of Aluminum and Glass for 12 years where he was the plant manager. +PHILIP S. HOCHBERG – Executive Vice President of Business Development +Mr. Hochberg, age 54 , has been Executive Vice President of Business Development since July 2012. Prior to this, Mr. Hochberg served as Vice President of Business Development from October 2009 through June 2012. He was Director of Business Development and Program Management from July 2008 to October 2009. Mr. Hochberg served as Director of Business Development from October 2004 to July 2008 and as Director of EMS Sales and Marketing from July 2000 to October 2004. Prior to joining Key Tronic, Mr. Hochberg worked for Quinton Instrument Company as their Director of Marketing and Product Management from 1992 to 2000. From 1988 to 1992, he was employed by SpaceLabs Medical as their Business Development Marketing Manager. Mr. Hochberg has an MBA from the University of British Columbia, a BA in Psychology, with a minor in Business from Washington University in St. Louis. +LAWRENCE J. BOSTWICK – Vice President of Engineering and Quality +Mr. Bostwick, age 64 , has been Vice President of Engineering and Quality since July 2008. Previously he was Director of Engineering and Quality from February 2007 to July 2008 and served as Corporate Director of Quality from February 2006 to February 2007. From 2003 to 2006 he was Director of Supply Chain Management and Quality for the Lancer Corporation and from 1998 to 2003 he was Vice President of Operations for Thermacore International. He is a graduate of the Westinghouse and General Electric – Engineering and Manufacturing Professional Development Programs. He is certified in both Quality and Industrial Engineering and is a Lean – Six Sigma Master Black Belt. Mr. Bostwick has a combined B.S. degree in Production and Operation and Industrial Engineering from Bowling Green State University and a Masters degree in Industrial Engineering and Business Administration from Syracuse University. +FRANK CRISPIGNA III – Vice President of Materials +Mr. Crispigna, age 55 , has been Vice President of Materials of the company since October 2011. Prior to this, Mr. Crispigna held a variety of Materials and Supply Chain positions at Plexus Corporation since 1997, most recently serving as the Director – Supply Chain Solutions from 2005 - 2011. He has a Masters degree in Business Administration, and a Bachelor of Business Administration Degree in Marketing from the University of Wisconsin – Oshkosh. Mr. Crispigna also is a C.P.M., and received his certification in Supply Chain Leadership from the University of Wisconsin. +DUANE D. MACKLEIT – Vice President of Program Management +Mr. Mackleit, age 48 , has been Vice President of Program Management of the company since July 2012. He served as Director of Program Management from July 2008 through June 2012. From May 2006 to July 2008 he served as Principal Program Manager. Prior to that, he served as Program Manager from March 2002 to May 2006 and Associate Program Manager from August 2000 to March 2002. Mr. Mackleit has also held several other positions with Key Tronic Corporation. Mr. Mackleit has an AA in Business from Spokane Falls Community College and a BA in Business/Marketing from Eastern Washington University. He also holds a MBA from Gonzaga University. +Available Information +Our principal executive offices are located at 4424 North Sullivan Road, Spokane Valley, Washington 99216, and our telephone number is (509) 928-8000. Our website is located at http://www.keytronic.com where filings of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or current reports on Form 8-K are available after they have been filed with the Securities and Exchange Commission. The information presented on our website currently and in the future is not considered to be part of this document or any document incorporated by reference in this document. +8 \ No newline at end of file diff --git a/raw/filings/0000719733/2016/0000719733-16-000164/item13.txt b/raw/filings/0000719733/2016/0000719733-16-000164/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..c12e50063c066e752a36b44d6b8957ed7b2d7b10 --- /dev/null +++ b/raw/filings/0000719733/2016/0000719733-16-000164/item13.txt @@ -0,0 +1,3 @@ +Item 13: +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions”, “Compensation Committee Interlocks and Insider Participation”, and “Directors’ Independence” in the Company’s 2016 Proxy Statement is incorporated herein by this reference. \ No newline at end of file diff --git a/raw/filings/0000719733/2016/0000719733-16-000164/item9a.txt b/raw/filings/0000719733/2016/0000719733-16-000164/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..ae93b18c40e72179c0b7e419ee5f69a2a3645564 --- /dev/null +++ b/raw/filings/0000719733/2016/0000719733-16-000164/item9a.txt @@ -0,0 +1,26 @@ +Item 9A: +CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +It is the responsibility of our management to establish, maintain, and monitor disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 are recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Additionally, these disclosure controls include controls and procedures that are designed to accumulate and communicate the information required to be disclosed to our Company’s Chief Executive Officer and Chief Financial Officer, allowing for timely decisions regarding required disclosures. As of the end of the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(f). Based on our assessment, we believe that as of July 2, 2016 , the Company’s disclosure controls and procedures are effective based on that criteria. +Management’s Report on Internal Control over Financial Reporting +Our management has the responsibility to establish and maintain adequate internal controls over our financial reporting, as defined in Rule 13a-15(f) under the Securities and Exchange Act of 1934. Our internal controls are designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our external financial statements in accordance with generally accepted accounting principles (GAAP). +Due to inherent limitations of any internal control system, management acknowledges that there are limitations as to the effectiveness of internal controls over financial reporting and therefore recognize that only reasonable assurance can be gained from any internal control system. Accordingly, our internal control system may not detect or prevent material misstatements in our financial statements and projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, we have performed an assessment of the effectiveness of our internal controls over financial reporting as of July 2, 2016 . This assessment was based on the criteria established in Internal Control-Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that as of July 2, 2016 , the Company’s internal control over financial reporting is effective based on that criteria. +The effectiveness of the Company's internal control over financial reporting as of July 2, 2016 has been audited by BDO USA LLP, an independent registered public accounting firm, as stated in their report which is included herein. +Changes in Internal Control over Financial Reporting +There have been no significant changes in our internal controls over financial reporting during our fourth fiscal quarter ended July 2, 2016 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)). +55 +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Key Tronic Corporation +Spokane Valley, Washington +We have audited Key Tronic Corporation's internal control over financial reporting as of July 2, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Key Tronic Corporation's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Item 9A “Management's Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, Key Tronic Corporation maintained, in all material respects, effective internal control over financial reporting as of July 2, 2016, based on the COSO criteria . +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Key Tronic Corporation as of July 2, 2016 and June 27, 2015, and the related consolidated statements of income, comprehensive income (loss), shareholders' equity, and cash flows for each of the three years in the period ended July 2, 2016 and our report dated September 9, 2016, expressed an unqualified opinion thereon. +/s/ BDO USA, LLP +Spokane, Washington +September 9, 2016 +56 \ No newline at end of file diff --git a/raw/filings/0000719733/2016/0000719733-16-000164/rp_note.txt b/raw/filings/0000719733/2016/0000719733-16-000164/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000719733/2016/0000719733-16-000164/rpt_disclosure.txt b/raw/filings/0000719733/2016/0000719733-16-000164/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..dfde333ac1ff0b50f22df05f324a9cc77bbe251b --- /dev/null +++ b/raw/filings/0000719733/2016/0000719733-16-000164/rpt_disclosure.txt @@ -0,0 +1,5 @@ +Related Person Transactions +In April 2007, the Board of Directors adopted a written policy and procedures for the approval or ratification of Interested Transactions with Related Parties. The policy and procedures supplement the Company’s Code of Conduct. The policy defines an “Interested Transaction” as any transaction, arrangement or relationship or series of similar transactions, arrangements or relationships (including any indebtedness or guarantee of indebtedness) in which (1) the aggregate amount involved will or may be expected to exceed $120,000 in any calendar year, (2) the Company is a participant, and (3) any Related Party has or will have a direct or indirect interest (other than solely as a result of being a director or a less than 10 percent beneficial owner of another entity). +The policy defines a “Related Party” as any (a) person who is or was (since the beginning of the last fiscal year for which the Company has filed a Form 10-K and proxy statement, even if they do not presently serve in that role) an executive officer, director or nominee for election as a director, (b) greater than 5 percent beneficial owner of the Company’s common stock, or (c) immediate family member of any of the foregoing. Immediate family member includes a person’s spouse, parents, stepparents, children, stepchildren, siblings, mothers- and fathers-in-law, sons- and daughters-in-law, and brothers- and sisters-in-law and anyone residing in such person’s home (other than a tenant or employee). +The Audit Committee is responsible for review, approval, ratification or disapproval of Interested Transactions. In determining whether to approve or ratify an Interested Transaction, the Committee will take into account, among other factors it deems appropriate, whether the Interested Transaction is on terms no less favorable than terms generally available to an unaffiliated third party under the same or similar circumstances and the extent of the Related Party’s interest in the Transaction. +6 \ No newline at end of file diff --git a/raw/filings/0000719733/2017/0000719733-17-000028/filing.txt b/raw/filings/0000719733/2017/0000719733-17-000028/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..321c36ffc2b80689debf4327655ccf92c7171111 --- /dev/null +++ b/raw/filings/0000719733/2017/0000719733-17-000028/filing.txt @@ -0,0 +1,3503 @@ +10-K +1 +ktcc-07012017x10k.htm +10-K +Document +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +____________________________________________________________ +FORM 10-K +____________________________________________________________ +x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE FISCAL YEAR ENDED JULY 1, 2017 +OR +¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE PERIOD FROM TO +Commission File Number 0-11559 +____________________________________________________________ +KEY TRONIC CORPORATION +(Exact name of registrant as specified in its charter) +____________________________________________________________ +Washington +91-0849125 +(State or other jurisdiction of +Incorporation or organization) +(I.R.S. Employer +Identification No.) +N. 4424 Sullivan Road, Spokane Valley, +Washington +99216 +(Address of principal executive offices) +(Zip Code) +(509) 928-8000 +(Registrant’s telephone number, including area code) +N/A +(Former name, former address and former fiscal year, if changed since last report) +____________________________________________________________ +Securities Registered Pursuant to Section 12(b) of the Act: None +Title of each class +Name of each exchange on which registered +Common stock, no par value +The NASDAQ Stock Market LLC +Securities Registered Pursuant to Section 12(g) of the Act: None +____________________________________________________________ +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ¨ No x +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulations S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. +(Check one): +Large accelerated filer +¨ +Accelerated filer +x +Non-accelerated filer +¨ (Do not check if a smaller reporting company) +Smaller reporting company +¨ +Emerging growth company +¨ +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x +State the aggregate market value of the voting and non-voting common equity held by non affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. +As of December 31, 2016, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $79.8 million based on the closing price as reported on the NASDAQ. +Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: 10,759,680 shares of common stock were outstanding as of September 6, 2017 . +____________________________________________________________ +Documents Incorporated by Reference: +Certain information is incorporated into Part III of this report by reference to the Proxy Statement for the registrant's 2017 annual meeting of stockholders to be filed with the Securities and Exchange Commission pursuant to Regulation 14A not later than 120 days after the end of the fiscal year covered by this Form 10-K. +KEY TRONIC CORPORATION +2017 FORM 10-K +TABLE OF CONTENTS +Page No. +PART I +Item 1. +Business +4 +Item 1A. +Risk Factors +9 +Item 1B. +Unresolved Staff Comments +15 +Item 2. +Properties +15 +Item 3. +Legal Proceedings +16 +Item 4. +Mine Safety Disclosures +16 +PART II +Item 5. +Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities +16 +Item 6. +Selected Financial Data +18 +Item 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +19 +Item 7A. +Quantitative and Qualitative Disclosures about Market Risk +29 +Item 8. +Financial Statements and Supplementary Data +31-56 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +57 +Item 9A. +Controls and Procedures +57 +Item 9B. +Other Information +59 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +59 +Item 11. +Executive Compensation +59 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +59 +Item 13. +Certain Relationships and Related Transactions, and Director Independence +60 +Item 14. +Principal Accounting Fees and Services +60 +PART IV +Item 15. +Exhibits and Financial Statement Schedule +60 +Signatures +65 +3 +FORWARD-LOOKING STATEMENTS +References in this report to “the Company,” “Key Tronic,” “KeyTronicEMS,” “we,” “our,” or “us” mean Key Tronic Corporation together with its subsidiaries, except where the context otherwise requires. +This Annual Report on Form 10-K contains forward-looking statements in addition to historical information. Forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those reflected in the forward-looking statements. Risks and uncertainties that might cause such differences include, but are not limited to those outlined in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risks and Uncertainties that May Affect Future Results.” Readers are cautioned not to place undue reliance on forward-looking statements, which reflect management’s opinions only as of the date hereof. The Company undertakes no obligation to update forward-looking statements to reflect developments or information obtained after the date hereof and disclaims any obligation to do so. Readers should carefully review the risk factors described in periodic reports the Company files from time to time with the Securities and Exchange Commission, including Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. +PART I +Item 1. +BUSINESS +Background +Key Tronic Corporation (dba: KeyTronicEMS Co.) was organized in 1969, as a Washington corporation that locally manufactured computer keyboards. The ability to design, build and deliver a quality product led us to become a leading independent manufacturer of keyboards for computers in the United States. Our fully integrated design, tooling, and automated manufacturing capabilities enabled us to rapidly respond to customers’ needs for keyboards in production quantities worldwide. We supported our sales growth through the development and purchase of international manufacturing facilities. As the computer keyboard market matured with increasing competition from other international providers, we determined that our business could no longer solely rely on keyboard sales. +After assessing market conditions and our strengths and capabilities, we shifted our focus from keyboard manufacturing to contract manufacturing for a wide range of products. Our unique strategic attributes are based on our core strengths of innovative design and engineering expertise in electronics, mechanical engineering, sheet metal fabrication and stamping, and precision plastics combined with high-quality, low cost production, and assembly on an international basis while providing exceptional customer service. These strengths have made our company a strong competitor in the electronic manufacturing services (EMS) market. +Acquisition +On September 3, 2014, we completed the acquisition of all of the outstanding shares of CDR Manufacturing, Inc. (dba Ayrshire Electronics), which added five locations (four in North America and one in Mexico). This acquisition expanded our printed circuit board assembly capacity, total revenue, and added to and diversified our customer base with the addition of many new multi-national companies. Subsequent to the acquisition, the Reynosa, Mexico operations were transferred to the Company’s existing Juarez, Mexico facilities. During the second quarter of fiscal year 2017, we closed the Harrodsburg, Kentucky facility in order to improve operating efficiencies. The remaining programs from the Kentucky facility have been transferred to other Key Tronic facilities. +Our Industry and Strategy +The expansion of the EMS industry and our acquisitions have allowed us to continue to expand our customer base and the industries that we serve. The increase in new programs represents a growing portion of our revenue and a promising foundation for our future. In keeping with our long-term strategic objectives, we have been successfully building a more diversified customer portfolio, spanning a wider range of industries. We currently offer our customers the following services: integrated electronic and mechanical engineering, precision plastic molding, sheet metal fabrication, printed circuit board (PCB) and complete product assembly, component selection, sourcing and procurement, worldwide logistics, and new product testing and production all at competitive pricing due to our global footprint. We differentiate ourselves from others our size and larger in the EMS industry by providing vertical integration, a flexible and responsive approach to our customer’s changing supply demand, and complete design engineering support. +4 +We believe that we are well positioned in the EMS industry to continue the expansion of our customer base and achieve long term growth. Our unique blend of multinational facilities, vertical integration, centralized management, and core strengths continue to support our growth and our customers’ needs. We continue to focus on controlling operating expenses and leveraging the synergistic capabilities of our world-class facilities in the United States, Mexico, and China. This international production capability provides our customers with the benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs, and reduced product fulfillment time. Given our competitive advantages and the growing pressure for new potential customers to move forward with their outsourcing strategies, we are strongly positioned to win new business in coming periods and grow our revenue and profits. +The EMS industry is intensely competitive. Although our customer base is growing, we still have less than 1% of the potential global market and our revenue can fluctuate significantly due to reliance on a concentrated base of customers. We are planning for new customer growth in the coming quarters by securing new programs with new and existing customers, increasing our worldwide manufacturing capacity, leveraging further our design engineering capabilities and continuing to improve our manufacturing and procurement processes. Ongoing challenges that we face include but are not limited to the following: Continuing to win programs from new and existing customers, balancing capital employed, production capacity and key personnel in support of new customer programs, improving operating efficiencies, controlling costs while developing competitive pricing strategies, and successfully transitioning new program wins to full production. +Customers and Marketing +We provide a mix of manufacturing services for outsourced Original Equipment Manufacturing (OEM) products. We provide the following EMS services: Product design, surface mount technologies (SMT) and pin through hole capability for printed circuit board assembly, tool making, precision plastic molding, sheet metal fabrication, liquid injection molding, complex assembly, automated tape winding, prototype design and full product assembly. +Sales of the majority of our products have not historically been seasonal in nature, but may be seasonal in the future if there are changes in the types of products manufactured. Sales can, however, fluctuate significantly between quarters from changes in customers and customer demand due to the concentration of sales generated by our largest customers. +For the fiscal years 2017 , 2016 and 2015 , the five largest customers in each year accounted for 42%, 41% and 42% of combined total net sales, respectively. We continue to diversify our customer base by adding additional programs and customers. We expect net sales to our five largest customers as a percentage of total net sales to approximate current levels going forward. +The following table represents all customers that represented 10% or more of total net sales during the last three fiscal years: +Percentage of Net Sales by Fiscal Year +2017 +2016 +2015 +Customer A +18% +18% +17% +There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +We market our products and services primarily through our direct sales department which is comprised of strategically located field sales people and distributors. We also maintain relationships with several independent sales organizations to assist in marketing our EMS product lines. +Manufacturing +We have continually made investments in developing and expanding a capital equipment base to achieve vertical integration and efficiencies in our manufacturing processes. We have invested significant capital into SMT for volume manufacturing of complex printed circuit board assemblies and in our metal shop providing precision metal stamping, fabricating, and finishing. We also design and develop tooling for injection molding and sheet metal fabrication and manufacture the majority of plastic and sheet metal parts used in the products we manufacture. Additionally, we have equipment to maintain a controlled clean environment for manufacturing processes that require a high level of precise control. +We use a variety of manual and automated assembly processes in our facilities, depending upon product complexity and degree of customization. Some examples of automated processes include component insertion, SMT, selective soldering, flexible robotic assembly, automated storage tape winding, computerized vision system quality inspection, laser turrets, automated switch and key top installation, and automated functional testing. +5 +Our engineering expertise and automated manufacturing processes enable us to work closely with our customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. We use computer-aided design techniques and software to assist in preparation of the tool design layout and component placement, to reduce tooling and production costs, improve component and product quality, and enhance turnaround time during product development. +We purchase materials and components for our products from many different suppliers, including both domestic and international sources. We develop close working relationships with our suppliers, many of whom have been supplying products to us for several years. +Research, Development, and Engineering +As part of our long-term strategy, we are committed to supporting our customers by providing research, development, and engineering services. We have recently seen an increase in the success of providing design support on existing and potential customers in differentiating ourselves. These services allow us to facilitate in optimizing new product designs, and the production processes of our customers' programs. +Research, development, and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials costs, depreciation, and allocated information technology and facilities costs. +Competition +The market for the products and services we provide is highly competitive. There are numerous competitors in the EMS industry, many of which have substantially more resources and are more geographically diverse than we are. Some of our competitors have similar international production capabilities, large financial resources and some have substantially greater manufacturing, research and development, and marketing resources. There is also competition from the manufacturing operations of our current and potential customers, who are continually evaluating the merits of manufacturing their products internally versus the advantages of outsourcing. We believe that we can currently compete favorably in these areas primarily on the basis of our international footprint, responsiveness, creativity, vertical production capability, quality, and cost. +Trademarks +Our name and logo are federally registered trademarks, and we believe they are valuable assets of our business. We operate under the trade name “KeyTronicEMS” to better identify our primary business concentration in contract manufacturing in the EMS industry. +Employees +We consider our employees to be our primary strength and we make considerable efforts to maintain a well-qualified workforce. Our employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. We regularly provide transportation, medical services, and meals to all of our employees in foreign locations. The Company also has defined contribution plans available to U.S. employees who have attained age 21 and provide group health, life, and disability insurance plans. We also maintain share based compensation plans and other long term incentive plans for certain employees and outside directors. +As of July 1, 2017 we had 5,038 full-time employees compared to 4,947 on July 2, 2016 , and 4,866 on June 27, 2015 . Since we can have significant fluctuations in product demand, we seek to maintain flexibility in our workforce by utilizing skilled temporary and short-term contract labor in our manufacturing facilities in addition to full-time employees. +Backlog +On July 29, 2017 our order backlog was valued at approximately $126.9 million, compared to approximately $122.2 million on July 30, 2016. The amount of backlog is not necessarily indicative of future sales but can be indicative of trends in expected future sales revenue. Due to the relationships with our customers, we will occasionally allow orders to be canceled or rescheduled and as a result it is not a meaningful indicator of future financial results. If there are canceled or rescheduled orders, we typically negotiate fees to cover the costs we have incurred. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change due to design modifications, customer forecast changes, or other customer requirements. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in Note 12, “Enterprise-Wide Disclosures” of the consolidated financial statements of this Annual Report on Form 10-K and that information is incorporated herein. +6 +Executive Officers of the Registrant +The table below sets forth the name, current age and current position of our executive officers and other significant employees: +Name +Age +Positions Held +Executive Officers +Craig D. Gates +58 +President and Chief Executive Officer +Brett R. Larsen +44 +Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Douglas G. Burkhardt +59 +Executive Vice President of Worldwide Operations +Philip S. Hochberg +55 +Executive Vice President of Business Development +Lawrence J. Bostwick +65 +Vice President of Regulatory Affairs +David H. Knaggs +36 +Vice President of Quality +Frank Crispigna III +56 +Vice President of Materials +Duane D. Mackleit +49 +Vice President of Program Management +Chad T. Orebaugh +46 +Vice President of Engineering +Executive Officers +CRAIG D. GATES – President and Chief Executive Officer +Mr. Gates, age 58 , has been President and Chief Executive officer of the Company since April 2009. Previously, he was Executive Vice President and General Manager from August 2002 to April 2009. He served as Executive Vice President of Marketing, Engineering and Sales from July 1997 to August 2002 and served as Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of 1994. From 1982 to 1991 he held various engineering and management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. Mr. Gates has a Bachelor of Science Degree in Mechanical Engineering and a Masters in Business Administration from the University of Illinois, Urbana. +BRETT R. LARSEN – Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Mr. Larsen, age 44 , has served as Executive Vice President of Administration, Chief Financial Officer, and Treasurer since July 2015. Previously, he was Vice President of Finance and Controller from February 2010 to July 2015. He was Chief Financial Officer of FLSmidth Spokane, Inc. from December 2008 to February 2010. From October 2005 through November 2008, Mr. Larsen served as Controller of Key Tronic Corporation. From May 2004 to October 2005, Mr. Larsen served as Manager of Financial Reporting of Key Tronic Corporation. From 2002 to May 2004, Mr. Larsen was an audit manager for the public accounting firm BDO USA, LLP. He also held various auditing and supervisory positions with Grant Thornton LLP from 1997 to 2002. Mr. Larsen has a Bachelor of Science degree in Accounting and a Masters degree in Accounting from Brigham Young University and is a Certified Public Accountant. +DOUGLAS G. BURKHARDT – Executive Vice President of Worldwide Operations +Mr. Burkhardt, age 59 , has been Executive Vice President of Worldwide Operations of the Company since July 2010. Previously Mr. Burkhardt was Vice President of Worldwide Operations from July 2008 to July 2010 and Director of China Operations and Program Management from January 2006 to July 2008. Mr. Burkhardt also served as Director of Northwest and China Operations from November of 1998 to January of 2006. Mr. Burkhardt also served as Director of Customer Satisfaction from March 1997 to November 1998 and Director of Molding from September of 1995 to March of 1997. Prior to this, Mr. Burkhardt served in other various senior management positions within the Company. Mr. Burkhardt has been with the Company since May of 1989. Prior to joining Key Tronic, Mr. Burkhardt worked for House of Aluminum and Glass for 12 years where he was the plant manager. +PHILIP S. HOCHBERG – Executive Vice President of Business Development +Mr. Hochberg, age 55 , has been Executive Vice President of Business Development since July 2012. Prior to this, Mr. Hochberg served as Vice President of Business Development from October 2009 through June 2012. He was Director of Business Development and Program Management from July 2008 to October 2009. Mr. Hochberg served as Director of Business Development from October 2004 to July 2008 and as Director of EMS Sales and Marketing from July 2000 to October 2004. Prior to joining Key Tronic, Mr. Hochberg worked for Quinton Instrument Company as their Director of Marketing and Product Management from 1992 to 2000. From 1988 to 1992, he was employed by SpaceLabs Medical as their Business Development Marketing Manager. Mr. Hochberg has an MBA from the University of British Columbia, a BA in Psychology, with a minor in Business from Washington University in St. Louis. +7 +LAWRENCE J. BOSTWICK – Vice President of Regulatory Affairs +Mr. Bostwick, age 65 , has been Vice President of Engineering and Quality since July 2008. Previously he was Director of Engineering and Quality from February 2007 to July 2008 and served as Corporate Director of Quality from February 2006 to February 2007. From 2003 to 2006 he was Director of Supply Chain Management and Quality for the Lancer Corporation and from 1998 to 2003 he was Vice President of Operations for Thermacore International. He is a graduate of the Westinghouse and General Electric – Engineering and Manufacturing Professional Development Programs. He is certified in both Quality and Industrial Engineering and is a Lean – Six Sigma Master Black Belt. Mr. Bostwick has a combined B.S. degree in Production and Operation and Industrial Engineering from Bowling Green State University and a Masters degree in Industrial Engineering and Business Administration from Syracuse University. +DAVID H. KNAGGS – Vice President of Quality +Mr. Knaggs, age 36 , has been Vice President of Quality of the company since October 2016. Before joining KeyTronicEMS, Mr. Knaggs worked at Telect, Inc. from 2008 to 2016 as their Director of Engineering. Prior to that, he worked at Isothermal Systems Research as Lead Systems Engineer from 2003 to 2008. He has a Bachelor of Science degree in Mechanical Engineering with a minor in mathematics from the University of Washington. +FRANK CRISPIGNA III – Vice President of Materials +Mr. Crispigna, age 56 , has been Vice President of Materials of the company since October 2011. Prior to this, Mr. Crispigna held a variety of Materials and Supply Chain positions at Plexus Corporation since 1997, most recently serving as the Director – Supply Chain Solutions from 2005 - 2011. He has a Masters degree in Business Administration, and a Bachelor of Business Administration Degree in Marketing from the University of Wisconsin – Oshkosh. Mr. Crispigna also is a C.P.M., and received his certification in Supply Chain Leadership from the University of Wisconsin. +DUANE D. MACKLEIT – Vice President of Program Management +Mr. Mackleit, age 49 , has been Vice President of Program Management of the company since July 2012. He served as Director of Program Management from July 2008 through June 2012. From May 2006 to July 2008 he served as Principal Program Manager. Prior to that, he served as Program Manager from March 2002 to May 2006 and Associate Program Manager from August 2000 to March 2002. Mr. Mackleit has also held several other positions with Key Tronic Corporation. Mr. Mackleit has an AA in Business from Spokane Falls Community College and a BA in Business/Marketing from Eastern Washington University. He also holds a MBA from Gonzaga University. +CHAD T. OREBAUGH – Vice President of Engineering +Mr. Orebaugh, age 46 , has been Vice President of Engineering since April 2017. Prior to this, Mr. Orebaugh served as Director of Engineering since May 2013. From April 2010 to May 2013, he served as Manager of Engineering. From January 2000 to April 2010 he served as Lead Mechanical Engineer. Prior to that, he served as Mechanical Engineer from October 1998 to January 2000 and Associate Mechanical Engineer since October 1997. Mr. Orebaugh holds a BA in Mechanical Engineering from Gonzaga University. +Available Information +Our principal executive offices are located at 4424 North Sullivan Road, Spokane Valley, Washington 99216, and our telephone number is (509) 928-8000. Our website is located at http://www.keytronic.com where filings of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or current reports on Form 8-K are available after they have been filed with the Securities and Exchange Commission. The information presented on our website currently and in the future is not considered to be part of this document or any document incorporated by reference in this document. +8 +Item 1A. +RISK FACTORS +There are risks and uncertainties that could affect our business. These risks and uncertainties include but are not limited to, the risk factors described below, in Item 7A: “Quantitative and Qualitative Disclosures about Market Risk” and elsewhere in this Form 10-K. +RISKS AND UNCERTAINTIES THAT MAY AFFECT FUTURE RESULTS +The following risks and uncertainties could affect our actual results and could cause results to differ materially from past results or those contemplated by our forward-looking statements. When used herein, the words “expects,” “believes,” “anticipates” and other similar expressions are intended to identify forward-looking statements. +We may experience fluctuations in quarterly results of operations. +Our quarterly operating results have varied in the past and may vary in the future due to a variety of factors, including adverse changes in the U.S. and global macroeconomic environment, volatility in overall demand for our customers’ products, success of customers’ programs, timing of new programs, new product introductions or technological advances by us, our customers and our competitors, and changes in pricing policies by us, our customers, our suppliers, and our competitors. Our customer base is diverse in the markets they serve, however, decreases in demand, particularly from customers in certain industries could affect future quarterly results. Additionally, our customers could be adversely impacted by illiquidity in the credit markets which could directly impact our operating results. +Component procurement, production schedules, personnel and other resource requirements are based on estimates of customer requirements. Occasionally, our customers may request accelerated production that can stress resources and reduce operating margins. Conversely, our customers may abruptly lower or cancel production which may lead to a sudden, unexpected increase in inventory or accounts receivable for which we may not be reimbursed even when under contract with customers. In addition, because many of our operating expenses are relatively fixed, a reduction in customer demand can harm our gross profit and operating results. The products which we manufacture for our customers have relatively short product lifecycles. Therefore, our business, operating results and financial condition are dependent in a significant way on our ability to obtain orders from new customers and new product programs from existing customers. +Operating results can also fluctuate if changes are made to significant estimates and assumptions. Significant estimates and assumptions include the allowance for doubtful receivables, provision for obsolete and non-saleable inventory, stock-based compensation, the valuation allowance on deferred tax assets, valuation of goodwill, impairment of long-lived assets, long-term incentive compensation accrual, the provision for warranty costs, the impact of hedging activities and purchase price allocation. +We are exposed to general economic conditions, which could have a material adverse impact on our business, operating results and financial condition. +Adverse economic conditions and uncertainty in the global economy such as unstable global financial and credit markets, inflation, and recession can negatively impact our business. Unfavorable economic conditions could affect the demand for our customers’ products by triggering a reduction in orders as well as a decline in forecasts which could adversely affect our sales in future periods. Additionally, the financial strength of our customers and suppliers and their ability to obtain and rely on credit financing may affect their ability to fulfill their obligations to us and have an adverse effect on our financial results. +The majority of our sales come from a small number of customers and a decline in sales to any of these customers could adversely affect our business. +At present, our customer base is concentrated and could become more or less concentrated. There can be no assurance that our principal customers will continue to purchase products from us at current levels. Moreover, we typically do not enter into long-term volume purchase contracts with our customers, and our customers have certain rights to extend or delay the shipment of their orders. We, however, typically require that our customers contractually agree to buy back inventory purchased within specified lead times to build their products if not used. +The loss of one or more of our major customers, or the reduction, delay or cancellation of orders from such customers, due to economic conditions or other forces, could materially and adversely affect our business, operating results and financial condition. The contraction in demand from certain industries could impact our customer orders and have a negative impact on our operations over the foreseeable future. Additionally, if one or more of our customers were to become insolvent or otherwise unable to pay for the manufacturing services provided by us, our operating results and financial condition would be adversely affected. +9 +We depend on a limited number of suppliers for certain components that are critical to our manufacturing processes. A shortage of these components or an increase in their price could interrupt our operations and result in a significant change in our results of operations. +We are dependent on many suppliers, including sole source suppliers, to provide key components and raw materials used in manufacturing customers’ products. We have seen supply shortages in certain electronic components. In addition, our suppliers' facilities may also experience earthquakes, tsunamis and other natural disasters which may cause a shortage of components. This can result in longer lead times and the inability to meet our customers request for flexible production and extended shipment dates. If demand for components outpaces supply, capacity delays could affect future operations. Delays in deliveries from suppliers or the inability to obtain sufficient quantities of components and raw materials could cause delays or reductions in shipment of products to our customers which could adversely affect our operating results and damage customer relationships. +We operate in a highly competitive industry; if we are not able to compete effectively in the EMS industry, our business could be adversely affected. +Competitors may offer customers lower prices on certain high volume programs. This could result in price reductions, reduced margins and loss of market share, all of which would materially and adversely affect our business, operating results, and financial condition. If we were unable to provide comparable or better manufacturing services at a lower cost than our competitors, it could cause sales to decline. In addition, competitors can copy our non-proprietary designs and processes after we have invested in development of products for customers, thereby enabling such competitors to offer lower prices on such products due to savings in development costs. +Cash and cash equivalents are exposed to concentrations of credit risk. +We place our cash with high credit quality institutions. At times, such balances may be in excess of the federal depository insurance limit or may be on deposit at institutions which are not covered by insurance. If such institutions were to become insolvent during which time it held our cash and cash equivalents in excess of the insurance limit, it could be necessary to obtain other credit financing to operate our facilities. +Our ability to secure and maintain sufficient credit arrangements is key to our continued operations. +There is no assurance that we will be able to retain or renew our credit agreements in the future. In the event the business grows rapidly or there is uncertainty in the macroeconomic climate, additional financing resources could be necessary in the current or future fiscal years. There is no assurance that we will be able to obtain equity or debt financing at acceptable terms, or at all in the future. In addition, we have restrictive covenants with our financial institution which could impact how we manage our business. If we cannot meet our financial covenants, our borrowings could become immediately payable which could have a material adverse impact on our financial statements. For a summary of our banking arrangements, see Note 4 Long-Term Debt of the “Notes to Consolidated Financial Statements.” +Our operations may be subject to certain risks. +We manufacture product in facilities located in Mexico, China and the United States. These operations may be subject to a number of risks, including: +• +difficulties in staffing, turnover and managing onshore and offshore operations; +• +political and economic instability (including acts of terrorism, pandemics, civil unrest, forms of violence and outbreaks of war), which could impact our ability to ship, manufacture, and/or receive product; +• +unexpected changes in regulatory requirements and laws; +• +longer customer payment cycles and difficulty collecting accounts receivable; +• +export duties, import controls and trade barriers (including quotas); +• +governmental restrictions on the transfer of funds; +• +burdens of complying with a wide variety of foreign laws and labor practices; +• +our locations may be impacted by hurricanes, tornadoes, earthquakes, water shortages, tsunamis, floods, typhoons, fires, extreme weather conditions and other natural or man-made disasters. +Our operations in certain foreign locations receive favorable income tax treatment in the form of tax credits or other incentives. In the event that such tax incentives are not extended, are repealed, or we no longer qualify for such programs, our taxes may increase, which would reduce our net income. +10 +Additionally, certain foreign jurisdictions restrict the amount of cash that can be transferred to the U.S or impose taxes and penalties on such transfers of cash. To the extent we have excess cash in foreign locations that could be used in, or is needed by, our operations in the United States, we may incur significant penalties and/or taxes to repatriate these funds. +Fluctuations in foreign currency exchange rates could increase our operating costs. +We have manufacturing operations located in Mexico and China. A significant portion of our operations are denominated in the Mexican peso and the Chinese currency, the renminbi ("RMB"). Currency exchange rates fluctuate daily as a result of a number of factors, including changes in a country's political and economic policies. Volatility in the currencies of our entities and the United States dollar could seriously harm our business, operating results and financial condition. The primary impact of currency exchange fluctuations is on the cash, receivables, payables and expenses of our operating entities. As part of our hedging strategy, we currently use Mexican peso forward contracts to hedge foreign currency fluctuations for a portion of our Mexican peso denominated expenses. We currently do not hedge expenses denominated in RMB. Unexpected losses could occur from increases in the value of these currencies relative to the United States dollar. +Our success will continue to depend to a significant extent on our key personnel. +Our future success depends in large part on the continued service of our key technical, marketing and management personnel and on our ability to continue to attract and retain qualified production employees. There can be no assurance that we will be successful in attracting and retaining such personnel, particularly in our manufacturing locales that may be experiencing high demand for similar key personnel. The loss of key employees could have a material adverse effect on our business, operating results and financial condition. +If we are unable to maintain our technological and manufacturing process expertise, our business could be adversely affected. +The markets for our customers’ products is characterized by rapidly changing technology, evolving industry standards, frequent new product introductions and short product life cycles. The introduction of products embodying new technologies or the emergence of new industry standards can render existing products obsolete or unmarketable. Our success will depend upon our customers’ ability to enhance existing products and to develop and introduce, on a timely and cost-effective basis, new products that keep pace with technological developments and emerging industry standards and address evolving and increasingly sophisticated customer requirements. Failure of our customers to do so could substantially harm our customers’ competitive positions. There can be no assurance that our customers will be successful in identifying, developing and marketing products that respond to technological change, emerging industry standards or evolving customer requirements. +Start-up costs and inefficiencies related to new or transferred programs can adversely affect our operating results and such costs may not be recoverable if such new programs or transferred programs are canceled or don’t meet expected sales volumes. +Start-up costs, the management of labor and equipment resources in connection with the establishment of new programs and new customer relationships, and the need to obtain required resources in advance can adversely affect our gross margins and operating results. These factors are particularly evident in the ramping stages of new programs. These factors also affect our ability to efficiently use labor and equipment. We are currently managing a number of new programs. Consequently, our exposure to these factors has increased. In addition, if any of these new programs or new customer relationships were terminated, our operating results could be harmed, particularly in the short term. We may not be able to recoup these start-up costs or replace anticipated new program revenues. +Customers may change production timing and demand schedules which makes it difficult for us to schedule production and capital expenditures and to maximize the efficiency of our manufacturing capacity. +Changes in demand for customer products reduce our ability to accurately estimate the future requirements of our customers. This makes it difficult to schedule production and maximize utilization of our manufacturing capacity. We must determine the levels of business that we will seek and accept from customers, set production schedules, commit to procuring inventory, and allocate personnel and resources, based on our estimates of our customers' requirements. Customers can require sudden increases and decreases in production which can put added stress on resources and reduce margins. Sudden decreases in production can lead to excess inventory on hand which may or may not be reimbursed by our customers even when under contract. +Continued growth could further lead to capacity constraints. We may need to transfer production to other facilities, acquire new facilities, or outsource production which could negatively impact gross margin. +11 +An adverse change in the interest rates for our borrowings could adversely affect our financial condition. +We are exposed to interest rate risk under our revolving line of credit and term loan. We currently hedge a portion of our term loan with an interest rate swap. We have not historically hedged the interest rate on our credit facility; therefore, unless we do so, significant changes in interest rates could adversely affect our results of operations. Refer to the discussion in note 4, "Long-Term Debt" to the consolidated financial statements for further details of our debt obligations. We are also exposed to interest rate risk on our factoring activities. +Compliance or the failure to comply with current and future environmental laws or regulations could cause us significant expense. +We are subject to a variety of domestic and foreign environmental regulations relating to the use, storage, and disposal of materials used in our manufacturing processes. If we fail to comply with any present or future regulations, we could be subject to future liabilities or the suspension of current manufacturing operations. In addition, such regulations could restrict our ability to expand our operations or could require us to acquire costly equipment, substitute materials, or incur other significant expenses to comply with government regulations. +Our stock price is volatile. +Holders of the common stock will suffer immediate dilution to the extent outstanding equity awards are exercised to purchase common stock. Our stock price may be subject to wide fluctuations and possible rapid increases or declines over a short time period. These fluctuations may be due to factors specific to us such as our stock's thinly traded nature, variations in quarterly operating results or changes in earnings estimates, or to factors relating to the EMS industry or to the securities markets in general, which, in recent years, have experienced significant price fluctuations. These fluctuations often have been unrelated to the operating performance of the specific companies whose stocks are traded. +Due to inherent limitations, there can be no assurance that our system of disclosure and internal controls and procedures will be successful in preventing all errors, theft and fraud, or in informing management of all material information in a timely manner. +Management does not expect that our disclosure controls and internal controls and procedures will prevent all errors or fraud. A control system is designed to give reasonable, but not absolute, assurance that the objectives of the control system are met. In addition, any control system reflects resource constraints and the benefits of controls must be considered relative to their costs. Inherent limitations of a control system may include: judgments in decision making may be faulty, breakdowns can occur simply because of error or mistake and controls can be circumvented by collusion or management override. Due to the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and may not be detected. +If we do not manage our growth effectively, our profitability could decline. +Our business is experiencing growth which can place considerable additional demands upon our management team and our operational, financial and management information systems. Our ability to manage growth effectively requires us to continue to implement and improve these systems; avoid cost overruns; maintain customer, supplier and other favorable business relationships during possible transition periods; continue to develop the management skills of our managers and supervisors; and continue to train, motivate and manage our employees. Our failure to effectively manage growth could have a material adverse effect on our results of operations. +12 +If our manufacturing processes and services do not comply with applicable statutory and regulatory requirements, or if we manufacture products containing design or manufacturing defects, demand for our services may decline and we may be subject to liability claims. +We manufacture and design products to our customers’ specifications, and, in some cases, our manufacturing processes and facilities may need to comply with applicable statutory and regulatory requirements. For example, medical devices that we manufacture or design, as well as the facilities and manufacturing processes that we use to produce them, are regulated by the Food and Drug Administration and non-U.S. counterparts of this agency. In addition, our customers’ products and the manufacturing processes that we use to produce them often are highly complex. As a result, products that we manufacture may at times contain manufacturing or design defects, and our manufacturing processes may be subject to errors or not be in compliance with applicable statutory and regulatory requirements. Defects in the products we manufacture or design, whether caused by a design, manufacturing or component failure or error, or deficiencies in our manufacturing processes, may result in delayed shipments to customers or reduced or canceled customer orders. If these defects or deficiencies are significant, our business reputation may also be damaged. The failure of the products that we manufacture or our manufacturing processes and facilities to comply with applicable statutory and regulatory requirements may subject us to legal fines or penalties and, in some cases, require us to shut down or incur considerable expense to correct a manufacturing process or facility. Our customers are required to indemnify us against liability associated with designing products to meet their specifications. However, if our customers are responsible for the defects, they may not, or may not have resources to, assume responsibility for any costs or liabilities arising from these defects, which could expose us to additional liability claims. +Energy price increases may negatively impact our results of operations. +Certain components that we use in our manufacturing process are petroleum-based. In addition, we, along with our suppliers and customers, rely on various energy sources in our transportation activities. While significant uncertainty currently exists about the future levels of energy prices, a significant increase is possible. Increased energy prices could cause an increase to our raw material costs and transportation costs. In addition, increased transportation costs of certain of our suppliers and customers could be passed along to us. We may not be able to increase our product prices enough to offset these increased costs. In addition, any increase in our product prices may reduce our future customer orders and profitability. +Disruptions to our information systems, including security breaches, losses of data or outages, could adversely affect our operations. +We rely on information technology networks and systems to process, transmit and store electronic information. In particular, we depend on our information technology infrastructure for a variety of functions, including worldwide financial reporting, inventory management, procurement, invoicing and email communications. Any of these systems may be susceptible to outages due to fire, floods, power loss, telecommunications failures, terrorist attacks and similar events. Despite the implementation of network security measures, our systems and those of third parties on which we rely may also be vulnerable to computer viruses, break-ins and similar disruptions. If we or our vendors are unable to prevent such outages and breaches, our operations could be disrupted. +We are involved in various legal proceedings. +In the past, we have been notified of claims relating to various matters including contractual matters, intellectual property rights or other issues arising in the ordinary course of business. In the event of such a claim, we may be required to spend a significant amount of money to defend or otherwise address the claim. The Company is currently involved in an arbitration claim with a former customer to collect a significant payment for excess inventory purchased to an existing manufacturing agreement in place at the time. Any litigation or dispute resolution, even where a claim is without merit, could result in substantial costs and diversion of resources. Accordingly, the resolution or adjudication of such disputes, even those encountered in the ordinary course of business, could have a material adverse effect on our business, consolidated financial conditions and results of operations. +Our levels of insurance coverage may not be sufficient for potential damages, claims or losses. +We have various forms of business and liability insurance which we believe are appropriate based on the needs of companies in our industry. As a result, not all of our potential business risks or potential losses would be covered by our insurance policies. If we sustain a significant claim or loss which is not covered by insurance, our net income could be negatively impacted. +13 +Changes in securities laws and regulations will increase our costs and risk of noncompliance. +We are required to file as an accelerated filer. As such, we are subject to additional requirements contained in the Sarbanes-Oxley Act of 2002 (the Sarbanes-Oxley Act) and more recently the Dodd-Frank Act. The Sarbanes-Oxley and Dodd-Frank Acts required or will require changes in some of our corporate governance, securities disclosure and compliance practices. In response to the requirements of the Sarbanes-Oxley and Dodd-Frank Acts, the SEC and NASDAQ promulgated new rules and additional rulemaking is expected in the future. Compliance with these new rules and future rules has increased and may increase further our legal, financial and accounting costs as well as a potential risk of noncompliance. Absent significant changes in related rules, which we cannot assure, we anticipate some level of increased costs related to these new regulations to continue indefinitely. We also expect these developments to make it more difficult and more expensive to obtain director and officer liability insurance, and we may be forced to accept reduced coverage or incur substantially higher costs to obtain coverage. Likewise, these developments may make it more difficult for us to attract and retain qualified members of our Board of Directors or qualified management personnel. Further, the costs associated with the compliance with and implementation of procedures under these and future laws and related rules could have a material impact on our results of operations. In addition, the costs associated with noncompliance with additional securities laws and regulations could also impact our business. +We may encounter complications with acquisitions, which could potentially harm our business. +Any current or future acquisitions may require additional equity financing, which could be dilutive to our existing shareholders, or additional debt financing, which could potentially affect our credit ratings. Any downgrades in our credit ratings associated with an acquisition could adversely affect our ability to borrow by resulting in more restrictive borrowing terms. To integrate acquired businesses, we must implement our management information systems, operating systems and internal controls, and assimilate and manage the personnel of the acquired operations. The integration of acquired businesses may be further complicated by difficulties managing operations in geographically dispersed locations. The integration of acquired businesses may not be successful and could result in disruption by diverting management’s attention from the core business. In addition, the integration of acquired businesses may require that we incur significant restructuring charges or other increases in our expenses and working capital requirements, which reduce our return on invested capital. +Acquisitions may involve numerous other risks and challenges including but not limited to: potential loss of key employees and customers of the acquired companies; the potential for deficiencies in internal controls at acquired companies; lack of experience operating in the geographic market or industry sector of the acquired business; constraints on available liquidity, and exposure to unanticipated liabilities of acquired companies. These and other factors could harm our ability to achieve anticipated levels of profitability at acquired operations or realize other anticipated benefits of an acquisition, and could adversely affect our consolidated business and operating results. +Our goodwill and identifiable intangible assets could become impaired, which could reduce the value of our assets and reduce net income in the year in which the write-off occurs. +Goodwill represents the excess of the cost of an acquisition over the fair value of the net assets acquired. The Company also ascribes value to certain identifiable intangible assets, which consists of customer relationships, non-compete agreements, and favorable leases, as a result of the acquisitions of Sabre and Ayrshire. The Company may incur impairment charges on goodwill or identifiable intangible assets if it determines that the fair values of goodwill or identifiable intangible assets are less than their current carrying values. The Company evaluates, on a regular basis, whether events or circumstances have occurred that indicate all, or a portion, of the carrying amount of goodwill may no longer be recoverable, in which case an impairment charge to earnings would become necessary. +Refer to Notes 1 and 15 to the consolidated financial statements and critical accounting policies and estimates' in management’s discussion and analysis of financial condition and results of operations for further discussion regarding the impairment testing of goodwill and identifiable intangible assets. +A decline in general economic conditions or global equity valuations could impact the judgments and assumptions about the fair value of the Company’s businesses and the Company could be required to record impairment charges on its goodwill or other identifiable intangible assets in the future, which could impact the Company’s consolidated balance sheet, as well as the Company’s consolidated statement of operations. If the Company was required to recognize an impairment charge in the future, the charge would not impact the Company's consolidated cash flows, current liquidity, capital resources, and covenants under its existing credit facilities. +14 +Changes in financial accounting standards may affect our reported financial condition or results of operations as well increase costs related to implementation of new standards and modifications to internal controls. +Our consolidated financial statements are prepared in conformity with accounting standards generally accepted in the United States, or U.S. GAAP. These principles are subject to amendments made primarily by the Financial Accounting Standards Board (FASB) and the Securities and Exchange Commission (SEC). A change in those policies can have a significant effect on our reported results and may affect our reporting of transactions which are completed before a change is announced. For example, significant changes to revenue recognition rules will be effective for us in fiscal 2019 and we may incur significant costs to implement this new rule. Changes to accounting rules or challenges to our interpretation or application of the rules by regulators may have a material adverse effect on our reported financial results or on the way we conduct business. In addition, the continued convergence of U.S. GAAP and International Financial Reporting Standards ("IFRS") creates uncertainty as to the financial accounting policies and practices we will need to adopt in the future. +Item 1B. +UNRESOLVED STAFF COMMENTS +None +Item 2. +PROPERTIES AS OF DATE OF FILING +We have manufacturing and sales operations located in the United States, Mexico, and China. The table below lists the locations and square footage of our operating facilities: +Location +Approx. +Sq. Ft. +Type of Interest +(Leased/Owned) +Description of Use +Corinth, Mississippi +350,000 +Leased +Manufacturing and warehouse +El Paso, Texas +80,000 +Leased +Shipping and warehouse +Fayetteville, Arkansas +175,000 +Leased +Manufacturing and warehouse +Harrodsburg, Kentucky (1) +22,000 +Owned +Manufacturing and warehouse +Louisville, Kentucky +2,000 +Leased +Administration +Oakdale, Minnesota +60,000 +Leased +Manufacturing and warehouse +Spokane Valley, Washington +95,000 +Leased +Sales, research, administration and manufacturing +Spokane Valley, Washington +36,000 +Leased +Manufacturing +Total USA +820,000 +Juarez, Mexico +193,000 +Leased +Warehouse +Juarez, Mexico +174,000 +Owned +Manufacturing +Juarez, Mexico +115,000 +Owned +Manufacturing and warehouse +Juarez, Mexico +103,000 +Owned +Manufacturing and warehouse +Juarez, Mexico +72,000 +Leased +Manufacturing +Juarez, Mexico +66,000 +Owned +Manufacturing and warehouse +Juarez, Mexico +60,000 +Owned +Manufacturing and warehouse +Total Mexico +783,000 +Shanghai, China +121,000 +Leased +Manufacturing and warehouse +Shanghai, China +36,000 +Leased +Manufacturing +Total China +157,000 +Grand Total +1,760,000 +(1) +During fiscal year 2017, we closed the Harrodsburg, Kentucky location and transferred customer programs to other facilities in the USA. The facility is currently listed for sale. Additionally, the property is not yet actively marketed and sale of the building in less than one year is not probable at this time. As such, the property is appropriately being reported in Property, Plant, and Equipment. +The geographic diversity of these locations allows us to offer services near certain of our customers and major electronics markets with the additional benefit of reduced labor costs. We consider the productive capacity of our current facilities sufficient to carry on our current business. In addition, in Juarez, Mexico one of our buildings includes adjacent vacant land that could be developed into additional manufacturing and warehouse space. +15 +All of our facilities are ISO certified to ISO 9001:2008 standard and to Customs Trade Partnership against Terrorism (CTPAT). In addition, the Juarez, Mexico; Shanghai, China and Spokane, Washington facilities are registered/certified to ISO/TS 16949 automotive standard, AS 9100C aviation, space and defense standard, ISO 13485 medical devices, ISO 14001 environmental standard, ANSI/ESD S20.20-2007 Electrostatic Discharge Control Program, OHSAS 18001 Occupational Health and Safety standard, and SA8000 / ISO 2600 social accountability standard. Oakdale, Minnesota is additionally registered to ISO-13485:2003 medical devices standard, AS9100C aviation, space and defense standard, and NADCAP certified. The Spokane, Washington and Juarez, Mexico facilities are additionally registered to ISO/IEC 80079-34 explosive atmospheres. Additionally, Juarez, Mexico is registered by the NSF for water products. The Oakdale, Minnesota; Corinth, Mississippi; Fayetteville, Arkansas and Spokane, Washington facilities are all registered by the U.S. State Department for International Traffic in Arms Regulations (ITAR). +Item 3. +LEGAL PROCEEDINGS +We are a party to certain lawsuits or claims in the ordinary course of business. We do not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on our financial position, results of operations or cash flow. Refer to Commitment and Contingencies footnote for further details on litigation in the fiscal year. +Item 4. +MINE SAFETY DISCLOSURES +Not Applicable +PART II +Item 5: +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES +Market Information +Our common stock is traded on the NASDAQ Global Market, formerly the NASDAQ National Market System under the symbol “KTCC.” Quarterly high and low sales prices for our common stock for fiscal years 2017 and 2016 were as follows: +2017 +2016 +High +Low +High +Low +First Quarter +$ +8.28 +$ +7.23 +$ +11.15 +$ +9.75 +Second Quarter +8.18 +7.08 +10.39 +7.50 +Third Quarter +8.20 +7.08 +8.47 +6.09 +Fourth Quarter +8.00 +6.69 +8.97 +6.99 +High and low stock prices are based on the daily sales prices reported by the NASDAQ Stock Market. These quotations represent prices between dealers without adjustment for markups, markdowns, and commissions, and may not represent actual transactions. +Holders and Dividends +As of July 1, 2017 , we had 688 shareholders of common stock on record. As a result of our credit agreement with Wells Fargo Bank, N.A. we are restricted from declaring or paying dividends in cash or stock without the Bank’s prior written consent. We have not paid a cash dividend and do not anticipate payment of dividends in the foreseeable future. +Equity Compensation Plan Information +Information concerning securities authorized for issuance under our equity compensation plans is set forth in Part III, Item 12 of this Annual Report, under the caption “Securities Authorized for Issuance under Equity Compensation Plans”, and that information is incorporated herein by reference. +16 +Performance Graph +Set forth below is a line graph comparing the cumulative total shareholder return on our common stock with the cumulative total return of the NASDAQ Stock Market (U.S. & Foreign) Index and the NASDAQ Electronic Components Index in fiscal 2017 . +6/30/2012 +6/29/2013 +6/28/2014 +6/27/2015 +7/2/2016 +7/1/2017 +Key Tronic Corporation +100.00 +125.61 +130.22 +129.37 +89.68 +86.04 +NASDAQ Composite +100.00 +117.69 +155.50 +177.19 +173.36 +221.11 +NASDAQ Electronic Components +100.00 +108.97 +149.17 +164.19 +178.10 +251.18 +17 +Item 6: +SELECTED FINANCIAL DATA +The following selected data is derived from our audited consolidated financial statements and should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the consolidated financial statements and related notes, and other information included in this report. +Financial Highlights +(In thousands, except for Supplemental Data and Per Share Amounts) +Fiscal Year Ended +July 1, 2017 +July 2, 2016 +June 27, 2015 (3) +June 28, 2014 (3) +June 29, 2013 +Consolidated Statements of Operations Data : +Net sales +$ +467,797 +$ +484,965 +$ +433,997 +$ +305,394 +$ +361,033 +Gross profit +38,300 +38,825 +33,305 +26,854 +34,512 +Gross margin percentage +8.2 +% +8.0 +% +7.7 +% +8.8 +% +9.6 +% +Operating income +9,544 +10,416 +6,653 +9,304 +18,126 +Operating margin percentage +2.0 +% +2.1 +% +1.5 +% +3.0 +% +5.0 +% +Net income +5,617 +6,533 +4,304 +7,613 +12,583 +Earnings per share – diluted +0.51 +0.58 +0.38 +0.67 +1.12 +Consolidated Cash Flow Data : +Cash flows provided by operations +9,425 +4,580 +7,667 +1,458 +29,282 +Capital expenditures +9,307 +13,277 +8,808 +7,763 +3,470 +Consolidated Balance Sheet Data : +Net working capital (1) +100,440 +97,349 +98,318 +71,049 +73,827 +Total assets +232,840 +235,924 +230,794 +156,660 +135,130 +Long-term liabilities +38,520 +46,232 +43,237 +848 +3,030 +Shareholders’ equity +116,567 +105,582 +100,768 +103,645 +94,160 +Book value per share (2) +$ +10.83 +$ +9.84 +$ +9.42 +$ +9.83 +$ +8.97 +Supplemental Data : +Number of shares outstanding at year-end +10,759,680 +10,725,349 +10,706,136 +10,546,750 +10,502,188 +Number of employees at year-end +5,038 +4,947 +4,866 +3,343 +2,584 +Approximate square footage of operational facilities +1,760,000 +1,828,000 +1,892,000 +1,139,000 +1,011,000 +(1) +Net working capital is defined as total current assets less total current liabilities. Net working capital measures the portion of current assets that are financed by long term funds and is an indicator of short term financial management. +(2) +Book value per share is defined as total shareholders’ equity divided by the number of shares outstanding at the end of the fiscal year. +(3) +Reflects the acquisition of Ayrshire on September 3, 2014 in fiscal year 2015 and Sabre on July 1, 2013 in fiscal year 2014. +18 +Item 7: +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +Overview +KeyTronicEMS is a leader in electronic manufacturing services and solutions to original equipment manufacturers of a broad range of products. We provide engineering services, worldwide procurement and distribution, materials management, world-class manufacturing and assembly services, in-house testing, and unparalleled customer service. Our international production capability provides our customers with benefits of improved supply-chain management, reduced inventories, lower transportation costs, and reduced product fulfillment time. We continue to make investments in all of our operating facilities to give us the production capacity, capabilities and logistical advantages to continue to win new business. The following information should be read in conjunction with the consolidated financial statements included herein and with Item 1A, Risk Factors included as part of this filing. +Our mission is to provide our customers with superior manufacturing and engineering services at the lowest total cost for the highest quality products, and create long-term mutually beneficial business relationships by employing our “Trust, Commitment, Results” philosophy. +Executive Summary +During fiscal 2017, our revenue and margins were impacted by declining demand from some longstanding customers, which was not yet offset by the continued ramp in revenue from our new programs. While the EMS business is very competitive, we continued to win new business during the year, including two new programs involving gaming and seismic monitoring devices awarded in the fourth quarter, bringing the total number of significant program wins to nine for the fiscal year. +Net sales of $467.8 million for fiscal year 2017 decreased by 3.5 percent as compared to net sales of $485.0 million in fiscal year 2016 . The decrease in net sales was primarily driven by a decrease in net sales from the former longstanding customer and closure of our Harrodsburg, Kentucky facility which has been discussed in prior quarters, partially offset by an increase in new program wins. +Throughout fiscal 2017, we made significant investments in improving our customer support organization and expanding our SMT, sheet metal and plastic molding capabilities in preparation for future growth. Moving into fiscal 2018, we continue to see a strong pipeline of potential new business and our new programs continue to ramp. We believe we’re well positioned to see growth in revenue and increasing profitability in the second half of the year +For the first quarter of fiscal year 2018 , the Company expects to report revenue in the range of $110 million to $115 million. Future results will depend on actual levels of customers’ orders, the timing of the start-up of production of new product programs and the potential impact of the geopolitical uncertainty. We believe that we are well positioned in the EMS industry to continue expansion of our customer base and continue long-term growth. +We continue to diversify our customer base by adding additional programs and customers. Our current customer relationships involve a variety of products, including consumer electronics, electronic storage devices, plastics, household products, gaming devices, specialty printers, telecommunications, industrial equipment, military supplies, computer accessories, medical, educational, irrigation, automotive, transportation management, robotics, RFID, power supply, off-road vehicle equipment, fitness equipment, HVAC controls, consumer products, home building products, material handling systems and lighting equipment. +Gross profit as a percent of net sales was 8.2 percent in fiscal year 2017 compared to 8.0 percent for the prior fiscal year. The increase in gross profit as a percentage of net sales was primarily related to a decrease in material related costs partially offset by an increase in certain overhead costs. The level of gross margin is impacted by product mix, timing of the startup of new programs, facility utilization, pricing within the electronics industry and material costs, which can fluctuate significantly from quarter to quarter and year to year. +Operating income as a percentage of net sales for fiscal year 2017 was 2.0 percent compared to 2.1 percent for fiscal year 2016 . The decrease in operating income as a percentage of net sales was primarily due to an increase in selling, general and administrative expenses. This increase in SG&A expenses is primarily related to an increase in legal fees. +Net income for fiscal year 2017 was $5.6 million or $0.51 per diluted share, as compared to net income of $6.5 million or $0.58 per diluted share for fiscal year 2016 . The decrease in net income for fiscal year 2017 as compared to fiscal year 2016 was primarily driven by the decrease in net revenue as described above. +19 +We maintain a strong balance sheet with a current ratio of 2.3 and a debt to equity ratio of 0.37 . Total cash provided by operating activities as defined on our cash flow statement was $9.4 million during fiscal year 2017 . We maintain sufficient liquidity for our expected future operations. As of July 1, 2017 , we had $18.3 million outstanding on our revolving line of credit with Wells Fargo Bank, N.A. As a result, $26.3 million remained available to borrow as of July 1, 2017 . We believe cash flow from operations, our borrowing capacity, our accounts receivable sale program, and equipment financing should provide adequate capital for planned growth over the long term. +RESULTS OF OPERATIONS +Comparison of the Fiscal Year Ended July 1, 2017 with the Fiscal Year Ended July 2, 2016 +The following table sets forth for the periods indicated certain items of the consolidated statements of income expressed as a percentage of net sales. The financial information and discussion below should be read in conjunction with the consolidated financial statements and notes contained in this Annual Report. +Fiscal Year Ended +July 1, 2017 +% of +net sales +July 2, 2016 +% of +net sales +$ change +% point +change +Net sales +$ +467,797 +100.0% +$ +484,965 +100.0% +$ +(17,168 +) +— +Cost of sales +429,497 +91.8 +446,140 +92.0 +(16,643 +) +(0.2) +Gross profit +38,300 +8.2 +38,825 +8.0 +(525 +) +0.2 +Operating expenses: +Research, development and engineering +6,393 +1.4 +6,397 +1.3 +(4 +) +0.1 +Selling, general and administrative +22,363 +4.8 +22,012 +4.5 +351 +0.3 +Total operating expenses +28,756 +6.2 +28,409 +5.8 +347 +0.4 +Operating income +9,544 +2.0 +10,416 +2.1 +(872 +) +(0.1) +Interest expense, net +2,288 +0.4 +2,265 +0.5 +23 +(0.1) +Income before income taxes +7,256 +1.6 +8,151 +1.7 +(895 +) +(0.1) +Income tax provision +1,639 +0.4 +1,618 +0.3 +21 +0.1 +Net income +$ +5,617 +1.2% +$ +6,533 +1.3% +$ +(916 +) +(0.1) +Effective income tax rate +22.6 +% +19.9 +% +Net Sales +The decrease in net sales of $17.2 million from prior year was primarily driven by a decrease in net sales from the former longstanding customer which has been discussed in prior quarters, partially offset by an increase in new program wins. +The following table shows the revenue by industry sectors as a percentage of revenue for fiscal years 2017 and 2016 : +Fiscal Year Ended +July 1, 2017 +July 2, 2016 +Industrial +40% +39% +Consumer +35 +31 +Gaming +9 +7 +Communication +8 +13 +Printers +5 +6 +Computer and Peripheral +2 +1 +Transportation +1 +3 +Total +100% +100% +We provide services to customers in a number of industries and produce a variety of products for our customers in each industry. Key Tronic does not target any particular industry, but rather seeks to find programs that strategically fit our vertical manufacturing capabilities. As we continue to diversify our customer base and win new customers, we will continue to see a change in the industry concentrations of our revenue. +Sales to foreign locations represented 22.6 percent and 28.3 percent of our total net sales in fiscal years 2017 and 2016 , respectively. +20 +Cost of Sales +Total cost of sales as a percentage of net sales was 91.8 percent and 92.0 percent in fiscal years 2017 and 2016 , respectively. +Total cost of materials as a percentage of net sales was approximately 61.7 percent and 63.9 percent in fiscal years 2017 and 2016 , respectively. The change from year-to-year is primarily a result of improved pricing of certain raw materials as well as a more favorable product mix. +Production and support costs as a percentage of net sales were 30.1 percent and 28.1 percent in fiscal years 2017 and 2016 , respectively. The increase in fiscal year 2017 is primarily related absorption increasing as a percentage of sales during the fiscal year. +We provide a reserve for obsolete and non-saleable inventories based on specific identification of inventory against current demand and recent usage. We also consider our customers' ability to pay for inventory whether or not there is a lead-time assurance agreement for a specific program. The amounts charged to expense for these inventories were approximately $0.5 million and $0.8 million in fiscal years 2017 and 2016 , respectively. +We provide warranties on certain products we sell and estimate warranty costs based on historical experience and anticipated product returns. Warranty expense is related to workmanship claims on keyboards and EMS products. The amounts charged to expense are determined based on an estimate of warranty exposure. The net warranty expense was approximately $68,000 and $95,000 in fiscal years 2017 and 2016 , respectively. +Gross Profit +Gross profit as a percentage of net sales was 8.2 percent and 8.0 percent in fiscal years 2017 , and 2016 , respectively. The 0.2 percentage point increase in gross profit as a percentage of net sales during fiscal year 2017 as compared to fiscal year 2016 is primarily related to a 1.7 percentage point decrease in material related costs partially offset by a 1.5 percentage point increase in certain overhead costs. This reflects an increase in gross margin percentage year-over-year as the unprofitable manufacturing facility was closed and trimming non-profitable programs. +Changes in gross profit margins reflect the impact of a number of factors that can vary from period to period, including product mix, start-up costs and efficiencies associated with new programs, product life cycles, sales volumes, capacity utilization of our resources, management of inventories, component pricing and shortages, end market demand for customers’ products, fluctuations in and timing of customer orders, and competition within the EMS industry. These and other factors can cause variations in operating results. There can be no assurance that gross margins will not decrease in future periods. +We took early pay discounts to suppliers that totaled approximately $1.9 million and $1.9 million in fiscal years 2017 and 2016 , respectively. Early pay discounts will fluctuate based on our liquidity and changes in the discounts and terms offered by our suppliers. +Research, Development and Engineering +Research, development and engineering expenses (RD&E) consists principally of employee related costs, third party development costs, program materials, depreciation and allocated information technology and facilities costs. Total RD&E expenses were $6.4 million in fiscal years 2017 and 2016 . Total RD&E expenses as a percent of net sales were 1.4 percent and 1.3 percent in fiscal years 2017 and 2016 , respectively. +Selling, General and Administrative +Selling, general and administrative expenses (SG&A) consist principally of salaries and benefits, advertising and marketing programs, sales commissions, travel expenses, provision for doubtful accounts, facilities costs, and professional services. Total SG&A expenses were $22.4 million and $22.0 million in fiscal years 2017 and 2016 , respectively. Total SG&A expenses as a percent of net sales were 4.8 percent and 4.5 percent in fiscal years 2017 and 2016 , respectively. This 0.3 percentage point increase in SG&A as a percentage of net sales is primarily related to an increase in legal fees. +Interest Expense +We had net interest expense of $2.3 million in both fiscal years 2017 and 2016 . +Income Tax Provision +We had an income tax expense of approximately $1.6 million during both fiscal years 2017 and 2016 . The income tax expense recognized during both fiscal years 2017 and 2016 , was primarily a function of U.S., federal, state and foreign taxes recognized at the statutory rates offset by the net benefit associated with federal research and development tax credits and changes in potential foreign tax credits. +21 +We continually review our requirements for liquidity domestically to fund current operations, revenue growth and to look for potential future acquisitions. We anticipate repatriating a portion of our unremitted foreign earnings. The estimated taxes and associated foreign tax credits are included in the income tax calculation. For further information on taxes please review footnote 6 of the “Notes to Consolidated Financial Statements.” +International Subsidiaries +We offer customers a complete global manufacturing solution. Our facilities provide our customers the opportunity to have their products manufactured in the facility that best serves specific cost, product manufacturing and distribution needs. The locations of active foreign subsidiaries are as follows: +• +Key Tronic Juarez, SA de CV owns five facilities and leases two facilities in Juarez, Mexico. These facilities include an SMT facility, an assembly and molding facility, a sheet metal fabrication facility, and assembly and storage facilities. This subsidiary is primarily used to support our U.S. operations. +• +Key Tronic Computer Peripherals (Shanghai) Co., Ltd. leases two facilities with SMT, assembly, global purchasing and warehouse capabilities in Shanghai, China, which began operations in 1999. Its primary function is to provide EMS services for export. +Foreign sales (based on shipping instructions) from our worldwide operations, including domestic exports, were $105.9 million and $137.4 million in fiscal years 2017 and 2016 , respectively. Products and manufacturing services provided by our subsidiary operations are often shipped to customers directly by the parent company. +RESULTS OF OPERATIONS +Comparison of the Fiscal Year Ended July 2, 2016 with the Fiscal Year Ended June 27, 2015 +The following table sets forth for the periods indicated certain items of the consolidated statements of income expressed as a percentage of net sales. The financial information and discussion below should be read in conjunction with the consolidated financial statements and notes contained in this Annual Report. +Fiscal Year Ended +July 2, 2016 +% of +net sales +June 27, 2015 +% of +net sales +$ change +% point +change +Net sales +$ +484,965 +100.0% +$ +433,997 +100.0% +$ +50,968 +— +Cost of sales +446,140 +92.0 +400,692 +92.3 +45,448 +(0.3) +Gross profit +38,825 +8.0 +33,305 +7.7 +5,520 +0.3 +Operating expenses: +Research, development and engineering +6,397 +1.3 +5,784 +1.3 +613 +— +Selling, general and administrative +22,012 +4.5 +20,868 +4.8 +1,144 +(0.3) +Total operating expenses +28,409 +5.8 +26,652 +6.1 +1,757 +(0.3) +Operating income +10,416 +2.1 +6,653 +1.5 +3,763 +0.6 +Interest expense, net +2,265 +0.5 +1,353 +0.3 +912 +0.2 +Income before income taxes +8,151 +1.7 +5,300 +1.2 +2,851 +0.5 +Income tax provision +1,618 +0.3 +996 +0.2 +622 +0.1 +Net income +$ +6,533 +1.3% +$ +4,304 +1.0% +$ +2,229 +0.3 +Effective income tax rate +19.9 +% +18.8 +% +Net Sales +The increase in net sales of $51.0 million from prior year was primarily driven by new program wins and to a lesser degree an increase in demand from current customers and the inclusion of Ayrshire for a full year of operations. +22 +The following table shows the revenue by industry sectors as a percentage of revenue for fiscal years 2016 and 2015: +Fiscal Year Ended +July 2, 2016 +June 27, 2015 +Industrial +39% +34% +Consumer +31 +28 +Communication +13 +16 +Gaming +7 +6 +Printers +6 +6 +Transportation +3 +8 +Computer and Peripheral +1 +2 +Total +100% +100% +We provide services to customers in a number of industries and produce a variety of products for our customers in each industry. As we continue to diversify our customer base and win new customers we may continue to see a change in the industry concentrations of our revenue. +Sales to foreign locations represented 28.3 percent and 30.4 percent of our total net sales in fiscal years 2016 and 2015, respectively. +Cost of Sales +Total cost of sales as a percentage of net sales was 92.0 percent and 92.3 percent in fiscal years 2016 and 2015, respectively. +Total cost of materials as a percentage of net sales was approximately 63.9 percent and 64.6 percent in fiscal years 2016 and 2015, respectively. The change from year-to-year is primarily a result of improved pricing of certain raw materials as well as a more favorable product mix. +Production and support costs as a percentage of net sales were 28.1 percent and 27.7 percent in fiscal years 2016 and 2015, respectively. The increase in fiscal year 2016 is primarily related to inefficiencies associated with ramping production of new products that resulted in higher than expected operating expenses during the first half of fiscal year 2016. +We provide a reserve for obsolete and non-saleable inventories based on specific identification of inventory against current demand and recent usage. We also consider our customers' ability to pay for inventory whether or not there is a lead-time assurance agreement for a specific program. The amounts charged to expense for these inventories were approximately $0.8 million and $0.5 million in fiscal years 2016 and 2015, respectively. +We provide warranties on certain products we sell and estimate warranty costs based on historical experience and anticipated product returns. Warranty expense is related to workmanship claims on keyboards and EMS products. The amounts charged to expense are determined based on an estimate of warranty exposure. The net warranty expense was approximately $95,000 and $115,000 in fiscal years 2016 and 2015, respectively. +Gross Profit +Gross profit as a percentage of net sales was 8.0 percent and 7.7 percent in fiscal years 2016, and 2015, respectively. The 0.3 percentage point increase in gross profit as a percentage of net sales during fiscal year 2016 as compared to fiscal year 2015 is primarily related to a 1.2 percentage point decrease in material related costs partially offset by a 0.9 percentage point increase in certain overhead costs. +Changes in gross profit margins reflect the impact of a number of factors that can vary from period to period, including product mix, start-up costs and efficiencies associated with new programs, product life cycles, sales volumes, capacity utilization of our resources, management of inventories, component pricing and shortages, end market demand for customers’ products, fluctuations in and timing of customer orders, and competition within the EMS industry. These and other factors can cause variations in operating results. There can be no assurance that gross margins will not decrease in future periods. +We took early pay discounts to suppliers that totaled approximately $1.9 million and $1.5 million in fiscal years 2016 and 2015, respectively. Early pay discounts will fluctuate based on our liquidity and changes in the discounts and terms offered by our suppliers. +Research, Development and Engineering +Research, development and engineering expenses (RD&E) consists principally of employee related costs, third party development costs, program materials, depreciation and allocated information technology and facilities costs. Total RD&E expenses were $6.4 million and $5.8 million in fiscal years 2016 and 2015, respectively. Total RD&E expenses as a percent of net sales were 1.3 percent in fiscal years 2016 and 2015, respectively. +23 +Selling, General and Administrative +Selling, general and administrative expenses (SG&A) consist principally of salaries and benefits, advertising and marketing programs, sales commissions, travel expenses, provision for doubtful accounts, facilities costs, and professional services. Total SG&A expenses were $22.0 million and $20.9 million in fiscal years 2016 and 2015, respectively. Total SG&A expenses as a percent of net sales were 4.5 percent and 4.8 percent in fiscal years 2016 and 2015, respectively. This 0.3 percentage point decrease in SG&A as a percentage of net sales is primarily related to approximately $0.8 million of non-recurring closing costs associated with the Ayrshire acquisition incurred during fiscal year 2015. +Interest Expense +We had net interest expense of $2.3 million and $1.4 million in fiscal years 2016 and 2015, respectively. The increase in interest expense is primarily related to the inclusion of a full year of the term loan balance outstanding and an increase in the average balance outstanding on our line of credit which was primarily used to fund growth in operations. +Income Tax Provision +We had an income tax expense of $1.6 million during fiscal year 2016 as compared to an income tax expense of $1.0 million in fiscal year 2015. The income tax expense recognized during both fiscal years 2016 and 2015, was primarily a function of U.S., federal, state and foreign taxes recognized at the statutory rates offset by the net benefit associated with federal research and development tax credits and changes in potential foreign tax credits. +We continually review our requirements for liquidity domestically to fund current operations, revenue growth and to look for potential future acquisitions. We anticipate repatriating a portion of our unremitted foreign earnings. The estimated taxes and associated foreign tax credits are included in the income tax calculation. For further information on taxes please review footnote 6 of the “Notes to Consolidated Financial Statements.” +Capital Resources and Liquidity +Operating Cash Flow +Net cash provided by operating activities for fiscal year 2017 was $9.4 million compared to net cash provided by operating activities of $4.6 million and $7.7 million in fiscal years 2016 and 2015 , respectively. +The $9.4 million of net cash provided by operating activities during fiscal year 2017 is primarily related to $5.6 million of net income, $7.2 million of depreciation and amortization and a $4.9 million decrease in inventory, partially offset by a $3.5 million increase in accounts receivable and a $5.9 million decrease in accounts payable. The $4.6 million of net cash provided by operating activities during fiscal year 2016 was primarily due to $6.5 million of net income, $6.2 million of depreciation and amortization and an $11.1 million decrease in accounts receivable offset by a $16.2 million increase in inventory and a $2.6 million decrease in accounts payable. The $7.7 million of cash provided by operating activities during fiscal year 2015 was primarily due to $4.3 million of net income, $5.9 million of depreciation and amortization and an $18.0 million increase in accounts payable partially offset by a $14.7 million increase in inventory, a $2.1 million increase in accounts receivable and a $4.2 million increase in other assets. +Accounts receivable fluctuates based on the timing of shipments, terms offered and collections. In addition, accounts receivable will fluctuate based upon the amount of accounts receivable sold under our Trade Accounts Receivable Purchase Program. During fiscal years 2017, 2016 and 2015, we factored receivables of $86.5 million , $78.0 million and $12.1 million, respectively, from accounts receivable sold to financial institutions, which are not included on our Consolidated Balance Sheets. We purchase inventory based on customer forecasts and orders, and when those forecasts and orders change, the amount of inventory may also fluctuate. Accounts payable fluctuates with changes in inventory levels, volume of inventory purchases, negotiated supplier terms, and taking advantage of early pay discounts. +Investing Cash Flow +Cash flows used in investing activities were $8.5 million , $5.7 million , and $48.1 million in fiscal years 2017 , 2016 and 2015 , respectively. Our primary investing activity during fiscal year 2017 was purchasing equipment to support increased production levels for new programs. Our primary investing activities during fiscal year 2016 was the purchase of equipment to support increased production levels for new programs as well as the sale and leaseback of equipment. Our primary investing activities during fiscal year 2015 was the acquisitions of Ayrshire as discussed in further detail in footnote 14 of the “Notes to Consolidated Financial Statements.” +Operating and capital leases are often utilized when potential technical obsolescence and funding requirement advantages outweigh the benefits of equipment ownership. Capital expenditures and periodic lease payments are expected to be financed with internally generated funds and available borrowing capacities. During fiscal years 2017, 2016, and 2015, we received $0.6 million, $13.3 million, and $8.8 million of cash resulting from the sale and leaseback of equipment under operating leases, respectively. +24 +Financing Cash Flow +Cash flows used in financing activities were $1.6 million in fiscal year 2017 as compared to cash flows provided by financing activities of $1.7 million and $35.0 million in fiscal years 2016 and 2015 , respectively. Our primary financing activities during fiscal year 2017 was the funding of a $3.9 million equipment term loan, repayments on our term loans of $5.4 million as well as borrowings and repayments under our revolving line of credit facility. Our primary financing activities during fiscal year 2016 were repayments on our term loan of $5.0 million as well as borrowings and repayments under our revolving line of credit facility. Our primary financing activities during fiscal year 2015 were borrowings on our term loan of $31.3 million, net of repayments related to the Ayrshire acquisition, borrowings and repayments under our revolving line of credit facility and net repayments of $7.9 million related to the accounts receivable transfer program with Wells Fargo Bank N.A. +As of July 1, 2017 , the Company had an outstanding balance on the line of credit of $18.3 million . We had availability to borrow an additional $26.3 million under the Wells Fargo line of credit and we were in compliance with our loan covenants. Our cash requirements are affected by the level of current operations and new EMS programs. We believe that projected cash from operations, funds available under the revolving credit facility and fixed asset financing will be sufficient to meet our working and fixed capital requirements for the foreseeable future. +As of July 1, 2017 , we had approximately $0.4 million of cash held by foreign subsidiaries. If cash is to be repatriated in the future from these foreign subsidiaries, the Company could be subject to additional income taxes payable in the U.S. The total amount of U.S. taxes required to be paid for the amount of foreign subsidiary cash on hand as of July 1, 2017 would approximate $37,000. The Company also has approximately $28.4 million of foreign earnings that have not been repatriated to the U.S. Of that amount, the Company estimates that $13.4 million is to be repatriated in the future, requiring U.S. taxes of $1.4 million that is currently accrued in our deferred tax liabilities. The remaining $15.0 million is considered to be permanently reinvested in Mexico and China. If these amounts were required to be repatriated, we estimate it would create an additional $2.3 million in U.S. tax liability. +25 +Contractual Obligations and Commitments +In the normal course of business, we enter into contracts which obligate us to make payments in the future. The table below sets forth our significant future obligations by fiscal year: +Payments Due by Fiscal Year (in thousands) +Total +2018 +2019 +2020 +2021 +2022 +Thereafter +Term loans (1) +$ +24,733 +$ +5,871 +$ +5,871 +$ +12,120 +$ +871 +$ +— +$ +— +Wells Fargo Bank N.A. revolving loan (2) +$ +18,335 +$ +— +$ +— +$ +18,335 +$ +— +$ +— +$ +— +Operating leases (3) +$ +14,892 +$ +6,747 +$ +3,979 +$ +1,873 +$ +1,114 +$ +325 +$ +854 +Purchase orders (4) +(1) +The terms of the Wells Fargo Bank N.A. term loans are discussed in the consolidated financial statements at Note 4, “Long-Term Debt.” Principal on the term loan is payable in equal quarterly installments of $1.25 million through June 15, 2019, with final installment of all remaining unpaid principal due on August 31, 2019. The equipment term loan is payable in equal quarterly payments of approximately $0.2 million which commenced on March 31, 2017 and will continue through the maturity of the equipment term loan on June 30, 2021. +(2) +The terms of the Wells Fargo Bank N.A. revolving loan are discussed in the consolidated financial statements at Note 4, “Long-Term Debt.” As of July 1, 2017 , we were in compliance with our loan covenants. Breaching these covenants could have resulted in a material impact on our operations or financial condition and could impact our ability to borrow under this facility in the future. +(3) +We maintain vertically integrated manufacturing operations in the United States, Mexico and China. We lease some of our administrative and manufacturing facilities and equipment. A complete discussion of properties can be found in Part 1, Item 2 at “Properties.” Leases have proven to be an acceptable method for us to acquire new or replacement equipment and to maintain facilities with a minimum impact on our short term cash flows for operations. In addition, such operations are heavily dependent upon technically superior manufacturing equipment including molding machines in various tonnages, Surface Mount Technology (SMT) lines, sheet metal fabrication and stamping machines, clean rooms, and automated insertion, and test equipment for the various products we are capable of producing. +(4) +As of July 1, 2017 , we had open purchase order commitments for materials and other supplies of approximately $28.9 million. Included in the open purchase orders are various blanket orders for annual requirements. Actual needs under these blanket purchase orders fluctuate with our manufacturing levels and as such cannot be broken out between fiscal years. In addition, we have contracts with many of our customers that minimize our exposure to losses for material purchased within lead-times necessary to meet customer forecasts. Purchase orders generally can be cancelled without penalty within specified ranges that are determined in negotiations with our suppliers. These agreements depend in part on the type of materials purchased as well as the circumstances surrounding any requested cancellations. +In addition to the cash requirements presented above, we have various other accruals which are not included in the table above. For example, we owe our suppliers approximately $53.1 million for accounts payable and shipments in transit at the end of the fiscal year. We generally pay our suppliers in a range from 30 to 120 days depending on terms offered. These payments are financed by operating cash flows and our revolving line of credit. +We believe that cash flows generated from operations, factoring, leasing facilities, and funds available under the revolving credit facility will satisfy cash requirements for a period in excess of 12 months and into the foreseeable future. +26 +Critical Accounting Policies and Estimates +Preparation of our consolidated financial statements requires management to make estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses. Note 1 to our consolidated financial statements describes the significant accounting policies used in the preparation of our consolidated financial statements. Management believes the most complex and sensitive judgments, because of their significance to our consolidated financial statements, result primarily from the need to make estimates about effects of matters that are inherently uncertain. The most significant areas involving management judgments are described below. Actual results in these areas could differ from management’s estimates. +Revenue +Sales revenue from manufacturing is recognized upon shipment of the manufactured product per contractual terms. Upon shipment, title transfers and the customer assumes risks and rewards of ownership of the product. The price to the buyer is fixed or determinable and recoverability is reasonably assured. Unless specifically stated in contractual terms, there are no formal customer acceptance requirements or further obligations related to the manufacturing services; if any such requirements exist, then sales revenue is recognized at the time when such requirements are completed and such obligations are fulfilled. Revenue is recorded net of estimated returns of manufactured product based on management’s analysis of historical returns. +Revenues and associated costs from engineering design, development services and tooling, which are performed under contract of short term durations, are recognized only after the completed performance of the service. +Inactive, Obsolete, and Surplus Inventory Reserve +Inventories are stated at the lower of cost or net realizable value. Cost is determined principally using the first-in, first-out (FIFO) method. We reserve for inventories that we deem inactive, obsolete or surplus. This reserve is calculated based upon the demand for the products that we produce. Demand is determined by expected sales, customer purchase orders, or customer forecasts. If expected sales do not materialize, then we would have inventory in excess of our reserves and would have to charge the excess against future earnings. In the case where we have purchased material based upon a customer’s forecast or purchase orders, we are usually covered by lead-time assurance agreements or purchase orders with each customer. These contracts state that the financial liability for material purchased within agreed upon lead-time and based upon the customer’s forecasts, lies with the customer. If we purchase material outside the lead-time assurance agreement and the customer’s forecasts do not materialize or if we have no lead-time assurance agreement for a specific program, we would have the financial liability and may have to charge inactive, obsolete or surplus inventory against earnings. We also reserve for inventory related to specific customers covered by lead-time assurance agreements when those customers are experiencing financial difficulties or reimbursement is not reasonably assured. +Allowance for Doubtful Accounts +We value our accounts receivable net of an allowance for doubtful accounts. As of July 1, 2017 and July 2, 2016 , the allowance for doubtful accounts was approximately $0.1 million , respectively. This allowance is based on estimates of the portion of accounts receivable that may not be collected in the future. The estimates used are based primarily on specific identification of potentially uncollectible accounts. Such accounts are identified using publicly available information in conjunction with evaluations of current payment activity. However, if any of our customers were to develop unexpected and immediate financial problems that would prevent payment of open invoices, we could incur additional and possibly material expenses that would negatively impact earnings. +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. We review the adequacy of this accrual quarterly based on historical analysis and anticipated product returns and rework costs. Our warranty period for keyboards is generally longer than that for EMS products. We only warrant materials and workmanship on EMS products, and we do not warrant design defects for EMS customers. +Income Taxes +Income tax expense includes U.S. and international income taxes and the provision for U.S. taxes on undistributed earnings of foreign subsidiaries not deemed to be permanently invested. We do not record U.S. tax liabilities on undistributed earnings of international subsidiaries that are deemed to be permanently reinvested. Certain income and expenses are not reported in tax returns and financial statements in the same year. The tax effect of such temporary differences is reported as deferred income taxes. The deferred income taxes are classified as long-term assets or liabilities. The most significant areas involving management judgments include deferred income tax assets and liabilities, uncertain tax positions, and research and development tax credits. Our estimates of the realization of the deferred tax assets related to our tax credits are based upon our estimates of future taxable income which may change. +27 +Stock-Based Compensation +Stock-based compensation is accounted for according to Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 718, Compensation—Stock Compensation . ASC 718 requires us to expense the fair value of employee stock options, stock appreciation rights and other forms of stock-based compensation. Under the fair value recognition provisions of ASC 718, share-based compensation cost is estimated at the grant date based upon the fair value of the award and is recognized as expense ratably over the requisite service period of the award (generally the vesting period). Determining the appropriate fair value model and calculating the fair value of share-based awards requires judgment, including estimating the expected life of the share-based award, the expected stock price volatility over the expected life of the share-based award and forfeitures. +To determine the fair value of stock based awards on the date of grant we use the Black-Scholes option-pricing model. Inherent in this model are assumptions related to expected stock price volatility, option life, risk-free interest rate and dividend yield. The risk-free interest rate is a less-subjective assumption as it is based on factual data derived from public sources. We use a dividend yield of zero as we have never paid cash dividends and have no intention to pay cash dividends in the foreseeable future. The expected stock price volatility and option life assumptions require a greater level of judgment. Our expected stock-price volatility assumption is based upon the historical volatility of our stock which is obtained from public data sources. The expected life represents the weighted average period of time that share-based awards are expected to be outstanding, giving consideration to vesting schedules and historical exercise patterns. We determine the expected life assumption based upon the exercise and post-vesting behavior that has been exhibited historically, adjusted for specific factors that may influence future exercise patterns. If expected volatility or expected life were to increase, that would result in an increase in the fair value of our stock options which would result in higher compensation charges, while a decrease in volatility or the expected life would result in a lower fair value of our stock option awards resulting in lower compensation charges. +We estimate forfeitures for all of our awards based upon historical experience of stock-based pre-vesting forfeitures. We believe that our estimates are based upon outcomes that are reasonably likely to occur. If actual forfeitures are higher than our estimates it would result in lower compensation expense and to the extent the actual forfeitures are lower than our estimate we would record higher compensation expense. +Impairment of Long-Lived Assets +Long-lived assets, such as property, plant, and equipment are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment charge would be recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. +Derivatives and Hedging Activity +Derivatives are recognized on the balance sheet at their estimated fair value. On the date a derivative contract is entered into, the Company designates the derivative as a hedge of a forecasted transaction or of the variability of cash flows to be received or paid related to a recognized asset or liability (a “cash flow” hedge). The Company does not enter into derivatives for speculative purposes. Changes in the fair value of a derivative that qualifies as a cash flow hedge are recorded in “Accumulated Other Comprehensive Income,” until earnings are affected by the variability of cash flows. See Note 11 of the Company’s consolidated financial statements for additional information. +Long-Term Incentive Compensation Accrual +Long-term incentive compensation is recognized as expense ratably over the requisite service period of the award which is generally three years. The Board of Directors approve target performance measures for the three year period for each of the Company’s officers and non-employee Directors. Performance measures are based on a combination of sales growth targets and return on invested capital targets. No cash awards will be made to participants if actual Company performance does not exceed the minimum target performance measures. The calculation used to determine the necessary accrual uses a combination of actual results and projected results. We believe that our estimates are based upon outcomes that are reasonably likely to occur. These estimates and assumptions are based on historical results as well as future expectations. Actual results could vary from our estimates and assumptions. +28 +Impairment of Goodwill +In accordance with ASC 350, Goodwill and Other Intangible Assets , goodwill is not amortized but is required to be reviewed for impairment at least annually or when events or circumstances indicate that carrying value may exceed fair value. The Company is permitted the option to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the fair value of any reporting unit is less than its corresponding carrying value. If, after assessing the totality of events and circumstances, the Company concludes that it is not more likely than not that the fair value of any reporting unit is less than its corresponding carrying value then the Company is not required to take further action. However, if the Company concludes otherwise, then it is required to perform a quantitative impairment test, including computing the fair value of the reporting unit and comparing that value to its carrying value. The Company utilizes a weighting of the income approach and a market approach in the impairment test. We also consider valuation factors including the Company's market capitalization, future discounted cash flows and an estimated control premium based upon a review of comparable market transactions. Our consideration of discounted future cashflows included assumptions regarding growth rates and margins based on our historical trends. In addition, we applied a market discount rate calculated based upon an analysis of companies similar in size. If our future cash flows do not meet our projections or there is an event that impacts our market capitalization, the assumptions used in our goodwill analysis could be negatively impacted. The estimated fair value of the reporting unit exceeded the carrying value by approximately 20%. We will continue to monitor our market capitalization and impairment indicators. +If the fair value is less than its carrying value, a second step of the test is required to determine if recorded goodwill is impaired. In the event that goodwill is impaired, an impairment charge to earnings would become necessary. The Company also has the option to bypass the qualitative assessment for goodwill in any period and proceed directly to performing the quantitative impairment test. +Business Combinations +The Company recognizes the assets acquired and liabilities assumed in business combinations on the basis of their fair values at the date of acquisition. We assess the fair value of assets, including intangible assets, using a variety of methods and each asset is measured at fair value from the perspective of a market participant. The method used to estimate the fair values of intangible assets incorporates significant assumptions regarding the estimates a market participant would make in order to evaluate an asset, including a market participant’s use of the asset and the appropriate discount rates for a market participant. Assets recorded from the perspective of a market participant that are determined to not have economic use for us are expensed immediately. Any excess purchase price over the fair value of the net tangible and intangible assets acquired is allocated to goodwill. Transaction costs and restructuring costs associated with a business combination are expensed as incurred. +New and Future Accounting Pronouncements +See Note 1 to our consolidated financial statements. +Item 7A: +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Interest Rate Risk +We are subject to the risk of fluctuating interest rates in the normal course of business. Our major market risk relates to our secured debt. Our revolving credit facility and term loan are secured by substantially all of our assets. The interest rates applicable to our revolving credit facility and term loans fluctuate with the Wells Fargo Bank N.A. prime rate and LIBOR rates. There was outstanding $18.3 million in borrowings under our revolving credit facility and $24.6 million outstanding on our term loans as of July 1, 2017 . See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity” and Note 4 – “Long-Term Debt” to the Consolidated Financial Statements for additional information regarding our revolving credit facility and term loan. +Our only material interest rate risk is associated with our revolving credit facility and term loans. During the second quarter of fiscal year 2015, we entered into an interest rate swap contract with a notional amount of $25.0 million related to the borrowings outstanding under the term loan and revolving credit facility. As of July 1, 2017 , the remaining notional amount of the interest rate swap contract was $14.5 million. Through the use of the interest rate swap, as described above, we fixed the basis on which we pay interest, thus eliminating much of our interest rate risk. See Note 11 – “Derivative Financial Instruments” to the Consolidated Financial Statements for additional information regarding our derivative instruments. +29 +Foreign Currency Exchange Risk +A significant portion of our operations are in foreign locations. As a result, transactions occur in currencies other than the U.S. dollar. Exchange rate fluctuations among other currencies used by us would directly or indirectly affect our financial results. We currently use Mexican peso forward contracts to hedge foreign currency fluctuations for a portion of our Mexican peso denominated expenses. There was $55.7 million of foreign currency forward contracts outstanding as of July 1, 2017 . The fair value of these contracts was approximately $(4.1) million . See Note 11 – “Derivative Financial Instruments” to the Consolidated Financial Statements for additional information regarding our derivative instruments. +30 +Item 8: +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Key Tronic Corporation +Spokane Valley, Washington +We have audited the accompanying consolidated balance sheets of Key Tronic Corporation as of July 1, 2017 and July 2, 2016 and the related consolidated statements of income, comprehensive income (loss), shareholders' equity, and cash flows for each of the three years in the period ended July 1, 2017. In connection with our audits of the financial statements, we have also audited the financial statement schedule listed in the accompanying index. These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits. +We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Key Tronic Corporation at July 1, 2017 and July 2, 2016, and the results of its operations and its cash flows for each of the three years in the period ended July 1, 2017 , in conformity with accounting principles generally accepted in the United States of America. +Also, in our opinion, the financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Key Tronic Corporation's internal control over financial reporting as of July 1, 2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) and our report dated August 17, 2017 expressed an unqualified opinion thereon. +/s/ BDO USA, LLP +Spokane, Washington +September 8, 2017 +31 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED BALANCE SHEETS +(In thousands) +July 1, 2017 +July 2, 2016 +ASSETS +Current assets: +Cash and cash equivalents +$ +373 +$ +1,018 +Trade receivables, net of allowance for doubtful accounts of $84 and $135 +65,193 +61,678 +Inventories, net +101,590 +107,006 +Other +11,037 +11,757 +Total current assets +178,193 +181,459 +Property, plant and equipment, net +30,496 +27,925 +Other assets: +Deferred income tax asset +6,981 +8,982 +Goodwill +9,957 +9,957 +Other intangible assets, net +4,800 +5,928 +Other +2,413 +1,673 +Total other assets +24,151 +26,540 +Total assets +$ +232,840 +$ +235,924 +LIABILITIES AND SHAREHOLDERS ’ EQUITY +Current liabilities: +Accounts payable +$ +53,078 +$ +58,967 +Accrued compensation and vacation +10,005 +9,571 +Current portion of debt, net +5,841 +5,000 +Other +8,829 +10,572 +Total current liabilities +77,753 +84,110 +Long-term liabilities: +Term loans +18,773 +21,250 +Revolving loan +18,335 +18,073 +Other long-term obligations +1,412 +6,909 +Total long-term liabilities +38,520 +46,232 +Total liabilities +116,273 +130,342 +Commitments and contingencies (Note 4 and 9) +Shareholders’ equity: +Common stock, no par value—shares authorized 25,000; issued and outstanding 10,760 and 10,725 shares, respectively +45,797 +45,227 +Retained earnings +73,545 +67,928 +Accumulated other comprehensive loss +(2,775 +) +(7,573 +) +Total shareholders’ equity +116,567 +105,582 +Total liabilities and shareholders’ equity +$ +232,840 +$ +235,924 +See accompanying notes to consolidated financial statements. +32 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF INCOME +(In thousands, except per share amounts) +Fiscal Year Ended +July 1, 2017 +July 2, 2016 +June 27, 2015 +Net sales +$ +467,797 +$ +484,965 +$ +433,997 +Cost of sales +429,497 +446,140 +400,692 +Gross profit +38,300 +38,825 +33,305 +Research, development and engineering expenses +6,393 +6,397 +5,784 +Selling, general and administrative expenses +22,363 +22,012 +20,868 +Total operating expenses +28,756 +28,409 +26,652 +Operating income +9,544 +10,416 +6,653 +Interest expense, net +2,288 +2,265 +1,353 +Income before income taxes +7,256 +8,151 +5,300 +Income tax provision +1,639 +1,618 +996 +Net income +$ +5,617 +$ +6,533 +$ +4,304 +Net income per share — Basic +$ +0.52 +$ +0.61 +$ +0.41 +Weighted average shares outstanding — Basic +10,756 +10,710 +10,572 +Net income per share — Diluted +$ +0.51 +$ +0.58 +$ +0.38 +Weighted average shares outstanding — Diluted +10,917 +11,278 +11,286 +See accompanying notes to consolidated financial statements. +33 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) +(In thousands) +Fiscal Year Ended +July 1, 2017 +July 2, 2016 +June 27, 2015 +Comprehensive income (loss): +Net income +$ +5,617 +$ +6,533 +$ +4,304 +Other comprehensive income (loss): +Unrealized gain (loss) on hedging instruments, net of tax +4,798 +(2,810 +) +(7,166 +) +Comprehensive income (loss) +$ +10,415 +$ +3,723 +$ +(2,862 +) +Other comprehensive income (loss) for fiscal years 2017 , 2016 , and 2015 is reflected net of tax provision (benefit) of approximately $2.5 million , $(1.4) million and $(3.7) million , respectively. +See accompanying notes to consolidated financial statements. +34 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Fiscal Year Ended +July 1, 2017 +July 2, 2016 +June 27, 2015 +Operating activities: +Net income +$ +5,617 +$ +6,533 +$ +4,304 +Adjustments to reconcile net income to cash provided by operating activities: +Depreciation and amortization +7,232 +6,162 +5,910 +Amortization of deferred loan costs +17 +— +— +Excess tax benefit from exercise of stock options +— +(402 +) +(50 +) +Provision for obsolete inventory +496 +757 +520 +Provision for warranty +68 +95 +115 +(Recovery of) provision for doubtful accounts +(10 +) +38 +97 +Loss on disposal of assets +101 +— +70 +Share-based compensation expense +692 +764 +732 +Deferred income taxes +(471 +) +(1,313 +) +(1,517 +) +Changes in operating assets and liabilities, net of acquisition: +Trade receivables +(3,505 +) +11,136 +(2,080 +) +Inventories +4,920 +(16,169 +) +(14,708 +) +Other assets +636 +1,739 +(4,249 +) +Accounts payable +(5,889 +) +(2,561 +) +17,999 +Accrued compensation and vacation +434 +104 +(283 +) +Other liabilities +(913 +) +(2,303 +) +807 +Cash provided by operating activities +9,425 +4,580 +7,667 +Investing activities: +Payment for acquisition, net of cash acquired +— +— +(47,964 +) +Purchases of property and equipment +(9,307 +) +(13,277 +) +(8,808 +) +Proceeds from sale of fixed assets +834 +7,612 +8,641 +Cash used in investing activities +(8,473 +) +(5,665 +) +(48,131 +) +Financing activities: +Payment of financing costs +(221 +) +(113 +) +(62 +) +Proceeds from issuance of long term debt +3,919 +— +35,000 +Repayments of long term debt +(5,435 +) +(5,000 +) +(3,750 +) +Borrowings under revolving credit agreement +161,240 +197,568 +137,987 +Repayments of revolving credit agreement +(160,978 +) +(191,126 +) +(126,356 +) +Proceeds from accounts receivable transfer agreement +— +— +1,116 +Payments towards accounts receivable transfer agreement +— +— +(8,969 +) +Excess tax benefit from exercise of stock options +— +402 +50 +Proceeds from exercise of stock options +— +— +17 +Tax withholding from exercise of share-based compensation +(122 +) +— +— +Cash (used in) provided by financing activities +(1,597 +) +1,731 +35,033 +Net (decrease) increase in cash and cash equivalents +(645 +) +646 +(5,431 +) +Cash and cash equivalents, beginning of period +1,018 +372 +5,803 +Cash and cash equivalents, end of period +$ +373 +$ +1,018 +$ +372 +Supplemental cash flow information: +Interest payments +$ +2,238 +$ +2,308 +$ +1,221 +Income tax payments, net of refunds +$ +1,799 +$ +813 +$ +3,274 +See accompanying notes to consolidated financial statements. +35 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY +(In thousands) +Shares +Common +Stock +Retained +Earnings +Accumulated +Other +Comprehensive +Income (Loss) +Total +Shareholders’ +Equity +Balances, June 28, 2014 +10,547 +$ +44,151 +$ +57,091 +$ +2,403 +$ +103,645 +Net income +— +— +4,304 +— +4,304 +Unrealized loss on hedging instruments, net +— +— +— +(7,166 +) +(7,166 +) +Exercise of stock options +5 +17 +— +— +17 +Exercise of stock appreciation rights +223 +— +— +— +— +Shares withheld for taxes +(69 +) +(814 +) +— +— +(814 +) +Share-based compensation +— +732 +— +— +732 +Excess tax benefit from share-based compensation +— +50 +— +— +50 +Balances, June 27, 2015 +10,706 +$ +44,136 +$ +61,395 +$ +(4,763 +) +$ +100,768 +Net income +— +— +6,533 +— +6,533 +Unrealized loss on hedging instruments, net +— +— +— +(2,810 +) +(2,810 +) +Exercise of stock appreciation rights +28 +— +— +— +— +Shares withheld for taxes +(9 +) +(75 +) +— +— +(75 +) +Share-based compensation +— +764 +— +— +764 +Excess tax benefit from share-based compensation +— +402 +— +— +402 +Balances, July 2, 2016 +10,725 +$ +45,227 +$ +67,928 +$ +(7,573 +) +$ +105,582 +Net income +— +— +5,617 +— +5,617 +Unrealized gain on hedging instruments, net +— +— +— +4,798 +4,798 +Exercise of stock appreciation rights +49 +— +— +— +— +Shares withheld for taxes +(14 +) +(122 +) +— +— +(122 +) +Share-based compensation +— +692 +— +— +692 +Balances, July 1, 2017 +10,760 +$ +45,797 +$ +73,545 +$ +(2,775 +) +$ +116,567 +See accompanying notes to consolidated financial statements. +36 +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. SIGNIFICANT ACCOUNTING POLICIES +Business +Key Tronic Corporation and subsidiaries (the Company) is engaged in electronic manufacturing services (EMS) for original equipment manufacturers (OEMs) and also manufactures keyboards and other input devices. The Company’s headquarters are located in Spokane Valley, Washington with manufacturing operations in Oakdale, Minnesota; Fayetteville, Arkansas; Corinth, Mississippi; and foreign manufacturing operations in Juarez, Mexico; and Shanghai, China. +Principles of Consolidation +The consolidated financial statements include the Company and its wholly owned subsidiaries in the United States, Mexico and China. Intercompany balances and transactions have been eliminated during consolidation. +Reclassifications +Certain prior period reclassifications were made to conform with the current period presentation. These reclassifications had no effect on reported income, comprehensive income (loss), cash flows, total assets, or shareholders' equity as previously reported. +Use of Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates include the allowance for doubtful receivables, the provision for obsolete and non-saleable inventories, deferred tax assets and liabilities, uncertain tax positions, valuation of goodwill, impairment of long-lived assets, medical self-funded insurance liability, long-term incentive compensation accrual, the provision for warranty costs, the fair value of stock appreciation rights granted under the Company’s share-based compensation plan and purchase price allocation of acquired businesses. Due to uncertainties with respect to the assumptions and estimates, actual results could differ from those estimates. +Cash and Cash Equivalents +The Company considers investments with an original maturity of three months or less to be cash equivalents. Cash equivalents are carried at cost, which approximates fair value. The Company may have cash and cash equivalents at financial institutions that are in excess of federally insured limits from time to time. +Allowance for Doubtful Accounts +The Company evaluates the collectability of accounts receivable and records an allowance for doubtful accounts, which reduces the receivables to an amount that management reasonably estimates will be collected. A specific allowance is recorded against receivables considered to be impaired based on the Company’s knowledge of the financial condition of the customer. In determining the amount of the allowance, the Company considers several factors including the aging of the receivables, the current business environment and historical experience. After all attempts to collect a receivable have failed, the receivable is written off against the allowance. +Inventories +Inventories are stated at the lower of cost or net realizable value. Cost is determined principally using the first-in, first-out (FIFO) method. Customer orders are based upon forecasted quantities of product manufactured for shipment over defined periods. Raw material inventories are purchased to fulfill these customer requirements. Within these arrangements, customer demands for products frequently change, sometimes creating excess and obsolete inventories. The Company regularly reviews raw material inventories by customer for both excess and obsolete quantities. Wherever possible, the Company attempts to recover its full cost of excess and obsolete inventories from customers or, in some cases, through other markets. When it is determined that the Company’s carrying cost of such excess and obsolete inventories cannot be recovered in full, a charge is taken against income for the difference between the carrying cost and the estimated realizable amount. We also reserve for inventory related to specific customers covered by lead-time assurance agreements when those customers are experiencing financial difficulties or reimbursement is not reasonably assured. +Property, Plant and Equipment +Property, plant and equipment are carried at cost and depreciated using straight-line methods over the expected useful lives of the assets. Repairs and maintenance costs are expensed as incurred. +37 +Business Combinations +The Company recognizes the assets acquired and liabilities assumed in business combinations on the basis of their fair values at the date of acquisition. We assess the fair value of assets, including intangible assets, using a variety of methods and each asset is measured at fair value from the perspective of a market participant. The method used to estimate the fair values of intangible assets incorporates significant assumptions regarding the estimates a market participant would make in order to evaluate an asset, including a market participant’s use of the asset and the appropriate discount rates for a market participant. Assets recorded from the perspective of a market participant that are determined to not have economic use for us are expensed immediately. Any excess purchase price over the fair value of the net tangible and intangible assets acquired is allocated to goodwill. Transaction costs and restructuring costs associated with a business combination are expensed as incurred. +Impairment of Goodwill +The Company records intangible assets that are acquired individually or with a group of other assets in the financial statements at acquisition. In accordance with ASC 350, Goodwill and Other Intangible Assets , goodwill is not amortized but is required to be reviewed for impairment at least annually or when events or circumstances indicate that carrying value may exceed fair value. The Company tests goodwill by first performing a qualitative analysis (“Step 0”) to determine if it is more likely than not that the fair value of the reporting unit is greater than its carrying value. If the Company determines that it is not more likely than not that the fair value of the reporting unit is greater than its carrying value, the Company calculates the fair value of the reporting unit and compares the fair value of the reporting unit to its carrying value (“Step 1”). If the carrying value of the reporting unit exceeds the fair value, goodwill is potentially impaired and the second step (“Step 2”) of the impairment test must be performed. In the second step, the Company compares the implied fair value of the goodwill, as defined by ASC 350, to the carrying amount to determine the impairment loss, if any. +The Company performed its annual qualitative Step 0 analysis as of April 2, 2017 and determined a Step 1 analysis was necessary due to market conditions. Based on the results of the Step 1 analysis, the Company concluded that the fair value of the reporting unit was greater than the carrying value of the reporting unit based on a methodology that utilized both an income approach and a market approach. We considered valuation factors including the Company's market capitalization, future discounted cash flows and an estimated control premium based upon a review of comparable market transactions. Our consideration of discounted future cash included assumptions regarding growth rates and margins based on our historical trends. In addition, we applied a market discount rate calculated based upon an analysis of companies similar in size. The estimated fair value of the reporting unit exceeded the carrying value by approximately 20%. We will continue to monitor our market capitalization and impairment indicators. +Impairment of Long-lived Assets +The Company, using its best estimates based on reasonable and supportable assumptions and projections, reviews assets for impairment whenever events or changes in circumstances have indicated that the carrying amount of its assets might not be recoverable. Impaired assets are reported at the lower of cost or fair value. +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. Management reviews the adequacy of this accrual quarterly based on historical analyses and anticipated product returns. +Self-funded Insurance +The Company self-funds its domestic employee health plans. The Company contracts with a separate administrative service company to supervise and administer the programs and act as its representative. The Company reduces its risk under this self-funded platform by purchasing stop-loss insurance coverage for high dollar individual claims. In addition, if the aggregate annual claims amount to more than 125 percent of expected claims for the plan year this insurance will also pay those claims amounts exceeding that level. +The Company estimates its exposure for claims incurred but not paid at the end of each reporting period and uses historical claims data supplied by the Company’s broker to estimate its self-funded insurance liability. This liability is subject to a total limitation that varies based on employee enrollment and factors that are established at each annual contract renewal. Actual claims experience may differ from the Company’s estimates. Costs related to the administration of the plan and related claims are expensed as incurred. +38 +Revenue Recognition +Sales revenue from manufacturing is recognized upon shipment of the manufactured product per contractual terms. Upon shipment, title transfers and the customer assumes risks and rewards of ownership of the product. The price to the buyer is fixed or determinable and recoverability is reasonably assured. Unless specifically stated in contractual terms, there are no formal customer acceptance requirements or further obligations related to the manufacturing services; if any such requirements exist, then sales revenue is recognized at the time when such requirements are completed and such obligations are fulfilled. Revenue is recorded net of estimated returns of manufactured product based on management’s analysis of historical returns. +Revenues and associated costs from engineering design, development services and tooling, which are performed under contract of short term durations, are recognized only after the completed performance of the service. Revenue from engineering design, development services and tooling represented approximately 2.1 percent , 1.7 percent and 2.5 percent of total revenue in fiscal years 2017 , 2016 , and 2015 , respectively. +Shipping and Handling Fees +The Company classifies costs associated with shipping and handling fees as a component of cost of goods sold. Customer billings related to shipping and handling fees are reported as revenue. +Research, Development and Engineering +Research, development and engineering expenses include unreimbursed EMS costs as well as design and engineering costs associated with the production of EMS programs. Research, development and engineering costs are expensed as incurred. +Income Taxes +Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the estimated future tax consequences and benefits attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis, as well as operating losses and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities for a change in tax rates is recognized in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amount that is more likely than not to be realized. +We utilize a two-step approach to recognizing and measuring uncertain tax positions. The first step is to evaluate the tax position for recognition by determining if the weight of available evidence indicates it is more likely than not that the position will be sustained on audit, including resolution of related appeals or litigation processes, if any. The second step is to measure the tax benefit as the largest amount which is more than 50% likely of being realized upon ultimate settlement. We consider many factors when evaluating and estimating our tax positions and tax benefits, which may require periodic adjustments based on new assessments and changes in estimates and which may not accurately forecast actual outcomes. Our policy is to recognize interest and penalties related to the underpayment of income taxes as a component of income tax provision. To date, we have not incurred charges for interest or penalties in relation to the underpayment of income taxes. The tax years 1997 through the present remain open to examination by the major U.S. taxing jurisdictions to which we are subject. Refer to Note 6 for further discussions. +Derivative Instruments and Hedging Activities +The Company has entered into foreign currency forward contracts and an interest rate swap which are accounted for as cash flow hedges in accordance with ASC 815, Derivatives and Hedging . The effective portion of the gain or loss on the derivative is reported as a component of accumulated other comprehensive income (AOCI) and is reclassified into earnings in the same period in which the underlying hedged transaction affects earnings. The derivative’s effectiveness represents the change in fair value of the hedge that offsets the change in fair value of the hedged item. +The Company uses derivatives to manage the variability of foreign currency fluctuations of expenses in our Mexico facilities and interest rate risk associated with certain borrowings under the Company’s debt arrangement. The foreign currency forward contracts and interest rate swaps have terms that are matched to the underlying transactions being hedged. As a result, these transactions fully offset the hedged risk and no ineffectiveness has been recorded. +The Company’s foreign currency forward contracts and interest rate swaps potentially expose the Company to credit risk to the extent the counterparties may be unable to meet the terms of the agreement. The Company minimizes such risk by seeking high quality counterparties. The Company’s counterparties to the foreign currency forward contracts and interest rate swaps are major banking institutions. These institutions do not require collateral for the contracts, and the Company believes that the risk of the counterparties failing to meet their contractual obligations is remote. The Company does not enter into derivative instruments for trading or speculative purposes. +39 +Earnings Per Common Share +Basic earnings per common share is computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is computed by dividing net income by the combination of other potentially dilutive weighted average common shares and the weighted average number of common shares outstanding during the period using the treasury stock method. The computation assumes the proceeds from the exercise of stock options were used to repurchase common shares at the average market price during the period. The computation of diluted earnings per common share does not assume conversion, exercise, or contingent issuance of common stock equivalent shares that would have an anti-dilutive effect on earnings per share. +Foreign Currency Transactions +The functional currency of the Company’s subsidiaries in Mexico and China is the U.S. dollar. Realized foreign currency transaction gains and losses for local currency denominated assets and liabilities are included in cost of goods sold. +Fair Value of Financial Instruments +The carrying values of cash and cash equivalents, accounts receivable and current liabilities reflected on the balance sheets at July 1, 2017 and July 2, 2016 , reasonably approximate their fair value. The Company had an outstanding balance on the line of credit of $18.3 million as of July 1, 2017 and $18.1 million as of July 2, 2016 , with a carrying value that reasonably approximates the fair value. The Company had an outstanding balance on the term loan of $21.3 million as of July 1, 2017 and $26.3 million as of July 2, 2016 , with a carrying value that reasonably approximates the fair value. The equipment term loan is estimated to be $3.5 million as of July 1, 2017 , with a carrying value that reasonably approximates the fair value. As of July 2, 2016 , the Company did not have a balance under the equipment term loan. +Share-based Compensation +The Company’s incentive plan may provide for equity and liability awards to employees in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, stock units, performance shares, performance units, and other stock-based or cash-based awards. Compensation cost is recognized on a straight-line basis over the requisite employee service period, which is generally the vesting period, and is included in cost of goods sold, research, development and engineering, and selling, general, and administrative expenses. Share-based compensation is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on historical experience and future expectations. +Restructuring +Periodically the Company may consolidate excess facilities in order to maximize efficiencies and reduce its costs. In connection with these activities, we recognize restructuring charges for employee termination costs, exit costs and long-lived asset impairment when applicable. +The recognition of these restructuring charges require that we make certain judgments and estimates regarding the nature, timing and amount of costs associated with the planned exit activity. To the extent our actual results differ from our estimates and assumptions, we may be required to revise the estimates of future liabilities, requiring the recognition of additional restructuring charges or the reduction of liabilities already recognized. Such changes to previously estimated amounts may be material to the consolidated financial statements. At the end of each reporting period, we evaluate the remaining accrued balances to ensure that no excess accruals are retained and the utilization of the provisions are for their intended purpose in accordance with developed exit plans. +40 +Newly Adopted and Recent Accounting Pronouncements +In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update 2014-09 (ASU 2014-09), Revenue from Contracts with Customers . The guidance in this Update affects any entity that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (for example, insurance contracts or lease contracts). The standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In doing so, companies will need to use more judgment and make more estimates than under current guidance. This may include identifying performance obligations in the contract, estimating the amount of variable consideration to include in the transaction price and allocating the transaction price to each separate performance obligation. Additionally, disclosures required for revenue recognition will include qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments, and assets recognized from costs to obtain or fulfill a contract. Such disclosures are more extensive than what is required under existing GAAP. In August 2015, the FASB issued an amendment to defer the effective date of ASU 2014-09 for all entities by one year. This Update is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company has assessed that the impact of the new guidance will result in a change of the Company's revenue recognition model for electronics manufacturing services from "point in time" upon physical delivery to an "over time" model and believes this transition may have a material impact on the Company's consolidated financial statements upon adoption primarily as it will recognize an increase in contract assets for unbilled receivables with a corresponding reduction in finished goods and work-in-progress inventory. The Company has commenced implementation in accordance with the planned effective date and such efforts are ongoing. Companies have the option of using either a full or modified retrospective approach in applying this standard. The Company has not yet concluded upon its selection of the transition method. +In July 2015, the FASB issued final guidance that simplifies the subsequent measurement of inventory for which cost is determined by methods other than last-in first-out (“LIFO”) and the retail inventory method. For inventory within the scope of the new guidance, entities will be required to compare the cost of inventory to only one measure, its net realizable value, and not the three measures required by the existing guidance. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. The new guidance should not change how entities initially measure the cost of inventory. The guidance will be effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Early adoption is permitted. The Company adopted this guidance during the second quarter of fiscal year 2017 and it had no impact on our financial statements. +In February 2016, the FASB issued Accounting Standards Update 2016-02 (ASU 2016-02), Leases which supersedes ASC 840 Leases and creates a new topic, ASC 842 Leases . This update requires lessees to recognize a lease asset and a lease liability for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. This update is effective for fiscal years beginning after December 15, 2018 and interim periods within those fiscal years, with earlier adoption permitted. This update will be applied using a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. Upon initial evaluation, the Company believes the new guidance will have a material impact on its consolidated balance sheets when adopted. The Company is currently assessing the timing of adoption. +In March 2016, the FASB issued Accounting Standards Update 2016-09 (ASU 2016-09), Improvements to Employee Share-Based Payment Accounting . This update simplifies several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, with earlier adoption permitted. The Company prospectively adopted this ASU during the first quarter of fiscal year 2017. As a result, excess tax benefits are recorded in income tax expense instead of a component of shareholders’ equity and excess tax benefits are no longer broken out on the consolidated statement of cash flows beginning in fiscal year 2017. +In August 2016, the FASB issued Accounting Standards Update 2016-15 (ASU 2016-15), Classification of Certain Cash Receipts and Cash Payments . This update provides guidance on how to record eight specific cash flow issues. This update is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted and a retrospective transition method to each period should be presented. The Company early adopted this guidance during the second quarter of fiscal year 2017 and it had no impact on our consolidated financial statements. +41 +In January 2017, the FASB issued Accounting Standards Update 2017-04, Simplifying the Test for Goodwill Impairment . Under the new standard, goodwill impairment would be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying value of goodwill. This ASU eliminates existing guidance that requires an entity to determine goodwill impairment by calculating the implied fair value of goodwill by hypothetically assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. This update is effective prospectively to impairment tests beginning June 28, 2020, with early adoption permitted. The Company would apply this guidance to applicable impairment tests after the adoption date. The Company is currently evaluating the effect of this update on its consolidated financial statements. +In May 2017, the FASB issued Accounting Standards Update 2017-09, Compensation - Stock Compensation . This update provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. This update is effective for fiscal years beginning after December 15, 2017. Early adoption is permitted. The Company is currently evaluating the effect of this update on its consolidated financial statements. +Fiscal Year +The Company operates on a 52/53 week fiscal year. Fiscal years end on the Saturday nearest June 30. As such, fiscal years 2017 , 2016 , and 2015 , ended on July 1, 2017 , July 2, 2016 , and June 27, 2015 , respectively. Fiscal year 2017 and 2015 were 52 week years whereas fiscal year 2016 was a 53 week year. +2. INVENTORIES +The components of inventories consist of the following (in thousands): +July 1, 2017 +July 2, 2016 +Finished goods +$ +12,244 +$ +13,384 +Work-in-process +20,596 +18,988 +Raw materials and supplies +68,750 +74,634 +$ +101,590 +$ +107,006 +3. PROPERTY, PLANT AND EQUIPMENT +Property, plant and equipment consists of the following: +Life +July 1, 2017 +July 2, 2016 +(in years) +(in thousands) +Land +— +$ +2,940 +$ +2,940 +Buildings and improvements +3 to 30 +23,158 +23,737 +Equipment +1 to 10 +57,848 +53,095 +Furniture and fixtures +3 to 5 +3,512 +2,924 +87,458 +82,696 +Accumulated depreciation +(56,962 +) +(54,771 +) +$ +30,496 +$ +27,925 +42 +4. LONG-TERM DEBT +On September 3, 2014, the Company entered into a five-year term loan in the amount of $35.0 million used to acquire all of the outstanding shares of CDR Manufacturing, Inc. (dba Ayrshire Electronics). The term loan requires quarterly payments of $1.25 million through June 15, 2019, with a final payment of the remaining outstanding balance on August 31, 2019. The Company had an outstanding balance of $21.3 million and $26.3 million under the term loan as of July 1, 2017 and July 2, 2016 , respectively. +On August 6, 2015, the Company entered into a First Amendment to the amended and restated credit agreement extending the limit on our line of credit facility to $45.0 million as evidenced by the Second Replacement Revolving Note. The agreement specifies that the proceeds of the revolving line of credit be used primarily for working capital and general corporate purposes. The line of credit is secured by substantially all of the assets of the Company and matures on August 31, 2019 at which time all outstanding balances are payable. As of July 1, 2017 , the Company had an outstanding balance under the credit facility of $18.3 million , $0.4 million in outstanding letters of credit and $26.3 million available for future borrowings. As of July 2, 2016 , the Company had an outstanding balance under the credit facility of $18.1 million , $0.4 million in outstanding letters of credit and $26.5 million available for future borrowings. +On December 28, 2016, the Company entered into an equipment term loan agreement in the amount of $3.9 million in order to further invest in production equipment. The equipment term loan is collateralized by production equipment. Under this loan agreement, equal quarterly payments of approximately $0.2 million commenced on March 31, 2017 and will continue through the maturity of the equipment term loan on June 30, 2021. Amortization of the debt issuance costs is reported as interest expense on the consolidated income statement. As of July 1, 2017 , the Company had an outstanding balance of $3.5 million . The Company did not have a balance as of July 2, 2016 . The Company has available an additional $2.1 million which can be borrowed in the future under this agreement. +Borrowings under the revolving line of credit, term loan and equipment term loan bear interest at either a “Base Rate” or a “Fixed Rate,” as elected by the Company. The base rate is the higher of the Wells Fargo Bank prime rate, daily one month London Interbank Offered Rate (LIBOR) plus 1.5% , or the Federal Funds rate plus 1.5% . The fixed rate is LIBOR plus 1.75% , LIBOR plus 2.0% or LIBOR plus 2.25% depending on the level of the Company’s trailing four quarters Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA). The interest rates on the outstanding debt as of July 1, 2017 range from 3.22% - 4.25% compared to 2.45% - 3.50% as of July 2, 2016 . +Debt maturities as of July 1, 2017 for the next five years and thereafter are as follows (in thousands): +Fiscal Years Ending +Amount +2018 +$ +5,871 +2019 +5,871 +2020 +30,455 +2021 +871 +2022 +— +Total debt +$ +43,068 +Unamortized debt issuance costs +$ +(119 +) +Long-term debt, net of debt issuance costs +$ +42,949 +The Company must comply with certain financial covenants, including a cash flow leverage ratio, an asset coverage ratio and a fixed charge coverage ratio. The credit agreement requires the Company to maintain a minimum profit threshold, limits the maximum capital lease expenditures and restricts the Company from declaring or paying dividends in cash or stock without prior bank approval. The Company is in compliance with all financial covenants for all periods presented. +43 +5. TRADE ACCOUNTS RECEIVABLE PURCHASE PROGRAMS +Sale Programs +The Company utilizes an Account Purchase Agreement with Wells Fargo Bank, N.A. ("WFB") which allows the Company to sell and assign to WFB and WFB may purchase from Company the accounts receivable of certain Company customers in a maximum aggregate amount outstanding of $20.0 million . This agreement may be cancelled at any time by either party. The Company also has an Account Purchase Agreement with Orbian Financial Services (“Orbian”). This agreement allows the Company to sell accounts receivable of certain customers to Orbian and the agreement may be cancelled at any time by either party. +Total accounts receivables sold during the twelve months ended July 1, 2017 and July 2, 2016 was approximately $86.5 million and $78.0 million , respectively. Accounts receivables sold and not yet collected was approximately $1.6 million and $1.7 million as of July 1, 2017 and July 2, 2016 , respectively. The receivables that were sold were removed from the consolidated balance sheets and the cash received is reflected as cash provided by operating activities in the consolidated statements of cash flows. +6. INCOME TAXES +Income tax provision consists of the following: +Fiscal Year Ended +July 1, 2017 +July 2, 2016 +June 27, 2015 +(in thousands) +Current income tax provision: +United States +$ +1,231 +$ +1,014 +$ +1,701 +Foreign +1,206 +1,960 +975 +2,437 +2,974 +2,676 +Deferred income tax benefit: +United States +(539 +) +(1,285 +) +(1,486 +) +Foreign +(259 +) +(71 +) +(194 +) +(798 +) +(1,356 +) +(1,680 +) +Total income tax provision +$ +1,639 +$ +1,618 +$ +996 +The Company has gross tax credit carryforwards of approximately $8.2 million at July 1, 2017 . Included in total tax credits carryforwards is approximately $7.4 million in research and development (R&D) tax credits. +Management also has reviewed its other deferred tax assets for purposes of determining whether or not a valuation allowance may be required. A valuation allowance against these deferred tax assets is required if it is more likely than not that some of the deferred tax assets will not be realized. Based on the Company’s profitability and estimated future repatriations from foreign subsidiaries, it has been determined that it is more likely than not that the deferred tax assets will be realized. +Management has reviewed and updated as necessary estimates of future repatriations of the undistributed earnings of its foreign subsidiaries. Based on this analysis, management expects to repatriate a portion of the foreign undistributed earnings based on increased sales growth driving additional U.S. capital requirements, cash requirements for potential acquisitions and to potentially implement certain tax strategies. No foreign earnings were repatriated from either foreign subsidiary during fiscal 2017 or 2016 . The Company currently estimates that future repatriations from foreign subsidiaries will approximate $13.4 million . As such, as earnings are recognized in the United States, the Company would be subject to U.S. federal and state income taxes and potential withholding taxes are estimated to be approximately $6.6 million . Both the domestic tax and estimated withholding tax have been recorded as part of deferred taxes as of July 1, 2017 . All other unremitted foreign earnings are expected to remain permanently reinvested for planned fixed asset purchases in foreign locations. +The Company has not provided for U.S. income taxes or foreign withholding taxes on approximately $15.0 million of earnings from foreign subsidiaries which are permanently reinvested outside the U.S. The unrecognized net tax provision, after netting U.S. federal and state income tax and any related foreign tax credits, would be approximately $2.3 million associated with these earnings. +During the second quarter of fiscal year 2017, the Company signed a unilateral advance pricing agreement (APA) with the Large Taxpayer Division of Mexico’s Servicio de Administración Tributaria (SAT) under an elective framework that has been agreed to by the U.S. and Mexican authorities. The APA is part of a larger program affecting hundreds of U.S. companies with maquiladora operations in Mexico. The general impact of the APA is to increase margins between the maquiladora and U.S. parent company, shifting profits to Mexico from the U.S. +44 +As a result of the APA, the Company recognized an increased tax liability in Mexico of approximately $0.4 million related to the calendar years 2014-2016. However, the increased costs to the U.S. resulted in a reduced tax liability of approximately $0.4 million in the U.S. during fiscal year 2017. The overall net impact of the APA is therefore estimated to not be material to the Company’s consolidated financial results. The estimated increased liabilities in Mexico and related offsetting tax benefit in the U.S. were recorded during the second quarter of fiscal year 2017. The APA was finalized during the fourth quarter of fiscal year 2017. +Further, the resulting impact of the APA resulted in approximately $1.8 million of additional earnings being recognized in Mexico. The Company has reevaluated its repatriation assumptions and based on new customer growth in Mexico and related required capital expenditures, it is assumed that 50% of the additional $1.8 million in earnings will be permanently reinvested in Mexico. +The Company’s effective tax rate differs from the federal tax rate as follows: +Fiscal Year Ended +July 1, 2017 +July 2, 2016 +June 27, 2015 +(in thousands) +Federal income tax provision at statutory rates +$ +2,467 +$ +2,771 +$ +1,802 +State income taxes, net of federal tax effect +175 +250 +133 +Foreign tax rate differences +(156 +) +(442 +) +(80 +) +Effect of income tax credits +(738 +) +(1,254 +) +(1,085 +) +Effect of repatriation of foreign earnings, net +199 +(161 +) +(80 +) +Other +(308 +) +454 +124 +Transaction costs +— +— +182 +Income tax provision +$ +1,639 +$ +1,618 +$ +996 +The domestic and foreign components of income before income taxes were: +Fiscal Year Ended +July 1, 2017 +July 2, 2016 +June 27, 2015 +(in thousands) +Domestic +$ +3,553 +$ +2,228 +$ +3,395 +Foreign +3,703 +5,923 +1,905 +Income before income taxes +$ +7,256 +$ +8,151 +$ +5,300 +45 +Deferred income tax assets and liabilities consist of the following at: +July 1, 2017 +July 2, 2016 +(in thousands) +Deferred tax assets: +Tax credit carryforwards, net +$ +4,164 +$ +4,056 +Foreign subsidiaries - future tax credits +840 +840 +Inventory +840 +508 +Accruals +4,020 +4,270 +Mark-to-market adjustments +1,443 +4,043 +Other +28 +86 +Deferred income tax assets +$ +11,335 +$ +13,803 +Deferred tax liabilities: +Foreign subsidiaries – unremitted earnings +(2,288 +) +(2,098 +) +Fixed assets +(456 +) +(1,025 +) +Identifiable intangibles +(1,308 +) +(1,613 +) +Other +(302 +) +(85 +) +Deferred income tax liabilities +$ +(4,354 +) +$ +(4,821 +) +Net deferred income tax assets +$ +6,981 +$ +8,982 +Balance sheet caption reported in: +Long-term deferred income tax asset +$ +6,981 +$ +8,982 +Net deferred income tax asset +$ +6,981 +$ +8,982 +Uncertain Tax Positions +The Company has R&D tax credits that approximate $7.4 million that have 20 year carryforwards before expiring. The Company’s R&D tax credits expire in various fiscal years from 2021 to 2036. The Company also has alternative minimum tax credits, which do not expire, approximating $726,000 . +As of July 1, 2017 , the Company had unrecognized tax benefits of $3.9 million related to its gross R&D tax credits. The unrecognized tax benefits relate to certain R&D tax credits generated from 1999 to 2016. +A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: +Fiscal Year Ended +July 1, 2017 +July 2, 2016 +June 27, 2015 +(in thousands) +Beginning Balance +$ +3,760 +$ +3,446 +$ +3,072 +Additions based on tax positions related to the current year +187 +314 +374 +Ending Balance +$ +3,947 +$ +3,760 +$ +3,446 +The increase from the prior year is due to additional R&D credits that were recorded in 2017 as discussed above. Management does not anticipate any material changes to this amount during the next 12 months. +The Company recognizes interest accrued related to unrecognized tax benefits and penalties in its income tax provision. The Company has not recognized any interest or penalties in the fiscal years presented in these financial statements. The Company is subject to income tax in the U.S. federal jurisdiction, various state jurisdictions, Mexico and China. Certain years remain subject to examination but there are currently no ongoing exams in any taxing jurisdictions. +46 +7. EARNINGS PER SHARE +Basic earnings per share (EPS) is calculated by dividing net income (the numerator) by the weighted-average number of common shares outstanding (the denominator) during the period. Diluted EPS is computed by including both the weighted-average number of shares outstanding and any dilutive common share equivalents in the denominator. The following table presents a reconciliation of the denominator and the number of antidilutive common share awards that were not included in the diluted earnings per share calculation. These antidilutive securities occur when equity awards outstanding have an option price greater than the average market price for the period: +Fiscal Year Ended +(in thousands, except per share information) +July 1, 2017 +July 2, 2016 +June 27, 2015 +Net income +$ +5,617 +$ +6,533 +$ +4,304 +Weighted average shares outstanding– basic +10,756 +10,710 +10,572 +Effect of dilutive common stock awards +161 +568 +714 +Weighted average shares outstanding – diluted +10,917 +11,278 +11,286 +Earnings per share – basic +$ +0.52 +$ +0.61 +$ +0.41 +Earnings per share – diluted +$ +0.51 +$ +0.58 +$ +0.38 +Antidilutive SARs not included in diluted earnings per share +892 +442 +208 +8. STOCK OPTION AND BENEFIT PLANS +The Company’s incentive plan provides for equity and liability awards to employees and non-employee directors in the form of stock options, stock appreciation rights (SARs), restricted stock, restricted stock units, stock awards, stock units, performance shares, performance units, and other stock-based or cash-based awards. Compensation cost is recognized on a straight-line basis over the requisite employee service period, which is generally the vesting period, and is recorded as employee compensation expense in cost of goods sold, research, development and engineering, and selling, general and administrative expenses. Share-based compensation is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on historical experience and future expectations. +In addition to service conditions, these SARs contain a performance condition. The additional performance condition is based upon the achievement of Return on Invested Capital (ROIC) goals relative to a peer group. All awards with performance conditions are measured over the vesting period and are charged to compensation expense over the requisite service period based on the number of shares expected to vest. The SARs cliff vest after a three-year period from date of grant and expire five years from date of grant. +On October 28, 2016, the Company granted 10,000 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $8.04 and a grant date fair value of $2.30 , as of July 1, 2017 , 10,000 remain outstanding. The grant date fair value for the awards granted during fiscal year 2017 , were estimated using the Black Scholes option valuation method with the following weighted average assumptions as of October 28, 2016: +Fiscal Year 2017 +October 28, 2016 +Expected dividend yield +—% +Risk – free interest rate +1.63% +Expected volatility +33.43% +Expected life +4.00 +47 +On July 26, 2016, the Company granted 242,500 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $8.18 and a grant date fair value of $2.42 , as of July 1, 2017 , 242,500 remain outstanding. The grant date fair value for the awards granted during fiscal year 2017 , were estimated using the Black Scholes option valuation method with the following weighted average assumptions as of July 26, 2016: +Fiscal Year 2017 +July 26, 2016 +Expected dividend yield +—% +Risk – free interest rate +0.93% +Expected volatility +36.13% +Expected life +4.00 +On July 29, 2015, the Company granted 248,166 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $10.26 and a grant date fair value of $3.65 , as of July 1, 2017 , 233,333 remain outstanding. The grant date fair value for the awards granted during fiscal year 2016, were estimated using the Black Scholes option valuation method with the following weighted average assumptions as of July 29, 2015: +Fiscal Year 2016 +July 29, 2015 +Expected dividend yield +—% +Risk – free interest rate +1.39% +Expected volatility +43.66% +Expected life +4.00 +On October 31, 2014, the Company granted 213,166 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $8.22 and a grant date fair value of $3.04 , as of July 1, 2017 , 205,833 remain outstanding. The grant date fair value for the awards granted during fiscal year 2016, were estimated using the Black Scholes option valuation method with the following weighted average assumptions as of October 31, 2014: +Fiscal Year 2015 +October 31, 2014 +Expected dividend yield +—% +Risk – free interest rate +1.39% +Expected volatility +45.67% +Expected life +4.00 +Subsequent to July 1, 2017 , the Company granted 272,500 SARs with a strike price of $7.26 and a grant date fair value of $1.89 . +Share-based compensation expense is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on the Company’s historical experience and future expectations. This forfeiture rate will be revised, if necessary, in subsequent periods if actual forfeitures differ from the amount estimated. Share-based compensation expense for fiscal years ended July 1, 2017 , July 2, 2016 and June 27, 2015 was $0.7 million , $0.8 million and $0.7 million , respectively. +The Black-Scholes option valuation model is used by the Company for estimating the fair value of SARs. Option valuation models require the input of highly subjective assumptions, particularly for the expected term and expected stock price volatility. Changes in these assumptions can materially affect the fair value estimates. +The intrinsic value for stock options and SARs exercised in fiscal years 2017 , 2016 and 2015 was $0.4 million , $0.2 million and $1.9 million , respectively. +As of July 1, 2017 , total unrecognized compensation expense related to nonvested share-based compensation arrangements was approximately $0.8 million . This expense is expected to be recognized over a weighted-average period of 1.54 years . +48 +The following table summarizes the Company’s Options and SARs activity for all plans from June 28, 2014 through July 1, 2017 : +SARs +Available +For Grant +SARs +Outstanding +Aggregate +Intrinsic +Value (in +thousands) +Weighted +Average +Exercise +Price +Weighted +Average +Remaining +Contractual +Life (in +years) +Balances, June 28, 2014 +69,002 +1,065,928 +$ +4,096 +$ +7.01 +1.8 +Shares authorized +1,000,000 +— +SARs granted +(213,166 +) +213,166 +8.22 +SARs forfeited +— +— +— +Options/SARs exercised +— +(465,263 +) +1,877 +5.84 +Balances, June 27, 2015 +855,836 +813,831 +$ +2,312 +$ +7.99 +2.5 +Shares authorized +— +SARs granted +(248,166 +) +248,166 +10.26 +SARs forfeited +26,999 +(26,999 +) +9.48 +SARs exercised +— +(63,333 +) +165 +4.56 +Balances, July 2, 2016 +634,669 +971,665 +$ +339 +$ +8.75 +2.4 +Shares authorized +— +SARs granted +(252,500 +) +252,500 +8.17 +SARs forfeited +12,166 +(12,166 +) +8.60 +SARs exercised +— +(127,000 +) +385 +4.77 +Balances, July 1, 2017 +394,335 +1,084,999 +$ +— +$ +9.09 +2.3 +Exercisable at July 1, 2017 +393,333 +$ +— +$ +9.43 +0.6 +Additional information regarding SARs outstanding and exercisable as of July 1, 2017 , is as follows: +Range of +Exercise Prices +Number Outstanding +Weighted Avg. +Remaining +Contractual Life (yrs.) +Weighted Avg. +Exercise Price +Number +Exercisable +Weighted +Avg. Exercise +Price +$4.40 – $7.90 +192,500 +0.1 +$ +7.44 +192,500 +$ +7.44 +7.91 – 9.91 +458,333 +3.3 +8.19 +— +— +9.92 – 11.34 +434,166 +2.2 +10.76 +200,833 +11.34 +$4.40 to $11.34 +1,084,999 +2.3 +$ +9.09 +393,333 +$ +9.43 +The Company has defined contribution plans available to U.S. employees who have attained age 21. Company contributions to the plans were approximately $0.6 million , $0.6 million , and $0.6 million during fiscal years 2017 , 2016 and 2015 , respectively. +49 +9. COMMITMENTS AND CONTINGENCIES +Leases : As of July 1, 2017 , July 2, 2016 and June 27, 2015 , the Company did not have any property and equipment financed under capital leases. As of July 1, 2017 , the Company has operating leases for certain equipment and production facilities, which expire at various dates during the next eight years . +Future minimum payments under non-cancelable operating leases at July 1, 2017 , are summarized as follows (in thousands): +Fiscal Years Ending +Operating Leases +2018 +$ +6,747 +2019 +3,979 +2020 +1,873 +2021 +1,114 +2022 +325 +Thereafter +854 +Total minimum lease payments +$ +14,892 +Rental expense under operating leases was approximately $7.8 million , $6.6 million , and $3.8 million during fiscal years 2017 , 2016 and 2015 , respectively. +Warranty Costs : The Company provides warranties on certain product sales, and allowances for estimated warranty costs are recorded during the period of sale. The determination of such allowances requires the Company to make estimates of product return rates and expected costs to repair or to replace the products under warranty. The Company establishes warranty reserves based on historical warranty costs for each product line combined with liability estimates based on the prior twelve months’ sales activities. As of July 1, 2017 and July 2, 2016 , the reserve for warranty costs was approximately $32,000 and $30,000 , respectively. +If actual return rates and/or repair and replacement costs differ significantly from estimates, adjustments to recognize additional cost of sales may be required in future periods. Warranty expense for fiscal years 2017 , 2016 and 2015 was related to workmanship claims on keyboards and certain EMS products. +Litigation : During the second quarter of fiscal year 2017, the Company commenced the arbitration process with a former customer related to approximately $9 million in inventory purchased, cancellation fees, and other carrying costs we believe should be reimbursed by this former customer based on the terms of the manufacturing agreement. The Company is actively working through the arbitration process and expects further clarity on the resolution of this matter, whether through negotiations or a scheduled hearing by the end of the calendar year. The Company has not accrued for any potential gains or losses related to this claim and legal costs are being expensed as incurred. The ultimate disposition of these matters could have a material effect on our consolidated financial position, results of operations or cash flows. +Indemnification Rights : Under the Company’s bylaws, the Company’s directors and officers have certain rights to indemnification by the Company against certain liabilities that may arise by reason of their status or service as directors or officers. The Company maintains director and officer insurance, which may cover certain liabilities arising from its obligation to indemnify its directors and officers and former directors in certain circumstances. +50 +10. FAIR VALUE MEASUREMENTS +The Company has adopted ASC 820, Fair Value Measurements, which defines fair value, establishes a framework for assets and liabilities being measured and reported at fair value and expands disclosures about fair value measurements. There are three levels of fair value hierarchy inputs used to value assets and liabilities which include: Level 1 – inputs are quoted market prices for identical assets or liabilities; Level 2 – inputs other than quoted market prices included in Level 1 that are observable for the asset or liability, either directly or indirectly; and Level 3 – inputs are unobservable inputs for the asset or liability. There have been no changes in the fair value methodologies used at July 1, 2017 and July 2, 2016 . +The following table summarizes the fair value of assets (liabilities) of the Company’s derivatives that are required to be measured on a recurring basis as of July 1, 2017 and July 2, 2016 (in thousands): +July 1, 2017 +Level 1 +Level 2 +Level 3 +Total +Fair Value +Financial Assets: +Foreign currency forward contracts & swaps +$ +— +$ +1,010 +$ +— +$ +1,010 +Financial Liabilities: +Interest rate swaps +$ +— +$ +(103 +) +$ +— +$ +(103 +) +Foreign currency forward contracts & swaps +$ +— +$ +(5,112 +) +$ +— +$ +(5,112 +) +July 2, 2016 +Level 1 +Level 2 +Level 3 +Total +Fair Value +Financial Assets: +Foreign currency forward contracts +— +136 +— +$ +136 +Financial Liabilities: +Interest rate swaps +$ +— +$ +(498 +) +$ +— +$ +(498 +) +Foreign currency forward contracts & swaps +$ +— +$ +(11,112 +) +$ +— +$ +(11,112 +) +The Company currently has forward contracts and swaps to hedge known future cash outflows for expenses denominated in the Mexican peso and an interest rate swap to mitigate risk associated with certain borrowings under the Company’s debt arrangement. These contracts are measured on a recurring basis based on the foreign currency spot rates and forward rates quoted by banks or foreign currency dealers. These contracts are marked to market using level 2 input criteria every period with the unrealized gain or loss, net of tax, reported as a component of shareholders’ equity in accumulated other comprehensive income (loss), as they qualify for hedge accounting. +The carrying values of cash and cash equivalents, accounts receivable and current liabilities reflected on the balance sheets at July 1, 2017 and July 2, 2016 , reasonably approximate their fair value. The Company’s long-term debt primarily consists of a revolving line of credit, a term loan and an equipment term loan. These borrowings bear interest at either a “Base Rate” or a “Fixed Rate,” as elected by the Company. Each of these rates is a variable floating rate dependent upon current market conditions and the Company’s current credit risk as discussed in footnote 4. +As a result of the determinable market rate for our revolving line of credit, term loan and equipment term, they are classified within Level 2 of the fair value hierarchy. The discounted cash flow of the revolving line of credit is estimated to be $18.3 million as of July 1, 2017 and $18.1 million as of July 2, 2016 , with a carrying value that reasonably approximates the fair value. The discounted cash flow of the term loan is estimated to be $21.3 million as of July 1, 2017 and $26.3 million as of July 2, 2016 , with a carrying value that reasonably approximates the fair value. The discounted cash flow of the equipment term loan is estimated to be $3.5 million as of July 1, 2017 , with a carrying value that reasonably approximates the fair value. As of July 2, 2016 , the Company did not have a balance under the equipment term loan. +51 +11. DERIVATIVE FINANCIAL INSTRUMENTS +As of July 1, 2017 , the Company had outstanding foreign currency forward contracts and swaps with a total notional amount of $55.7 million . The maturity dates for these contracts and swaps extend through September 2019 . As of July 1, 2017 , the net amount of unrealized loss expected to be reclassified into earnings within the next 12 months is approximately $2.8 million . During the fiscal year ended July 1, 2017 , the Company entered into $6.7 million of foreign currency forward contracts and settled $20.5 million of such contracts. During the fiscal year ended July 2, 2016 , the Company entered into $25.9 million of foreign currency forward contracts and settled $21.5 million of such contracts. During the fiscal year ended June 27, 2015 , the Company entered into $23.1 million of foreign currency forward contracts and settled $20.5 million of such contracts. +As of July 1, 2017 , the aggregate notional amount of the Company’s outstanding foreign currency contracts and swaps along with their unrealized gains (losses) are expected to mature as summarized below (in thousands): +Quarter Ending +Notional Contracts and Swaps in MXN +Notional Contracts and Swaps in USD +Estimated Fair Value +September 30, 2017 +$ +76,192 +$ +5,395 +$ +(1,218 +) +December 30, 2017 +$ +88,558 +$ +6,162 +$ +(1,370 +) +March 31, 2018 +$ +90,812 +$ +5,713 +$ +(864 +) +June 30, 2018 +$ +95,500 +$ +5,811 +$ +(774 +) +September 29, 2018 +$ +90,443 +$ +5,301 +$ +(588 +) +December 29, 2018 +$ +125,328 +$ +6,746 +$ +(298 +) +March 30, 2019 +$ +137,944 +$ +6,979 +$ +33 +June 29, 2019 +$ +142,947 +$ +6,828 +$ +350 +September 28, 2019 +$ +148,468 +$ +6,740 +$ +627 +On October 1, 2014, the Company entered into an interest rate swap contract with an effective date of September 1, 2015 and a termination date of September 3, 2019, with a notional amount of $25.0 million related to the borrowings outstanding under the term loan. The interest rate swap pays the Company variable interest at the one month LIBOR rate, and the Company pays the counter party a fixed interest rate. The fixed interest rate for the contract is 1.97% that replaces the one month LIBOR rate component of our contractual interest to be paid to WFB as part of our term loan. Based on the terms of the interest rate swap contract and the underlying borrowings outstanding under the term loan, the interest rate contract was determined to be effective, and thus qualifies as a cash flow hedge. As of July 1, 2017 and July 2, 2016 , the remaining notional balance of this swap was $14.5 million and $20.5 million , respectively. +The following table summarizes the fair value of derivative instruments in the Consolidated Balance Sheets as of July 1, 2017 and July 2, 2016 (in thousands): +July 1, 2017 +July 2, 2016 +Derivatives Designated as Hedging Instruments +Balance Sheet Location +Fair Value +Fair Value +Foreign currency forward contracts & swaps +Other long-term assets +$ +1,010 +$ +136 +Foreign currency forward contracts & swaps +Other current liabilities +$ +(4,226 +) +$ +(4,670 +) +Foreign currency forward contracts & swaps +Other long-term liabilities +$ +(886 +) +$ +(6,442 +) +Interest rate swaps +Other long-term assets +$ +— +$ +— +Interest rate swaps +Other current liabilities +$ +(81 +) +$ +(264 +) +Interest rate swaps +Other long-term liabilities +$ +(22 +) +$ +(234 +) +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2017 (in thousands): +Derivatives Designated as Hedging Instruments +Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) +AOCI Balance +as of +July 2, 2016 +Effective +Portion +Recorded In +AOCI +Effective Portion +Reclassified From +AOCI Into Income +AOCI Balance +as of +July 1, 2017 +Forward contracts & swaps +Cost of sales +$ +(7,245 +) +$ +(600 +) +$ +5,138 +$ +(2,707 +) +Interest rate swap +Interest expense +(328 +) +14 +246 +(68 +) +Total +$ +(7,573 +) +$ +(586 +) +$ +5,384 +$ +(2,775 +) +52 +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2016 (in thousands): +Derivatives Designated as Hedging Instruments +Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) +AOCI Balance +as of +June 27, 2015 +Effective +Portion +Recorded In +AOCI +Effective Portion +Reclassified From +AOCI Into Income +AOCI Balance +as of +July 2, 2016 +Forward contracts & swaps +Cost of sales +$ +(4,487 +) +$ +(6,939 +) +$ +4,181 +$ +(7,245 +) +Interest rate swap +Interest expense +(276 +) +(348 +) +296 +(328 +) +Total +$ +(4,763 +) +$ +(7,287 +) +$ +4,477 +$ +(7,573 +) +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2015 (in thousands): +Derivatives Designated as Hedging Instruments +Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) +AOCI Balance +as of +June 28, 2014 +Effective +Portion +Recorded In +AOCI +Effective Portion +Reclassified From +AOCI Into Income +AOCI Balance +as of +June 27, 2015 +Forward contracts +Cost of sales +$ +2,403 +$ +(7,208 +) +$ +318 +$ +(4,487 +) +Interest rate swap +Interest expense +— +(276 +) +— +(276 +) +Total +$ +2,403 +$ +(7,484 +) +$ +318 +$ +(4,763 +) +As of July 1, 2017 , the Company does not have any foreign exchange contracts with credit-risk-related contingent features. The Company is subject to the risk of fluctuating interest rates from our line of credit and foreign currency risk resulting from our China operations. The Company does not currently manage these risk exposures by using derivative instruments. +12. ENTERPRISE-WIDE DISCLOSURES +Operating segments are defined in ASC Topic 280, Segment Reporting as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker, or decision making group, in deciding how to allocate resources and in assessing performance. The Company’s chief operating decision maker is its Chief Executive Officer. As of July 1, 2017 , the Company operates and internally manages a single operating segment, Electronics Manufacturing Services as this is the only discrete financial information that is regularly reviewed by the chief operating decision maker. This segment provides integrated electronic and mechanical engineering, assembly, sourcing and procurement, logistics, and new product testing for our customers. +Products and Services +Of the revenues for the years ended July 1, 2017 , July 2, 2016 , and June 27, 2015 , EMS sales and services were $466.6 million , $483.3 million and $432.1 million , respectively. Keyboard sales for the years ended July 1, 2017 , July 2, 2016 , and June 27, 2015 were $1.2 million , $1.7 million and $1.9 million , respectively. +Geographic Areas +Net sales and long-lived assets (property, plant, and equipment) by geographic area for the years ended and as of July 1, 2017 , July 2, 2016 and June 27, 2015 are summarized in the following table. Net sales set forth below are based on the shipping destination. Long-lived assets information is based on the physical location of the asset. +Fiscal Year Ended +(in thousands) +2017 +2016 +2015 +Geographic net sales: +Domestic (U.S.) +$ +361,886 +$ +347,552 +$ +301,891 +Foreign +105,911 +137,413 +132,106 +Total +$ +467,797 +$ +484,965 +$ +433,997 +Long-lived assets: +United States +$ +8,988 +$ +11,406 +$ +8,969 +Mexico +20,878 +15,756 +17,156 +China +630 +763 +849 +Total +$ +30,496 +$ +27,925 +$ +26,974 +53 +Percentage of net sales made to customers located in the following countries: +Fiscal Year Ended +2017 +2016 +2015 +United States +77% +72% +70% +Canada +1 +7 +10 +Other foreign countries (a) +22 +21 +20 +Total +100% +100% +100% +(a) No other individual foreign country accounted for 10% or more of the foreign sales in fiscal years 2017, 2016 or 2015. +Significant Customers +The percentage of net sales to and trade accounts receivables from significant customers were as follows: +Percentage of Net +Sales Fiscal Year +Percentage of +Trade Accounts Receivable +Fiscal Year +2017 +2016 +2015 +2017 +2016 +Customer A +18% +18% +17% +30% +24% +13. QUARTERLY FINANCIAL DATA (Unaudited) +Fiscal Year Ended July 1, 2017 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +(in thousands, except per share amounts) +Net sales +$ +117,135 +$ +118,517 +$ +113,601 +$ +118,544 +Gross profit +9,709 +9,612 +9,139 +9,840 +Income before income taxes +2,201 +1,995 +1,283 +1,777 +Net income +1,792 +1,528 +961 +1,336 +Earnings per common share-basic +$ +0.17 +$ +0.14 +$ +0.09 +$ +0.12 +Earnings per common share-diluted +$ +0.16 +$ +0.14 +$ +0.09 +$ +0.12 +Weighted average shares outstanding +Basic +10,748 +10,758 +10,759 +10,760 +Diluted +10,922 +10,968 +10,957 +10,856 +Fiscal Year Ended July 2, 2016 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +(in thousands, except per share amounts) +Net sales +$ +126,209 +$ +116,403 +$ +118,448 +$ +123,905 +Gross profit +8,919 +9,110 +9,955 +10,841 +Income before income taxes +1,247 +1,882 +2,137 +2,885 +Net income +817 +1,787 +1,783 +2,146 +Earnings per common share-basic +$ +0.08 +$ +0.17 +$ +0.17 +$ +0.20 +Earnings per common share-diluted +$ +0.07 +$ +0.16 +$ +0.16 +$ +0.20 +Weighted average shares outstanding +Basic +10,706 +10,710 +10,711 +10,714 +Diluted +11,391 +11,418 +11,068 +10,966 +54 +14. ACQUISITION +On September 3, 2014, the Company acquired all of the outstanding stock of Ayrshire, resulting in Ayrshire becoming a wholly owned subsidiary of the Company. Ayrshire provides printed circuit board assembly and other electronic manufacturing services to a diversified customer base through manufacturing facilities operated by Ayrshire or its subsidiaries in Minnesota, Arkansas, Mississippi, and Kentucky and through a sheltered maquiladora facility in Reynosa, Mexico. The Reynosa, Mexico operations were moved to the Company's existing facility in Juarez, Mexico shortly after acquisition. During the second quarter of fiscal year 2017, the Company closed the Harrodsburg, Kentucky facility in order to improve operating efficiencies. The remaining programs from the Kentucky facility were transferred to other facilities. This acquisition expanded our printed circuit board assembly capacity, total revenue, and added to and diversified our customer base with the addition of many new multi-national companies. The total cash payment of approximately $48.0 million was funded through borrowings on our term loan, revolving line of credit, and cash on hand. The Company incurred approximately $775,000 of costs related to due diligence. +The following table summarizes the purchase price paid for Ayrshire and the fair value of the assets acquired and liabilities assumed as of the date of acquisition (in thousands): +Estimated Fair Values +At September 3, 2014 +Purchase Price Paid +$ +48,010 +Cash Acquired +(46 +) +Purchase Price, Net of Cash Received +$ +47,964 +Cash +$ +46 +Accounts Receivable +21,211 +Inventories +21,772 +Other Current Assets +1,013 +Property, Plant and Equipment +7,823 +Favorable Leases +2,941 +Customer Relationships +2,833 +Non-Compete Agreements +196 +Goodwill +8,217 +Other Assets +42 +Accounts Payable +(11,070 +) +Accrued Salaries and Wages +(2,188 +) +Other Current Liabilities +(2,408 +) +Deferred Tax Liability +(2,418 +) +Fair Value of Assets Acquired +$ +48,010 +The Ayrshire acquisition was accounted for using the acquisition method of accounting whereby the total purchase price is allocated to tangible and intangible assets and liabilities based on their fair values on the date of acquisition. The Company determined the purchase price allocations on the acquisition based on estimates of the fair values of the assets acquired and liabilities assumed. +The following summary pro forma condensed consolidated financial information reflects the Ayrshire acquisition as if it had occurred on June 30, 2013 for purposes of the statements of income. This summary pro forma information is not necessarily representative of what the Company’s results of operations would have been had this acquisition in fact occurred on June 30, 2013 and is not intended to project the Company’s results of operations for any future period. +55 +Pro forma condensed consolidated financial information for the year ended June 27, 2015 (in thousands): +Fiscal Year Ended +(unaudited) +June 27, 2015 +Net sales +$ +457,475 +Net income +$ +4,136 +It is impracticable to determine the revenue and net income related to the Ayrshire acquisition as certain customer programs have been transferred to the Company’s Juarez facilities. +15. GOODWILL AND OTHER INTANGIBLE ASSETS +The Company recorded goodwill in connection with the Ayrshire and Sabre acquisitions resulting primarily from the synergies that resulted from the Company's acquisitions and the assembled workforce. The goodwill is not amortized for financial accounting purposes. The goodwill from the acquisitions is not deductible for tax purposes. As of July 1, 2017 and July 2, 2016 , goodwill was recorded at $10.0 million . +The components of acquired intangible assets are as follows (in thousands): +July 1, 2017 +Amortization Period +in Years +Gross Carrying +Amount +Accumulated +Amortization +Net Carrying +Amount +Other intangible assets: +Non-Compete Agreements +3 - 5 +$ +568 +$ +(483 +) +$ +85 +Customer Relationships +10 +4,803 +(1,590 +) +3,213 +Favorable Lease Agreements +4 - 7 +2,941 +(1,439 +) +1,502 +Total +$ +8,312 +$ +(3,512 +) +$ +4,800 +July 2, 2016 +Amortization Period +in Years +Gross Carrying +Amount +Accumulated +Amortization +Net Carrying +Amount +Other intangible assets: +Non-Compete Agreements +3 - 5 +$ +568 +$ +(343 +) +$ +225 +Customer Relationships +10 +4,803 +(1,110 +) +3,693 +Favorable Lease Agreements +4 - 7 +2,941 +(931 +) +2,010 +Total +$ +8,312 +$ +(2,384 +) +$ +5,928 +Amortization expense related to intangible assets was approximately $1.1 million for the years ended July 1, 2017 and July 2, 2016 , respectively. +Aggregate amortization expense related to existing intangible assets by fiscal year is currently estimated to be as follows (in thousands): +Fiscal Years Ending +Amount +2018 +$ +1,073 +2019 +818 +2020 +783 +2021 +784 +2022 +531 +Thereafter +811 +Total amortization expense +$ +4,800 +56 +Item 9: +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES +None +Item 9A: +CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +It is the responsibility of our management to establish, maintain, and monitor disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 are recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Additionally, these disclosure controls include controls and procedures that are designed to accumulate and communicate the information required to be disclosed to our Company’s Chief Executive Officer and Chief Financial Officer, allowing for timely decisions regarding required disclosures. As of the end of the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(f). Based on our assessment, we believe that as of July 1, 2017 , the Company’s disclosure controls and procedures are effective based on that criteria. +Management’s Report on Internal Control over Financial Reporting +Our management has the responsibility to establish and maintain adequate internal controls over our financial reporting, as defined in Rule 13a-15(f) under the Securities and Exchange Act of 1934. Our internal controls are designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our external financial statements in accordance with generally accepted accounting principles (GAAP). +Due to inherent limitations of any internal control system, management acknowledges that there are limitations as to the effectiveness of internal controls over financial reporting and therefore recognize that only reasonable assurance can be gained from any internal control system. Accordingly, our internal control system may not detect or prevent material misstatements in our financial statements and projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, we have performed an assessment of the effectiveness of our internal controls over financial reporting as of July 1, 2017 . This assessment was based on the criteria established in Internal Control-Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that as of July 1, 2017 , the Company’s internal control over financial reporting is effective based on that criteria. +The effectiveness of the Company's internal control over financial reporting as of July 1, 2017 has been audited by BDO USA LLP, an independent registered public accounting firm, as stated in their report which is included herein. +Changes in Internal Control over Financial Reporting +There have been no significant changes in our internal controls over financial reporting during our fourth fiscal quarter ended July 1, 2017 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)). +57 +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Key Tronic Corporation +Spokane Valley, Washington +We have audited Key Tronic Corporation's internal control over financial reporting as of July 1, 2017 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Key Tronic Corporation's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Item 9A “Management's Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, Key Tronic Corporation maintained, in all material respects, effective internal control over financial reporting as of July 1, 2017 , based on the COSO criteria . +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Key Tronic Corporation as of July 1, 2017 and July 2, 2016 , and the related consolidated statements of income, comprehensive income (loss), shareholders' equity, and cash flows for each of the three years in the period ended July 1, 2017 and our report dated September 8, 2017 , expressed an unqualified opinion thereon. +/s/ BDO USA, LLP +Spokane, Washington +September 8, 2017 +58 +Item 9B: +OTHER INFORMATION +None +PART III +Item 10: +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Directors of the Registrant +Information on the nominees for election as Directors of the Company is incorporated by reference from the Company’s definitive proxy statement for the 2017 Annual Meeting of Shareholders to be filed pursuant to Regulation 14A under the Exchange Act no later than 120 days after the end of the Company’s 2017 fiscal year. +Executive Officers of the Registrant +This information is included in a separate item captioned “Executive Officers of the Registrant” in Item 1 of Part 1 of this report pursuant to Instruction G(3) of Form 10-K and Instruction 3 to Item 401(b) of Regulation S-K. +Compliance with Section 16(a) of the Exchange Act: +Incorporated by reference to Key Tronic Corporation’s 2017 Proxy Statement to Shareholders. +Code of Conduct +The Board of Directors has adopted a written Code of Conduct which applies to its directors and employees, including its executive officers. The Code of Conduct is available on the Company’s website at www.keytronic.com . The Company intends to disclose on its website any amendments to or waivers of the Code of Conduct. +Item 11: +EXECUTIVE COMPENSATION +Information appearing under the caption “Executive Compensation” in the Company’s 2017 Proxy Statement is incorporated herein by this reference. +Item 12: +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The following table sets forth the aggregate information for the Company’s equity compensation plans in effect as of July 1, 2017 . +EQUITY COMPENSATION PLAN INFORMATION +Plan category +Number of securities to +be issued upon exercise +of outstanding options, +warrants, and rights +(a) +Weighted-average +exercise price of +outstanding options, +warrants, and rights +(b) +Number of securities +remaining available for +future issuance under +equity compensation +plans (excluding +securities reflected in +column (a) +(c) +Equity compensation plans approved by security holders (1) +1,084,999 +$ +9.09 +394,335 +Equity compensation plans not approved by security holders +— +$ +— +— +Total +1,084,999 +$ +9.09 +394,335 +(1) +Included are the 1,200,000 shares subject to the 2010 Plan, the issuance of which were approved by the shareholders at the 2010 Annual Meeting. During the 2015 Annual Meeting, an additional 1,000,000 shares were approved. As a result of the shareholder approval, the Company made the decision to amend the cash-settled SARs granted during fiscal year 2010 to stock-settled SARs effective October 21, 2011. +Information under the caption “Beneficial Ownership of Securities” in the Company’s 2017 Proxy Statement is incorporated herein by this reference. +59 +Item 13: +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions”, “Compensation Committee Interlocks and Insider Participation”, and “Directors’ Independence” in the Company’s 2017 Proxy Statement is incorporated herein by this reference. +Item 14: +PRINCIPAL ACCOUNTING FEES AND SERVICES +Information appearing under the caption “Principal Accountant Fees and Services” in the Company’s 2017 Proxy Statement is incorporated herein by this reference. +PART IV +Item 15: +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +(a) 1. FINANCIAL STATEMENTS +Page in Form 10-K +FINANCIAL STATEMENTS +Report of Independent Registered Public Accounting Firm +31 +Consolidated Balance Sheets +32 +Consolidated Statements of Income +33 +Consolidated Statements of Comprehensive Income (Loss) +34 +Consolidated Statements of Cash Flows +35 +Consolidated Statements of Shareholders’ Equity +36 +Notes to Consolidated Financial Statements +37-56 +2. SCHEDULES +II. Consolidated Valuation and Qualifying Accounts +64 +Other schedules are omitted because of the absence of conditions under which they are required, or because required information is given in the financial statements or notes thereto. +60 +3. EXHIBITS +Exhibit No. +Description +3.1 +Articles of Incorporation, incorporated by reference to the Exhibit 3.1 to the Company’s form 10-K filed with the SEC for the year ended July 1, 1995 (File No. 2-83898) +3.2 +Bylaws, as amended, incorporated by reference to the Exhibit 3 (iii) to the Company’s Form 10-K for the year ended July 1, 1995 (File No. 2-83898) +10.1* +Amended and Restated 1990 Stock Option Plan for Non-Employee Directors, as amended, incorporated by reference to the Company’s 1997 Proxy Statement dated October 10, 1997 (Proposal 2) +10.2* +1995 Executive Stock Option Plan, incorporated by reference to the Company’s 1995 Proxy Statement, pages 19-22 (Proposal 3) +10.3* +2000 Employee Stock Option Plan, incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.4* +Officers’ Employment Contracts, incorporated by reference to the Company’s 1998 Proxy Statement, pages 10 and 11 +10.5* +Addenda to Officers’ Employment Contracts, incorporated by reference to Exhibits to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.6* +Description of Retention Bonus Plan, incorporated by reference to the Exhibits to the Company’s 10-Q for the quarter ended December 28, 2002 +10.7* +Addenda to Officers’ Employment Contracts, incorporated by reference to Exhibits to the Company’s Form 10-K for the year ended June 29, 2002 +10.8 +Promise to execute a Purchase and Sale Agreement with Key Safety Systems de Mexico, S.A. de C.V., incorporated by reference to the Exhibit to the Company’s Form 8-K filed April 26, 2005 +10.9 +Summary of material terms and conditions of the Purchase and Sale Agreement with Key Safety Systems de Mexico, S.A. de C.V., incorporated by reference to the Exhibit to the Company’s Form 8-K filed June 6, 2005 +10.10* +Summary of Key Tronic Corporation Long Term Incentive Compensation Plan, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed September 27, 2005 +61 +10.11* +Summary of Key Tronic Corporation Incentive Compensation Plan, incorporated by reference to Exhibit 10.23 to the Company’s Form 10-K for the year ended July 2, 2005 +10.12* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2007 and Fiscal Years 2007 – 2009 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 28, 2006 +10.13 +Summary of material terms and conditions of the Purchase and Sale Agreement with Todenko Mexico S.A. de C.V., incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed October 12, 2006 +10.14 +Summary of material terms and conditions of the Purchase and Sale Agreement with Todenko Mexico S.A. de C.V., incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed November 20, 2006 +10.15 +Summary of material terms and conditions of the Sale and Purchase Agreement with Adevco Corporation, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed January 5, 2007 +10.16 +Summary of Second Amendment to Agreement of Sale and Purchase Agreement with Adevco Corporation, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed April 11, 2007 +10.17* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2008 and Fiscal Years 2008-2010 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 27, 2007 +10.18* +Summary of Incentive Compensation Plan Performance Goals and Target payments for Fiscal Year 2009 and Fiscal Years 2009 – 2011 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 24, 2008 +10.19* +Summary of Incentive Compensation Plan Performance Goals and Target payments for Fiscal Year 2010 and Fiscal Years 2010 – 2012 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 23, 2009 +10.20 +Financing Agreement with Wells Fargo Bank, N.A., incorporated by reference to the Exhibits to the Company’s Form 8-K filed on August 24, 2009 +10.21* +2010 Incentive Plan, incorporated by reference to Exhibit 10.36 to the Company’s Form 10-K for the year ended July 3, 2010 +10.22* +Employment Contract with Douglas G. Burkhardt, incorporated by reference to Exhibit 10.37 to the Company’s Form 10-K for the year ended July 3, 2010 +10.23 +Summary of material terms and conditions of the Purchase and Sale Agreement with Autopartes Y Arneses de Mexico S.A. de C.V., incorporated by reference to Exhibit 10.38 to the Company’s Form 10-K for the year ended July 3, 2010 +10.24* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2011 and Fiscal Years 2011 – 2013 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 23, 2010 +10.25* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2012 and Fiscal Years 2012 – 2014 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 2, 2011 +62 +10.26* +Amendment to Employment Contract of Craig D. Gates, dated August 23, 2011; of Ronald F. Klawitter, dated August 23, 2011 and of Douglas G. Burkhardt dated September 6, 2011; incorporated by reference to the Exhibits to the Company’s Form 10-K for the year ended July 2, 2011 filed on September 12, 2011 +10.27 +Second Loan Modification Agreement to the Credit Agreement with Wells Fargo Bank, N.A., incorporated by reference to the Exhibits to the Company’s Form 8-K filed on February 2, 2012 +10.28* +Amendment to Employment Contract of Craig D. Gates, dated May 10, 2012, incorporated by reference to the Exhibits to the Company’s Form 10-Q filed on May 14, 2012 +10.29* +Amendment to Employment Contract of Douglas G. Burkhardt dated May 10, 2012; incorporated by reference to the Exhibits to the Company’s Form 10-Q filed on May 14, 2012 +10.30* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2013 and Fiscal Years 2013 – 2015 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 7, 2012 +10.31* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2014 and Fiscal Years 2014 – 2016 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 6, 2013 +10.32* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2015 and Fiscal Years 2015 – 2017 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 1, 2014 +10.33 +Summary of material terms and conditions of the Stock Purchase Agreement with CDR Manufacturing and Amended and Restated Credit Agreement with Wells Fargo Bank, N. A. incorporated by reference to the Company’s Form 8-K filed September 9, 2014 +10.34* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2016 and Fiscal Years 2016 – 2018 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 30, 2015 +10.35 +First Amendment to Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, incorporated by reference to the Company's Form 8-K filed August 11, 2015 +10.36 +Second Replacement Revolving Line of Credit Note with Wells Fargo Bank, National Association, incorporated by reference to the Company's Form 8-K filed August 11, 2015 +10.37* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2017 and Fiscal Years 2017 – 2019 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 29, 2016 +10.38* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2018 and Fiscal Years 2018 – 2020 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 22, 2017 +21 +Subsidiaries of Registrant, submitted herewith +23.1 +Consent of Independent Registered Public Accounting Firm, submitted herewith +63 +31.1 +Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer, submitted herewith +31.2 +Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer, submitted herewith +32.1 +Section 1350 Certification of Chief Executive Officer, submitted herewith +32.2 +Section 1350 Certification of Chief Financial Officer, submitted herewith +101.INS +XBRL Instance Document ** +101.SCH +XBRL Taxonomy Extension Schema Document ** +101.CAL +XBRL Taxonomy Extension Calculation Linkbase Document ** +101.DEF +XBRL Taxonomy Extension Definition Linkbase Document ** +101.LAB +XBRL Taxonomy Extension Label Linkbase Document ** +101.PRE +XBRL Taxonomy Extension Presentation Linkbase Document ** +* +Management contract or compensatory plan or arrangement +** +Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities and Exchange Act of 1934, as amended and otherwise are not subject to liability under those sections. +SCHEDULE II +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS +FISCAL YEARS ENDED JULY 1, 2017 , JULY 2, 2016 , AND JUNE 27, 2015 +Fiscal Year Ended +2017 +2016 +2015 +(in thousands) +Allowance for Obsolete Inventory +Balance at beginning of year +$ +1,113 +$ +417 +$ +332 +Provisions +496 +757 +520 +Dispositions +(303 +) +(61 +) +(435 +) +Balance at end of year +$ +1,306 +$ +1,113 +$ +417 +Allowance for Doubtful Accounts +Balance at beginning of year +$ +135 +$ +97 +$ +— +Provisions +(10 +) +38 +97 +Write-offs +(41 +) +— +— +Balance at end of year +$ +84 +$ +135 +$ +97 +64 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +Dated: September 8, 2017 +KEY TRONIC CORPORATION +By: +/s/ Craig D. Gates +Craig D. Gates, President and Chief Executive Officer +(Principal Executive Officer) +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated: +/s/ Craig D. Gates +September 8, 2017 +Craig D. Gates +Date +Director and President and Chief Executive Officer +(Principal Executive Officer) +/s/ Brett R. Larsen +September 8, 2017 +Brett R. Larsen +Date +Executive Vice President of Administration, Chief Financial Officer and Treasurer +(Principal Financial Officer) +/s/ Ronald F. Klawitter +September 8, 2017 +Ronald F. Klawitter, Director +Date +/s/ James R. Bean +September 8, 2017 +James R. Bean, Director +Date +/s/ Yacov A. Shamash +September 8, 2017 +Yacov A. Shamash, Director +Date +/s/ Patrick Sweeney +September 8, 2017 +Patrick Sweeney, Director and Chairman of the Board +Date +65 \ No newline at end of file diff --git a/raw/filings/0000719733/2017/0000719733-17-000028/filing_metadata.csv b/raw/filings/0000719733/2017/0000719733-17-000028/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..223f913c9fdb06504de14ac46c37fbc5d95d79e2 --- /dev/null +++ b/raw/filings/0000719733/2017/0000719733-17-000028/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000719733,KTCC,KEY TRONIC CORP,10-K,2017-09-11,2017-07-01,2017-09-08T21:36:03.000Z,0000719733-17-000028,ktcc-07012017x10k.htm,10-K,8469068,1,0,https://www.sec.gov/Archives/edgar/data/719733/000071973317000028/ktcc-07012017x10k.htm,https://www.sec.gov/Archives/edgar/data/719733/000071973317000028/,2017,2017,1 diff --git a/raw/filings/0000719733/2017/0000719733-17-000028/item1.txt b/raw/filings/0000719733/2017/0000719733-17-000028/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..a0f8736ccf47ec2bc5a59223af7dc1b63d523e94 --- /dev/null +++ b/raw/filings/0000719733/2017/0000719733-17-000028/item1.txt @@ -0,0 +1,104 @@ +Item 1. +BUSINESS +Background +Key Tronic Corporation (dba: KeyTronicEMS Co.) was organized in 1969, as a Washington corporation that locally manufactured computer keyboards. The ability to design, build and deliver a quality product led us to become a leading independent manufacturer of keyboards for computers in the United States. Our fully integrated design, tooling, and automated manufacturing capabilities enabled us to rapidly respond to customers’ needs for keyboards in production quantities worldwide. We supported our sales growth through the development and purchase of international manufacturing facilities. As the computer keyboard market matured with increasing competition from other international providers, we determined that our business could no longer solely rely on keyboard sales. +After assessing market conditions and our strengths and capabilities, we shifted our focus from keyboard manufacturing to contract manufacturing for a wide range of products. Our unique strategic attributes are based on our core strengths of innovative design and engineering expertise in electronics, mechanical engineering, sheet metal fabrication and stamping, and precision plastics combined with high-quality, low cost production, and assembly on an international basis while providing exceptional customer service. These strengths have made our company a strong competitor in the electronic manufacturing services (EMS) market. +Acquisition +On September 3, 2014, we completed the acquisition of all of the outstanding shares of CDR Manufacturing, Inc. (dba Ayrshire Electronics), which added five locations (four in North America and one in Mexico). This acquisition expanded our printed circuit board assembly capacity, total revenue, and added to and diversified our customer base with the addition of many new multi-national companies. Subsequent to the acquisition, the Reynosa, Mexico operations were transferred to the Company’s existing Juarez, Mexico facilities. During the second quarter of fiscal year 2017, we closed the Harrodsburg, Kentucky facility in order to improve operating efficiencies. The remaining programs from the Kentucky facility have been transferred to other Key Tronic facilities. +Our Industry and Strategy +The expansion of the EMS industry and our acquisitions have allowed us to continue to expand our customer base and the industries that we serve. The increase in new programs represents a growing portion of our revenue and a promising foundation for our future. In keeping with our long-term strategic objectives, we have been successfully building a more diversified customer portfolio, spanning a wider range of industries. We currently offer our customers the following services: integrated electronic and mechanical engineering, precision plastic molding, sheet metal fabrication, printed circuit board (PCB) and complete product assembly, component selection, sourcing and procurement, worldwide logistics, and new product testing and production all at competitive pricing due to our global footprint. We differentiate ourselves from others our size and larger in the EMS industry by providing vertical integration, a flexible and responsive approach to our customer’s changing supply demand, and complete design engineering support. +4 +We believe that we are well positioned in the EMS industry to continue the expansion of our customer base and achieve long term growth. Our unique blend of multinational facilities, vertical integration, centralized management, and core strengths continue to support our growth and our customers’ needs. We continue to focus on controlling operating expenses and leveraging the synergistic capabilities of our world-class facilities in the United States, Mexico, and China. This international production capability provides our customers with the benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs, and reduced product fulfillment time. Given our competitive advantages and the growing pressure for new potential customers to move forward with their outsourcing strategies, we are strongly positioned to win new business in coming periods and grow our revenue and profits. +The EMS industry is intensely competitive. Although our customer base is growing, we still have less than 1% of the potential global market and our revenue can fluctuate significantly due to reliance on a concentrated base of customers. We are planning for new customer growth in the coming quarters by securing new programs with new and existing customers, increasing our worldwide manufacturing capacity, leveraging further our design engineering capabilities and continuing to improve our manufacturing and procurement processes. Ongoing challenges that we face include but are not limited to the following: Continuing to win programs from new and existing customers, balancing capital employed, production capacity and key personnel in support of new customer programs, improving operating efficiencies, controlling costs while developing competitive pricing strategies, and successfully transitioning new program wins to full production. +Customers and Marketing +We provide a mix of manufacturing services for outsourced Original Equipment Manufacturing (OEM) products. We provide the following EMS services: Product design, surface mount technologies (SMT) and pin through hole capability for printed circuit board assembly, tool making, precision plastic molding, sheet metal fabrication, liquid injection molding, complex assembly, automated tape winding, prototype design and full product assembly. +Sales of the majority of our products have not historically been seasonal in nature, but may be seasonal in the future if there are changes in the types of products manufactured. Sales can, however, fluctuate significantly between quarters from changes in customers and customer demand due to the concentration of sales generated by our largest customers. +For the fiscal years 2017 , 2016 and 2015 , the five largest customers in each year accounted for 42%, 41% and 42% of combined total net sales, respectively. We continue to diversify our customer base by adding additional programs and customers. We expect net sales to our five largest customers as a percentage of total net sales to approximate current levels going forward. +The following table represents all customers that represented 10% or more of total net sales during the last three fiscal years: +Percentage of Net Sales by Fiscal Year +2017 +2016 +2015 +Customer A +18% +18% +17% +There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +We market our products and services primarily through our direct sales department which is comprised of strategically located field sales people and distributors. We also maintain relationships with several independent sales organizations to assist in marketing our EMS product lines. +Manufacturing +We have continually made investments in developing and expanding a capital equipment base to achieve vertical integration and efficiencies in our manufacturing processes. We have invested significant capital into SMT for volume manufacturing of complex printed circuit board assemblies and in our metal shop providing precision metal stamping, fabricating, and finishing. We also design and develop tooling for injection molding and sheet metal fabrication and manufacture the majority of plastic and sheet metal parts used in the products we manufacture. Additionally, we have equipment to maintain a controlled clean environment for manufacturing processes that require a high level of precise control. +We use a variety of manual and automated assembly processes in our facilities, depending upon product complexity and degree of customization. Some examples of automated processes include component insertion, SMT, selective soldering, flexible robotic assembly, automated storage tape winding, computerized vision system quality inspection, laser turrets, automated switch and key top installation, and automated functional testing. +5 +Our engineering expertise and automated manufacturing processes enable us to work closely with our customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. We use computer-aided design techniques and software to assist in preparation of the tool design layout and component placement, to reduce tooling and production costs, improve component and product quality, and enhance turnaround time during product development. +We purchase materials and components for our products from many different suppliers, including both domestic and international sources. We develop close working relationships with our suppliers, many of whom have been supplying products to us for several years. +Research, Development, and Engineering +As part of our long-term strategy, we are committed to supporting our customers by providing research, development, and engineering services. We have recently seen an increase in the success of providing design support on existing and potential customers in differentiating ourselves. These services allow us to facilitate in optimizing new product designs, and the production processes of our customers' programs. +Research, development, and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials costs, depreciation, and allocated information technology and facilities costs. +Competition +The market for the products and services we provide is highly competitive. There are numerous competitors in the EMS industry, many of which have substantially more resources and are more geographically diverse than we are. Some of our competitors have similar international production capabilities, large financial resources and some have substantially greater manufacturing, research and development, and marketing resources. There is also competition from the manufacturing operations of our current and potential customers, who are continually evaluating the merits of manufacturing their products internally versus the advantages of outsourcing. We believe that we can currently compete favorably in these areas primarily on the basis of our international footprint, responsiveness, creativity, vertical production capability, quality, and cost. +Trademarks +Our name and logo are federally registered trademarks, and we believe they are valuable assets of our business. We operate under the trade name “KeyTronicEMS” to better identify our primary business concentration in contract manufacturing in the EMS industry. +Employees +We consider our employees to be our primary strength and we make considerable efforts to maintain a well-qualified workforce. Our employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. We regularly provide transportation, medical services, and meals to all of our employees in foreign locations. The Company also has defined contribution plans available to U.S. employees who have attained age 21 and provide group health, life, and disability insurance plans. We also maintain share based compensation plans and other long term incentive plans for certain employees and outside directors. +As of July 1, 2017 we had 5,038 full-time employees compared to 4,947 on July 2, 2016 , and 4,866 on June 27, 2015 . Since we can have significant fluctuations in product demand, we seek to maintain flexibility in our workforce by utilizing skilled temporary and short-term contract labor in our manufacturing facilities in addition to full-time employees. +Backlog +On July 29, 2017 our order backlog was valued at approximately $126.9 million, compared to approximately $122.2 million on July 30, 2016. The amount of backlog is not necessarily indicative of future sales but can be indicative of trends in expected future sales revenue. Due to the relationships with our customers, we will occasionally allow orders to be canceled or rescheduled and as a result it is not a meaningful indicator of future financial results. If there are canceled or rescheduled orders, we typically negotiate fees to cover the costs we have incurred. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change due to design modifications, customer forecast changes, or other customer requirements. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in Note 12, “Enterprise-Wide Disclosures” of the consolidated financial statements of this Annual Report on Form 10-K and that information is incorporated herein. +6 +Executive Officers of the Registrant +The table below sets forth the name, current age and current position of our executive officers and other significant employees: +Name +Age +Positions Held +Executive Officers +Craig D. Gates +58 +President and Chief Executive Officer +Brett R. Larsen +44 +Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Douglas G. Burkhardt +59 +Executive Vice President of Worldwide Operations +Philip S. Hochberg +55 +Executive Vice President of Business Development +Lawrence J. Bostwick +65 +Vice President of Regulatory Affairs +David H. Knaggs +36 +Vice President of Quality +Frank Crispigna III +56 +Vice President of Materials +Duane D. Mackleit +49 +Vice President of Program Management +Chad T. Orebaugh +46 +Vice President of Engineering +Executive Officers +CRAIG D. GATES – President and Chief Executive Officer +Mr. Gates, age 58 , has been President and Chief Executive officer of the Company since April 2009. Previously, he was Executive Vice President and General Manager from August 2002 to April 2009. He served as Executive Vice President of Marketing, Engineering and Sales from July 1997 to August 2002 and served as Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of 1994. From 1982 to 1991 he held various engineering and management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. Mr. Gates has a Bachelor of Science Degree in Mechanical Engineering and a Masters in Business Administration from the University of Illinois, Urbana. +BRETT R. LARSEN – Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Mr. Larsen, age 44 , has served as Executive Vice President of Administration, Chief Financial Officer, and Treasurer since July 2015. Previously, he was Vice President of Finance and Controller from February 2010 to July 2015. He was Chief Financial Officer of FLSmidth Spokane, Inc. from December 2008 to February 2010. From October 2005 through November 2008, Mr. Larsen served as Controller of Key Tronic Corporation. From May 2004 to October 2005, Mr. Larsen served as Manager of Financial Reporting of Key Tronic Corporation. From 2002 to May 2004, Mr. Larsen was an audit manager for the public accounting firm BDO USA, LLP. He also held various auditing and supervisory positions with Grant Thornton LLP from 1997 to 2002. Mr. Larsen has a Bachelor of Science degree in Accounting and a Masters degree in Accounting from Brigham Young University and is a Certified Public Accountant. +DOUGLAS G. BURKHARDT – Executive Vice President of Worldwide Operations +Mr. Burkhardt, age 59 , has been Executive Vice President of Worldwide Operations of the Company since July 2010. Previously Mr. Burkhardt was Vice President of Worldwide Operations from July 2008 to July 2010 and Director of China Operations and Program Management from January 2006 to July 2008. Mr. Burkhardt also served as Director of Northwest and China Operations from November of 1998 to January of 2006. Mr. Burkhardt also served as Director of Customer Satisfaction from March 1997 to November 1998 and Director of Molding from September of 1995 to March of 1997. Prior to this, Mr. Burkhardt served in other various senior management positions within the Company. Mr. Burkhardt has been with the Company since May of 1989. Prior to joining Key Tronic, Mr. Burkhardt worked for House of Aluminum and Glass for 12 years where he was the plant manager. +PHILIP S. HOCHBERG – Executive Vice President of Business Development +Mr. Hochberg, age 55 , has been Executive Vice President of Business Development since July 2012. Prior to this, Mr. Hochberg served as Vice President of Business Development from October 2009 through June 2012. He was Director of Business Development and Program Management from July 2008 to October 2009. Mr. Hochberg served as Director of Business Development from October 2004 to July 2008 and as Director of EMS Sales and Marketing from July 2000 to October 2004. Prior to joining Key Tronic, Mr. Hochberg worked for Quinton Instrument Company as their Director of Marketing and Product Management from 1992 to 2000. From 1988 to 1992, he was employed by SpaceLabs Medical as their Business Development Marketing Manager. Mr. Hochberg has an MBA from the University of British Columbia, a BA in Psychology, with a minor in Business from Washington University in St. Louis. +7 +LAWRENCE J. BOSTWICK – Vice President of Regulatory Affairs +Mr. Bostwick, age 65 , has been Vice President of Engineering and Quality since July 2008. Previously he was Director of Engineering and Quality from February 2007 to July 2008 and served as Corporate Director of Quality from February 2006 to February 2007. From 2003 to 2006 he was Director of Supply Chain Management and Quality for the Lancer Corporation and from 1998 to 2003 he was Vice President of Operations for Thermacore International. He is a graduate of the Westinghouse and General Electric – Engineering and Manufacturing Professional Development Programs. He is certified in both Quality and Industrial Engineering and is a Lean – Six Sigma Master Black Belt. Mr. Bostwick has a combined B.S. degree in Production and Operation and Industrial Engineering from Bowling Green State University and a Masters degree in Industrial Engineering and Business Administration from Syracuse University. +DAVID H. KNAGGS – Vice President of Quality +Mr. Knaggs, age 36 , has been Vice President of Quality of the company since October 2016. Before joining KeyTronicEMS, Mr. Knaggs worked at Telect, Inc. from 2008 to 2016 as their Director of Engineering. Prior to that, he worked at Isothermal Systems Research as Lead Systems Engineer from 2003 to 2008. He has a Bachelor of Science degree in Mechanical Engineering with a minor in mathematics from the University of Washington. +FRANK CRISPIGNA III – Vice President of Materials +Mr. Crispigna, age 56 , has been Vice President of Materials of the company since October 2011. Prior to this, Mr. Crispigna held a variety of Materials and Supply Chain positions at Plexus Corporation since 1997, most recently serving as the Director – Supply Chain Solutions from 2005 - 2011. He has a Masters degree in Business Administration, and a Bachelor of Business Administration Degree in Marketing from the University of Wisconsin – Oshkosh. Mr. Crispigna also is a C.P.M., and received his certification in Supply Chain Leadership from the University of Wisconsin. +DUANE D. MACKLEIT – Vice President of Program Management +Mr. Mackleit, age 49 , has been Vice President of Program Management of the company since July 2012. He served as Director of Program Management from July 2008 through June 2012. From May 2006 to July 2008 he served as Principal Program Manager. Prior to that, he served as Program Manager from March 2002 to May 2006 and Associate Program Manager from August 2000 to March 2002. Mr. Mackleit has also held several other positions with Key Tronic Corporation. Mr. Mackleit has an AA in Business from Spokane Falls Community College and a BA in Business/Marketing from Eastern Washington University. He also holds a MBA from Gonzaga University. +CHAD T. OREBAUGH – Vice President of Engineering +Mr. Orebaugh, age 46 , has been Vice President of Engineering since April 2017. Prior to this, Mr. Orebaugh served as Director of Engineering since May 2013. From April 2010 to May 2013, he served as Manager of Engineering. From January 2000 to April 2010 he served as Lead Mechanical Engineer. Prior to that, he served as Mechanical Engineer from October 1998 to January 2000 and Associate Mechanical Engineer since October 1997. Mr. Orebaugh holds a BA in Mechanical Engineering from Gonzaga University. +Available Information +Our principal executive offices are located at 4424 North Sullivan Road, Spokane Valley, Washington 99216, and our telephone number is (509) 928-8000. Our website is located at http://www.keytronic.com where filings of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or current reports on Form 8-K are available after they have been filed with the Securities and Exchange Commission. The information presented on our website currently and in the future is not considered to be part of this document or any document incorporated by reference in this document. +8 \ No newline at end of file diff --git a/raw/filings/0000719733/2017/0000719733-17-000028/item13.txt b/raw/filings/0000719733/2017/0000719733-17-000028/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..df5743be1bac655c782d8327c71e59ea85983791 --- /dev/null +++ b/raw/filings/0000719733/2017/0000719733-17-000028/item13.txt @@ -0,0 +1,3 @@ +Item 13: +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions”, “Compensation Committee Interlocks and Insider Participation”, and “Directors’ Independence” in the Company’s 2017 Proxy Statement is incorporated herein by this reference. \ No newline at end of file diff --git a/raw/filings/0000719733/2017/0000719733-17-000028/item9a.txt b/raw/filings/0000719733/2017/0000719733-17-000028/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..28d7c41aefc4b1ab2b0ff91ec51dde768f76a5a6 --- /dev/null +++ b/raw/filings/0000719733/2017/0000719733-17-000028/item9a.txt @@ -0,0 +1,26 @@ +Item 9A: +CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +It is the responsibility of our management to establish, maintain, and monitor disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 are recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Additionally, these disclosure controls include controls and procedures that are designed to accumulate and communicate the information required to be disclosed to our Company’s Chief Executive Officer and Chief Financial Officer, allowing for timely decisions regarding required disclosures. As of the end of the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(f). Based on our assessment, we believe that as of July 1, 2017 , the Company’s disclosure controls and procedures are effective based on that criteria. +Management’s Report on Internal Control over Financial Reporting +Our management has the responsibility to establish and maintain adequate internal controls over our financial reporting, as defined in Rule 13a-15(f) under the Securities and Exchange Act of 1934. Our internal controls are designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our external financial statements in accordance with generally accepted accounting principles (GAAP). +Due to inherent limitations of any internal control system, management acknowledges that there are limitations as to the effectiveness of internal controls over financial reporting and therefore recognize that only reasonable assurance can be gained from any internal control system. Accordingly, our internal control system may not detect or prevent material misstatements in our financial statements and projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, we have performed an assessment of the effectiveness of our internal controls over financial reporting as of July 1, 2017 . This assessment was based on the criteria established in Internal Control-Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that as of July 1, 2017 , the Company’s internal control over financial reporting is effective based on that criteria. +The effectiveness of the Company's internal control over financial reporting as of July 1, 2017 has been audited by BDO USA LLP, an independent registered public accounting firm, as stated in their report which is included herein. +Changes in Internal Control over Financial Reporting +There have been no significant changes in our internal controls over financial reporting during our fourth fiscal quarter ended July 1, 2017 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)). +57 +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Key Tronic Corporation +Spokane Valley, Washington +We have audited Key Tronic Corporation's internal control over financial reporting as of July 1, 2017 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Key Tronic Corporation's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Item 9A “Management's Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit. +We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +In our opinion, Key Tronic Corporation maintained, in all material respects, effective internal control over financial reporting as of July 1, 2017 , based on the COSO criteria . +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Key Tronic Corporation as of July 1, 2017 and July 2, 2016 , and the related consolidated statements of income, comprehensive income (loss), shareholders' equity, and cash flows for each of the three years in the period ended July 1, 2017 and our report dated September 8, 2017 , expressed an unqualified opinion thereon. +/s/ BDO USA, LLP +Spokane, Washington +September 8, 2017 +58 \ No newline at end of file diff --git a/raw/filings/0000719733/2017/0000719733-17-000028/rp_note.txt b/raw/filings/0000719733/2017/0000719733-17-000028/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000719733/2017/0000719733-17-000028/rpt_disclosure.txt b/raw/filings/0000719733/2017/0000719733-17-000028/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..c13d9a30a53090342a57becdbc52720cd39f17d4 --- /dev/null +++ b/raw/filings/0000719733/2017/0000719733-17-000028/rpt_disclosure.txt @@ -0,0 +1,6 @@ +Related Person Transactions +In April 2007, the Board of Directors adopted a written policy and procedures for the approval or ratification of Interested Transactions with Related Parties. The policy and procedures supplement the Company’s Code of Conduct. The policy defines an “Interested Transaction” as any transaction, arrangement or relationship or series of similar transactions, arrangements or relationships (including any indebtedness or guarantee of indebtedness) in which (1) the aggregate amount involved will or may be expected to exceed $120,000 in any calendar year, (2) the Company is a participant, and (3) any Related Party has or will have a direct or indirect interest (other than solely as a result of being a director or a less than 10 percent beneficial owner of another entity). +The policy defines a “Related Party” as any (a) person who is or was (since the beginning of the last fiscal year for which the Company has filed a Form 10-K and proxy statement, even if they do not presently serve in that role) an executive officer, director or nominee for election as a director, (b) greater than 5 percent beneficial owner of the Company’s common stock, or (c) immediate family member of any of the foregoing. Immediate family member includes a person’s spouse, parents, stepparents, children, stepchildren, siblings, mothers- and fathers-in-law, sons- and daughters-in-law, and brothers- and sisters-in-law and anyone residing in such person’s home (other than a tenant or employee). +The Audit Committee is responsible for review, approval, ratification or disapproval of Interested Transactions. In determining whether to approve or ratify an Interested Transaction, the Committee will take into account, among other factors it deems appropriate, whether the Interested Transaction is on terms no less favorable than terms generally available to an unaffiliated third party under the same or similar circumstances and the extent of the Related Party’s interest in the Transaction. +During the fiscal year 2018, the Company purchased surface mount technology inspection equipment from CyberOptics. The purchases by the Company during fiscal year 2018 totaled $159,600. These transactions were conducted at arm’s length in the ordinary course of business of the Company and CyberOptics, and the terms of purchase were no more favorable to the Company than purchases by unaffiliated parties from CyberOptics. +6 \ No newline at end of file diff --git a/raw/filings/0000719733/2018/0000719733-18-000054/filing.txt b/raw/filings/0000719733/2018/0000719733-18-000054/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..b13c1a1ee1bb595982cb30741a5f1042a2b02df8 --- /dev/null +++ b/raw/filings/0000719733/2018/0000719733-18-000054/filing.txt @@ -0,0 +1,3501 @@ +10-K +1 +ktcc-06302018x10k.htm +10-K +Document +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +____________________________________________________________ +FORM 10-K +____________________________________________________________ +x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE FISCAL YEAR ENDED JUNE 30, 2018 +OR +¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE PERIOD FROM TO +Commission File Number 0-11559 +____________________________________________________________ +KEY TRONIC CORPORATION +(Exact name of registrant as specified in its charter) +____________________________________________________________ +Washington +91-0849125 +(State or other jurisdiction of +Incorporation or organization) +(I.R.S. Employer +Identification No.) +N. 4424 Sullivan Road, Spokane Valley, +Washington +99216 +(Address of principal executive offices) +(Zip Code) +(509) 928-8000 +(Registrant’s telephone number, including area code) +N/A +(Former name, former address and former fiscal year, if changed since last report) +____________________________________________________________ +Securities Registered Pursuant to Section 12(b) of the Act: None +Title of each class +Name of each exchange on which registered +Common stock, no par value +The NASDAQ Stock Market LLC +Securities Registered Pursuant to Section 12(g) of the Act: None +____________________________________________________________ +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ¨ No x +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulations S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. +(Check one): +Large accelerated filer +¨ +Accelerated filer +x +Non-accelerated filer +¨ (Do not check if a smaller reporting company) +Smaller reporting company +¨ +Emerging growth company +¨ +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x +State the aggregate market value of the voting and non-voting common equity held by non affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. +As of December 30, 2017, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $69.5 million based on the closing price as reported on the NASDAQ. +Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: 10,759,680 shares of common stock were outstanding as of September 4, 2018 . +____________________________________________________________ +Documents Incorporated by Reference: +Certain information is incorporated into Part III of this report by reference to the Proxy Statement for the registrant's 2018 annual meeting of stockholders to be filed with the Securities and Exchange Commission pursuant to Regulation 14A not later than 120 days after the end of the fiscal year covered by this Form 10-K. +KEY TRONIC CORPORATION +2018 FORM 10-K +TABLE OF CONTENTS +Page No. +PART I +Item 1. +Business +4 +Item 1A. +Risk Factors +9 +Item 1B. +Unresolved Staff Comments +15 +Item 2. +Properties +16 +Item 3. +Legal Proceedings +17 +Item 4. +Mine Safety Disclosures +17 +PART II +Item 5. +Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities +17 +Item 6. +Selected Financial Data +19 +Item 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +20 +Item 7A. +Quantitative and Qualitative Disclosures about Market Risk +31 +Item 8. +Financial Statements and Supplementary Data +32-57 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +57 +Item 9A. +Controls and Procedures +58 +Item 9B. +Other Information +60 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +60 +Item 11. +Executive Compensation +60 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +60 +Item 13. +Certain Relationships and Related Transactions, and Director Independence +61 +Item 14. +Principal Accounting Fees and Services +61 +PART IV +Item 15. +Exhibits and Financial Statement Schedule +61 +Signatures +67 +3 +FORWARD-LOOKING STATEMENTS +References in this report to “the Company,” “Key Tronic,” “KeyTronicEMS,” “we,” “our,” or “us” mean Key Tronic Corporation together with its subsidiaries, except where the context otherwise requires. +This Annual Report on Form 10-K contains forward-looking statements in addition to historical information. Forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those reflected in the forward-looking statements. Risks and uncertainties that might cause such differences include, but are not limited to those outlined in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risks and Uncertainties that May Affect Future Results.” Readers are cautioned not to place undue reliance on forward-looking statements, which reflect management’s opinions only as of the date hereof. The Company undertakes no obligation to update forward-looking statements to reflect developments or information obtained after the date hereof and disclaims any obligation to do so. Readers should carefully review the risk factors described in periodic reports the Company files from time to time with the Securities and Exchange Commission, including Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. +PART I +Item 1. +BUSINESS +Background +Key Tronic Corporation (dba: KeyTronicEMS Co.) was organized in 1969, as a Washington corporation that locally manufactured computer keyboards. The ability to design, build and deliver a quality product led us to become a leading independent manufacturer of keyboards for computers in the United States. Our fully integrated design, tooling, and automated manufacturing capabilities enabled us to rapidly respond to customers’ needs for keyboards in production quantities worldwide. We supported our sales growth through the development and purchase of international manufacturing facilities. As the computer keyboard market matured with increasing competition from other international providers, we determined that our business could no longer solely rely on keyboard sales. +After assessing market conditions and our strengths and capabilities, we shifted our focus from keyboard manufacturing to contract manufacturing for a wide range of products. Our unique strategic attributes are based on our core strengths of innovative design and engineering expertise in electronics, mechanical engineering, sheet metal fabrication and stamping, and precision plastics combined with high-quality, low cost production, and assembly on an international basis while providing exceptional customer service. These strengths have made our company a strong competitor in the electronic manufacturing services (EMS) market. +Our Industry and Strategy +The expansion of the EMS industry and our acquisitions have allowed us to continue to expand our customer base and the industries that we serve. The increase in new programs represents a growing portion of our revenue and a promising foundation for our future. In keeping with our long-term strategic objectives, we have been successfully building a more diversified customer portfolio, spanning a wider range of industries. We currently offer our customers the following services: integrated electronic and mechanical engineering, precision plastic molding, sheet metal fabrication, printed circuit board (PCB) and complete product assembly, component selection, sourcing and procurement, worldwide logistics, and new product testing and production all at competitive pricing due to our global footprint. We differentiate ourselves from others our size and larger in the EMS industry by providing vertical integration, a flexible and responsive approach to our customer’s changing supply demand, and complete design engineering support. +We believe that we are well positioned in the EMS industry to continue the expansion of our customer base and achieve long-term growth. Our unique blend of multinational facilities, vertical integration, centralized management, and core strengths continue to support our growth and our customers’ needs. We continue to focus on controlling operating expenses and leveraging the synergistic capabilities of our world-class facilities in the United States, Mexico, and China. This international production capability provides our customers with the benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs, and reduced product fulfillment time. Given our competitive advantages and the growing pressure for new potential customers to move forward with their outsourcing strategies, we are strongly positioned to win new business in coming periods and grow our revenue and profits. +4 +The EMS industry is intensely competitive. Although our customer base is growing, we still have less than 1% of the potential global market and our revenue can fluctuate significantly due to reliance on a concentrated base of customers. We are planning for new customer growth in the coming quarters by securing new programs with new and existing customers, increasing our worldwide manufacturing capacity, leveraging further our design engineering capabilities and continuing to improve our manufacturing and procurement processes and capabilities. Ongoing challenges that we face include but are not limited to the following: continuing to win programs from new and existing customers, balancing capital employed, production capacity and key personnel in support of new customer programs, improving operating efficiencies, controlling costs while developing competitive pricing strategies, and successfully transitioning new program wins to full production. +Customers and Marketing +We provide a mix of manufacturing services for outsourced Original Equipment Manufacturing (OEM) products. We provide the following EMS services: product design, surface mount technologies (SMT) and pin through hole capability for printed circuit board assembly, tool making, precision plastic molding, sheet metal fabrication and painting, liquid injection molding, complex assembly, automated tape winding, prototype design and full product assembly. +Sales of the majority of our products have not historically been seasonal in nature, but may be seasonal in the future if there are changes in the types of products manufactured. Sales can, however, fluctuate significantly between quarters from changes in customers and customer demand due to the concentration of sales generated by our largest customers. +For the fiscal years 2018 , 2017 and 2016 , the five largest customers in each year accounted for 42%, 42% and 41% of combined total net sales, respectively. We continue to diversify our customer base by adding additional programs and customers. We expect net sales to our five largest customers as a percentage of total net sales to approximate current levels going forward. +The following table represents all customers that represented 10% or more of total net sales during the last three fiscal years: +Percentage of Net Sales by Fiscal Year +2018 +2017 +2016 +Customer A +19% +18% +18% +There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with it’s customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +We market our products and services primarily through our direct sales department which is comprised of strategically located field sales people and distributors. We also maintain relationships with several independent sales organizations to assist in marketing our EMS product lines. +Manufacturing +We have continually made investments in developing and expanding a capital equipment base to achieve vertical integration and efficiencies in our manufacturing processes. We have invested significant capital into SMT for volume manufacturing of complex printed circuit board assemblies and in our metal shop providing precision metal stamping, fabricating, and finishing. We also design and develop tooling for injection molding and sheet metal fabrication and manufacture the majority of plastic and sheet metal parts used in the products we manufacture. Additionally, we have equipment to maintain a controlled clean environment for manufacturing processes that require a high level of precise control. +We use a variety of manual and automated assembly processes in our facilities, depending upon product complexity and degree of customization. Some examples of automated processes include component insertion, SMT, selective soldering, flexible robotic assembly, automated storage tape winding, computerized vision system quality inspection, laser turrets, automated switch and key top installation, robotic welding, automated powder coat application, and automated functional testing. +Our engineering expertise and automated manufacturing processes enable us to work closely with our customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. We use computer-aided design techniques and software to assist in preparation of the tool design layout and component placement, to reduce tooling and production costs, improve component and product quality, and enhance turnaround time during product development. +We purchase materials and components for our products from many different suppliers, including both domestic and international sources. We develop close working relationships with our suppliers, many of whom have been supplying products to us for several years. +5 +Research, Development, and Engineering +As part of our long-term strategy, we are committed to supporting our customers by providing research, development, and engineering services. We have recently seen an increase in the success of providing design support on existing and potential customers in differentiating ourselves. These services allow us to facilitate in optimizing new product designs, and the production processes of our customers’ programs. +Research, development, and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials costs, depreciation, and allocated information technology and facilities costs. +Competition +The market for the products and services we provide is highly competitive. There are numerous competitors in the EMS industry, many of which have substantially more resources and are more geographically diverse than we are. Some of our competitors have similar international production capabilities, large financial resources and some have substantially greater manufacturing, research and development, and marketing resources. There is also competition from the manufacturing operations of our current and potential customers, who are continually evaluating the merits of manufacturing their products internally versus the advantages of outsourcing. We believe that we can currently compete favorably in these areas primarily on the basis of our international footprint, responsiveness, creativity, vertical production capability, quality, and cost. +Trademarks +Our name and logo are federally registered trademarks, and we believe they are valuable assets of our business. We operate under the trade name “KeyTronicEMS” to better identify our primary business concentration in contract manufacturing in the EMS industry. +Employees +We consider our employees to be our primary strength and we make considerable efforts to maintain a well-qualified workforce. Our employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. We regularly provide transportation, medical services, and meals to all of our employees in foreign locations. The Company also has defined contribution plans available to U.S. employees who have attained age 21 and provide group health, life, and disability insurance plans. We also maintain share based compensation plans and other long-term incentive plans for certain employees and outside directors. +As of June 30, 2018 we had 4,701 full-time employees compared to 5,038 on July 1, 2017 , and 4,947 on July 2, 2016 . Since we can have significant fluctuations in product demand, we seek to maintain flexibility in our workforce by utilizing skilled temporary labor in our manufacturing facilities in addition to full-time employees. +Backlog +On July 28, 2018 our order backlog was valued at approximately $167.7 million, compared to approximately $126.9 million on July 29, 2017. The amount of backlog is not necessarily indicative of future sales but can be indicative of trends in expected future sales revenue. Due to the relationships with our customers, we will occasionally allow orders to be canceled or rescheduled and as a result it is not a meaningful indicator of future financial results. If there are canceled or rescheduled orders, we typically negotiate fees to cover the costs we have incurred. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change due to design modifications, customer forecast changes, or other customer requirements. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in Note 12, “Enterprise-Wide Disclosures” of the consolidated financial statements of this Annual Report on Form 10-K and that information is incorporated herein. +6 +Executive Officers of the Registrant +The table below sets forth the name, current age and current position of our executive officers and other significant employees: +Name +Age +Positions Held +Executive Officers +Craig D. Gates +59 +President and Chief Executive Officer +Brett R. Larsen +45 +Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Douglas G. Burkhardt +60 +Executive Vice President of Worldwide Operations +Philip S. Hochberg +56 +Executive Vice President of Business Development +David H. Knaggs +37 +Vice President of Quality and Regulatory Affairs +Frank Crispigna III +57 +Vice President of Supply Chain +Duane D. Mackleit +50 +Vice President of Program Management +Chad T. Orebaugh +47 +Vice President of Engineering +Executive Officers +CRAIG D. GATES – President and Chief Executive Officer +Mr. Gates, age 59 , has been President and Chief Executive officer of the Company since April 2009. Previously, he was Executive Vice President and General Manager from August 2002 to April 2009. He served as Executive Vice President of Marketing, Engineering and Sales from July 1997 to August 2002 and served as Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of 1994. From 1982 to 1991 he held various engineering and management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. Mr. Gates has a Bachelor of Science Degree in Mechanical Engineering and a Masters in Business Administration from the University of Illinois, Urbana. +BRETT R. LARSEN – Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Mr. Larsen, age 45 , has served as Executive Vice President of Administration, Chief Financial Officer, and Treasurer since July 2015. Previously, he was Vice President of Finance and Controller from February 2010 to July 2015. He was Chief Financial Officer of FLSmidth Spokane, Inc. from December 2008 to February 2010. From October 2005 through November 2008, Mr. Larsen served as Controller of Key Tronic Corporation. From May 2004 to October 2005, Mr. Larsen served as Manager of Financial Reporting of Key Tronic Corporation. From 2002 to May 2004, Mr. Larsen was an audit manager for the public accounting firm BDO USA, LLP. He also held various auditing and supervisory positions with Grant Thornton LLP from 1997 to 2002. Mr. Larsen has a Bachelor of Science degree in Accounting and a Masters degree in Accounting from Brigham Young University and is a Certified Public Accountant. +DOUGLAS G. BURKHARDT – Executive Vice President of Worldwide Operations +Mr. Burkhardt, age 60 , has been Executive Vice President of Worldwide Operations of the Company since July 2010. Previously Mr. Burkhardt was Vice President of Worldwide Operations from July 2008 to July 2010 and Director of China Operations and Program Management from January 2006 to July 2008. Mr. Burkhardt also served as Director of Northwest and China Operations from November of 1998 to January of 2006. Mr. Burkhardt also served as Director of Customer Satisfaction from March 1997 to November 1998 and Director of Molding from September of 1995 to March of 1997. Prior to this, Mr. Burkhardt served in other various senior management positions within the Company. Mr. Burkhardt has been with the Company since May of 1989. Prior to joining Key Tronic, Mr. Burkhardt worked for House of Aluminum and Glass for 12 years where he was the plant manager. +PHILIP S. HOCHBERG – Executive Vice President of Business Development +Mr. Hochberg, age 56 , has been Executive Vice President of Business Development since July 2012. Prior to this, Mr. Hochberg served as Vice President of Business Development from October 2009 through June 2012. He was Director of Business Development and Program Management from July 2008 to October 2009. Mr. Hochberg served as Director of Business Development from October 2004 to July 2008 and as Director of EMS Sales and Marketing from July 2000 to October 2004. Prior to joining Key Tronic, Mr. Hochberg worked for Quinton Instrument Company as their Director of Marketing and Product Management from 1992 to 2000. From 1988 to 1992, he was employed by SpaceLabs Medical as their Business Development Marketing Manager. Mr. Hochberg has an MBA from the University of British Columbia, a BA in Psychology, with a minor in Business from Washington University in St. Louis. +7 +DAVID H. KNAGGS – Vice President of Quality and Regulatory Affairs +Mr. Knaggs, age 37 , has been Vice President of Quality and Regulatory Affairs since October 2016. Before joining KeyTronicEMS, Mr. Knaggs worked at Telect, Inc. from 2008 to 2016 as their Director of Engineering. Prior to that, he worked at Isothermal Systems Research as Lead Systems Engineer from 2003 to 2008. He has a Bachelor of Science degree in Mechanical Engineering with a minor in mathematics from the University of Washington. +FRANK CRISPIGNA III – Vice President of Supply Chain +Mr. Crispigna, age 57 , has been Vice President of Supply Chain of the company since October 2011. Prior to this, Mr. Crispigna held a variety of Materials and Supply Chain positions at Plexus Corporation since 1997, most recently serving as the Director – Supply Chain Solutions from 2005 - 2011. He has a Masters degree in Business Administration, and a Bachelor of Business Administration Degree in Marketing from the University of Wisconsin – Oshkosh. Mr. Crispigna also is a C.P.M., and received his certification in Supply Chain Leadership from the University of Wisconsin. +DUANE D. MACKLEIT – Vice President of Program Management +Mr. Mackleit, age 50 , has been Vice President of Program Management of the company since July 2012. He served as Director of Program Management from July 2008 through June 2012. From May 2006 to July 2008 he served as Principal Program Manager. Prior to that, he served as Program Manager from March 2002 to May 2006 and Associate Program Manager from August 2000 to March 2002. Mr. Mackleit has also held several other positions with Key Tronic Corporation. Mr. Mackleit has an AA in Business from Spokane Falls Community College and a BA in Business/Marketing from Eastern Washington University. He also holds a MBA from Gonzaga University. +CHAD T. OREBAUGH – Vice President of Engineering +Mr. Orebaugh, age 47 , has been Vice President of Engineering since April 2017. Prior to this, Mr. Orebaugh served as Director of Engineering since May 2013. From April 2010 to May 2013, he served as Manager of Engineering. From January 2000 to April 2010 he served as Lead Mechanical Engineer. Prior to that, he served as Mechanical Engineer from October 1998 to January 2000 and Associate Mechanical Engineer since October 1997. Mr. Orebaugh holds a BA in Mechanical Engineering from Gonzaga University. +Available Information +Our principal executive offices are located at 4424 North Sullivan Road, Spokane Valley, Washington 99216, and our telephone number is (509) 928-8000. Our website is located at http://www.keytronic.com where filings of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or current reports on Form 8-K are available after they have been filed with the Securities and Exchange Commission. The information presented on our website currently and in the future is not considered to be part of this document or any document incorporated by reference in this document. +8 +Item 1A. +RISK FACTORS +There are risks and uncertainties that could affect our business. These risks and uncertainties include but are not limited to, the risk factors described below, in Item 7A: “Quantitative and Qualitative Disclosures about Market Risk” and elsewhere in this Form 10-K. +RISKS AND UNCERTAINTIES THAT MAY AFFECT FUTURE RESULTS +The following risks and uncertainties could affect our actual results and could cause results to differ materially from past results or those contemplated by our forward-looking statements. When used herein, the words “expects,” “believes,” “anticipates” and other similar expressions are intended to identify forward-looking statements. +We may experience fluctuations in quarterly results of operations. +Our quarterly operating results have varied in the past and may vary in the future due to a variety of factors, including adverse changes in the U.S. and global macroeconomic environment, volatility in overall demand for our customers’ products, success of customers’ programs, timing of new programs, new product introductions or technological advances by us, our customers and our competitors, and changes in pricing policies by us, our customers, our suppliers, and our competitors. Our customer base is diverse in the markets they serve, however, decreases in demand, particularly from customers in certain industries could affect future quarterly results. Additionally, our customers could be adversely impacted by illiquidity in the credit markets which could directly impact our operating results. +Component procurement, production schedules, personnel and other resource requirements are based on estimates of customer requirements. Occasionally, our customers may request accelerated production that can stress resources and reduce operating margins. Conversely, our customers may abruptly lower or cancel production which may lead to a sudden, unexpected increase in inventory or accounts receivable for which we may not be reimbursed even when under contract with customers. In addition, because many of our operating expenses are relatively fixed, a reduction in customer demand can harm our gross profit and operating results. The products which we manufacture for our customers have relatively short product life cycles. Therefore, our business, operating results and financial condition are dependent in a significant way on our ability to obtain orders from new customers and new product programs from existing customers. +Operating results can also fluctuate if changes are made to significant estimates and assumptions. Significant estimates and assumptions include the allowance for doubtful receivables, provision for obsolete and non-saleable inventory, stock-based compensation, the valuation allowance on deferred tax assets, valuation of goodwill, impairment of long-lived assets, long-term incentive compensation accrual, the provision for warranty costs, the impact of hedging activities and purchase price allocation. +We are exposed to general economic conditions, which could have a material adverse impact on our business, operating results and financial condition. +Adverse economic conditions and uncertainty in the global economy such as unstable global financial and credit markets, inflation, tariffs, and recession can negatively impact our business. Unfavorable economic conditions could affect the demand for our customers’ products by triggering a reduction in orders as well as a decline in forecasts which could adversely affect our sales in future periods. Additionally, the financial strength of our customers and suppliers and their ability to obtain and rely on credit financing may affect their ability to fulfill their obligations to us and have an adverse effect on our financial results. +The majority of our sales come from a small number of customers and a decline in sales to any of these customers could adversely affect our business. +At present, our customer base is concentrated and could become more or less concentrated. There can be no assurance that our principal customers will continue to purchase products from us at current levels. Moreover, we typically do not enter into long-term volume purchase contracts with our customers, and our customers have certain rights to extend or delay the shipment of their orders. We, however, typically require that our customers contractually agree to buy back inventory purchased within specified lead times to build their products if not used. +The loss of one or more of our major customers, or the reduction, delay or cancellation of orders from such customers, due to economic conditions or other forces, could materially and adversely affect our business, operating results and financial condition. The contraction in demand from certain industries could impact our customer orders and have a negative impact on our operations over the foreseeable future. Additionally, if one or more of our customers were to become insolvent or otherwise unable to pay for the manufacturing services provided by us, our operating results and financial condition would be adversely affected. +9 +We depend on a limited number of suppliers for certain components that are critical to our manufacturing processes. A shortage of these components or an increase in their price could interrupt our operations and result in a significant change in our results of operations. +We are dependent on many suppliers, including sole source suppliers, to provide key components and raw materials used in manufacturing customers’ products. We have seen supply shortages in certain electronic components. In addition, our suppliers' facilities may also experience earthquakes, tsunamis and other natural disasters which may cause a shortage of components. This can result in longer lead times and the inability to meet our customers request for flexible production and extended shipment dates. If demand for components outpaces supply, capacity delays could affect future operations. Delays in deliveries from suppliers or the inability to obtain sufficient quantities of components and raw materials could cause delays or reductions in shipment of products to our customers which could adversely affect our operating results and damage customer relationships. +We operate in a highly competitive industry; if we are not able to compete effectively in the EMS industry, our business could be adversely affected. +Competitors may offer customers lower prices on certain high volume programs. This could result in price reductions, reduced margins and loss of market share, all of which would materially and adversely affect our business, operating results, and financial condition. If we were unable to provide comparable or better manufacturing services at a lower cost than our competitors, it could cause sales to decline. In addition, competitors can copy our non-proprietary designs and processes after we have invested in development of products for customers, thereby enabling such competitors to offer lower prices on such products due to savings in development costs. +Cash and cash equivalents are exposed to concentrations of credit risk. +We place our cash with high credit quality institutions. At times, such balances may be in excess of the federal depository insurance limit or may be on deposit at institutions which are not covered by insurance. If such institutions were to become insolvent during which time it held our cash and cash equivalents in excess of the insurance limit, it could be necessary to obtain other credit financing to operate our facilities. +Our ability to secure and maintain sufficient credit arrangements is key to our continued operations. +There is no assurance that we will be able to retain or renew our credit agreements in the future. In the event the business grows rapidly or there is uncertainty in the macroeconomic climate, additional financing resources could be necessary in the current or future fiscal years. There is no assurance that we will be able to obtain equity or debt financing at acceptable terms, or at all in the future. In addition, we have restrictive covenants with our financial institution which could impact how we manage our business. If we cannot meet our financial covenants, our borrowings could become immediately payable which could have a material adverse impact on our financial statements. For a summary of our banking arrangements, see Note 4 Long-Term Debt of the “Notes to Consolidated Financial Statements.” +Our operations may be subject to certain risks. +We manufacture product in facilities located in Mexico, China and the United States. These operations may be subject to a number of risks, including: +• +difficulties in staffing, turnover and managing onshore and offshore operations; +• +political and economic instability (including acts of terrorism, pandemics, civil unrest, forms of violence and outbreaks of war), which could impact our ability to ship, manufacture, and/or receive product; +• +unexpected changes in regulatory requirements and laws; +• +longer customer payment cycles and difficulty collecting accounts receivable; +• +export duties, import controls and trade barriers (including quotas); +• +governmental restrictions on the transfer of funds; +• +burdens of complying with a wide variety of foreign laws and labor practices; +• +our locations may be impacted by hurricanes, tornadoes, earthquakes, water shortages, tsunamis, floods, typhoons, fires, extreme weather conditions and other natural or man-made disasters. +Our operations in certain foreign locations receive favorable income tax treatment in the form of tax credits or other incentives. In the event that such tax incentives are not extended, are repealed, or we no longer qualify for such programs, our taxes may increase, which would reduce our net income. +10 +Additionally, certain foreign jurisdictions restrict the amount of cash that can be transferred to the U.S or impose taxes and penalties on such transfers of cash. To the extent we have excess cash in foreign locations that could be used in, or is needed by, our operations in the United States, we may incur significant penalties and/or taxes to repatriate these funds. +Fluctuations in foreign currency exchange rates could increase our operating costs. +We have manufacturing operations located in Mexico and China. A significant portion of our operations are denominated in the Mexican peso and the Chinese currency, the renminbi ( “ RMB ” ). Currency exchange rates fluctuate daily as a result of a number of factors, including changes in a country ’ s political and economic policies. Volatility in the currencies of our entities and the United States dollar could seriously harm our business, operating results and financial condition. The primary impact of currency exchange fluctuations is on the cash, receivables, payables and expenses of our operating entities. As part of our hedging strategy, we currently use Mexican peso forward contracts to hedge foreign currency fluctuations for a portion of our Mexican peso denominated expenses. We currently do not hedge expenses denominated in RMB. Unexpected losses could occur from increases in the value of these currencies relative to the United States dollar. +Our success will continue to depend to a significant extent on our key personnel. +Our future success depends in large part on the continued service of our key technical, marketing and management personnel and on our ability to continue to attract and retain qualified production employees. There can be no assurance that we will be successful in attracting and retaining such personnel, particularly in our manufacturing locales that may be experiencing high demand for similar key personnel. The loss of key employees could have a material adverse effect on our business, operating results and financial condition. +If we are unable to maintain our technological and manufacturing process expertise, our business could be adversely affected. +The markets for our customers’ products is characterized by rapidly changing technology, evolving industry standards, frequent new product introductions and short product life cycles. The introduction of products embodying new technologies or the emergence of new industry standards can render existing products obsolete or unmarketable. Our success will depend upon our customers’ ability to enhance existing products and to develop and introduce, on a timely and cost-effective basis, new products that keep pace with technological developments and emerging industry standards and address evolving and increasingly sophisticated customer requirements. Failure of our customers to do so could substantially harm our customers’ competitive positions. There can be no assurance that our customers will be successful in identifying, developing and marketing products that respond to technological change, emerging industry standards or evolving customer requirements. +Start-up costs and inefficiencies related to new or transferred programs can adversely affect our operating results and such costs may not be recoverable if such new programs or transferred programs are canceled or don’t meet expected sales volumes. +Start-up costs, the management of labor and equipment resources in connection with the establishment of new programs and new customer relationships, and the need to obtain required resources in advance can adversely affect our gross margins and operating results. These factors are particularly evident in the ramping stages of new programs. These factors also affect our ability to efficiently use labor and equipment. We are currently managing a number of new programs. Consequently, our exposure to these factors has increased. In addition, if any of these new programs or new customer relationships were terminated, our operating results could be harmed, particularly in the short term. We may not be able to recoup these start-up costs or replace anticipated new program revenues. +Customers may change production timing and demand schedules which makes it difficult for us to schedule production and capital expenditures and to maximize the efficiency of our manufacturing capacity. +Changes in demand for customer products reduce our ability to accurately estimate the future requirements of our customers. This makes it difficult to schedule production and maximize utilization of our manufacturing capacity. We must determine the levels of business that we will seek and accept from customers, set production schedules, commit to procuring inventory, and allocate personnel and resources, based on our estimates of our customers' requirements. Customers can require sudden increases and decreases in production which can put added stress on resources and reduce margins. Sudden decreases in production can lead to excess inventory on hand which may or may not be reimbursed by our customers even when under contract. +Continued growth could further lead to capacity constraints. We may need to transfer production to other facilities, acquire new facilities, or outsource production which could negatively impact gross margin. +11 +An adverse change in the interest rates for our borrowings could adversely affect our financial condition. +We are exposed to interest rate risk under our revolving line of credit and term loan. We currently hedge a portion of our term loan with an interest rate swap. We have not historically hedged the interest rate on our credit facility; therefore, unless we do so, significant changes in interest rates could adversely affect our results of operations. Refer to the discussion in note 4, "Long-Term Debt" to the consolidated financial statements for further details of our debt obligations. We are also exposed to interest rate risk on our factoring activities. +Compliance or the failure to comply with current and future environmental laws or regulations could cause us significant expense. +We are subject to a variety of domestic and foreign environmental regulations relating to the use, storage, and disposal of materials used in our manufacturing processes. If we fail to comply with any present or future regulations, we could be subject to future liabilities or the suspension of current manufacturing operations. In addition, such regulations could restrict our ability to expand our operations or could require us to acquire costly equipment, substitute materials, or incur other significant expenses to comply with government regulations. +Our stock price is volatile. +Holders of the common stock will suffer immediate dilution to the extent outstanding equity awards are exercised to purchase common stock. Our stock price may be subject to wide fluctuations and possible rapid increases or declines over a short time period. These fluctuations may be due to factors specific to us such as our stock's thinly traded nature, variations in quarterly operating results or changes in earnings estimates, or to factors relating to the EMS industry or to the securities markets in general, which, in recent years, have experienced significant price fluctuations. These fluctuations often have been unrelated to the operating performance of the specific companies whose stocks are traded. +Due to inherent limitations, there can be no assurance that our system of disclosure and internal controls and procedures will be successful in preventing all errors, theft and fraud, or in informing management of all material information in a timely manner. +Management does not expect that our disclosure controls and internal controls and procedures will prevent all errors or fraud. A control system is designed to give reasonable, but not absolute, assurance that the objectives of the control system are met. In addition, any control system reflects resource constraints and the benefits of controls must be considered relative to their costs. Inherent limitations of a control system may include: judgments in decision making may be faulty, breakdowns can occur simply because of error or mistake and controls can be circumvented by collusion or management override. Due to the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and may not be detected. +If we do not manage our growth effectively, our profitability could decline. +Our business is experiencing growth which can place considerable additional demands upon our management team and our operational, financial and management information systems. Our ability to manage growth effectively requires us to continue to implement and improve these systems; avoid cost overruns; maintain customer, supplier and other favorable business relationships during possible transition periods; continue to develop the management skills of our managers and supervisors; and continue to train, motivate and manage our employees. Our failure to effectively manage growth could have a material adverse effect on our results of operations. +12 +If our manufacturing processes and services do not comply with applicable statutory and regulatory requirements, or if we manufacture products containing design or manufacturing defects, demand for our services may decline and we may be subject to liability claims. +We manufacture and design products to our customers’ specifications, and, in some cases, our manufacturing processes and facilities may need to comply with applicable statutory and regulatory requirements. For example, medical devices that we manufacture or design, as well as the facilities and manufacturing processes that we use to produce them, are regulated by the Food and Drug Administration and non-U.S. counterparts of this agency. In addition, our customers’ products and the manufacturing processes that we use to produce them often are highly complex. As a result, products that we manufacture may at times contain manufacturing or design defects, and our manufacturing processes may be subject to errors or not be in compliance with applicable statutory and regulatory requirements. Defects in the products we manufacture or design, whether caused by a design, manufacturing or component failure or error, or deficiencies in our manufacturing processes, may result in delayed shipments to customers or reduced or canceled customer orders. If these defects or deficiencies are significant, our business reputation may also be damaged. The failure of the products that we manufacture or our manufacturing processes and facilities to comply with applicable statutory and regulatory requirements may subject us to legal fines or penalties and, in some cases, require us to shut down or incur considerable expense to correct a manufacturing process or facility. Our customers are required to indemnify us against liability associated with designing products to meet their specifications. However, if our customers are responsible for the defects, they may not, or may not have resources to, assume responsibility for any costs or liabilities arising from these defects, which could expose us to additional liability claims. +Energy price increases may negatively impact our results of operations. +Certain components that we use in our manufacturing process are petroleum-based. In addition, we, along with our suppliers and customers, rely on various energy sources in our transportation activities. While significant uncertainty currently exists about the future levels of energy prices, a significant increase is possible. Increased energy prices could cause an increase to our raw material costs and transportation costs. In addition, increased transportation costs of certain of our suppliers and customers could be passed along to us. We may not be able to increase our product prices enough to offset these increased costs. In addition, any increase in our product prices may reduce our future customer orders and profitability. +Disruptions to our information systems, including security breaches, losses of data or outages, could adversely affect our operations. +We rely on information technology networks and systems to process, transmit and store electronic information. In particular, we depend on our information technology infrastructure for a variety of functions, including worldwide financial reporting, inventory management, procurement, invoicing and email communications. Any of these systems may be susceptible to outages due to fire, floods, power loss, telecommunications failures, terrorist attacks and similar events. Despite the implementation of network security measures, our systems and those of third parties on which we rely may also be vulnerable to computer viruses, break-ins and similar disruptions. If we or our vendors are unable to prevent such outages and breaches, our operations could be disrupted. +We are involved in various legal proceedings. +In the past, we have been notified of claims relating to various matters including contractual matters, intellectual property rights or other issues arising in the ordinary course of business. In the event of such a claim, we may be required to spend a significant amount of money to defend or otherwise address the claim. Any litigation or dispute resolution, even where a claim is without merit, could result in substantial costs and diversion of resources. Accordingly, the resolution or adjudication of such disputes, even those encountered in the ordinary course of business, could have a material adverse effect on our business, consolidated financial conditions and results of operations. +Our levels of insurance coverage may not be sufficient for potential damages, claims or losses. +We have various forms of business and liability insurance which we believe are appropriate based on the needs of companies in our industry. As a result, not all of our potential business risks or potential losses would be covered by our insurance policies. If we sustain a significant claim or loss which is not covered by insurance, our net income could be negatively impacted. +13 +Changes in securities laws and regulations will increase our costs and risk of noncompliance. +We are required to file as an accelerated filer. As such, we are subject to additional requirements contained in the Sarbanes-Oxley Act of 2002 (the Sarbanes-Oxley Act) and more recently the Dodd-Frank Act. The Sarbanes-Oxley and Dodd-Frank Acts required or will require changes in some of our corporate governance, securities disclosure and compliance practices. In response to the requirements of the Sarbanes-Oxley and Dodd-Frank Acts, the SEC and NASDAQ promulgated new rules and additional rulemaking is expected in the future. Compliance with these new rules and future rules has increased and may increase further our legal, financial and accounting costs as well as a potential risk of noncompliance. Absent significant changes in related rules, which we cannot assure, we anticipate some level of increased costs related to these new regulations to continue indefinitely. We also expect these developments to make it more difficult and more expensive to obtain director and officer liability insurance, and we may be forced to accept reduced coverage or incur substantially higher costs to obtain coverage. Likewise, these developments may make it more difficult for us to attract and retain qualified members of our Board of Directors or qualified management personnel. Further, the costs associated with the compliance with and implementation of procedures under these and future laws and related rules could have a material impact on our results of operations. In addition, the costs associated with noncompliance with additional securities laws and regulations could also impact our business. +We may encounter complications with acquisitions, which could potentially harm our business. +Any current or future acquisitions may require additional equity financing, which could be dilutive to our existing shareholders, or additional debt financing, which could potentially affect our credit ratings. Any downgrades in our credit ratings associated with an acquisition could adversely affect our ability to borrow by resulting in more restrictive borrowing terms. To integrate acquired businesses, we must implement our management information systems, operating systems and internal controls, and assimilate and manage the personnel of the acquired operations. The integration of acquired businesses may be further complicated by difficulties managing operations in geographically dispersed locations. The integration of acquired businesses may not be successful and could result in disruption by diverting management’s attention from the core business. In addition, the integration of acquired businesses may require that we incur significant restructuring charges or other increases in our expenses and working capital requirements, which reduce our return on invested capital. +Acquisitions may involve numerous other risks and challenges including but not limited to: potential loss of key employees and customers of the acquired companies; the potential for deficiencies in internal controls at acquired companies; lack of experience operating in the geographic market or industry sector of the acquired business; constraints on available liquidity, and exposure to unanticipated liabilities of acquired companies. These and other factors could harm our ability to achieve anticipated levels of profitability at acquired operations or realize other anticipated benefits of an acquisition, and could adversely affect our consolidated business and operating results. +Our goodwill and identifiable intangible assets could become impaired, which could reduce the value of our assets and reduce net income in the year in which the write-off occurs. +Goodwill represents the excess of the cost of an acquisition over the fair value of the net assets acquired. The Company also ascribes value to certain identifiable intangible assets, which consists of customer relationships, non-compete agreements, and favorable leases, as a result of the acquisitions of Sabre and Ayrshire. The Company may incur impairment charges on goodwill or identifiable intangible assets if it determines that the fair values of goodwill or identifiable intangible assets are less than their current carrying values. The Company evaluates, on a regular basis, whether events or circumstances have occurred that indicate all, or a portion, of the carrying amount of goodwill may no longer be recoverable, in which case an impairment charge to earnings would become necessary. +Refer to Notes 1 and 15 to the consolidated financial statements and critical accounting policies and estimates in management’s discussion and analysis of financial condition and results of operations for further discussion regarding the impairment testing of goodwill and identifiable intangible assets. +A decline in general economic conditions or global equity valuations could impact the judgments and assumptions about the fair value of the Company’s businesses and the Company could be required to record impairment charges on its goodwill or other identifiable intangible assets in the future, which could impact the Company’s consolidated balance sheet, as well as the Company’s consolidated statement of operations. If the Company was required to recognize an impairment charge in the future, the charge would not impact the Company’s consolidated cash flows, current liquidity, capital resources, and covenants under its existing credit facilities. +14 +Changes in financial accounting standards may affect our reported financial condition or results of operations as well increase costs related to implementation of new standards and modifications to internal controls. +Our consolidated financial statements are prepared in conformity with accounting standards generally accepted in the United States, or U.S. GAAP. These principles are subject to amendments made primarily by the Financial Accounting Standards Board (FASB) and the Securities and Exchange Commission (SEC). A change in those policies can have a significant effect on our reported results and may affect our reporting of transactions which are completed before a change is announced. For example, significant changes to revenue recognition rules will be effective for us in fiscal 2019 and we may have material fluctuations in revenue from quarter to quarter once implemented. Changes to accounting rules or challenges to our interpretation or application of the rules by regulators may have a material adverse effect on our reported financial results or on the way we conduct business. +Item 1B. +UNRESOLVED STAFF COMMENTS +None +15 +Item 2. +PROPERTIES AS OF DATE OF FILING +We have manufacturing and sales operations located in the United States, Mexico, and China. The table below lists the locations and square footage of our operating facilities: +Location +Approx. +Sq. Ft. +Type of Interest +(Leased/Owned) +Description of Use +Corinth, Mississippi +350,000 +Leased +Manufacturing and warehouse +El Paso, Texas +80,000 +Leased +Shipping and warehouse +Fayetteville, Arkansas (1) +175,000 +Leased +Manufacturing and warehouse +Fayetteville, Arkansas (1) +105,000 +Leased +Manufacturing and warehouse +Harrodsburg, Kentucky (2) +22,000 +Owned +Manufacturing and warehouse +Louisville, Kentucky +2,300 +Leased +Administration +Oakdale, Minnesota (3) +60,000 +Leased +Manufacturing and warehouse +Spokane Valley, Washington +95,000 +Leased +Sales, research, administration and manufacturing +Spokane Valley, Washington +36,000 +Leased +Manufacturing +Total USA +925,300 +Juarez, Mexico +193,000 +Leased +Warehouse +Juarez, Mexico +174,000 +Owned +Manufacturing +Juarez, Mexico +115,000 +Owned +Manufacturing and warehouse +Juarez, Mexico +103,000 +Owned +Manufacturing and warehouse +Juarez, Mexico +72,000 +Leased +Manufacturing +Juarez, Mexico +66,000 +Owned +Manufacturing and warehouse +Juarez, Mexico +60,000 +Owned +Manufacturing and warehouse +Total Mexico +783,000 +Shanghai, China +121,000 +Leased +Manufacturing and warehouse +Shanghai, China +8,000 +Leased +Manufacturing +Total China +129,000 +Grand Total +1,837,300 +(1) +The Arkansas facility is currently in the process of moving to a smaller and more cost effective location. The move should be completed by the beginning of December 2018 and the lease on the facility with 175,000 square feet will be terminated. +(2) +During fiscal year 2017, we closed the Harrodsburg, Kentucky location and transferred customer programs to other facilities in the USA. The facility is currently listed for sale. Additionally, the sale of the building in less than one year is not probable at this time. As such, the property is appropriately being reported in Property, Plant, and Equipment. +(3) +Commencing on January 1, 2019, the approximate square footage for the Oakdale, Minnesota location will be increasing to approximately 102,914 square feet as we are expanding in our current building. +The geographic diversity of these locations allows us to offer services near certain of our customers and major electronics markets with the additional benefit of reduced labor costs. We consider the productive capacity of our current facilities sufficient to carry on our current business. In addition, in Juarez, Mexico one of our buildings includes adjacent vacant land that could be developed into additional manufacturing and warehouse space. +16 +All of our facilities are ISO certified to ISO 9001:2015 standard and to Customs Trade Partnership against Terrorism (CTPAT). In addition, the Juarez, Mexico; Shanghai, China and Spokane, Washington facilities are registered/certified to IATF 16949 automotive standard, AS 9100D aviation, space and defense standard, ISO 13485:2016 medical devices, ISO 14001:2015 environmental standard, ANSI/ESD S20.20 Electrostatic Discharge Control Program, OHSAS 18001 Occupational Health and Safety standard, and SA8000 / ISO 2600 social accountability standard. +Oakdale, Minnesota is additionally registered to ISO-13485:2016 medical devices standard, AS9100C aviation, space and defense standard, and NADCAP certified. The Spokane, Washington and Juarez, Mexico facilities are additionally registered to ISO/IEC 80079-34 explosive atmospheres. Additionally, Juarez, Mexico is registered by the NSF for water products. The Oakdale, Minnesota; Corinth, Mississippi; Fayetteville, Arkansas and Spokane, Washington facilities are all registered by the U.S. State Department for International Traffic in Arms Regulations (ITAR). +Item 3. +LEGAL PROCEEDINGS +We are a party to certain lawsuits or claims in the ordinary course of business. We do not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on our financial position, results of operations or cash flow. Refer to Commitment and Contingencies footnote for further details on litigation in the fiscal year. +Item 4. +MINE SAFETY DISCLOSURES +Not Applicable +PART II +Item 5: +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES +Market Information +Our common stock is traded on the NASDAQ Global Market, formerly the NASDAQ National Market System under the symbol “KTCC.” Quarterly high and low sales prices for our common stock for fiscal years 2018 and 2017 were as follows: +2018 +2017 +High +Low +High +Low +First Quarter +$ +7.40 +$ +6.69 +$ +8.28 +$ +7.23 +Second Quarter +7.95 +6.74 +8.18 +7.08 +Third Quarter +7.30 +6.81 +8.20 +7.08 +Fourth Quarter +8.60 +6.85 +8.00 +6.69 +High and low stock prices are based on the daily sales prices reported by the NASDAQ Stock Market. These quotations represent prices between dealers without adjustment for markups, markdowns, and commissions, and may not represent actual transactions. +Holders and Dividends +As of June 30, 2018 , we had 671 shareholders of common stock on record. As a result of our credit agreement with Wells Fargo Bank, N.A. we are restricted from declaring or paying dividends in cash or stock without the Bank’s prior written consent. We have not paid a cash dividend and do not anticipate payment of dividends in the foreseeable future. +Equity Compensation Plan Information +Information concerning securities authorized for issuance under our equity compensation plans is set forth in Part III, Item 12 of this Annual Report, under the caption “Securities Authorized for Issuance under Equity Compensation Plans”, and that information is incorporated herein by reference. +17 +Performance Graph +Set forth below is a line graph comparing the cumulative total shareholder return on our common stock with the cumulative total return of the NASDAQ Stock Market (U.S. & Foreign) Index and the NASDAQ Electronic Components Index in fiscal 2018 . +6/29/2013 +6/28/2014 +6/27/2015 +7/2/2016 +7/1/2017 +6/30/2018 +Key Tronic Corporation +100.00 +103.67 +103.00 +71.40 +68.50 +73.24 +NASDAQ Composite +100.00 +132.45 +151.00 +148.88 +189.66 +233.12 +NASDAQ Electronic Components +100.00 +141.22 +150.63 +158.95 +227.17 +300.77 +18 +Item 6: +SELECTED FINANCIAL DATA +The following selected data is derived from our audited consolidated financial statements and should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the consolidated financial statements and related notes, and other information included in this report. +Financial Highlights +(In thousands, except for Supplemental Data and Per Share Amounts) +Fiscal Year Ended +June 30, 2018 +July 1, 2017 +July 2, 2016 +June 27, 2015 (3) +June 28, 2014 (3) +Consolidated Statements of Operations Data : +Net sales +$ +446,322 +$ +467,797 +$ +484,965 +$ +433,997 +$ +305,394 +Gross profit +34,169 +38,300 +38,825 +33,305 +26,854 +Gross margin percentage +7.7 +% +8.2 +% +8.0 +% +7.7 +% +8.8 +% +Operating income +1,114 +9,544 +10,416 +6,653 +9,304 +Operating margin percentage +0.2 +% +2.0 +% +2.1 +% +1.5 +% +3.0 +% +Net income (loss) +(1,325 +) +5,617 +6,533 +4,304 +7,613 +Net income (loss) per share – diluted +(0.12 +) +0.51 +0.58 +0.38 +0.67 +Consolidated Cash Flow Data : +Cash flows provided by operations +11,457 +9,425 +4,580 +7,667 +1,458 +Capital expenditures +4,523 +9,307 +13,277 +8,808 +7,763 +Consolidated Balance Sheet Data : +Net working capital (1) +95,607 +100,440 +97,349 +98,318 +71,049 +Total assets +246,528 +232,840 +235,924 +230,794 +156,660 +Long-term liabilities +29,534 +38,520 +46,232 +43,237 +848 +Shareholders’ equity +118,081 +116,567 +105,582 +100,768 +103,645 +Book value per share (2) +$ +10.97 +$ +10.83 +$ +9.84 +$ +9.42 +$ +9.83 +Supplemental Data : +Number of shares outstanding at year-end +10,759,680 +10,759,680 +10,725,349 +10,706,136 +10,546,750 +Number of employees at year-end +4,701 +5,038 +4,947 +4,866 +3,343 +Approximate square footage of operational facilities +1,837,300 +1,760,000 +1,828,000 +1,892,000 +1,139,000 +(1) +Net working capital is defined as total current assets less total current liabilities. Net working capital measures the portion of current assets that are financed by long term funds and is an indicator of short term financial management. +(2) +Book value per share is defined as total shareholders’ equity divided by the number of shares outstanding at the end of the fiscal year. +(3) +Reflects the acquisition of Ayrshire on September 3, 2014 in fiscal year 2015 and Sabre on July 1, 2013 in fiscal year 2014. +19 +Item 7: +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +Overview +KeyTronicEMS is a leader in electronic manufacturing services and solutions to original equipment manufacturers of a broad range of products. We provide engineering services, worldwide procurement and distribution, materials management, world-class manufacturing and assembly services, in-house testing, and unparalleled customer service. Our international production capability provides our customers with benefits of improved supply-chain management, reduced inventories, lower transportation costs, and reduced product fulfillment time. We continue to make investments in all of our operating facilities to give us the production capacity, capabilities and logistical advantages to continue to win new business. The following information should be read in conjunction with the consolidated financial statements included herein and with Item 1A, Risk Factors included as part of this filing. +Our mission is to provide our customers with superior manufacturing and engineering services at the lowest total cost for the highest quality products, and create long-term mutually beneficial business relationships by employing our “Trust, Commitment, Results” philosophy. +Executive Summary +For the fourth quarter of fiscal 2018, we saw increasing demand from a number of our longstanding customers and most of our new programs, including Skybell Technologies, continued to ramp steadily. We also continued to win significant new business from EMS competitors and from existing customers, including new programs involving medical devices, distribution services and electronic signage. At the same time, our productivity continued to be adversely impacted by industry wide shortages in key components, resulting in delays in delivery and increased costs. +Net sales of $446.3 million for fiscal year 2018 decreased by 4.6 percent as compared to net sales of $467.8 million in fiscal year 2017 . The decrease in net sales was primarily driven by a decrease in demand from current customers, partially offset by an increase in new program wins. +While 2018 was a challenging year, we replaced the revenue shortfall caused by a large former customer, significantly diversified our customer base, reduced our debt by $8.0 million for the year and returned to strong sequential growth in the fourth quarter. Moving into the first quarter of fiscal year 2019, although we continue to face industry supply chain issues, we expect significant growth in revenue and earnings. In preparation, we continue to invest in new equipment and processes to be more productive in our Mexico facilities, and we are expanding and enhancing our profitable US facilities. We’re optimistic about our opportunities for growth in fiscal 2019 and beyond. +For the first quarter of fiscal year 2019 , the Company expects to report revenue in the range of $118 million to $122 million. Future results will depend on actual levels of customers’ orders, the timing of the start-up of production of new product programs, impact of the new revenue recognition accounting policy and the potential impact of the geopolitical uncertainty. We believe that we are well positioned in the EMS industry to continue expansion of our customer base and continue long-term growth. +We continue to diversify our customer base by adding additional programs and customers. Our current customer relationships involve a variety of products, including consumer electronics, electronic storage devices, plastics, household products, gaming devices, specialty printers, telecommunications, industrial equipment, military supplies, computer accessories, medical, educational, irrigation, automotive, transportation management, robotics, RFID, power supply, off-road vehicle equipment, fitness equipment, HVAC controls, consumer products, home building products, material handling systems, lighting equipment and consumer security products. +Gross profit as a percent of net sales was 7.7 percent in fiscal year 2018 compared to 8.2 percent for the prior fiscal year. The decrease in gross profit as a percentage of net sales was primarily related to an increase in certain overhead costs partially offset by a decrease in material related costs. The level of gross margin is impacted by product mix, timing of the startup of new programs, facility utilization, and pricing within the electronics industry and material costs, which can fluctuate significantly from quarter to quarter and year to year. +Operating income as a percentage of net sales for fiscal year 2018 was 0.2 percent compared to 2.0 percent for fiscal year 2017 . The decrease in operating income as a percentage of net sales was primarily due to a decrease in net revenue and a before tax one-time loss of approximately $4.5 million related to the arbitration settlement. +Net loss for fiscal year 2018 was $(1.3) million or $(0.12) per share, as compared to net income of $5.6 million or $0.52 per share for fiscal year 2017 . The decrease in net income for fiscal year 2018 as compared to fiscal year 2017 was primarily driven by the decrease in net revenue as described above as well as a before tax one-time loss of approximately $4.5 million related to the arbitration settlement. +20 +We maintain a strong balance sheet with a current ratio of 2.0 and a debt to equity ratio of 0.30 . Total cash provided by operating activities as defined on our cash flow statement was $11.5 million during fiscal year 2018 . We maintain sufficient liquidity for our expected future operations. As of June 30, 2018 , we had $16.2 million outstanding on our revolving line of credit with Wells Fargo Bank, N.A. As a result, $28.4 million remained available to borrow as of June 30, 2018 . We believe cash flow from operations, our borrowing capacity, our accounts receivable sale program, and equipment financing should provide adequate capital for planned growth over the long term. +RESULTS OF OPERATIONS +Comparison of the Fiscal Year Ended June 30, 2018 with the Fiscal Year Ended July 1, 2017 +The following table sets forth for the periods indicated certain items of the consolidated statements of income expressed as a percentage of net sales. The financial information and discussion below should be read in conjunction with the consolidated financial statements and notes contained in this Annual Report. +Fiscal Year Ended +June 30, 2018 +% of +net sales +July 1, 2017 +% of +net sales +$ change +% point +change +Net sales +$ +446,322 +100.0% +$ +467,797 +100.0% +$ +(21,475 +) +— +Cost of sales +412,153 +92.3 +429,497 +91.8 +(17,344 +) +0.5 +Gross profit +34,169 +7.7 +38,300 +8.2 +(4,131 +) +(0.5) +Operating expenses: +Research, development and engineering +6,186 +1.4 +6,393 +1.4 +(207 +) +— +Selling, general and administrative +22,334 +5.0 +22,363 +4.8 +(29 +) +0.2 +Loss on settlement of arbitration +4,535 +1.0 +— +— +4,535 +1.0 +Total operating expenses +33,055 +7.4 +28,756 +6.2 +4,299 +1.2 +Operating income +1,114 +0.2 +9,544 +2.0 +(8,430 +) +(1.8) +Interest expense, net +2,556 +0.6 +2,288 +0.5 +268 +0.1 +Income before income taxes +(1,442 +) +(0.3) +7,256 +1.6 +(8,698 +) +(1.9) +Income tax provision +(117 +) +— +1,639 +0.4 +(1,756 +) +(0.4) +Net income +$ +(1,325 +) +(0.3)% +$ +5,617 +1.2% +$ +(6,942 +) +(1.5) +Effective income tax rate +8.1 +% +22.6 +% +Net Sales +The decrease in net sales of $21.5 million from prior year period was primarily driven by a decrease in demand from current customers, partially offset by an increase in net sales from new program wins. +The following table shows the revenue by industry sectors as a percentage of revenue for fiscal years 2018 and 2017 : +Fiscal Year Ended +June 30, 2018 +July 1, 2017 +Industrial +42% +40% +Consumer +38 +35 +Gaming +7 +9 +Communication +4 +8 +Transportation +4 +1 +Computer and Peripheral +3 +2 +Printers +2 +5 +Total +100% +100% +We provide services to customers in a number of industries and produce a variety of products for our customers in each industry. Key Tronic does not target any particular industry, but rather seeks to find programs that strategically fit our vertical manufacturing capabilities. As we continue to diversify our customer base and win new customers, we will continue to see a change in the industry concentrations of our revenue. +21 +Sales to foreign locations represented 26.2 percent and 22.6 percent of our total net sales in fiscal years 2018 and 2017 , respectively. +Cost of Sales +Total cost of sales as a percentage of net sales was 92.3 percent and 91.8 percent in fiscal years 2018 and 2017 , respectively. +Total cost of materials as a percentage of net sales was approximately 61.1 percent and 61.7 percent in fiscal years 2018 and 2017 , respectively. The change from year-to-year is primarily a result of improved pricing of certain raw materials as well as a more favorable product mix. +Production and support costs as a percentage of net sales were 31.2 percent and 30.1 percent in fiscal years 2018 and 2017 , respectively. The increase in fiscal year 2018 is primarily related to severance expenses related to streamlining the company’s facilities in Mexico. +We provide a reserve for obsolete and non-saleable inventories based on specific identification of inventory against current demand and recent usage. We also consider our customers' ability to pay for inventory whether or not there is a lead-time assurance agreement for a specific program. The amounts charged to expense for these inventories were approximately $31,000 and $496,000 in fiscal years 2018 and 2017 , respectively. +We provide warranties on certain products we sell and estimate warranty costs based on historical experience and anticipated product returns. Warranty expense is related to workmanship claims on keyboards and EMS products. The amounts charged to expense are determined based on an estimate of warranty exposure. The net warranty expense was approximately $74,000 and $68,000 in fiscal years 2018 and 2017 , respectively. +Gross Profit +Gross profit as a percentage of net sales was 7.7 percent and 8.2 percent in fiscal years 2018 , and 2017 , respectively. The 0.5 percentage point decrease in gross profit as a percentage of net sales during fiscal year 2018 as compared to fiscal year 2017 is primarily related to a 0.6 percentage point decrease in material related costs partially offset by a 1.1 percentage point increase in certain overhead costs. +Changes in gross profit margins reflect the impact of a number of factors that can vary from period to period, including product mix, start-up costs and efficiencies associated with new programs, product life cycles, sales volumes, capacity utilization of our resources, management of inventories, component pricing and shortages, end market demand for customers’ products, fluctuations in and timing of customer orders, and competition within the EMS industry. These and other factors can cause variations in operating results. There can be no assurance that gross margins will not decrease in future periods. +We took early pay discounts to suppliers that totaled approximately $1.7 million and $1.9 million in fiscal years 2018 and 2017 , respectively. Early pay discounts will fluctuate based on our liquidity and changes in the discounts and terms offered by our suppliers. +Research, Development and Engineering +Research, development and engineering expenses (RD&E) consists principally of employee related costs, third party development costs, program materials, depreciation and allocated information technology and facilities costs. Total RD&E expenses were $6.2 million in fiscal year 2018 and $6.4 million in fiscal year 2017 , respectively. Total RD&E expenses as a percent of net sales were 1.4 percent in fiscal years 2018 and 2017 . +Selling, General and Administrative +Selling, general and administrative expenses (SG&A) consist principally of salaries and benefits, advertising and marketing programs, sales commissions, travel expenses, provision for doubtful accounts, facilities costs, and professional services. Total SG&A expenses were $22.3 million and $22.4 million in fiscal years 2018 and 2017 , respectively. Total SG&A expenses as a percent of net sales were 5.0 percent and 4.8 percent in fiscal years 2018 and 2017 , respectively. This 0.2 percentage point increase in SG&A as a percentage of net sales is primarily related to an increase in legal fees related to an effort to collect from a former customer through arbitration. +Loss on Settlement of Arbitration +We were awarded $6.7 million following the conclusion of a previously disclosed arbitration proceeding, which began in the second quarter of fiscal year 2017. This award resolved a dispute with a former customer involving approximately $9.3 million in inventory purchased and approximately $1.9 million in outstanding accounts receivables and other related fees and costs that we believed to be reimbursable. This event, including all related disposal fees, resulted in an approximately $4.5 million before tax one-time loss to fiscal year 2018. The adverse impact net of taxes on net loss was $3.4 million. +22 +Interest Expense +We had net interest expense of $2.6 million and $2.3 million in both fiscal years 2018 and 2017 . The increase in interest expense is primarily related to an increase in the average balance outstanding on our line of credit. +Income Tax Provision +We had an income tax benefit of approximately $(0.1) million during fiscal year 2018 and an income tax expense of approximately $1.6 million during fiscal year 2017 . The income tax expense (benefit) recognized during both fiscal years 2018 and 2017 , was primarily a function of U.S., federal, state and foreign taxes recognized at the statutory rates offset by the net benefit associated with federal research and development tax credits and changes in potential foreign tax credits. The Company also recognized the impacts of U.S. tax reform, including a provisional estimate related to mandatory repatriation, in the fiscal year ended June 30, 2018. +We continually review our requirements for liquidity domestically to fund current operations, revenue growth and to look for potential future acquisitions. We anticipate repatriating a portion of our unremitted foreign earnings. The estimated taxes and associated foreign tax credits are included in the income tax calculation. For further information on taxes please review footnote 6 of the “Notes to Consolidated Financial Statements.” +International Subsidiaries +We offer customers a complete global manufacturing solution. Our facilities provide our customers the opportunity to have their products manufactured in the facility that best serves specific cost, product manufacturing and distribution needs. The locations of active foreign subsidiaries are as follows: +• +Key Tronic Juarez, SA de CV owns five facilities and leases two facilities in Juarez, Mexico. These facilities include an SMT facility, an assembly and molding facility, a sheet metal fabrication facility, and assembly and warehouse facilities. This subsidiary is primarily used to support our U.S. operations. +• +Key Tronic Computer Peripherals (Shanghai) Co., Ltd. leases two facilities with SMT, assembly, global purchasing and warehouse capabilities in Shanghai, China, which began operations in 1999. Its primary function is to provide EMS services for export. +Foreign sales (based on shipping instructions) from our worldwide operations, including domestic exports, were $117.1 million and $105.9 million in fiscal years 2018 and 2017 , respectively. Products and manufacturing services provided by our subsidiary operations are often shipped to customers directly by the parent company. +RESULTS OF OPERATIONS +Comparison of the Fiscal Year Ended July 1, 2017 with the Fiscal Year Ended July 2, 2016 +The following table sets forth for the periods indicated certain items of the consolidated statements of income expressed as a percentage of net sales. The financial information and discussion below should be read in conjunction with the consolidated financial statements and notes contained in this Annual Report. +Fiscal Year Ended +July 1, 2017 +% of +net sales +July 2, 2016 +% of +net sales +$ change +% point +change +Net sales +$ +467,797 +100.0% +$ +484,965 +100.0% +$ +(17,168 +) +— +Cost of sales +429,497 +91.8 +446,140 +92.0 +(16,643 +) +(0.2) +Gross profit +38,300 +8.2 +38,825 +8.0 +(525 +) +0.2 +Operating expenses: +Research, development and engineering +6,393 +1.4 +6,397 +1.3 +(4 +) +0.1 +Selling, general and administrative +22,363 +4.8 +22,012 +4.5 +351 +0.3 +Total operating expenses +28,756 +6.2 +28,409 +5.8 +347 +0.4 +Operating income +9,544 +2.0 +10,416 +2.1 +(872 +) +(0.1) +Interest expense, net +2,288 +0.5 +2,265 +0.5 +23 +— +Income before income taxes +7,256 +1.6 +8,151 +1.7 +(895 +) +(0.1) +Income tax provision +1,639 +0.4 +1,618 +0.3 +21 +0.1 +Net income +$ +5,617 +1.2% +$ +6,533 +1.3% +$ +(916 +) +(0.1) +Effective income tax rate +22.6 +% +19.9 +% +23 +Net Sales +The decrease in net sales of $17.2 million from prior year was primarily driven by a decrease in net sales from the former longstanding customer which has been discussed in prior quarters, partially offset by an increase in new program wins. +The following table shows the revenue by industry sectors as a percentage of revenue for fiscal years 2017 and 2016: +Fiscal Year Ended +July 1, 2017 +July 2, 2016 +Industrial +40% +39% +Consumer +35 +31 +Gaming +9 +7 +Communication +8 +13 +Printers +5 +6 +Computer and Peripheral +2 +1 +Transportation +1 +3 +Total +100% +100% +We provide services to customers in a number of industries and produce a variety of products for our customers in each industry. As we continue to diversify our customer base and win new customers we may continue to see a change in the industry concentrations of our revenue. +Sales to foreign locations represented 22.6 percent and 28.3 percent of our total net sales in fiscal years 2017 and 2016, respectively. +Cost of Sales +Total cost of sales as a percentage of net sales was 91.8 percent and 92.0 percent in fiscal years 2017 and 2016, respectively. +Total cost of materials as a percentage of net sales was approximately 61.7 percent and 63.9 percent in fiscal years 2017 and 2016, respectively. The change from year-to-year is primarily a result of improved pricing of certain raw materials as well as a more favorable product mix. +Production and support costs as a percentage of net sales were 30.1 percent and 28.1 percent in fiscal years 2017 and 2016, respectively. The increase in fiscal year 2017 is primarily related absorption increasing as a percentage of sales during the fiscal year. +We provide a reserve for obsolete and non-saleable inventories based on specific identification of inventory against current demand and recent usage. We also consider our customers' ability to pay for inventory whether or not there is a lead-time assurance agreement for a specific program. The amounts charged to expense for these inventories were approximately $0.5 million and $0.8 million in fiscal years 2017 and 2016, respectively. +We provide warranties on certain products we sell and estimate warranty costs based on historical experience and anticipated product returns. Warranty expense is related to workmanship claims on keyboards and EMS products. The amounts charged to expense are determined based on an estimate of warranty exposure. The net warranty expense was approximately $68,000 and $95,000 in fiscal years 2017 and 2016, respectively. +Gross Profit +Gross profit as a percentage of net sales was 8.2 percent and 8.0 percent in fiscal years 2017, and 2016, respectively. The 0.2 percentage point increase in gross profit as a percentage of net sales during fiscal year 2017 as compared to fiscal year 2016 is primarily related to a 1.7 percentage point decrease in material related costs partially offset by a 1.5 percentage point increase in certain overhead costs. This reflects an increase in gross margin percentage year-over-year as the unprofitable manufacturing facility was closed and trimming non-profitable programs. +Changes in gross profit margins reflect the impact of a number of factors that can vary from period to period, including product mix, start-up costs and efficiencies associated with new programs, product life cycles, sales volumes, capacity utilization of our resources, management of inventories, component pricing and shortages, end market demand for customers’ products, fluctuations in and timing of customer orders, and competition within the EMS industry. These and other factors can cause variations in operating results. There can be no assurance that gross margins will not decrease in future periods. +We took early pay discounts to suppliers that totaled approximately $1.9 million and $1.9 million in fiscal years 2017 and 2016, respectively. Early pay discounts will fluctuate based on our liquidity and changes in the discounts and terms offered by our suppliers. +24 +Research, Development and Engineering +Research, development and engineering expenses (RD&E) consists principally of employee related costs, third party development costs, program materials, depreciation and allocated information technology and facilities costs. Total RD&E expenses were $6.4 million in fiscal years 2017 and 2016. Total RD&E expenses as a percent of net sales were 1.4 percent and 1.3 percent in fiscal years 2017 and 2016, respectively. +Selling, General and Administrative +Selling, general and administrative expenses (SG&A) consist principally of salaries and benefits, advertising and marketing programs, sales commissions, travel expenses, provision for doubtful accounts, facilities costs, and professional services. Total SG&A expenses were $22.4 million and $22.0 million in fiscal years 2017 and 2016, respectively. Total SG&A expenses as a percent of net sales were 4.8 percent and 4.5 percent in fiscal years 2017 and 2016, respectively. This 0.3 percentage point increase in SG&A as a percentage of net sales is primarily related to an increase in legal fees. +Interest Expense +We had net interest expense of $2.3 million in both fiscal years 2017 and 2016. +Income Tax Provision +We had an income tax expense of approximately $1.6 million during both fiscal years 2017 and 2016. The income tax expense recognized during both fiscal years 2017 and 2016, was primarily a function of U.S., federal, state and foreign taxes recognized at the statutory rates offset by the net benefit associated with federal research and development tax credits and changes in potential foreign tax credits. +We continually review our requirements for liquidity domestically to fund current operations, revenue growth and to look for potential future acquisitions. We anticipate repatriating a portion of our unremitted foreign earnings. The estimated taxes and associated foreign tax credits are included in the income tax calculation. For further information on taxes please review footnote 6 of the “Notes to Consolidated Financial Statements.” +25 +Capital Resources and Liquidity +Operating Cash Flow +Net cash provided by operating activities for fiscal year 2018 was $11.5 million compared to net cash provided by operating activities of $9.4 million and $4.6 million in fiscal years 2017 and 2016 , respectively. +The $11.5 million of net cash provided by operating activities during fiscal year 2018 is primarily related to $1.3 million of net loss, $7.8 million of depreciation and amortization, a $23.3 million increase in accounts payable, $10.6 million decrease in accounts receivable, a $0.6 million decrease in inventory, partially offset by a $4.5 million loss on arbitration. The $9.4 million of net cash provided by operating activities during fiscal year 2017 was primarily due to $5.6 million of net income, $7.2 million of depreciation and amortization and a $4.9 million decrease in inventory, partially offset by a $3.5 million increase in accounts receivable and a $5.9 million decrease in accounts payable. The $4.6 million of cash provided by operating activities during fiscal year 2016 was primarily due to $6.5 million of net income, $6.2 million of depreciation and amortization and an $11.1 million decrease in accounts receivable offset by a $16.2 million increase in inventory and a $2.6 million decrease in accounts payable. +Accounts receivable fluctuates based on the timing of shipments, terms offered and collections. In addition, accounts receivable will fluctuate based upon the amount of accounts receivable sold under our Trade Accounts Receivable Purchase Program. During fiscal years 2018 , 2017 and 2016 , we factored receivables of $104.7 million , $86.5 million and $78.0 million, respectively, from accounts receivable sold to financial institutions, which are not included on our Consolidated Balance Sheets. We purchase inventory based on customer forecasts and orders, and when those forecasts and orders change, the amount of inventory may also fluctuate. Accounts payable fluctuates with changes in inventory levels, volume of inventory purchases, negotiated supplier terms, and taking advantage of early pay discounts. +Investing Cash Flow +Cash flows used in investing activities were $3.5 million , $8.5 million , and $5.7 million in fiscal years 2018 , 2017 and 2016 , respectively. Our primary investing activity during fiscal year 2018 and 2017, was purchasing equipment to support increased production levels for new programs. Our primary investing activities during fiscal year 2016 was the purchase of equipment to support increased production levels for new programs as well as the sale and leaseback of equipment. +Operating and capital leases are often utilized when potential technical obsolescence and funding requirement advantages outweigh the benefits of equipment ownership. Capital expenditures and periodic lease payments are expected to be financed with internally generated funds and available borrowing capacities. During fiscal years 2018, 2017 and 2016, we received $1.0 million, $0.6 million and $13.3 million of cash resulting from the sale and leaseback of equipment under operating leases, respectively. +Financing Cash Flow +Cash flows used in financing activities were $8.0 million in fiscal year 2018 and $1.6 million in fiscal year 2017 as compared to cash provided by financing activities of $1.7 million in fiscal year 2016 . Our primary financing activities during fiscal year 2018 , were repayments on our term loans of $5.9 million as well as borrowings and repayments under our revolving line of credit facility. Our primary financing activities during fiscal year 2017 was the funding of a $3.9 million equipment term loan, repayments on our term loans of $5.4 million as well as borrowings and repayments under our revolving line of credit facility. Our primary financing activities during fiscal year 2016 were repayments on our term loan of $5.0 million as well as borrowings and repayments under our revolving line of credit facility. +As of June 30, 2018 , the Company had an outstanding balance on the line of credit of $16.2 million . We had availability to borrow an additional $28.4 million under the Wells Fargo line of credit and we were in compliance with our loan covenants. Our cash requirements are affected by the level of current operations and new EMS programs. We believe that projected cash from operations, funds available under the revolving credit facility and fixed asset financing will be sufficient to meet our working and fixed capital requirements for the foreseeable future. +As of June 30, 2018 , we had approximately $0.3 million of cash held by foreign subsidiaries. Under the Tax Cuts and Jobs Act, future cash repatriations from these foreign subsidiaries are no longer subject to U.S. income taxes, but may be subject to foreign withholding taxes. See additional discussion in Footnote 6, Income Taxes. The total amount of foreign withholding taxes required to be paid for the amount of foreign subsidiary cash on hand as of June 30, 2018 , would approximate $27,000. The Company also has approximately $29.5 million of foreign earnings that have not been repatriated to the U.S. Of that amount, the Company estimates that $14.3 million is to be repatriated in the future, requiring foreign withholding taxes of $0.8 million that is currently accrued in our deferred tax liabilities. The remaining $15.2 million is considered to be permanently reinvested in Mexico and China. If these amounts were required to be repatriated, we estimate it would create an additional $1.3 million in foreign withholding taxes payable. +26 +Contractual Obligations and Commitments +In the normal course of business, we enter into contracts which obligate us to make payments in the future. The table below sets forth our significant future obligations by fiscal year: +Payments Due by Fiscal Year (in thousands) +Total +2019 +2020 +2021 +2022 +2023 +Thereafter +Term loans (1) +$ +18,862 +$ +5,871 +$ +12,120 +$ +871 +$ +— +$ +— +$ +— +Wells Fargo Bank N.A. revolving loan (2) +$ +16,222 +$ +— +$ +16,222 +$ +— +$ +— +$ +— +$ +— +Operating leases (3) +$ +18,500 +$ +6,387 +$ +3,128 +$ +2,119 +$ +1,385 +$ +1,308 +$ +4,173 +Purchase orders (4) +(1) +The terms of the Wells Fargo Bank N.A. term loans are discussed in the consolidated financial statements at Note 4, “Long-Term Debt.” Principal on the term loan is payable in equal quarterly installments of $1.25 million through June 15, 2019, with final installment of all remaining unpaid principal due on August 31, 2019. The equipment term loan is payable in equal quarterly payments of approximately $0.2 million which commenced on March 31, 2017 and will continue through the maturity of the equipment term loan on June 30, 2021. +(2) +The terms of the Wells Fargo Bank N.A. revolving loan are discussed in the consolidated financial statements at Note 4, “Long-Term Debt.” As of June 30, 2018 , we were in compliance with our loan covenants. +(3) +We maintain vertically integrated manufacturing operations in the United States, Mexico and China. We lease some of our administrative and manufacturing facilities and equipment. A complete discussion of properties can be found in Part 1, Item 2 at “Properties.” Leases have proven to be an acceptable method for us to acquire new or replacement equipment and to maintain facilities with a minimum impact on our short term cash flows for operations. In addition, such operations are heavily dependent upon technically superior manufacturing equipment including molding machines in various tonnages, Surface Mount Technology (SMT) lines, sheet metal fabrication and stamping machines, clean rooms, and automated insertion, and test equipment for the various products we are capable of producing. +(4) +As of June 30, 2018 , we had open purchase order commitments for materials and other supplies of approximately $36.4 million. Included in the open purchase orders are various blanket orders for annual requirements. Actual needs under these blanket purchase orders fluctuate with our manufacturing levels and as such cannot be broken out between fiscal years. In addition, we have contracts with many of our customers that minimize our exposure to losses for material purchased within lead-times necessary to meet customer forecasts. Purchase orders generally can be cancelled without penalty within specified ranges that are determined in negotiations with our suppliers. These agreements depend in part on the type of materials purchased as well as the circumstances surrounding any requested cancellations. +In addition to the cash requirements presented above, we have various other accruals which are not included in the table above. For example, we owe our suppliers approximately $76.2 million for accounts payable and shipments in transit at the end of the fiscal year. We generally pay our suppliers in a range from 30 to 120 days depending on terms offered. These payments are financed by operating cash flows and our revolving line of credit. +We believe that cash flows generated from operations, factoring, leasing facilities, and funds available under the revolving credit facility will satisfy cash requirements for a period in excess of 12 months and into the foreseeable future. +27 +Critical Accounting Policies and Estimates +Preparation of our consolidated financial statements requires management to make estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses. Note 1 to our consolidated financial statements describes the significant accounting policies used in the preparation of our consolidated financial statements. Management believes the most complex and sensitive judgments, because of their significance to our consolidated financial statements, result primarily from the need to make estimates about effects of matters that are inherently uncertain. The most significant areas involving management judgments are described below. Actual results in these areas could differ from management’s estimates. +Revenue +Sales revenue from manufacturing is recognized upon shipment of the manufactured product per contractual terms. Upon shipment, title transfers and the customer assumes risks and rewards of ownership of the product. The price to the buyer is fixed or determinable and recoverability is reasonably assured. Unless specifically stated in contractual terms, there are no formal customer acceptance requirements or further obligations related to the manufacturing services; if any such requirements exist, then sales revenue is recognized at the time when such requirements are completed and such obligations are fulfilled. Revenue is recorded net of estimated returns of manufactured product based on management’s analysis of historical returns. +Revenues and associated costs from engineering design, development services and tooling, which are performed under contract of short term durations, are recognized only after the completed performance of the service. +Inactive, Obsolete, and Surplus Inventory Reserve +Inventories are stated at the lower of cost or net realizable value. Cost is determined principally using the first-in, first-out (FIFO) method. We reserve for inventories that we deem inactive, obsolete or surplus. This reserve is calculated based upon the demand for the products that we produce. Demand is determined by expected sales, customer purchase orders, or customer forecasts. If expected sales do not materialize, then we would have inventory in excess of our reserves and would have to charge the excess against future earnings. In the case where we have purchased material based upon a customer’s forecast or purchase orders, we are usually covered by lead-time assurance agreements or purchase orders with each customer. These contracts state that the financial liability for material purchased within agreed upon lead-time and based upon the customer’s forecasts, lies with the customer. If we purchase material outside the lead-time assurance agreement and the customer’s forecasts do not materialize or if we have no lead-time assurance agreement for a specific program, we would have the financial liability and may have to charge inactive, obsolete or surplus inventory against earnings. We also reserve for inventory related to specific customers covered by lead-time assurance agreements when those customers are experiencing financial difficulties or reimbursement is not reasonably assured. +Allowance for Doubtful Accounts +We value our accounts receivable net of an allowance for doubtful accounts. As of June 30, 2018 , we did not have an allowance for doubtful accounts. As of July 1, 2017 , the allowance for doubtful accounts was approximately $0.1 million. This allowance is based on estimates of the portion of accounts receivable that may not be collected in the future. The estimates used are based primarily on specific identification of potentially uncollectible accounts. Such accounts are identified using publicly available information in conjunction with evaluations of current payment activity. However, if any of our customers were to develop unexpected and immediate financial problems that would prevent payment of open invoices, we could incur additional and possibly material expenses that would negatively impact earnings. +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. We review the adequacy of this accrual quarterly based on historical analysis and anticipated product returns and rework costs. Our warranty period for keyboards is generally longer than that for EMS products. We only warrant materials and workmanship on EMS products, and we do not warrant design defects for EMS customers. +Income Taxes +Income tax expense includes U.S. and international income taxes and a provisional estimate for U.S. taxes on undistributed earnings of foreign subsidiaries. We do not record foreign withholding taxes on undistributed earnings of international subsidiaries that are deemed to be permanently reinvested. Certain income and expenses are not reported in tax returns and financial statements in the same year. The tax effect of such temporary differences is reported as deferred income taxes. The deferred income taxes are classified as long-term assets or liabilities. The most significant areas involving management judgments include deferred income tax assets and liabilities, uncertain tax positions, and research and development tax credits. Our estimates of the realization of the deferred tax assets related to our tax credits are based upon our estimates of future taxable income which may change. +28 +Stock-Based Compensation +Stock-based compensation is accounted for according to Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 718, Compensation—Stock Compensation . ASC 718 requires us to expense the fair value of employee stock options, stock appreciation rights and other forms of stock-based compensation. Under the fair value recognition provisions of ASC 718, share-based compensation cost is estimated at the grant date based upon the fair value of the award and is recognized as expense ratably over the requisite service period of the award (generally the vesting period). Determining the appropriate fair value model and calculating the fair value of share-based awards requires judgment, including estimating the expected life of the share-based award, the expected stock price volatility over the expected life of the share-based award and forfeitures. +To determine the fair value of stock based awards on the date of grant we use the Black-Scholes option-pricing model. Inherent in this model are assumptions related to expected stock price volatility, option life, risk-free interest rate and dividend yield. The risk-free interest rate is a less-subjective assumption as it is based on factual data derived from public sources. We use a dividend yield of zero as we have never paid cash dividends and have no intention to pay cash dividends in the foreseeable future. The expected stock price volatility and option life assumptions require a greater level of judgment. Our expected stock-price volatility assumption is based upon the historical volatility of our stock which is obtained from public data sources. The expected life represents the weighted average period of time that share-based awards are expected to be outstanding, giving consideration to vesting schedules and historical exercise patterns. We determine the expected life assumption based upon the exercise and post-vesting behavior that has been exhibited historically, adjusted for specific factors that may influence future exercise patterns. If expected volatility or expected life were to increase, that would result in an increase in the fair value of our stock options which would result in higher compensation charges, while a decrease in volatility or the expected life would result in a lower fair value of our stock option awards resulting in lower compensation charges. +We estimate forfeitures for all of our awards based upon historical experience of stock-based pre-vesting forfeitures. We believe that our estimates are based upon outcomes that are reasonably likely to occur. If actual forfeitures are higher than our estimates it would result in lower compensation expense and to the extent the actual forfeitures are lower than our estimate we would record higher compensation expense. +Impairment of Long-Lived Assets +Long-lived assets, such as property, plant, and equipment are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment charge would be recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. +Derivatives and Hedging Activity +Derivatives are recognized on the balance sheet at their estimated fair value. On the date a derivative contract is entered into, the Company designates the derivative as a hedge of a forecasted transaction or of the variability of cash flows to be received or paid related to a recognized asset or liability (a “cash flow” hedge). The Company does not enter into derivatives for speculative purposes. Changes in the fair value of a derivative that qualifies as a cash flow hedge are recorded in “Accumulated Other Comprehensive Income,” until earnings are affected by the variability of cash flows. See Note 11 of the Company’s consolidated financial statements for additional information. +Long-Term Incentive Compensation Accrual +Long-term incentive compensation is recognized as expense ratably over the requisite service period of the award which is generally three years. The Board of Directors approve target performance measures for the three year period for each of the Company’s officers and non-employee Directors. Performance measures are based on a combination of sales growth targets and return on invested capital targets. No cash awards will be made to participants if actual Company performance does not exceed the minimum target performance measures. The calculation used to determine the necessary accrual uses a combination of actual results and projected results. We believe that our estimates are based upon outcomes that are reasonably likely to occur. These estimates and assumptions are based on historical results as well as future expectations. Actual results could vary from our estimates and assumptions. +29 +Impairment of Goodwill +In accordance with ASC 350, Goodwill and Other Intangible Assets , goodwill is not amortized but is required to be reviewed for impairment at least annually or when events or circumstances indicate that carrying value may exceed fair value. The Company is permitted the option to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the fair value of any reporting unit is less than its corresponding carrying value. If, after assessing the totality of events and circumstances, the Company concludes that it is not more likely than not that the fair value of any reporting unit is less than its corresponding carrying value then the Company is not required to take further action. However, if the Company concludes otherwise, then it is required to perform a quantitative impairment test, including computing the fair value of the reporting unit and comparing that value to its carrying value. The Company utilizes a weighting of the income approach and a market approach in the impairment test. We also consider valuation factors including the Company's market capitalization, future discounted cash flows and an estimated control premium based upon a review of comparable market transactions. Our consideration of discounted future cash flows included assumptions regarding growth rates and margins based on our historical trends. In addition, we applied a market discount rate calculated based upon an analysis of companies similar in size. If our future cash flows do not meet our projections or there is an event that impacts our market capitalization, the assumptions used in our goodwill analysis could be negatively impacted. The estimated fair value of the reporting unit exceeded the carrying value by approximately 38%. We will continue to monitor our market capitalization and impairment indicators. +If the fair value is less than its carrying value, a second step of the test is required to determine if recorded goodwill is impaired. In the event that goodwill is impaired, an impairment charge to earnings would become necessary. The Company also has the option to bypass the qualitative assessment for goodwill in any period and proceed directly to performing the quantitative impairment test. +New and Future Accounting Pronouncements +See Note 1 to our consolidated financial statements. +30 +Item 7A: +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Interest Rate Risk +We are subject to the risk of fluctuating interest rates in the normal course of business. Our major market risk relates to our secured debt. Our revolving credit facility and term loan are secured by substantially all of our assets. The interest rates applicable to our revolving credit facility and term loans fluctuate with the Wells Fargo Bank N.A. prime rate and LIBOR rates. There was outstanding $16.2 million in borrowings under our revolving credit facility and $18.9 million outstanding on our term loans as of June 30, 2018 . See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity” and Note 4 – “Long-Term Debt” to the Consolidated Financial Statements for additional information regarding our revolving credit facility and term loan. +Our only material interest rate risk is associated with our revolving credit facility and term loans. During the second quarter of fiscal year 2015, we entered into an interest rate swap contract with a notional amount of $25.0 million related to the borrowings outstanding under the term loan and revolving credit facility. As of June 30, 2018 , the remaining notional amount of the interest rate swap contract was $8.5 million. Through the use of the interest rate swap, as described above, we fixed the basis on which we pay interest, thus eliminating much of our interest rate risk. See Note 11 – “Derivative Financial Instruments” to the Consolidated Financial Statements for additional information regarding our derivative instruments. +Foreign Currency Exchange Risk +A significant portion of our operations are in foreign locations. As a result, transactions occur in currencies other than the U.S. dollar. Exchange rate fluctuations among other currencies used by us would directly or indirectly affect our financial results. We currently use Mexican peso forward contracts and swaps to hedge foreign currency fluctuations for a portion of our Mexican peso denominated expenses. There was $46.3 million of foreign currency forward contracts and swaps outstanding as of June 30, 2018 . The fair value of these contracts and swaps was approximately $(1.2) million . See Note 11 – “Derivative Financial Instruments” to the Consolidated Financial Statements for additional information regarding our derivative instruments. +31 +Item 8: +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Key Tronic Corporation +Spokane Valley, Washington +Opinion on the Consolidated Financial Statements +We have audited the accompanying consolidated balance sheets of Key Tronic Corporation (the “Company”) and subsidiaries as of June 30, 2018 and July 1, 2017, the related consolidated statements of income (loss), comprehensive income, shareholders’ equity, and cash flows for each of the three years in the period ended June 20, 2018, and the related notes and schedule (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company and subsidiaries at June 30, 2018 and July 1, 2017, and the results of their operations and their cash flows for each of the three years in the period ended June 30, 2018 , in conformity with accounting principles generally accepted in the United States of America. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company's internal control over financial reporting as of June 30, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) and our report dated September 10, 2018 expressed an unqualified opinion thereon. +Basis for Opinion +These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. +Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. +/s/ BDO USA, LLP +We have served as the Company's auditor since 2003 +Spokane, Washington +September 10, 2018 +32 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED BALANCE SHEETS +(In thousands) +June 30, 2018 +July 1, 2017 +ASSETS +Current assets: +Cash and cash equivalents +$ +343 +$ +373 +Trade receivables, net of allowance for doubtful accounts of $0 and $84 +70,262 +65,193 +Inventories, net +110,315 +101,590 +Other +13,600 +11,037 +Total current assets +194,520 +178,193 +Property, plant and equipment, net +27,548 +30,496 +Other assets: +Deferred income tax asset +7,882 +6,981 +Goodwill +9,957 +9,957 +Other intangible assets, net +3,726 +4,800 +Other +2,895 +2,413 +Total other assets +24,460 +24,151 +Total assets +$ +246,528 +$ +232,840 +LIABILITIES AND SHAREHOLDERS ’ EQUITY +Current liabilities: +Accounts payable +$ +76,198 +$ +53,078 +Accrued compensation and vacation +8,105 +10,005 +Current portion of debt, net +5,841 +5,841 +Other +8,769 +8,829 +Total current liabilities +98,913 +77,753 +Long-term liabilities: +Term loans +12,932 +18,773 +Revolving loan +16,222 +18,335 +Other long-term obligations +380 +1,412 +Total long-term liabilities +29,534 +38,520 +Total liabilities +128,447 +116,273 +Commitments and contingencies (Note 4 and 9) +Shareholders’ equity: +Common stock, no par value—shares authorized 25,000; issued and outstanding 10,760 and 10,760 shares, respectively +46,244 +45,797 +Retained earnings +72,806 +73,545 +Accumulated other comprehensive loss +(969 +) +(2,775 +) +Total shareholders’ equity +118,081 +116,567 +Total liabilities and shareholders’ equity +$ +246,528 +$ +232,840 +See accompanying notes to consolidated financial statements. +33 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF INCOME (LOSS) +(In thousands, except per share amounts) +Fiscal Year Ended +June 30, 2018 +July 1, 2017 +July 2, 2016 +Net sales +$ +446,322 +$ +467,797 +$ +484,965 +Cost of sales +412,153 +429,497 +446,140 +Gross profit +34,169 +38,300 +38,825 +Research, development and engineering expenses +6,186 +6,393 +6,397 +Selling, general and administrative expenses +22,334 +22,363 +22,012 +Loss on settlement of arbitration +4,535 +— +— +Total operating expenses +33,055 +28,756 +28,409 +Operating income +1,114 +9,544 +10,416 +Interest expense, net +2,556 +2,288 +2,265 +Income (loss) before income taxes +(1,442 +) +7,256 +8,151 +Income tax provision +(117 +) +1,639 +1,618 +Net income (loss) +$ +(1,325 +) +$ +5,617 +$ +6,533 +Net income (loss) per share — Basic +$ +(0.12 +) +$ +0.52 +$ +0.61 +Weighted average shares outstanding — Basic +10,760 +10,756 +10,710 +Net income (loss) per share — Diluted +$ +(0.12 +) +$ +0.51 +$ +0.58 +Weighted average shares outstanding — Diluted +10,760 +10,917 +11,278 +See accompanying notes to consolidated financial statements. +34 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME +(In thousands) +Fiscal Year Ended +June 30, 2018 +July 1, 2017 +July 2, 2016 +Comprehensive income: +Net income (loss) +$ +(1,325 +) +$ +5,617 +$ +6,533 +Other comprehensive income (loss): +Unrealized gain (loss) on hedging instruments, net of tax +2,392 +4,798 +(2,810 +) +Comprehensive income +$ +1,067 +$ +10,415 +$ +3,723 +Other comprehensive income for fiscal years 2018 , 2017 , and 2016 is reflected net of tax provision (benefit) of approximately $0.7 million , $2.5 million and $(1.4) million , respectively. +See accompanying notes to consolidated financial statements. +35 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Fiscal Year Ended +June 30, 2018 +July 1, 2017 +July 2, 2016 +Operating activities: +Net income (loss) +$ +(1,325 +) +$ +5,617 +$ +6,533 +Adjustments to reconcile net income (loss) to cash provided by operating activities: +Depreciation and amortization +7,774 +7,232 +6,162 +Amortization of deferred loan costs +30 +17 +— +Excess tax benefit from exercise of stock options +— +— +(402 +) +Provision for obsolete inventory +31 +496 +757 +Provision for warranty +74 +68 +95 +(Recovery of) provision for doubtful accounts +(84 +) +(10 +) +38 +Loss on disposal of assets +20 +101 +— +Share-based compensation expense +447 +692 +764 +Deferred income taxes +(1,562 +) +(471 +) +(1,313 +) +Loss on settlement of arbitration +(4,535 +) +— +— +Changes in operating assets and liabilities +Trade receivables +(10,601 +) +(3,505 +) +11,136 +Inventories +589 +4,920 +(16,169 +) +Other assets +(2,872 +) +636 +1,739 +Accounts payable +23,320 +(5,889 +) +(2,561 +) +Accrued compensation and vacation +(1,900 +) +434 +104 +Other liabilities +2,051 +(913 +) +(2,303 +) +Cash provided by operating activities +11,457 +9,425 +4,580 +Investing activities: +Purchases of property and equipment +(4,523 +) +(9,307 +) +(13,277 +) +Proceeds from sale of fixed assets +1,041 +834 +7,612 +Cash used in investing activities +(3,482 +) +(8,473 +) +(5,665 +) +Financing activities: +Payment of financing costs +(21 +) +(221 +) +(113 +) +Proceeds from issuance of long term debt +— +3,919 +— +Repayments of long term debt +(5,871 +) +(5,435 +) +(5,000 +) +Borrowings under revolving credit agreement +187,419 +161,240 +197,568 +Repayments of revolving credit agreement +(189,532 +) +(160,978 +) +(191,126 +) +Excess tax benefit from exercise of stock options +— +— +402 +Tax withholding from exercise of share-based compensation +— +(122 +) +— +Cash (used in) provided by financing activities +(8,005 +) +(1,597 +) +1,731 +Net (decrease) increase in cash and cash equivalents +(30 +) +(645 +) +646 +Cash and cash equivalents, beginning of period +373 +1,018 +372 +Cash and cash equivalents, end of period +$ +343 +$ +373 +$ +1,018 +Supplemental cash flow information: +Interest payments +$ +2,529 +$ +2,238 +$ +2,308 +Income tax payments, net of refunds +$ +304 +$ +1,799 +$ +813 +See accompanying notes to consolidated financial statements. +36 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY +(In thousands) +Shares +Common +Stock +Retained +Earnings +Accumulated +Other +Comprehensive +Income (Loss) +Total +Shareholders’ +Equity +Balances, June 27, 2015 +10,706 +$ +44,136 +$ +61,395 +$ +(4,763 +) +$ +100,768 +Net income +— +— +6,533 +— +6,533 +Unrealized loss on hedging instruments, net +— +— +— +(2,810 +) +(2,810 +) +Exercise of stock appreciation rights +28 +— +— +— +— +Shares withheld for taxes +(9 +) +(75 +) +— +— +(75 +) +Share-based compensation +— +764 +— +— +764 +Excess tax benefit from share-based compensation +— +402 +— +— +402 +Balances, July 2, 2016 +10,725 +$ +45,227 +$ +67,928 +$ +(7,573 +) +$ +105,582 +Net income +— +— +5,617 +— +5,617 +Unrealized gain on hedging instruments, net +— +— +— +4,798 +4,798 +Exercise of stock appreciation rights +49 +— +— +— +— +Shares withheld for taxes +(14 +) +(122 +) +— +— +(122 +) +Share-based compensation +— +692 +— +— +692 +Balances, July 1, 2017 +10,760 +$ +45,797 +$ +73,545 +$ +(2,775 +) +$ +116,567 +Net loss +— +— +(1,325 +) +— +(1,325 +) +Tax Rate Effect Reclassification +— +— +586 +(586 +) +— +Unrealized gain on hedging instruments, net +— +— +— +2,392 +2,392 +Share-based compensation +— +447 +— +— +447 +Balances, June 30, 2018 +10,760 +$ +46,244 +$ +72,806 +$ +(969 +) +$ +118,081 +See accompanying notes to consolidated financial statements. +37 +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. SIGNIFICANT ACCOUNTING POLICIES +Business +Key Tronic Corporation and subsidiaries (the Company) is engaged in electronic manufacturing services (EMS) for original equipment manufacturers (OEMs) and also manufactures keyboards and other input devices. The Company’s headquarters are located in Spokane Valley, Washington with manufacturing operations in Oakdale, Minnesota; Fayetteville, Arkansas; Corinth, Mississippi; and foreign manufacturing operations in Juarez, Mexico; and Shanghai, China. +Principles of Consolidation +The consolidated financial statements include the Company and its wholly owned subsidiaries in the United States, Mexico and China. Intercompany balances and transactions have been eliminated during consolidation. +Use of Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates include the allowance for doubtful receivables, the provision for obsolete and non-saleable inventories, deferred tax assets and liabilities, uncertain tax positions, valuation of goodwill, impairment of long-lived assets, medical self-funded insurance liability, long-term incentive compensation accrual, the provision for warranty costs, the fair value of stock appreciation rights granted under the Company’s share-based compensation plan and purchase price allocation of acquired businesses. Due to uncertainties with respect to the assumptions and estimates, actual results could differ from those estimates. +Cash and Cash Equivalents +The Company considers investments with an original maturity of three months or less to be cash equivalents. Cash equivalents are carried at cost, which approximates fair value. The Company may have cash and cash equivalents at financial institutions that are in excess of federally insured limits from time to time. +Allowance for Doubtful Accounts +The Company evaluates the collectability of accounts receivable and records an allowance for doubtful accounts, which reduces the receivables to an amount that management reasonably estimates will be collected. A specific allowance is recorded against receivables considered to be impaired based on the Company’s knowledge of the financial condition of the customer. In determining the amount of the allowance, the Company considers several factors including the aging of the receivables, the current business environment and historical experience. After all attempts to collect a receivable have failed, the receivable is written off against the allowance. +Inventories +Inventories are stated at the lower of cost or net realizable value. Cost is determined principally using the first-in, first-out (FIFO) method. Customer orders are based upon forecasted quantities of product manufactured for shipment over defined periods. Raw material inventories are purchased to fulfill these customer requirements. Within these arrangements, customer demands for products frequently change, sometimes creating excess and obsolete inventories. The Company regularly reviews raw material inventories by customer for both excess and obsolete quantities. Wherever possible, the Company attempts to recover its full cost of excess and obsolete inventories from customers or, in some cases, through other markets. When it is determined that the Company’s carrying cost of such excess and obsolete inventories cannot be recovered in full, a charge is taken against income for the difference between the carrying cost and the estimated realizable amount. We also reserve for inventory related to specific customers covered by lead-time assurance agreements when those customers are experiencing financial difficulties or reimbursement is not reasonably assured. +Property, Plant and Equipment +Property, plant and equipment are carried at cost and depreciated using straight-line methods over the expected useful lives of the assets. Repairs and maintenance costs are expensed as incurred. +38 +Impairment of Goodwill +The Company records intangible assets that are acquired individually or with a group of other assets in the financial statements at acquisition. In accordance with ASC 350, Goodwill and Other Intangible Assets , goodwill is not amortized but is required to be reviewed for impairment at least annually or when events or circumstances indicate that carrying value may exceed fair value. The Company tests goodwill by first performing a qualitative analysis (“Step 0”) to determine if it is more likely than not that the fair value of the reporting unit is greater than its carrying value. If the Company determines that it is not more likely than not that the fair value of the reporting unit is greater than its carrying value, the Company calculates the fair value of the reporting unit and compares the fair value of the reporting unit to its carrying value (“Step 1”). If the carrying value of the reporting unit exceeds the fair value, goodwill is potentially impaired and the second step (“Step 2”) of the impairment test must be performed. In the second step, the Company compares the implied fair value of the goodwill, as defined by ASC 350, to the carrying amount to determine the impairment loss, if any. +The Company performed its annual qualitative Step 0 analysis as of April 2, 2018 and determined a Step 1 analysis was necessary due to market conditions. Based on the results of the Step 1 analysis, the Company concluded that the fair value of the reporting unit was greater than the carrying value of the reporting unit based on a methodology that utilized both an income approach and a market approach. We considered valuation factors including the Company's market capitalization, future discounted cash flows and an estimated control premium based upon a review of comparable market transactions. Our consideration of discounted future cash included assumptions regarding growth rates and margins based on our historical trends. In addition, we applied a market discount rate calculated based upon an analysis of companies similar in size. The estimated fair value of the reporting unit exceeded the carrying value by approximately 38%. We will continue to monitor our market capitalization and impairment indicators. +Impairment of Long-lived Assets +The Company, using its best estimates based on reasonable and supportable assumptions and projections, reviews assets for impairment whenever events or changes in circumstances have indicated that the carrying amount of its assets might not be recoverable. Impaired assets are reported at the lower of cost or fair value. +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. Management reviews the adequacy of this accrual quarterly based on historical analyses and anticipated product returns. +Self-funded Insurance +The Company self-funds its domestic employee health plans. The Company contracts with a separate administrative service company to supervise and administer the programs and act as its representative. The Company reduces its risk under this self-funded platform by purchasing stop-loss insurance coverage for high dollar individual claims. In addition, if the aggregate annual claims amount to more than 125 percent of expected claims for the plan year this insurance will also pay those claims amounts exceeding that level. +The Company estimates its exposure for claims incurred but not paid at the end of each reporting period and uses historical claims data supplied by the Company’s broker to estimate its self-funded insurance liability. This liability is subject to a total limitation that varies based on employee enrollment and factors that are established at each annual contract renewal. Actual claims experience may differ from the Company’s estimates. Costs related to the administration of the plan and related claims are expensed as incurred. +39 +Revenue Recognition +Sales revenue from manufacturing is recognized upon shipment of the manufactured product per contractual terms. Upon shipment, title transfers and the customer assumes risks and rewards of ownership of the product. The price to the buyer is fixed or determinable and recoverability is reasonably assured. Unless specifically stated in contractual terms, there are no formal customer acceptance requirements or further obligations related to the manufacturing services; if any such requirements exist, then sales revenue is recognized at the time when such requirements are completed and such obligations are fulfilled. Revenue is recorded net of estimated returns of manufactured product based on management’s analysis of historical returns. +Revenues and associated costs from engineering design, development services and tooling, which are performed under contract of short term durations, are recognized only after the completed performance of the service. Revenue from engineering design, development services and tooling represented approximately 2.7 percent , 2.1 percent and 1.7 percent of total revenue in fiscal years 2018 , 2017 , and 2016 , respectively. +Shipping and Handling Fees +The Company classifies costs associated with shipping and handling fees as a component of cost of goods sold. Customer billings related to shipping and handling fees are reported as revenue. +Research, Development and Engineering +Research, development and engineering expenses include unreimbursed EMS costs as well as design and engineering costs associated with the production of EMS programs. Research, development and engineering costs are expensed as incurred. +Income Taxes +Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the estimated future tax consequences and benefits attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities for a change in tax rates is recognized in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amount that is more likely than not to be realized. +We utilize a two-step approach to recognizing and measuring uncertain tax positions. The first step is to evaluate the tax position for recognition by determining if the weight of available evidence indicates it is more likely than not that the position will be sustained on audit, including resolution of related appeals or litigation processes, if any. The second step is to measure the tax benefit as the largest amount which is more than 50% likely of being realized upon ultimate settlement. We consider many factors when evaluating and estimating our tax positions and tax benefits, which may require periodic adjustments based on new assessments and changes in estimates and which may not accurately forecast actual outcomes. Our policy is to recognize interest and penalties related to the underpayment of income taxes as a component of income tax provision. To date, we have not incurred charges for interest or penalties in relation to the underpayment of income taxes. The tax years 1997 through the present remain open to examination by the major U.S. taxing jurisdictions to which we are subject. Refer to Note 6 for further discussions. +Derivative Instruments and Hedging Activities +The Company has entered into foreign currency forward contracts and an interest rate swap which are accounted for as cash flow hedges in accordance with ASC 815, Derivatives and Hedging . The effective portion of the gain or loss on the derivative is reported as a component of accumulated other comprehensive income (AOCI) and is reclassified into earnings in the same period in which the underlying hedged transaction affects earnings. The derivative’s effectiveness represents the change in fair value of the hedge that offsets the change in fair value of the hedged item. +The Company uses derivatives to manage the variability of foreign currency fluctuations of expenses in our Mexico facilities and interest rate risk associated with certain borrowings under the Company’s debt arrangement. The foreign currency forward contracts and interest rate swaps have terms that are matched to the underlying transactions being hedged. As a result, these transactions fully offset the hedged risk and no ineffectiveness has been recorded. +The Company’s foreign currency forward contracts and interest rate swaps potentially expose the Company to credit risk to the extent the counterparties may be unable to meet the terms of the agreement. The Company minimizes such risk by seeking high quality counterparties. The Company’s counterparties to the foreign currency forward contracts and interest rate swaps are major banking institutions. These institutions do not require collateral for the contracts, and the Company believes that the risk of the counterparties failing to meet their contractual obligations is remote. The Company does not enter into derivative instruments for trading or speculative purposes. +40 +Earnings Per Common Share +Basic earnings per common share is computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is computed by dividing net income by the combination of other potentially dilutive weighted average common shares and the weighted average number of common shares outstanding during the period using the treasury stock method. The computation assumes the proceeds from the exercise of stock options were used to repurchase common shares at the average market price during the period. The computation of diluted earnings per common share does not assume conversion, exercise, or contingent issuance of common stock equivalent shares that would have an anti-dilutive effect on earnings per share. +Foreign Currency Transactions +The functional currency of the Company’s subsidiaries in Mexico and China is the U.S. dollar. Realized foreign currency transaction gains and losses for local currency denominated assets and liabilities are included in cost of goods sold. +Fair Value of Financial Instruments +The carrying values of cash and cash equivalents, accounts receivable and current liabilities reflected on the balance sheets at June 30, 2018 and July 1, 2017 , reasonably approximate their fair value. The Company had an outstanding balance on the line of credit of $16.2 million as of June 30, 2018 and $18.3 million as of July 1, 2017 , with a carrying value that reasonably approximates the fair value. The Company had an outstanding balance on the term loan of $16.3 million as of June 30, 2018 and $21.3 million as of July 1, 2017 , with a carrying value that reasonably approximates the fair value. The equipment term loan is estimated to be $2.6 million as of June 30, 2018 and $3.5 million as of July 1, 2017 , with a carrying value that reasonably approximates the fair value. +Share-based Compensation +The Company’s incentive plan may provide for equity and liability awards to employees in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, stock units, performance shares, performance units, and other stock-based or cash-based awards. Compensation cost is recognized on a straight-line basis over the requisite employee service period, which is generally the vesting period, and is included in cost of goods sold, research, development and engineering, and selling, general, and administrative expenses. Share-based compensation is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on historical experience and future expectations. +41 +Newly Adopted and Recent Accounting Pronouncements +In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update 2014-09 (ASU 2014-09), Revenue from Contracts with Customers. The guidance in this Update affects any entity that either enters into contracts with customers to transfer goods or services or enters into contracts for the transfer of nonfinancial assets unless those contracts are within the scope of other standards (for example, insurance contracts or lease contracts). The standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In doing so, companies will need to use more judgment and make more estimates than under current guidance. This may include identifying performance obligations in the contract, estimating the amount of variable consideration to include in the transaction price and allocating the transaction price to each separate performance obligation. This Update is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. As such, the guidance is effective for the Company beginning in the first quarter of fiscal year 2019. The Company has substantially completed its review of significant customer contracts and is in the process of finalizing its implementation in accordance with the planned effective date. Remaining implementation activities are focused on improvement of additional system tools and capabilities to enable the Company to make timely and reasonable estimates of revenue during the manufacturing process, as well as the implementation and maintenance of relevant internal controls. The Company has assessed that the impact of the new guidance will result in a change of the Company’s revenue recognition model for the majority of electronics manufacturing services from “point in time” upon physical delivery to an “over time” model and believes this transition will have an impact on the Company’s consolidated financial statements upon adoption primarily as it will recognize an increase in contract assets for unbilled receivables with a corresponding reduction in finished goods and work-in-process inventory. The new guidance allows for two transition methods in application (i) retrospective approach, or (ii) modified retrospective approach. The Company will adopt the standard using the modified retrospective approach, which will result in an adjustment for the cumulative effect of applying this guidance to contracts in process as of the adoption date. Under this approach, prior financial statements presented will not be restated and the effects of the modified retrospective approach will be recorded as an adjustment through retained earnings in the period of adoption. The Company expects the opening balance sheet adjustment to increase retained earnings in the range of $0.5 million and $2.0 million . Additionally, disclosures required for revenue recognition will include qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments, and assets recognized from costs to obtain or fulfill a contract. Such disclosures are more extensive than what is required under existing GAAP. +In February 2016, the FASB issued Accounting Standards Update 2016-02, Leases which supersedes ASC 840 Leases and creates a new topic, ASC 842 Leases. This update requires lessees to recognize a lease asset and a lease liability for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. This update will be applied using a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. Upon initial evaluation, the Company believes the new guidance will have a material impact on its consolidated balance sheets when adopted. The Company intends to adopt the new lease guidance when it becomes effective in the first quarter of fiscal year 2020. +In August 2016, the FASB issued Accounting Standards Update 2016-15, Classification of Certain Cash Receipts and Cash Payments. This update provides guidance on how to record eight specific cash flow issues. This update is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted and a retrospective transition method to each period should be presented. The Company is still assessing the impact of this update on its operating and investing cash flows. The Company intends to adopt the new guidance when it becomes effective in the first quarter of fiscal year 2019. +In January 2017, the FASB issued Accounting Standards Update 2017-04, Simplifying the Test for Goodwill Impairment. Under the new standard, goodwill impairment would be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying value of goodwill. This ASU eliminates existing guidance that requires an entity to determine goodwill impairment by calculating the implied fair value of goodwill by hypothetically assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. This update is effective prospectively to impairment tests beginning January 1, 2020, with early adoption permitted. The Company would apply this guidance to applicable impairment tests after the adoption date. The Company believes this new guidance will not have a material effect on its consolidated financial statements. +In May 2017, the FASB issued Accounting Standards Update 2017-09, Compensation - Stock Compensation. This update provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. The Company believes the new guidance will not have a material effect on its consolidated financial statements. The Company intends to adopt the new guidance when it becomes effective in the first quarter of fiscal year 2019. +42 +In August 2017, the FASB issued Accounting Standards Update 2017-12, Derivatives and Hedging, which amends the hedge accounting recognition and presentation requirements in ASC 815. The Board’s objectives in issuing this update are to (1) improve the transparency and understandability of information about an entity’s risk management activities by better aligning the entity’s financial reporting for hedging relationships with those risk management activities and (2) simplify the application of hedge accounting. This update is effective for fiscal years beginning after December 15, 2018. Early adoption is permitted. The Company is currently evaluating the effect of this update on its consolidated financial statements. The Company expects the new guidance will have an immaterial impact on its consolidated financial statements, and it intends to adopt the guidance when it becomes effective in the first quarter of fiscal year 2020. +In February 2018, the FASB issued Accounting Standards Update 2018-02, Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. This update allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act. The Company early adopted this ASU during the third quarter of fiscal year 2018. As a result of adoption there was a one-time impact to the financial statements to the current period only, as such prior periods were not restated. The impact of adopting ASU 2018-02 is reflected in the Statement of Shareholder’s Equity. +In March 2018, the FASB issued Accounting Standards Update 2018-05, Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118. This update, effective upon issuance, amends SEC paragraphs in ASC 740, Income Taxes, to reflect SEC Staff Accounting Bulletin (SAB) 118, which provides guidance for companies that are not able to complete their accounting for the income tax effects of the Tax Cuts and Jobs Act in the period of enactment. The impact of adopting this guidance is reflected in Footnote 6, Income Taxes. +Fiscal Year +The Company operates on a 52/53 week fiscal year. Fiscal years end on the Saturday nearest June 30. As such, fiscal years 2018 , 2017 , and 2016 , ended on June 30, 2018 , July 1, 2017 , and July 2, 2016 , respectively. Fiscal year 2018 and 2017 were 52 week years whereas fiscal year 2016 was a 53 week year. +2. INVENTORIES +The components of inventories consist of the following (in thousands): +June 30, 2018 +July 1, 2017 +Finished goods +$ +14,927 +$ +12,244 +Work-in-process +22,254 +20,596 +Raw materials and supplies +73,134 +68,750 +$ +110,315 +$ +101,590 +3. PROPERTY, PLANT AND EQUIPMENT +Property, plant and equipment consists of the following: +Life +June 30, 2018 +July 1, 2017 +(in years) +(in thousands) +Land +— +$ +2,940 +$ +2,940 +Buildings and improvements +3 to 30 +23,441 +23,158 +Equipment +1 to 10 +60,367 +57,848 +Furniture and fixtures +3 to 5 +3,754 +3,512 +90,502 +87,458 +Accumulated depreciation +(62,954 +) +(56,962 +) +$ +27,548 +$ +30,496 +43 +4. LONG-TERM DEBT +On September 3, 2014, the Company entered into a five-year term loan in the amount of $35.0 million used to acquire all of the outstanding shares of CDR Manufacturing, Inc. (dba Ayrshire Electronics). The term loan requires quarterly payments of $1.25 million through June 15, 2019, with a final payment of the remaining outstanding balance on August 31, 2019. The Company expects to renew its term loan agreement during the first quarter of fiscal year 2019 and management believes this to be probable. The Company had an outstanding balance of $16.3 million and $21.3 million under the term loan as of June 30, 2018 and July 1, 2017 , respectively. +On August 6, 2015, the Company entered into a First Amendment to the amended and restated credit agreement extending the limit on our line of credit facility to $45.0 million as evidenced by the Second Replacement Revolving Note. The agreement specifies that the proceeds of the revolving line of credit be used primarily for working capital and general corporate purposes. The line of credit is secured by substantially all of the assets of the Company and matures on August 31, 2019 at which time all outstanding balances are payable. The Company expects to renew its credit agreement during the first quarter of fiscal year 2019 and management believes this to be probable. As of June 30, 2018 , the Company had an outstanding balance under the credit facility of $16.2 million , $0.4 million in outstanding letters of credit and $28.4 million available for future borrowings. As of July 1, 2017 , the Company had an outstanding balance under the credit facility of $18.3 million , $0.4 million in outstanding letters of credit and $26.3 million available for future borrowings. +On December 28, 2016, the Company entered into an equipment term loan agreement in the amount of $3.9 million in order to further invest in production equipment. The equipment term loan is collateralized by production equipment. Under this loan agreement, equal quarterly payments of approximately $0.2 million commenced on March 31, 2017 and will continue through the maturity of the equipment term loan on June 30, 2021. Amortization of the debt issuance costs is reported as interest expense on the consolidated income statement. As of June 30, 2018 , the Company had an outstanding balance of $2.6 million . As of July 1, 2017 , the Company had an outstanding balance of $3.5 million . The Company has available an additional $2.1 million which can be borrowed in the future under this agreement. +Borrowings under the revolving line of credit, term loan and equipment term loan bear interest at either a “Base Rate” or a “Fixed Rate,” as elected by the Company. The base rate is the higher of the Wells Fargo Bank prime rate, daily one month London Interbank Offered Rate (LIBOR) plus 1.5% , or the Federal Funds rate plus 1.5% . The fixed rate is LIBOR plus 1.75% , LIBOR plus 2.0% or LIBOR plus 2.25% depending on the level of the Company’s trailing four quarters Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA). The interest rates on the outstanding debt as of June 30, 2018 range from 4.09% - 5.00% compared to 3.22% - 4.25% as of July 1, 2017 . +Debt maturities as of June 30, 2018 for the next three years are as follows (in thousands): +Fiscal Years Ending +Amount +2019 +$ +5,871 +2020 +28,342 +2021 +871 +Total debt +$ +35,084 +Unamortized debt issuance costs +$ +(89 +) +Long-term debt, net of debt issuance costs +$ +34,995 +The Company must comply with certain financial covenants, including a cash flow leverage ratio, an asset coverage ratio and a fixed charge coverage ratio. The credit agreement requires the Company to maintain a minimum profit threshold, limits the maximum capital lease expenditures and restricts the Company from declaring or paying dividends in cash or stock without prior bank approval. The Company was not in compliance with all financial covenants as of June 30, 2018 due to the loss recognized by the arbitration settlement. However, the Company obtained a waiver from Wells Fargo Bank with respect to the noncompliance as of June 30, 2018. +44 +5. TRADE ACCOUNTS RECEIVABLE PURCHASE PROGRAMS +Sale Programs +The Company utilizes an Account Purchase Agreement with Wells Fargo Bank, N.A. ("WFB") which allows the Company to sell and assign to WFB and WFB may purchase from Company the accounts receivable of certain Company customers in a maximum aggregate amount outstanding of $25.0 million . This agreement may be cancelled at any time by either party. The Company also has an Account Purchase Agreement with Orbian Financial Services (“Orbian”). This agreement allows the Company to sell accounts receivable of certain customers to Orbian and the agreement may be cancelled at any time by either party. +Total accounts receivables sold during the twelve months ended June 30, 2018 and July 1, 2017 was approximately $104.7 million and $86.5 million , respectively. Accounts receivables sold and not yet collected was approximately $2.0 million and $1.6 million as of June 30, 2018 and July 1, 2017 , respectively. The receivables that were sold were removed from the consolidated balance sheets and the cash received is reflected as cash provided by operating activities in the consolidated statements of cash flows. +6. INCOME TAXES +Income tax provision consists of the following: +Fiscal Year Ended +June 30, 2018 +July 1, 2017 +July 2, 2016 +(in thousands) +Current income tax provision (benefit): +United States +$ +(221 +) +$ +1,231 +$ +1,014 +Foreign +1,722 +1,206 +1,960 +1,501 +2,437 +2,974 +Deferred income tax provision (benefit): +United States +(795 +) +(539 +) +(1,285 +) +Foreign +(823 +) +(259 +) +(71 +) +(1,618 +) +(798 +) +(1,356 +) +Total income tax provision +$ +(117 +) +$ +1,639 +$ +1,618 +The Company has gross tax credit carryforwards of approximately $8.7 million at June 30, 2018 . Included in total tax credits carryforwards is approximately $8.0 million in research and development (R&D) tax credits. +Management also has reviewed its other deferred tax assets for purposes of determining whether or not a valuation allowance may be required. A valuation allowance against these deferred tax assets is required if it is more likely than not that some of the deferred tax assets will not be realized. Based on the Company’s profitability, it has been determined that it is more likely than not that the deferred tax assets will be realized. +On December 22, 2017, the Tax Cuts and Jobs Act (“Tax Act”) was signed into law. The Tax Act reduced Federal corporate tax rates effective January 1, 2018, and changed certain other provisions, many of which are not effective until the fiscal year ending in 2019. Effective tax rates for the quarter and the twelve months ended June 30, 2018, are blended rates reflecting the benefit of two quarters of Federal tax rate reductions for fiscal year 2018. These benefits were offset by discrete expenses relating to the revaluation of our U.S. net deferred tax assets, an adjustment relating to foreign exchange, and required adjustments associated with the transition from a global to a territorial tax system (discussed further below). +As a result of the U.S. tax system under the Tax Act from a global to a territorial model, a deemed one-time repatriation of all accumulated earnings and profits (AE&P) in Mexico and China occurred on December 31, 2017. For purposes of calculating the toll tax associated with this deemed repatriation, AE&P pools are stratified into two asset categories, subjected to certain allowable deductions and then the net amounts are subjected to the toll tax ( 15.5% for cash/cash equivalents and 8% for illiquid assets). Management has previously relied upon estimates of AE&P and the related tax pools in Mexico and China in order to calculate the amount of foreign earnings that may potentially be repatriated and the resulting potential U.S. tax liability (see further discussion below). Management has undertaken formal studies of the AE&P and tax pools in both Mexico and China and has increased its provisional calculation of the toll tax liability in the fourth quarter by $0.4 million to $1.2 million . +In addition to the $1.2 million toll tax described above, the Company recognized a $1.3 million discrete expense due to the revaluation of our U.S. net deferred tax assets. Offsetting these amounts, because of the shift to a territorial system of taxation in the U.S., the Company recognized a discrete benefit of approximately $1.3 million during the second quarter related to reversing its previously recognized estimated liability associated with estimated future repatriations from Mexico and China. +45 +Compliance with the 2017 Tax Act will require significant complex computations not previously required by U.S. tax law. It is unclear how certain provisions of the 2017 Tax Act will be applied absent further legislative, regulatory, or accounting clarification and guidance. Also, on December 22, 2017, the staff of the SEC issued Staff Accounting Bulletin No. 118 (“SAB No. 118”). SAB No. 118 provides guidance on accounting for the tax effects of the 2017 Tax Act and allows registrants to record provisional amounts for a period of up to one year from the date of enactment of the 2017 Tax Act. We expect to refine and complete the accounting for the 2017 Tax Act during the first half of fiscal year 2019 as we finalize the formal AE&P and tax pools studies and as additional legislative, regulatory, and accounting guidance and interpretations become available. +In future years, because of the toll tax on AE&P described above, repatriations of cash will generally be tax-free in the U.S. However, withholding taxes in China and Mexico may still apply to any such future repatriations. Management has not changed its indefinite investment assertions with regards to the portion of AE&P in each jurisdiction that may be repatriated in the future. Accordingly, management estimates that future repatriations of cash from China may result in approximately $0.8 million of withholding tax. There would be no offsetting foreign tax credits in the U.S. and as such, this potential liability is a direct cost associated with actual repatriations. +A similar analysis was conducted with anticipated future repatriations in Mexico. Under Mexican tax law, any previously taxed earnings from before 2014 (“CUFIN”) are not subject to withholding when monies are repatriated to another country. Based on management’s estimated future repatriations from Mexico and based on the estimated AE&P in Mexico as of December 31, 2013, no withholding tax liability has been recognized as of June 30, 2018. If in the future, estimated future repatriations exceed CUFIN, the Company will be required to recognize a withholding tax as a deferred tax liability at that time. Similar to China, this withholding would not be creditable and would be a direct cost associated with the actual repatriation. +The Company expects to repatriate a portion of its foreign earnings based on increased net sales growth driving additional capital requirements domestically, cash requirements for potential acquisitions and to implement certain tax strategies. The Company currently expects to repatriate approximately $14.3 million of foreign earnings in the future. All other unremitted foreign earnings are expected to remain permanently reinvested for planned fixed assets purchases and improvements in foreign locations. +During the second quarter of fiscal year 2017, the Company signed a unilateral advance pricing agreement (APA) with the Large Taxpayer Division of Mexico’s Servicio de Administración Tributaria (SAT) under an elective framework that has been agreed to by the U.S. and Mexican authorities. The APA is part of a larger program affecting hundreds of U.S. companies with maquiladora operations in Mexico. The general impact of the APA is to increase margins between the maquiladora and U.S. parent company, shifting profits to Mexico from the U.S. The APA was finalized during the fourth quarter of fiscal 2017; the overall impact to the financial statements was not material. +The Company’s effective tax rate differs from the federal tax rate as follows: +Fiscal Year Ended +June 30, 2018 +July 1, 2017 +July 2, 2016 +(in thousands) +Federal income tax provision at statutory rates +$ +(397 +) +$ +2,467 +$ +2,771 +State income taxes, net of federal tax effect +(4 +) +175 +250 +Foreign tax rate differences +103 +(156 +) +(442 +) +Tax rate change +1,634 +— +— +Provisional transition tax on accumulated foreign earnings +1,190 +— +— +Effect of income tax credits +(687 +) +(738 +) +(1,254 +) +Effect of repatriation of foreign earnings, net +(1,484 +) +199 +(161 +) +Provision to return reconciliation +(401 +) +8 +(75 +) +Other +(71 +) +(316 +) +529 +Income tax provision +$ +(117 +) +$ +1,639 +$ +1,618 +46 +The domestic and foreign components of income before income taxes were: +Fiscal Year Ended +June 30, 2018 +July 1, 2017 +July 2, 2016 +(in thousands) +Domestic +$ +(4,593 +) +$ +3,553 +$ +2,228 +Foreign +3,151 +3,703 +5,923 +Income before income taxes +$ +(1,442 +) +$ +7,256 +$ +8,151 +Deferred income tax assets and liabilities consist of the following at: +June 30, 2018 +July 1, 2017 +(in thousands) +Deferred tax assets: +Tax credit carryforwards, net +$ +3,946 +$ +4,164 +Foreign subsidiaries - future tax credits +— +840 +Inventory +667 +840 +Accruals +3,830 +4,020 +Mark-to-market adjustments +247 +1,443 +Arbitration settlement +1,100 +— +Other +33 +28 +Deferred income tax assets +$ +9,823 +$ +11,335 +Deferred tax liabilities: +Foreign subsidiaries – unremitted earnings +(822 +) +(2,288 +) +Fixed assets +(289 +) +(456 +) +Identifiable intangibles +(670 +) +(1,308 +) +Other +(160 +) +(302 +) +Deferred income tax liabilities +$ +(1,941 +) +$ +(4,354 +) +Net deferred income tax assets +$ +7,882 +$ +6,981 +Balance sheet caption reported in: +Long-term deferred income tax asset +$ +7,882 +$ +6,981 +Net deferred income tax asset +$ +7,882 +$ +6,981 +Uncertain Tax Positions +The Company has R&D tax credits that approximate $8.0 million that have 20 year carryforwards before expiring. The Company’s R&D tax credits expire in various fiscal years from 2025 to 2038. The Company also has alternative minimum tax credits, which do not expire, approximating $726,000 , which are now classified as a receivable due to the repeal of the alternative minimum tax. +As of June 30, 2018 , the Company had unrecognized tax benefits of $4.0 million related to its gross R&D tax credits. The unrecognized tax benefits relate to certain R&D tax credits generated from 1997 to 2018. +A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: +Fiscal Year Ended +June 30, 2018 +July 1, 2017 +July 2, 2016 +(in thousands) +Beginning Balance +$ +3,947 +$ +3,760 +$ +3,446 +Additions based on tax positions related to the current year +64 +187 +314 +Ending Balance +$ +4,011 +$ +3,947 +$ +3,760 +The increase from the prior year is due to additional R&D credits that were recorded in 2018 as discussed above. Management does not anticipate any material changes to this amount during the next 12 months. +47 +The Company recognizes interest accrued related to unrecognized tax benefits and penalties in its income tax provision. The Company has not recognized any interest or penalties in the fiscal years presented in these financial statements. The Company is subject to income tax in the U.S. federal jurisdiction, various state jurisdictions, Mexico and China. Certain years remain subject to examination but there are currently no ongoing exams in any taxing jurisdictions. +7. EARNINGS PER SHARE +Basic earnings per share (EPS) is calculated by dividing net income (the numerator) by the weighted-average number of common shares outstanding (the denominator) during the period. Diluted EPS is computed by including both the weighted-average number of shares outstanding and any dilutive common share equivalents in the denominator. The following table presents a reconciliation of the denominator and the number of antidilutive common share awards that were not included in the diluted earnings per share calculation. These antidilutive securities occur when equity awards outstanding have an option price greater than the average market price for the period: +Fiscal Year Ended +(in thousands, except per share information) +June 30, 2018 +July 1, 2017 +July 2, 2016 +Net income (loss) +$ +(1,325 +) +$ +5,617 +$ +6,533 +Weighted average shares outstanding– basic +10,760 +10,756 +10,710 +Effect of dilutive common stock awards +— +161 +568 +Weighted average shares outstanding – diluted +10,760 +10,917 +11,278 +Net income (loss) per share – basic +$ +(0.12 +) +$ +0.52 +$ +0.61 +Net income (loss) per share – diluted +$ +(0.12 +) +$ +0.51 +$ +0.58 +Antidilutive SARs not included in diluted earnings per share +— +892 +442 +8. STOCK OPTION AND BENEFIT PLANS +The Company’s incentive plan provides for equity and liability awards to employees and non-employee directors in the form of stock options, stock appreciation rights (SARs), restricted stock, restricted stock units, stock awards, stock units, performance shares, performance units, and other stock-based or cash-based awards. Compensation cost is recognized on a straight-line basis over the requisite employee service period, which is generally the vesting period, and is recorded as employee compensation expense in cost of goods sold, research, development and engineering, and selling, general and administrative expenses. Share-based compensation is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on historical experience and future expectations. +In addition to service conditions, these SARs contain a performance condition. The additional performance condition is based upon the achievement of Return on Invested Capital (ROIC) goals relative to a peer group. All awards with performance conditions are measured over the vesting period and are charged to compensation expense over the requisite service period based on the number of shares expected to vest. The SARs cliff vest after a three-year period from date of grant and expire five years from date of grant. +On July 28, 2017, the Company granted 272,500 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $7.26 and a grant date fair value of $1.89 , as of June 30, 2018 , 247,500 remain outstanding. The grant date fair value for the awards granted during fiscal year 2018, were estimated using the Black Scholes option valuation method with the following weighted average assumptions as of July 28, 2017: +Fiscal Year 2018 +July 28, 2017 +Expected dividend yield +—% +Risk – free interest rate +1.70% +Expected volatility +29.76% +Expected life +4.00 +48 +On October 28, 2016, the Company granted 10,000 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $8.04 and a grant date fair value of $2.30 , as of June 30, 2018 , 10,000 remain outstanding. The grant date fair value for the awards granted during fiscal year 2017, were estimated using the Black Scholes option valuation method with the following weighted average assumptions as of October 28, 2016: +Fiscal Year 2017 +October 28, 2016 +Expected dividend yield +—% +Risk – free interest rate +1.63% +Expected volatility +33.43% +Expected life +4.00 +On July 26, 2016, the Company granted 242,500 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $8.18 and a grant date fair value of $2.42 , as of June 30, 2018 , 217,500 remain outstanding. The grant date fair value for the awards granted during fiscal year 2017, were estimated using the Black Scholes option valuation method with the following weighted average assumptions as of July 26, 2016: +Fiscal Year 2017 +July 26, 2016 +Expected dividend yield +—% +Risk – free interest rate +0.93% +Expected volatility +36.13% +Expected life +4.00 +On July 29, 2015, the Company granted 248,166 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $10.26 and a grant date fair value of $3.65 , as of June 30, 2018 , 213,333 remain outstanding. The grant date fair value for the awards granted during fiscal year 2016, were estimated using the Black Scholes option valuation method with the following weighted average assumptions as of July 29, 2015: +Fiscal Year 2016 +July 29, 2015 +Expected dividend yield +—% +Risk – free interest rate +1.39% +Expected volatility +43.66% +Expected life +4.00 +Subsequent to June 30, 2018 , the Company granted 161,250 SARs with a strike price of $8.17 and a grant date fair value of $2.27 . +Share-based compensation expense is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on the Company’s historical experience and future expectations. This forfeiture rate will be revised, if necessary, in subsequent periods if actual forfeitures differ from the amount estimated. Share-based compensation expense for fiscal years ended June 30, 2018 , July 1, 2017 and July 2, 2016 was $0.4 million , $0.7 million and $0.8 million , respectively. +The Black-Scholes option valuation model is used by the Company for estimating the fair value of SARs. Option valuation models require the input of highly subjective assumptions, particularly for the expected term and expected stock price volatility. Changes in these assumptions can materially affect the fair value estimates. +There were no SARs exercised during fiscal year 2018. The intrinsic value for SARs exercised in fiscal years 2017 and 2016 was $0.4 million and $0.2 million , respectively. +As of June 30, 2018 , total unrecognized compensation expense related to nonvested share-based compensation arrangements was approximately $0.5 million . This expense is expected to be recognized over a weighted-average period of 1.63 years . +49 +The following table summarizes the Company’s Options and SARs activity for all plans from June 27, 2015 through June 30, 2018 : +SARs +Available +For Grant +SARs +Outstanding +Aggregate +Intrinsic +Value (in +thousands) +Weighted +Average +Exercise +Price +Weighted +Average +Remaining +Contractual +Life (in +years) +Balances, June 27, 2015 +855,836 +813,831 +$ +2,312 +$ +7.99 +2.5 +Shares authorized +— +— +SARs granted +(248,166 +) +248,166 +10.26 +SARs forfeited +26,999 +(26,999 +) +9.48 +SARs exercised +— +(63,333 +) +165 +4.56 +Balances, July 2, 2016 +634,669 +971,665 +$ +339 +$ +8.75 +2.4 +Shares authorized +— +— +SARs granted +(252,500 +) +252,500 +8.17 +SARs forfeited +12,166 +(12,166 +) +8.60 +SARs exercised +— +(127,000 +) +385 +4.77 +Balances, July 1, 2017 +394,335 +1,084,999 +$ +— +$ +9.09 +2.3 +Shares authorized +— +— +SARs granted +(272,500 +) +272,500 +7.26 +SARs forfeited +282,500 +(282,500 +) +7.84 +SARs exercised +— +— +— +— +Balances, June 30, 2018 +404,335 +1,074,999 +$ +79 +$ +8.90 +2.3 +Exercisable at June 30, 2018 +386,666 +$ +— +$ +9.62 +0.7 +Additional information regarding SARs outstanding and exercisable as of June 30, 2018 , is as follows: +Range of +Exercise Prices +Number Outstanding +Weighted Avg. +Remaining +Contractual Life (yrs.) +Weighted Avg. +Exercise Price +Number +Exercisable +Weighted +Avg. Exercise +Price +$4.40 – $7.90 +247,500 +4.1 +$ +7.26 +— +$ +— +7.91 – 9.91 +423,333 +2.3 +8.07 +195,833 +7.94 +9.92 – 11.34 +404,166 +1.1 +10.77 +190,833 +11.34 +$4.40 to $11.34 +1,074,999 +2.3 +$ +8.90 +386,666 +$ +9.62 +The Company has defined contribution plans available to U.S. employees who have attained age 21. Company contributions to the plans were approximately $0.8 million , $0.6 million , and $0.6 million during fiscal years 2018 , 2017 and 2016 , respectively. +50 +9. COMMITMENTS AND CONTINGENCIES +Leases : As of June 30, 2018 , July 1, 2017 and July 2, 2016 , the Company did not have any property and equipment financed under capital leases. As of June 30, 2018 , the Company has operating leases for certain equipment and production facilities, which expire at various dates during the next ten years . +Future minimum payments under non-cancelable operating leases at June 30, 2018 , are summarized as follows (in thousands): +Fiscal Years Ending +Operating Leases +2019 +$ +6,387 +2020 +3,128 +2021 +2,119 +2022 +1,385 +2023 +1,308 +Thereafter +4,173 +Total minimum lease payments +$ +18,500 +Rental expense under operating leases was approximately $7.1 million , $7.8 million , and $6.6 million during fiscal years 2018 , 2017 and 2016 , respectively. +Warranty Costs : The Company provides warranties on certain product sales, and allowances for estimated warranty costs are recorded during the period of sale. The determination of such allowances requires the Company to make estimates of product return rates and expected costs to repair or to replace the products under warranty. The Company establishes warranty reserves based on historical warranty costs for each product line combined with liability estimates based on the prior twelve months’ sales activities. As of June 30, 2018 and July 1, 2017 , the reserve for warranty costs was approximately $20,000 and $32,000 , respectively. +If actual return rates and/or repair and replacement costs differ significantly from estimates, adjustments to recognize additional cost of sales may be required in future periods. Warranty expense for fiscal years 2018 , 2017 and 2016 was related to workmanship claims on keyboards and certain EMS products. +Litigation : During the second quarter of fiscal year 2017, the Company commenced the arbitration process with a former customer related to approximately $9.3 million in inventory purchased and approximately $1.9 million in outstanding receivables that we believed should be reimbursed by this former customer based on the terms of the manufacturing agreement. On September 5, 2018, the Company was awarded $6.7 million following the conclusion of the arbitration proceeding. This event, including all related disposal fees, resulted in an approximately $4.5 million before tax one-time loss to fiscal year 2018. The adverse impact net of taxes on net loss was $3.4 million . The effects of the arbitration proceeding has been included in our consolidated financial position, results of operations or cash flows. +Indemnification Rights : Under the Company’s bylaws, the Company’s directors and officers have certain rights to indemnification by the Company against certain liabilities that may arise by reason of their status or service as directors or officers. The Company maintains director and officer insurance, which may cover certain liabilities arising from its obligation to indemnify its directors and officers and former directors in certain circumstances. +51 +10. FAIR VALUE MEASUREMENTS +The Company has adopted ASC 820, Fair Value Measurements, which defines fair value, establishes a framework for assets and liabilities being measured and reported at fair value and expands disclosures about fair value measurements. There are three levels of fair value hierarchy inputs used to value assets and liabilities which include: Level 1 – inputs are quoted market prices for identical assets or liabilities; Level 2 – inputs other than quoted market prices included in Level 1 that are observable for the asset or liability, either directly or indirectly; and Level 3 – inputs are unobservable inputs for the asset or liability. There have been no changes in the fair value methodologies used at June 30, 2018 and July 1, 2017 . +The following table summarizes the fair value of assets (liabilities) of the Company’s derivatives that are required to be measured on a recurring basis as of June 30, 2018 and July 1, 2017 (in thousands): +June 30, 2018 +Level 1 +Level 2 +Level 3 +Total +Fair Value +Financial Assets: +Interest rate swaps +$ +— +$ +24 +$ +— +$ +24 +Foreign currency forward contracts & swaps +$ +— +$ +500 +$ +— +$ +500 +Financial Liabilities: +Foreign currency forward contracts & swaps +$ +— +$ +(1,676 +) +$ +— +$ +(1,676 +) +July 1, 2017 +Level 1 +Level 2 +Level 3 +Total +Fair Value +Financial Assets: +Foreign currency forward contracts & swaps +— +1,010 +— +$ +1,010 +Financial Liabilities: +Interest rate swaps +$ +— +$ +(103 +) +$ +— +$ +(103 +) +Foreign currency forward contracts & swaps +$ +— +$ +(5,112 +) +$ +— +$ +(5,112 +) +The Company currently has forward contracts and swaps to hedge known future cash outflows for expenses denominated in the Mexican peso and an interest rate swap to mitigate risk associated with certain borrowings under the Company’s debt arrangement. These contracts are measured on a recurring basis based on the foreign currency spot rates and forward rates quoted by banks or foreign currency dealers. These contracts are marked to market using level 2 input criteria every period with the unrealized gain or loss, net of tax, reported as a component of shareholders’ equity in accumulated other comprehensive income (loss), as they qualify for hedge accounting. +The carrying values of cash and cash equivalents, accounts receivable and current liabilities reflected on the balance sheets at June 30, 2018 and July 1, 2017 , reasonably approximate their fair value. +The Company’s long-term debt, which is measured at amortized cost, primarily consists of a revolving line of credit, a term loan and an equipment term loan. These borrowings bear interest at either a “Base Rate” or a “Fixed Rate,” as elected by the Company. Each of these rates is a variable floating rate dependent upon current market conditions and the Company’s current credit risk as discussed in footnote 4. +As a result of the determinable market rate for our revolving line of credit, term loan and equipment term, they are classified within Level 2 of the fair value hierarchy. Further, the carrying value of each of these instruments reasonably approximates their fair value as of June 30, 2018 and July 1, 2017 . +52 +11. DERIVATIVE FINANCIAL INSTRUMENTS +As of June 30, 2018 , the Company had outstanding foreign currency forward contracts and swaps with a total notional amount of $46.3 million . The maturity dates for these contracts and swaps extend through March 2020 . As of June 30, 2018 , the net amount of unrealized loss expected to be reclassified into earnings within the next 12 months is approximately $1.2 million . During the fiscal year ended June 30, 2018 , the Company entered into $13.7 million of foreign currency forward contracts and settled $28.1 million of such contracts. During the fiscal year ended July 1, 2017 , the Company entered into $6.7 million of foreign currency forward contracts and settled $20.5 million of such contracts. During the fiscal year ended July 2, 2016 , the Company entered into $25.9 million of foreign currency forward contracts and settled $21.5 million of such contracts. +As of June 30, 2018 , the aggregate notional amount of the Company’s outstanding foreign currency contracts and swaps along with their unrealized gains (losses) are expected to mature as summarized below (in thousands): +Quarter Ending +Notional Contracts and Swaps in MXN +Notional Contracts and Swaps in USD +Estimated Fair Value +September 29, 2018 +$ +90,443 +$ +5,301 +$ +(779 +) +December 29, 2018 +$ +125,328 +$ +6,746 +$ +(566 +) +March 30, 2019 +$ +137,944 +$ +6,979 +$ +(273 +) +June 29, 2019 +$ +142,947 +$ +6,828 +$ +23 +September 28, 2019 +$ +148,468 +$ +6,740 +$ +275 +December 28, 2019 +$ +152,613 +$ +7,187 +$ +(58 +) +March 28, 2020 +$ +146,613 +$ +6,553 +$ +203 +On October 1, 2014, the Company entered into an interest rate swap contract with an effective date of September 1, 2015 and a termination date of September 3, 2019, with a notional amount of $25.0 million related to the borrowings outstanding under the term loan. The interest rate swap pays the Company variable interest at the one month LIBOR rate, and the Company pays the counter party a fixed interest rate. The fixed interest rate for the contract is 1.97% that replaces the one month LIBOR rate component of our contractual interest to be paid to WFB as part of our term loan. Based on the terms of the interest rate swap contract and the underlying borrowings outstanding under the term loan, the interest rate contract was determined to be effective, and thus qualifies as a cash flow hedge. As of June 30, 2018 and July 1, 2017 , the remaining notional balance of this swap was $8.5 million and $14.5 million , respectively. +The following table summarizes the fair value of derivative instruments in the Consolidated Balance Sheets as of June 30, 2018 and July 1, 2017 (in thousands): +June 30, 2018 +July 1, 2017 +Derivatives Designated as Hedging Instruments +Balance Sheet Location +Fair Value +Fair Value +Foreign currency forward contracts & swaps +Other current assets +$ +23 +$ +— +Foreign currency forward contracts & swaps +Other long-term assets +$ +477 +$ +1,010 +Foreign currency forward contracts & swaps +Other current liabilities +$ +(1,618 +) +$ +(4,226 +) +Foreign currency forward contracts & swaps +Other long-term liabilities +$ +(58 +) +$ +(886 +) +Interest rate swaps +Other current assets +$ +20 +$ +— +Interest rate swaps +Other long-term assets +$ +4 +$ +— +Interest rate swaps +Other current liabilities +$ +— +$ +(81 +) +Interest rate swaps +Other long-term liabilities +$ +— +$ +(22 +) +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2018 (in thousands): +Derivatives Designated as Hedging Instruments +Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) +AOCI Balance +as of +July 1, 2017 +Effective +Portion +Recorded In +AOCI +Tax Rate Effect +Reclassification +Effective Portion +Reclassified From +AOCI Into Income +AOCI Balance +as of +June 30, 2018 +Forward contracts & swaps +Cost of sales +$ +(2,707 +) +$ +(1,942 +) +$ +(583 +) +$ +4,244 +$ +(988 +) +Interest rate swap +Interest expense +(68 +) +20 +(3 +) +70 +19 +Total +$ +(2,775 +) +$ +(1,922 +) +$ +(586 +) +$ +4,314 +$ +(969 +) +53 +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2017 (in thousands): +Derivatives Designated as Hedging Instruments +Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) +AOCI Balance +as of +July 2, 2016 +Effective +Portion +Recorded In +AOCI +Effective Portion +Reclassified From +AOCI Into Income +AOCI Balance +as of +July 1, 2017 +Forward contracts & swaps +Cost of sales +$ +(7,245 +) +$ +(600 +) +$ +5,138 +$ +(2,707 +) +Interest rate swap +Interest expense +(328 +) +14 +246 +(68 +) +Total +$ +(7,573 +) +$ +(586 +) +$ +5,384 +$ +(2,775 +) +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2016 (in thousands): +Derivatives Designated as Hedging Instruments +Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) +AOCI Balance +as of +June 27, 2015 +Effective +Portion +Recorded In +AOCI +Effective Portion +Reclassified From +AOCI Into Income +AOCI Balance +as of +July 2, 2016 +Forward contracts +Cost of sales +$ +(4,487 +) +$ +(6,939 +) +$ +4,181 +$ +(7,245 +) +Interest rate swap +Interest expense +(276 +) +(348 +) +296 +(328 +) +Total +$ +(4,763 +) +$ +(7,287 +) +$ +4,477 +$ +(7,573 +) +As of June 30, 2018 , the Company does not have any foreign exchange contracts with credit-risk-related contingent features. The Company is subject to the risk of fluctuating interest rates from our line of credit and foreign currency risk resulting from our China operations. The Company does not currently manage these risk exposures by using derivative instruments. +12. ENTERPRISE-WIDE DISCLOSURES +Operating segments are defined in ASC Topic 280, Segment Reporting as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker, or decision making group, in deciding how to allocate resources and in assessing performance. The Company’s chief operating decision maker is its Chief Executive Officer. As of June 30, 2018 , the Company operates and internally manages a single operating segment, Electronics Manufacturing Services as this is the only discrete financial information that is regularly reviewed by the chief operating decision maker. This segment provides integrated electronic and mechanical engineering, assembly, sourcing and procurement, logistics, and new product testing for our customers. +Products and Services +Of the revenues for the years ended June 30, 2018 , July 1, 2017 , and July 2, 2016 , EMS sales and services were $445.8 million , $466.6 million and $483.3 million , respectively. Keyboard sales for the years ended June 30, 2018 , July 1, 2017 , and July 2, 2016 were $0.5 million , $1.2 million and $1.7 million , respectively. +Geographic Areas +Net sales and long-lived assets (property, plant, and equipment) by geographic area for the years ended and as of June 30, 2018 , July 1, 2017 and July 2, 2016 are summarized in the following table. Net sales set forth below are based on the shipping destination. Long-lived assets information is based on the physical location of the asset. +Fiscal Year Ended +(in thousands) +2018 +2017 +2016 +Geographic net sales: +Domestic (U.S.) +$ +329,230 +$ +361,886 +$ +347,552 +Foreign +117,092 +105,911 +137,413 +Total +$ +446,322 +$ +467,797 +$ +484,965 +Long-lived assets: +United States +$ +7,454 +$ +8,988 +$ +11,406 +Mexico +19,395 +20,878 +15,756 +China +699 +630 +763 +Total +$ +27,548 +$ +30,496 +$ +27,925 +54 +Percentage of net sales made to customers located in the following countries: +Fiscal Year Ended +2018 +2017 +2016 +United States +74% +77% +72% +China +24 +19 +15 +Canada +— +1 +7 +Other foreign countries (a) +2 +3 +6 +Total +100% +100% +100% +(a) No other individual foreign country accounted for 10% or more of the foreign sales in fiscal years 2018, 2017 or 2016. +Significant Customers +The percentage of net sales to and trade accounts receivables from significant customers were as follows: +Percentage of Net +Sales Fiscal Year +Percentage of +Trade Accounts Receivable +Fiscal Year +2018 +2017 +2016 +2018 +2017 +Customer A +19% +18% +18% +17% +30% +Customer B +* +* +* +12% +10% +Customer C +* +* +* +10% +* +* Current customer amount represents less than 10%. +55 +13. QUARTERLY FINANCIAL DATA (Unaudited) +Fiscal Year Ended June 30, 2018 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +(in thousands, except per share amounts) +Net sales +$ +109,217 +$ +111,725 +$ +108,352 +$ +117,028 +Gross profit +7,845 +8,800 +8,155 +9,369 +Income before income taxes +570 +1,035 +123 +(3,170 +) +Net income (loss) +432 +(224 +) +644 +(2,177 +) +Net income (loss) per share - basic +$ +0.04 +$ +(0.02 +) +$ +0.06 +$ +(0.20 +) +Net income (loss) per share - diluted +$ +0.04 +$ +(0.02 +) +$ +0.06 +$ +(0.20 +) +Weighted average shares outstanding +Basic +10,760 +10,760 +10,760 +10,760 +Diluted +10,760 +10,760 +10,760 +10,760 +Fiscal Year Ended July 1, 2017 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +(in thousands, except per share amounts) +Net sales +$ +117,135 +$ +118,517 +$ +113,601 +$ +118,544 +Gross profit +9,709 +9,612 +9,139 +9,840 +Income before income taxes +2,201 +1,995 +1,283 +1,777 +Net income +1,792 +1,528 +961 +1,336 +Net income per share - basic +$ +0.17 +$ +0.14 +$ +0.09 +$ +0.12 +Net income per share - diluted +$ +0.16 +$ +0.14 +$ +0.09 +$ +0.12 +Weighted average shares outstanding +Basic +10,748 +10,758 +10,759 +10,760 +Diluted +10,922 +10,968 +10,957 +10,856 +56 +14. GOODWILL AND OTHER INTANGIBLE ASSETS +The Company recorded goodwill in connection with the Ayrshire and Sabre acquisitions resulting primarily from the synergies that resulted from the Company's acquisitions and the assembled workforce. The goodwill is not amortized for financial accounting purposes. The goodwill from the acquisitions is not deductible for tax purposes. As of June 30, 2018 and July 1, 2017 , goodwill was recorded at $10.0 million . +The components of acquired intangible assets are as follows (in thousands): +June 30, 2018 +Amortization Period +in Years +Gross Carrying +Amount +Accumulated +Amortization +Net Carrying +Amount +Other intangible assets: +Non-Compete Agreements +3 - 5 +$ +568 +$ +(568 +) +$ +— +Customer Relationships +10 +4,803 +(2,071 +) +2,732 +Favorable Lease Agreements +4 - 7 +2,941 +(1,947 +) +994 +Total +$ +8,312 +$ +(4,586 +) +$ +3,726 +July 1, 2017 +Amortization Period +in Years +Gross Carrying +Amount +Accumulated +Amortization +Net Carrying +Amount +Other intangible assets: +Non-Compete Agreements +3 - 5 +$ +568 +$ +(483 +) +$ +85 +Customer Relationships +10 +4,803 +(1,590 +) +3,213 +Favorable Lease Agreements +4 - 7 +2,941 +(1,439 +) +1,502 +Total +$ +8,312 +$ +(3,512 +) +$ +4,800 +Amortization expense related to intangible assets was approximately $1.1 million for the years ended June 30, 2018 and July 1, 2017 , respectively. +Aggregate amortization expense related to existing intangible assets by fiscal year is currently estimated to be as follows (in thousands): +Fiscal Years Ending +Amount +2019 +$ +818 +2020 +783 +2021 +784 +2022 +531 +2023 +480 +Thereafter +330 +Total amortization expense +$ +3,726 +15. SUBSEQUENT EVENT +On September 5, 2018, the Company was awarded $6.7 million following the conclusion of a previously disclosed arbitration proceeding, which the Company commenced in the second fiscal quarter of fiscal year 2017. This award resolved a dispute with a former customer involving approximately $9.3 million in inventory purchased and approximately $1.9 million in outstanding accounts receivables and other related fees and costs that the Company believed to be reimbursable. This event, including all related disposal fees, resulted in an approximately $4.5 million before tax one-time loss to fiscal year 2018. The adverse impact net of taxes on net loss was $3.4 million . +Item 9: +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES +None +57 +Item 9A: +CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +It is the responsibility of our management to establish, maintain, and monitor disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 are recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Additionally, these disclosure controls include controls and procedures that are designed to accumulate and communicate the information required to be disclosed to our Company’s Chief Executive Officer and Chief Financial Officer, allowing for timely decisions regarding required disclosures. As of the end of the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(f). Based on our assessment, we believe that as of June 30, 2018 , the Company’s disclosure controls and procedures are effective based on that criteria. +Management’s Report on Internal Control over Financial Reporting +Our management has the responsibility to establish and maintain adequate internal controls over our financial reporting, as defined in Rule 13a-15(f) under the Securities and Exchange Act of 1934. Our internal controls are designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our external financial statements in accordance with generally accepted accounting principles (GAAP). +Due to inherent limitations of any internal control system, management acknowledges that there are limitations as to the effectiveness of internal controls over financial reporting and therefore recognize that only reasonable assurance can be gained from any internal control system. Accordingly, our internal control system may not detect or prevent material misstatements in our financial statements and projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, we have performed an assessment of the effectiveness of our internal controls over financial reporting as of June 30, 2018 . This assessment was based on the criteria established in Internal Control-Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that as of June 30, 2018 , the Company’s internal control over financial reporting is effective based on that criteria. +The effectiveness of the Company's internal control over financial reporting as of June 30, 2018 has been audited by BDO USA LLP, an independent registered public accounting firm, as stated in their report which is included herein. +Changes in Internal Control over Financial Reporting +There have been no significant changes in our internal controls over financial reporting during our fourth fiscal quarter ended June 30, 2018 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)). +58 +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Key Tronic Corporation +Spokane Valley, Washington +We have audited Key Tronic Corporation’s (the “Company’s”) internal control over financial reporting as of June 30, 2018 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of June 30, 2018, based on the COSO criteria . +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company and subsidiaries as of June 30, 2018 and July 1, 2017, the related consolidated statements of income (loss), comprehensive income, shareholders’ equity, and cash flows for each of the three years in the period ended June 30, 2018, and the related notes and schedule and our report dated September 10, 2018 expressed an unqualified opinion thereon. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying “Item 9A, Management’s Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit of internal control over financial reporting in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ BDO USA, LLP +Spokane, Washington +September 10, 2018 +59 +Item 9B: +OTHER INFORMATION +None +PART III +Item 10: +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Directors of the Registrant +Information on the nominees for election as Directors of the Company is incorporated by reference from the Company’s definitive proxy statement for the 2018 Annual Meeting of Shareholders to be filed pursuant to Regulation 14A under the Exchange Act no later than 120 days after the end of the Company’s 2018 fiscal year. +Executive Officers of the Registrant +This information is included in a separate item captioned “Executive Officers of the Registrant” in Item 1 of Part 1 of this report pursuant to Instruction G(3) of Form 10-K and Instruction 3 to Item 401(b) of Regulation S-K. +Compliance with Section 16(a) of the Exchange Act: +Incorporated by reference to Key Tronic Corporation’s 2018 Proxy Statement to Shareholders. +Code of Conduct +The Board of Directors has adopted a written Code of Conduct which applies to its directors and employees, including its executive officers. The Code of Conduct is available on the Company’s website at www.keytronic.com . The Company intends to disclose on its website any amendments to or waivers of the Code of Conduct. +Item 11: +EXECUTIVE COMPENSATION +Information appearing under the caption “Executive Compensation” in the Company’s 2018 Proxy Statement is incorporated herein by this reference. +Item 12: +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The following table sets forth the aggregate information for the Company’s equity compensation plans in effect as of June 30, 2018 . +EQUITY COMPENSATION PLAN INFORMATION +Plan category +Number of securities to +be issued upon exercise +of outstanding options, +warrants, and rights +(a) +Weighted-average +exercise price of +outstanding options, +warrants, and rights +(b) +Number of securities +remaining available for +future issuance under +equity compensation +plans (excluding +securities reflected in +column (a) +(c) +Equity compensation plans approved by security holders (1) +1,074,999 +$ +8.90 +404,335 +Equity compensation plans not approved by security holders +— +$ +— +— +Total +1,074,999 +$ +8.90 +404,335 +(1) +Included are the 1,200,000 shares subject to the 2010 Plan, the issuance of which were approved by the shareholders at the 2010 Annual Meeting. During the 2015 Annual Meeting, an additional 1,000,000 shares were approved. As a result of the shareholder approval, the Company made the decision to amend the cash-settled SARs granted during fiscal year 2010 to stock-settled SARs effective October 21, 2011. +Information under the caption “Beneficial Ownership of Securities” in the Company’s 2018 Proxy Statement is incorporated herein by this reference. +60 +Item 13: +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions”, “Compensation Committee Interlocks and Insider Participation”, and “Directors’ Independence” in the Company’s 2018 Proxy Statement is incorporated herein by this reference. +Item 14: +PRINCIPAL ACCOUNTING FEES AND SERVICES +Information appearing under the caption “Principal Accountant Fees and Services” in the Company’s 2018 Proxy Statement is incorporated herein by this reference. +PART IV +Item 15: +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +(a) 1. FINANCIAL STATEMENTS +Page in Form 10-K +FINANCIAL STATEMENTS +Report of Independent Registered Public Accounting Firm +32 +Consolidated Balance Sheets +33 +Consolidated Statements of Income (Loss) +34 +Consolidated Statements of Comprehensive Income +35 +Consolidated Statements of Cash Flows +36 +Consolidated Statements of Shareholders’ Equity +37 +Notes to Consolidated Financial Statements +38-57 +2. SCHEDULES +II. Consolidated Valuation and Qualifying Accounts +66 +Other schedules are omitted because of the absence of conditions under which they are required, or because required information is given in the financial statements or notes thereto. +61 +3. EXHIBITS +Exhibit No. +Description +3.1 +Articles of Incorporation, incorporated by reference to the Exhibit 3.1 to the Company’s form 10-K filed with the SEC for the year ended July 1, 1995 (File No. 2-83898) +3.2 +Bylaws, as amended, incorporated by reference to the Exhibit 3 (iii) to the Company’s Form 10-K for the year ended July 1, 1995 (File No. 2-83898) +10.1* +Amended and Restated 1990 Stock Option Plan for Non-Employee Directors, as amended, incorporated by reference to the Company’s 1997 Proxy Statement dated October 10, 1997 (Proposal 2) +10.2* +1995 Executive Stock Option Plan, incorporated by reference to the Company’s 1995 Proxy Statement, pages 19-22 (Proposal 3) +10.3* +2000 Employee Stock Option Plan, incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.4* +Officers’ Employment Contracts, incorporated by reference to the Company’s 1998 Proxy Statement, pages 10 and 11 +10.5* +Addenda to Officers’ Employment Contracts, incorporated by reference to Exhibits to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.6* +Description of Retention Bonus Plan, incorporated by reference to the Exhibits to the Company’s 10-Q for the quarter ended December 28, 2002 +10.7* +Addenda to Officers’ Employment Contracts, incorporated by reference to Exhibits to the Company’s Form 10-K for the year ended June 29, 2002 +10.8 +Promise to execute a Purchase and Sale Agreement with Key Safety Systems de Mexico, S.A. de C.V., incorporated by reference to the Exhibit to the Company’s Form 8-K filed April 26, 2005 +10.9 +Summary of material terms and conditions of the Purchase and Sale Agreement with Key Safety Systems de Mexico, S.A. de C.V., incorporated by reference to the Exhibit to the Company’s Form 8-K filed June 6, 2005 +10.10* +Summary of Key Tronic Corporation Long Term Incentive Compensation Plan, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed September 27, 2005 +62 +10.11* +Summary of Key Tronic Corporation Incentive Compensation Plan, incorporated by reference to Exhibit 10.23 to the Company’s Form 10-K for the year ended July 2, 2005 +10.12* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2007 and Fiscal Years 2007 – 2009 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 28, 2006 +10.13 +Summary of material terms and conditions of the Purchase and Sale Agreement with Todenko Mexico S.A. de C.V., incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed October 12, 2006 +10.14 +Summary of material terms and conditions of the Purchase and Sale Agreement with Todenko Mexico S.A. de C.V., incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed November 20, 2006 +10.15 +Summary of material terms and conditions of the Sale and Purchase Agreement with Adevco Corporation, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed January 5, 2007 +10.16 +Summary of Second Amendment to Agreement of Sale and Purchase Agreement with Adevco Corporation, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed April 11, 2007 +10.17* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2008 and Fiscal Years 2008-2010 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 27, 2007 +10.18* +Summary of Incentive Compensation Plan Performance Goals and Target payments for Fiscal Year 2009 and Fiscal Years 2009 – 2011 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 24, 2008 +10.19* +Summary of Incentive Compensation Plan Performance Goals and Target payments for Fiscal Year 2010 and Fiscal Years 2010 – 2012 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 23, 2009 +10.20 +Financing Agreement with Wells Fargo Bank, N.A., incorporated by reference to the Exhibits to the Company’s Form 8-K filed on August 24, 2009 +10.21* +2010 Incentive Plan, incorporated by reference to Exhibit 10.36 to the Company’s Form 10-K for the year ended July 3, 2010 +10.22* +Employment Contract with Douglas G. Burkhardt, incorporated by reference to Exhibit 10.37 to the Company’s Form 10-K for the year ended July 3, 2010 +10.23 +Summary of material terms and conditions of the Purchase and Sale Agreement with Autopartes Y Arneses de Mexico S.A. de C.V., incorporated by reference to Exhibit 10.38 to the Company’s Form 10-K for the year ended July 3, 2010 +10.24* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2011 and Fiscal Years 2011 – 2013 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 23, 2010 +10.25* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2012 and Fiscal Years 2012 – 2014 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 2, 2011 +63 +10.26* +Amendment to Employment Contract of Craig D. Gates, dated August 23, 2011; of Ronald F. Klawitter, dated August 23, 2011 and of Douglas G. Burkhardt dated September 6, 2011; incorporated by reference to the Exhibits to the Company’s Form 10-K for the year ended July 2, 2011 filed on September 12, 2011 +10.27 +Second Loan Modification Agreement to the Credit Agreement with Wells Fargo Bank, N.A., incorporated by reference to the Exhibits to the Company’s Form 8-K filed on February 2, 2012 +10.28* +Amendment to Employment Contract of Craig D. Gates, dated May 10, 2012, incorporated by reference to the Exhibits to the Company’s Form 10-Q filed on May 14, 2012 +10.29* +Amendment to Employment Contract of Douglas G. Burkhardt dated May 10, 2012; incorporated by reference to the Exhibits to the Company’s Form 10-Q filed on May 14, 2012 +10.30* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2013 and Fiscal Years 2013 – 2015 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 7, 2012 +10.31* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2014 and Fiscal Years 2014 – 2016 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 6, 2013 +10.32* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2015 and Fiscal Years 2015 – 2017 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 1, 2014 +10.33 +Summary of material terms and conditions of the Stock Purchase Agreement with CDR Manufacturing and Amended and Restated Credit Agreement with Wells Fargo Bank, N. A. incorporated by reference to the Company’s Form 8-K filed September 9, 2014 +10.34* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2016 and Fiscal Years 2016 – 2018 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 30, 2015 +10.35 +First Amendment to Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, incorporated by reference to the Company's Form 8-K filed August 11, 2015 +10.36 +Second Replacement Revolving Line of Credit Note with Wells Fargo Bank, National Association, incorporated by reference to the Company's Form 8-K filed August 11, 2015 +10.37* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2017 and Fiscal Years 2017 – 2019 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 29, 2016 +10.38* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2018 and Fiscal Years 2018 – 2020 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 22, 2017 +10.39 +Announcement of contract awarded with SkyBell Technologies, a global leader in patented Wi-Fi video doorbell technology incorporated by reference to the Company’s Form 8-K filed May 1, 2018 +10.40* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2019 and Fiscal Years 2019 – 2021 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 2, 2018 +64 +10.41 +Announcement of award of $6.7 million following the conclusion of a previously disclosed arbitration proceeding incorporated by reference to the Company's Form 8-K filed September 5, 2018 +21 +Subsidiaries of Registrant, submitted herewith +23.1 +Consent of Independent Registered Public Accounting Firm, submitted herewith +31.1 +Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer, submitted herewith +31.2 +Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer, submitted herewith +32.1 +Section 1350 Certification of Chief Executive Officer, submitted herewith +32.2 +Section 1350 Certification of Chief Financial Officer, submitted herewith +101.INS +XBRL Instance Document ** +101.SCH +XBRL Taxonomy Extension Schema Document ** +101.CAL +XBRL Taxonomy Extension Calculation Linkbase Document ** +101.DEF +XBRL Taxonomy Extension Definition Linkbase Document ** +101.LAB +XBRL Taxonomy Extension Label Linkbase Document ** +101.PRE +XBRL Taxonomy Extension Presentation Linkbase Document ** +* +Management contract or compensatory plan or arrangement +** +Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities and Exchange Act of 1934, as amended and otherwise are not subject to liability under those sections. +65 +SCHEDULE II +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS +FISCAL YEARS ENDED JUNE 30, 2018 , JULY 1, 2017 , AND JULY 2, 2016 +Fiscal Year Ended +2018 +2017 +2016 +(in thousands) +Allowance for Obsolete Inventory +Balance at beginning of year +$ +1,306 +$ +1,113 +$ +417 +Provisions +31 +496 +757 +Dispositions +121 +(303 +) +(61 +) +Balance at end of year +$ +1,458 +$ +1,306 +$ +1,113 +Allowance for Doubtful Accounts +Balance at beginning of year +$ +84 +$ +135 +$ +97 +Provisions (Recovery) +(84 +) +(10 +) +38 +Write-offs +— +(41 +) +— +Balance at end of year +$ +— +$ +84 +$ +135 +66 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +Dated: September 10, 2018 +KEY TRONIC CORPORATION +By: +/s/ Craig D. Gates +Craig D. Gates, President and Chief Executive Officer +(Principal Executive Officer) +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated: +/s/ Craig D. Gates +September 10, 2018 +Craig D. Gates +Date +Director and President and Chief Executive Officer +(Principal Executive Officer) +/s/ Brett R. Larsen +September 10, 2018 +Brett R. Larsen +Date +Executive Vice President of Administration, Chief Financial Officer and Treasurer +(Principal Financial Officer) +/s/ Ronald F. Klawitter +September 10, 2018 +Ronald F. Klawitter, Director +Date +/s/ James R. Bean +September 10, 2018 +James R. Bean, Director +Date +/s/ Yacov A. Shamash +September 10, 2018 +Yacov A. Shamash, Director +Date +/s/ Patrick Sweeney +September 10, 2018 +Patrick Sweeney, Director and Chairman of the Board +Date +67 \ No newline at end of file diff --git a/raw/filings/0000719733/2018/0000719733-18-000054/filing_metadata.csv b/raw/filings/0000719733/2018/0000719733-18-000054/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..41db48b3efa4b9ad73c7f058488bc6af3f4b0256 --- /dev/null +++ b/raw/filings/0000719733/2018/0000719733-18-000054/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000719733,KTCC,KEY TRONIC CORP,10-K,2018-09-10,2018-06-30,2018-09-10T20:50:21.000Z,0000719733-18-000054,ktcc-06302018x10k.htm,10-K,8301552,1,0,https://www.sec.gov/Archives/edgar/data/719733/000071973318000054/ktcc-06302018x10k.htm,https://www.sec.gov/Archives/edgar/data/719733/000071973318000054/,2018,2018,1 diff --git a/raw/filings/0000719733/2018/0000719733-18-000054/item1.txt b/raw/filings/0000719733/2018/0000719733-18-000054/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..373161208fd62768d039c4e9591c7ef2c2aa9452 --- /dev/null +++ b/raw/filings/0000719733/2018/0000719733-18-000054/item1.txt @@ -0,0 +1,97 @@ +Item 1. +BUSINESS +Background +Key Tronic Corporation (dba: KeyTronicEMS Co.) was organized in 1969, as a Washington corporation that locally manufactured computer keyboards. The ability to design, build and deliver a quality product led us to become a leading independent manufacturer of keyboards for computers in the United States. Our fully integrated design, tooling, and automated manufacturing capabilities enabled us to rapidly respond to customers’ needs for keyboards in production quantities worldwide. We supported our sales growth through the development and purchase of international manufacturing facilities. As the computer keyboard market matured with increasing competition from other international providers, we determined that our business could no longer solely rely on keyboard sales. +After assessing market conditions and our strengths and capabilities, we shifted our focus from keyboard manufacturing to contract manufacturing for a wide range of products. Our unique strategic attributes are based on our core strengths of innovative design and engineering expertise in electronics, mechanical engineering, sheet metal fabrication and stamping, and precision plastics combined with high-quality, low cost production, and assembly on an international basis while providing exceptional customer service. These strengths have made our company a strong competitor in the electronic manufacturing services (EMS) market. +Our Industry and Strategy +The expansion of the EMS industry and our acquisitions have allowed us to continue to expand our customer base and the industries that we serve. The increase in new programs represents a growing portion of our revenue and a promising foundation for our future. In keeping with our long-term strategic objectives, we have been successfully building a more diversified customer portfolio, spanning a wider range of industries. We currently offer our customers the following services: integrated electronic and mechanical engineering, precision plastic molding, sheet metal fabrication, printed circuit board (PCB) and complete product assembly, component selection, sourcing and procurement, worldwide logistics, and new product testing and production all at competitive pricing due to our global footprint. We differentiate ourselves from others our size and larger in the EMS industry by providing vertical integration, a flexible and responsive approach to our customer’s changing supply demand, and complete design engineering support. +We believe that we are well positioned in the EMS industry to continue the expansion of our customer base and achieve long-term growth. Our unique blend of multinational facilities, vertical integration, centralized management, and core strengths continue to support our growth and our customers’ needs. We continue to focus on controlling operating expenses and leveraging the synergistic capabilities of our world-class facilities in the United States, Mexico, and China. This international production capability provides our customers with the benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs, and reduced product fulfillment time. Given our competitive advantages and the growing pressure for new potential customers to move forward with their outsourcing strategies, we are strongly positioned to win new business in coming periods and grow our revenue and profits. +4 +The EMS industry is intensely competitive. Although our customer base is growing, we still have less than 1% of the potential global market and our revenue can fluctuate significantly due to reliance on a concentrated base of customers. We are planning for new customer growth in the coming quarters by securing new programs with new and existing customers, increasing our worldwide manufacturing capacity, leveraging further our design engineering capabilities and continuing to improve our manufacturing and procurement processes and capabilities. Ongoing challenges that we face include but are not limited to the following: continuing to win programs from new and existing customers, balancing capital employed, production capacity and key personnel in support of new customer programs, improving operating efficiencies, controlling costs while developing competitive pricing strategies, and successfully transitioning new program wins to full production. +Customers and Marketing +We provide a mix of manufacturing services for outsourced Original Equipment Manufacturing (OEM) products. We provide the following EMS services: product design, surface mount technologies (SMT) and pin through hole capability for printed circuit board assembly, tool making, precision plastic molding, sheet metal fabrication and painting, liquid injection molding, complex assembly, automated tape winding, prototype design and full product assembly. +Sales of the majority of our products have not historically been seasonal in nature, but may be seasonal in the future if there are changes in the types of products manufactured. Sales can, however, fluctuate significantly between quarters from changes in customers and customer demand due to the concentration of sales generated by our largest customers. +For the fiscal years 2018 , 2017 and 2016 , the five largest customers in each year accounted for 42%, 42% and 41% of combined total net sales, respectively. We continue to diversify our customer base by adding additional programs and customers. We expect net sales to our five largest customers as a percentage of total net sales to approximate current levels going forward. +The following table represents all customers that represented 10% or more of total net sales during the last three fiscal years: +Percentage of Net Sales by Fiscal Year +2018 +2017 +2016 +Customer A +19% +18% +18% +There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with it’s customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +We market our products and services primarily through our direct sales department which is comprised of strategically located field sales people and distributors. We also maintain relationships with several independent sales organizations to assist in marketing our EMS product lines. +Manufacturing +We have continually made investments in developing and expanding a capital equipment base to achieve vertical integration and efficiencies in our manufacturing processes. We have invested significant capital into SMT for volume manufacturing of complex printed circuit board assemblies and in our metal shop providing precision metal stamping, fabricating, and finishing. We also design and develop tooling for injection molding and sheet metal fabrication and manufacture the majority of plastic and sheet metal parts used in the products we manufacture. Additionally, we have equipment to maintain a controlled clean environment for manufacturing processes that require a high level of precise control. +We use a variety of manual and automated assembly processes in our facilities, depending upon product complexity and degree of customization. Some examples of automated processes include component insertion, SMT, selective soldering, flexible robotic assembly, automated storage tape winding, computerized vision system quality inspection, laser turrets, automated switch and key top installation, robotic welding, automated powder coat application, and automated functional testing. +Our engineering expertise and automated manufacturing processes enable us to work closely with our customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. We use computer-aided design techniques and software to assist in preparation of the tool design layout and component placement, to reduce tooling and production costs, improve component and product quality, and enhance turnaround time during product development. +We purchase materials and components for our products from many different suppliers, including both domestic and international sources. We develop close working relationships with our suppliers, many of whom have been supplying products to us for several years. +5 +Research, Development, and Engineering +As part of our long-term strategy, we are committed to supporting our customers by providing research, development, and engineering services. We have recently seen an increase in the success of providing design support on existing and potential customers in differentiating ourselves. These services allow us to facilitate in optimizing new product designs, and the production processes of our customers’ programs. +Research, development, and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials costs, depreciation, and allocated information technology and facilities costs. +Competition +The market for the products and services we provide is highly competitive. There are numerous competitors in the EMS industry, many of which have substantially more resources and are more geographically diverse than we are. Some of our competitors have similar international production capabilities, large financial resources and some have substantially greater manufacturing, research and development, and marketing resources. There is also competition from the manufacturing operations of our current and potential customers, who are continually evaluating the merits of manufacturing their products internally versus the advantages of outsourcing. We believe that we can currently compete favorably in these areas primarily on the basis of our international footprint, responsiveness, creativity, vertical production capability, quality, and cost. +Trademarks +Our name and logo are federally registered trademarks, and we believe they are valuable assets of our business. We operate under the trade name “KeyTronicEMS” to better identify our primary business concentration in contract manufacturing in the EMS industry. +Employees +We consider our employees to be our primary strength and we make considerable efforts to maintain a well-qualified workforce. Our employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. We regularly provide transportation, medical services, and meals to all of our employees in foreign locations. The Company also has defined contribution plans available to U.S. employees who have attained age 21 and provide group health, life, and disability insurance plans. We also maintain share based compensation plans and other long-term incentive plans for certain employees and outside directors. +As of June 30, 2018 we had 4,701 full-time employees compared to 5,038 on July 1, 2017 , and 4,947 on July 2, 2016 . Since we can have significant fluctuations in product demand, we seek to maintain flexibility in our workforce by utilizing skilled temporary labor in our manufacturing facilities in addition to full-time employees. +Backlog +On July 28, 2018 our order backlog was valued at approximately $167.7 million, compared to approximately $126.9 million on July 29, 2017. The amount of backlog is not necessarily indicative of future sales but can be indicative of trends in expected future sales revenue. Due to the relationships with our customers, we will occasionally allow orders to be canceled or rescheduled and as a result it is not a meaningful indicator of future financial results. If there are canceled or rescheduled orders, we typically negotiate fees to cover the costs we have incurred. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change due to design modifications, customer forecast changes, or other customer requirements. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in Note 12, “Enterprise-Wide Disclosures” of the consolidated financial statements of this Annual Report on Form 10-K and that information is incorporated herein. +6 +Executive Officers of the Registrant +The table below sets forth the name, current age and current position of our executive officers and other significant employees: +Name +Age +Positions Held +Executive Officers +Craig D. Gates +59 +President and Chief Executive Officer +Brett R. Larsen +45 +Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Douglas G. Burkhardt +60 +Executive Vice President of Worldwide Operations +Philip S. Hochberg +56 +Executive Vice President of Business Development +David H. Knaggs +37 +Vice President of Quality and Regulatory Affairs +Frank Crispigna III +57 +Vice President of Supply Chain +Duane D. Mackleit +50 +Vice President of Program Management +Chad T. Orebaugh +47 +Vice President of Engineering +Executive Officers +CRAIG D. GATES – President and Chief Executive Officer +Mr. Gates, age 59 , has been President and Chief Executive officer of the Company since April 2009. Previously, he was Executive Vice President and General Manager from August 2002 to April 2009. He served as Executive Vice President of Marketing, Engineering and Sales from July 1997 to August 2002 and served as Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of 1994. From 1982 to 1991 he held various engineering and management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. Mr. Gates has a Bachelor of Science Degree in Mechanical Engineering and a Masters in Business Administration from the University of Illinois, Urbana. +BRETT R. LARSEN – Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Mr. Larsen, age 45 , has served as Executive Vice President of Administration, Chief Financial Officer, and Treasurer since July 2015. Previously, he was Vice President of Finance and Controller from February 2010 to July 2015. He was Chief Financial Officer of FLSmidth Spokane, Inc. from December 2008 to February 2010. From October 2005 through November 2008, Mr. Larsen served as Controller of Key Tronic Corporation. From May 2004 to October 2005, Mr. Larsen served as Manager of Financial Reporting of Key Tronic Corporation. From 2002 to May 2004, Mr. Larsen was an audit manager for the public accounting firm BDO USA, LLP. He also held various auditing and supervisory positions with Grant Thornton LLP from 1997 to 2002. Mr. Larsen has a Bachelor of Science degree in Accounting and a Masters degree in Accounting from Brigham Young University and is a Certified Public Accountant. +DOUGLAS G. BURKHARDT – Executive Vice President of Worldwide Operations +Mr. Burkhardt, age 60 , has been Executive Vice President of Worldwide Operations of the Company since July 2010. Previously Mr. Burkhardt was Vice President of Worldwide Operations from July 2008 to July 2010 and Director of China Operations and Program Management from January 2006 to July 2008. Mr. Burkhardt also served as Director of Northwest and China Operations from November of 1998 to January of 2006. Mr. Burkhardt also served as Director of Customer Satisfaction from March 1997 to November 1998 and Director of Molding from September of 1995 to March of 1997. Prior to this, Mr. Burkhardt served in other various senior management positions within the Company. Mr. Burkhardt has been with the Company since May of 1989. Prior to joining Key Tronic, Mr. Burkhardt worked for House of Aluminum and Glass for 12 years where he was the plant manager. +PHILIP S. HOCHBERG – Executive Vice President of Business Development +Mr. Hochberg, age 56 , has been Executive Vice President of Business Development since July 2012. Prior to this, Mr. Hochberg served as Vice President of Business Development from October 2009 through June 2012. He was Director of Business Development and Program Management from July 2008 to October 2009. Mr. Hochberg served as Director of Business Development from October 2004 to July 2008 and as Director of EMS Sales and Marketing from July 2000 to October 2004. Prior to joining Key Tronic, Mr. Hochberg worked for Quinton Instrument Company as their Director of Marketing and Product Management from 1992 to 2000. From 1988 to 1992, he was employed by SpaceLabs Medical as their Business Development Marketing Manager. Mr. Hochberg has an MBA from the University of British Columbia, a BA in Psychology, with a minor in Business from Washington University in St. Louis. +7 +DAVID H. KNAGGS – Vice President of Quality and Regulatory Affairs +Mr. Knaggs, age 37 , has been Vice President of Quality and Regulatory Affairs since October 2016. Before joining KeyTronicEMS, Mr. Knaggs worked at Telect, Inc. from 2008 to 2016 as their Director of Engineering. Prior to that, he worked at Isothermal Systems Research as Lead Systems Engineer from 2003 to 2008. He has a Bachelor of Science degree in Mechanical Engineering with a minor in mathematics from the University of Washington. +FRANK CRISPIGNA III – Vice President of Supply Chain +Mr. Crispigna, age 57 , has been Vice President of Supply Chain of the company since October 2011. Prior to this, Mr. Crispigna held a variety of Materials and Supply Chain positions at Plexus Corporation since 1997, most recently serving as the Director – Supply Chain Solutions from 2005 - 2011. He has a Masters degree in Business Administration, and a Bachelor of Business Administration Degree in Marketing from the University of Wisconsin – Oshkosh. Mr. Crispigna also is a C.P.M., and received his certification in Supply Chain Leadership from the University of Wisconsin. +DUANE D. MACKLEIT – Vice President of Program Management +Mr. Mackleit, age 50 , has been Vice President of Program Management of the company since July 2012. He served as Director of Program Management from July 2008 through June 2012. From May 2006 to July 2008 he served as Principal Program Manager. Prior to that, he served as Program Manager from March 2002 to May 2006 and Associate Program Manager from August 2000 to March 2002. Mr. Mackleit has also held several other positions with Key Tronic Corporation. Mr. Mackleit has an AA in Business from Spokane Falls Community College and a BA in Business/Marketing from Eastern Washington University. He also holds a MBA from Gonzaga University. +CHAD T. OREBAUGH – Vice President of Engineering +Mr. Orebaugh, age 47 , has been Vice President of Engineering since April 2017. Prior to this, Mr. Orebaugh served as Director of Engineering since May 2013. From April 2010 to May 2013, he served as Manager of Engineering. From January 2000 to April 2010 he served as Lead Mechanical Engineer. Prior to that, he served as Mechanical Engineer from October 1998 to January 2000 and Associate Mechanical Engineer since October 1997. Mr. Orebaugh holds a BA in Mechanical Engineering from Gonzaga University. +Available Information +Our principal executive offices are located at 4424 North Sullivan Road, Spokane Valley, Washington 99216, and our telephone number is (509) 928-8000. Our website is located at http://www.keytronic.com where filings of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or current reports on Form 8-K are available after they have been filed with the Securities and Exchange Commission. The information presented on our website currently and in the future is not considered to be part of this document or any document incorporated by reference in this document. +8 \ No newline at end of file diff --git a/raw/filings/0000719733/2018/0000719733-18-000054/item13.txt b/raw/filings/0000719733/2018/0000719733-18-000054/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..2bde812f869c9297381ce4be19a8daeb0754eb85 --- /dev/null +++ b/raw/filings/0000719733/2018/0000719733-18-000054/item13.txt @@ -0,0 +1,3 @@ +Item 13: +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions”, “Compensation Committee Interlocks and Insider Participation”, and “Directors’ Independence” in the Company’s 2018 Proxy Statement is incorporated herein by this reference. \ No newline at end of file diff --git a/raw/filings/0000719733/2018/0000719733-18-000054/item9a.txt b/raw/filings/0000719733/2018/0000719733-18-000054/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..2e642cb6bace25a88add1dc7ba89934d7a04ff56 --- /dev/null +++ b/raw/filings/0000719733/2018/0000719733-18-000054/item9a.txt @@ -0,0 +1,28 @@ +Item 9A: +CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +It is the responsibility of our management to establish, maintain, and monitor disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 are recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Additionally, these disclosure controls include controls and procedures that are designed to accumulate and communicate the information required to be disclosed to our Company’s Chief Executive Officer and Chief Financial Officer, allowing for timely decisions regarding required disclosures. As of the end of the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(f). Based on our assessment, we believe that as of June 30, 2018 , the Company’s disclosure controls and procedures are effective based on that criteria. +Management’s Report on Internal Control over Financial Reporting +Our management has the responsibility to establish and maintain adequate internal controls over our financial reporting, as defined in Rule 13a-15(f) under the Securities and Exchange Act of 1934. Our internal controls are designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our external financial statements in accordance with generally accepted accounting principles (GAAP). +Due to inherent limitations of any internal control system, management acknowledges that there are limitations as to the effectiveness of internal controls over financial reporting and therefore recognize that only reasonable assurance can be gained from any internal control system. Accordingly, our internal control system may not detect or prevent material misstatements in our financial statements and projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, we have performed an assessment of the effectiveness of our internal controls over financial reporting as of June 30, 2018 . This assessment was based on the criteria established in Internal Control-Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that as of June 30, 2018 , the Company’s internal control over financial reporting is effective based on that criteria. +The effectiveness of the Company's internal control over financial reporting as of June 30, 2018 has been audited by BDO USA LLP, an independent registered public accounting firm, as stated in their report which is included herein. +Changes in Internal Control over Financial Reporting +There have been no significant changes in our internal controls over financial reporting during our fourth fiscal quarter ended June 30, 2018 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)). +58 +Report of Independent Registered Public Accounting Firm +Board of Directors and Stockholders +Key Tronic Corporation +Spokane Valley, Washington +We have audited Key Tronic Corporation’s (the “Company’s”) internal control over financial reporting as of June 30, 2018 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of June 30, 2018, based on the COSO criteria . +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company and subsidiaries as of June 30, 2018 and July 1, 2017, the related consolidated statements of income (loss), comprehensive income, shareholders’ equity, and cash flows for each of the three years in the period ended June 30, 2018, and the related notes and schedule and our report dated September 10, 2018 expressed an unqualified opinion thereon. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying “Item 9A, Management’s Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit of internal control over financial reporting in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ BDO USA, LLP +Spokane, Washington +September 10, 2018 +59 \ No newline at end of file diff --git a/raw/filings/0000719733/2018/0000719733-18-000054/rp_note.txt b/raw/filings/0000719733/2018/0000719733-18-000054/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000719733/2018/0000719733-18-000054/rpt_disclosure.txt b/raw/filings/0000719733/2018/0000719733-18-000054/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..7d8b3231f42bc0d6a37460b033cd88e6ecde5701 --- /dev/null +++ b/raw/filings/0000719733/2018/0000719733-18-000054/rpt_disclosure.txt @@ -0,0 +1,6 @@ +Related Person Transactions +In April 2007, the Board of Directors adopted a written policy and procedures for the approval or ratification of Interested Transactions with Related Parties. The policy and procedures supplement the Company’s Code of Conduct. The policy defines an “Interested Transaction” as any transaction, arrangement or relationship or series of similar transactions, arrangements or relationships (including any indebtedness or guarantee of indebtedness) in which (1) the aggregate amount involved will or may be expected to exceed $120,000 in any calendar year, (2) the Company is a participant, and (3) any Related Party has or will have a direct or indirect interest (other than solely as a result of being a director or a less than 10 percent beneficial owner of another entity). +The policy defines a “Related Party” as any (a) person who is or was (since the beginning of the last fiscal year for which the Company has filed a Form 10-K and proxy statement, even if they do not presently serve in that role) an executive officer, director or nominee for election as a director, (b) greater than 5 percent beneficial owner of the Company’s common stock, or (c) immediate family member of any of the foregoing. Immediate family member includes a person’s spouse, parents, stepparents, children, stepchildren, siblings, mothers- and fathers-in-law, sons- and daughters-in-law, and brothers- and sisters-in-law and anyone residing in such person’s home (other than a tenant or employee). +The Audit Committee is responsible for review, approval, ratification or disapproval of Interested Transactions. In determining whether to approve or ratify an Interested Transaction, the Committee will take into account, among other factors it deems appropriate, whether the Interested Transaction is on terms no less favorable than terms generally available to an unaffiliated third party under the same or similar circumstances and the extent of the Related Party’s interest in the Transaction. +During the fiscal year 2019, the Company had no transactions with CyberOptics. During fiscal year 2018, the Company purchased surface mount technology inspection equipment from CyberOptics. The purchases by the Company during fiscal year 2018 totaled $159,600. 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jurisdiction of +Incorporation or organization) +(I.R.S. Employer +Identification No.) +4424 North Sullivan Road +Spokane Valley, +Washington +99216 +(Address of principal executive offices) +(Zip Code) +( 509 ) 928-8000 +(Registrant’s telephone number, including area code) +N/A +(Former name, former address and former fiscal year, if changed since last report) +____________________________________________________________ +Securities Registered Pursuant to Section 12(b) of the Act: None +Title of each class +Trading Symbol +Name of each exchange on which registered +Common stock, no par value +KTCC +The NASDAQ Stock Market LLC +Securities Registered Pursuant to Section 12(g) of the Act: None +____________________________________________________________ +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ☐ No ☒ +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulations S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☒ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. +(Check one): +Large accelerated filer +☐ +Accelerated filer +☒ +Non-accelerated filer +☐ (Do not check if a smaller reporting company) +Smaller reporting company +☒ +Emerging growth company +☐ +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ +State the aggregate market value of the voting and non-voting common equity held by non affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. +As of December 31, 2018, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $ 60.8 million based on the closing price as reported on the NASDAQ. +Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: 10,759,680 shares of common stock were outstanding as of September 4, 2019 . +____________________________________________________________ +Documents Incorporated by Reference: +Certain information is incorporated into Part III of this report by reference to the Proxy Statement for the registrant’s 2019 annual meeting of stockholders to be filed with the Securities and Exchange Commission pursuant to Regulation 14A not later than 120 days after the end of the fiscal year covered by this Form 10-K. +KEY TRONIC CORPORATION +2019 FORM 10-K +TABLE OF CONTENTS +Page No. +PART I +Item 1. +Business +4 +Item 1A. +Risk Factors +9 +Item 1B. +Unresolved Staff Comments +15 +Item 2. +Properties +16 +Item 3. +Legal Proceedings +17 +Item 4. +Mine Safety Disclosures +17 +PART II +Item 5. +Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities +17 +Item 6. +Selected Financial Data +19 +Item 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +20 +Item 7A. +Quantitative and Qualitative Disclosures about Market Risk +30 +Item 8. +Financial Statements and Supplementary Data +31-62 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +62 +Item 9A. +Controls and Procedures +62 +Item 9B. +Other Information +65 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +65 +Item 11. +Executive Compensation +65 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +65 +Item 13. +Certain Relationships and Related Transactions, and Director Independence +66 +Item 14. +Principal Accounting Fees and Services +66 +PART IV +Item 15. +Exhibits and Financial Statement Schedule +66 +Signatures +72 +3 +FORWARD-LOOKING STATEMENTS +References in this report to “the Company,” “Key Tronic,” “KeyTronicEMS,” “we,” “our,” or “us” mean Key Tronic Corporation together with its subsidiaries, except where the context otherwise requires. +This Annual Report on Form 10-K contains forward-looking statements in addition to historical information. Forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those reflected in the forward-looking statements. Risks and uncertainties that might cause such differences include, but are not limited to those outlined in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risks and Uncertainties that May Affect Future Results.” Readers are cautioned not to place undue reliance on forward-looking statements, which reflect management’s opinions only as of the date hereof. The Company undertakes no obligation to update forward-looking statements to reflect developments or information obtained after the date hereof and disclaims any obligation to do so. Readers should carefully review the risk factors described in periodic reports the Company files from time to time with the Securities and Exchange Commission, including Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. +PART I +Item 1. +BUSINESS +Background +Key Tronic Corporation (dba: KeyTronicEMS Co.) was organized in 1969, as a Washington corporation that locally manufactured computer keyboards. The ability to design, build and deliver a quality product led us to become a leading independent manufacturer of keyboards for computers in the United States. Our fully integrated design, tooling, and automated manufacturing capabilities enabled us to rapidly respond to customers’ needs for keyboards in production quantities worldwide. We supported our sales growth through the development and purchase of international manufacturing facilities. As the computer keyboard market matured with increasing competition from other international providers, we determined that our business could no longer solely rely on keyboard sales. +After assessing market conditions and our strengths and capabilities, we shifted our focus from keyboard manufacturing to contract manufacturing for a wide range of products. Our unique strategic attributes are based on our core strengths of innovative design and engineering expertise in electronics, mechanical engineering, sheet metal fabrication and stamping, and precision plastics combined with high-quality, low cost production, and assembly on an international basis while providing exceptional customer service. These strengths have made our company a strong competitor in the electronic manufacturing services (EMS) market. +Our Industry and Strategy +The expansion of the EMS industry and our acquisitions have allowed us to continue to expand our customer base and the industries that we serve. The increase in new programs represents a growing portion of our revenue and a promising foundation for our future. In keeping with our long-term strategic objectives, we have been successfully building a more diversified customer portfolio, spanning a wider range of industries. We currently offer our customers the following services: integrated electronic and mechanical engineering, precision plastic molding, sheet metal fabrication, printed circuit board (PCB) and complete product assembly, component selection, sourcing and procurement, worldwide logistics, and new product testing and production all at competitive pricing due to our global footprint. We differentiate ourselves from others our size and larger in the EMS industry by providing vertical integration, a flexible and responsive approach to our customer’s changing supply demand, and complete design engineering support. +We believe that we are well positioned in the EMS industry to continue the expansion of our customer base and achieve long-term growth. Our unique blend of multinational facilities, vertical integration, centralized management, and core strengths continue to support our growth and our customers’ needs. We continue to focus on controlling operating expenses and leveraging the synergistic capabilities of our world-class facilities in the United States, Mexico, China and Vietnam. This international production capability provides our customers with the benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs, and reduced product fulfillment time. Given our competitive advantages and the growing pressure for new potential customers to move forward with their outsourcing strategies, we are strongly positioned to win new business in coming periods and grow our revenue and profits. +4 +The EMS industry is intensely competitive. Although our customer base is growing, we still have less than 1% of the potential global market and our revenue can fluctuate significantly due to reliance on a concentrated base of customers. We are planning for new customer growth in the coming quarters by securing new programs with new and existing customers, increasing our worldwide manufacturing capacity, leveraging further our design engineering capabilities and continuing to improve our manufacturing and procurement processes and capabilities. Ongoing challenges that we face include but are not limited to the following: continuing to win programs from new and existing customers, balancing capital employed, production capacity and key personnel in support of new customer programs, improving operating efficiencies, controlling costs while developing competitive pricing strategies, and successfully transitioning new program wins to full production. +Customers and Marketing +We provide a mix of manufacturing services for outsourced Original Equipment Manufacturing (OEM) products. We provide the following EMS services: product design, surface mount technologies (SMT) and pin through hole capability for printed circuit board assembly, tool making, precision plastic molding, sheet metal fabrication and painting, liquid injection molding, complex assembly, automated tape winding, prototype design and full product assembly. +Sales of the majority of our products have not historically been seasonal in nature, but may be seasonal in the future if there are changes in the types of products manufactured. Sales can, however, fluctuate significantly between quarters from changes in customers and customer demand due to the concentration of sales generated by our largest customers. +For the fiscal years 2019 , 2018 and 2017 , the five largest customers in each year accounted for 41%, 42% and 42% of combined total net sales, respectively. We continue to diversify our customer base by adding additional programs and customers. We expect net sales to our five largest customers as a percentage of total net sales to approximate current levels going forward. +The following table represents all customers that represented 10% or more of total net sales during the last three fiscal years: +Percentage of Net Sales by Fiscal Year +2019 +2018 +2017 +Customer A +17% +19% +18% +There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +We market our products and services primarily through our direct sales department which is comprised of strategically located field sales people and distributors. We also maintain relationships with several independent sales organizations to assist in marketing our EMS product lines. +Manufacturing +We have continually made investments in developing and expanding a capital equipment base to achieve vertical integration and efficiencies in our manufacturing processes. We have invested significant capital into SMT for volume manufacturing of complex printed circuit board assemblies and in our metal shop providing precision metal stamping, fabricating, and finishing. We also design and develop tooling for injection molding and sheet metal fabrication and manufacture the majority of plastic and sheet metal parts used in the products we manufacture. Additionally, we have equipment to maintain a controlled clean environment for manufacturing processes that require a high level of precise control. +We use a variety of manual and automated assembly processes in our facilities, depending upon product complexity and degree of customization. Some examples of automated processes include component insertion, SMT, selective soldering, flexible robotic assembly, automated storage tape winding, computerized vision system quality inspection, laser turrets, automated switch and key top installation, robotic welding, automated powder coat application, and automated functional testing. +Our engineering expertise and automated manufacturing processes enable us to work closely with our customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. We use computer-aided design techniques and software to assist in preparation of the tool design layout and component placement, to reduce tooling and production costs, improve component and product quality, and enhance turnaround time during product development. +We purchase materials and components for our products from many different suppliers, including both domestic and international sources. We develop close working relationships with our suppliers, many of whom have been supplying products to us for several years. +5 +Research, Development, and Engineering +As part of our long-term strategy, we are committed to supporting our customers by providing research, development, and engineering services. We have seen an increase in the success of providing design support on existing and potential customers in differentiating ourselves. These services allow us to facilitate in optimizing new product designs, and the production processes of our customers’ programs. +Research, development, and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials costs, depreciation, and allocated information technology and facilities costs. +Competition +The market for the products and services we provide is highly competitive. There are numerous competitors in the EMS industry, many of which have substantially more resources and are more geographically diverse than we are. Some of our competitors have similar international production capabilities, large financial resources and some have substantially greater manufacturing, research and development, and marketing resources. There is also competition from the manufacturing operations of our current and potential customers, who are continually evaluating the merits of manufacturing their products internally versus the advantages of outsourcing. We believe that we can currently compete favorably in these areas primarily on the basis of our international footprint, responsiveness, creativity, vertical production capability, quality, and cost. +Trademarks +Our name and logo are federally registered trademarks, and we believe they are valuable assets of our business. We operate under the trade name “KeyTronicEMS” to better identify our primary business concentration in contract manufacturing in the EMS industry. +Employees +We consider our employees to be our primary strength and we make considerable efforts to maintain a well-qualified workforce. Our employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. We regularly provide transportation, medical services, and meals to all of our employees in foreign locations. The Company also has defined contribution plans available to U.S. employees who have attained age 21 and provide group health, life, and disability insurance plans. We also maintain share based compensation plans and other long-term incentive plans for certain employees and outside directors. +As of June 29, 2019 we had 4,067 full-time employees compared to 4,701 on June 30, 2018 , and 5,038 on July 1, 2017 . Since we can have significant fluctuations in product demand, we seek to maintain flexibility in our workforce by utilizing skilled temporary labor in some of our manufacturing facilities in addition to full-time employees. +Backlog +On July 27, 2019 our order backlog was valued at approximately $159.48 million, compared to approximately $167.7 million on July 28, 2018. The amount of backlog is not necessarily indicative of future sales but can be indicative of trends in expected future sales revenue. Due to the relationships with our customers, we will occasionally allow orders to be canceled or rescheduled and as a result it is not a meaningful indicator of future financial results. If there are canceled or rescheduled orders, we typically negotiate fees to cover the costs we have incurred. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change due to design modifications, customer forecast changes, or other customer requirements. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in Note 12, “Enterprise-Wide Disclosures” of the consolidated financial statements of this Annual Report on Form 10-K and that information is incorporated herein. +6 +Executive Officers of the Registrant +The table below sets forth the name, current age and current position of our executive officers and other significant employees: +Name +Age +Positions Held +Executive Officers +Craig D. Gates +60 +President and Chief Executive Officer +Brett R. Larsen +46 +Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Douglas G. Burkhardt +61 +Executive Vice President of Worldwide Operations +Philip S. Hochberg +57 +Executive Vice President of Business Development +David H. Knaggs +38 +Vice President of Quality and Regulatory Affairs +Duane D. Mackleit +51 +Vice President of Program Management +Chad T. Orebaugh +48 +Vice President of Engineering +Thomas Despres +57 +Vice President of Southwest Operations +Mark Courtney +53 +Vice President of Supply Chain +Executive Officers +CRAIG D. GATES – President and Chief Executive Officer +Mr. Gates, age 60 , has been President and Chief Executive officer of the Company since April 2009. Previously, he was Executive Vice President and General Manager from August 2002 to April 2009. He served as Executive Vice President of Marketing, Engineering and Sales from July 1997 to August 2002 and served as Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of 1994. From 1982 to 1991 he held various engineering and management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. Mr. Gates has a Bachelor of Science Degree in Mechanical Engineering and a Masters in Business Administration from the University of Illinois, Urbana. +BRETT R. LARSEN – Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Mr. Larsen, age 46 , has served as Executive Vice President of Administration, Chief Financial Officer, and Treasurer since July 2015. Previously, he was Vice President of Finance and Controller from February 2010 to July 2015. He was Chief Financial Officer of FLSmidth Spokane, Inc. from December 2008 to February 2010. From October 2005 through November 2008, Mr. Larsen served as Controller of Key Tronic Corporation. From May 2004 to October 2005, Mr. Larsen served as Manager of Financial Reporting of Key Tronic Corporation. From 2002 to May 2004, Mr. Larsen was an audit manager for the public accounting firm BDO USA, LLP. He also held various auditing and supervisory positions with Grant Thornton LLP from 1997 to 2002. Mr. Larsen has a Bachelor of Science degree in Accounting and a Masters degree in Accounting from Brigham Young University and is a Certified Public Accountant. +DOUGLAS G. BURKHARDT – Executive Vice President of Worldwide Operations +Mr. Burkhardt, age 61 , has been Executive Vice President of Worldwide Operations of the Company since July 2010. Previously Mr. Burkhardt was Vice President of Worldwide Operations from July 2008 to July 2010 and Director of China Operations and Program Management from January 2006 to July 2008. Mr. Burkhardt also served as Director of Northwest and China Operations from November of 1998 to January of 2006. Mr. Burkhardt also served as Director of Customer Satisfaction from March 1997 to November 1998 and Director of Molding from September of 1995 to March of 1997. Prior to this, Mr. Burkhardt served in other various senior management positions within the Company. Mr. Burkhardt has been with the Company since May of 1989. Prior to joining Key Tronic, Mr. Burkhardt worked for House of Aluminum and Glass for 12 years where he was the plant manager. +PHILIP S. HOCHBERG – Executive Vice President of Business Development +Mr. Hochberg, age 57 , has been Executive Vice President of Business Development since July 2012. Prior to this, Mr. Hochberg served as Vice President of Business Development from October 2009 through June 2012. He was Director of Business Development and Program Management from July 2008 to October 2009. Mr. Hochberg served as Director of Business Development from October 2004 to July 2008 and as Director of EMS Sales and Marketing from July 2000 to October 2004. Prior to joining Key Tronic, Mr. Hochberg worked for Quinton Instrument Company as their Director of Marketing and Product Management from 1992 to 2000. From 1988 to 1992, he was employed by SpaceLabs Medical as their Business Development Marketing Manager. Mr. Hochberg has an MBA from the University of British Columbia, a BA in Psychology, with a minor in Business from Washington University in St. Louis. +7 +DAVID H. KNAGGS – Vice President of Quality and Regulatory Affairs +Mr. Knaggs, age 38 , has been Vice President of Quality and Regulatory Affairs since October 2016. Before joining KeyTronicEMS, Mr. Knaggs worked at Telect, Inc. from 2008 to 2016 as their Director of Engineering. Prior to that, he worked at Isothermal Systems Research as Lead Systems Engineer from 2003 to 2008. He has a Bachelor of Science degree in Mechanical Engineering with a minor in mathematics from the University of Washington. +DUANE D. MACKLEIT – Vice President of Program Management +Mr. Mackleit, age 51 , has been Vice President of Program Management of the company since July 2012. He served as Director of Program Management from July 2008 through June 2012. From May 2006 to July 2008 he served as Principal Program Manager. Prior to that, he served as Program Manager from March 2002 to May 2006 and Associate Program Manager from August 2000 to March 2002. Mr. Mackleit has also held several other positions with Key Tronic Corporation. Mr. Mackleit has an AA in Business from Spokane Falls Community College and a BA in Business/Marketing from Eastern Washington University. He also holds a MBA from Gonzaga University. +CHAD T. OREBAUGH – Vice President of Engineering +Mr. Orebaugh, age 48 , has been Vice President of Engineering since April 2017. Prior to this, Mr. Orebaugh served as Director of Engineering since May 2013. From April 2010 to May 2013, he served as Manager of Engineering. From January 2000 to April 2010 he served as Lead Mechanical Engineer. Prior to that, he served as Mechanical Engineer from October 1998 to January 2000 and Associate Mechanical Engineer since October 1997. Mr. Orebaugh holds a BA in Mechanical Engineering from Gonzaga University. +THOMAS DESPRES – Vice President of Southwest Operations +Thomas Despres, age 57, has been Vice President of Southwest Operations since November 2017. Prior to joining KeyTronicEMS, Mr. Despres worked for Gates Corporation as Plant General Manager from July 2017 to November 2017. From 2016 to 2017, he was self-employed and from 2012 to 2016 he was employed by Flextronics as Vice President Global Account Management. He has an MBA from Campbell University, and a BBA, Production Management from Ohio University in Athens. +MARK COURTNEY – Vice President of Supply Chain +Mark Courtney, age 53, has been Vice President of Supply Chain since August 2019. He returned to KeyTronicEMS in September 2015 having worked for the company in 2006. He has also served as Purchasing Manager and Director of North American Purchasing since his return. Mark worked for Amphenol Telect from 2007 to 2015 as Supply Chain manager, then ERP & Business Operations Manager. From June 2005 to March 2006 Mark worked for MRV Communications as Purchasing Manager before leaving California to relocate his family to the Inland Northwest to work for KeyTronicEMS. Prior to MRV Communications, Mark worked for Arrow Electronics as a Field Sales Representative from May 2000 to June 2005. From October 1990 to May of 2005 Mark worked as Purchasing Manager for Apogee Electronics. His career in electronics manufacturing and procurement began in October 1991 working for Alesis Studio Electronics where he worked in various procurement and scheduling roles, leaving in October 1999 as Purchasing Manager. +Available Information +Our principal executive offices are located at 4424 North Sullivan Road, Spokane Valley, Washington 99216, and our telephone number is (509) 928-8000. Our website is located at http://www.keytronic.com where filings of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or current reports on Form 8-K are available after they have been filed with the Securities and Exchange Commission. The information presented on our website currently and in the future is not considered to be part of this document or any document incorporated by reference in this document. +8 +Item 1A. +RISK FACTORS +There are risks and uncertainties that could affect our business. These risks and uncertainties include but are not limited to, the risk factors described below, in Item 7A: “Quantitative and Qualitative Disclosures about Market Risk” and elsewhere in this Form 10-K. +RISKS AND UNCERTAINTIES THAT MAY AFFECT FUTURE RESULTS +The following risks and uncertainties could affect our actual results and could cause results to differ materially from past results or those contemplated by our forward-looking statements. When used herein, the words “expects,” “believes,” “anticipates” and other similar expressions are intended to identify forward-looking statements. +We may experience fluctuations in quarterly results of operations. +Our quarterly operating results have varied in the past and may vary in the future due to a variety of factors, including adverse changes in the U.S. and global macroeconomic environment, volatility in overall demand for our customers’ products, success of customers’ programs, timing of new programs, new product introductions or technological advances by us, our customers and our competitors, and changes in pricing policies by us, our customers, our suppliers, and our competitors. Our customer base is diverse in the markets they serve, however, decreases in demand, particularly from customers in certain industries could affect future quarterly results. Additionally, our customers could be adversely impacted by illiquidity in the credit markets which could directly impact our operating results. +Component procurement, production schedules, personnel and other resource requirements are based on estimates of customer requirements. Occasionally, our customers may request accelerated production that can stress resources and reduce operating margins. Conversely, our customers may abruptly lower or cancel production which may lead to a sudden, unexpected increase in inventory or accounts receivable for which we may not be reimbursed even when under contract with customers. In addition, because many of our operating expenses are relatively fixed, a reduction in customer demand can harm our gross profit and operating results. The products which we manufacture for our customers have relatively short product life cycles. Therefore, our business, operating results and financial condition are dependent in a significant way on our ability to obtain orders from new customers and new product programs from existing customers. +Operating results can also fluctuate if changes are made to significant estimates and assumptions. Significant estimates and assumptions include the allowance for doubtful receivables, provision for obsolete and non-saleable inventory, stock-based compensation, the valuation allowance on deferred tax assets, valuation of goodwill, impairment of long-lived assets, long-term incentive compensation accrual, the provision for warranty costs, the impact of hedging activities.. +We are exposed to general economic conditions, which could have a material adverse impact on our business, operating results and financial condition. +Adverse economic conditions and uncertainty in the global economy such as unstable global financial and credit markets, inflation, tariffs, and recession can negatively impact our business. Unfavorable economic conditions could affect the demand for our customers’ products by triggering a reduction in orders as well as a decline in forecasts which could adversely affect our sales in future periods. Additionally, the financial strength of our customers and suppliers and their ability to obtain and rely on credit financing may affect their ability to fulfill their obligations to us and have an adverse effect on our financial results. +The majority of our sales come from a small number of customers and a decline in sales to any of these customers could adversely affect our business. +At present, our customer base is concentrated and could become more or less concentrated. There can be no assurance that our principal customers will continue to purchase products from us at current levels. Moreover, we typically do not enter into long-term volume purchase contracts with our customers, and our customers have certain rights to extend or delay the shipment of their orders. We, however, typically require that our customers contractually agree to buy back inventory purchased within specified lead times to build their products if not used. +The loss of one or more of our major customers, or the reduction, delay or cancellation of orders from such customers, due to economic conditions or other forces, could materially and adversely affect our business, operating results and financial condition. The contraction in demand from certain industries could impact our customer orders and have a negative impact on our operations over the foreseeable future. Additionally, if one or more of our customers were to become insolvent or otherwise unable to pay for the manufacturing services provided by us, our operating results and financial condition would be adversely affected. +9 +We depend on a limited number of suppliers for certain components that are critical to our manufacturing processes. A shortage of these components or an increase in their price could interrupt our operations and result in a significant change in our results of operations. +We are dependent on many suppliers, including sole source suppliers, to provide key components and raw materials used in manufacturing customers’ products. We have seen supply shortages in certain electronic components. In addition, our suppliers' facilities may also experience earthquakes, tsunamis and other natural disasters which may cause a shortage of components. This can result in longer lead times and the inability to meet our customers request for flexible production and extended shipment dates. If demand for components outpaces supply, capacity delays could affect future operations. Delays in deliveries from suppliers or the inability to obtain sufficient quantities of components and raw materials could cause delays or reductions in shipment of products to our customers which could adversely affect our operating results and damage customer relationships. +We operate in a highly competitive industry; if we are not able to compete effectively in the EMS industry, our business could be adversely affected. +Competitors may offer customers lower prices on certain high volume programs. This could result in price reductions, reduced margins and loss of market share, all of which would materially and adversely affect our business, operating results, and financial condition. If we were unable to provide comparable or better manufacturing services at a lower cost than our competitors, it could cause sales to decline. In addition, competitors can copy our non-proprietary designs and processes after we have invested in development of products for customers, thereby enabling such competitors to offer lower prices on such products due to savings in development costs. +Cash and cash equivalents are exposed to concentrations of credit risk. +We place our cash with high credit quality institutions. At times, such balances may be in excess of the federal depository insurance limit or may be on deposit at institutions which are not covered by insurance. If such institutions were to become insolvent during which time it held our cash and cash equivalents in excess of the insurance limit, it could be necessary to obtain other credit financing to operate our facilities. +Our ability to secure and maintain sufficient credit arrangements is key to our continued operations. +There is no assurance that we will be able to retain or renew our credit agreements in the future. In the event the business grows rapidly or there is uncertainty in the macroeconomic climate, additional financing resources could be necessary in the current or future fiscal years. There is no assurance that we will be able to obtain equity or debt financing at acceptable terms, or at all in the future. In addition, we have restrictive covenants with our financial institution which could impact how we manage our business. If we cannot meet our financial covenants, our borrowings could become immediately payable which could have a material adverse impact on our financial statements. For a summary of our banking arrangements, see Note 4 Long-Term Debt of the “Notes to Consolidated Financial Statements.” +Our operations may be subject to certain risks. +We manufacture product in facilities located in Mexico, China and the United States. These operations may be subject to a number of risks, including: +• +difficulties in staffing, turnover and managing onshore and offshore operations; +• +political and economic instability (including acts of terrorism, pandemics, civil unrest, forms of violence and outbreaks of war), which could impact our ability to ship, manufacture, and/or receive product; +• +unexpected changes in regulatory requirements and laws; +• +longer customer payment cycles and difficulty collecting accounts receivable; +• +export duties, import controls and trade barriers (including quotas); +• +governmental restrictions on the transfer of funds; +• +burdens of complying with a wide variety of foreign laws and labor practices; subject to trade wars and tariffs +• +our locations may be impacted by hurricanes, tornadoes, earthquakes, water shortages, tsunamis, floods, typhoons, fires, extreme weather conditions and other natural or man-made disasters. +Our operations in certain foreign locations receive favorable income tax treatment in the form of tax credits or other incentives. In the event that such tax incentives are not extended, are repealed, or we no longer qualify for such programs, our taxes may increase, which would reduce our net income. +10 +Additionally, certain foreign jurisdictions restrict the amount of cash that can be transferred to the U.S or impose taxes and penalties on such transfers of cash. To the extent we have excess cash in foreign locations that could be used in, or is needed by, our operations in the United States, we may incur significant penalties and/or taxes to repatriate these funds. +Fluctuations in foreign currency exchange rates could increase our operating costs. +We have manufacturing operations located in Mexico, China and Vietnam. A significant portion of our operations are denominated in the Mexican peso, the Chinese currency, the renminbi ( “ RMB ” ) and soon the Vietnamese dong. Currency exchange rates fluctuate daily as a result of a number of factors, including changes in a country ’ s political and economic policies. Volatility in the currencies of our entities and the United States dollar could seriously harm our business, operating results and financial condition. The primary impact of currency exchange fluctuations is on the cash, receivables, payables and expenses of our operating entities. As part of our hedging strategy, we currently use Mexican peso forward contracts to hedge foreign currency fluctuations for a portion of our Mexican peso denominated expenses. We currently do not hedge expenses denominated in RMB or dong. Unexpected losses could occur from increases in the value of these currencies relative to the United States dollar. +Our success will continue to depend to a significant extent on our key personnel. +Our future success depends in large part on the continued service of our key technical, marketing and management personnel and on our ability to continue to attract and retain qualified production employees. There can be no assurance that we will be successful in attracting and retaining such personnel, particularly in our manufacturing locales that may be experiencing high demand for similar key personnel. The loss of key employees could have a material adverse effect on our business, operating results and financial condition. +If we are unable to maintain our technological and manufacturing process expertise, our business could be adversely affected. +The markets for our customers’ products is characterized by rapidly changing technology, evolving industry standards, frequent new product introductions and short product life cycles. The introduction of products embodying new technologies or the emergence of new industry standards can render existing products obsolete or unmarketable. Our success will depend upon our customers’ ability to enhance existing products and to develop and introduce, on a timely and cost-effective basis, new products that keep pace with technological developments and emerging industry standards and address evolving and increasingly sophisticated customer requirements. Failure of our customers to do so could substantially harm our customers’ competitive positions. There can be no assurance that our customers will be successful in identifying, developing and marketing products that respond to technological change, emerging industry standards or evolving customer requirements. +Start-up costs and inefficiencies related to new or transferred programs can adversely affect our operating results and such costs may not be recoverable if such new programs or transferred programs are canceled or don’t meet expected sales volumes. +Start-up costs, the management of labor and equipment resources in connection with the establishment of new programs and new customer relationships, and the need to obtain required resources in advance can adversely affect our gross margins and operating results. These factors are particularly evident in the ramping stages of new programs. These factors also affect our ability to efficiently use labor and equipment. We are currently managing a number of new programs. Consequently, our exposure to these factors has increased. In addition, if any of these new programs or new customer relationships were terminated, our operating results could be harmed, particularly in the short term. We may not be able to recoup these start-up costs or replace anticipated new program revenues. +Customers may change production timing and demand schedules which makes it difficult for us to schedule production and capital expenditures and to maximize the efficiency of our manufacturing capacity. +Changes in demand for customer products reduce our ability to accurately estimate the future requirements of our customers. This makes it difficult to schedule production and maximize utilization of our manufacturing capacity. We must determine the levels of business that we will seek and accept from customers, set production schedules, commit to procuring inventory, and allocate personnel and resources, based on our estimates of our customers' requirements. Customers can require sudden increases and decreases in production which can put added stress on resources and reduce margins. Sudden decreases in production can lead to excess inventory on hand which may or may not be reimbursed by our customers even when under contract. +Continued growth could further lead to capacity constraints. We may need to transfer production to other facilities, acquire new facilities, or outsource production which could negatively impact gross margin. +11 +An adverse change in the interest rates for our borrowings could adversely affect our financial condition. +We are exposed to interest rate risk under our revolving line of credit and term loan. We currently hedge a portion of our term loan with an interest rate swap. We have not historically hedged the interest rate on our credit facility; therefore, unless we do so, significant changes in interest rates could adversely affect our results of operations. Refer to the discussion in note 4, "Long-Term Debt" to the consolidated financial statements for further details of our debt obligations. We are also exposed to interest rate risk on our factoring activities. +Compliance or the failure to comply with current and future environmental laws or regulations could cause us significant expense. +We are subject to a variety of domestic and foreign environmental regulations relating to the use, storage, and disposal of materials used in our manufacturing processes. If we fail to comply with any present or future regulations, we could be subject to future liabilities or the suspension of current manufacturing operations. In addition, such regulations could restrict our ability to expand our operations or could require us to acquire costly equipment, substitute materials, or incur other significant expenses to comply with government regulations. +Our stock price is volatile. +Holders of the common stock will suffer immediate dilution to the extent outstanding equity awards are exercised to purchase common stock. Our stock price may be subject to wide fluctuations and possible rapid increases or declines over a short time period. These fluctuations may be due to factors specific to us such as our stock's thinly traded nature, variations in quarterly operating results or changes in earnings estimates, or to factors relating to the EMS industry or to the securities markets in general, which, in recent years, have experienced significant price fluctuations. These fluctuations often have been unrelated to the operating performance of the specific companies whose stocks are traded. +Due to inherent limitations, there can be no assurance that our system of disclosure and internal controls and procedures will be successful in preventing all errors, theft and fraud, or in informing management of all material information in a timely manner. +Management does not expect that our disclosure controls and internal controls and procedures will prevent all errors or fraud. A control system is designed to give reasonable, but not absolute, assurance that the objectives of the control system are met. In addition, any control system reflects resource constraints and the benefits of controls must be considered relative to their costs. Inherent limitations of a control system may include: judgments in decision making may be faulty, breakdowns can occur simply because of error or mistake and controls can be circumvented by collusion or management override. Due to the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and may not be detected. +If we do not manage our growth effectively, our profitability could decline. +Our business is experiencing growth which can place considerable additional demands upon our management team and our operational, financial and management information systems. Our ability to manage growth effectively requires us to continue to implement and improve these systems; avoid cost overruns; maintain customer, supplier and other favorable business relationships during possible transition periods; continue to develop the management skills of our managers and supervisors; and continue to train, motivate and manage our employees. Our failure to effectively manage growth could have a material adverse effect on our results of operations. +12 +If our manufacturing processes and services do not comply with applicable statutory and regulatory requirements, or if we manufacture products containing design or manufacturing defects, demand for our services may decline and we may be subject to liability claims. +We manufacture and design products to our customers’ specifications, and, in some cases, our manufacturing processes and facilities may need to comply with applicable statutory and regulatory requirements. For example, medical devices that we manufacture or design, as well as the facilities and manufacturing processes that we use to produce them, are regulated by the Food and Drug Administration and non-U.S. counterparts of this agency. In addition, our customers’ products and the manufacturing processes that we use to produce them often are highly complex. As a result, products that we manufacture may at times contain manufacturing or design defects, and our manufacturing processes may be subject to errors or not be in compliance with applicable statutory and regulatory requirements. Defects in the products we manufacture or design, whether caused by a design, manufacturing or component failure or error, or deficiencies in our manufacturing processes, may result in delayed shipments to customers or reduced or canceled customer orders. If these defects or deficiencies are significant, our business reputation may also be damaged. The failure of the products that we manufacture or our manufacturing processes and facilities to comply with applicable statutory and regulatory requirements may subject us to legal fines or penalties and, in some cases, require us to shut down or incur considerable expense to correct a manufacturing process or facility. Our customers are required to indemnify us against liability associated with designing products to meet their specifications. However, if our customers are responsible for the defects, they may not, or may not have resources to, assume responsibility for any costs or liabilities arising from these defects, which could expose us to additional liability claims. +Energy price increases may negatively impact our results of operations. +Certain components that we use in our manufacturing process are petroleum-based. In addition, we, along with our suppliers and customers, rely on various energy sources in our transportation activities. While significant uncertainty currently exists about the future levels of energy prices, a significant increase is possible. Increased energy prices could cause an increase to our raw material costs and transportation costs. In addition, increased transportation costs of certain of our suppliers and customers could be passed along to us. We may not be able to increase our product prices enough to offset these increased costs. In addition, any increase in our product prices may reduce our future customer orders and profitability. +Disruptions to our information systems, including security breaches, losses of data or outages, could adversely affect our operations. +We rely on information technology networks and systems to process, transmit and store electronic information. In particular, we depend on our information technology infrastructure for a variety of functions, including worldwide financial reporting, inventory management, procurement, invoicing and email communications. Any of these systems may be susceptible to outages due to fire, floods, power loss, telecommunications failures, terrorist attacks and similar events. Despite the implementation of network security measures, our systems and those of third parties on which we rely may also be vulnerable to computer viruses, break-ins and similar disruptions. If we or our vendors are unable to prevent such outages and breaches, our operations could be disrupted. +We are involved in various legal proceedings. +In the past, we have been notified of claims relating to various matters including contractual matters, intellectual property rights or other issues arising in the ordinary course of business. In the event of such a claim, we may be required to spend a significant amount of money to defend or otherwise address the claim. Any litigation or dispute resolution, even where a claim is without merit, could result in substantial costs and diversion of resources. Accordingly, the resolution or adjudication of such disputes, even those encountered in the ordinary course of business, could have a material adverse effect on our business, consolidated financial conditions and results of operations. +Our levels of insurance coverage may not be sufficient for potential damages, claims or losses. +We have various forms of business and liability insurance which we believe are appropriate based on the needs of companies in our industry. As a result, not all of our potential business risks or potential losses would be covered by our insurance policies. If we sustain a significant claim or loss which is not covered by insurance, our net income could be negatively impacted. +13 +Changes in securities laws and regulations will increase our costs and risk of noncompliance. +We are required to file as an accelerated filer. As such, we are subject to additional requirements contained in the Sarbanes-Oxley Act of 2002 (the Sarbanes-Oxley Act) and more recently the Dodd-Frank Act. The Sarbanes-Oxley and Dodd-Frank Acts required or will require changes in some of our corporate governance, securities disclosure and compliance practices. In response to the requirements of the Sarbanes-Oxley and Dodd-Frank Acts, the SEC and NASDAQ promulgated new rules and additional rulemaking is expected in the future. Compliance with these new rules and future rules has increased and may increase further our legal, financial and accounting costs as well as a potential risk of noncompliance. Absent significant changes in related rules, which we cannot assure, we anticipate some level of increased costs related to these new regulations to continue indefinitely. We also expect these developments to make it more difficult and more expensive to obtain director and officer liability insurance, and we may be forced to accept reduced coverage or incur substantially higher costs to obtain coverage. Likewise, these developments may make it more difficult for us to attract and retain qualified members of our Board of Directors or qualified management personnel. Further, the costs associated with the compliance with and implementation of procedures under these and future laws and related rules could have a material impact on our results of operations. In addition, the costs associated with noncompliance with additional securities laws and regulations could also impact our business. +We may encounter complications with acquisitions, which could potentially harm our business. +Any current or future acquisitions may require additional equity financing, which could be dilutive to our existing shareholders, or additional debt financing, which could potentially affect our credit ratings. Any downgrades in our credit ratings associated with an acquisition could adversely affect our ability to borrow by resulting in more restrictive borrowing terms. To integrate acquired businesses, we must implement our management information systems, operating systems and internal controls, and assimilate and manage the personnel of the acquired operations. The integration of acquired businesses may be further complicated by difficulties managing operations in geographically dispersed locations. The integration of acquired businesses may not be successful and could result in disruption by diverting management’s attention from the core business. In addition, the integration of acquired businesses may require that we incur significant restructuring charges or other increases in our expenses and working capital requirements, which reduce our return on invested capital. +Acquisitions may involve numerous other risks and challenges including but not limited to: potential loss of key employees and customers of the acquired companies; the potential for deficiencies in internal controls at acquired companies; lack of experience operating in the geographic market or industry sector of the acquired business; constraints on available liquidity, and exposure to unanticipated liabilities of acquired companies. These and other factors could harm our ability to achieve anticipated levels of profitability at acquired operations or realize other anticipated benefits of an acquisition, and could adversely affect our consolidated business and operating results. +Our identifiable intangible assets could become impaired, which could reduce the value of our assets and reduce net income in the year in which the write-off occurs. +The Company ascribes value to certain identifiable intangible assets, which consists of favorable leases, as a result of the acquisitions of Sabre and Ayrshire. The Company may incur further impairment charges of identifiable intangible assets if it determines that the fair values of the identifiable intangible assets are less than their current carrying values. The Company evaluates, on a regular basis, whether events or circumstances have occurred that indicate all, or a portion, of the carrying amount of intangibles may no longer be recoverable, in which case an impairment charge to earnings would become necessary. +Refer to Notes 1 and 14 to the consolidated financial statements and critical accounting policies and estimates’ in management’s discussion and analysis of financial condition and results of operations for further discussion regarding the impairment testing of identifiable intangible assets. +A decline in general economic conditions or global equity valuations could impact the judgments and assumptions about the fair value of the Company’s businesses and the Company could be required to record impairment charges on its other identifiable intangible assets in the future, which could impact the Company’s consolidated balance sheet, as well as the Company’s consolidated statement of operations. The Company notes further impairment of intangibles would not have a material impact on the financial statements noted above. If the Company was required to recognize an impairment charge in the future, the charge would not impact the Company's consolidated cash flows, current liquidity, capital resources, and covenants under its existing credit facilities. +14 +Changes in financial accounting standards may affect our reported financial condition or results of operations as well increase costs related to implementation of new standards and modifications to internal controls. +Our consolidated financial statements are prepared in conformity with accounting standards generally accepted in the United States, or U.S. GAAP. These principles are subject to amendments made primarily by the Financial Accounting Standards Board (FASB) and the Securities and Exchange Commission (SEC). A change in those policies can have a significant effect on our reported results and may affect our reporting of transactions which are completed before a change is announced. Changes to accounting rules or challenges to our interpretation or application of the rules by regulators may have a material adverse effect on our reported financial results or on the way we conduct business. In addition, the continued convergence of U.S. GAAP and International Financial Reporting Standards (“IFRS”) creates uncertainty as to the financial accounting policies and practices we will need to adopt in the future. +Item 1B. +UNRESOLVED STAFF COMMENTS +None +15 +Item 2. +PROPERTIES AS OF DATE OF FILING +We have manufacturing and sales operations located in the United States, Mexico, China and Vietnam. The table below lists the locations and square footage of our operating facilities: +Location +Approx. +Sq. Ft. +Type of Interest +(Leased/Owned) +Description of Use +Corinth, Mississippi +350,000 +Leased +Manufacturing and warehouse +El Paso, Texas +80,000 +Leased +Shipping and warehouse +Fayetteville, Arkansas +105,000 +Leased +Manufacturing and warehouse +Harrodsburg, Kentucky (1) +22,000 +Owned +Manufacturing and warehouse +Louisville, Kentucky +2,300 +Leased +Administration +Oakdale, Minnesota +103,000 +Leased +Manufacturing and warehouse +Spokane Valley, Washington +95,000 +Leased +Sales, research, administration and manufacturing +Spokane Valley, Washington +36,000 +Leased +Manufacturing +Total USA +793,300 +Juarez, Mexico +193,000 +Leased +Warehouse +Juarez, Mexico +174,000 +Owned +Manufacturing +Juarez, Mexico +115,000 +Owned +Manufacturing and warehouse +Juarez, Mexico +103,000 +Owned +Manufacturing and warehouse +Juarez, Mexico +72,000 +Leased +Manufacturing +Juarez, Mexico +66,000 +Owned +Manufacturing and warehouse +Juarez, Mexico +60,000 +Owned +Manufacturing and warehouse +Total Mexico +783,000 +Shanghai, China +121,000 +Leased +Manufacturing and warehouse +Shanghai, China +8,000 +Leased +Manufacturing +Total China +129,000 +Da Nang, Vietnam +133,000 +Leased +Manufacturing and warehouse +Total Vietnam +133,000 +Grand Total +1,838,300 +(1) +During fiscal year 2017, we closed the Harrodsburg, Kentucky location and transferred customer programs to other facilities in the USA. +The geographic diversity of these locations allows us to offer services near certain of our customers and major electronics markets with the additional benefit of reduced labor costs. We consider the productive capacity of our current facilities sufficient to carry on our current business. In addition, in Juarez, Mexico one of our buildings includes adjacent vacant land that could be developed into additional manufacturing and warehouse space. +All of our facilities are ISO certified to ISO 9001:2015 standard and to Customs Trade Partnership against Terrorism (CTPAT). In addition, the Juarez, Mexico; Shanghai, China and Spokane, Washington facilities are registered/certified to IATF 16949 automotive standard, AS 9100D aviation, space and defense standard, ISO 13485:2016 medical devices, ISO 14001:2015 environmental standard, ANSI/ESD S20.20 Electrostatic Discharge Control Program, OHSAS 18001 Occupational Health and Safety standard, and SA8000 / ISO 2600 social accountability standard. +Oakdale, Minnesota and Corinth, Mississippi are additionally registered to ISO 14001:2015 environmental standard. Oakdale, Minnesota is additionally registered to ISO-13485:2016 medical devices standard, AS9100C aviation, space and defense standard, and NADCAP certified. The Spokane, Washington and Juarez, Mexico facilities are additionally registered to ISO/IEC 80079-34 explosive atmospheres. Additionally, Juarez, Mexico is registered by the NSF for water products. The Oakdale, Minnesota; Corinth, Mississippi; Fayetteville, Arkansas and Spokane, Washington facilities are all registered by the U.S. State Department for International Traffic in Arms Regulations (ITAR). +16 +Item 3. +LEGAL PROCEEDINGS +We are a party to certain lawsuits or claims in the ordinary course of business. We do not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on our financial position, results of operations or cash flow. Refer to Commitment and Contingencies footnote for further details on litigation in the fiscal year. +Item 4. +MINE SAFETY DISCLOSURES +Not Applicable +PART II +Item 5: +MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES +Market Information +Our common stock is traded on the NASDAQ Global Market, formerly the NASDAQ National Market System under the symbol “KTCC.” Quarterly high and low sales prices for our common stock for fiscal years 2019 and 2018 were as follows: +2019 +2018 +High +Low +High +Low +First Quarter +$ +8.24 +$ +7.41 +$ +7.40 +$ +6.69 +Second Quarter +7.61 +5.33 +7.95 +6.74 +Third Quarter +7.30 +5.59 +7.30 +6.81 +Fourth Quarter +6.25 +4.97 +8.60 +6.85 +High and low stock prices are based on the daily sales prices reported by the NASDAQ Stock Market. These quotations represent prices between dealers without adjustment for markups, markdowns, and commissions, and may not represent actual transactions. +Holders and Dividends +As of June 29, 2019 , we had 655 shareholders of common stock on record. As a result of our credit agreement with Wells Fargo Bank, N.A. we are restricted from declaring or paying dividends in cash or stock without the Bank’s prior written consent. We have not paid a cash dividend and do not anticipate payment of dividends in the foreseeable future. +Equity Compensation Plan Information +Information concerning securities authorized for issuance under our equity compensation plans is set forth in Part III, Item 12 of this Annual Report, under the caption “Securities Authorized for Issuance under Equity Compensation Plans”, and that information is incorporated herein by reference. +17 +Performance Graph +Set forth below is a line graph comparing the cumulative total shareholder return on our common stock with the cumulative total return of the NASDAQ Stock Market (U.S. & Foreign) Index and the NASDAQ Electronic Components Index in fiscal 2019 . +6/28/2014 +6/27/2015 +7/2/2016 +7/1/2017 +6/30/2018 +6/29/2019 +Key Tronic Corporation +100.00 +99.35 +68.87 +66.08 +70.64 +46.41 +NASDAQ Composite +100.00 +114.44 +112.51 +144.35 +178.42 +192.30 +NASDAQ Electronic Components +100.00 +106.45 +112.98 +161.62 +214.02 +215.09 +18 +Item 6: +SELECTED FINANCIAL DATA +The following selected data is derived from our audited consolidated financial statements and should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the consolidated financial statements and related notes, and other information included in this report. +Financial Highlights +(In thousands, except for Supplemental Data and Per Share Amounts) +Fiscal Year Ended +June 29, 2019 +June 30, 2018 +July 1, 2017 +July 2, 2016 +June 27, 2015 (3) +Consolidated Statements of Operations Data : +Net sales +$ +464,044 +$ +446,322 +$ +467,797 +$ +484,965 +$ +433,997 +Gross profit +34,601 +34,169 +38,300 +38,825 +33,305 +Gross margin percentage +7.5 +% +7.7 +% +8.2 +% +8.0 +% +7.7 +% +Operating income (loss) +(5,958 +) +1,114 +9,544 +10,416 +6,653 +Operating margin percentage +(1.3 +)% +0.2 +% +2.0 +% +2.1 +% +1.5 +% +Net income (loss) +(7,982 +) +(1,325 +) +5,617 +6,533 +4,304 +Net income (loss) per share – diluted +(0.74 +) +(0.12 +) +0.51 +0.58 +0.38 +Consolidated Cash Flow Data : +Cash flows provided by operations (4) +919 +3,122 +2,284 +571 +6,987 +Capital expenditures +8,386 +4,523 +9,307 +13,277 +8,808 +Consolidated Balance Sheet Data : +Net working capital (1) +104,695 +95,607 +100,440 +97,349 +98,318 +Total assets +238,310 +246,528 +232,840 +235,924 +230,794 +Long-term liabilities +30,447 +29,534 +38,520 +46,232 +43,237 +Shareholders’ equity +114,459 +118,081 +116,567 +105,582 +100,768 +Book value per share (2) +$ +10.64 +$ +10.97 +$ +10.83 +$ +9.84 +$ +9.42 +Supplemental Data : +Number of shares outstanding at year-end +10,759,680 +10,759,680 +10,759,680 +10,725,349 +10,706,136 +Number of employees at year-end +4,067 +4,701 +5,038 +4,947 +4,866 +Approximate square footage of operational facilities +1,816,300 +1,837,300 +1,760,000 +1,828,000 +1,892,000 +(1) +Net working capital is defined as total current assets less total current liabilities. Net working capital measures the portion of current assets that are financed by long term funds and is an indicator of short term financial management. +(2) +Book value per share is defined as total shareholders’ equity divided by the number of shares outstanding at the end of the fiscal year. +(3) +Reflects the acquisition of Ayrshire on September 3, 2014 in fiscal year 2015. +(4) +Reflects the retrospective adoption of ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, during the year ended June 29, 2019. +19 +Item 7: +MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +Overview +KeyTronicEMS is a leader in electronic manufacturing services and solutions to original equipment manufacturers of a broad range of products. We provide engineering services, worldwide procurement and distribution, materials management, world-class manufacturing and assembly services, in-house testing, and unparalleled customer service. Our international production capability provides our customers with benefits of improved supply-chain management, reduced inventories, lower transportation costs, and reduced product fulfillment time. We continue to make investments in all of our operating facilities to give us the production capacity, capabilities and logistical advantages to continue to win new business. The following information should be read in conjunction with the consolidated financial statements included herein and with Item 1A, Risk Factors included as part of this filing. +Our mission is to provide our customers with superior manufacturing and engineering services at the lowest total cost for the highest quality products, and create long-term mutually beneficial business relationships by employing our “Trust, Commitment, Results” philosophy. +Executive Summary +During the fourth quarter of fiscal year 2019, we continued to win significant new business from EMS competitors and from existing customers, including new programs involving smart security, architectural LED lighting, power meters and smart grid, and wireless power solutions. We also continue to invest in new equipment and processes to be more productive in our Mexico and Vietnam facilities, and we’re expanding and enhancing our US facilities. We’re optimistic about our opportunities for growth in fiscal 2020 and beyond. +Net sales of $464.0 million for fiscal year 2019 increased by 4.0 percent as compared to net sales of $446.3 million in fiscal year 2018 . The increase in net sales was primarily driven by an increase in net sales from new program wins, an increase in revenue recognized related to the adoption of Accounting Standards Update 2014-09 Revenue from Contracts with Customers (Topic 606), as well as an increase in demand from current customers. +Despite the many unexpected challenges during the second half of fiscal year 2019, we managed to grow our business for the year and ramp up most of our new programs. In the fourth quarter of fiscal year 2019, we saw a disruption in deliveries of a critical component from a supplier in China; delays in the ramp of a new program due to customer-driven design changes; and temporary reductions in customer demand due to concerns over tariffs and trade tension between the US and Mexico. Moving into the first quarter of fiscal 2020, these issues have been largely resolved and we expect revenue to increase significantly. +For the first quarter of fiscal year 2020 , the Company expects to report revenue in the range of $115 million to $120 million. Future results will depend on actual levels of customers’ orders, the timing of the start-up of production of new product programs, impact of the new revenue recognition accounting policy and the potential impact of the geopolitical uncertainty. We believe that we are well positioned in the EMS industry to continue expansion of our customer base and continue long-term growth. +We continue to diversify our customer base by adding additional programs and customers. Our current customer relationships involve a variety of products, including consumer electronics, electronic storage devices, plastics, household products, gaming devices, specialty printers, telecommunications, industrial equipment, military supplies, computer accessories, medical, educational, irrigation, automotive, transportation management, robotics, RFID, power supply, off-road vehicle equipment, fitness equipment, HVAC controls, consumer products, home building products, material handling systems, lighting equipment, consumer security products, smart security, architectural LED lighting, power meters and smart grid, and wireless power solutions. +Gross profit as a percent of net sales was 7.5 percent in fiscal year 2019 compared to 7.7 percent for the prior fiscal year. The decrease in gross profit as a percentage of net sales was primarily related to an increase in certain overhead costs and by an increase in material related costs. The level of gross margin is impacted by product mix, timing of the startup of new programs, facility utilization, and pricing within the electronics industry and material costs, which can fluctuate significantly from quarter to quarter and year to year. +Operating loss as a percentage of net sales for fiscal year 2019 was (1.3) percent compared to operating income of 0.2 percent for fiscal year 2018 . The decrease in operating income as a percentage of net sales was primarily driven by the one-time impairment of goodwill and intangible assets during fiscal year 2019. +20 +Net loss for fiscal year 2019 was $(8.0) million or $(0.74) per share, as compared to net loss of $(1.3) million or $(0.12) per share for fiscal year 2018 . The decrease in net loss for fiscal year 2019 as compared to fiscal year 2018 was primarily driven by the one-time impairment of approximately $12.4 million related to the impairment of goodwill and intangible assets and $1.1 million in severance expense due to improvements in operating efficiencies during fiscal year 2019. +We maintain a strong balance sheet with a current ratio of 2.1 and a debt to equity ratio of 0.32 . Total cash provided by operating activities as defined on our cash flow statement was $0.9 million during fiscal year 2019 . We maintain sufficient liquidity for our expected future operations. As of June 29, 2019 , we had $23.4 million outstanding on our revolving line of credit with Wells Fargo Bank, N.A. As a result, $21.3 million remained available to borrow as of June 29, 2019 . We believe cash flow from operations, our borrowing capacity, our accounts receivable sale program, and equipment financing should provide adequate capital for planned growth over the long term. +RESULTS OF OPERATIONS +Comparison of the Fiscal Year Ended June 29, 2019 with the Fiscal Year Ended June 30, 2018 +The following table sets forth for the periods indicated certain items of the consolidated statements of income expressed as a percentage of net sales. The financial information and discussion below should be read in conjunction with the consolidated financial statements and notes contained in this Annual Report. +Fiscal Year Ended +June 29, 2019 +% of +net sales +June 30, 2018 +% of +net sales +$ change +% point +change +Net sales +$ +464,044 +100.0% +$ +446,322 +100.0% +$ +17,722 +— +Cost of sales +429,443 +92.5 +412,153 +92.3 +17,290 +0.2 +Gross profit +34,601 +7.5 +34,169 +7.7 +432 +(0.2) +Operating expenses: +Research, development and engineering +6,555 +1.4 +6,186 +1.4 +369 +— +Selling, general and administrative +21,556 +4.6 +22,334 +5.0 +(778 +) +(0.4) +Impairment of goodwill and intangibles +12,448 +2.7 +— +— +12,448 +2.7 +Loss on settlement of arbitration +— +— +4,535 +1.0 +(4,535 +) +(1.0) +Total operating expenses +40,559 +8.7 +33,055 +7.4 +7,504 +1.3 +Operating income (loss) +(5,958 +) +(1.3) +1,114 +0.2 +(7,072 +) +(1.5) +Interest expense, net +2,782 +0.6 +2,556 +0.6 +226 +— +Income (loss) before income taxes +(8,740 +) +(1.9) +(1,442 +) +(0.3) +(7,298 +) +(1.6) +Income tax benefit +(758 +) +(0.2) +(117 +) +— +(641 +) +(0.2) +Net loss +$ +(7,982 +) +(1.7)% +$ +(1,325 +) +(0.3)% +$ +(6,657 +) +(1.4) +Effective income tax rate +8.7 +% +8.1 +% +Net Sales +The increase in net sales of $17.7 million from prior year period was primarily driven by an increase in net sales from new program wins, an increase in revenue recognized related to the adoption of Accounting Standards Update 2014-09 Revenue from Contracts with Customers (Topic 606), as well as an increase in demand from current customers. +21 +The following table shows the revenue by industry sectors as a percentage of revenue for fiscal years 2019 and 2018 : +Fiscal Year Ended +June 29, 2019 +June 30, 2018 +Industrial +44% +42% +Consumer +39 +38 +Gaming +8 +7 +Communication +5 +4 +Transportation +2 +4 +Computer and Peripheral +1 +3 +Printers +1 +2 +Total +100% +100% +We provide services to customers in a number of industries and produce a variety of products for our customers in each industry. Key Tronic does not target any particular industry, but rather seeks to find programs that strategically fit our vertical manufacturing capabilities. As we continue to diversify our customer base and win new customers, we will continue to see a change in the industry concentrations of our revenue. +Sales to foreign locations represented 23.0 percent and 26.2 percent of our total net sales in fiscal years 2019 and 2018 , respectively. +Cost of Sales +Total cost of sales as a percentage of net sales was 92.5 percent and 92.3 percent in fiscal years 2019 and 2018 , respectively. +Total cost of materials as a percentage of net sales was approximately 62.8 percent and 61.1 percent in fiscal years 2019 and 2018 , respectively. The change from year-to-year is primarily a result of unfavorable product mix. +Production and support costs as a percentage of net sales were 29.7 percent and 31.2 percent in fiscal years 2019 and 2018 , respectively. +We provide a reserve for obsolete and non-saleable inventories based on specific identification of inventory against current demand and recent usage. We also consider our customers' ability to pay for inventory whether or not there is a lead-time assurance agreement for a specific program. The amounts charged to expense for these inventories were approximately $91,000 and $31,000 in fiscal years 2019 and 2018 , respectively. +We provide warranties on certain products we sell and estimate warranty costs based on historical experience and anticipated product returns. Warranty expense is related to workmanship claims on keyboards and EMS products. The amounts charged to expense are determined based on an estimate of warranty exposure. The net warranty expense was approximately $83,000 and $74,000 in fiscal years 2019 and 2018 , respectively. +Gross Profit +Gross profit as a percentage of net sales was 7.5 percent and 7.7 percent in fiscal years 2019 , and 2018 , respectively. The 0.2 percentage point decrease in gross profit as a percentage of net sales during fiscal year 2019 as compared to fiscal year 2018 is primarily related to a 1.6 percentage point increase in material related costs partially offset by a 1.4 percentage point decrease in certain overhead costs related to headcount reductions. +Changes in gross profit margins reflect the impact of a number of factors that can vary from period to period, including product mix, start-up costs and efficiencies associated with new programs, product life cycles, sales volumes, capacity utilization of our resources, management of inventories, component pricing and shortages, end market demand for customers’ products, fluctuations in and timing of customer orders, and competition within the EMS industry. These and other factors can cause variations in operating results. There can be no assurance that gross margins will not decrease in future periods. +We took early pay discounts to suppliers that totaled approximately $0.8 million and $1.7 million in fiscal years 2019 and 2018 , respectively. Early pay discounts will fluctuate based on our liquidity and changes in the discounts and terms offered by our suppliers. +22 +Research, Development and Engineering +Research, development and engineering expenses (RD&E) consists principally of employee related costs, third party development costs, program materials, depreciation and allocated information technology and facilities costs. Total RD&E expenses were $6.6 million in fiscal year 2019 and $6.2 million in fiscal year 2018 , respectively. Total RD&E expenses as a percent of net sales were 1.4 percent in fiscal years 2019 and 2018 . +Selling, General and Administrative +Selling, general and administrative expenses (SG&A) consist principally of salaries and benefits, advertising and marketing programs, sales commissions, travel expenses, provision for doubtful accounts, facilities costs, and professional services. Total SG&A expenses were $21.6 million and $22.3 million in fiscal years 2019 and 2018 , respectively. Total SG&A expenses as a percent of net sales were 4.6 percent and 5.0 percent in fiscal years 2019 and 2018 , respectively. This 0.4 percentage point decrease in SG&A as a percentage of net sales is primarily related to a decrease in legal fees and a decrease in amortization expense related to intangibles assets that were impaired during fiscal year 2019. +Impairment of goodwill and intangibles +During fiscal year 2019, the Company assessed other finite-lived intangible assets including the Company’s customer relationships and favorable lease agreements due to an indicator of possible impairment being present, as discussed in footnote 14 of the “Notes to Consolidated Financial Statements.” As a result of the analysis performed, the Company determined that the carrying value of the customer relationships intangible asset was not recoverable and recorded an impairment for the entire carrying amount during the third quarter of fiscal year 2019. During fiscal year 2019, a goodwill impairment of $10.0 million and other intangible assets impairment of $2.5 million was recognized. The Company’s analysis did not indicate that any of its other long-lived assets were impaired. +Loss on Settlement of Arbitration +We were awarded $6.7 million following the conclusion of a previously disclosed arbitration proceeding, which began in the second quarter of fiscal year 2017. This award resolved a dispute with a former customer involving approximately $9.3 million in inventory purchased and approximately $1.9 million in outstanding accounts receivables and other related fees and costs that we believed to be reimbursable. This event, including all related disposal fees, resulted in an approximately $4.5 million before tax one-time loss to fiscal year 2018. The adverse impact net of taxes on net loss was $3.4 million. +Interest Expense +We had net interest expense of $2.8 million and $2.6 million in fiscal years 2019 and 2018 , respectively. The increase in interest expense is primarily related to an increase in the average balance outstanding on our line of credit. +Income Tax Benefit +We had an income tax benefit of approximately $(0.8) million during fiscal year 2019 and $(0.1) million during fiscal year 2018 . The income tax benefit recognized during fiscal years 2019 and 2018 was primarily a function of U.S., and foreign taxes recognized at statutory rates and the net benefit associated with federal research and development tax credits, offset by the tax impact of the nondeductible goodwill write-off in fiscal year 2019 and the impacts of U.S. tax reform in fiscal year 2018. +We continually review our requirements for liquidity domestically to fund current operations, revenue growth and to look for potential future acquisitions. We anticipate repatriating a portion of our unremitted foreign earnings. The estimated taxes associated with these expected repatriations are included in the income tax calculation. For further information on taxes please review footnote 6 of the “Notes to Consolidated Financial Statements.” +23 +International Subsidiaries +We offer customers a complete global manufacturing solution. Our facilities provide our customers the opportunity to have their products manufactured in the facility that best serves specific cost, product manufacturing and distribution needs. The locations of active foreign subsidiaries are as follows: +• +Key Tronic Juarez, SA de CV owns five facilities and leases two facilities in Juarez, Mexico. These facilities include an SMT facility, an assembly and molding facility, a sheet metal fabrication facility, and assembly and warehouse facilities. This subsidiary is primarily used to support our U.S. operations. +• +Key Tronic Computer Peripherals (Shanghai) Co., Ltd. leases two facilities with SMT, assembly, global purchasing and warehouse capabilities in Shanghai, China, which began operations in 1999. Its primary function is to provide EMS services for export. +• +Key Tronic Vietnam leases one facility in Da Nang, Vietnam. This facility includes SMT, assembly, and warehouse capabilities. Its primary function is to provide EMS services for export. +Foreign sales (based on shipping instructions) from our worldwide operations, including domestic exports, were $106.7 million and $117.1 million in fiscal years 2019 and 2018 , respectively. Products and manufacturing services provided by our subsidiary operations are often shipped to customers directly by the parent company. +RESULTS OF OPERATIONS +Comparison of the Fiscal Year Ended June 30, 2018 with the Fiscal Year Ended July 1, 2017 +To review the results of operations comparison of the fiscal year ended June 30, 2018 with the fiscal year ended July 1, 2017 , please refer to our Form 10-K filed September 10, 2018 with the Securities and Exchange Commission or follow the link below. +https://www.sec.gov/Archives/edgar/data/719733/000071973318000054/ktcc-06302018x10k.htm +24 +Capital Resources and Liquidity +Operating Cash Flow +Net cash provided by operating activities for fiscal year 2019 was $0.9 million compared to net cash provided by operating activities of $3.1 million and $2.3 million in fiscal years 2018 and 2017 , respectively. The decrease in cash provided by operating activities is a result of the net loss and the impairment of the goodwill and intangible assets. Upon adoption of ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments , the Company recorded $6.5 million of cash receipts on the deferred purchase price from receivables factored by the Company during fiscal year 2019, in cash flows from investing activities that under the previous guidance would have been classified as cash flows from operating activities. Further, the Company reclassified $8.3 million and $7.1 million of similar cash receipts related to fiscal year 2018 and 2017, respectively, from cash flows from operating activities to cash flows from investing activities. +The $0.9 million of net cash provided by operating activities during fiscal year 2019 is primarily related to $8.0 million of net loss adjusted for $12.4 million impairment of goodwill and intangibles, $7.3 million of depreciation and amortization, $6.7 million of cash received from arbitration settlement, $3.3 million decrease in accounts receivable, partially offset by a $10.3 million increase in contract assets, a $4.5 million increase in other assets and a $2.6 million decrease in accounts payable and a $1.4 million increase in inventory. +The $3.1 million of net cash provided by operating activities during fiscal year 2018 was primarily related to $1.3 million of net loss, $7.8 million of depreciation and amortization, a $23.3 million increase in accounts payable, a $12.6 million decrease in accounts receivable, a $0.6 million decrease in inventory, partially offset by a $4.5 million loss on arbitration. +The $2.3 million of net cash provided by operating activities during fiscal year 2017 was primarily due to $5.6 million of net income, $7.2 million of depreciation and amortization and a $4.9 million decrease in inventory partially offset by a $5.1 million increase in accounts receivable and a $5.9 million decrease in accounts payable. +Accounts receivable fluctuates based on the timing of shipments, terms offered and collections. In addition, accounts receivable will fluctuate based upon the amount of accounts receivable sold under our Trade Accounts Receivable Purchase Program. During fiscal years 2019 , 2018 and 2017 , we factored receivables of $81.0 million , $104.7 million and $86.5 million, respectively, from accounts receivable sold to financial institutions, which are not included on our Consolidated Balance Sheets. We purchase inventory based on customer forecasts and orders, and when those forecasts and orders change, the amount of inventory may also fluctuate. Accounts payable fluctuates with changes in inventory levels, volume of inventory purchases, negotiated supplier terms, and taking advantage of early pay discounts. +Investing Cash Flow +Cash flows used in investing activities were $1.9 million for fiscal year 2019 . Cash flows provided by investing activities were $4.9 million for fiscal year 2018 and cash flows used in investing activities were $1.3 million in fiscal year 2017 . Our primary use of cash in investing activities during fiscal years 2019, 2018 and 2017, was purchasing equipment to support increased production levels for new programs, and our primary source of cash provided by investing activities came from receipts of the deferred purchase price on factored receivables. +Operating and capital leases are often utilized when potential technical obsolescence and funding requirement advantages outweigh the benefits of equipment ownership. Capital expenditures and periodic lease payments are expected to be financed with internally generated funds and available borrowing capacities. During fiscal year 2019, we did not receive any cash resulting from the sale and leaseback of equipment under operating leases. During fiscal years 2018 and 2017, we received $1.0 million and $0.6 million of cash resulting from the sale and leaseback of equipment under operating leases, respectively. +Financing Cash Flow +Cash flows provided by financing activities were $1.2 million in fiscal year 2019 , cash flows used in financing activities were $8.0 million in fiscal year 2018 and $1.6 million in fiscal year 2017 . Our primary financing activities during fiscal year 2019 , were repayments on our term loans of $5.9 million as well as borrowings and repayments under our revolving line of credit facility. Our primary financing activities during fiscal year 2018 was repayments on our term loans of $5.9 million as well as borrowings and repayments under our revolving line of credit facility. Our primary financing activities during fiscal year 2017 was the funding of a $3.9 million equipment term loan, repayments on our term loans of $5.4 million as well as borrowings and repayments under our revolving line of credit facility. +As of June 29, 2019 , the Company had an outstanding balance on the line of credit of $23.4 million . We had availability to borrow an additional $21.3 million under the Wells Fargo line of credit and we were in compliance with our loan covenants. Our cash requirements are affected by the level of current operations and new EMS programs. We believe that projected cash from operations, funds available under the revolving credit facility and fixed asset financing will be sufficient to meet our working and fixed capital requirements for the foreseeable future. +25 +As of June 29, 2019 , we had approximately $0.6 million of cash held by foreign subsidiaries. Under the Tax Cuts and Jobs Act, future cash repatriations from these foreign subsidiaries are no longer subject to U.S. income taxes, but may be subject to foreign withholding taxes. See additional discussion in Footnote 6, Income Taxes. The total amount of foreign withholding taxes required to be paid for the amount of foreign subsidiary cash on hand as of June 29, 2019 , would approximate $54,000. The Company also has approximately $20.7 million of foreign earnings that have not been repatriated to the U.S. Of that amount, the Company estimates that $7.8 million is to be repatriated in the future, requiring foreign withholding taxes of $0.8 million that is currently accrued in our deferred tax liabilities. The remaining $12.9 million is considered to be permanently reinvested in Mexico and China. If these amounts were required to be repatriated, we estimate it would create an additional $1.3 million in foreign withholding taxes payable. +Contractual Obligations and Commitments +In the normal course of business, we enter into contracts which obligate us to make payments in the future. The table below sets forth our significant future obligations by fiscal year: +Payments Due by Fiscal Year (in thousands) +Total +2020 +2021 +2022 +2023 +2024 +Thereafter +Term loans (1) +$ +12,992 +$ +5,871 +$ +5,871 +$ +1,250 +$ +— +$ +— +$ +— +Wells Fargo Bank N.A. revolving loan (2) +$ +23,356 +$ +— +$ +— +$ +— +$ +— +$ +23,356 +$ +— +Operating leases (3) +$ +18,239 +$ +4,777 +$ +3,563 +$ +2,641 +$ +1,866 +$ +1,271 +$ +4,121 +Purchase orders (4) +(1) +The terms of the Wells Fargo Bank N.A. term loans are discussed in the consolidated financial statements at Note 4, “Long-Term Debt.” Principal on the term loan is payable in equal quarterly installments of $1.25 million through June 15, 2021, with final installment of all remaining unpaid principal due on August 31, 2021. The equipment term loan is payable in equal quarterly payments of approximately $0.2 million which commenced on March 31, 2017 and will continue through the maturity of the equipment term loan on June 30, 2021. +(2) +The terms of the Wells Fargo Bank N.A. revolving loan are discussed in the consolidated financial statements at Note 4, “Long-Term Debt.” As of June 29, 2019 , we were in compliance with our loan covenants. +(3) +We maintain vertically integrated manufacturing operations in the United States, Mexico, China and Vietnam. We lease some of our administrative and manufacturing facilities and equipment. A complete discussion of properties can be found in Part 1, Item 2 at “Properties.” Leases have proven to be an acceptable method for us to acquire new or replacement equipment and to maintain facilities with a minimum impact on our short term cash flows for operations. In addition, such operations are heavily dependent upon technically superior manufacturing equipment including molding machines in various tonnages, Surface Mount Technology (SMT) lines, sheet metal fabrication and stamping machines, clean rooms, and automated insertion, and test equipment for the various products we are capable of producing. +(4) +As of June 29, 2019 , we had open purchase order commitments for materials and other supplies of approximately $31.8 million. Included in the open purchase orders are various blanket orders for annual requirements. Actual needs under these blanket purchase orders fluctuate with our manufacturing levels and as such cannot be broken out between fiscal years. In addition, we have contracts with many of our customers that minimize our exposure to losses for material purchased within lead-times necessary to meet customer forecasts. Purchase orders generally can be cancelled without penalty within specified ranges that are determined in negotiations with our suppliers. These agreements depend in part on the type of materials purchased as well as the circumstances surrounding any requested cancellations. +In addition to the cash requirements presented above, we have various other accruals which are not included in the table above. For example, we owe our suppliers approximately $73.6 million for accounts payable and shipments in transit at the end of the fiscal year. We generally pay our suppliers in a range from 30 to 120 days depending on terms offered. These payments are financed by operating cash flows and our revolving line of credit. +We believe that cash flows generated from operations, factoring, leasing facilities, and funds available under the revolving credit facility will satisfy cash requirements for a period in excess of 12 months and into the foreseeable future. +26 +Critical Accounting Policies and Estimates +Preparation of our consolidated financial statements requires management to make estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses. Note 1 to our consolidated financial statements describes the significant accounting policies used in the preparation of our consolidated financial statements. Management believes the most complex and sensitive judgments, because of their significance to our consolidated financial statements, result primarily from the need to make estimates about effects of matters that are inherently uncertain. The most significant areas involving management judgments are described below. Actual results in these areas could differ from management’s estimates. +Revenue +The Company specializes in services ranging from product manufacturing to engineering and tooling services. Subsequent to the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606) during the year ended June 29, 2019, the first step in its process for revenue recognition is to identify the contract with a customer. A contract is defined as an agreement between two or more parties that creates enforceable rights and obligations. A contract can be written, oral, or implied. The Company generally enters into manufacturing service agreements (“MSA”) with its customers that outlines the terms of the business relationship between the customer and the Company. This includes matters such as warranty, indemnification, transfer of title and risk of loss, liability for excess and obsolete inventory, pricing, payment terms, etc. The Company will also bid on a program-by-program basis for customers in which an executed MSA may not be in place. In these instances, as well as when we have an MSA in place, we receive customer purchase orders for specific quantities and timing of products. As a result, the Company considers its contract with a customer to be the combination of the MSA and the purchase order. The transaction price is fixed and set forth in each purchase order. In the Company's normal course of business, there are no variable pricing components, or material amounts refunded to customers in the form of refunds or rebates. +The Company assesses whether control of the product or services promised under the contract is transferred to the customer at a point in time (shipment) or over time (as we manufacture the product). The Company is first required to evaluate whether its contracts meet the criteria for 'over-time' or 'point-in-time' recognition. The Company has determined that for the majority of its contracts the Company is manufacturing products for which there is no alternative use due to the unique nature of the customer-specific product, IP and other contract restrictions. Further, the Company has an enforceable right to payment including a reasonable profit for performance completed to date with respect to these contracts. As a result, revenue is recognized under these contracts 'over-time' based on the input cost-to-cost method as it better depicts the transfer of control. This input method is based on the ratio of costs incurred to date as compared to the total estimated costs at completion of the performance obligation. For all other contracts that do not meet these criteria, such as manufacturing contracts for which the terms do not provide an enforceable right to payment for performance completed to date, the Company recognizes revenue when it has transferred control of the related manufactured products which generally occurs upon shipment to the customer. Revenue from engineering services is recognized over time as the services are performed +Prior to the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606), sales revenue from manufacturing is recognized upon shipment of the manufactured product per contractual terms. Upon shipment, title transfers and the customer assumes risks and rewards of ownership of the product. The price to the buyer is fixed or determinable and recoverability is reasonably assured. Unless specifically stated in contractual terms, there are no formal customer acceptance requirements or further obligations related to the manufacturing services; if any such requirements exist, then sales revenue is recognized at the time when such requirements are completed and such obligations are fulfilled. Revenue is recorded net of estimated returns of manufactured product based on management’s analysis of historical returns. Revenues and associated costs from engineering design, development services and tooling, which are performed under contract of short term durations, are recognized only after the completed performance of the service. +Inactive, Obsolete, and Surplus Inventory Reserve +Inventories are stated at the lower of cost or net realizable value. Inventory valuation is determined using the first-in, first-out (FIFO) method. We reserve for inventories that we deem inactive, obsolete or surplus. This reserve is calculated based upon the demand for the products that we produce. Demand is determined by expected sales, customer purchase orders, or customer forecasts. If expected sales do not materialize, then we would have inventory in excess of our reserves and would have to charge the excess against future earnings. In the case where we have purchased material based upon a customer’s forecast or purchase orders, we are usually covered by lead-time assurance agreements or purchase orders with each customer. These contracts state that the financial liability for material purchased within agreed upon lead-time and based upon the customer’s forecasts, lies with the customer. If we purchase material outside the lead-time assurance agreement and the customer’s forecasts do not materialize or if we have no lead-time assurance agreement for a specific program, we would have the financial liability and may have to charge inactive, obsolete or surplus inventory against earnings. We also reserve for inventory related to specific customers covered by lead-time assurance agreements when those customers are experiencing financial difficulties or reimbursement is not reasonably assured. +27 +Allowance for Doubtful Accounts +We value our accounts receivable net of an allowance for doubtful accounts. As of June 29, 2019 , the allowance for doubtful accounts was approximately $58,000. As of June 30, 2018 , we did not have an allowance for doubtful accounts. This allowance is based on estimates of the portion of accounts receivable that may not be collected in the future. The estimates used are based primarily on specific identification of potentially uncollectible accounts. Such accounts are identified using publicly available information in conjunction with evaluations of current payment activity. However, if any of our customers were to develop unexpected and immediate financial problems that would prevent payment of open invoices, we could incur additional and possibly material expenses that would negatively impact earnings. +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. We review the adequacy of this accrual quarterly based on historical analysis and anticipated product returns and rework costs. Our warranty period for keyboards is generally longer than that for EMS products. We only warrant materials and workmanship on EMS products, and we do not warrant design defects for EMS customers. +Income Taxes +Income tax expense includes U.S. and international income taxes and a provisional estimate for U.S. taxes on undistributed earnings of foreign subsidiaries. We do not record foreign withholding taxes on undistributed earnings of international subsidiaries that are deemed to be permanently reinvested. Certain income and expenses are not reported in tax returns and financial statements in the same year. The tax effect of such temporary differences is reported as deferred income taxes. The deferred income taxes are classified as long-term assets or liabilities. The most significant areas involving management judgments include deferred income tax assets and liabilities, uncertain tax positions, and research and development tax credits. Our estimates of the realization of the deferred tax assets related to our tax credits are based upon our estimates of future taxable income which may change. +Stock-Based Compensation +Stock-based compensation is accounted for according to Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 718, Compensation—Stock Compensation . ASC 718 requires us to expense the fair value of employee stock options, stock appreciation rights and other forms of stock-based compensation. Under the fair value recognition provisions of ASC 718, share-based compensation cost is estimated at the grant date based upon the fair value of the award and is recognized as expense ratably over the requisite service period of the award (generally the vesting period). Determining the appropriate fair value model and calculating the fair value of share-based awards requires judgment, including estimating the expected life of the share-based award, the expected stock price volatility over the expected life of the share-based award and forfeitures. +To determine the fair value of stock based awards on the date of grant we use the Black-Scholes option-pricing model. Inherent in this model are assumptions related to expected stock price volatility, option life, risk-free interest rate and dividend yield. The risk-free interest rate is a less-subjective assumption as it is based on factual data derived from public sources. We use a dividend yield of zero as we have never paid cash dividends and have no intention to pay cash dividends in the foreseeable future. The expected stock price volatility and option life assumptions require a greater level of judgment. Our expected stock-price volatility assumption is based upon the historical volatility of our stock which is obtained from public data sources. The expected life represents the weighted average period of time that share-based awards are expected to be outstanding, giving consideration to vesting schedules and historical exercise patterns. We determine the expected life assumption based upon the exercise and post-vesting behavior that has been exhibited historically, adjusted for specific factors that may influence future exercise patterns. If expected volatility or expected life were to increase, that would result in an increase in the fair value of our stock options which would result in higher compensation charges, while a decrease in volatility or the expected life would result in a lower fair value of our stock option awards resulting in lower compensation charges. +We estimate forfeitures for all of our awards based upon historical experience of stock-based pre-vesting forfeitures. We believe that our estimates are based upon outcomes that are reasonably likely to occur. If actual forfeitures are higher than our estimates it would result in lower compensation expense and to the extent the actual forfeitures are lower than our estimate we would record higher compensation expense. +28 +Impairment of Long-Lived Assets +Long-lived assets, such as property, plant, and equipment are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment charge would be recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. +Derivatives and Hedging Activity +Derivatives are recognized on the balance sheet at their estimated fair value. On the date a derivative contract is entered into, the Company designates the derivative as a hedge of a forecasted transaction or of the variability of cash flows to be received or paid related to a recognized asset or liability (a “cash flow” hedge). The Company does not enter into derivatives for speculative purposes. Changes in the fair value of a derivative that qualifies as a cash flow hedge are recorded in “Accumulated Other Comprehensive Income,” until earnings are affected by the variability of cash flows. See Note 10 of the Company’s consolidated financial statements for additional information. +Long-Term Incentive Compensation Accrual +Long-term incentive compensation is recognized as expense ratably over the requisite service period of the award which is generally three years. The Board of Directors approve target performance measures for the three year period for each of the Company’s officers and non-employee Directors. Performance measures are based on a combination of sales growth targets and return on invested capital targets. No cash awards will be made to participants if actual Company performance does not exceed the minimum target performance measures. The calculation used to determine the necessary accrual uses a combination of actual results and projected results. We believe that our estimates are based upon outcomes that are reasonably likely to occur. These estimates and assumptions are based on historical results as well as future expectations. Actual results could vary from our estimates and assumptions. +Impairment of Goodwill +In accordance with ASC 350, Goodwill and Other Intangible Assets , goodwill is not amortized but is required to be reviewed for impairment at least annually or when events or circumstances indicate that carrying value may exceed fair value. The Company is permitted the option to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the fair value of any reporting unit is less than its corresponding carrying value. If, after assessing the totality of events and circumstances, the Company concludes that it is not more likely than not that the fair value of any reporting unit is less than its corresponding carrying value then the Company is not required to take further action. However, if the Company concludes otherwise, then it is required to perform a quantitative impairment test, including computing the fair value of the reporting unit and comparing that value to its carrying value. The Company utilizes a weighting of the income approach and a market approach in the impairment test. We also consider valuation factors including the Company's market capitalization, future discounted cash flows and an estimated control premium based upon a review of comparable market transactions. Our consideration of discounted future cash flows included assumptions regarding growth rates and margins based on our historical trends. In addition, we applied a market discount rate calculated based upon an analysis of companies similar in size. If our future cash flows do not meet our projections or there is an event that impacts our market capitalization, the assumptions used in our goodwill analysis could be negatively impacted. +Goodwill impairment would be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying value of goodwill. In the event that goodwill is impaired, an impairment charge to earnings would become necessary. The Company also has the option to bypass the qualitative assessment for goodwill in any period and proceed directly to performing the quantitative impairment test. Refer to footnote 14 for discussion of the write-off of goodwill and other intangibles that occurred during fiscal year 2019, as a result of certain triggering events being present. +New and Future Accounting Pronouncements +See Note 1 to our consolidated financial statements. +29 +Item 7A: +QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Interest Rate Risk +We are subject to the risk of fluctuating interest rates in the normal course of business. Our major market risk relates to our secured debt. Our revolving credit facility and term loan are secured by substantially all of our assets. The interest rates applicable to our revolving credit facility and term loans fluctuate with the Wells Fargo Bank prime rate and LIBOR rates. There was outstanding $23.4 million in borrowings under our revolving credit facility and $13.0 million outstanding on our term loans as of June 29, 2019 . See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity” and Note 4 – “Long-Term Debt” to the Consolidated Financial Statements for additional information regarding our revolving credit facility and term loan. +Our only material interest rate risk is associated with our revolving credit facility and term loans. During the second quarter of fiscal year 2015, we entered into an interest rate swap contract with a notional amount of $25.0 million related to the borrowings outstanding under the term loan and revolving credit facility. As of June 29, 2019 , the remaining notional amount of the interest rate swap contract was $2.5 million. Through the use of the interest rate swap, as described above, we fixed the basis on which we pay interest, thus eliminating much of our interest rate risk. See Note 10 – “Derivative Financial Instruments” to the Consolidated Financial Statements for additional information regarding our derivative instruments. +Foreign Currency Exchange Risk +A significant portion of our operations are in foreign locations. As a result, transactions occur in currencies other than the U.S. dollar. Exchange rate fluctuations among other currencies used by us would directly or indirectly affect our financial results. We currently use Mexican peso forward contracts and swaps to hedge foreign currency fluctuations for a portion of our Mexican peso denominated expenses. There was $39.7 million of foreign currency forward contracts and swaps outstanding as of June 29, 2019 . The fair value of these contracts and swaps was approximately $3.2 million . See Note 10 – “Derivative Financial Instruments” to the Consolidated Financial Statements for additional information regarding our derivative instruments. +30 +Item 8: +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Report of Independent Registered Public Accounting Firm +Shareholders and Board of Directors +Key Tronic Corporation +Spokane Valley, Washington +Opinion on the Consolidated Financial Statements +We have audited the accompanying consolidated balance sheets of Key Tronic Corporation (the “Company”) as of June 29, 2019 and June 30, 2018, the related consolidated statements of income (loss), comprehensive income (loss), shareholders’ equity, and cash flows for each of the three years in the period ended June 29, 2019, and the related notes and schedule (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at June 29, 2019 and June 30, 2018, and the results of its operations and its cash flows for each of the three years in the period ended June 29, 2019, in conformity with accounting principles generally accepted in the United States of America. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company's internal control over financial reporting as of June 29, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) and our report dated September 12, 2019 expressed an unqualified opinion thereon. +Change in Accounting Principles +As discussed in Note 1 to the consolidated financial statements, effective July 1, 2018, the Company adopted Topic 606: Revenue from Contracts with Customers, and ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. +Basis for Opinion +These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. +Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. +/s/ BDO USA, LLP +We have served as the Company's auditor since 2003 +Spokane, Washington +September 12, 2019 +31 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED BALANCE SHEETS +(In thousands) +June 29, 2019 +June 30, 2018 +ASSETS +Current assets: +Cash and cash equivalents +$ +601 +$ +343 +Trade receivables, net of allowance for doubtful accounts of $58 and $0 +58,429 +70,262 +Contract assets +22,161 +— +Inventories, net +100,431 +110,315 +Other +16,477 +13,600 +Total current assets +198,099 +194,520 +Property, plant and equipment, net +29,413 +27,548 +Other assets: +Deferred income tax asset +7,840 +7,882 +Goodwill +— +9,957 +Other intangible assets, net +657 +3,726 +Other +2,301 +2,895 +Total other assets +10,798 +24,460 +Total assets +$ +238,310 +$ +246,528 +LIABILITIES AND SHAREHOLDERS ’ EQUITY +Current liabilities: +Accounts payable +$ +73,571 +$ +76,198 +Accrued compensation and vacation +6,759 +8,105 +Current portion of debt, net +5,841 +5,841 +Other +7,233 +8,769 +Total current liabilities +93,404 +98,913 +Long-term liabilities: +Term loans +7,091 +12,932 +Revolving loan +23,356 +16,222 +Other long-term obligations +— +380 +Total long-term liabilities +30,447 +29,534 +Total liabilities +123,851 +128,447 +Commitments and contingencies (Note 4 and 9) +Shareholders’ equity: +Common stock, no par value—shares authorized 25,000; issued and outstanding 10,760 and 10,760 shares, respectively +46,680 +46,244 +Retained earnings +65,353 +72,806 +Accumulated other comprehensive loss +2,426 +( 969 +) +Total shareholders’ equity +114,459 +118,081 +Total liabilities and shareholders’ equity +$ +238,310 +$ +246,528 +See accompanying notes to consolidated financial statements. +32 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF INCOME (LOSS) +(In thousands, except per share amounts) +Fiscal Year Ended +June 29, 2019 +June 30, 2018 +July 1, 2017 +Net sales +$ +464,044 +$ +446,322 +$ +467,797 +Cost of sales +429,443 +412,153 +429,497 +Gross profit +34,601 +34,169 +38,300 +Research, development and engineering expenses +6,555 +6,186 +6,393 +Selling, general and administrative expenses +21,556 +22,334 +22,363 +Impairment of goodwill and intangibles +12,448 +— +— +Loss on settlement of arbitration +— +4,535 +— +Total operating expenses +40,559 +33,055 +28,756 +Operating income (loss) +( 5,958 +) +1,114 +9,544 +Interest expense, net +2,782 +2,556 +2,288 +Income (loss) before income taxes +( 8,740 +) +( 1,442 +) +7,256 +Income tax provision (benefit) +( 758 +) +( 117 +) +1,639 +Net income (loss) +$ +( 7,982 +) +$ +( 1,325 +) +$ +5,617 +Net income (loss) per share — Basic +$ +( 0.74 +) +$ +( 0.12 +) +$ +0.52 +Weighted average shares outstanding — Basic +10,760 +10,760 +10,756 +Net income (loss) per share — Diluted +$ +( 0.74 +) +$ +( 0.12 +) +$ +0.51 +Weighted average shares outstanding — Diluted +10,760 +10,760 +10,917 +See accompanying notes to consolidated financial statements. +33 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) +(In thousands) +Fiscal Year Ended +June 29, 2019 +June 30, 2018 +July 1, 2017 +Comprehensive income: +Net income (loss) +$ +( 7,982 +) +$ +( 1,325 +) +$ +5,617 +Other comprehensive income (loss): +Unrealized gain on hedging instruments, net of tax +3,395 +2,392 +4,798 +Comprehensive income (loss) +$ +( 4,587 +) +$ +1,067 +$ +10,415 +Other comprehensive income (loss) for fiscal years 2019 , 2018 , and 2017 is reflected net of tax provision of approximately $ 1.0 million , $ 0.7 million and $ 2.5 million , respectively. +See accompanying notes to consolidated financial statements. +34 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Fiscal Year Ended +June 29, 2019 +June 30, 2018 +July 1, 2017 +Operating activities: +Net income (loss) +$ +( 7,982 +) +$ +( 1,325 +) +$ +5,617 +Adjustments to reconcile net income (loss) to cash provided by operating activities: +Goodwill and intangible assets impairment +12,448 +— +— +Depreciation and amortization +7,298 +7,774 +7,232 +Amortization of deferred loan costs +30 +30 +17 +Provision for obsolete inventory +91 +31 +496 +Provision for warranty +83 +74 +68 +Provision for (recovery of) doubtful accounts +58 +( 84 +) +( 10 +) +Loss on disposal of assets +3 +20 +101 +Share-based compensation expense +436 +447 +692 +Deferred income taxes +( 1,116 +) +( 1,562 +) +( 471 +) +Loss on settlement of arbitration +— +( 4,535 +) +— +Changes in operating assets and liabilities +Trade receivables +3,344 +( 12,559 +) +( 5,102 +) +Contract assets +( 10,255 +) +— +— +Cash received from arbitration settlement +6,684 +— +— +Inventories +( 1,417 +) +589 +4,920 +Other assets +( 4,490 +) +( 9,249 +) +( 4,908 +) +Accounts payable +( 2,627 +) +23,320 +( 5,889 +) +Accrued compensation and vacation +( 1,346 +) +( 1,900 +) +434 +Other liabilities +( 323 +) +2,051 +( 913 +) +Cash provided by operating activities +919 +3,122 +2,284 +Investing activities: +Purchases of property and equipment +( 8,386 +) +( 4,523 +) +( 9,307 +) +Proceeds from sale of fixed assets +22 +1,041 +834 +Cash receipts from deferred purchase price of factored receivables +6,455 +8,335 +7,141 +Cash provided by (used in) investing activities +( 1,909 +) +4,853 +( 1,332 +) +Financing activities: +Payment of financing costs +( 15 +) +( 21 +) +( 221 +) +Proceeds from issuance of long term debt +— +— +3,919 +Repayments of long term debt +( 5,871 +) +( 5,871 +) +( 5,435 +) +Borrowings under revolving credit agreement +181,688 +187,419 +161,240 +Repayments of revolving credit agreement +( 174,554 +) +( 189,532 +) +( 160,978 +) +Tax withholding from exercise of share-based compensation +— +— +( 122 +) +Cash provided by (used in) financing activities +1,248 +( 8,005 +) +( 1,597 +) +Net increase (decrease) in cash and cash equivalents +258 +( 30 +) +( 645 +) +Cash and cash equivalents, beginning of period +343 +373 +1,018 +Cash and cash equivalents, end of period +$ +601 +$ +343 +$ +373 +Supplemental cash flow information: +Interest payments +$ +2,773 +$ +2,529 +$ +2,238 +Income tax payments, net of refunds +$ +( 511 +) +$ +304 +$ +1,799 +See accompanying notes to consolidated financial statements. +35 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY +(In thousands) +Shares +Common +Stock +Retained +Earnings +Accumulated +Other +Comprehensive +Income (Loss) +Total +Shareholders’ +Equity +Balances, July 2, 2016 +10,725 +$ +45,227 +$ +67,928 +$ +( 7,573 +) +$ +105,582 +Net income +— +— +5,617 +— +5,617 +Unrealized gain on hedging instruments, net +— +— +— +4,798 +4,798 +Exercise of stock appreciation rights +49 +— +— +— +— +Shares withheld for taxes +( 14 +) +( 122 +) +— +— +( 122 +) +Share-based compensation +— +692 +— +— +692 +Balances, July 1, 2017 +10,760 +$ +45,797 +$ +73,545 +$ +( 2,775 +) +$ +116,567 +Net loss +— +— +( 1,325 +) +— +( 1,325 +) +Tax rate effect reclassification +586 +( 586 +) +— +Unrealized gain on hedging instruments, net +— +— +— +2,392 +2,392 +Share-based compensation +— +447 +— +— +447 +Balances, June 30, 2018 +10,760 +$ +46,244 +$ +72,806 +$ +( 969 +) +$ +118,081 +Net loss +— +— +( 7,982 +) +— +( 7,982 +) +ASC 606 opening balance sheet adjustment +— +— +529 +— +529 +Unrealized gain on hedging instruments, net +— +— +— +3,395 +3,395 +Share-based compensation +— +436 +— +— +436 +Balances, June 29, 2019 +10,760 +$ +46,680 +$ +65,353 +$ +2,426 +$ +114,459 +See accompanying notes to consolidated financial statements. +36 +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. SIGNIFICANT ACCOUNTING POLICIES +Business +Key Tronic Corporation and subsidiaries (the Company) is engaged in electronic manufacturing services (EMS) for original equipment manufacturers (OEMs) and also manufactures keyboards and other input devices. The Company’s headquarters are located in Spokane Valley, Washington with manufacturing operations in Oakdale, Minnesota; Fayetteville, Arkansas; Corinth, Mississippi; and foreign manufacturing operations in Juarez, Mexico; Shanghai, China; and Da Nang, Vietnam. +Principles of Consolidation +The consolidated financial statements include the Company and its wholly owned subsidiaries in the United States, Mexico, China and Vietnam. Intercompany balances and transactions have been eliminated during consolidation. +Use of Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates include the allowance for doubtful receivables, the provision for obsolete and non-saleable inventories, deferred tax assets and liabilities, uncertain tax positions, valuation of goodwill, impairment of long-lived assets, medical self-funded insurance liability, long-term incentive compensation accrual, the provision for warranty costs, the fair value of stock appreciation rights granted under the Company’s share-based compensation plan and purchase price allocation of acquired businesses. Due to uncertainties with respect to the assumptions and estimates, actual results could differ from those estimates. +Cash and Cash Equivalents +The Company considers investments with an original maturity of three months or less to be cash equivalents. Cash equivalents are carried at cost, which approximates fair value. The Company may have cash and cash equivalents at financial institutions that are in excess of federally insured limits from time to time. +Allowance for Doubtful Accounts +The Company evaluates the collectability of accounts receivable and records an allowance for doubtful accounts, which reduces the receivables to an amount that management reasonably estimates will be collected. A specific allowance is recorded against receivables considered to be impaired based on the Company’s knowledge of the financial condition of the customer. In determining the amount of the allowance, the Company considers several factors including the aging of the receivables, the current business environment and historical experience. After all attempts to collect a receivable have failed, the receivable is written off against the allowance. +Inventories +Inventories are stated at the lower of cost or net realizable value. Inventory valuation is determined using the first-in, first-out (FIFO) method. Customer orders are based upon forecasted quantities of product manufactured for shipment over defined periods. Raw material inventories are purchased to fulfill these customer requirements. Within these arrangements, customer demands for products frequently change, sometimes creating excess and obsolete inventories. The Company regularly reviews raw material inventories by customer for both excess and obsolete quantities. Wherever possible, the Company attempts to recover its full cost of excess and obsolete inventories from customers or, in some cases, through other markets. When it is determined that the Company’s carrying cost of such excess and obsolete inventories cannot be recovered in full, a charge is taken against income for the difference between the carrying cost and the estimated realizable amount. We also reserve for inventory related to specific customers covered by lead-time assurance agreements when those customers are experiencing financial difficulties or reimbursement is not reasonably assured. +Property, Plant and Equipment +Property, plant and equipment are carried at cost and depreciated using straight-line methods over the expected useful lives of the assets. Repairs and maintenance costs are expensed as incurred. +37 +Impairment of Goodwill +In accordance with accounting guidance on goodwill and other intangible assets, the Company evaluates goodwill for impairment at the reporting unit level annually, and whenever circumstances occur indicating that goodwill might be impaired. Upon adoption of ASU 2017-04, the Company now recognizes an impairment charge (not to exceed the total amount of goodwill allocated to the reporting unit) for the amount by which the carrying amount of a reporting unit exceeds the reporting unit’s fair value. During the quarter, a few large programs declined in revenue and two new programs were delayed. This decrease in the Company’s total revenue combined with book value continuing to exceed market capitalization caused a “triggering event” in which to perform a quantitative impairment analysis as of March 30, 2019. To estimate the fair value of the Company’s equity, the Company used both a market approach and an income approach, based on a discounted cash flows analysis. As of March 30, 2019, market related factors increased expected required rates of return, which also increased the Company’s discount rate used to project future cash flows. Further, push outs of the Company’s forecasted future cash flows relating to delays in customer orders adversely impacted the Company’s discounted cash flows model. As a result, a lower estimate in the Company’s fair value using these two valuation methods indicated an impairment charge. +During the third quarter of fiscal year 2019, the Company also assessed other finite-lived intangible assets including the Company’s customer relationships and favorable lease agreements due to an indicator of possible impairment being present, as discussed above. As a result of the analysis performed, the Company determined that the carrying value of the customer relationships intangible asset was not recoverable and recorded an impairment for the entire carrying amount during the third quarter of fiscal year 2019. The Company’s analysis did not indicate that any of its other long-lived assets were impaired. Refer to footnote 14 for impairment analysis for goodwill and other intangibles that occurred during fiscal year 2019, as a result of certain triggering events being present. +Impairment of Long-lived Assets +The Company, using its best estimates based on reasonable and supportable assumptions and projections, reviews assets for impairment whenever events or changes in circumstances have indicated that the carrying amount of its assets might not be recoverable. Impaired assets are reported at the lower of cost or fair value. +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. Management reviews the adequacy of this accrual quarterly based on historical analyses and anticipated product returns. +Self-funded Insurance +The Company self-funds its domestic employee health plans. The Company contracts with a separate administrative service company to supervise and administer the programs and act as its representative. The Company reduces its risk under this self-funded platform by purchasing stop-loss insurance coverage for high dollar individual claims. In addition, if the aggregate annual claims amount to more than 125 percent of expected claims for the plan year this insurance will also pay those claims amounts exceeding that level. +The Company estimates its exposure for claims incurred but not paid at the end of each reporting period and uses historical claims data supplied by the Company’s broker to estimate its self-funded insurance liability. This liability is subject to a total limitation that varies based on employee enrollment and factors that are established at each annual contract renewal. Actual claims experience may differ from the Company’s estimates. Costs related to the administration of the plan and related claims are expensed as incurred. +38 +Revenue Recognition +Prior to the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606), sales revenue from manufacturing is recognized upon shipment of the manufactured product per contractual terms. Upon shipment, title transfers and the customer assumes risks and rewards of ownership of the product. The price to the buyer is fixed or determinable and recoverability is reasonably assured. Unless specifically stated in contractual terms, there are no formal customer acceptance requirements or further obligations related to the manufacturing services; if any such requirements exist, then sales revenue is recognized at the time when such requirements are completed and such obligations are fulfilled. Revenue is recorded net of estimated returns of manufactured product based on management’s analysis of historical returns. +Subsequent to the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606) during the year ended June 29, 2019, the first step in its process for revenue recognition is to identify the contract with a customer. A contract is defined as an agreement between two or more parties that creates enforceable rights and obligations. A contract can be written, oral, or implied. The Company generally enters into manufacturing service agreements (“MSA”) with its customers that outlines the terms of the business relationship between the customer and the Company. This includes matters such as warranty, indemnification, transfer of title and risk of loss, liability for excess and obsolete inventory, pricing, payment terms, etc. The Company will also bid on a program-by-program basis for customers in which an executed MSA may not be in place. In these instances, as well as when we have an MSA in place, we receive customer purchase orders for specific quantities and timing of products. As a result, the Company considers its contract with a customer to be the combination of the MSA and the purchase order. The transaction price is fixed and set forth in each purchase order. In the Company's normal course of business, there are no variable pricing components, or material amounts refunded to customers in the form of refunds or rebates. +The Company assesses whether control of the product or services promised under the contract is transferred to the customer at a point in time (shipment) or over time (as we manufacture the product). The Company is first required to evaluate whether its contracts meet the criteria for 'over-time' or 'point-in-time' recognition. The Company has determined that for the majority of its contracts the Company is manufacturing products for which there is no alternative use due to the unique nature of the customer-specific product, IP and other contract restrictions. The Company has an enforceable right to payment including a reasonable profit for performance completed to date with respect to these contracts. As a result, revenue is recognized under these contracts 'over-time' based on the input cost-to-cost method as it better depicts the transfer of control. This input method is based on the ratio of costs incurred to date as compared to the total estimated costs at completion of the performance obligation. For all other contracts that do not meet these criteria, such as manufacturing contracts for which the terms do not provide an enforceable right to payment for performance completed to date, the Company recognizes revenue when it has transferred control of the related manufactured products which generally occurs upon shipment to the customer. Revenue from engineering services is recognized over time as the services are performed. +Shipping and Handling Fees +The Company classifies costs associated with shipping and handling fees as a component of cost of goods sold. Customer billings related to shipping and handling fees are reported as revenue. +Research, Development and Engineering +Research, development and engineering expenses include unreimbursed EMS costs as well as design and engineering costs associated with the production of EMS programs. Research, development and engineering costs are expensed as incurred. +Income Taxes +Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the estimated future tax consequences and benefits attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities for a change in tax rates is recognized in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amount that is more likely than not to be realized. +39 +We utilize a two-step approach to recognizing and measuring uncertain tax positions. The first step is to evaluate the tax position for recognition by determining if the weight of available evidence indicates it is more likely than not that the position will be sustained on audit, including resolution of related appeals or litigation processes, if any. The second step is to measure the tax benefit as the largest amount which is more than 50 % likely of being realized upon ultimate settlement. We consider many factors when evaluating and estimating our tax positions and tax benefits, which may require periodic adjustments based on new assessments and changes in estimates and which may not accurately forecast actual outcomes. Our policy is to recognize interest and penalties related to the underpayment of income taxes as a component of income tax provision. To date, we have not incurred charges for interest or penalties in relation to the underpayment of income taxes. The tax years 1997 through the present remain open to examination by the major U.S. taxing jurisdictions to which we are subject. Refer to Note 6 for further discussions. +Derivative Instruments and Hedging Activities +The Company has entered into foreign currency forward contracts and an interest rate swap which are accounted for as cash flow hedges in accordance with ASC 815, Derivatives and Hedging . The effective portion of the gain or loss on the derivative is reported as a component of accumulated other comprehensive income (AOCI) and is reclassified into earnings in the same period in which the underlying hedged transaction affects earnings. The derivative’s effectiveness represents the change in fair value of the hedge that offsets the change in fair value of the hedged item. +The Company uses derivatives to manage the variability of foreign currency fluctuations of expenses in our Mexico facilities. The foreign currency forward contracts and interest rate swaps have terms that are matched to the underlying transactions being hedged. As a result, these transactions fully offset the hedged risk and no ineffectiveness has been recorded. +The Company’s foreign currency forward contracts and interest rate swaps potentially expose the Company to credit risk to the extent the counterparties may be unable to meet the terms of the agreement. The Company minimizes such risk by seeking high quality counterparties. The Company’s counterparties to the foreign currency forward contracts and interest rate swaps are major banking institutions. These institutions do not require collateral for the contracts, and the Company believes that the risk of the counterparties failing to meet their contractual obligations is remote. The Company does not enter into derivative instruments for trading or speculative purposes. +Earnings Per Common Share +Basic earnings per common share is computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is computed by dividing net income by the combination of other potentially dilutive weighted average common shares and the weighted average number of common shares outstanding during the period using the treasury stock method. The computation assumes the proceeds from the exercise of stock options were used to repurchase common shares at the average market price during the period. The computation of diluted earnings per common share does not assume conversion, exercise, or contingent issuance of common stock equivalent shares that would have an anti-dilutive effect on earnings per share. +Foreign Currency Transactions +The functional currency of the Company’s subsidiaries in Mexico and China is the U.S. dollar. Realized foreign currency transaction gains and losses for local currency denominated assets and liabilities are included in cost of goods sold. +Fair Value of Financial Instruments +The carrying values of cash and cash equivalents, accounts receivable and current liabilities reflected on the balance sheets at June 29, 2019 and June 30, 2018 , reasonably approximate their fair value. The Company had an outstanding balance on the line of credit of $ 23.4 million as of June 29, 2019 and $ 16.2 million as of June 30, 2018 , with a carrying value that reasonably approximates the fair value. The Company had an outstanding balance on the term loan of $ 11.3 million as of June 29, 2019 and $ 16.3 million as of June 30, 2018 , with a carrying value that reasonably approximates the fair value. The equipment term loan is estimated to be $ 1.7 million as of June 29, 2019 and $ 2.6 million as of June 30, 2018 , with a carrying value that reasonably approximates the fair value. +Share-based Compensation +The Company’s incentive plan may provide for equity and liability awards to employees in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, stock units, performance shares, performance units, and other stock-based or cash-based awards. Compensation cost is recognized on a straight-line basis over the requisite employee service period, which is generally the vesting period, and is included in cost of goods sold, research, development and engineering, and selling, general, and administrative expenses. Share-based compensation is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on historical experience and future expectations. +40 +Newly Adopted and Recent Accounting Pronouncements +In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update 2014-09 (ASU 2014-09), Revenue from Contracts with Customers (Topic 606) (also referred to as Accounting Standard Codification 606 (“ASC 606”). The standard’s core principle is that a company will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. In doing so, companies will need to use more judgment and make more estimates than under current guidance. This may include identifying performance obligations in the contract, estimating the amount of variable consideration to include in the transaction price and allocating the transaction price to each separate performance obligation. Additionally, disclosures required for revenue recognition will include qualitative and quantitative information about contracts with customers, significant judgments and changes in judgments, and assets recognized from costs to obtain or fulfill a contract. Such disclosures are more extensive than what is required under existing GAAP. The Company adopted the standard on July 1, 2018 using the modified retrospective approach by applying the guidance to all open contracts at the adoption date and has implemented revised accounting policies, new operational and financial reporting processes, enhanced systems capabilities and relevant internal controls. As part of adopting ASC 606, revenue for certain customer contracts where the Company is manufacturing products for which there is no alternative use and the Company has an enforceable right to payment including a reasonable profit for work-in-progress inventory will be recognized over time instead of upon shipment of products. In addition to the following disclosures, footnote 15 provides further disclosures required by the new standard. +41 +The cumulative effect of change made to our July 1, 2018 consolidated balance sheet for the adoption of ASC 606 was as follows: +Consolidated Balance Sheet +Impact of Adopting ASC 606 +(Unaudited, in thousands) +Balance at June 30, 2018 +Adjustments +Balance at July 1, 2018 +ASSETS +Contract assets +— +11,906 +11,906 +Inventories +110,315 +( 11,210 +) +99,105 +Deferred income tax asset +7,882 +( 167 +) +7,715 +LIABILITIES AND SHAREHOLDERS’ EQUITY +Retained earnings +72,806 +529 +73,335 +The following tables summarize the impacts of ASC 606 adoption on the Company’s consolidated balance sheets and consolidated statements of income (loss): +Consolidated Balance Sheet +As of June 29, 2019 +Impact of Adopting ASC 606 +(Unaudited, in thousands) +As Reported +606 Adjustment +Balance without 606 Adoption +ASSETS +Contract assets +22,161 +( 22,161 +) +— +Inventories +100,431 +19,563 +119,994 +Deferred income tax asset +7,840 +167 +8,007 +LIABILITIES AND SHAREHOLDERS’ EQUITY +Retained earnings +65,353 +2,431 +62,922 +Consolidated Statement of Income (Loss) +Impact of Adopting ASC 606 +(Unaudited, in thousands) +Twelve Months Ended June 29, 2019 +As Reported +606 Adjustment +Balance without 606 Adoption +Net sales +$ +464,044 +$ +10,254 +$ +453,790 +Cost of sales +429,443 +8,353 +421,090 +Gross profit +34,601 +1,901 +32,700 +Net income +$ +( 7,982 +) +$ +1,901 +$ +( 9,883 +) +For the fiscal year ended June 29, 2019, the reported revenue and gross profit was approximately $ 464.0 million , and $ 34.6 million ; respectively. This reflects the adoption of ASC 606 as revenue and gross profit would have been $ 10.3 million and $ 1.9 million less without ASC 606 adoption; respectively. This is primarily due to the change from 'point-in-time' to 'over-time' recognition as the standard requires. There was not a material tax impact for the twelve months ended June 29, 2019 from adopting ASC 606. +The Company applies the following practical expedients: +The Company elected to not disclose information about remaining performance obligations as its performance obligations generally have an expected durations of one year or less. +42 +In February 2016, the FASB issued Accounting Standards Update 2016-02, Leases which supersedes ASC 840 Leases and creates a new topic, ASC 842 Leases. This update requires lessees to recognize a lease asset and a lease liability for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. This update will be applied using a modified retrospective transition approach for leases existing at, or entered into after, June 30, 2019. In July 2018, the FASB issued Accounting Standards Update 2018-10, Codification Improvements to Topic 842, Leases. The update is intended to clarify certain aspects of the new leases standard, Topic 842. The amendments affect narrow aspects of the guidance issued in update 2016-02 discussed above. The amendments address residual value guarantees, the rate implicit in the lease, certain lessee and lessor reassessments, variable lease payments that depend on an index or rate, investment tax credits, lease term and purchase option, transition guidance and certain adjustments, impairment of the net investment in the lease, residual assets that are not guaranteed, as well as other areas of improvement and clarification. The amendments have the same effective date and transition requirements as the new leases standard. The Company intends to adopt the new lease guidance when it becomes effective in the first quarter of fiscal year 2020. +The Company is continuing to assess the impact of adopting the new standard on its consolidated financial statements, as well as its process to determine the actual amount of the required transition adjustment to reflect the balance of the right of use asset and lease liability. These conclusions may change as the Company continues its evaluation. ASC 842 provides a number of optional practical expedients impacting transition to the new standard. Management elected the package of practical expedients which, among other things, allows the Company to carry forward historical lease classification in place prior to June 30, 2019. ASC 842 also provides practical expedients for an entity’s accounting after transition. Management has elected the short-term lease recognition exemption for all leases that qualify, as well as the practical expedient to not separate lease and non-lease components. Both of these expedients were elected for all classes of underlying leased assets. The Company is also continuing to adjust its accounting policies, operational and financial reporting processes, systems capabilities and relevant internal controls. +In August 2016, the FASB issued Accounting Standards Update 2016-15, Classification of Certain Cash Receipts and Cash Payments. The update is intended to provide guidance on how certain cash receipts and payments are presented and classified in the statement of cash flows. Under the guidance, cash receipts from the deferred purchase price of the Company's factored receivables will be classified as cash flows from investing activities instead of the Company's former presentation as cash flows from operations. The Company adopted the guidance during the first quarter of fiscal year 2019 and retrospectively adjusted cash flows from operating and investing activities for the fiscal year ended June 29, 2019 and June 30, 2018 ; respectively. Upon adoption of the standard, the Company recorded $ 6.5 million of cash receipts on the deferred purchase price from receivables factored by the Company during the fiscal year ended June 29, 2019 , and reclassified $ 8.3 million of cash receipts on the deferred purchase price from receivables factored by the Company for the fiscal year ended June 30, 2018 , from cash flows from operating activities to cash flows from investing activities. +In January 2017, the FASB issued Accounting Standards Update 2017-04, Simplifying the Test for Goodwill Impairment. Under the new standard, goodwill impairment would be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying value of goodwill. This ASU eliminates existing guidance that requires an entity to determine goodwill impairment by calculating the implied fair value of goodwill by hypothetically assigning the fair value of a reporting unit to all of its assets and liabilities as if that reporting unit had been acquired in a business combination. This update is effective prospectively to impairment tests beginning January 1, 2020, with early adoption permitted. The Company chose to early adopt the new guidance during the third quarter of fiscal year 2019. +In May 2017, the FASB issued Accounting Standards Update 2017-09, Compensation - Stock Compensation. This update provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. The Company adopted the new guidance during the first quarter of fiscal year 2019 and the result had an immaterial impact on its consolidated financial statements. +In August 2017, the FASB issued Accounting Standards Update 2017-12, Derivatives and Hedging, which amends the hedge accounting recognition and presentation requirements in ASC 815. The Board’s objectives in issuing this update are to (1) improve the transparency and understandability of information about an entity’s risk management activities by better aligning the entity’s financial reporting for hedging relationships with those risk management activities and (2) simplify the application of hedge accounting. This update is effective for fiscal years beginning after December 15, 2018. Early adoption is permitted. The Company is currently evaluating the effect of this update on its consolidated financial statements. The Company expects the new guidance will have an immaterial impact on its consolidated financial statements, and it intends to adopt the guidance when it becomes effective in the first quarter of fiscal year 2020. +In January 2018, the FASB released guidance on the accounting for tax on the Global Intangible Low-Taxed Income (“GILTI”) provisions of the Tax Act. The GILTI provisions impose a tax on foreign income in excess of a deemed return on tangible assets of foreign corporations. The Company elects to treat any potential GILTI inclusions as a period cost. +43 +In June 2018, the FASB issued ASU 2018-07 "Compensation - Stock Compensation (Topic 718): Improvement to Nonemployee Share-Based Payment Accounting" with the objective of simplifying several aspects of the accounting for nonemployee share-based payment transactions in current GAAP. The guidance is effective for the Company beginning in the first quarter of fiscal year 2020 with early adoption permitted. The Company expects the new guidance will not have a material impact on its consolidated financial statements, and it intends to adopt the guidance when it becomes effective in the first quarter of fiscal year 2020. +In August 2018, the FASB issued ASU 2018-13, "Fair Value Measurement (Topic 820): Disclosure Framework Changes to the Disclosure Requirements for Fair Value Measurement”, which amends ASC 820 to add, remove, and modify fair value measurement disclosure requirements. The guidance is effective for the Company beginning in the first quarter of fiscal year 2020 with early adoption permitted. The Company expects the new guidance will not have a material impact on its consolidated financial statements, and it intends to adopt the guidance when it becomes effective in the first quarter of fiscal year 2020. +Fiscal Year +The Company operates on a 52/53 week fiscal year. Fiscal years end on the Saturday nearest June 30. As such, fiscal years 2019 , 2018 , and 2017 , ended on June 29, 2019 , June 30, 2018 , and July 1, 2017 , respectively. Fiscal year 2019, 2018 and 2017 were all 52 week years. +2. INVENTORIES +The components of inventories consist of the following (in thousands): +June 29, 2019 +June 30, 2018 +Finished goods +$ +76,757 +$ +14,927 +Work-in-process +11,705 +22,254 +Raw materials and supplies +11,969 +73,134 +$ +100,431 +$ +110,315 +As a result of the adoption of ASC 606, amounts that would have been reported as inventory under prior guidance are now included in contract assets on the Consolidated Balance Sheet as disclosed in footnote 1. As a result of this accounting change, finished goods as of June 29, 2019 are $ 10.0 million less than they would have been had we not adopted ASC 606 and work-in-process inventory as of June 29, 2019 is $ 9.6 million less than they would have been had we not adopted ASC 606. The comparative information as of June 30, 2018 , has not been restated and continues to be reported under the accounting standards in effect at that time. +44 +3. PROPERTY, PLANT AND EQUIPMENT +Property, plant and equipment consists of the following: +Life +June 29, 2019 +June 30, 2018 +(in years) +(in thousands) +Land +— +$ +2,940 +$ +2,940 +Buildings and improvements +3 to 30 +23,776 +23,441 +Equipment +1 to 10 +67,348 +60,367 +Furniture and fixtures +3 to 5 +4,248 +3,754 +Total Property, Plant and Equipment +98,312 +90,502 +Accumulated depreciation +( 68,899 +) +( 62,954 +) +Property, Plant and Equipment, net +$ +29,413 +$ +27,548 +45 +4. LONG-TERM DEBT +On September 30, 2018, the Company entered into a Fourth amendment to the amended and restated credit agreement to extend the maturity date to August 31, 2021 on the term loan in the amount of $ 35.0 million that was used to acquire all of the outstanding shares of CDR Manufacturing, Inc. (dba Ayrshire Electronics). The term loan requires quarterly payments of $ 1.25 million through June 15, 2021, with a final payment of the remaining outstanding balance on August 31, 2021. The Company had an outstanding balance of $ 11.3 million and $ 16.3 million under the term loan as of June 29, 2019 and June 30, 2018 , respectively. +On August 6, 2015, the Company entered into a First Amendment to the amended and restated credit agreement extending the limit on our line of credit facility to $ 45.0 million as evidenced by the Second Replacement Revolving Note. The agreement specifies that the proceeds of the revolving line of credit be used primarily for working capital and general corporate purposes. The line of credit is secured by substantially all of the assets of the Company. On September 30, 2018, the Company entered into a Fourth amendment to the amended and restated credit agreement to extend the maturity date to November 1, 2023, at which time all outstanding balances are payable. As of June 29, 2019 , the Company had an outstanding balance under the credit facility of $ 23.4 million , $ 0.4 million in outstanding letters of credit and $ 21.3 million available for future borrowings. As of June 30, 2018 , the Company had an outstanding balance under the credit facility of $ 16.2 million , $ 0.4 million in outstanding letters of credit and $ 28.4 million available for future borrowings. +On December 28, 2016, the Company entered into an equipment term loan agreement in the amount of $ 3.9 million in order to further invest in production equipment. The equipment term loan is collateralized by production equipment. Under this loan agreement, equal quarterly payments of approximately $ 0.2 million commenced on March 31, 2017 and will continue through the maturity of the equipment term loan on June 30, 2021. Amortization of the debt issuance costs is reported as interest expense on the consolidated income statement. As of June 29, 2019 , the Company had an outstanding balance of $ 1.7 million . As of June 30, 2018 , the Company had an outstanding balance of $ 2.6 million . +Borrowings under the revolving line of credit, term loan and equipment term loan bear interest at either a “Base Rate” or a “Fixed Rate,” as elected by the Company. The base rate is the higher of the Wells Fargo Bank prime rate, daily one month London Interbank Offered Rate (LIBOR) plus 1.5 % , or the Federal Funds rate plus 1.5 % . The fixed rate is LIBOR plus 1.75 % , LIBOR plus 2.0 % or LIBOR plus 2.25 % depending on the level of the Company’s trailing four quarters Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA). The interest rates on the outstanding debt as of June 29, 2019 range from 4.40 % - 5.50 % compared to 4.09 % - 5.00 % as of June 30, 2018 . +Debt maturities as of June 29, 2019 for the next three years are as follows (in thousands): +Fiscal Years Ending +Amount +2020 +$ +5,871 +2021 +5,871 +2022 +1,250 +2023 +— +2024 +23,356 +Total debt +$ +36,348 +Unamortized debt issuance costs +$ +( 60 +) +Long-term debt, net of debt issuance costs +$ +36,288 +The Company must comply with certain financial covenants, including a cash flow leverage ratio, an asset coverage ratio and a fixed charge coverage ratio. The credit agreement requires the Company to maintain a minimum profit threshold, limits the maximum capital lease expenditures and restricts the Company from declaring or paying dividends in cash or stock without prior bank approval. The Company was in compliance with all financial covenants as of June 29, 2019. +46 +5. TRADE ACCOUNTS RECEIVABLE PURCHASE PROGRAMS +Sale Programs +The Company utilizes an Account Purchase Agreement with Wells Fargo Bank, N.A. ("WFB") which allows the Company to sell and assign to WFB and WFB may purchase from Company the accounts receivable of certain Company customers in a maximum aggregate amount outstanding of $ 25.0 million . This agreement may be cancelled at any time by either party. The Company also has an Account Purchase Agreement with Orbian Financial Services (“Orbian”). This agreement allows the Company to sell accounts receivable of certain customers to Orbian and the agreement may be cancelled at any time by either party. +Total accounts receivables sold during the twelve months ended June 29, 2019 and June 30, 2018 was approximately $ 81.0 million and $ 104.7 million , respectively. Accounts receivables sold and not yet collected was approximately $ 1.7 million and $ 2.0 million as of June 29, 2019 and June 30, 2018 , respectively. The receivables that were sold were removed from the consolidated balance sheets and the cash received is reflected as cash provided by operating activities in the consolidated statements of cash flows. +6. INCOME TAXES +Income tax provision consists of the following: +Fiscal Year Ended +June 29, 2019 +June 30, 2018 +July 1, 2017 +(in thousands) +Current income tax provision (benefit): +United States +$ +( 537 +) +$ +( 221 +) +$ +1,231 +Foreign +895 +1,722 +1,206 +358 +1,501 +2,437 +Deferred income tax provision (benefit): +United States +( 910 +) +( 795 +) +( 539 +) +Foreign +( 206 +) +( 823 +) +( 259 +) +( 1,116 +) +( 1,618 +) +( 798 +) +Total income tax provision (benefit) +$ +( 758 +) +$ +( 117 +) +$ +1,639 +The Company has gross tax credit carryforwards of approximately $ 9.1 million at June 29, 2019 . Included in total tax credits carryforwards is approximately $ 9.0 million in research and development (R&D) tax credits. +Management has reviewed all deferred tax assets for purposes of determining whether or not a valuation allowance may be required. A valuation allowance against deferred tax assets is required if it is more likely than not that some of the deferred tax assets will not be realized. Based upon the Company’s profitability, forecasted income, and evaluation of all other positive and negative evidence, management determined that it is more likely than not that the deferred tax assets will be realized. +On December 22, 2017, the Tax Cuts and Jobs Act (“Tax Act”) was signed into law. The Tax Act reduced Federal corporate tax rates effective January 1, 2018, and changed certain other provisions, many of which were not effective until fiscal year 2019. Effective tax rates for fiscal year 2018, were blended rates reflecting the benefit of two quarters of Federal tax rate reductions. These benefits were offset by discrete expenses relating to the revaluation of our U.S. net deferred tax assets, an adjustment relating to foreign exchange, and required adjustments associated with the transition from a global to a territorial tax system (discussed further below). +As a result of the U.S. tax system under the Tax Act from a global to a territorial model, a deemed one-time repatriation of all accumulated earnings and profits (AE&P) in Mexico and China occurred on December 31, 2017. For purposes of calculating the toll tax associated with this deemed repatriation, AE&P pools are stratified into two asset categories, subjected to certain allowable deductions and then the net amounts were subjected to the toll tax ( 15.5 % for cash/cash equivalents and 8 % for illiquid assets). +47 +On December 22, 2017, the staff of the SEC issued Staff Accounting Bulletin No. 118 (“SAB No. 118”). SAB No. 118 provided guidance on accounting for the tax effects of the 2017 Tax Act and allowed registrants to record provisional amounts for a period of up to one year from the date of enactment of the 2017 Tax Act. In fiscal year 2019, we finalized the toll tax calculation, resulting in a net toll tax amount of $ 0.8 million , a decrease of $ 0.4 million for the fiscal year. +In addition to the $ 0.8 million toll tax described above, the Company recognized a $ 1.3 million discrete expense in fiscal year 2018 due to the revaluation of our U.S. net deferred tax assets. Offsetting these amounts, because of the shift to a territorial system of taxation in the U.S., the Company recognized a discrete benefit of approximately $ 1.3 million related to reversing its previously recognized estimated liability associated with estimated future repatriations from Mexico and China. +In future years, because of the toll tax on AE&P described above, repatriations of cash will generally be tax-free in the U.S. However, withholding taxes in China and Mexico may still apply to any such future repatriations. Management has not changed its indefinite investment assertions with regards to the portion of AE&P in China that may be repatriated in the future. Accordingly, management estimates that future repatriations of cash from China may result in approximately $ 0.8 million of withholding tax. There would be no offsetting foreign tax credits in the U.S. and as such, this potential liability is a direct cost associated with actual repatriations. +Under Mexican tax law, any previously taxed earnings from before 2014 (“CUFIN”) are not subject to withholding when monies are repatriated to another country. In the second quarter of fiscal year 2019, the U.S. parent company received a distribution of the remaining CUFIN amount. As such, future distributions from Mexico will be subject to withholding tax. The currently remaining earnings in Mexico are permanently reinvested; therefore, no withholding tax liability has been recognized as of June 29, 2019. If, in the future, repatriations from Mexico are expected, the Company could be required to recognize a withholding tax as a deferred tax liability at that time. Similar to China, this withholding would not be creditable and would be a direct cost associated with the actual repatriation. +The Company expects to repatriate a portion of its foreign earnings based on increased net sales growth driving additional capital requirements domestically, cash requirements for potential acquisitions and to implement certain tax strategies. The Company expects to repatriate approximately $ 7.8 million from China, in the future. All other unremitted foreign earnings are expected to remain permanently reinvested for planned fixed assets purchases and improvements in foreign locations. +During the second quarter of fiscal year 2017, the Company signed a unilateral advance pricing agreement (APA) with the Large Taxpayer Division of Mexico’s Servicio de Administración Tributaria (SAT) under an elective framework that has been agreed to by the U.S. and Mexican authorities. The APA is part of a larger program affecting hundreds of U.S. companies with maquiladora operations in Mexico. The general impact of the APA is to increase margins between the maquiladora and U.S. parent company, shifting profits to Mexico from the U.S. The APA was finalized during the fourth quarter of fiscal 2017; the overall impact to the financial statements was not material. +The Company’s effective tax rate differs from the federal tax rate as follows: +Fiscal Year Ended +June 29, 2019 +June 30, 2018 +July 1, 2017 +(in thousands) +Federal income tax provision at statutory rates +$ +( 1,836 +) +$ +( 397 +) +$ +2,467 +State income taxes, net of federal tax effect +( 158 +) +( 4 +) +175 +Foreign tax rate differences +251 +103 +( 156 +) +Tax rate change +— +1,634 +— +Provisional transition tax on accumulated foreign earnings +( 384 +) +1,190 +— +Effect of income tax credits +( 861 +) +( 687 +) +( 738 +) +Effect of repatriation of foreign earnings, net +( 42 +) +( 1,484 +) +199 +Goodwill write-off +1,726 +— +— +Global Intangible Low-Taxed Income (GILTI) tax +150 +— +— +Provision to return reconciliation +630 +( 401 +) +8 +Other +( 234 +) +( 71 +) +( 316 +) +Income tax provision (benefit) +$ +( 758 +) +$ +( 117 +) +$ +1,639 +48 +The domestic and foreign components of income (loss) before income taxes were: +Fiscal Year Ended +June 29, 2019 +June 30, 2018 +July 1, 2017 +(in thousands) +Domestic +$ +( 12,220 +) +$ +( 4,593 +) +$ +3,553 +Foreign +3,480 +3,151 +3,703 +Income (loss) before income taxes +$ +( 8,740 +) +$ +( 1,442 +) +$ +7,256 +Deferred income tax assets and liabilities consist of the following at: +June 29, 2019 +June 30, 2018 +(in thousands) +Deferred tax assets: +Net operating loss +$ +33 +$ +— +Tax credit carryforwards, net +$ +4,986 +$ +3,946 +Inventory +1,087 +667 +Identifiable intangibles +407 +— +Interest expense carryforward +474 +— +Accruals +3,549 +3,830 +Research and development expenses +232 +— +Mark-to-market adjustments +— +247 +Arbitration settlement +— +1,100 +Other +30 +33 +Deferred income tax assets +$ +10,798 +$ +9,823 +Deferred tax liabilities: +Accrued withholding tax - unremitted earnings +( 820 +) +( 822 +) +Fixed assets +( 443 +) +( 289 +) +Mart-to-market adjustments +( 730 +) +— +Deferred revenue +( 790 +) +— +Identifiable intangibles +— +( 670 +) +Other +( 175 +) +( 160 +) +Deferred income tax liabilities +$ +( 2,958 +) +$ +( 1,941 +) +Net deferred income tax assets +$ +7,840 +$ +7,882 +Balance sheet caption reported in: +Long-term deferred income tax asset +$ +7,840 +$ +7,882 +Net deferred income tax asset +$ +7,840 +$ +7,882 +49 +Uncertain Tax Positions: +The Company has R&D tax credits that approximate $ 9.0 million that have 20 year carryforwards before expiring. The Company’s R&D tax credits expire in various fiscal years from 2025 to 2039. The Company also has alternative minimum tax credits, which do not expire, approximating $ 726,000 , which are now classified as a receivable due to the repeal of the alternative minimum tax. +As of June 29, 2019 , the Company had unrecognized tax benefits of $ 4.1 million related to its gross R&D tax credits. The unrecognized tax benefits relate to certain R&D tax credits generated from 1997 to 2019. +A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: +Fiscal Year Ended +June 29, 2019 +June 30, 2018 +July 1, 2017 +(in thousands) +Beginning Balance +$ +4,011 +$ +3,947 +$ +3,760 +Additions based on tax positions related to the current year +88 +64 +187 +Ending Balance +$ +4,099 +$ +4,011 +$ +3,947 +The increase from the prior year is due to additional R&D credits that were recorded in 2019 as discussed above. Management does not anticipate any material changes to this amount during the next 12 months. +The Company recognizes interest accrued related to unrecognized tax benefits and penalties in its income tax provision. The Company has not recognized any interest or penalties in the fiscal years presented in these financial statements. The Company is subject to income tax in the U.S. federal jurisdiction, various state jurisdictions, Mexico and China. Certain years remain subject to examination but there are currently no ongoing exams in any taxing jurisdictions. +7. EARNINGS PER SHARE +Basic earnings per share (EPS) is calculated by dividing net income (the numerator) by the weighted-average number of common shares outstanding (the denominator) during the period. Diluted EPS is computed by including both the weighted-average number of shares outstanding and any dilutive common share equivalents in the denominator. The following table presents a reconciliation of the denominator and the number of antidilutive common share awards that were not included in the diluted earnings per share calculation. These antidilutive securities occur when equity awards outstanding have an option price greater than the average market price for the period: +Fiscal Year Ended +(in thousands, except per share information) +June 29, 2019 +June 30, 2018 +July 1, 2017 +Net income (loss) +$ +( 7,982 +) +$ +( 1,325 +) +$ +5,617 +Weighted average shares outstanding– basic +10,760 +10,760 +10,756 +Effect of dilutive common stock awards +— +— +161 +Weighted average shares outstanding – diluted +10,760 +10,760 +10,917 +Net income (loss) per share – basic +$ +( 0.74 +) +$ +( 0.12 +) +$ +0.52 +Net income (loss) per share – diluted +$ +( 0.74 +) +$ +( 0.12 +) +$ +0.51 +Antidilutive SARs not included in diluted earnings per share +985 +827 +892 +50 +8. STOCK OPTION AND BENEFIT PLANS +The Company’s incentive plan provides for equity and liability awards to employees and non-employee directors in the form of stock options, stock appreciation rights (SARs), restricted stock, restricted stock units, stock awards, stock units, performance shares, performance units, and other stock-based or cash-based awards. Compensation cost is recognized on a straight-line basis over the requisite employee service period, which is generally the vesting period, and is recorded as employee compensation expense in cost of goods sold, research, development and engineering, and selling, general and administrative expenses. Share-based compensation is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on historical experience and future expectations. +In addition to service conditions, these SARs contain a performance condition. The additional performance condition is based upon the achievement of Return on Invested Capital (ROIC) goals relative to a peer group. All awards with performance conditions are measured over the vesting period and are charged to compensation expense over the requisite service period based on the number of shares expected to vest. The SARs cliff vest after a three-year period from date of grant and expire five years from date of grant. +On July 27, 2018, the Company granted 161,250 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $ 8.17 and a grant date fair value of $ 2.27 , as of June 29, 2019 , 141,250 remain outstanding. The grant date fair value for the awards granted during fiscal year 2019, were estimated using the Black Scholes option valuation method with the following weighted average assumptions as of July 27, 2018: +Fiscal Year 2019 +July 27, 2018 +Expected dividend yield +— % +Risk – free interest rate +2.80 % +Expected volatility +29.75 % +Expected life +4.00 +On July 28, 2017, the Company granted 272,500 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $ 7.26 and a grant date fair value of $ 1.89 , as of June 29, 2019 , 227,500 remain outstanding. The grant date fair value for the awards granted during fiscal year 2018, were estimated using the Black Scholes option valuation method with the following weighted average assumptions as of July 28, 2017: +Fiscal Year 2018 +July 28, 2017 +Expected dividend yield +— % +Risk – free interest rate +1.70 % +Expected volatility +29.76 % +Expected life +4.00 +On October 28, 2016, the Company granted 10,000 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $ 8.04 and a grant date fair value of $ 2.30 , as of June 29, 2019 , 10,000 remain outstanding. The grant date fair value for the awards granted during fiscal year 2017, were estimated using the Black Scholes option valuation method with the following weighted average assumptions as of October 28, 2016: +Fiscal Year 2017 +October 28, 2016 +Expected dividend yield +— % +Risk – free interest rate +1.63 % +Expected volatility +33.43 % +Expected life +4.00 +51 +On July 26, 2016, the Company granted 242,500 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $ 8.18 and a grant date fair value of $ 2.42 , as of June 29, 2019 , 207,500 remain outstanding. The grant date fair value for the awards granted during fiscal year 2017, were estimated using the Black Scholes option valuation method with the following weighted average assumptions as of July 26, 2016: +Fiscal Year 2017 +July 26, 2016 +Expected dividend yield +— % +Risk – free interest rate +0.93 % +Expected volatility +36.13 % +Expected life +4.00 +Subsequent to June 29, 2019 , the Company granted 160,000 SARs with a strike price of $ 4.98 and a grant date fair value of $ 1.24 . +Share-based compensation expense is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on the Company’s historical experience and future expectations. This forfeiture rate will be revised, if necessary, in subsequent periods if actual forfeitures differ from the amount estimated. Share-based compensation expense for fiscal years ended June 29, 2019 , June 30, 2018 and July 1, 2017 was $ 0.4 million , $ 0.4 million and $ 0.7 million , respectively. +The Black-Scholes option valuation model is used by the Company for estimating the fair value of SARs. Option valuation models require the input of highly subjective assumptions, particularly for the expected term and expected stock price volatility. Changes in these assumptions can materially affect the fair value estimates. +There were no SARs exercised during fiscal year 2019 or 2018. The intrinsic value for SARs exercised in fiscal year 2017 was $ 0.4 million . +As of June 29, 2019 , total unrecognized compensation expense related to nonvested share-based compensation arrangements was approximately $ 0.4 million . This expense is expected to be recognized over a weighted-average period of 1.62 years . +52 +The following table summarizes the Company’s Options and SARs activity for all plans from July 2, 2016 through June 29, 2019 : +SARs +Available +For Grant +SARs +Outstanding +Aggregate +Intrinsic +Value (in +thousands) +Weighted +Average +Exercise +Price +Weighted +Average +Remaining +Contractual +Life (in +years) +Balances, July 2, 2016 +634,669 +971,665 +$ +339 +$ +8.75 +2.4 +Shares authorized +— +— +SARs granted +( 252,500 +) +252,500 +8.17 +SARs forfeited +12,166 +( 12,166 +) +8.60 +SARs exercised +— +( 127,000 +) +385 +4.77 +Balances, July 1, 2017 +394,335 +1,084,999 +$ +— +$ +9.09 +2.3 +Shares authorized +— +— +SARs granted +( 272,500 +) +272,500 +7.26 +SARs forfeited +282,500 +( 282,500 +) +7.84 +SARs exercised +— +— +— +— +Balances, June 30, 2018 +404,335 +1,074,999 +$ +79 +$ +8.90 +2.3 +Shares authorized +— +— +SARs granted +( 161,250 +) +161,250 +8.17 +SARs forfeited +250,833 +( 250,833 +) +10.59 +SARs exercised +— +— +— +— +Balances, June 29, 2019 +493,918 +985,416 +$ +— +$ +8.35 +3.5 +Exercisable at June 29, 2019 +399,166 +$ +— +$ +9.12 +1.7 +Additional information regarding SARs outstanding and exercisable as of June 29, 2019 , is as follows: +Range of +Exercise Prices +Number Outstanding +Weighted Avg. +Remaining +Contractual Life (yrs.) +Weighted Avg. +Exercise Price +Number +Exercisable +Weighted +Avg. Exercise +Price +$4.40 – $7.90 +227,500 +4.1 +$ +7.26 +— +$ +— +7.91 – 9.91 +554,583 +0.9 +8.09 +195,833 +7.94 +9.92 – 11.34 +203,333 +2.1 +10.26 +203,333 +10.26 +$4.40 to $11.34 +985,416 +3.5 +$ +8.35 +399,166 +$ +9.12 +The Company has defined contribution plans available to U.S. employees who have attained age 21. Company contributions to the plans were approximately $ 0.9 million , $ 0.8 million , and $ 0.6 million during fiscal years 2019 , 2018 and 2017 , respectively. +53 +9. COMMITMENTS AND CONTINGENCIES +Leases : As of June 29, 2019 , June 30, 2018 and July 1, 2017 , the Company did not have any property and equipment financed under capital leases. As of June 29, 2019 , the Company has operating leases for certain equipment and production facilities, which expire at various dates during the next ten years . +Future minimum payments under non-cancelable operating leases at June 29, 2019 , are summarized as follows (in thousands): +Fiscal Years Ending +Operating Leases +2020 +$ +4,777 +2021 +3,563 +2022 +2,641 +2023 +1,866 +2024 +1,271 +Thereafter +4,121 +Total minimum lease payments +$ +18,239 +Rental expense under operating leases was approximately $ 5.0 million , $ 7.1 million , and $ 7.8 million during fiscal years 2019 , 2018 and 2017 , respectively. +Warranty Costs : The Company provides warranties on certain product sales, and allowances for estimated warranty costs are recorded during the period of sale. The determination of such allowances requires the Company to make estimates of product return rates and expected costs to repair or to replace the products under warranty. The Company establishes warranty reserves based on historical warranty costs for each product line combined with liability estimates based on the prior twelve months’ sales activities. As of June 29, 2019 and June 30, 2018 , the reserve for warranty costs was approximately $ 22,000 and $ 20,000 , respectively. +If actual return rates and/or repair and replacement costs differ significantly from estimates, adjustments to recognize additional cost of sales may be required in future periods. Warranty expense for fiscal years 2019 , 2018 and 2017 was related to workmanship claims on certain EMS products. +Litigation : The Company is party to certain lawsuits or claims in the ordinary course of business. The Company does not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on the financial position, results of operations or cash flow of the Company. +Indemnification Rights : Under the Company’s bylaws, the Company’s directors and officers have certain rights to indemnification by the Company against certain liabilities that may arise by reason of their status or service as directors or officers. The Company maintains director and officer insurance, which may cover certain liabilities arising from its obligation to indemnify its directors and officers and former directors in certain circumstances. +54 +10. DERIVATIVE FINANCIAL INSTRUMENTS +As of June 29, 2019 , the Company had outstanding foreign currency forward contracts and swaps with a total notional amount of $ 39.7 million . The maturity dates for these contracts and swaps extend through December 2020 . As of June 29, 2019 , the net amount of unrealized gain expected to be reclassified into earnings within the next 12 months is approximately $ 2.3 million . During the fiscal year ended June 29, 2019 , the Company entered into $ 19.2 million of foreign currency forward contracts and settled $ 25.9 million of such contracts. During the fiscal year ended June 30, 2018 , the Company entered into $ 13.7 million of foreign currency forward contracts and settled $ 28.1 million of such contracts. During the fiscal year ended July 1, 2017 , the Company entered into $ 6.7 million of foreign currency forward contracts and settled $ 20.5 million of such contracts. +As of June 29, 2019 , the aggregate notional amount of the Company’s outstanding foreign currency contracts and swaps along with their unrealized gains (losses) are expected to mature as summarized below (in thousands): +Quarter Ending +Notional Contracts and Swaps in MXN +Notional Contracts and Swaps in USD +Estimated Fair Value +September 28, 2019 +$ +148,468 +$ +6,740 +$ +942 +December 28, 2019 +$ +152,613 +$ +7,187 +$ +590 +March 28, 2020 +$ +146,613 +$ +6,553 +$ +803 +June 27, 2020 +$ +138,213 +$ +6,257 +$ +577 +September 26, 2020 +$ +141,173 +$ +6,729 +$ +163 +December 26, 2020 +$ +132,773 +$ +6,241 +$ +157 +On October 1, 2014, the Company entered into an interest rate swap contract with an effective date of September 1, 2015 and a termination date of September 3, 2019, with a notional amount of $ 25.0 million related to the borrowings outstanding under the term loan. The interest rate swap pays the Company variable interest at the one month LIBOR rate, and the Company pays the counter party a fixed interest rate. The fixed interest rate for the contract is 1.97 % that replaces the one month LIBOR rate component of our contractual interest to be paid to WFB as part of our term loan. Based on the terms of the interest rate swap contract and the underlying borrowings outstanding under the term loan, the interest rate contract was determined to be effective, and thus qualifies as a cash flow hedge. As of June 29, 2019 and June 30, 2018 , the remaining notional balance of this swap was $ 2.5 million and $ 8.5 million , respectively. +The following table summarizes the fair value of derivative instruments in the Consolidated Balance Sheets as of June 29, 2019 and June 30, 2018 (in thousands): +June 29, 2019 +June 30, 2018 +Derivatives Designated as Hedging Instruments +Balance Sheet Location +Fair Value +Fair Value +Foreign currency forward contracts & swaps +Other current assets +$ +2,912 +$ +23 +Foreign currency forward contracts & swaps +Other long-term assets +$ +320 +$ +477 +Foreign currency forward contracts & swaps +Other current liabilities +$ +— +$ +( 1,618 +) +Foreign currency forward contracts & swaps +Other long-term liabilities +$ +— +$ +( 58 +) +Interest rate swaps +Other current assets +$ +2 +$ +20 +Interest rate swaps +Other long-term assets +$ +— +$ +4 +55 +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2019 (in thousands): +Derivatives Designated as Hedging Instruments +Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) +AOCI Balance +as of +June 30, 2018 +Effective +Portion +Recorded In +AOCI +Effective Portion +Reclassified From +AOCI Into Income +AOCI Balance +as of +June 29, 2019 +Forward contracts & swaps +Cost of sales +$ +( 988 +) +$ +3,332 +$ +80 +$ +2,424 +Interest rate swap +Interest expense +19 +2 +( 19 +) +2 +Total +$ +( 969 +) +$ +3,334 +$ +61 +$ +2,426 +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2018 (in thousands): +Derivatives Designated as Hedging Instruments +Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) +AOCI Balance +as of +July 1, 2017 +Effective +Portion +Recorded In +AOCI +Tax Rate Effect Reclassification +Effective Portion +Reclassified From +AOCI Into Income +AOCI Balance +as of +June 30, 2018 +Forward contracts & swaps +Cost of sales +$ +( 2,707 +) +$ +( 1,942 +) +$ +( 583 +) +$ +4,244 +$ +( 988 +) +Interest rate swap +Interest expense +( 68 +) +20 +( 3 +) +70 +19 +Total +$ +( 2,775 +) +$ +( 1,922 +) +$ +( 586 +) +$ +4,314 +$ +( 969 +) +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2017 (in thousands): +Derivatives Designated as Hedging Instruments +Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) +AOCI Balance +as of +July 2, 2016 +Effective +Portion +Recorded In +AOCI +Effective Portion +Reclassified From +AOCI Into Income +AOCI Balance +as of +July 1, 2017 +Forward contracts & swaps +Cost of sales +$ +( 7,245 +) +$ +( 600 +) +$ +5,138 +$ +( 2,707 +) +Interest rate swap +Interest expense +( 328 +) +14 +246 +( 68 +) +Total +$ +( 7,573 +) +$ +( 586 +) +$ +5,384 +$ +( 2,775 +) +As of June 29, 2019 , the Company does not have any foreign exchange contracts with credit-risk-related contingent features. The Company is subject to the risk of fluctuating interest rates from our line of credit and foreign currency risk resulting from our China operations. The Company does not currently manage these risk exposures by using derivative instruments. +56 +11. FAIR VALUE MEASUREMENTS +The Company has adopted ASC 820, Fair Value Measurements, which defines fair value, establishes a framework for assets and liabilities being measured and reported at fair value and expands disclosures about fair value measurements. There are three levels of fair value hierarchy inputs used to value assets and liabilities which include: Level 1 – inputs are quoted market prices for identical assets or liabilities; Level 2 – inputs other than quoted market prices included in Level 1 that are observable for the asset or liability, either directly or indirectly; and Level 3 – inputs are unobservable inputs for the asset or liability. There have been no changes in the fair value methodologies used at June 29, 2019 and June 30, 2018 . +The following table summarizes the fair value of assets (liabilities) of the Company’s derivatives that are required to be measured on a recurring basis as of June 29, 2019 and June 30, 2018 (in thousands): +June 29, 2019 +Level 1 +Level 2 +Level 3 +Total +Fair Value +Financial Assets: +Interest rate swaps +$ +— +$ +2 +$ +— +$ +2 +Foreign currency forward contracts & swaps +$ +— +$ +3,232 +$ +— +$ +3,232 +June 30, 2018 +Level 1 +Level 2 +Level 3 +Total +Fair Value +Financial Assets: +Interest rate swaps +$ +— +$ +24 +$ +— +$ +24 +Foreign currency forward contracts & swaps +— +500 +— +$ +500 +Financial Liabilities: +Foreign currency forward contracts & swaps +$ +— +$ +( 1,676 +) +$ +— +$ +( 1,676 +) +The Company currently has forward contracts and swaps to hedge known future cash outflows for expenses denominated in the Mexican peso and an interest rate swap to mitigate risk associated with certain borrowings under the Company’s debt arrangement. These contracts are measured on a recurring basis based on the foreign currency spot rates and forward rates quoted by banks or foreign currency dealers. These contracts are marked to market using level 2 input criteria every period with the unrealized gain or loss, net of tax, reported as a component of shareholders’ equity in accumulated other comprehensive income (loss), as they qualify for hedge accounting. +The carrying values of cash and cash equivalents, accounts receivable and current liabilities reflected on the balance sheets at June 29, 2019 and June 30, 2018 , reasonably approximate their fair value. +The Company’s long-term debt, which is measured at amortized cost, primarily consists of a revolving line of credit, a term loan and an equipment term loan. These borrowings bear interest at either a “Base Rate” or a “Fixed Rate,” as elected by the Company. Each of these rates is a variable floating rate dependent upon current market conditions and the Company’s current credit risk as discussed in footnote 4. +As a result of the determinable market rate for our revolving line of credit, term loan and equipment term, they are classified within Level 2 of the fair value hierarchy. Further, the carrying value of each of these instruments reasonably approximates their fair value as of June 29, 2019 and June 30, 2018 . +Other assets and liabilities held by the Company may be required to be measured at fair value on a non recurring basis. As of June 29, 2019 , the customer relationship intangibles were written down to their fair value of $0. This measurement was the result of certain triggering events that occurred during the third quarter of fiscal year 2019. Refer to Note 14 for further discussion of the impairment. +57 +12. ENTERPRISE-WIDE DISCLOSURES +Operating segments are defined in ASC Topic 280, Segment Reporting as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker, or decision making group, in deciding how to allocate resources and in assessing performance. The Company’s chief operating decision maker is its Chief Executive Officer. As of June 29, 2019 , the Company operates and internally manages a single operating segment, Electronics Manufacturing Services as this is the only discrete financial information that is regularly reviewed by the chief operating decision maker. This segment provides integrated electronic and mechanical engineering, assembly, sourcing and procurement, logistics, and new product testing for our customers. +Products and Services +Of the revenues for the years ended June 29, 2019 , June 30, 2018 , and July 1, 2017 , EMS sales and services were $ 463.9 million , $ 445.8 million and $ 466.6 million , respectively. Keyboard sales for the years ended June 29, 2019 , June 30, 2018 , and July 1, 2017 were $ 0.1 million , $ 0.5 million and $ 1.2 million , respectively. +Geographic Areas +Net sales and long-lived assets (property, plant, and equipment) by geographic area for the years ended and as of June 29, 2019 , June 30, 2018 and July 1, 2017 are summarized in the following table. Net sales set forth below are based on the shipping destination. Long-lived assets information is based on the physical location of the asset. +Fiscal Year Ended +(in thousands) +2019 +2018 +2017 +Geographic net sales: +Domestic (U.S.) +$ +357,341 +$ +329,230 +$ +361,886 +Foreign +106,703 +117,092 +105,911 +Total +$ +464,044 +$ +446,322 +$ +467,797 +Long-lived assets: +United States +$ +9,658 +$ +7,454 +$ +8,988 +Mexico +17,781 +19,395 +20,878 +Vietnam +1,220 +— +— +China +754 +699 +630 +Total +$ +29,413 +$ +27,548 +$ +30,496 +Percentage of net sales made to customers located in the following countries: +Fiscal Year Ended +2019 +2018 +2017 +United States +77 % +74 % +77 % +China +19 +24 +19 +Other foreign countries (a) +3 +2 +3 +Canada +1 +— +1 +Total +100 % +100 % +100 % +(a) No other individual foreign country accounted for 10% or more of the foreign sales in fiscal years 2019, 2018 or 2017. +58 +Significant Customers +The percentage of net sales to and trade accounts receivables from significant customers were as follows: +Percentage of Net +Sales Fiscal Year +Percentage of +Trade Accounts Receivable +Fiscal Year +2019 +2018 +2017 +2019 +2018 +Customer A +17 % +19 % +18 % +11 % +17 % +Customer B +* +* +* +10 % +10 % +* Current customer amount represents less than 10%. +13. QUARTERLY FINANCIAL DATA (Unaudited) +Fiscal Year Ended June 29, 2019 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +(in thousands, except per share amounts) +Net sales +$ +127,472 +$ +123,037 +$ +107,954 +$ +105,581 +Gross profit +9,533 +9,880 +6,807 +8,381 +Income (loss) before income taxes +1,868 +1,916 +( 13,256 +) +732 +Net income (loss) +1,593 +1,589 +( 11,981 +) +817 +Net income (loss) per share - basic +$ +0.15 +$ +0.15 +$ +( 1.11 +) +$ +0.08 +Net income (loss) per share - diluted +$ +0.15 +$ +0.15 +$ +( 1.11 +) +$ +0.08 +Weighted average shares outstanding +Basic +10,760 +10,760 +10,760 +10,760 +Diluted +10,979 +10,881 +10,760 +10,760 +Fiscal Year Ended June 30, 2018 +First +Quarter +Second +Quarter +Third +Quarter +Fourth +Quarter +(in thousands, except per share amounts) +Net sales +$ +109,217 +$ +111,725 +$ +108,352 +$ +117,028 +Gross profit +7,845 +8,800 +8,155 +9,369 +Income (loss) before income taxes +570 +1,035 +123 +( 3,170 +) +Net income (loss) +432 +( 224 +) +644 +( 2,177 +) +Net income (loss) per share - basic +$ +0.04 +$ +( 0.02 +) +$ +0.06 +$ +( 0.20 +) +Net income (loss) per share - diluted +$ +0.04 +$ +( 0.02 +) +$ +0.06 +$ +( 0.20 +) +Weighted average shares outstanding +Basic +10,760 +10,760 +10,760 +10,760 +Diluted +10,760 +10,760 +10,760 +10,760 +59 +14. GOODWILL AND OTHER INTANGIBLE ASSETS +The Company recorded goodwill in connection with the Ayrshire and Sabre acquisitions resulting primarily from the synergies that resulted from the Company's acquisitions and the assembled workforce. The goodwill is not amortized for financial accounting purposes. +In accordance with accounting guidance on goodwill and other intangible assets, the Company evaluates goodwill for impairment at the reporting unit level annually, and whenever circumstances occur indicating that goodwill might be impaired. Upon adoption of ASU 2017-04, the Company now recognizes an impairment charge (not to exceed the total amount of goodwill allocated to the reporting unit) for the amount by which the carrying amount of a reporting unit exceeds the reporting unit’s fair value. During the third quarter of fiscal year 2019, a few large programs declined in revenue and two new programs were delayed. This decrease in the Company’s total revenue combined with book value continuing to exceed market capitalization caused a “triggering event” in which to perform a quantitative impairment analysis as of March 30, 2019. To estimate the fair value of the Company’s equity, the Company used both a market approach and an income approach, based on a discounted cash flows analysis. As of March 30, 2019, market related factors increased expected required rates of return, which also increased the Company’s discount rate used to project future cash flows. Further, push outs of the Company’s forecasted future cash flows relating to delays in customer orders adversely impacted the Company’s discounted cash flows model. As a result, a lower estimate in the Company’s fair value using these two valuation methods indicated an impairment charge. +During the third quarter of fiscal year 2019, the Company also assessed other finite-lived intangible assets including the Company’s customer relationships and favorable lease agreements due to an indicator of possible impairment being present, as discussed above. The Company performed this analysis through comparing the sum of the undiscounted future cash flows expected to result from the assets with the carrying value of the assets. As a result of the analysis performed, the Company determined that the carrying value of the customer relationships intangible asset was not recoverable and recorded an impairment for the entire carrying amount during the third quarter of fiscal year 2019. The Company’s analysis did not indicate that any of its other long-lived assets were impaired. +During the third quarter of fiscal year 2019, a goodwill impairment of $ 10.0 million and other intangible assets impairment of $ 2.5 million was recognized. During fiscal year 2018, no goodwill impairment was recognized. Goodwill was recorded at $ 10.0 million as of June 30, 2018 . +The components of acquired intangible assets are as follows (in thousands): +June 29, 2019 +Amortization Period +in Years +Gross Carrying +Amount +Accumulated +Amortization +Impairment +Recognized +Net Carrying +Amount +Other intangible assets: +Non-Compete Agreements +3 - 5 +$ +568 +$ +( 568 +) +$ +— +$ +— +Customer Relationships +10 +4,803 +( 2,311 +) +( 2,492 +) +— +Favorable Lease Agreements +4 - 7 +2,941 +( 2,284 +) +— +657 +Total +$ +8,312 +$ +( 5,163 +) +$ +( 2,492 +) +$ +657 +June 30, 2018 +Amortization Period +in Years +Gross Carrying +Amount +Accumulated +Amortization +Net Carrying +Amount +Other intangible assets: +Non-Compete Agreements +3 - 5 +$ +568 +$ +( 568 +) +$ +— +Customer Relationships +10 +4,803 +( 2,071 +) +2,732 +Favorable Lease Agreements +4 - 7 +2,941 +( 1,947 +) +994 +Total +$ +8,312 +$ +( 4,586 +) +$ +3,726 +Amortization expense related to intangible assets was approximately $ 0.6 million for the year ended June 29, 2019 and $ 1.1 million for the year ended June 30, 2018 . +60 +Aggregate amortization expense related to existing intangible assets by fiscal year is currently estimated to be as follows (in thousands): +Fiscal Years Ending +Amount +2020 +$ +303 +2021 +303 +2022 +51 +Total amortization expense +$ +657 +15. REVENUE +Revenue Recognition +The Company specializes in services ranging from product manufacturing to engineering and tooling services. The first step in its process for revenue recognition is to identify the contract with a customer. A contract is defined as an agreement between two or more parties that creates enforceable rights and obligations. A contract can be written, oral, or implied. The Company generally enters into manufacturing service agreements (“MSA”) with its customers that outlines the terms of the business relationship between the customer and the Company. This includes matters such as warranty, indemnification, transfer of title and risk of loss, liability for excess and obsolete inventory, pricing, payment terms, etc. The Company will also bid on a program-by-program basis for customers in which an executed MSA may not be in place. In these instances, as well as when we have an MSA in place, we receive customer purchase orders for specific quantities and timing of products. As a result, the Company considers its contract with a customer to be the combination of the MSA and the purchase order. The transaction price is fixed and set forth in each purchase order. In the Company's normal course of business, there are no variable pricing components, or material amounts refunded to customers in the form of refunds or rebates. +The Company assesses whether control of the product or services promised under the contract is transferred to the customer at a point in time (shipment) or over time (as we manufacture the product). The Company is first required to evaluate whether its contracts meet the criteria for 'over-time' or 'point-in-time' recognition. The Company has determined that for the majority of its contracts the Company is manufacturing products for which there is no alternative use due to the unique nature of the customer-specific product, IP and other contract restrictions. The Company has an enforceable right to payment including a reasonable profit for performance completed to date with respect to these contracts. As a result, revenue is recognized under these contracts 'over-time' based on the input cost-to-cost method as it better depicts the transfer of control. This input method is based on the ratio of costs incurred to date as compared to the total estimated costs at completion of the performance obligation. For all other contracts that do not meet these criteria, such as manufacturing contracts for which the terms do not provide an enforceable right to payment for performance completed to date, the Company recognizes revenue when it has transferred control of the related manufactured products which generally occurs upon shipment to the customer. Revenue from engineering services is recognized over time as the services are performed. +The Company’s typical payment terms are 30 to 45 days and its sales arrangements do not contain any significant financing component for its customers. +The Company generally provides a warranty for workmanship on its manufacturing contracts. Historically, the amount of returns for workmanship issues has been de minimis under the Company’s warranties. +The Company elected to not disclose information about remaining performance obligations as they are part of contracts that that have expected durations of one year or less. +The Company has elected to expense costs to obtain contracts as incurred as these costs are immaterial to the financial statements. +During fiscal 2019, no revenues were recognized from performance obligations satisfied or partially satisfied in previous periods. +61 +Contract Balances +A contract asset is recognized when the Company has recognized revenue, but has not issued an invoice for payment. Contract assets are classified separately on the condensed consolidated balance sheet and transferred to receivables when the right to payment becomes unconditional. The following table summarizes the activity in the Company’s contract assets during the twelve months ended June 29, 2019 (in thousands): +Contract Assets +Beginning balance, June 30, 2018 +$ +— +Cumulative effect adjustment at July 1, 2018 +11,906 +Revenue recognized +448,003 +Amounts collected or invoiced +( 437,748 +) +Ending balance, June 29, 2019 +$ +22,161 +Disaggregation of Revenue +The following table presents the Company’s revenue disaggregated for the twelve months ended June 29, 2019 (in thousands): +EMS Revenue +Recognition +Twelve Months Ended +Over-Time +$ +458,256 +Point-in-Time +5,788 +Total +$ +464,044 +Revenues and associated costs from engineering design, development services and tooling, which are performed under contract of short term durations, are recognized over time as the services are performed. Revenue from engineering design, development services and tooling represented approximately 2.9 percent of total revenue in fiscal year 2019 . +16. SUBSEQUENT EVENT +On September 10, 2019, the Company entered into a fifth amendment to the amended and restated credit agreement and loan documents increasing our term loan balance by $ 5 million and fixing borrowings under the revolving line of credit, term loan, and equipment term loan to bear interest at LIBOR plus 2.0 % , as opposed to previous borrowings at either a “Base Rate” or a “Fixed Rate,” as elected by the Company, as evidenced by the First Replacement Term Note and the Third Replacement Revolving Note. This agreement increases the Company’s term loan outstanding balance from $ 11.3 million to $ 16.3 million . Refer to footnote 4 for further details regarding the Company’s borrowings. +Item 9: +CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES +None +Item 9A: +CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +It is the responsibility of our management to establish, maintain, and monitor disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 are recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Additionally, these disclosure controls include controls and procedures that are designed to accumulate and communicate the information required to be disclosed to our Company’s Chief Executive Officer and Chief Financial Officer, allowing for timely decisions regarding required disclosures. As of the end of the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(f). Based on our assessment, we believe that as of June 29, 2019 , the Company’s disclosure controls and procedures are effective based on that criteria. +62 +Management’s Report on Internal Control over Financial Reporting +Our management has the responsibility to establish and maintain adequate internal controls over our financial reporting, as defined in Rule 13a-15(f) under the Securities and Exchange Act of 1934. Our internal controls are designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our external financial statements in accordance with generally accepted accounting principles (GAAP). +Due to inherent limitations of any internal control system, management acknowledges that there are limitations as to the effectiveness of internal controls over financial reporting and therefore recognize that only reasonable assurance can be gained from any internal control system. Accordingly, our internal control system may not detect or prevent material misstatements in our financial statements and projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, we have performed an assessment of the effectiveness of our internal controls over financial reporting as of June 29, 2019 . This assessment was based on the criteria established in Internal Control-Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that as of June 29, 2019 , the Company’s internal control over financial reporting is effective based on that criteria. +The effectiveness of the Company's internal control over financial reporting as of June 29, 2019 has been audited by BDO USA LLP, an independent registered public accounting firm, as stated in their report which is included herein. +Changes in Internal Control over Financial Reporting +There have been no significant changes in our internal controls over financial reporting during our fourth fiscal quarter ended June 29, 2019 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)). +63 +Report of Independent Registered Public Accounting Firm +Shareholders and Board of Directors +Key Tronic Corporation +Spokane Valley, Washington +Opinion on Internal Control over Financial Reporting +We have audited Key Tronic Corporation’s (the “Company’s”) internal control over financial reporting as of June 29, 2019 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of June 29, 2019 , based on the COSO criteria. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company as of June 29, 2019 and June 30, 2018, the related consolidated statements of income (loss), comprehensive income (loss), shareholders’ equity, and cash flows for each of the three years in the period ended June 29, 2019 , and the related notes and schedule and our report dated September 12, 2019 expressed an unqualified opinion thereon. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying “Item 9A, Management’s Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit of internal control over financial reporting in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ BDO USA, LLP +Spokane, Washington +September 12, 2019 +64 +Item 9B: +OTHER INFORMATION +None +PART III +Item 10: +DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Directors of the Registrant +Information on the nominees for election as Directors of the Company is incorporated by reference from the Company’s definitive proxy statement for the 2019 Annual Meeting of Shareholders to be filed pursuant to Regulation 14A under the Exchange Act no later than 120 days after the end of the Company’s 2019 fiscal year. +Executive Officers of the Registrant +This information is included in a separate item captioned “Executive Officers of the Registrant” in Item 1 of Part 1 of this report pursuant to Instruction G(3) of Form 10-K and Instruction 3 to Item 401(b) of Regulation S-K. +Compliance with Section 16(a) of the Exchange Act: +Incorporated by reference to Key Tronic Corporation’s 2019 Proxy Statement to Shareholders. +Code of Conduct +The Board of Directors has adopted a written Code of Conduct which applies to its directors and employees, including its executive officers. The Code of Conduct is available on the Company’s website at www.keytronic.com . The Company intends to disclose on its website any amendments to or waivers of the Code of Conduct. +Item 11: +EXECUTIVE COMPENSATION +Information appearing under the caption “Executive Compensation” in the Company’s 2019 Proxy Statement is incorporated herein by this reference. +Item 12: +SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The following table sets forth the aggregate information for the Company’s equity compensation plans in effect as of June 29, 2019 . +EQUITY COMPENSATION PLAN INFORMATION +Plan category +Number of securities to +be issued upon exercise +of outstanding options, +warrants, and rights +(a) +Weighted-average +exercise price of +outstanding options, +warrants, and rights +(b) +Number of securities +remaining available for +future issuance under +equity compensation +plans (excluding +securities reflected in +column (a) +(c) +Equity compensation plans approved by security holders (1) +985,416 +$ +8.35 +493,918 +Equity compensation plans not approved by security holders +— +$ +— +— +Total +985,416 +$ +8.35 +493,918 +(1) +Included are the 1,200,000 shares subject to the 2010 Plan, the issuance of which were approved by the shareholders at the 2010 Annual Meeting. During the 2015 Annual Meeting, an additional 1,000,000 shares were approved. As a result of the shareholder approval, the Company made the decision to amend the cash-settled SARs granted during fiscal year 2010 to stock-settled SARs effective October 21, 2011. +Information under the caption “Beneficial Ownership of Securities” in the Company’s 2019 Proxy Statement is incorporated herein by this reference. +65 +Item 13: +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions”, “Compensation Committee Interlocks and Insider Participation”, and “Directors’ Independence” in the Company’s 2019 Proxy Statement is incorporated herein by this reference. +Item 14: +PRINCIPAL ACCOUNTING FEES AND SERVICES +Information appearing under the caption “Principal Accountant Fees and Services” in the Company’s 2019 Proxy Statement is incorporated herein by this reference. +PART IV +Item 15: +EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +(a) 1. FINANCIAL STATEMENTS +Page in Form 10-K +FINANCIAL STATEMENTS +Report of Independent Registered Public Accounting Firm +31 +Consolidated Balance Sheets +32 +Consolidated Statements of Income (Loss) +33 +Consolidated Statements of Comprehensive Income (Loss) +34 +Consolidated Statements of Cash Flows +35 +Consolidated Statements of Shareholders’ Equity +36 +Notes to Consolidated Financial Statements +37-62 +2. SCHEDULES +II. Consolidated Valuation and Qualifying Accounts +71 +Other schedules are omitted because of the absence of conditions under which they are required, or because required information is given in the financial statements or notes thereto. +66 +3. EXHIBITS +Exhibit No. +Description +3.1 +Articles of Incorporation, incorporated by reference to the Exhibit 3.1 to the Company’s form 10-K filed with the SEC for the year ended July 1, 1995 (File No. 2-83898) +3.2 +Bylaws, as amended, incorporated by reference to the Exhibit 3 (iii) to the Company’s Form 10-K for the year ended July 1, 1995 (File No. 2-83898) +10.1* +Amended and Restated 1990 Stock Option Plan for Non-Employee Directors, as amended, incorporated by reference to the Company’s 1997 Proxy Statement dated October 10, 1997 (Proposal 2) +10.2* +1995 Executive Stock Option Plan, incorporated by reference to the Company’s 1995 Proxy Statement, pages 19-22 (Proposal 3) +10.3* +2000 Employee Stock Option Plan, incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.4* +Officers’ Employment Contracts, incorporated by reference to the Company’s 1998 Proxy Statement, pages 10 and 11 +10.5* +Addenda to Officers’ Employment Contracts, incorporated by reference to Exhibits to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.6* +Description of Retention Bonus Plan, incorporated by reference to the Exhibits to the Company’s 10-Q for the quarter ended December 28, 2002 +10.7* +Addenda to Officers’ Employment Contracts, incorporated by reference to Exhibits to the Company’s Form 10-K for the year ended June 29, 2002 +10.8 +Promise to execute a Purchase and Sale Agreement with Key Safety Systems de Mexico, S.A. de C.V., incorporated by reference to the Exhibit to the Company’s Form 8-K filed April 26, 2005 +10.9 +Summary of material terms and conditions of the Purchase and Sale Agreement with Key Safety Systems de Mexico, S.A. de C.V., incorporated by reference to the Exhibit to the Company’s Form 8-K filed June 6, 2005 +10.10* +Summary of Key Tronic Corporation Long Term Incentive Compensation Plan, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed September 27, 2005 +67 +10.11* +Summary of Key Tronic Corporation Incentive Compensation Plan, incorporated by reference to Exhibit 10.23 to the Company’s Form 10-K for the year ended July 2, 2005 +10.12* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2007 and Fiscal Years 2007 – 2009 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 28, 2006 +10.13 +Summary of material terms and conditions of the Purchase and Sale Agreement with Todenko Mexico S.A. de C.V., incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed October 12, 2006 +10.14 +Summary of material terms and conditions of the Purchase and Sale Agreement with Todenko Mexico S.A. de C.V., incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed November 20, 2006 +10.15 +Summary of material terms and conditions of the Sale and Purchase Agreement with Adevco Corporation, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed January 5, 2007 +10.16 +Summary of Second Amendment to Agreement of Sale and Purchase Agreement with Adevco Corporation, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed April 11, 2007 +10.17* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2008 and Fiscal Years 2008-2010 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 27, 2007 +10.18* +Summary of Incentive Compensation Plan Performance Goals and Target payments for Fiscal Year 2009 and Fiscal Years 2009 – 2011 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 24, 2008 +10.19* +Summary of Incentive Compensation Plan Performance Goals and Target payments for Fiscal Year 2010 and Fiscal Years 2010 – 2012 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 23, 2009 +10.20 +Financing Agreement with Wells Fargo Bank, N.A., incorporated by reference to the Exhibits to the Company’s Form 8-K filed on August 24, 2009 +10.21* +2010 Incentive Plan, incorporated by reference to Exhibit 10.36 to the Company’s Form 10-K for the year ended July 3, 2010 +10.22* +Employment Contract with Douglas G. Burkhardt, incorporated by reference to Exhibit 10.37 to the Company’s Form 10-K for the year ended July 3, 2010 +10.23 +Summary of material terms and conditions of the Purchase and Sale Agreement with Autopartes Y Arneses de Mexico S.A. de C.V., incorporated by reference to Exhibit 10.38 to the Company’s Form 10-K for the year ended July 3, 2010 +10.24* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2011 and Fiscal Years 2011 – 2013 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 23, 2010 +10.25* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2012 and Fiscal Years 2012 – 2014 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 2, 2011 +68 +10.26* +Amendment to Employment Contract of Craig D. Gates, dated August 23, 2011; of Ronald F. Klawitter, dated August 23, 2011 and of Douglas G. Burkhardt dated September 6, 2011; incorporated by reference to the Exhibits to the Company’s Form 10-K for the year ended July 2, 2011 filed on September 12, 2011 +10.27 +Second Loan Modification Agreement to the Credit Agreement with Wells Fargo Bank, N.A., incorporated by reference to the Exhibits to the Company’s Form 8-K filed on February 2, 2012 +10.28* +Amendment to Employment Contract of Craig D. Gates, dated May 10, 2012, incorporated by reference to the Exhibits to the Company’s Form 10-Q filed on May 14, 2012 +10.29* +Amendment to Employment Contract of Douglas G. Burkhardt dated May 10, 2012; incorporated by reference to the Exhibits to the Company’s Form 10-Q filed on May 14, 2012 +10.30* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2013 and Fiscal Years 2013 – 2015 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 7, 2012 +10.31* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2014 and Fiscal Years 2014 – 2016 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 6, 2013 +10.32* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2015 and Fiscal Years 2015 – 2017 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 1, 2014 +10.33 +Summary of material terms and conditions of the Stock Purchase Agreement with CDR Manufacturing and Amended and Restated Credit Agreement with Wells Fargo Bank, N. A. incorporated by reference to the Company’s Form 8-K filed September 9, 2014 +10.34* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2016 and Fiscal Years 2016 – 2018 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 30, 2015 +10.35 +First Amendment to Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, incorporated by reference to the Company's Form 8-K filed August 11, 2015 +10.36 +Second Replacement Revolving Line of Credit Note with Wells Fargo Bank, National Association, incorporated by reference to the Company's Form 8-K filed August 11, 2015 +10.37* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2017 and Fiscal Years 2017 – 2019 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 29, 2016 +10.38* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2018 and Fiscal Years 2018 – 2020 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 22, 2017 +10.39 +Announcement of contract awarded with SkyBell Technologies, a global leader in patented Wi-Fi video doorbell technology incorporated by reference to the Company’s Form 8-K filed May 1, 2018 +10.40* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2019 and Fiscal Years 2019 – 2021 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 2, 2018 +69 +10.41 +Announcement of award of $6.7 million following the conclusion of a previously disclosed arbitration proceeding incorporated by reference to the Company's Form 8-K filed September 5, 2018 +10.42 +Announcement that the Company has signed a letter of intent to lease a new facility in Da Nang, Vietnam +10.43* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2020 and Fiscal Years 2020 – 2022 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 30, 2019 +21 +Subsidiaries of Registrant, submitted herewith +23.1 +Consent of Independent Registered Public Accounting Firm, submitted herewith +31.1 +Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer, submitted herewith +31.2 +Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer, submitted herewith +32.1 +Section 1350 Certification of Chief Executive Officer, submitted herewith +32.2 +Section 1350 Certification of Chief Financial Officer, submitted herewith +101.INS +XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. +101.SCH +XBRL Taxonomy Extension Schema Document ** +101.CAL +XBRL Taxonomy Extension Calculation Linkbase Document ** +101.DEF +XBRL Taxonomy Extension Definition Linkbase Document ** +101.LAB +XBRL Taxonomy Extension Label Linkbase Document ** +101.PRE +XBRL Taxonomy Extension Presentation Linkbase Document ** +104 +Cover Page Interactive Data File (formatted as inline XBRL with applicable taxonomy extention information contained in Exhibits 101.INS, 101.SCH, 101.CAL, 101.DEF, 101.LAB and 101.PRE) +* +Management contract or compensatory plan or arrangement +** +Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities and Exchange Act of 1934, as amended and otherwise are not subject to liability under those sections. +70 +SCHEDULE II +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS +FISCAL YEARS ENDED JUNE 29, 2019 , JUNE 30, 2018 , AND JULY 1, 2017 +Fiscal Year Ended +2019 +2018 +2017 +(in thousands) +Allowance for Obsolete Inventory +Balance at beginning of year +$ +1,458 +$ +1,306 +$ +1,113 +Provisions +91 +31 +496 +Dispositions +243 +121 +( 303 +) +Balance at end of year +$ +1,792 +$ +1,458 +$ +1,306 +Allowance for Doubtful Accounts +Balance at beginning of year +$ +— +$ +84 +$ +135 +Provisions (Recovery) +58 +( 84 +) +( 10 +) +Write-offs +— +— +( 41 +) +Balance at end of year +$ +58 +$ +— +$ +84 +71 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +Dated: September 12, 2019 +KEY TRONIC CORPORATION +By: +/s/ Craig D. Gates +Craig D. Gates, President and Chief Executive Officer +(Principal Executive Officer) +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated: +/s/ Craig D. Gates +September 12, 2019 +Craig D. Gates +Date +Director and President and Chief Executive Officer +(Principal Executive Officer) +/s/ Brett R. Larsen +September 12, 2019 +Brett R. Larsen +Date +Executive Vice President of Administration, Chief Financial Officer and Treasurer +(Principal Financial Officer) +/s/ Ronald F. Klawitter +September 12, 2019 +Ronald F. Klawitter, Director +Date +/s/ James R. Bean +September 12, 2019 +James R. Bean, Director +Date +/s/ Subodh K. Kulkarni +September 12, 2019 +Subodh K. Kulkarni, Director +Date +/s/ Yacov A. Shamash +September 12, 2019 +Yacov A. Shamash, Director +Date +/s/ Patrick Sweeney +September 12, 2019 +Patrick Sweeney, Director and Chairman of the Board +Date +72 \ No newline at end of file diff --git a/raw/filings/0000719733/2019/0000719733-19-000063/filing_metadata.csv b/raw/filings/0000719733/2019/0000719733-19-000063/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..d542018664654f71ff7cb0b8aaaca156ff69082a --- /dev/null +++ b/raw/filings/0000719733/2019/0000719733-19-000063/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000719733,KTCC,KEY TRONIC CORP,10-K,2019-09-12,2019-06-29,2019-09-12T19:28:49.000Z,0000719733-19-000063,ktcc-06292019x10k.htm,10-K,10286161,1,1,https://www.sec.gov/Archives/edgar/data/719733/000071973319000063/ktcc-06292019x10k.htm,https://www.sec.gov/Archives/edgar/data/719733/000071973319000063/,2019,2019,1 diff --git a/raw/filings/0000719733/2019/0000719733-19-000063/item1.txt b/raw/filings/0000719733/2019/0000719733-19-000063/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..4cbf179d62af27ffdc14f5ea411fe6c37a42cf1e --- /dev/null +++ b/raw/filings/0000719733/2019/0000719733-19-000063/item1.txt @@ -0,0 +1,102 @@ +Item 1. +BUSINESS +Background +Key Tronic Corporation (dba: KeyTronicEMS Co.) was organized in 1969, as a Washington corporation that locally manufactured computer keyboards. The ability to design, build and deliver a quality product led us to become a leading independent manufacturer of keyboards for computers in the United States. Our fully integrated design, tooling, and automated manufacturing capabilities enabled us to rapidly respond to customers’ needs for keyboards in production quantities worldwide. We supported our sales growth through the development and purchase of international manufacturing facilities. As the computer keyboard market matured with increasing competition from other international providers, we determined that our business could no longer solely rely on keyboard sales. +After assessing market conditions and our strengths and capabilities, we shifted our focus from keyboard manufacturing to contract manufacturing for a wide range of products. Our unique strategic attributes are based on our core strengths of innovative design and engineering expertise in electronics, mechanical engineering, sheet metal fabrication and stamping, and precision plastics combined with high-quality, low cost production, and assembly on an international basis while providing exceptional customer service. These strengths have made our company a strong competitor in the electronic manufacturing services (EMS) market. +Our Industry and Strategy +The expansion of the EMS industry and our acquisitions have allowed us to continue to expand our customer base and the industries that we serve. The increase in new programs represents a growing portion of our revenue and a promising foundation for our future. In keeping with our long-term strategic objectives, we have been successfully building a more diversified customer portfolio, spanning a wider range of industries. We currently offer our customers the following services: integrated electronic and mechanical engineering, precision plastic molding, sheet metal fabrication, printed circuit board (PCB) and complete product assembly, component selection, sourcing and procurement, worldwide logistics, and new product testing and production all at competitive pricing due to our global footprint. We differentiate ourselves from others our size and larger in the EMS industry by providing vertical integration, a flexible and responsive approach to our customer’s changing supply demand, and complete design engineering support. +We believe that we are well positioned in the EMS industry to continue the expansion of our customer base and achieve long-term growth. Our unique blend of multinational facilities, vertical integration, centralized management, and core strengths continue to support our growth and our customers’ needs. We continue to focus on controlling operating expenses and leveraging the synergistic capabilities of our world-class facilities in the United States, Mexico, China and Vietnam. This international production capability provides our customers with the benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs, and reduced product fulfillment time. Given our competitive advantages and the growing pressure for new potential customers to move forward with their outsourcing strategies, we are strongly positioned to win new business in coming periods and grow our revenue and profits. +4 +The EMS industry is intensely competitive. Although our customer base is growing, we still have less than 1% of the potential global market and our revenue can fluctuate significantly due to reliance on a concentrated base of customers. We are planning for new customer growth in the coming quarters by securing new programs with new and existing customers, increasing our worldwide manufacturing capacity, leveraging further our design engineering capabilities and continuing to improve our manufacturing and procurement processes and capabilities. Ongoing challenges that we face include but are not limited to the following: continuing to win programs from new and existing customers, balancing capital employed, production capacity and key personnel in support of new customer programs, improving operating efficiencies, controlling costs while developing competitive pricing strategies, and successfully transitioning new program wins to full production. +Customers and Marketing +We provide a mix of manufacturing services for outsourced Original Equipment Manufacturing (OEM) products. We provide the following EMS services: product design, surface mount technologies (SMT) and pin through hole capability for printed circuit board assembly, tool making, precision plastic molding, sheet metal fabrication and painting, liquid injection molding, complex assembly, automated tape winding, prototype design and full product assembly. +Sales of the majority of our products have not historically been seasonal in nature, but may be seasonal in the future if there are changes in the types of products manufactured. Sales can, however, fluctuate significantly between quarters from changes in customers and customer demand due to the concentration of sales generated by our largest customers. +For the fiscal years 2019 , 2018 and 2017 , the five largest customers in each year accounted for 41%, 42% and 42% of combined total net sales, respectively. We continue to diversify our customer base by adding additional programs and customers. We expect net sales to our five largest customers as a percentage of total net sales to approximate current levels going forward. +The following table represents all customers that represented 10% or more of total net sales during the last three fiscal years: +Percentage of Net Sales by Fiscal Year +2019 +2018 +2017 +Customer A +17% +19% +18% +There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +We market our products and services primarily through our direct sales department which is comprised of strategically located field sales people and distributors. We also maintain relationships with several independent sales organizations to assist in marketing our EMS product lines. +Manufacturing +We have continually made investments in developing and expanding a capital equipment base to achieve vertical integration and efficiencies in our manufacturing processes. We have invested significant capital into SMT for volume manufacturing of complex printed circuit board assemblies and in our metal shop providing precision metal stamping, fabricating, and finishing. We also design and develop tooling for injection molding and sheet metal fabrication and manufacture the majority of plastic and sheet metal parts used in the products we manufacture. Additionally, we have equipment to maintain a controlled clean environment for manufacturing processes that require a high level of precise control. +We use a variety of manual and automated assembly processes in our facilities, depending upon product complexity and degree of customization. Some examples of automated processes include component insertion, SMT, selective soldering, flexible robotic assembly, automated storage tape winding, computerized vision system quality inspection, laser turrets, automated switch and key top installation, robotic welding, automated powder coat application, and automated functional testing. +Our engineering expertise and automated manufacturing processes enable us to work closely with our customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. We use computer-aided design techniques and software to assist in preparation of the tool design layout and component placement, to reduce tooling and production costs, improve component and product quality, and enhance turnaround time during product development. +We purchase materials and components for our products from many different suppliers, including both domestic and international sources. We develop close working relationships with our suppliers, many of whom have been supplying products to us for several years. +5 +Research, Development, and Engineering +As part of our long-term strategy, we are committed to supporting our customers by providing research, development, and engineering services. We have seen an increase in the success of providing design support on existing and potential customers in differentiating ourselves. These services allow us to facilitate in optimizing new product designs, and the production processes of our customers’ programs. +Research, development, and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials costs, depreciation, and allocated information technology and facilities costs. +Competition +The market for the products and services we provide is highly competitive. There are numerous competitors in the EMS industry, many of which have substantially more resources and are more geographically diverse than we are. Some of our competitors have similar international production capabilities, large financial resources and some have substantially greater manufacturing, research and development, and marketing resources. There is also competition from the manufacturing operations of our current and potential customers, who are continually evaluating the merits of manufacturing their products internally versus the advantages of outsourcing. We believe that we can currently compete favorably in these areas primarily on the basis of our international footprint, responsiveness, creativity, vertical production capability, quality, and cost. +Trademarks +Our name and logo are federally registered trademarks, and we believe they are valuable assets of our business. We operate under the trade name “KeyTronicEMS” to better identify our primary business concentration in contract manufacturing in the EMS industry. +Employees +We consider our employees to be our primary strength and we make considerable efforts to maintain a well-qualified workforce. Our employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. We regularly provide transportation, medical services, and meals to all of our employees in foreign locations. The Company also has defined contribution plans available to U.S. employees who have attained age 21 and provide group health, life, and disability insurance plans. We also maintain share based compensation plans and other long-term incentive plans for certain employees and outside directors. +As of June 29, 2019 we had 4,067 full-time employees compared to 4,701 on June 30, 2018 , and 5,038 on July 1, 2017 . Since we can have significant fluctuations in product demand, we seek to maintain flexibility in our workforce by utilizing skilled temporary labor in some of our manufacturing facilities in addition to full-time employees. +Backlog +On July 27, 2019 our order backlog was valued at approximately $159.48 million, compared to approximately $167.7 million on July 28, 2018. The amount of backlog is not necessarily indicative of future sales but can be indicative of trends in expected future sales revenue. Due to the relationships with our customers, we will occasionally allow orders to be canceled or rescheduled and as a result it is not a meaningful indicator of future financial results. If there are canceled or rescheduled orders, we typically negotiate fees to cover the costs we have incurred. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change due to design modifications, customer forecast changes, or other customer requirements. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in Note 12, “Enterprise-Wide Disclosures” of the consolidated financial statements of this Annual Report on Form 10-K and that information is incorporated herein. +6 +Executive Officers of the Registrant +The table below sets forth the name, current age and current position of our executive officers and other significant employees: +Name +Age +Positions Held +Executive Officers +Craig D. Gates +60 +President and Chief Executive Officer +Brett R. Larsen +46 +Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Douglas G. Burkhardt +61 +Executive Vice President of Worldwide Operations +Philip S. Hochberg +57 +Executive Vice President of Business Development +David H. Knaggs +38 +Vice President of Quality and Regulatory Affairs +Duane D. Mackleit +51 +Vice President of Program Management +Chad T. Orebaugh +48 +Vice President of Engineering +Thomas Despres +57 +Vice President of Southwest Operations +Mark Courtney +53 +Vice President of Supply Chain +Executive Officers +CRAIG D. GATES – President and Chief Executive Officer +Mr. Gates, age 60 , has been President and Chief Executive officer of the Company since April 2009. Previously, he was Executive Vice President and General Manager from August 2002 to April 2009. He served as Executive Vice President of Marketing, Engineering and Sales from July 1997 to August 2002 and served as Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of 1994. From 1982 to 1991 he held various engineering and management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. Mr. Gates has a Bachelor of Science Degree in Mechanical Engineering and a Masters in Business Administration from the University of Illinois, Urbana. +BRETT R. LARSEN – Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Mr. Larsen, age 46 , has served as Executive Vice President of Administration, Chief Financial Officer, and Treasurer since July 2015. Previously, he was Vice President of Finance and Controller from February 2010 to July 2015. He was Chief Financial Officer of FLSmidth Spokane, Inc. from December 2008 to February 2010. From October 2005 through November 2008, Mr. Larsen served as Controller of Key Tronic Corporation. From May 2004 to October 2005, Mr. Larsen served as Manager of Financial Reporting of Key Tronic Corporation. From 2002 to May 2004, Mr. Larsen was an audit manager for the public accounting firm BDO USA, LLP. He also held various auditing and supervisory positions with Grant Thornton LLP from 1997 to 2002. Mr. Larsen has a Bachelor of Science degree in Accounting and a Masters degree in Accounting from Brigham Young University and is a Certified Public Accountant. +DOUGLAS G. BURKHARDT – Executive Vice President of Worldwide Operations +Mr. Burkhardt, age 61 , has been Executive Vice President of Worldwide Operations of the Company since July 2010. Previously Mr. Burkhardt was Vice President of Worldwide Operations from July 2008 to July 2010 and Director of China Operations and Program Management from January 2006 to July 2008. Mr. Burkhardt also served as Director of Northwest and China Operations from November of 1998 to January of 2006. Mr. Burkhardt also served as Director of Customer Satisfaction from March 1997 to November 1998 and Director of Molding from September of 1995 to March of 1997. Prior to this, Mr. Burkhardt served in other various senior management positions within the Company. Mr. Burkhardt has been with the Company since May of 1989. Prior to joining Key Tronic, Mr. Burkhardt worked for House of Aluminum and Glass for 12 years where he was the plant manager. +PHILIP S. HOCHBERG – Executive Vice President of Business Development +Mr. Hochberg, age 57 , has been Executive Vice President of Business Development since July 2012. Prior to this, Mr. Hochberg served as Vice President of Business Development from October 2009 through June 2012. He was Director of Business Development and Program Management from July 2008 to October 2009. Mr. Hochberg served as Director of Business Development from October 2004 to July 2008 and as Director of EMS Sales and Marketing from July 2000 to October 2004. Prior to joining Key Tronic, Mr. Hochberg worked for Quinton Instrument Company as their Director of Marketing and Product Management from 1992 to 2000. From 1988 to 1992, he was employed by SpaceLabs Medical as their Business Development Marketing Manager. Mr. Hochberg has an MBA from the University of British Columbia, a BA in Psychology, with a minor in Business from Washington University in St. Louis. +7 +DAVID H. KNAGGS – Vice President of Quality and Regulatory Affairs +Mr. Knaggs, age 38 , has been Vice President of Quality and Regulatory Affairs since October 2016. Before joining KeyTronicEMS, Mr. Knaggs worked at Telect, Inc. from 2008 to 2016 as their Director of Engineering. Prior to that, he worked at Isothermal Systems Research as Lead Systems Engineer from 2003 to 2008. He has a Bachelor of Science degree in Mechanical Engineering with a minor in mathematics from the University of Washington. +DUANE D. MACKLEIT – Vice President of Program Management +Mr. Mackleit, age 51 , has been Vice President of Program Management of the company since July 2012. He served as Director of Program Management from July 2008 through June 2012. From May 2006 to July 2008 he served as Principal Program Manager. Prior to that, he served as Program Manager from March 2002 to May 2006 and Associate Program Manager from August 2000 to March 2002. Mr. Mackleit has also held several other positions with Key Tronic Corporation. Mr. Mackleit has an AA in Business from Spokane Falls Community College and a BA in Business/Marketing from Eastern Washington University. He also holds a MBA from Gonzaga University. +CHAD T. OREBAUGH – Vice President of Engineering +Mr. Orebaugh, age 48 , has been Vice President of Engineering since April 2017. Prior to this, Mr. Orebaugh served as Director of Engineering since May 2013. From April 2010 to May 2013, he served as Manager of Engineering. From January 2000 to April 2010 he served as Lead Mechanical Engineer. Prior to that, he served as Mechanical Engineer from October 1998 to January 2000 and Associate Mechanical Engineer since October 1997. Mr. Orebaugh holds a BA in Mechanical Engineering from Gonzaga University. +THOMAS DESPRES – Vice President of Southwest Operations +Thomas Despres, age 57, has been Vice President of Southwest Operations since November 2017. Prior to joining KeyTronicEMS, Mr. Despres worked for Gates Corporation as Plant General Manager from July 2017 to November 2017. From 2016 to 2017, he was self-employed and from 2012 to 2016 he was employed by Flextronics as Vice President Global Account Management. He has an MBA from Campbell University, and a BBA, Production Management from Ohio University in Athens. +MARK COURTNEY – Vice President of Supply Chain +Mark Courtney, age 53, has been Vice President of Supply Chain since August 2019. He returned to KeyTronicEMS in September 2015 having worked for the company in 2006. He has also served as Purchasing Manager and Director of North American Purchasing since his return. Mark worked for Amphenol Telect from 2007 to 2015 as Supply Chain manager, then ERP & Business Operations Manager. From June 2005 to March 2006 Mark worked for MRV Communications as Purchasing Manager before leaving California to relocate his family to the Inland Northwest to work for KeyTronicEMS. Prior to MRV Communications, Mark worked for Arrow Electronics as a Field Sales Representative from May 2000 to June 2005. From October 1990 to May of 2005 Mark worked as Purchasing Manager for Apogee Electronics. His career in electronics manufacturing and procurement began in October 1991 working for Alesis Studio Electronics where he worked in various procurement and scheduling roles, leaving in October 1999 as Purchasing Manager. +Available Information +Our principal executive offices are located at 4424 North Sullivan Road, Spokane Valley, Washington 99216, and our telephone number is (509) 928-8000. Our website is located at http://www.keytronic.com where filings of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or current reports on Form 8-K are available after they have been filed with the Securities and Exchange Commission. The information presented on our website currently and in the future is not considered to be part of this document or any document incorporated by reference in this document. +8 \ No newline at end of file diff --git a/raw/filings/0000719733/2019/0000719733-19-000063/item13.txt b/raw/filings/0000719733/2019/0000719733-19-000063/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..53c383c8173e603fdd7082b8a8bab4b156849a21 --- /dev/null +++ b/raw/filings/0000719733/2019/0000719733-19-000063/item13.txt @@ -0,0 +1,3 @@ +Item 13: +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions”, “Compensation Committee Interlocks and Insider Participation”, and “Directors’ Independence” in the Company’s 2019 Proxy Statement is incorporated herein by this reference. \ No newline at end of file diff --git a/raw/filings/0000719733/2019/0000719733-19-000063/item9a.txt b/raw/filings/0000719733/2019/0000719733-19-000063/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..55e09f5aca36ce715d3c639c17bbf891b9b889db --- /dev/null +++ b/raw/filings/0000719733/2019/0000719733-19-000063/item9a.txt @@ -0,0 +1,30 @@ +Item 9A: +CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +It is the responsibility of our management to establish, maintain, and monitor disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 are recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Additionally, these disclosure controls include controls and procedures that are designed to accumulate and communicate the information required to be disclosed to our Company’s Chief Executive Officer and Chief Financial Officer, allowing for timely decisions regarding required disclosures. As of the end of the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(f). Based on our assessment, we believe that as of June 29, 2019 , the Company’s disclosure controls and procedures are effective based on that criteria. +62 +Management’s Report on Internal Control over Financial Reporting +Our management has the responsibility to establish and maintain adequate internal controls over our financial reporting, as defined in Rule 13a-15(f) under the Securities and Exchange Act of 1934. Our internal controls are designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our external financial statements in accordance with generally accepted accounting principles (GAAP). +Due to inherent limitations of any internal control system, management acknowledges that there are limitations as to the effectiveness of internal controls over financial reporting and therefore recognize that only reasonable assurance can be gained from any internal control system. Accordingly, our internal control system may not detect or prevent material misstatements in our financial statements and projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, we have performed an assessment of the effectiveness of our internal controls over financial reporting as of June 29, 2019 . This assessment was based on the criteria established in Internal Control-Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that as of June 29, 2019 , the Company’s internal control over financial reporting is effective based on that criteria. +The effectiveness of the Company's internal control over financial reporting as of June 29, 2019 has been audited by BDO USA LLP, an independent registered public accounting firm, as stated in their report which is included herein. +Changes in Internal Control over Financial Reporting +There have been no significant changes in our internal controls over financial reporting during our fourth fiscal quarter ended June 29, 2019 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)). +63 +Report of Independent Registered Public Accounting Firm +Shareholders and Board of Directors +Key Tronic Corporation +Spokane Valley, Washington +Opinion on Internal Control over Financial Reporting +We have audited Key Tronic Corporation’s (the “Company’s”) internal control over financial reporting as of June 29, 2019 , based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of June 29, 2019 , based on the COSO criteria. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company as of June 29, 2019 and June 30, 2018, the related consolidated statements of income (loss), comprehensive income (loss), shareholders’ equity, and cash flows for each of the three years in the period ended June 29, 2019 , and the related notes and schedule and our report dated September 12, 2019 expressed an unqualified opinion thereon. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying “Item 9A, Management’s Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit of internal control over financial reporting in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ BDO USA, LLP +Spokane, Washington +September 12, 2019 +64 \ No newline at end of file diff --git a/raw/filings/0000719733/2019/0000719733-19-000063/rp_note.txt b/raw/filings/0000719733/2019/0000719733-19-000063/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000719733/2019/0000719733-19-000063/rpt_disclosure.txt b/raw/filings/0000719733/2019/0000719733-19-000063/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..d1ddd1a1801f59b5b63c6f8232a9f8846d103611 --- /dev/null +++ b/raw/filings/0000719733/2019/0000719733-19-000063/rpt_disclosure.txt @@ -0,0 +1,6 @@ +Related Person Transactions +In April 2007, the Board of Directors adopted a written policy and procedures for the approval or ratification of Interested Transactions with Related Parties. The policy and procedures supplement the Company’s Code of Conduct. The policy defines an “Interested Transaction” as any transaction, arrangement or relationship or series of similar transactions, arrangements or relationships (including any indebtedness or guarantee of indebtedness) in which (1) the aggregate amount involved will or may be expected to exceed $120,000 in any calendar year, (2) the Company is a participant, and (3) any Related Party has or will have a direct or indirect interest (other than solely as a result of being a director or a less than 10 percent beneficial owner of another entity). +The policy defines a “Related Party” as any (a) person who is or was (since the beginning of the last fiscal year for which the Company has filed a Form 10-K and proxy statement, even if they do not presently serve in that role) an executive officer, director or nominee for election as a director, (b) greater than 5 percent beneficial owner of the Company’s common stock, or (c) immediate family member of any of the foregoing. Immediate family member includes a person’s spouse, parents, stepparents, children, stepchildren, siblings, mothers- and fathers-in-law, sons- and daughters-in-law, and brothers- and sisters-in-law and anyone residing in such person’s home (other than a tenant or employee). +The Audit Committee is responsible for review, approval, ratification or disapproval of Interested Transactions. In determining whether to approve or ratify an Interested Transaction, the Committee will take into account, among other factors it deems appropriate, whether the Interested Transaction is on terms no less favorable than terms generally available to an unaffiliated third party under the same or similar circumstances and the extent of the Related Party’s interest in the Transaction. +During the fiscal years 2020 and 2019, the Company had no transactions with CyberOptics. During fiscal year 2018, the Company purchased surface mount technology inspection equipment from CyberOptics. The purchases by the Company during fiscal year 2018 totaled $159,600. These transactions were conducted at arm’s length in the ordinary course of business of the Company and CyberOptics, and the terms of purchase were no more favorable to the Company than purchases by unaffiliated parties from CyberOptics. +7 \ No newline at end of file diff --git a/raw/filings/0000719733/2020/0000719733-20-000061/filing.txt b/raw/filings/0000719733/2020/0000719733-20-000061/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..419468ed9e7f96d1d147048b49c7f366765779f5 --- /dev/null +++ b/raw/filings/0000719733/2020/0000719733-20-000061/filing.txt @@ -0,0 +1,1613 @@ +ktcc-20200627 +false 2020 FY --06-27 0000719733 10,759,680 56.7 609 58 — — 25,000 25,000 10,760 10,760 10,760 10,760 3 30 1 10 3 5 4.40 7.90 7.91 9.91 9.92 11.34 4.40 11.34 3 5 4 7 0000719733 2019-06-30 2020-06-27 iso4217:USD 0000719733 2019-12-28 xbrli:shares 0000719733 2020-09-04 0000719733 2020-06-27 0000719733 2019-06-29 iso4217:USD xbrli:shares 0000719733 2018-07-01 2019-06-29 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0000719733 us-gaap:InventoryValuationReserveMember 2018-07-01 2019-06-29 0000719733 us-gaap:InventoryValuationReserveMember 2017-07-02 2018-06-30 0000719733 us-gaap:InventoryValuationReserveMember 2020-06-27 0000719733 us-gaap:AllowanceForCreditLossMember 2019-06-29 0000719733 us-gaap:AllowanceForCreditLossMember 2018-06-30 0000719733 us-gaap:AllowanceForCreditLossMember 2017-07-01 0000719733 us-gaap:AllowanceForCreditLossMember 2019-06-30 2020-06-27 0000719733 us-gaap:AllowanceForCreditLossMember 2018-07-01 2019-06-29 0000719733 us-gaap:AllowanceForCreditLossMember 2017-07-02 2018-06-30 0000719733 us-gaap:AllowanceForCreditLossMember 2020-06-27 +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +____________________________________________________________ +FORM 10-K +____________________________________________________________ +☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE FISCAL YEAR ENDED JUNE 27, 2020 +OR +☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE PERIOD FROM TO +Commission File Number 0-11559 +____________________________________________________________ +KEY TRONIC CORP ORATION +(Exact name of registrant as specified in its charter) +____________________________________________________________ +Washington 91-0849125 +(State or other jurisdiction of +Incorporation or organization) (I.R.S. Employer +Identification No.) +4424 North Sullivan Road Spokane Valley, Washington 99216 +(Address of principal executive offices) (Zip Code) +( 509 ) 928-8000 +(Registrant’s telephone number, including area code) +N/A +(Former name, former address and former fiscal year, if changed since last report) +____________________________________________________________ +Securities Registered Pursuant to Section 12(b) of the Act: None +Title of each class Trading Symbol Name of each exchange on which registered +Common stock, no par value KTCC The NASDAQ Stock Market LLC +Securities Registered Pursuant to Section 12(g) of the Act: None +____________________________________________________________ +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ☐ No ☒ +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulations S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. +(Check one): +Large accelerated filer ☐ Accelerated filer ☐ +Non-accelerated filer +☒ +Smaller reporting company ☒ +Emerging growth company ☐ +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ +Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of +the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. +7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ +State the aggregate market value of the voting and non-voting common equity held by non affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. +As of December 31, 2019, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $ 56.7 million based on the closing price as reported on the NASDAQ. +Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: 10,759,680 shares of common stock were outstanding as of September 4, 2020. +____________________________________________________________ +Documents Incorporated by Reference: +Certain information is incorporated into Part III of this report by reference to the Proxy Statement for the registrant’s 2020 annual meeting of stockholders to be filed with the Securities and Exchange Commission pursuant to Regulation 14A not later than 120 days after the end of the fiscal year covered by this Form 10-K. +KEY TRONIC CORPORATION +2020 FORM 10-K +TABLE OF CONTENTS +Page No. +PART I +Item 1. +Business +4 +Item 1A. +Risk Factors +9 +Item 1B. +Unresolved Staff Comments +14 +Item 2. +Properties +15 +Item 3. +Legal Proceedings +16 +Item 4. +Mine Safety Disclosures +16 +PART II +Item 5. +Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities +16 +Item 6. +Selected Financial Data +18 +Item 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +19 +Item 7A. +Quantitative and Qualitative Disclosures about Market Risk +29 +Item 8. +Financial Statements and Supplementary Data +30-60 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +61 +Item 9A. +Controls and Procedures +61 +Item 9B. +Other Information +63 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +63 +Item 11. +Executive Compensation +63 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +63 +Item 13. +Certain Relationships and Related Transactions, and Director Independence +64 +Item 14. +Principal Accounting Fees and Services +64 +PART IV +Item 15. +Exhibits and Financial Statement Schedule +64 +Signatures +70 +3 +FORWARD-LOOKING STATEMENTS +References in this report to “the Company,” “Key Tronic,” “KeyTronicEMS,” “we,” “our,” or “us” mean Key Tronic Corporation together with its subsidiaries, except where the context otherwise requires. +This Annual Report on Form 10-K contains forward-looking statements in addition to historical information. Forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those reflected in the forward-looking statements. Risks and uncertainties that might cause such differences include, but are not limited to those outlined in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risks and Uncertainties that May Affect Future Results.” Readers are cautioned not to place undue reliance on forward-looking statements, which reflect management’s opinions only as of the date hereof. The Company undertakes no obligation to update forward-looking statements to reflect developments or information obtained after the date hereof and disclaims any obligation to do so. Readers should carefully review the risk factors described in periodic reports the Company files from time to time with the Securities and Exchange Commission, including Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. +PART I +Item 1. BUSINESS +Background +Key Tronic Corporation (dba: KeyTronicEMS Co.) was organized in 1969, as a Washington corporation that locally manufactured computer keyboards. The ability to design, build and deliver a quality product led us to become a leading independent manufacturer of keyboards for computers in the United States. Our fully integrated design, tooling, and automated manufacturing capabilities enabled us to rapidly respond to customers’ needs for keyboards in production quantities worldwide. We supported our sales growth through the development and purchase of international manufacturing facilities. As the computer keyboard market matured with increasing competition from other international providers, we determined that our business could no longer solely rely on keyboard sales. +After assessing market conditions and our strengths and capabilities, we shifted our focus from keyboard manufacturing to contract manufacturing for a wide range of products. Our unique strategic attributes are based on our core strengths of innovative design and engineering expertise in electronics, mechanical engineering, sheet metal fabrication and stamping, and precision plastics combined with high-quality, low cost production, and assembly on an international basis while providing exceptional customer service. These strengths have made our company a strong competitor in the electronic manufacturing services (EMS) market. +Our Industry and Strategy +The expansion of the EMS industry and our acquisitions have allowed us to continue to expand our customer base and the industries that we serve. The increase in new programs represents a growing portion of our revenue and a promising foundation for our future. In keeping with our long-term strategic objectives, we have been successfully building a more diversified customer portfolio, spanning a wider range of industries. We currently offer our customers the following services: integrated electronic and mechanical engineering, precision plastic molding, sheet metal fabrication, printed circuit board (PCB) and complete product assembly, component selection, sourcing and procurement, worldwide logistics, and new product testing and production all at competitive pricing due to our global footprint. We differentiate ourselves from others our size and larger in the EMS industry by providing vertical integration, a flexible and responsive approach to our customer’s changing supply demand, and complete design engineering support. +We believe that we are well positioned in the EMS industry to continue the expansion of our customer base and achieve long-term growth. Our unique blend of multinational facilities, vertical integration, centralized management, and core strengths continue to support our growth and our customers’ needs. We continue to focus on controlling operating expenses and leveraging the synergistic capabilities of our world-class facilities in the United States, Mexico, China and Vietnam. This international production capability provides our customers with the benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs, and reduced product fulfillment time. Given our competitive advantages and the growing pressure for new potential customers to move forward with their outsourcing strategies, we are strongly positioned to win new business in coming periods and grow our revenue and profits. +4 +The EMS industry is intensely competitive. Although our customer base is growing, we still have less than 1% of the potential global market and our revenue can fluctuate significantly due to reliance on a concentrated base of customers. We are planning for new customer growth in the coming quarters by securing new programs with new and existing customers, increasing our worldwide manufacturing capacity, leveraging further our design engineering capabilities and continuing to improve our manufacturing and procurement processes and capabilities. Ongoing challenges that we face include but are not limited to the following: continuing to win programs from new and existing customers, balancing capital employed, production capacity and key personnel in support of new customer programs, improving operating efficiencies, controlling costs while developing competitive pricing strategies, and successfully transitioning new program wins to full production. +Customers and Marketing +We provide a mix of manufacturing services for outsourced Original Equipment Manufacturing (OEM) products. We provide the following EMS services: product design, surface mount technologies (SMT) and pin through hole capability for printed circuit board assembly, tool making, precision plastic molding, sheet metal fabrication and painting, liquid injection molding, complex assembly, automated tape winding, prototype design and full product assembly. +Sales of the majority of our products have not historically been seasonal in nature, but may be seasonal in the future if there are changes in the types of products manufactured. Sales can, however, fluctuate significantly between quarters from changes in customers and customer demand due to the concentration of sales generated by our largest customers. +For the fiscal years 2020, 2019 and 2018, the five largest customers in each year accounted for 40%, 41% and 42% of combined total net sales, respectively. We continue to diversify our customer base by adding additional programs and customers. We expect net sales to our five largest customers as a percentage of total net sales to approximate current levels going forward. +The following table represents all customers that represented 10% or more of total net sales during the last three fiscal years: +Percentage of Net Sales by Fiscal Year +2020 2019 2018 +Customer A 18% 17% 19% +There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +We market our products and services primarily through our direct sales department which is comprised of strategically located field sales people and distributors. We also maintain relationships with several independent sales organizations to assist in marketing our EMS product lines. +Manufacturing +We have continually made investments in developing and expanding a capital equipment base to achieve vertical integration and efficiencies in our manufacturing processes. We have invested significant capital into SMT for volume manufacturing of complex printed circuit board assemblies and in our metal shop providing precision metal stamping, fabricating, and finishing. We also design and develop tooling for injection molding and sheet metal fabrication and manufacture the majority of plastic and sheet metal parts used in the products we manufacture. Additionally, we have equipment to maintain a controlled clean environment for manufacturing processes that require a high level of precise control. +We use a variety of manual and automated assembly processes in our facilities, depending upon product complexity and degree of customization. Some examples of automated processes include component insertion, SMT, selective soldering, flexible robotic assembly, automated storage tape winding, computerized vision system quality inspection, laser turrets, automated switch and key top installation, robotic welding, automated powder coat application, and automated functional testing. +Our engineering expertise and automated manufacturing processes enable us to work closely with our customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. We use computer-aided design techniques and software to assist in preparation of the tool design layout and component placement, to reduce tooling and production costs, improve component and product quality, and enhance turnaround time during product development. +We purchase materials and components for our products from many different suppliers, including both domestic and international sources. We develop close working relationships with our suppliers, many of whom have been supplying products to us for several years. +5 +Research, Development, and Engineering +As part of our long-term strategy, we are committed to supporting our customers by providing research, development, and engineering services. We have seen an increase in the success of providing design support on existing and potential customers in differentiating ourselves. These services allow us to facilitate in optimizing new product designs, and the production processes of our customers’ programs. +Research, development, and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials costs, depreciation, and allocated information technology and facilities costs. +Competition +The market for the products and services we provide is highly competitive. There are numerous competitors in the EMS industry, many of which have substantially more resources and are more geographically diverse than we are. Some of our competitors have similar international production capabilities, large financial resources and some have substantially greater manufacturing, research and development, and marketing resources. There is also competition from the manufacturing operations of our current and potential customers, who are continually evaluating the merits of manufacturing their products internally versus the advantages of outsourcing. We believe that we can currently compete favorably in these areas primarily on the basis of our international footprint, responsiveness, creativity, vertical production capability, quality, and cost. +Trademarks +Our name and logo are federally registered trademarks, and we believe they are valuable assets of our business. We operate under the trade name “KeyTronicEMS” to better identify our primary business concentration in contract manufacturing in the EMS industry. +Employees +We consider our employees to be our primary strength and we make considerable efforts to maintain a well-qualified workforce. Our employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. We regularly provide transportation, medical services, and meals to all of our employees in foreign locations. The Company also has defined contribution plans available to U.S. employees who have attained age 21 and provide group health, life, and disability insurance plans. We also maintain share based compensation plans and other long-term incentive plans for certain employees and outside directors. +As of June 27, 2020 we had 5,741 full-time employees compared to 4,067 on June 29, 2019, and 4,701 on June 30, 2018. Since we can have significant fluctuations in product demand, we seek to maintain flexibility in our workforce by utilizing skilled temporary labor in some of our manufacturing facilities in addition to full-time employees. +Backlog +On July 25, 2020 our order backlog was valued at approximately $215.3 million, compared to approximately $159.5 million on July 27, 2019. The amount of backlog is not necessarily indicative of future sales but can be indicative of trends in expected future sales revenue. Due to the relationships with our customers, we will occasionally allow orders to be canceled or rescheduled and as a result it is not a meaningful indicator of future financial results. If there are canceled or rescheduled orders, we typically negotiate fees to cover the costs we have incurred. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change due to design modifications, customer forecast changes, or other customer requirements. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in Note 12, “Enterprise-Wide Disclosures” of the consolidated financial statements of this Annual Report on Form 10-K and that information is incorporated herein. +6 +Executive Officers of the Registrant +The table below sets forth the name, current age and current position of our executive officers and other significant employees: +Name Age Positions Held +Executive Officers +Craig D. Gates 61 President and Chief Executive Officer +Brett R. Larsen 47 Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Philip S. Hochberg 58 Executive Vice President of Business Development +Duane D. Mackleit 52 Executive Vice President of Operations +David H. Knaggs 39 Vice President of Quality and Regulatory Affairs +Chad T. Orebaugh 49 Vice President of Engineering +Thomas Despres 58 +Vice President of Southwest Operations +Mark Courtney 54 +Vice President of Supply Chain +Executive Officers +CRAIG D. GATES – President and Chief Executive Officer +Mr. Gates, age 61, has been President and Chief Executive officer of the Company since April 2009. Previously, he was Executive Vice President and General Manager from August 2002 to April 2009. He served as Executive Vice President of Marketing, Engineering and Sales from July 1997 to August 2002 and served as Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of 1994. From 1982 to 1991 he held various engineering and management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. Mr. Gates has a Bachelor of Science Degree in Mechanical Engineering and a Masters in Business Administration from the University of Illinois, Urbana. +BRETT R. LARSEN – Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Mr. Larsen, age 47, has served as Executive Vice President of Administration, Chief Financial Officer, and Treasurer since July 2015. Previously, he was Vice President of Finance and Controller from February 2010 to July 2015. He was Chief Financial Officer of FLSmidth Spokane, Inc. from December 2008 to February 2010. From October 2005 through November 2008, Mr. Larsen served as Controller of Key Tronic Corporation. From May 2004 to October 2005, Mr. Larsen served as Manager of Financial Reporting of Key Tronic Corporation. From 2002 to May 2004, Mr. Larsen was an audit manager for the public accounting firm BDO USA, LLP. He also held various auditing and supervisory positions with Grant Thornton LLP from 1997 to 2002. Mr. Larsen has a Bachelor of Science degree in Accounting and a Masters degree in Accounting from Brigham Young University and is a Certified Public Accountant. +PHILIP S. HOCHBERG – Executive Vice President of Business Development +Mr. Hochberg, age 58, has been Executive Vice President of Business Development since July 2012. Prior to this, Mr. Hochberg served as Vice President of Business Development from October 2009 through June 2012. He was Director of Business Development and Program Management from July 2008 to October 2009. Mr. Hochberg served as Director of Business Development from October 2004 to July 2008 and as Director of EMS Sales and Marketing from July 2000 to October 2004. Prior to joining Key Tronic, Mr. Hochberg worked for Quinton Instrument Company as their Director of Marketing and Product Management from 1992 to 2000. From 1988 to 1992, he was employed by SpaceLabs Medical as their Business Development Marketing Manager. Mr. Hochberg has an MBA from the University of British Columbia, a BA in Psychology, with a minor in Business from Washington University in St. Louis. +7 +DUANE D. MACKLEIT – Executive Vice President of Operations +Mr. Mackleit, age 52, has been Executive Vice President of Operations since December 2019. Prior to this, Mr. Mackleit served as Vice President of Program Management since July 2012. He served as Director of Program Management from July 2008 through June 2012. From May 2006 to July 2008 he served as Principal Program Manager. Prior to that, he served as Program Manager from March 2002 to May 2006 and Associate Program Manager from August 2000 to March 2002. Mr. Mackleit has also held several other positions with Key Tronic Corporation. Mr. Mackleit has an AA in Business from Spokane Falls Community College and a BA in Business/Marketing from Eastern Washington University. He also holds a MBA from Gonzaga University. +DAVID H. KNAGGS – Vice President of Quality and Regulatory Affairs +Mr. Knaggs, age 39, has been Vice President of Quality and Regulatory Affairs since November 2017. Previously he was Vice President of Quality since October 2016. Before joining KeyTronicEMS, Mr. Knaggs worked at Telect, Inc. from 2008 to 2016 as their Director of Engineering. Prior to that, he worked at Isothermal Systems Research as Lead Systems Engineer from 2003 to 2008. He has a Bachelor of Science degree in Mechanical Engineering with a minor in mathematics from the University of Washington. +CHAD T. OREBAUGH – Vice President of Engineering +Mr. Orebaugh, age 49, has been Vice President of Engineering since April 2017. Prior to this, Mr. Orebaugh served as Director of Engineering since May 2013. From April 2010 to May 2013, he served as Manager of Engineering. From January 2000 to April 2010 he served as Lead Mechanical Engineer. Prior to that, he served as Mechanical Engineer from October 1998 to January 2000 and Associate Mechanical Engineer since October 1997. Mr. Orebaugh holds a BA in Mechanical Engineering from Gonzaga University. +THOMAS DESPRES – Vice President of Southwest Operations +Thomas Despres, age 58, has been Vice President of Southwest Operations since November 2017. Prior to joining KeyTronicEMS, Mr. Despres worked for Gates Corporation as Plant General Manager from July 2017 to November 2017. From 2016 to 2017, he was self-employed and from 2012 to 2016 he was employed by Flextronics as Vice President Global Account Management. He has an MBA from Campbell University, and a BBA, Production Management from Ohio University in Athens. +MARK COURTNEY – Vice President of Supply Chain +Mark Courtney, age 54, has been Vice President of Supply Chain of the company since August 2019. Previously, he served as Purchasing Manager and Director of North American Purchasing from September 2015 to August 2019, and as Supply Chain Manager, ERP and Business Operations Manager for Amphenol Telect from August 2007 to September 2015. From March 2006 to August 2007, he served as Senior Buyer/Planner for Honeywell Specialty Materials and from June 2005 to March 2006 as Purchasing Manager for MRV Communications. From May 2000 to June 2005, he served as a Field and Inside Sales Associate for Arrow Electronics and from October 1991 to May 2000 held various positons at Alesis. +Available Information +Our principal executive offices are located at 4424 North Sullivan Road, Spokane Valley, Washington 99216, and our telephone number is (509) 928-8000. Our website is located at http://www.keytronic.com where filings of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or current reports on Form 8-K are available after they have been filed with the Securities and Exchange Commission. The information presented on our website currently and in the future is not considered to be part of this document or any document incorporated by reference in this document. +8 +Item 1A. RISK FACTORS +There are risks and uncertainties that could affect our business. These risks and uncertainties include but are not limited to, the risk factors described below, in Item 7A: “Quantitative and Qualitative Disclosures about Market Risk” and elsewhere in this Form 10-K. +RISKS AND UNCERTAINTIES THAT MAY AFFECT FUTURE RESULTS +The following risks and uncertainties could affect our actual results and could cause results to differ materially from past results or those contemplated by our forward-looking statements. When used herein, the words “expects,” “believes,” “anticipates” and other similar expressions are intended to identify forward-looking statements. +Our operations may be subject to certain risks. +We manufacture product in facilities located in Mexico, China, Vietnam and the United States. These operations may be subject to a number of risks, including: +• difficulties in staffing, turnover and managing onshore and offshore operations; +• political and economic instability (including acts of terrorism, pandemics, civil unrest, forms of violence and outbreaks of war), which could impact our ability to ship, manufacture, and/or receive product; +• unexpected changes in regulatory requirements and laws; +• longer customer payment cycles and difficulty collecting accounts receivable; +• export duties, import controls and trade barriers (including quotas); +• governmental restrictions on the transfer of funds; +• burdens of complying with a wide variety of foreign laws and labor practices; subject to trade wars and tariffs +• our locations may be impacted by hurricanes, tornadoes, earthquakes, water shortages, tsunamis, floods, typhoons, fires, extreme weather conditions and other natural or man-made disasters. Our locations may also be impacted by future temporary closures and labor constraints as a result of COVID-19. +Our operations in certain foreign locations receive favorable income tax treatment in the form of tax credits or other incentives. In the event that such tax incentives are not extended, are repealed, or we no longer qualify for such programs, our taxes may increase, which would reduce our net income. +Additionally, certain foreign jurisdictions restrict the amount of cash that can be transferred to the U.S or impose taxes and penalties on such transfers of cash. To the extent we have excess cash in foreign locations that could be used in, or is needed by, our operations in the United States, we may incur significant penalties and/or taxes to repatriate these funds. +We may experience fluctuations in quarterly results of operations. +Our quarterly operating results have varied in the past and may vary in the future due to a variety of factors, including adverse changes in the U.S. and global macroeconomic environment, volatility in overall demand for our customers’ products, success of customers’ programs, timing of new programs, new product introductions or technological advances by us, our customers and our competitors, and changes in pricing policies by us, our customers, our suppliers, and our competitors. Our customer base is diverse in the markets they serve, however, decreases in demand, particularly from customers in certain industries could affect future quarterly results. Additionally, our customers could be adversely impacted by illiquidity in the credit markets which could directly impact our operating results. +Component procurement, production schedules, personnel and other resource requirements are based on estimates of customer requirements. Occasionally, our customers may request accelerated production that can stress resources and reduce operating margins. Conversely, our customers may abruptly lower or cancel production which may lead to a sudden, unexpected increase in inventory or accounts receivable for which we may not be reimbursed even when under contract with customers. In addition, because many of our operating expenses are relatively fixed, a reduction in customer demand can harm our gross profit and operating results. The products which we manufacture for our customers have relatively short product lifecycles. Therefore, our business, operating results and financial condition are dependent in a significant way on our ability to obtain orders from new customers and new product programs from existing customers. +Operating results can also fluctuate if changes are made to significant estimates and assumptions. Significant estimates and assumptions include the allowance for doubtful receivables, provision for obsolete and non-saleable inventory, stock-based compensation, the valuation allowance on deferred tax assets, impairment of long-lived assets, long-term incentive compensation accrual, the provision for warranty costs, and the impact of hedging activities. +9 +Due to the COVID-19 pandemic, we have seen extreme shifts in demand from our customer base. The possibility of future temporary closures and labor constraints, as well as the inability to predict customer demand, costs, and future supply chain disruptions during the rapidly changing COVID-19 environment can materially impact operating results. +We are exposed to general economic conditions, which could have a material adverse impact on our business, operating results and financial condition. +Adverse economic conditions and uncertainty in the global economy such as unstable global financial and credit markets, inflation, and recession can negatively impact our business. Unfavorable economic conditions could affect the demand for our customers’ products by triggering a reduction in orders as well as a decline in forecasts which could adversely affect our sales in future periods. Additionally, the financial strength of our customers and suppliers and their ability to obtain and rely on credit financing may affect their ability to fulfill their obligations to us and have an adverse effect on our financial results. +Adverse macroeconomic conditions as a result of COVID-19 can affect our business. The conditions can affect the Company’s ability to predict and plan for future supply chain disruptions, fluctuations in customer demand and costs, and the ability to operate as there is uncertainty over future temporary closures. +The majority of our sales come from a small number of customers and a decline in sales to any of these customers could adversely affect our business. +At present, our customer base is concentrated and could become more or less concentrated. There can be no assurance that our principal customers will continue to purchase products from us at current levels. Moreover, we typically do not enter into long-term volume purchase contracts with our customers, and our customers have certain rights to extend or delay the shipment of their orders. We, however, typically require that our customers contractually agree to buy back inventory purchased within specified lead times to build their products if not used. +The loss of one or more of our major customers, or the reduction, delay or cancellation of orders from such customers, due to economic conditions or other forces, could materially and adversely affect our business, operating results and financial condition. The contraction in demand from certain industries could impact our customer orders and have a negative impact on our operations over the foreseeable future. Additionally, if one or more of our customers were to become insolvent or otherwise unable to pay for the manufacturing services provided by us, our operating results and financial condition would be adversely affected. +We depend on a limited number of suppliers for certain components that are critical to our manufacturing processes. A shortage of these components or an increase in their price could interrupt our operations and result in a significant change in our results of operations. +We are dependent on many suppliers, including sole source suppliers, to provide key components and raw materials used in manufacturing customers’ products. We have seen supply shortages in certain electronic components. In addition, our suppliers' facilities may also experience earthquakes, tsunamis and other natural disasters which may cause a shortage of components. This can result in longer lead times and the inability to meet our customers request for flexible production and extended shipment dates. If demand for components outpaces supply, capacity delays could affect future operations. Delays in deliveries from suppliers or the inability to obtain sufficient quantities of components and raw materials could cause delays or reductions in shipment of products to our customers which could adversely affect our operating results and damage customer relationships. +Key Tronic is working closely with its employees and key suppliers to ascertain delays attributable to the COVID-19 pandemic. Potential delays in production and extended transit times of critical parts may cause a shortage of components. +We operate in a highly competitive industry; if we are not able to compete effectively in the EMS industry, our business could be adversely affected. +Competitors may offer customers lower prices on certain high volume programs. This could result in price reductions, reduced margins and loss of market share, all of which would materially and adversely affect our business, operating results, and financial condition. If we were unable to provide comparable or better manufacturing services at a lower cost than our competitors, it could cause sales to decline. In addition, competitors can copy our non-proprietary designs and processes after we have invested in development of products for customers, thereby enabling such competitors to offer lower prices on such products due to savings in development costs. +Cash and cash equivalents are exposed to concentrations of credit risk. +We place our cash with high credit quality institutions. At times, such balances may be in excess of the federal depository insurance limit or may be on deposit at institutions which are not covered by insurance. If such institutions were to become insolvent during which time it held our cash and cash equivalents in excess of the insurance limit, it could be necessary to obtain other credit financing to operate our facilities. +10 +Our ability to secure and maintain sufficient credit arrangements is key to our continued operations. +There is no assurance that we will be able to retain or renew our credit agreements in the future. In the event the business grows rapidly or there is uncertainty in the macroeconomic climate, additional financing resources could be necessary in the current or future fiscal years. There is no assurance that we will be able to obtain equity or debt financing at acceptable terms, or at all in the future. In addition, we have restrictive covenants with our financial institution which could impact how we manage our business. If we cannot meet our financial covenants, our borrowings could become immediately payable which could have a material adverse impact on our financial statements. For a summary of our banking arrangements, see Note 4 Long-Term Debt of the “Notes to Consolidated Financial Statements.” +Fluctuations in foreign currency exchange rates could increase our operating costs. +We have manufacturing operations located in Mexico and China. A significant portion of our operations are denominated in the Mexican peso and the Chinese currency, the renminbi ("RMB"). Currency exchange rates fluctuate daily as a result of a number of factors, including changes in a country's political and economic policies. Volatility in the currencies of our entities and the United States dollar could seriously harm our business, operating results and financial condition. The primary impact of currency exchange fluctuations is on the cash, receivables, payables and expenses of our operating entities. As part of our hedging strategy, we currently use Mexican peso forward contracts to hedge foreign currency fluctuations for a portion of our Mexican peso denominated expenses. We currently do not hedge expenses denominated in RMB. Unexpected losses could occur from increases in the value of these currencies relative to the United States dollar. +As a result of COVID-19, significant currency exchange fluctuations can occur causing unexpected losses. Future temporary closures of production facilities in Mexico could also cause significant changes in our ability to qualify for hedge accounting treatment of our forward contracts to hedge foreign currency fluctuations. However, given the unprecedented nature of the pandemic the FASB staff believes that an entity may apply the exception in paragraph 815-30-40-4 for rare cases caused by extenuating circumstances that are related to the nature of the forecasted transaction and are outside the control or influence of an entity to delays in the timing of the forecasted transactions if those delays are related to the effects of the COVID-19 pandemic and are considered probable to still occur. In addition, the FASB staff believes that it would be acceptable for an entity to determine that missed forecasts related to the effects of the COVID-19 pandemic need not be considered when determining whether it has exhibited a pattern of missing forecasts that would call into question its ability to accurately predict forecasted transactions and the propriety of using cash flow hedge accounting in the future for similar transactions. +Our success will continue to depend to a significant extent on our key personnel. +Our future success depends in large part on the continued service of our key technical, marketing and management personnel and on our ability to continue to attract and retain qualified production employees. There can be no assurance that we will be successful in attracting and retaining such personnel, particularly in our manufacturing locales that may be experiencing high demand for similar key personnel. The loss of key employees could have a material adverse effect on our business, operating results and financial condition. +If we are unable to maintain our technological and manufacturing process expertise, our business could be adversely affected. +The markets for our customers’ products are characterized by rapidly changing technology, evolving industry standards, frequent new product introductions and short product life cycles. The introduction of products embodying new technologies or the emergence of new industry standards can render existing products obsolete or unmarketable. Our success will depend upon our customers’ ability to enhance existing products and to develop and introduce, on a timely and cost-effective basis, new products that keep pace with technological developments and emerging industry standards and address evolving and increasingly sophisticated customer requirements. Failure of our customers to do so could substantially harm our customers’ competitive positions. There can be no assurance that our customers will be successful in identifying, developing and marketing products that respond to technological change, emerging industry standards or evolving customer requirements. +Start-up costs and inefficiencies related to new or transferred programs can adversely affect our operating results and such costs may not be recoverable if such new programs or transferred programs are canceled or don’t meet expected sales volumes. +Start-up costs, the management of labor and equipment resources in connection with the establishment of new programs and new customer relationships, and the need to obtain required resources in advance can adversely affect our gross margins and operating results. These factors are particularly evident in the ramping stages of new programs. These factors also affect our ability to efficiently use labor and equipment. We are currently managing a number of new programs. Consequently, our exposure to these factors has increased. In addition, if any of these new programs or new customer relationships were terminated, our operating results could be harmed, particularly in the short term. We may not be able to recoup these start-up costs or replace anticipated new program revenues. +11 +Customers may change production timing and demand schedules which makes it difficult for us to schedule production and capital expenditures and to maximize the efficiency of our manufacturing capacity. +Changes in demand for customer products reduce our ability to accurately estimate the future requirements of our customers. This makes it difficult to schedule production and maximize utilization of our manufacturing capacity. We must determine the levels of business that we will seek and accept from customers, set production schedules, commit to procuring inventory, and allocate personnel and resources, based on our estimates of our customers' requirements. Customers can require sudden increases and decreases in production which can put added stress on resources and reduce margins. Sudden decreases in production can lead to excess inventory on hand which may or may not be reimbursed by our customers even when under contract. +Continued growth could further lead to capacity constraints. We may need to transfer production to other facilities, acquire new facilities, or outsource production which could negatively impact gross margin. The Company has been able to manage the arrival of components in an effort to control inventory levels of customers that have seen sharp decreases in demand, as a result of COVID-19. +An adverse change in the interest rates for our borrowings could adversely affect our financial condition. +We are exposed to interest rate risk under our revolving line of credit and term loan. We currently hedge a portion of our term loan with an interest rate swap. We have not historically hedged the interest rate on our credit facility; therefore, unless we do so, significant changes in interest rates could adversely affect our results of operations. Refer to the discussion in note 4, "Long-Term Debt" to the consolidated financial statements for further details of our debt obligations. We are also exposed to interest rate risk on our factoring activities. +Compliance or the failure to comply with current and future environmental and health laws or regulations could cause us significant expense. +We are subject to a variety of domestic and foreign environmental regulations relating to the use, storage, and disposal of materials used in our manufacturing processes. If we fail to comply with any present or future regulations, we could be subject to future liabilities or the suspension of current manufacturing operations. In addition, such regulations could restrict our ability to expand our operations or could require us to acquire costly equipment, substitute materials, or incur other significant expenses to comply with government regulations. +To protect the health of its employees, the Company has implemented the recommendations of WHO and the CDC including wearing of face masks and shields, workstation arrangements to provide social distancing, temperature monitoring, enhanced worksite disinfection, spacing in cafeterias and break areas, contact management and other precautions. The Company is also in compliance with government regulations related to COVID-19. +Our stock price is volatile. +Holders of the common stock will suffer immediate dilution to the extent outstanding equity awards are exercised to purchase common stock. Our stock price may be subject to wide fluctuations and possible rapid increases or declines over a short time period. These fluctuations may be due to factors specific to us such as our stock's thinly traded nature, variations in quarterly operating results or changes in earnings estimates, or to factors relating to the EMS industry or to the securities markets in general, which, in recent years, have experienced significant price fluctuations. These fluctuations often have been unrelated to the operating performance of the specific companies whose stocks are traded. +Due to inherent limitations, there can be no assurance that our system of disclosure and internal controls and procedures will be successful in preventing all errors, theft and fraud, or in informing management of all material information in a timely manner. +Management does not expect that our disclosure controls and internal controls and procedures will prevent all errors or fraud. A control system is designed to give reasonable, but not absolute, assurance that the objectives of the control system are met. In addition, any control system reflects resource constraints and the benefits of controls must be considered relative to their costs. Inherent limitations of a control system may include: judgments in decision making may be faulty, breakdowns can occur simply because of error or mistake and controls can be circumvented by collusion or management override. Due to the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and may not be detected. +If we do not manage our growth effectively, our profitability could decline. +Our business is experiencing growth which can place considerable additional demands upon our management team and our operational, financial and management information systems. Our ability to manage growth effectively requires us to continue to implement and improve these systems; avoid cost overruns; maintain customer, supplier and other favorable business relationships during possible transition periods; continue to develop the management skills of our managers and supervisors; and continue to train, motivate and manage our employees. Our failure to effectively manage growth could have a material adverse effect on our results of operations. +12 +If our manufacturing processes and services do not comply with applicable statutory and regulatory requirements, or if we manufacture products containing design or manufacturing defects, demand for our services may decline and we may be subject to liability claims. +We manufacture and design products to our customers’ specifications, and, in some cases, our manufacturing processes and facilities may need to comply with applicable statutory and regulatory requirements. For example, medical devices that we manufacture or design, as well as the facilities and manufacturing processes that we use to produce them, are regulated by the Food and Drug Administration and non-U.S. counterparts of this agency. In addition, our customers’ products and the manufacturing processes that we use to produce them often are highly complex. As a result, products that we manufacture may at times contain manufacturing or design defects, and our manufacturing processes may be subject to errors or not be in compliance with applicable statutory and regulatory requirements. Defects in the products we manufacture or design, whether caused by a design, manufacturing or component failure or error, or deficiencies in our manufacturing processes, may result in delayed shipments to customers or reduced or canceled customer orders. If these defects or deficiencies are significant, our business reputation may also be damaged. The failure of the products that we manufacture or our manufacturing processes and facilities to comply with applicable statutory and regulatory requirements may subject us to legal fines or penalties and, in some cases, require us to shut down or incur considerable expense to correct a manufacturing process or facility. Our customers are required to indemnify us against liability associated with designing products to meet their specifications. However, if our customers are responsible for the defects, they may not, or may not have resources to, assume responsibility for any costs or liabilities arising from these defects, which could expose us to additional liability claims. +Energy price increases may negatively impact our results of operations. +Certain components that we use in our manufacturing process are petroleum-based. In addition, we, along with our suppliers and customers, rely on various energy sources in our transportation activities. While significant uncertainty currently exists about the future levels of energy prices, a significant increase is possible. Increased energy prices could cause an increase to our raw material costs and transportation costs. In addition, increased transportation costs related to certain suppliers and customers could be passed along to us. We may not be able to increase our product prices enough to offset these increased costs. In addition, any increase in our product prices may reduce our future customer orders and profitability. +Disruptions to our information systems, including security breaches, losses of data or outages, could adversely affect our operations. +We rely on information technology networks and systems to process, transmit and store electronic information. In particular, we depend on our information technology infrastructure for a variety of functions, including worldwide financial reporting, inventory management, procurement, invoicing and email communications. Any of these systems may be susceptible to outages due to fire, floods, power loss, telecommunications failures, terrorist attacks and similar events. Despite the implementation of network security measures, our systems and those of third parties on which we rely may also be vulnerable to computer viruses, break-ins and similar disruptions. If we or our vendors are unable to prevent such outages and breaches, our operations could be disrupted. +We are involved in various legal proceedings. +In the past, we have been notified of claims relating to various matters including contractual matters, intellectual property rights or other issues arising in the ordinary course of business. In the event of such a claim, we may be required to spend a significant amount of money to defend or otherwise address the claim. Any litigation or dispute resolution, even where a claim is without merit, could result in substantial costs and diversion of resources. Accordingly, the resolution or adjudication of such disputes, even those encountered in the ordinary course of business, could have a material effect on our business, consolidated financial conditions and results of operations. +Our levels of insurance coverage may not be sufficient for potential damages, claims or losses. +We have various forms of business and liability insurance which we believe are appropriate based on the needs of companies in our industry. As a result, not all of our potential business risks or potential losses would be covered by our insurance policies. If we sustain a significant claim or loss which is not covered by insurance, our net income could be negatively impacted. +13 +Changes in securities laws and regulations will increase our costs and risk of noncompliance. +We are required to file as an accelerated filer. As such, we are subject to additional requirements contained in the Sarbanes-Oxley Act of 2002 (the Sarbanes-Oxley Act) and more recently the Dodd-Frank Act. The Sarbanes-Oxley and Dodd-Frank Acts required or will require changes in some of our corporate governance, securities disclosure and compliance practices. In response to the requirements of the Sarbanes-Oxley and Dodd-Frank Acts, the SEC and NASDAQ promulgated new rules and additional rulemaking is expected in the future. Compliance with these new rules and future rules has increased and may increase further our legal, financial and accounting costs as well as a potential risk of noncompliance. Absent significant changes in related rules, which we cannot assure, we anticipate some level of increased costs related to these new regulations to continue indefinitely. We also expect these developments to make it more difficult and more expensive to obtain director and officer liability insurance, and we may be forced to accept reduced coverage or incur substantially higher costs to obtain coverage. Likewise, these developments may make it more difficult for us to attract and retain qualified members of our Board of Directors or qualified management personnel. Further, the costs associated with the compliance with and implementation of procedures under these and future laws and related rules could have a material impact on our results of operations. In addition, the costs associated with noncompliance with additional securities laws and regulations could also impact our business. +We may encounter complications with acquisitions, which could potentially harm our business. +Any current or future acquisitions may require additional equity financing, which could be dilutive to our existing shareholders, or additional debt financing, which could potentially affect our credit ratings. Any downgrades in our credit ratings associated with an acquisition could adversely affect our ability to borrow by resulting in more restrictive borrowing terms. To integrate acquired businesses, we must implement our management information systems, operating systems and internal controls, and assimilate and manage the personnel of the acquired operations. The integration of acquired businesses may be further complicated by difficulties managing operations in geographically dispersed locations. The integration of acquired businesses may not be successful and could result in disruption by diverting management’s attention from the core business. In addition, the integration of acquired businesses may require that we incur significant restructuring charges or other increases in our expenses and working capital requirements, which reduce our return on invested capital. +Acquisitions may involve numerous other risks and challenges including but not limited to: potential loss of key employees and customers of the acquired companies; the potential for deficiencies in internal controls at acquired companies; lack of experience operating in the geographic market or industry sector of the acquired business; constraints on available liquidity, and exposure to unanticipated liabilities of acquired companies. These and other factors could harm our ability to achieve anticipated levels of profitability at acquired operations or realize other anticipated benefits of an acquisition, and could adversely affect our consolidated business and operating results. +Changes in financial accounting standards may affect our reported financial condition or results of operations as well increase costs related to implementation of new standards and modifications to internal controls. +Our consolidated financial statements are prepared in conformity with accounting standards generally accepted in the United States, or U.S. GAAP. These principles are subject to amendments made primarily by the Financial Accounting Standards Board (FASB) and the Securities and Exchange Commission (SEC). A change in those policies can have a significant effect on our reported results and may affect our reporting of transactions which are completed before a change is announced. Changes to accounting rules or challenges to our interpretation or application of the rules by regulators may have a material adverse effect on our reported financial results or on the way we conduct business. In addition, the continued convergence of U.S. GAAP and International Financial Reporting Standards (“IFRS”) creates uncertainty as to the financial accounting policies and practices we will need to adopt in the future. +Item 1B. UNRESOLVED STAFF COMMENTS +None +14 +Item 2. PROPERTIES AS OF DATE OF FILING +We have manufacturing and sales operations located in the United States, Mexico, China and Vietnam. The table below lists the locations and square footage of our operating facilities: +Location Approx. +Sq. Ft. Type of Interest +(Leased/Owned) Description of Use +Corinth, Mississippi 350,000 Leased Manufacturing and warehouse +El Paso, Texas 80,000 Leased Shipping and warehouse +Fayetteville, Arkansas 105,000 Leased Manufacturing and warehouse +Louisville, Kentucky 2,300 Leased Administration +Oakdale, Minnesota 103,000 Leased Manufacturing and warehouse +Spokane Valley, Washington 95,000 Leased Sales, research, administration and manufacturing +Spokane Valley, Washington 36,000 Leased Manufacturing +Total USA 771,300 +Juarez, Mexico 193,000 Leased Warehouse +Juarez, Mexico 174,000 Owned Manufacturing and warehouse +Juarez, Mexico 115,000 Owned Manufacturing and warehouse +Juarez, Mexico 103,000 Owned Manufacturing and warehouse +Juarez, Mexico 72,000 Leased Manufacturing and warehouse +Juarez, Mexico 66,000 Owned Manufacturing and warehouse +Juarez, Mexico 60,000 Owned Manufacturing and warehouse +Total Mexico 783,000 +Shanghai, China 114,000 Leased Manufacturing and warehouse +Shanghai, China 8,000 Leased Manufacturing +Total China 122,000 +Da Nang, Vietnam 133,000 Leased Manufacturing and warehouse +Total Vietnam 133,000 +Grand Total 1,809,300 +(1) +The geographic diversity of these locations allows us to offer services near certain of our customers and major electronics markets with the additional benefit of reduced labor costs. We consider the productive capacity of our current facilities sufficient to carry on our current business. In addition, in Juarez, Mexico one of our buildings includes adjacent vacant land that could be developed into additional manufacturing and warehouse space. +All of our facilities are ISO certified to ISO 9001:2015 standard and to Customs Trade Partnership against Terrorism (CTPAT). In addition, the Juarez, Mexico; Shanghai, China and Spokane, Washington facilities are registered/certified to IATF 16949 automotive standard, AS 9100D aviation, space and defense standard, ISO 13485:2016 medical devices, ISO 14001:2015 environmental standard, ANSI/ESD S20.20 Electrostatic Discharge Control Program, OHSAS 18001 Occupational Health and Safety standard, and SA8000 / ISO 2600 social accountability standard. +Oakdale, Minnesota and Corinth, Mississippi are additionally registered to ISO 14001:2015 environmental standard and to ISO 13485:2016 medical devices standard. Oakdale, Minnesota is additionally registered AS9100D aviation, space and defense standard, and NADCAP certified. Oakdale, Minnesota and Fayetteville, Arkansas are additional registered to ANSI/ESD S20.20 Electrostatic Discharge Control Program. The Spokane, Washington and Juarez, Mexico facilities are additionally registered to ISO/IEC 80079-34 explosive atmospheres. The Oakdale, Minnesota; Corinth, Mississippi; Fayetteville, Arkansas and Spokane, Washington facilities are all registered by the U.S. State Department for International Traffic in Arms Regulations (ITAR). +15 +Item 3. LEGAL PROCEEDINGS +We are a party to certain lawsuits or claims in the ordinary course of business. We do not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on our financial position, results of operations or cash flow. Refer to Commitment and Contingencies footnote for further details on litigation in the fiscal year. +Item 4. MINE SAFETY DISCLOSURES +Not Applicable +PART II +Item 5: MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES +Market Information +Our common stock is traded on the NASDAQ Global Market, formerly the NASDAQ National Market System under the symbol “KTCC.” Quarterly high and low sales prices for our common stock for fiscal years 2020 and 2019 were as follows: +2020 2019 +High Low High Low +First Quarter $ 6.62 $ 4.83 $ 8.24 $ 7.41 +Second Quarter 6.48 5.27 7.61 5.33 +Third Quarter 6.99 2.51 7.30 5.59 +Fourth Quarter 5.45 2.59 6.25 4.97 +High and low stock prices are based on the daily sales prices reported by the NASDAQ Stock Market. These quotations represent prices between dealers without adjustment for markups, markdowns, and commissions, and may not represent actual transactions. +Holders and Dividends +As of June 27, 2020, we had 645 shareholders of common stock on record. As a result of our credit agreements, we are restricted from declaring or paying dividends in cash or stock without the Bank’s prior written consent. We have not paid a cash dividend and do not anticipate payment of dividends in the foreseeable future. +Equity Compensation Plan Information +Information concerning securities authorized for issuance under our equity compensation plans is set forth in Part III, Item 12 of this Annual Report, under the caption “Securities Authorized for Issuance under Equity Compensation Plans”, and that information is incorporated herein by reference. +16 +Performance Graph +Set forth below is a line graph comparing the cumulative total shareholder return on our common stock with the cumulative total return of the NASDAQ Stock Market (U.S. & Foreign) Index and the NASDAQ Electronic Components Index in fiscal 2020. +6/27/2015 7/2/2016 7/1/2017 6/30/2018 6/29/2019 6/27/2020 +Key Tronic Corporation 100.00 69.32 66.51 71.11 46.72 49.34 +NASDAQ Composite 100.00 98.32 126.14 155.91 168.04 213.32 +NASDAQ Electronic Components 100.00 106.10 152.05 200.90 200.80 272.55 +17 +Item 6: SELECTED FINANCIAL DATA +The following selected data is derived from our audited consolidated financial statements and should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the consolidated financial statements and related notes, and other information included in this report. +Financial Highlights +(In thousands, except for Supplemental Data and Per Share Amounts) +Fiscal Year Ended +June 27, 2020 June 29, 2019 June 30, 2018 July 1, 2017 July 2, 2016 +Consolidated Statements of Operations Data : +Net sales $ 449,480 $ 464,044 $ 446,322 $ 467,797 $ 484,965 +Gross profit 35,249 34,601 34,169 38,300 38,825 +Gross margin percentage 7.8 % 7.5 % 7.7 % 8.2 % 8.0 % +Operating income (loss) 6,828 (5,958) 1,114 9,544 10,416 +Operating margin percentage 1.5 % (1.3) % 0.2 % 2.0 % 2.1 % +Net income (loss) 4,758 (7,982) (1,325) 5,617 6,533 +Net income (loss) per share – diluted 0.44 (0.74) (0.12) 0.51 0.58 +Consolidated Cash Flow Data : +Cash flows provided by (used in) operations (3) +(31,004) 919 3,122 2,284 571 +Capital expenditures 8,623 8,386 4,523 9,307 13,277 +Consolidated Balance Sheet Data : +Net working capital (1) +130,545 104,695 95,607 100,440 97,349 +Total assets 304,861 238,310 246,528 232,840 235,924 +Long-term liabilities 77,085 30,447 29,534 38,520 46,232 +Shareholders’ equity 115,557 114,459 118,081 116,567 105,582 +Book value per share (2) +$ 10.74 $ 10.64 $ 10.97 $ 10.83 $ 9.84 +Supplemental Data : +Number of shares outstanding at year-end 10,759,680 10,759,680 10,759,680 10,759,680 10,725,349 +Number of employees at year-end 5,741 4,067 4,701 5,038 4,947 +Approximate square footage of operational facilities 1,809,300 1,816,300 1,837,300 1,760,000 1,828,000 +(1) Net working capital is defined as total current assets less total current liabilities. Net working capital measures the portion of current assets that are financed by long term funds and is an indicator of short term financial management. +(2) Book value per share is defined as total shareholders’ equity divided by the number of shares outstanding at the end of the fiscal year. +(3) Reflects the retrospective adoption of ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, during the year ended June 29, 2019. Please refer to Capital Resources and Liquidity section for further information. +18 +Item 7: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +Overview +KeyTronicEMS is a leader in electronic manufacturing services and solutions to original equipment manufacturers of a broad range of products. We provide engineering services, worldwide procurement and distribution, materials management, world-class manufacturing and assembly services, in-house testing, and unparalleled customer service. Our international production capability provides our customers with benefits of improved supply-chain management, reduced inventories, lower transportation costs, and reduced product fulfillment time. We continue to make investments in all of our operating facilities to give us the production capacity, capabilities and logistical advantages to continue to win new business. The following information should be read in conjunction with the consolidated financial statements included herein and with Item 1A, Risk Factors included as part of this filing. +Our mission is to provide our customers with superior manufacturing and engineering services at the lowest total cost for the highest quality products, and create long-term mutually beneficial business relationships by employing our “Trust, Commitment, Results” philosophy. +Executive Summary +During the fourth quarter of fiscal year 2020, we won new programs involving sanitizer dispensing, automotive controllers, oil and gas drilling, wireless security and personal healthcare protective equipment. A large program that we announced in the third quarter, which when fully ramped is anticipated to contribute $100 million in annual revenue, got underway in the fourth quarter and is expected to contribute to revenue in fiscal 2021. +We reported net sales of $449.5 million for fiscal year 2020 compared to net sales of $464.0 million in fiscal year 2019. During the fourth quarter of fiscal year 2020, the Company’s revenue was constrained by the temporary shutdown of its facilities in Juarez by the Mexican government due to the COVID-19 pandemic and associated delays in production. +During the past fiscal year, we overcame a number of powerful global headwinds, including component shortages, trade disputes and the COVID-19 crisis, but we see the favorable trend of contract manufacturing returning to North America accelerating. On balance, the effect of the pandemic on our customer’s demand was a net positive during the second half of fiscal 2020. While some of our customers, particularly in the gaming industry, have seen large decreases in their demand, others have significantly increased their demand, including programs for healthcare and home-oriented consumer products and exercise equipment. +As we enter fiscal 2021, uncertainty remains around the continuing impact of COVID-19 and potential future disruptions to our production facilities and we continue to focus on protecting the health of all of our employees by adhering to current health guidelines. Nevertheless, thanks to the dedication and sacrifices of our employees, we enter the year with increasingly positive momentum. We continue to invest in new capacity and remain optimistic about our long-term opportunities for growth. +For the first quarter of fiscal year 2021, the Company expects to report revenue in the range of $118 million to $125 million. While the Company’s facilities in the US, Mexico, China and Vietnam are currently operating and rigorously following current health guidelines, uncertainty as to the possibility of future temporary closures, customer demand and costs, and future supply chain disruptions during the rapidly changing COVID-19 environment could significantly impact operations in coming periods. Due to the heightened risks associated with the above, we may issue updated guidance during the first quarter of fiscal year 2021. +We continue to diversify our customer base by adding additional programs and customers. Our current customer relationships involve a variety of products, including consumer electronics, electronic storage devices, plastics, household products, gaming devices, specialty printers, telecommunications, industrial equipment, military supplies, computer accessories, medical, educational, irrigation, automotive, transportation management, robotics, RFID, power supply, off-road vehicle equipment, fitness equipment, HVAC controls, consumer products, home building products, material handling systems, lighting equipment, consumer security products, smart security, architectural LED lighting, power meters and smart grid, wireless power solutions, sanitizer dispensing, automotive controllers, oil and gas drilling, wireless security and personal healthcare protective equipment. +Gross profit as a percent of net sales was 7.8 percent in fiscal year 2020 compared to 7.5 percent for the prior fiscal year. The increase in gross profit as a percentage of net sales was primarily related to streamlining efforts in the Company’s Juarez facilities and reductions in materials, offset by COVID related expenses. The level of gross margin is impacted by product mix, timing of the startup of new programs, facility utilization, and pricing within the electronics industry and material costs, which can fluctuate significantly from quarter to quarter and year to year. +Operating income as a percentage of net sales for fiscal year 2020 was 1.5 percent compared to operating loss of (1.3) percent for fiscal year 2019. The increase in operating income as a percentage of net sales was primarily driven by the one-time impairment of goodwill and intangible assets during fiscal year 2019. +19 +Net income for fiscal year 2020 was $4.8 million or $0.44 per share, as compared to net loss of $(8.0) million or $(0.74) per share for fiscal year 2019. The increase in net income for fiscal year 2020 as compared to fiscal year 2019 was primarily driven by the one-time impairment of approximately $12.4 million related to the impairment of goodwill and intangible assets and $1.1 million in severance expense due to improvements in operating efficiencies during fiscal year 2019. +We maintain a strong balance sheet with a current ratio of 2.2 and a debt to equity ratio of 0.61. Total cash used in operating activities as defined on our cash flow statement was $31.0 million during fiscal year 2020. We maintain sufficient liquidity for our expected future operations. We believe cash flow from operations, our borrowing capacity, our accounts receivable sale program, and equipment financing should provide adequate capital for planned growth over the long term. +RESULTS OF OPERATIONS +Comparison of the Fiscal Year Ended June 27, 2020 with the Fiscal Year Ended June 29, 2019 +The following table sets forth for the periods indicated certain items of the consolidated statements of income expressed as a percentage of net sales. The financial information and discussion below should be read in conjunction with the consolidated financial statements and notes contained in this Annual Report. +Fiscal Year Ended +June 27, 2020 % of +net sales June 29, 2019 % of +net sales $ change % point +change +Net sales $ 449,480 100.0% $ 464,044 100.0% $ (14,564) — +Cost of sales 414,231 92.2 429,443 92.5 (15,212) (0.3) +Gross profit 35,249 7.8 34,601 7.5 648 0.3 +Operating expenses: +Research, development and engineering 7,391 1.6 6,555 1.4 836 0.2 +Selling, general and administrative 21,030 4.7 21,556 4.6 (526) 0.1 +Impairment of goodwill and intangibles — — 12,448 2.7 (12,448) (2.7) +Total operating expenses 28,421 6.3 40,559 8.7 (12,138) (2.4) +Operating income (loss) 6,828 1.5 (5,958) (1.3) 12,786 2.8 +Interest expense, net 2,509 0.6 2,782 0.6 (273) — +Income (loss) before income taxes 4,319 1.0 (8,740) (1.9) 13,059 2.9 +Income tax benefit (439) (0.1) (758) (0.2) 319 0.1 +Net income (loss) $ 4,758 1.1% $ (7,982) (1.7)% $ 12,740 2.8 +Effective income tax rate (10.2) % 8.7 % +Net Sales +The decrease in net sales of $14.6 million from prior year period was primarily driven by the temporary shutdown of its facilities in Juarez by the Mexican government due to the COVID-19 pandemic and associated delays in production. +The following table shows the revenue by industry sectors as a percentage of revenue for fiscal years 2020 and 2019: +Fiscal Year Ended +June 27, 2020 June 29, 2019 +Industrial 42% 44% +Consumer 44 39 +Gaming 5 8 +Communication 4 5 +Transportation 2 2 +Printers 2 1 +Computer and Peripheral 1 1 +Total 100% 100% +20 +We provide services to customers in a number of industries and produce a variety of products for our customers in each industry. Key Tronic does not target any particular industry, but rather seeks to find programs that strategically fit our vertical manufacturing capabilities. As we continue to diversify our customer base and win new customers, we will continue to see a change in the industry concentrations of our revenue. +Sales to foreign locations represented 24.6 percent and 23.0 percent of our total net sales in fiscal years 2020 and 2019, respectively. +Cost of Sales +Total cost of sales as a percentage of net sales was 92.2 percent and 92.5 percent in fiscal years 2020 and 2019, respectively. +We provide a reserve for obsolete and non-saleable inventories based on specific identification of inventory against current demand and recent usage. We also consider our customers' ability to pay for inventory whether or not there is a lead-time assurance agreement for a specific program. The amounts charged to expense for these inventories were approximately $136,000 and $91,000 in fiscal years 2020 and 2019, respectively. +We provide warranties on certain products we sell and estimate warranty costs based on historical experience and anticipated product returns. Warranty expense is related to workmanship claims on keyboards and EMS products. The amounts charged to expense are determined based on an estimate of warranty exposure. The net warranty expense was approximately $121,000 and $83,000 in fiscal years 2020 and 2019, respectively. +Gross Profit +Gross profit as a percentage of net sales was 7.8 percent and 7.5 percent in fiscal years 2020, and 2019, respectively. The 0.3 percentage point increase in gross profit as a percentage of net sales during fiscal year 2020 as compared to fiscal year 2019 is primarily related to streamlining efforts in the Company’s Juarez facilities and material cost reductions, partially offset by the dampening of fiscal year 2020 margins from the COVID-19 pandemic. +Changes in gross profit margins reflect the impact of a number of factors that can vary from period to period, including product mix, start-up costs and efficiencies associated with new programs, product life cycles, sales volumes, capacity utilization of our resources, management of inventories, component pricing and shortages, end market demand for customers’ products, fluctuations in and timing of customer orders, and competition within the EMS industry. These and other factors can cause variations in operating results. There can be no assurance that gross margins will not decrease in future periods. +We took early pay discounts to suppliers that totaled approximately $0.1 million and $0.8 million in fiscal years 2020 and 2019, respectively. Early pay discounts will fluctuate based on our liquidity and changes in the discounts and terms offered by our suppliers. +Research, Development and Engineering +Research, development and engineering expenses (RD&E) consists principally of employee related costs, third party development costs, program materials, depreciation and allocated information technology and facilities costs. Total RD&E expenses were $7.4 million in fiscal year 2020 and $6.6 million in fiscal year 2019, respectively. Total RD&E expenses as a percent of net sales was 1.6 percent in fiscal year 2020 and 1.4 in fiscal year 2019. +Selling, General and Administrative +Selling, general and administrative expenses (SG&A) consist principally of salaries and benefits, advertising and marketing programs, sales commissions, travel expenses, provision for doubtful accounts, facilities costs, and professional services. Total SG&A expenses were $21.0 million and $21.6 million in fiscal years 2020 and 2019, respectively. Total SG&A expenses as a percent of net sales were 4.7 percent and 4.6 percent in fiscal years 2020 and 2019, respectively. This 0.1 percentage point increase in SG&A as a percentage of net sales is primarily related to a decrease in sales year over year, partially offset by a decrease in travel expenses and a decrease in amortization expense related to intangibles assets that were impaired during fiscal year 2019. +Impairment of goodwill and intangibles +During fiscal year 2019, the Company assessed other finite-lived intangible assets including the Company’s customer relationships and favorable lease agreements due to an indicator of possible impairment being present, as discussed in footnote 14 of the “Notes to Consolidated Financial Statements.” As a result of the analysis performed, the Company determined that the carrying value of the customer relationships intangible asset was not recoverable and recorded an impairment for the entire carrying amount during the third quarter of fiscal year 2019. During fiscal year 2019, a goodwill impairment of $10.0 million and other intangible assets impairment of $2.5 million was recognized. The Company’s analysis did not indicate that any of its other long-lived assets were impaired. +21 +Interest Expense +We had net interest expense of $2.5 million and $2.8 million in fiscal years 2020 and 2019, respectively. The decrease in interest expense is primarily related to a decrease in the interest rate on our line of credit. +Income Tax Benefit +We had an income tax benefit of approximately $(0.4) million during fiscal year 2020 and $(0.8) million during fiscal year 2019. The income tax benefit recognized during fiscal years 2020 and 2019 was primarily a function of U.S., and foreign taxes recognized at statutory rates and the net benefit associated with federal research and development tax credits, including the recognition of previously unrecognized tax benefits for federal research and development tax credits in fiscal year 2020 and offset by the tax impact of the nondeductible goodwill write-off in fiscal year 2019. +We continually review our requirements for liquidity domestically to fund current operations, revenue growth and to look for potential future acquisitions. We anticipate repatriating a portion of our unremitted foreign earnings. The estimated taxes associated with these expected repatriations are included in the income tax calculation. For further information on taxes please review footnote 6 of the “Notes to Consolidated Financial Statements.” +International Subsidiaries +We offer customers a complete global manufacturing solution. Our facilities provide our customers the opportunity to have their products manufactured in the facility that best serves specific cost, product manufacturing and distribution needs. The locations of active foreign subsidiaries are as follows: +• Key Tronic Juarez, SA de CV owns five facilities and leases two facilities in Juarez, Mexico. These facilities include an SMT facility, an assembly and molding facility, a sheet metal fabrication facility, and assembly and warehouse facilities. This subsidiary is primarily used to support our U.S. operations. +• Key Tronic Computer Peripherals (Shanghai) Co., Ltd. leases two facilities with SMT, assembly, global purchasing and warehouse capabilities in Shanghai, China, which began operations in 1999. Its primary function is to provide EMS services for export. +• Key Tronic Vietnam leases one facility in Da Nang, Vietnam. This facility includes SMT, assembly, and warehouse capabilities. Its primary function is to provide EMS services for export. +Foreign sales (based on shipping instructions) from our worldwide operations, including domestic exports, were $110.7 million and $106.7 million in fiscal years 2020 and 2019, respectively. Products and manufacturing services provided by our subsidiary operations are often shipped to customers directly by the parent company. +RESULTS OF OPERATIONS +Comparison of the Fiscal Year Ended June 29, 2019 with the Fiscal Year Ended June 30, 2018 +To review the results of operations comparison of the fiscal year ended June 29, 2019 with the fiscal year ended June 30, 2018, please refer to our Form 10-K filed September 12, 2019 with the Securities and Exchange Commission or follow the link below. +https://www.sec.gov/ix?doc=/Archives/edgar/data/719733/000071973319000063/ktcc-06292019x10k.htm +22 +Capital Resources and Liquidity +Operating Cash Flow +Net cash used in operating activities for fiscal year 2020 was $31.0 million compared to net cash provided by operating activities of $0.9 million and $3.1 million in fiscal years 2019 and 2018, respectively. The decrease in cash provided by operating activities from prior year was primarily attributable to the Company no longer factoring receivables at year end fiscal 2020, and an increase in inventory levels. +The $31.0 million of net cash used in operating activities during fiscal year 2020 is primarily related to $4.8 million of net income adjusted for $5.6 million of depreciation and amortization, $28.3 million increase in accounts receivable, a $14.7 million increase in inventory, a $7.7 million increase in other assets, a $1.6 million increase in contract assets, partially offset by a $6.6 million increase in accounts payable and a $3.7 million increase in accrued compensation and vacation. +The $0.9 million of net cash provided by operating activities during fiscal year 2019 was primarily related to $8.0 million of net loss, $12.4 million impairment of goodwill and intangibles, $7.3 million of depreciation and amortization, $6.7 million of cash received from arbitration settlement, a $3.3 million decrease in accounts receivable, partially offset by a $10.3 million increase in contract assets, a $4.5 million increase in other assets, a $2.6 million increase in accounts payable and a $1.4 million decrease in inventory. +The $3.1 million of net cash provided by operating activities during fiscal year 2018 was primarily due to $1.3 million of net loss adjusted for $7.8 million of depreciation and amortization and $4.5 million loss on arbitration, a $22.9 million increase in accounts payable, a $1.3 million decrease in accounts receivable, partially offset by an $18.1 million increase in inventory. +Accounts receivable fluctuates based on the timing of shipments, terms offered and collections. In addition, accounts receivable will fluctuate based upon the amount of accounts receivable sold under our Trade Accounts Receivable Purchase Program. During fiscal years 2020, 2019 and 2018, we factored receivables of $41.4 million, $81.0 million and $104.7 million, respectively, from accounts receivable sold to financial institutions, which are not included on our Consolidated Balance Sheets. The Company no longer had factored receivables at year end fiscal 2020. We purchase inventory based on customer forecasts and orders, and when those forecasts and orders change, the amount of inventory may also fluctuate. Accounts payable fluctuates with changes in inventory levels, volume of inventory purchases, negotiated supplier terms, and taking advantage of early pay discounts. +Investing Cash Flow +Cash flows used in investing activities were $3.6 million for fiscal year 2020. Cash flows used in investing activities were $1.9 million for fiscal year 2019 and cash flows provided by investing activities were $4.9 million in fiscal year 2018. Our primary use of cash in investing activities during fiscal years 2020, 2019 and 2018, was purchasing equipment to support increased production levels for new programs, and our primary source of cash provided by investing activities came from receipts of the deferred purchase price on factored receivables. +Operating and capital leases are often utilized when potential technical obsolescence and funding requirement advantages outweigh the benefits of equipment ownership. Capital expenditures and periodic lease payments are expected to be financed with internally generated funds and available borrowing capacities. During fiscal years 2020 and 2019, we did not receive any cash resulting from the sale and leaseback of equipment under operating leases. During fiscal year 2018, we received $1.0 million of cash resulting from the sale and leaseback of equipment under operating leases. +Financing Cash Flow +Cash flows provided by financing activities were $34.5 million in fiscal year 2020, cash flows provided by financing activities were $1.2 million in fiscal year 2019 and cash flows used in financing activities were $8.0 million in fiscal year 2018. Our primary financing activities during fiscal year 2020, were repayments on our term loans of $7.1 million as well as borrowings and repayments under our revolving line of credit facility. Our primary financing activities during fiscal year 2019 was repayments on our term loans of $5.9 million as well as borrowings and repayments under our revolving line of credit facility. Our primary financing activities during fiscal year 2018 was repayments on our term loans of $5.9 million as well as borrowings and repayments under our revolving line of credit facility. +As of June 27, 2020, the Company had an outstanding balance on the line of credit of $60.1 million. We had availability to borrow an additional $4.5 million under the Wells Fargo line of credit and we were in compliance with our loan covenants. Our cash requirements are affected by the level of current operations and new EMS programs. We believe that projected cash from operations, funds available under the revolving credit facility and fixed asset financing will be sufficient to meet our working and fixed capital requirements for the foreseeable future. +23 +As of June 27, 2020, we had approximately $0.6 million of cash held by foreign subsidiaries. Under the Tax Cuts and Jobs Act, future cash repatriations from these foreign subsidiaries are no longer subject to U.S. income taxes, but may be subject to foreign withholding taxes. See additional discussion in Footnote 6, Income Taxes. The total amount of foreign withholding taxes required to be paid for the amount of foreign subsidiary cash on hand as of June 27, 2020, would approximate $21,000. The Company also has approximately $21.3 million of foreign earnings that have not been repatriated to the U.S. Of that amount, the Company estimates that $7.8 million is to be repatriated in the future, requiring foreign withholding taxes of $0.8 million that is currently accrued in our deferred tax liabilities. The remaining $13.5 million is considered to be permanently reinvested in Mexico and China. If these amounts were required to be repatriated, we estimate it would create an additional $0.8 million in foreign withholding taxes payable. +Contractual Obligations and Commitments +In the normal course of business, we enter into contracts which obligate us to make payments in the future. The table below sets forth our significant future obligations by fiscal year: +Payments Due by Fiscal Year (in thousands) +Total 2021 2022 2023 2024 2025 Thereafter +Term loans (1) +$ 10,871 $ 7,537 $ 2,917 $ 417 $ — $ — $ — +Wells Fargo Bank N.A. revolving loan (2) +$ 60,094 $ — $ — $ — $ 60,094 $ — $ — +Operating leases (3) +$ 19,793 $ 4,250 $ 3,373 $ 2,598 $ 2,004 $ 1,894 $ 5,674 +Purchase orders (4) +$ 46,420 +(1) The terms of the Wells Fargo Bank N.A. term loans are discussed in the consolidated financial statements at Note 4, “Long-Term Debt.” Principal on the term loan is payable in quarterly installments of $1.67 million commencing December 31, 2019 through September 30, 2021, and quarterly payments of $0.4 million commencing December 31, 2021 through September 30, 2022, with a final installment of all remaining unpaid principal due on September 30, 2022. The equipment term loan is payable in equal quarterly payments of approximately $0.2 million which commenced on March 31, 2017 and will continue through the maturity of the equipment term loan on June 30, 2021. The Company’s debt was paid in full in conjunction with the closing of a new credit facility subsequent to June 27, 2020. Refer to footnote 17 - Subsequent Events for additional details. +(2) The terms of the Wells Fargo Bank N.A. revolving loan are discussed in the consolidated financial statements at Note 4, “Long-Term Debt.” As of June 27, 2020, we were in compliance with our loan covenants. The Company’s debt was paid in full in conjunction with the closing of a new credit facility subsequent to June 27, 2020. Refer to footnote 17 - Subsequent Events for additional details. +(3) We maintain vertically integrated manufacturing operations in the United States, Mexico, China and Vietnam. We lease some of our administrative and manufacturing facilities and equipment. A complete discussion of properties can be found in Part 1, Item 2 at “Properties.” Leases have proven to be an acceptable method for us to acquire new or replacement equipment and to maintain facilities with a minimum impact on our short term cash flows for operations. In addition, such operations are heavily dependent upon technically superior manufacturing equipment including molding machines in various tonnages, Surface Mount Technology (SMT) lines, sheet metal fabrication and stamping machines, clean rooms, and automated insertion, and test equipment for the various products we are capable of producing. +(4) As of June 27, 2020, we had open purchase order commitments for materials and other supplies of approximately $46.4 million. Included in the open purchase orders are various blanket orders for annual requirements. Actual needs under these blanket purchase orders fluctuate with our manufacturing levels and as such cannot be broken out between fiscal years. In addition, we have contracts with many of our customers that minimize our exposure to losses for material purchased within lead-times necessary to meet customer forecasts. Purchase orders generally can be cancelled without penalty within specified ranges that are determined in negotiations with our suppliers. These agreements depend in part on the type of materials purchased as well as the circumstances surrounding any requested cancellations. +In addition to the cash requirements presented above, we have various other accruals which are not included in the table above. For example, we owe our suppliers approximately $80.2 million for accounts payable and shipments in transit at the end of the fiscal year. We generally pay our suppliers in a range from 30 to 120 days depending on terms offered. These payments are financed by operating cash flows and our revolving line of credit. +24 +We believe that cash flows generated from operations, factoring, leasing facilities, and funds available under the revolving credit facility will satisfy cash requirements for a period in excess of 12 months and into the foreseeable future. +Critical Accounting Policies and Estimates +Preparation of our consolidated financial statements requires management to make estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses. Note 1 to our consolidated financial statements describes the significant accounting policies used in the preparation of our consolidated financial statements. Management believes the most complex and sensitive judgments, because of their significance to our consolidated financial statements, result primarily from the need to make estimates about effects of matters that are inherently uncertain. The most significant areas involving management judgments are described below. Actual results in these areas could differ from management’s estimates. +Revenue +The Company specializes in services ranging from product manufacturing to engineering and tooling services. Subsequent to the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606) during the year ended June 29, 2019, the first step in its process for revenue recognition is to identify the contract with a customer. A contract is defined as an agreement between two or more parties that creates enforceable rights and obligations. A contract can be written, oral, or implied. The Company generally enters into manufacturing service agreements (“MSA”) with its customers that outlines the terms of the business relationship between the customer and the Company. This includes matters such as warranty, indemnification, transfer of title and risk of loss, liability for excess and obsolete inventory, pricing, payment terms, etc. The Company will also bid on a program-by-program basis for customers in which an executed MSA may not be in place. In these instances, as well as when we have an MSA in place, we receive customer purchase orders for specific quantities and timing of products. As a result, the Company considers its contract with a customer to be the combination of the MSA and the purchase order. The transaction price is fixed and set forth in each purchase order. In the Company's normal course of business, there are no variable pricing components, or material amounts refunded to customers in the form of refunds or rebates. +The Company assesses whether control of the product or services promised under the contract is transferred to the customer at a point in time (shipment) or over time (as we manufacture the product). The Company is first required to evaluate whether its contracts meet the criteria for 'over-time' or 'point-in-time' recognition. The Company has determined that for the majority of its contracts the Company is manufacturing products for which there is no alternative use due to the unique nature of the customer-specific product, IP and other contract restrictions. Further, the Company has an enforceable right to payment including a reasonable profit for performance completed to date with respect to these contracts. As a result, revenue is recognized under these contracts 'over-time' based on the input cost-to-cost method as it better depicts the transfer of control. This input method is based on the ratio of costs incurred to date as compared to the total estimated costs at completion of the performance obligation. For all other contracts that do not meet these criteria, such as manufacturing contracts for which the terms do not provide an enforceable right to payment for performance completed to date, the Company recognizes revenue when it has transferred control of the related manufactured products which generally occurs upon shipment to the customer. Revenue from engineering services is recognized over time as the services are performed +Prior to the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606), sales revenue from manufacturing is recognized upon shipment of the manufactured product per contractual terms. Upon shipment, title transfers and the customer assumes risks and rewards of ownership of the product. The price to the buyer is fixed or determinable and recoverability is reasonably assured. Unless specifically stated in contractual terms, there are no formal customer acceptance requirements or further obligations related to the manufacturing services; if any such requirements exist, then sales revenue is recognized at the time when such requirements are completed and such obligations are fulfilled. Revenue is recorded net of estimated returns of manufactured product based on management’s analysis of historical returns. Revenues and associated costs from engineering design, development services and tooling, which are performed under contract of short term durations, are recognized only after the completed performance of the service. +25 +Inactive, Obsolete, and Surplus Inventory Reserve +Inventories are stated at the lower of cost or net realizable value. Inventory valuation is determined using the first-in, first-out (FIFO) method. We reserve for inventories that we deem inactive, obsolete or surplus. This reserve is calculated based upon the demand for the products that we produce. Demand is determined by expected sales, customer purchase orders, or customer forecasts. If expected sales do not materialize, then we would have inventory in excess of our reserves and would have to charge the excess against future earnings. In the case where we have purchased material based upon a customer’s forecast or purchase orders, we are usually covered by lead-time assurance agreements or purchase orders with each customer. These contracts state that the financial liability for material purchased within agreed upon lead-time and based upon the customer’s forecasts, lies with the customer. If we purchase material outside the lead-time assurance agreement and the customer’s forecasts do not materialize or if we have no lead-time assurance agreement for a specific program, we would have the financial liability and may have to charge inactive, obsolete or surplus inventory against earnings. We also reserve for inventory related to specific customers covered by lead-time assurance agreements when those customers are experiencing financial difficulties or reimbursement is not reasonably assured. +Allowance for Doubtful Accounts +We value our accounts receivable net of an allowance for doubtful accounts. As of June 27, 2020, the allowance for doubtful accounts was approximately $609,000. As of June 29, 2019, the allowance for doubtful accounts was approximately $58,000. This allowance is based on estimates of the portion of accounts receivable that may not be collected in the future. The estimates used are based primarily on specific identification of potentially uncollectible accounts. Such accounts are identified using publicly available information in conjunction with evaluations of current payment activity. However, if any of our customers were to develop unexpected and immediate financial problems that would prevent payment of open invoices, we could incur additional and possibly material expenses that would negatively impact earnings. +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. We review the adequacy of this accrual quarterly based on historical analysis and anticipated product returns and rework costs. Our warranty period for keyboards is generally longer than that for EMS products. We only warrant materials and workmanship on EMS products, and we do not warrant design defects for EMS customers. +Income Taxes +Income tax expense includes U.S. and international income taxes and a provisional estimate for U.S. taxes on undistributed earnings of foreign subsidiaries. We do not record foreign withholding taxes on undistributed earnings of international subsidiaries that are deemed to be permanently reinvested. Certain income and expenses are not reported in tax returns and financial statements in the same year. The tax effect of such temporary differences is reported as deferred income taxes. The deferred income taxes are classified as long-term assets or liabilities. The most significant areas involving management judgments include deferred income tax assets and liabilities, uncertain tax positions, and research and development tax credits. Our estimates of the realization of the deferred tax assets related to our tax credits are based upon our estimates of future taxable income which may change. +Stock-Based Compensation +Stock-based compensation is accounted for according to Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 718, Compensation—Stock Compensation . ASC 718 requires us to expense the fair value of employee stock options, stock appreciation rights and other forms of stock-based compensation. Under the fair value recognition provisions of ASC 718, share-based compensation cost is estimated at the grant date based upon the fair value of the award and is recognized as expense ratably over the requisite service period of the award (generally the vesting period). Determining the appropriate fair value model and calculating the fair value of share-based awards requires judgment, including estimating the expected life of the share-based award, the expected stock price volatility over the expected life of the share-based award and forfeitures. +26 +To determine the fair value of stock based awards on the date of grant we use the Black-Scholes option-pricing model. Inherent in this model are assumptions related to expected stock price volatility, option life, risk-free interest rate and dividend yield. The risk-free interest rate is a less-subjective assumption as it is based on factual data derived from public sources. We use a dividend yield of zero as we have never paid cash dividends and have no intention to pay cash dividends in the foreseeable future. The expected stock price volatility and option life assumptions require a greater level of judgment. Our expected stock-price volatility assumption is based upon the historical volatility of our stock which is obtained from public data sources. The expected life represents the weighted average period of time that share-based awards are expected to be outstanding, giving consideration to vesting schedules and historical exercise patterns. We determine the expected life assumption based upon the exercise and post-vesting behavior that has been exhibited historically, adjusted for specific factors that may influence future exercise patterns. If expected volatility or expected life were to increase, that would result in an increase in the fair value of our stock options which would result in higher compensation charges, while a decrease in volatility or the expected life would result in a lower fair value of our stock option awards resulting in lower compensation charges. +We estimate forfeitures for all of our awards based upon historical experience of stock-based pre-vesting forfeitures. We believe that our estimates are based upon outcomes that are reasonably likely to occur. If actual forfeitures are higher than our estimates it would result in lower compensation expense and to the extent the actual forfeitures are lower than our estimate we would record higher compensation expense. +Impairment of Long-Lived Assets +Long-lived assets, such as property, plant, and equipment are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment charge would be recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. +Derivatives and Hedging Activity +Derivatives are recognized on the balance sheet at their estimated fair value. On the date a derivative contract is entered into, the Company designates the derivative as a hedge of a forecasted transaction or of the variability of cash flows to be received or paid related to a recognized asset or liability (a “cash flow” hedge). The Company does not enter into derivatives for speculative purposes. Changes in the fair value of a derivative that qualifies as a cash flow hedge are recorded in “Accumulated Other Comprehensive Income,” until earnings are affected by the variability of cash flows. See Note 10 of the Company’s consolidated financial statements for additional information. +Long-Term Incentive Compensation Accrual +Long-term incentive compensation is recognized as expense ratably over the requisite service period of the award which is generally three years. The Board of Directors approve target performance measures for the three year period for each of the Company’s officers and non-employee Directors. Performance measures are based on a combination of sales growth targets and return on invested capital targets. No cash awards will be made to participants if actual Company performance does not exceed the minimum target performance measures. The calculation used to determine the necessary accrual uses a combination of actual results and projected results. We believe that our estimates are based upon outcomes that are reasonably likely to occur. These estimates and assumptions are based on historical results as well as future expectations. Actual results could vary from our estimates and assumptions. +27 +Impairment of Goodwill +In accordance with ASC 350, Goodwill and Other Intangible Assets , goodwill is not amortized but is required to be reviewed for impairment at least annually or when events or circumstances indicate that carrying value may exceed fair value. The Company is permitted the option to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the fair value of any reporting unit is less than its corresponding carrying value. If, after assessing the totality of events and circumstances, the Company concludes that it is not more likely than not that the fair value of any reporting unit is less than its corresponding carrying value then the Company is not required to take further action. However, if the Company concludes otherwise, then it is required to perform a quantitative impairment test, including computing the fair value of the reporting unit and comparing that value to its carrying value. The Company utilizes a weighting of the income approach and a market approach in the impairment test. We also consider valuation factors including the Company's market capitalization, future discounted cash flows and an estimated control premium based upon a review of comparable market transactions. Our consideration of discounted future cash flows included assumptions regarding growth rates and margins based on our historical trends. In addition, we applied a market discount rate calculated based upon an analysis of companies similar in size. If our future cash flows do not meet our projections or there is an event that impacts our market capitalization, the assumptions used in our goodwill analysis could be negatively impacted. +Goodwill impairment would be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying value of goodwill. In the event that goodwill is impaired, an impairment charge to earnings would become necessary. The Company also has the option to bypass the qualitative assessment for goodwill in any period and proceed directly to performing the quantitative impairment test. Refer to footnote 14 for discussion of the write-off of goodwill and other intangibles that occurred during fiscal year 2019, as a result of certain triggering events being present. +New and Future Accounting Pronouncements +See Note 1 to our consolidated financial statements. +28 +Item 7A: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Interest Rate Risk +We are subject to the risk of fluctuating interest rates in the normal course of business. Our major market risk relates to our secured debt. Our revolving credit facility, term loan and equipment term loan are secured by substantially all of our assets. The interest rates applicable to our revolving credit facility and term loans fluctuate with the Wells Fargo Bank prime rate and LIBOR rates. There was outstanding $60.1 million in borrowings under our revolving credit facility and $10.9 million outstanding on our term loans as of June 27, 2020. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity” and Note 4 – “Long-Term Debt” to the Consolidated Financial Statements for additional information regarding our revolving credit facility and term loans. +During the second quarter of fiscal year 2020, we entered into an interest rate swap contract with a notional amount of $15.0 million related to the borrowings outstanding under the revolving credit facility. During the second quarter of fiscal year 2020, we also entered into an interest rate swap contract with a notional amount of $11.7 million related to the borrowings outstanding under the term loan. As of June 27, 2020, the remaining notional amount of the interest rate swap contract related to the term loan was $11.7 million. Through the use of the interest rate swap, as described above, we fixed the basis on which we pay interest, thus eliminating much of our interest rate risk. See Note 10 – “Derivative Financial Instruments” to the Consolidated Financial Statements for additional information regarding our derivative instruments. +Foreign Currency Exchange Risk +A significant portion of our operations are in foreign locations. As a result, transactions occur in currencies other than the U.S. dollar. Exchange rate fluctuations among other currencies used by us would directly or indirectly affect our financial results. We currently use Mexican peso forward contracts and swaps to hedge foreign currency fluctuations for a portion of our Mexican peso denominated expenses. There was $36.7 million of foreign currency forward contracts and swaps outstanding as of June 27, 2020. The fair value of these contracts and swaps was approximately $(0.9) million. See Note 10 – “Derivative Financial Instruments” to the Consolidated Financial Statements for additional information regarding our derivative instruments. +29 +Item 8: +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Report of Independent Registered Public Accounting Firm +Shareholders and Board of Directors +Key Tronic Corporation +Spokane Valley, Washington +Opinion on the Consolidated Financial Statements +We have audited the accompanying consolidated balance sheets of Key Tronic Corporation (the “Company”) as of June 27, 2020 and June 29, 2019, the related consolidated statements of income (loss), comprehensive income (loss), shareholders’ equity, and cash flows for each of the three years in the period ended June 27, 2020, and the related notes and schedule (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at June 27, 2020 and June 29, 2019, and the results of its operations and its cash flows for each of the three years in the period ended June 27, 2020, in conformity with accounting principles generally accepted in the United States of America. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company's internal control over financial reporting as of June 27, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) and our report dated September 11, 2020 expressed an unqualified opinion thereon. +Change in Accounting Principles +As discussed in Note 1 to the consolidated financial statements, the Company has changed its accounting method for accounting for leases in fiscal year 2020 due to the adoption of Topic 842: Leases , using a modified retrospective approach, and as discussed in Note 1 to the consolidated financial statements, the Company changed its method for recognizing revenue in fiscal year 2019 due to the adoption of Topic 606: Revenue from Contracts with Customers . +Basis for Opinion +These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. +Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. +/s/ BDO USA, LLP +We have served as the Company's auditor since 2003 +Spokane, Washington +September 11, 2020 +30 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED BALANCE SHEETS +(In thousands) +June 27, 2020 June 29, 2019 +ASSETS +Current assets: +Cash and cash equivalents $ 553 $ 601 +Trade receivables, net of allowance for doubtful accounts of $609 and $58 86,123 58,429 +Contract assets 23,753 22,161 +Inventories, net 115,020 100,431 +Other 17,315 16,477 +Total current assets 242,764 198,099 +Property, plant and equipment, net 31,764 29,413 +Operating lease right-of-use assets, net 17,568 — +Other assets: +Deferred income tax asset 10,178 7,840 +Other intangible assets, net — 657 +Other 2,587 2,301 +Total other assets 12,765 10,798 +Total assets $ 304,861 $ 238,310 +LIABILITIES AND SHAREHOLDERS ’ EQUITY +Current liabilities: +Accounts payable $ 80,204 $ 73,571 +Accrued compensation and vacation 10,428 6,759 +Current portion of debt, net 7,508 5,841 +Other 14,079 7,233 +Total current liabilities 112,219 93,404 +Long-term liabilities: +Term loans 3,258 7,091 +Revolving loan 60,094 23,356 +Operating lease liabilities 12,624 — +Deferred income tax liability 234 — +Other long-term obligations 875 — +Total long-term liabilities 77,085 30,447 +Total liabilities 189,304 123,851 +Commitments and contingencies (Note 4 and 9) +Shareholders’ equity: +Common stock, no par value—shares authorized 25,000; issued and outstanding 10,760 and 10,760 shares, respectively 46,946 46,680 +Retained earnings 70,111 65,353 +Accumulated other comprehensive (loss) income ( 1,500 ) 2,426 +Total shareholders’ equity 115,557 114,459 +Total liabilities and shareholders’ equity $ 304,861 $ 238,310 +See accompanying notes to consolidated financial statements. +31 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF INCOME (LOSS) +(In thousands, except per share amounts) +Fiscal Year Ended +June 27, 2020 June 29, 2019 June 30, 2018 +Net sales $ 449,480 $ 464,044 $ 446,322 +Cost of sales 414,231 429,443 412,153 +Gross profit 35,249 34,601 34,169 +Research, development and engineering expenses 7,391 6,555 6,186 +Selling, general and administrative expenses 21,030 21,556 22,334 +Impairment of goodwill and intangibles — 12,448 — +Loss on settlement of arbitration — — 4,535 +Total operating expenses 28,421 40,559 33,055 +Operating income (loss) 6,828 ( 5,958 ) 1,114 +Interest expense, net 2,509 2,782 2,556 +Income (loss) before income taxes 4,319 ( 8,740 ) ( 1,442 ) +Income tax benefit ( 439 ) ( 758 ) ( 117 ) +Net income (loss) $ 4,758 $ ( 7,982 ) $ ( 1,325 ) +Net income (loss) per share — Basic $ 0.44 $ ( 0.74 ) $ ( 0.12 ) +Weighted average shares outstanding — Basic 10,760 10,760 10,760 +Net income (loss) per share — Diluted $ 0.44 $ ( 0.74 ) $ ( 0.12 ) +Weighted average shares outstanding — Diluted 10,816 10,760 10,760 +See accompanying notes to consolidated financial statements. +32 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) +(In thousands) +Fiscal Year Ended +June 27, 2020 June 29, 2019 June 30, 2018 +Comprehensive income (loss): +Net income (loss) $ 4,758 $ ( 7,982 ) $ ( 1,325 ) +Other comprehensive income (loss): +Unrealized gain (loss) on hedging instruments, net of tax ( 3,926 ) 3,395 2,392 +Comprehensive income (loss) $ 832 $ ( 4,587 ) $ 1,067 +Other comprehensive income (loss) for fiscal years 2020, 2019, and 2018 is reflected net of tax provision (benefit) of approximately $( 1.1 ) million, $ 1.0 million and $ 0.7 million, respectively. +See accompanying notes to consolidated financial statements. +33 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Fiscal Year Ended +June 27, 2020 June 29, 2019 June 30, 2018 +Operating activities: +Net income (loss) $ 4,758 $ ( 7,982 ) $ ( 1,325 ) +Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities: +Goodwill and intangible assets impairment — 12,448 — +Depreciation and amortization 5,591 7,298 7,774 +Amortization of deferred loan costs 30 30 30 +Provision for obsolete inventory 136 91 31 +Provision for warranty 121 83 74 +Provision for (recovery of) doubtful accounts 551 58 ( 84 ) +Loss on disposal of assets 207 3 20 +Share-based compensation expense 266 436 447 +Deferred income taxes ( 958 ) ( 1,116 ) ( 1,562 ) +Loss on settlement of arbitration — — 4,535 +Changes in operating assets and liabilities +Trade receivables ( 28,254 ) 3,344 ( 1,327 ) +Contract assets ( 1,592 ) ( 10,255 ) — +Cash received from arbitration settlement — 6,684 — +Inventories ( 14,725 ) ( 1,417 ) ( 18,101 ) +Other assets ( 7,728 ) ( 4,490 ) ( 10,461 ) +Accounts payable 6,632 ( 2,627 ) 22,920 +Accrued compensation and vacation 3,669 ( 1,346 ) ( 1,900 ) +Other liabilities 292 ( 323 ) 2,051 +Cash provided by (used in) operating activities ( 31,004 ) 919 3,122 +Investing activities: +Purchases of property and equipment ( 8,623 ) ( 8,386 ) ( 4,523 ) +Proceeds from sale of fixed assets 696 22 1,041 +Cash receipts from deferred purchase price of factored receivables 4,350 6,455 8,335 +Cash provided by (used in) investing activities ( 3,577 ) ( 1,909 ) 4,853 +Financing activities: +Payment of financing costs ( 84 ) ( 15 ) ( 21 ) +Proceeds from issuance of long term debt 5,000 — — +Repayments of long term debt ( 7,121 ) ( 5,871 ) ( 5,871 ) +Borrowings under revolving credit agreement 177,343 181,688 187,419 +Repayments of revolving credit agreement ( 140,605 ) ( 174,554 ) ( 189,532 ) +Cash provided by (used in) financing activities 34,533 1,248 ( 8,005 ) +Net increase (decrease) in cash and cash equivalents ( 48 ) 258 ( 30 ) +Cash and cash equivalents, beginning of period 601 343 373 +Cash and cash equivalents, end of period $ 553 $ 601 $ 343 +Supplemental cash flow information: +Interest payments $ 2,483 $ 2,773 $ 2,529 +Income tax payments, net of refunds $ 683 $ ( 511 ) $ 304 +See accompanying notes to consolidated financial statements. +34 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY +(In thousands) +Shares Common +Stock Retained +Earnings Accumulated +Other +Comprehensive +Income (Loss) Total +Shareholders’ +Equity +Balances, July 1, 2017 10,760 $ 45,797 $ 73,545 $ ( 2,775 ) $ 116,567 +Net loss — — ( 1,325 ) — ( 1,325 ) +Tax rate effect reclassification — — 586 ( 586 ) — +Unrealized gain on hedging instruments, net — — — 2,392 2,392 +Share-based compensation — 447 — — 447 +Balances, June 30, 2018 10,760 $ 46,244 $ 72,806 $ ( 969 ) $ 118,081 +Net loss — — ( 7,982 ) — ( 7,982 ) +ASC 606 opening balance sheet adjustment — — 529 — 529 +Unrealized gain on hedging instruments, net — — — 3,395 3,395 +Share-based compensation — 436 — — 436 +Balances, June 29, 2019 10,760 $ 46,680 $ 65,353 $ 2,426 $ 114,459 +Net income — — 4,758 — 4,758 +Unrealized loss on hedging instruments, net — — — ( 3,926 ) ( 3,926 ) +Share-based compensation — 266 — — 266 +Balances, June 27, 2020 10,760 $ 46,946 $ 70,111 $ ( 1,500 ) $ 115,557 +See accompanying notes to consolidated financial statements. +35 +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. SIGNIFICANT ACCOUNTING POLICIES +Business +Key Tronic Corporation and subsidiaries (the Company) is engaged in electronic manufacturing services (EMS) for original equipment manufacturers (OEMs) and also manufactures keyboards and other input devices. The Company’s headquarters are located in Spokane Valley, Washington with manufacturing operations in Oakdale, Minnesota; Fayetteville, Arkansas; Corinth, Mississippi; and foreign manufacturing operations in Juarez, Mexico; Shanghai, China; and Da Nang, Vietnam. +The 2019 novel strain of coronavirus ("COVID-19") has resulted in business slowdowns or shutdowns in affected areas. In January 2020, the Company’s China facilities faced temporary shutdowns as a result of government mandates. In March 2020, these facilities began returning to full operation and the supply chain disruptions have been abating. In April 2020, the Company announced the temporary closure of its Juarez facilities, however, operations successfully resumed six days later. +Due to the COVID-19 pandemic, the Company has seen extreme shifts in demand from its customer base. The possibility of future temporary closures, as well as adverse fluctuations in customer demand, freight and expedite costs, precautionary safety expenses, collectibility of accounts, and future supply chain disruptions during the rapidly changing COVID-19 environment can materially impact operating results. Additionally, continued adverse macroeconomic conditions and significant currency exchange fluctuations can also materially impact operating results. +Reclassifications +Certain prior period reclassifications were made to conform with the current period presentation. These reclassifications had no effect on reported income, comprehensive income, cash flows, total assets, or shareholders’ equity as previously reported. +Principles of Consolidation +The consolidated financial statements include the Company and its wholly owned subsidiaries in the United States, Mexico, China and Vietnam. Intercompany balances and transactions have been eliminated during consolidation. +Use of Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates include the allowance for doubtful receivables, the provision for obsolete and non-saleable inventories, deferred tax assets and liabilities, uncertain tax positions, valuation of goodwill, impairment of long-lived assets, medical self-funded insurance liability, long-term incentive compensation accrual, the provision for warranty costs, the fair value of stock appreciation rights granted under the Company’s share-based compensation plan and purchase price allocation of acquired businesses. Due to uncertainties with respect to the assumptions and estimates, actual results could differ from those estimates. +Cash and Cash Equivalents +The Company considers investments with an original maturity of three months or less to be cash equivalents. Cash equivalents are carried at cost, which approximates fair value. The Company may have cash and cash equivalents at financial institutions that are in excess of federally insured limits from time to time. +Allowance for Doubtful Accounts +The Company evaluates the collectability of accounts receivable and records an allowance for doubtful accounts, which reduces the receivables to an amount that management reasonably estimates will be collected. A specific allowance is recorded against receivables considered to be impaired based on the Company’s knowledge of the financial condition of the customer. In determining the amount of the allowance, the Company considers several factors including the aging of the receivables, the current business environment and historical experience. After all attempts to collect a receivable have failed, the receivable is written off against the allowance. +36 +Inventories +Inventories are stated at the lower of cost or net realizable value. Inventory valuation is determined using the first-in, first-out (FIFO) method. Customer orders are based upon forecasted quantities of product manufactured for shipment over defined periods. Raw material inventories are purchased to fulfill these customer requirements. Within these arrangements, customer demands for products frequently change, sometimes creating excess and obsolete inventories. The Company regularly reviews raw material inventories by customer for both excess and obsolete quantities. Wherever possible, the Company attempts to recover its full cost of excess and obsolete inventories from customers or, in some cases, through other markets. When it is determined that the Company’s carrying cost of such excess and obsolete inventories cannot be recovered in full, a charge is taken against income for the difference between the carrying cost and the estimated realizable amount. We also reserve for inventory related to specific customers covered by lead-time assurance agreements when those customers are experiencing financial difficulties or reimbursement is not reasonably assured. +Property, Plant and Equipment +Property, plant and equipment are carried at cost and depreciated using straight-line methods over the expected useful lives of the assets. Repairs and maintenance costs are expensed as incurred. +Impairment of Goodwill +In accordance with accounting guidance on goodwill and other intangible assets, the Company evaluates goodwill for impairment at the reporting unit level annually, and whenever circumstances occur indicating that goodwill might be impaired. Upon adoption of ASU 2017-04, the Company now recognizes an impairment charge (not to exceed the total amount of goodwill allocated to the reporting unit) for the amount by which the carrying amount of a reporting unit exceeds the reporting unit’s fair value. During the third quarter of fiscal year 2019, a few large programs declined in revenue and two new programs were delayed. This decrease in the Company’s total revenue combined with book value continuing to exceed market capitalization caused a “triggering event” in which to perform a quantitative impairment analysis as of March 30, 2019. To estimate the fair value of the Company’s equity, the Company used both a market approach and an income approach, based on a discounted cash flows analysis. As of March 30, 2019, market related factors increased expected required rates of return, which also increased the Company’s discount rate used to project future cash flows. Further, push outs of the Company’s forecasted future cash flows relating to delays in customer orders adversely impacted the Company’s discounted cash flows model. As a result, a lower estimate in the Company’s fair value using these two valuation methods indicated an impairment charge. +During the third quarter of fiscal year 2019, the Company also assessed other finite-lived intangible assets including the Company’s customer relationships and favorable lease agreements due to an indicator of possible impairment being present, as discussed above. As a result of the analysis performed, the Company determined that the carrying value of the customer relationships intangible asset was not recoverable and recorded an impairment for the entire carrying amount during the third quarter of fiscal year 2019. The Company’s analysis did not indicate that any of its other long-lived assets were impaired. Refer to footnote 14 for impairment analysis for goodwill and other intangibles that occurred during fiscal year 2019, as a result of certain triggering events being present. +Impairment of Long-lived Assets +The Company, using its best estimates based on reasonable and supportable assumptions and projections, reviews assets for impairment whenever events or changes in circumstances have indicated that the carrying amount of its assets might not be recoverable. Impaired assets are reported at the lower of cost or fair value. +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. Management reviews the adequacy of this accrual quarterly based on historical analyses and anticipated product returns. +Self-funded Insurance +The Company self-funds its domestic employee health plans. The Company contracts with a separate administrative service company to supervise and administer the programs and act as its representative. The Company reduces its risk under this self-funded platform by purchasing stop-loss insurance coverage for high dollar individual claims. In addition, if the aggregate annual claims amount to more than 125 percent of expected claims for the plan year this insurance will also pay those claims amounts exceeding that level. +The Company estimates its exposure for claims incurred but not paid at the end of each reporting period and uses historical claims data supplied by the Company’s broker to estimate its self-funded insurance liability. This liability is subject to a total limitation that varies based on employee enrollment and factors that are established at each annual contract renewal. Actual claims experience may differ from the Company’s estimates. Costs related to the administration of the plan and related claims are expensed as incurred. +37 +Revenue Recognition +Prior to the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606), sales revenue from manufacturing is recognized upon shipment of the manufactured product per contractual terms. Upon shipment, title transfers and the customer assumes risks and rewards of ownership of the product. The price to the buyer is fixed or determinable and recoverability is reasonably assured. Unless specifically stated in contractual terms, there are no formal customer acceptance requirements or further obligations related to the manufacturing services; if any such requirements exist, then sales revenue is recognized at the time when such requirements are completed and such obligations are fulfilled. Revenue is recorded net of estimated returns of manufactured product based on management’s analysis of historical returns. +Subsequent to the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606) during the year ended June 29, 2019, the first step in its process for revenue recognition is to identify the contract with a customer. A contract is defined as an agreement between two or more parties that creates enforceable rights and obligations. A contract can be written, oral, or implied. The Company generally enters into manufacturing service agreements (“MSA”) with its customers that outlines the terms of the business relationship between the customer and the Company. This includes matters such as warranty, indemnification, transfer of title and risk of loss, liability for excess and obsolete inventory, pricing, payment terms, etc. The Company will also bid on a program-by-program basis for customers in which an executed MSA may not be in place. In these instances, as well as when we have an MSA in place, we receive customer purchase orders for specific quantities and timing of products. As a result, the Company considers its contract with a customer to be the combination of the MSA and the purchase order. The transaction price is fixed and set forth in each purchase order. In the Company's normal course of business, there are no variable pricing components, or material amounts refunded to customers in the form of refunds or rebates. +The Company assesses whether control of the product or services promised under the contract is transferred to the customer at a point in time (shipment) or over time (as we manufacture the product). The Company is first required to evaluate whether its contracts meet the criteria for 'over-time' or 'point-in-time' recognition. The Company has determined that for the majority of its contracts the Company is manufacturing products for which there is no alternative use due to the unique nature of the customer-specific product, IP and other contract restrictions. The Company has an enforceable right to payment including a reasonable profit for performance completed to date with respect to these contracts. As a result, revenue is recognized under these contracts 'over-time' based on the input cost-to-cost method as it better depicts the transfer of control. This input method is based on the ratio of costs incurred to date as compared to the total estimated costs at completion of the performance obligation. For all other contracts that do not meet these criteria, such as manufacturing contracts for which the terms do not provide an enforceable right to payment for performance completed to date, the Company recognizes revenue when it has transferred control of the related manufactured products which generally occurs upon shipment to the customer. Revenue from engineering services is recognized over time as the services are performed. +Shipping and Handling Fees +The Company classifies costs associated with shipping and handling fees as a component of cost of goods sold. Customer billings related to shipping and handling fees are reported as revenue. +Research, Development and Engineering +Research, development and engineering expenses include unreimbursed EMS costs as well as design and engineering costs associated with the production of EMS programs. Research, development and engineering costs are expensed as incurred. +Income Taxes +Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the estimated future tax consequences and benefits attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities for a change in tax rates is recognized in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amount that is more likely than not to be realized. +38 +We utilize a two-step approach to recognizing and measuring uncertain tax positions. The first step is to evaluate the tax position for recognition by determining if the weight of available evidence indicates it is more likely than not that the position will be sustained on audit, including resolution of related appeals or litigation processes, if any. The second step is to measure the tax benefit as the largest amount which is more than 50 % likely of being realized upon ultimate settlement. We consider many factors when evaluating and estimating our tax positions and tax benefits, which may require periodic adjustments based on new assessments and changes in estimates and which may not accurately forecast actual outcomes. Our policy is to recognize interest and penalties related to the underpayment of income taxes as a component of income tax provision. To date, we have not incurred charges for interest or penalties in relation to the underpayment of income taxes. The tax years 1997 through the present remain open to examination by the major U.S. taxing jurisdictions to which we are subject. Refer to Note 6 for further discussions. +Derivative Instruments and Hedging Activities +The Company has entered into foreign currency forward contracts and an interest rate swap which are accounted for as cash flow hedges in accordance with ASC 815, Derivatives and Hedging . The effective portion of the gain or loss on the derivative is reported as a component of accumulated other comprehensive income (AOCI) and is reclassified into earnings in the same period in which the underlying hedged transaction affects earnings. The derivative’s effectiveness represents the change in fair value of the hedge that offsets the change in fair value of the hedged item. +The Company uses derivatives to manage the variability of foreign currency fluctuations of expenses in our Mexico facilities. The foreign currency forward contracts and interest rate swaps have terms that are matched to the underlying transactions being hedged. As a result, these transactions fully offset the hedged risk and no ineffectiveness has been recorded. +The Company’s foreign currency forward contracts and interest rate swaps potentially expose the Company to credit risk to the extent the counterparties may be unable to meet the terms of the agreement. The Company minimizes such risk by seeking high quality counterparties. The Company’s counterparties to the foreign currency forward contracts and interest rate swaps are major banking institutions. These institutions do not require collateral for the contracts, and the Company believes that the risk of the counterparties failing to meet their contractual obligations is remote. The Company does not enter into derivative instruments for trading or speculative purposes. +Earnings Per Common Share +Basic earnings per common share is computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is computed by dividing net income by the combination of other potentially dilutive weighted average common shares and the weighted average number of common shares outstanding during the period using the treasury stock method. The computation assumes the proceeds from the exercise of stock options were used to repurchase common shares at the average market price during the period. The computation of diluted earnings per common share does not assume conversion, exercise, or contingent issuance of common stock equivalent shares that would have an anti-dilutive effect on earnings per share. +Foreign Currency Transactions +The functional currency of the Company’s subsidiaries in Mexico and China is the U.S. dollar. Realized foreign currency transaction gains and losses for local currency denominated assets and liabilities are included in cost of goods sold. +Fair Value of Financial Instruments +The carrying values of cash and cash equivalents, accounts receivable, current liabilities, and non current operating lease liability are reflected on the balance sheets at June 27, 2020 and June 29, 2019, reasonably approximate their fair value. The Company had an outstanding balance on the line of credit of $ 60.1 million as of June 27, 2020 and $ 23.4 million as of June 29, 2019, with a carrying value that reasonably approximates the fair value. The Company had an outstanding balance on the term loan of $ 10.0 million as of June 27, 2020 and $ 11.3 million as of June 29, 2019, with a carrying value that reasonably approximates the fair value. The equipment term loan is estimated to be $ 0.9 million as of June 27, 2020 and $ 1.7 million as of June 29, 2019, with a carrying value that reasonably approximates the fair value. +Share-based Compensation +The Company’s incentive plan may provide for equity and liability awards to employees in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, stock units, performance shares, performance units, and other stock-based or cash-based awards. Compensation cost is recognized on a straight-line basis over the requisite employee service period, which is generally the vesting period, and is included in cost of goods sold, research, development and engineering, and selling, general, and administrative expenses. Share-based compensation is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on historical experience and future expectations. +39 +Newly Adopted and Recent Accounting Pronouncements +In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes (Topic 740), which modifies certain provisions of ASC 740, Income Taxes, in an effort to reduce the complexity of accounting for income taxes. ASU 2019-12 is effective for us the first quarter of fiscal year 2022. We are currently evaluating the effects and do not believe this standard will have a material impact on our consolidated financial position, results of operations, or cash flows. +In June 2018, the FASB issued ASU 2018-07 "Compensation - Stock Compensation (Topic 718): Improvement to Nonemployee Share-Based Payment Accounting" with the objective of simplifying several aspects of the accounting for nonemployee share-based payment transactions in current GAAP. The Company adopted this guidance during the first quarter of fiscal year 2020 with an immaterial impact on its consolidated financial statements. +In August 2017, the FASB issued ASU 2017-12 "Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities" with the objective of improving the financial reporting of hedging relationships and simplifying the application of the hedge accounting guidance in current GAAP. The Company adopted this guidance during the first quarter of fiscal year 2020 with no impact on its consolidated financial statements. +In February 2016, the FASB issued Accounting Standards Update ASU 2016-02, Leases which supersedes ASC 840 Leases and creates a new topic, ASC 842 Leases. This update requires lessees to recognize a lease asset and a lease liability for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. +The Company adopted ASC 842 on June 30, 2019 using the modified retrospective method for leases existing at June 30, 2019. As a result, the Company was not required to adjust its comparative period financial information for effects of the standard or make the new required lease disclosures for periods before our adoption date. Management elected the package of practical expedients which, among other things, allows the Company to carry forward historical lease classification in place prior to June 30, 2019. ASC 842 also provides practical expedients for an entity’s accounting after transition. Management has elected the short-term lease recognition exemption for all leases that qualify, as well as the practical expedient to not separate lease and non-lease components. Both of these expedients were elected for all classes of underlying leased assets. As the Company cannot determine the interest rate implicit in the lease for its leases, the Company uses its estimate of the incremental borrowing rate as of the commencement date in determining the present value of lease payments. The Company’s estimated incremental borrowing rate is the rate of interest it would have to pay on a collateralized basis over a similar term in an amount equal to the lease payments in a similar economic environment. The lease term for all of the Company’s leases includes the noncancellable period of the lease plus any additional periods covered by either an option to extend (or not to terminate) the lease that the Company is reasonably certain to exercise. +The adoption of ASC 842 had a material impact to the Company’s consolidated balance sheet, but did not materially impact the consolidated statement of income or consolidated statement of cash flows. The most significant changes to the consolidated balance sheet relate to the recognition of new right-of-use (ROU) assets and lease liabilities for operating leases. +As a result of adopting ASC 842 as of June 30, 2019, the Company recognized an ROU asset of $21.4 million, a corresponding lease liability of $20.4 million, a reduction in prepaid rent of $0.4 million, a reduction of favorable lease agreement intangible of $0.7 million, and no adjustment to retained earnings or future P&L impact. +In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” and also issued subsequent amendments to the initial guidance: ASU 2018-19, ASU 2019-04 and ASU 2019-05, which replaces the existing incurred loss impairment model with an expected credit loss model and requires a financial asset measured at amortized cost to be presented at the net amount expected to be collected. The guidance is effective for the Company beginning in the first quarter of fiscal year 2024 with early adoption permitted. The Company is currently assessing the impact on its consolidated financial statements, and it intends to adopt the guidance when it becomes effective in the first quarter of fiscal year 2024. +The Company adopted Accounting Standards Update 2014-09 (ASU 2014-09), Revenue from Contracts with Customers (Topic 606) (also referred to as Accounting Standard Codification 606 (“ASC 606”) on July 1, 2018 using the modified retrospective approach by applying the guidance to all open contracts at the adoption date and has implemented revised accounting policies, new operational and financial reporting processes, enhanced systems capabilities and relevant internal controls. As part of adopting ASC 606, revenue for certain customer contracts where the Company is manufacturing products for which there is no alternative use and the Company has an enforceable right to payment including a reasonable profit for work-in-progress inventory will be recognized over time instead of upon shipment of products. +40 +The cumulative effect of change made to our July 1, 2018 consolidated balance sheet for the adoption of ASC 606 was as follows: +Consolidated Balance Sheet Impact of Adopting ASC 606 +(Unaudited, in thousands) Balance at June 30, 2018 Adjustments Balance at July 1, 2018 +ASSETS +Contract assets — 11,906 11,906 +Inventories 110,315 ( 11,210 ) 99,105 +Deferred income tax asset 7,882 ( 167 ) 7,715 +LIABILITIES AND SHAREHOLDERS’ EQUITY +Retained earnings 72,806 529 73,335 +The following tables summarize the impacts of ASC 606 adoption on the Company’s consolidated balance sheets and consolidated statements of income (loss): +Consolidated Balance Sheet +As of June 29, 2019 Impact of Adopting ASC 606 +(Unaudited, in thousands) As Reported 606 Adjustment Balance without 606 Adoption +ASSETS +Contract assets 22,161 ( 22,161 ) — +Inventories 100,431 19,563 119,994 +Deferred income tax asset 7,840 167 8,007 +LIABILITIES AND SHAREHOLDERS’ EQUITY +Retained earnings 65,353 2,431 62,922 +Consolidated Statement of Income (Loss) +Impact of Adopting ASC 606 +(Unaudited, in thousands) Twelve Months Ended June 29, 2019 +As Reported 606 Adjustment Balance without 606 Adoption +Net sales $ 464,044 $ 10,254 $ 453,790 +Cost of sales $ 429,443 $ 8,353 $ 421,090 +Gross profit $ 34,601 $ 1,901 $ 32,700 +Net income $ ( 7,982 ) $ 1,901 $ ( 9,883 ) +For the fiscal year ended June 29, 2019, the reported revenue and gross profit was approximately $ 464.0 million, and $ 34.6 million; respectively. This reflects the adoption of ASC 606 as revenue and gross profit would have been $ 10.3 million and $ 1.9 million less without ASC 606 adoption; respectively. This is primarily due to the change from 'point-in-time' to 'over-time' recognition as the standard requires. There was not a material tax impact for the twelve months ended June 29, 2019 from adopting ASC 606. +Fiscal Year +The Company operates on a 52/53 week fiscal year. Fiscal years end on the Saturday nearest June 30. As such, fiscal years 2020, 2019, and 2018, ended on June 27, 2020, June 29, 2019, and June 30, 2018, respectively. Fiscal year 2020, 2019 and 2018 were all 52 week years. +41 +2. INVENTORIES +The components of inventories consist of the following (in thousands): +June 27, 2020 June 29, 2019 +Finished goods $ 15,269 $ 11,969 +Work-in-process 17,390 11,705 +Raw materials and supplies 82,361 76,757 +$ 115,020 $ 100,431 +Total inventory as of June 27, 2020 is net of $ 17.3 million of reserves, customer payments, and customer deposits compared to $ 10.8 million in reserves, customer payments, and customer deposits as of June 29, 2019. +3. PROPERTY, PLANT AND EQUIPMENT +Property, plant and equipment consists of the following: +Life June 27, 2020 June 29, 2019 +(in years) (in thousands) +Land — $ 4,034 $ 2,940 +Buildings and improvements 3 to 30 23,444 23,776 +Equipment 1 to 10 72,151 67,348 +Furniture and fixtures 3 to 5 4,883 4,248 +Total Property, Plant and Equipment 104,512 98,312 +Accumulated depreciation ( 72,748 ) ( 68,899 ) +Property, Plant and Equipment, net $ 31,764 $ 29,413 +4. LONG-TERM DEBT +On March 5, 2020, the Company entered into a Seventh amendment to the amended and restated credit agreement extending the limit on our line of credit facility to $ 65.0 million. Outside of the limit increase of the credit facility, the agreement reflects the same specifications and terms as the sixth amendment to the amended and restated credit agreement entered into by the Company on November 20, 2019; discussed below. As of June 27, 2020, the Company had an outstanding balance under the credit facility of $ 60.1 million, $ 0.4 million in outstanding letters of credit and $ 4.5 million available for future borrowings. As of June 29, 2019, the Company had an outstanding balance under the credit facility of $ 23.4 million, $ 0.4 million in outstanding letters of credit and $ 21.3 million available for future borrowings. The Company's debt was paid in full in conjunction with the closing of a new credit facility subsequent to June 27, 2020. Refer to footnote 17 - Subsequent Events for additional details. +On November 20, 2019, the Company entered into a Sixth amendment to the amended and restated credit agreement extending the limit on our line of credit facility to $ 55.0 million as evidenced by the Second Replacement Revolving Note. The agreement specifies that the proceeds of the revolving line of credit be used primarily for working capital and general corporate purposes. The line of credit is secured by substantially all of the assets of the Company. On September 30, 2018, the Company entered into a Fourth amendment to the amended and restated credit agreement to extend the maturity date to November 1, 2023, at which time all outstanding balances are payable. +On September 10, 2019, the Company entered into a Fifth amendment to the amended and restated credit agreement to increase the outstanding balance on the term loan in the amount of $ 5.0 million and to extend the maturity date to September 30, 2022 on the original term loan in the amount of $ 35.0 million that was used to acquire all of the outstanding shares of CDR Manufacturing, Inc. (dba Ayrshire Electronics). The term loan requires quarterly payments of $ 1.67 million commencing December 31, 2019 through September 30, 2021, and quarterly payments of $ 0.4 million commencing December 31, 2021 through September 30, 2022, with a final payment of the remaining outstanding balance on September 30, 2022. The Company had an outstanding balance of $ 10.0 million and $ 11.3 million under the term loan as of June 27, 2020 and June 29, 2019, respectively. +42 +On December 28, 2016, the Company entered into an equipment term loan agreement in the amount of $ 3.9 million in order to further invest in production equipment. The equipment term loan is collateralized by production equipment. Under this loan agreement, equal quarterly payments of approximately $ 0.2 million commenced on March 31, 2017 and will continue through the maturity of the equipment term loan on June 30, 2021. Amortization of the debt issuance costs is reported as interest expense on the consolidated income statement. As of June 27, 2020, the Company had an outstanding balance of $ 0.9 million. As of June 29, 2019, the Company had an outstanding balance of $ 1.7 million. +The Fifth amendment to the amended and restated credit agreement noted above to increase the outstanding balance on the term loan in the amount of $ 5.0 million fixes borrowings under the revolving line of credit, term loan and equipment term loan to bear interest at LIBOR plus 2.0 %, as opposed to previous borrowings at either a “Base Rate” or a “Fixed Rate,” as elected by the Company. The base rate is the higher of the Wells Fargo Bank prime rate, daily one month London Interbank Offered Rate (LIBOR) plus 1.5 %, or the Federal Funds rate plus 1.5 %. The fixed rate is LIBOR plus 1.75 %, LIBOR plus 2.0 % or LIBOR plus 2.25 % depending on the level of the Company’s trailing four quarters Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA). The interest rates on the outstanding debt as of June 27, 2020 range from 2.17 % - 2.18 % compared to 4.40 % - 5.50 % as of June 29, 2019. +Debt maturities as of June 27, 2020 for the next four years are as follows (in thousands): +Fiscal Years Ending Amount +2021 $ 7,537 +2022 2,917 +2023 417 +2024 60,094 +Total debt $ 70,965 +Unamortized debt issuance costs ( 30 ) +Long-term debt, net of debt issuance costs $ 70,935 +The Company must comply with certain financial covenants, including a cash flow leverage ratio, an asset coverage ratio and a fixed charge coverage ratio. The credit agreement requires the Company to maintain a minimum profit threshold, limits the maximum capital lease expenditures and restricts the Company from declaring or paying dividends in cash or stock without prior bank approval. The Company was in compliance with all financial covenants as of June 27, 2020. +5. TRADE ACCOUNTS RECEIVABLE PURCHASE PROGRAMS +Sale Programs +The Company has utilized an Account Purchase Agreement with Wells Fargo Bank, N.A. ("WFB") which allows the Company to sell and assign to WFB and WFB may purchase from Company the accounts receivable of certain Company customers in a maximum aggregate amount outstanding of $ 25.0 million. This agreement may be cancelled at any time by either party. The Company also has an Account Purchase Agreement with Orbian Financial Services (“Orbian”). This agreement allows the Company to sell accounts receivable of certain customers to Orbian and the agreement may be cancelled at any time by either party. +Total accounts receivables sold during the twelve months ended June 27, 2020 and June 29, 2019 was approximately $ 41.4 million and $ 81.0 million, respectively. Accounts receivables sold and not yet collected was approximately $ 9,000 and $ 1.7 million as of June 27, 2020 and June 29, 2019, respectively. The receivables that were sold were removed from the consolidated balance sheets and the cash received is reflected as cash provided by operating activities in the consolidated statements of cash flows. The Company no longer had factored receivables at year end fiscal 2020. +43 +6. INCOME TAXES +Income tax benefit consists of the following: +Fiscal Year Ended +June 27, 2020 June 29, 2019 June 30, 2018 +(in thousands) +Current income tax benefit: +United States $ 365 $ ( 537 ) $ ( 221 ) +Foreign 154 895 1,722 +519 358 1,501 +Deferred income tax benefit: +United States ( 1,850 ) ( 910 ) ( 795 ) +Foreign 892 ( 206 ) ( 823 ) +( 958 ) ( 1,116 ) ( 1,618 ) +Total income tax benefit $ ( 439 ) $ ( 758 ) $ ( 117 ) +The Company has gross tax credit carryforwards of approximately $ 8.8 million at June 27, 2020 consisting of federal research and development (R&D) tax credits. +Management has reviewed all deferred tax assets for purposes of determining whether or not a valuation allowance may be required. A valuation allowance against deferred tax assets is required if it is more likely than not that some of the deferred tax assets will not be realized. Based upon the Company’s profitability, forecasted income, and evaluation of all other positive and negative evidence, management determined that it is more likely than not that the deferred tax assets will be realized. +Subsequent to the end of the fiscal year ending June 27, 2020, the Treasury Department issued final regulations applicable to the Company’s position with respect to the U.S. taxability of foreign earnings under the global intangible low taxed income (also known as “GILTI”) regime and the deductibility of interest expense under IRC Section 163(j). The Company is still evaluating the impact of these regulations, and, at this time, it does not anticipate any material impact to its current or future income tax positions. +On March 27, 2020, the Coronavirus Aid, Relief, and Economic Security Act (CARES Act) was enacted in response to the COVID-19 pandemic. The CARES Act, among other things, permits net operating loss (NOL) carryovers and carrybacks to offset 100% of taxable income for taxable years beginning before 2021. In addition, the CARES Act allows NOLs incurred in 2018, 2019, and 2020 to be carried back to each of the five preceding taxable years to generate a refund of previously paid income taxes. The Company does not expect that the NOL carryback provision of the CARES Act will result in a material cash benefit. In addition, the CARES Act contains modifications on the limitation of business interest for tax years beginning in 2019 and 2020. The modifications to Section 163(j) increase the allowable business interest deduction from 30% of adjusted taxable income to 50% of adjusted taxable income. This modification would increase the allowable interest expense deduction of the Company and result in less taxable income for fiscal year 2020, but is not expected to have a material impact on the provision for income taxes. Also, under the CARES Act, AMT credits not previously refunded for the 2018 tax year are refundable in the 2019 taxable year rather than in years 2019-2021, and taxpayers can elect to claim 100% of the AMT credits in the first taxable year beginning in 2018 by applying for a tentative refund claim on or before December 31, 2020. The Company has made this election by applying for a tentative refund claim. The Company is taking advantage of the deferred payment payroll taxes provision, the impacts of which are not expected to be material. The Company is continuing to evaluate the impacts of other aspects of the CARES Act, and at this time the Company does not believe they will have a material impact on our consolidated financial position, results of operations, or cash flows. +On December 22, 2017, the Tax Cuts and Jobs Act (“Tax Act”) was signed into law. The Tax Act reduced Federal corporate tax rates effective January 1, 2018, and changed certain other provisions, many of which were not effective until fiscal year 2019. Effective tax rates for fiscal year 2018, were blended rates reflecting the benefit of two quarters of Federal tax rate reductions. These benefits were offset by discrete expenses relating to the revaluation of our U.S. net deferred tax assets, an adjustment relating to foreign exchange, and required adjustments associated with the transition from a global to a territorial tax system (discussed further below). +As a result of the U.S. tax system under the Tax Act from a global to a territorial model, a deemed one-time repatriation of all accumulated earnings and profits (AE&P) in Mexico and China occurred on December 31, 2017 (the “Transition Tax”). +44 +On December 22, 2017, the staff of the SEC issued Staff Accounting Bulletin No. 118 (“SAB No. 118”). SAB No. 118 provided guidance on accounting for the tax effects of the 2017 Tax Act and allowed registrants to record provisional amounts for a period of up to one year from the date of enactment of the 2017 Tax Act. In fiscal year 2019, we finalized the Transition Tax calculation, resulting in a net Transition Tax amount of $ 0.8 million, a decrease of $ 0.4 million for the fiscal year. +In addition to the $ 0.8 million Transition Tax described above, the Company recognized a $ 1.3 million discrete expense in fiscal year 2018 due to the revaluation of our U.S. net deferred tax assets. Offsetting these amounts, because of the shift to a territorial system of taxation in the U.S., the Company recognized a discrete benefit of approximately $ 1.3 million related to reversing its previously recognized estimated liability associated with estimated future repatriations from Mexico and China. +In future years, because of the Transition Tax on AE&P described above, repatriations of cash will generally be tax-free in the U.S. However, withholding taxes in China may still apply to any such future repatriations. Management has not changed its indefinite investment assertions with regards to the portion of AE&P in China that may be repatriated in the future. Accordingly, management estimates that future repatriations of cash from China may result in approximately $ 0.8 million of withholding tax. There would be no offsetting foreign tax credits in the U.S. and as such, this potential liability is a direct cost associated with actual repatriations. Withholding taxes will not apply to future repatriations from Mexico or Vietnam. +The Company expects to repatriate a portion of its foreign earnings based on increased net sales growth driving additional capital requirements domestically, cash requirements for potential acquisitions and to implement certain tax strategies. The Company expects to repatriate approximately $ 7.8 million from China, in the future. All other unremitted foreign earnings are expected to remain permanently reinvested for planned fixed assets purchases and improvements in foreign locations. +The Company’s effective tax rate differs from the federal tax rate as follows: +Fiscal Year Ended +June 27, 2020 June 29, 2019 June 30, 2018 +(in thousands) +Federal income tax provision (benefit) at statutory rates $ 907 $ ( 1,836 ) $ ( 397 ) +State income taxes, net of federal tax effect 90 ( 158 ) ( 4 ) +Foreign tax rate differences 336 251 103 +Tax rate change — — 1,634 +Provisional transition tax on accumulated foreign earnings — ( 384 ) 1,190 +Effect of income tax credits ( 310 ) ( 861 ) ( 687 ) +Previously unrecognized tax benefits ( 1,345 ) — — +Effect of repatriation of foreign earnings, net — ( 42 ) ( 1,484 ) +Goodwill write-off — 1,726 — +Global Intangible Low-Taxed Income (GILTI) tax — 150 — +Provision to return reconciliation ( 241 ) 630 ( 401 ) +Other 124 ( 234 ) ( 71 ) +Income tax benefit $ ( 439 ) $ ( 758 ) $ ( 117 ) +The domestic and foreign components of income (loss) before income taxes were: +Fiscal Year Ended +June 27, 2020 June 29, 2019 June 30, 2018 +(in thousands) +Domestic $ 1,142 $ ( 12,220 ) $ ( 4,593 ) +Foreign 3,177 3,480 3,151 +Income (loss) before income taxes $ 4,319 $ ( 8,740 ) $ ( 1,442 ) +45 +Deferred income tax assets and liabilities consist of the following at: +June 27, 2020 June 29, 2019 +(in thousands) +Deferred tax assets: +Net operating loss $ 184 $ 33 +Tax credit carryforwards, net 5,961 4,986 +Inventory 1,426 1,087 +Identifiable intangibles 493 407 +Interest expense carryforward — 474 +Accruals 2,847 3,549 +Research and development expenses — 232 +Mart-to-market adjustments 415 — +ASC 606 deferred costs 1,943 2,484 +Lease liabilities 3,201 — +Other 212 30 +Deferred income tax assets $ 16,682 $ 13,282 +Deferred tax liabilities: +Accrued withholding tax - unremitted earnings ( 820 ) ( 820 ) +Fixed assets ( 566 ) ( 443 ) +Right-of-use assets ( 3,290 ) — +Mart-to-market adjustments — ( 730 ) +ASC 606 accelerated revenue ( 1,344 ) ( 3,274 ) +Other ( 718 ) ( 175 ) +Deferred income tax liabilities $ ( 6,738 ) $ ( 5,442 ) +Net deferred income tax assets $ 9,944 $ 7,840 +Balance sheet caption reported in: +Long-term deferred income tax asset $ 10,178 $ 7,840 +Long-term deferred income tax liability ( 234 ) — +Net deferred income tax asset $ 9,944 $ 7,840 +Certain reclassifications have been made in the 2019 information in the above table to conform with 2020 presentation. +Uncertain Tax Positions: +The Company has R&D tax credits that approximate $ 8.8 million that have 20 -year carryforwards before expiring. The Company’s R&D tax credits expire in various fiscal years from 2026 to 2040. The Company also has alternative minimum tax credits, which do not expire, approximating $ 347,000 , which are now classified as a receivable due to the repeal of the alternative minimum tax. +As of June 27, 2020, the Company had unrecognized tax benefits of $ 2.9 million related to its gross R&D tax credits. The unrecognized tax benefits relate to certain R&D tax credits generated from 2002 to 2020. +A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: +Fiscal Year Ended +June 27, 2020 June 29, 2019 June 30, 2018 +(in thousands) +Beginning Balance $ 4,099 $ 4,011 $ 3,947 +Additions based on tax positions related to the current year 109 88 64 +Lapse of statute of limitations ( 1,345 ) — — +Ending Balance $ 2,863 $ 4,099 $ 4,011 +46 +The increase from the prior year is due to additional R&D credits that were recorded in 2020 as discussed above. Management does not anticipate any material changes to this amount during the next 12 months. +The Company recognizes interest accrued related to unrecognized tax benefits and penalties in its income tax provision. The Company has not recognized any interest or penalties in the fiscal years presented in these financial statements. The Company is subject to income tax in the U.S. federal jurisdiction, various state jurisdictions, Mexico, China and Vietnam. Certain years remain subject to examination but there are currently no ongoing exams in any taxing jurisdictions. +7. EARNINGS PER SHARE +Basic earnings per share (EPS) is calculated by dividing net income (the numerator) by the weighted-average number of common shares outstanding (the denominator) during the period. Diluted EPS is computed by including both the weighted-average number of shares outstanding and any dilutive common share equivalents in the denominator. The following table presents a reconciliation of the denominator and the number of antidilutive common share awards that were not included in the diluted earnings per share calculation. These antidilutive securities occur when equity awards outstanding have an option price greater than the average market price for the period: +Fiscal Year Ended +(in thousands, except per share information) +June 27, 2020 June 29, 2019 June 30, 2018 +Net income (loss) $ 4,758 $ ( 7,982 ) $ ( 1,325 ) +Weighted average shares outstanding– basic 10,760 10,760 10,760 +Effect of dilutive common stock awards 57 — — +Weighted average shares outstanding – diluted 10,816 10,760 10,760 +Net income (loss) per share – basic $ 0.44 $ ( 0.74 ) $ ( 0.12 ) +Net income (loss) per share – diluted $ 0.44 $ ( 0.74 ) $ ( 0.12 ) +Antidilutive SARs not included in diluted earnings per share 720 985 827 +47 +8. STOCK OPTION AND BENEFIT PLANS +The Company’s incentive plan provides for equity and liability awards to employees and non-employee directors in the form of stock options, stock appreciation rights (SARs), restricted stock, restricted stock units, stock awards, stock units, performance shares, performance units, and other stock-based or cash-based awards. Compensation cost is recognized on a straight-line basis over the requisite employee service period, which is generally the vesting period, and is recorded as employee compensation expense in cost of goods sold, research, development and engineering, and selling, general and administrative expenses. Share-based compensation is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on historical experience and future expectations. +In addition to service conditions, these SARs contain a performance condition. The additional performance condition is based upon the achievement of Return on Invested Capital (ROIC) goals relative to a peer group. All awards with performance conditions are measured over the vesting period and are charged to compensation expense over the requisite service period based on the number of shares expected to vest. The SARs cliff vest after a three-year period from date of grant and expire five years from date of grant. +On July 26, 2019, the Company granted 175,000 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $4.93 and a grant date fair value of $1.23. As of June 27, 2020, 150,000 remain outstanding. The grant date fair value for the awards granted during fiscal year 2020, were estimated using the Black Scholes option valuation method with the following weighted average assumptions as of July 26, 2019: +Fiscal Year 2020 +July 26, 2019 +Expected dividend yield — % +Risk – free interest rate 1.54 % +Expected volatility 28.50 % +Expected life 4.00 +On July 27, 2018, the Company granted 161,250 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $8.17 and a grant date fair value of $2.27. As of June 27, 2020, 121,250 remain outstanding. The grant date fair value for the awards granted during fiscal year 2019, were estimated using the Black Scholes option valuation method with the following weighted average assumptions as of July 27, 2018: +Fiscal Year 2019 +July 27, 2018 +Expected dividend yield — % +Risk – free interest rate 2.80 % +Expected volatility 29.75 % +Expected life 4.00 +On July 28, 2017, the Company granted 272,500 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $7.26 and a grant date fair value of $1.89. As of June 27, 2020, 197,500 remain outstanding. The grant date fair value for the awards granted during fiscal year 2018, were estimated using the Black Scholes option valuation method with the following weighted average assumptions as of July 28, 2017: +Fiscal Year 2018 +July 28, 2017 +Expected dividend yield — % +Risk – free interest rate 1.70 % +Expected volatility 29.76 % +Expected life 4.00 +48 +Subsequent to June 27, 2020, the Company granted 155,000 SARs with a strike price of $6.94 and a grant date fair value of $2.32. +Share-based compensation expense is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on the Company’s historical experience and future expectations. This forfeiture rate will be revised, if necessary, in subsequent periods if actual forfeitures differ from the amount estimated. Share-based compensation expense for fiscal years ended June 27, 2020, June 29, 2019 and June 30, 2018 was $ 0.3 million, $ 0.4 million and $ 0.4 million, respectively. +The Black-Scholes option valuation model is used by the Company for estimating the fair value of SARs. Option valuation models require the input of highly subjective assumptions, particularly for the expected term and expected stock price volatility. Changes in these assumptions can materially affect the fair value estimates. +There were no SARs exercised during fiscal year 2020, 2019 or 2018. +As of June 27, 2020, total unrecognized compensation expense related to nonvested share-based compensation arrangements was approximately $ 0.2 million. This expense is expected to be recognized over a weighted-average period of 1.58 years. +The following table summarizes the Company’s Options and SARs activity for all plans from July 2, 2016 through June 27, 2020: +SARs +Available +For Grant SARs +Outstanding Aggregate +Intrinsic +Value (in +thousands) Weighted +Average +Exercise +Price Weighted +Average +Remaining +Contractual +Life (in +years) +Balances, July 1, 2017 394,335 1,084,999 $ — $ 9.09 2.3 +Shares authorized — — +SARs granted ( 272,500 ) 272,500 7.26 +SARs forfeited 282,500 ( 282,500 ) 7.84 +SARs exercised — — — — +Balances June 30, 2018 404,335 1,074,999 $ 79 $ 8.90 2.3 +Shares authorized — — +SARs granted ( 161,250 ) 161,250 8.17 +SARs forfeited 250,833 ( 250,833 ) 10.59 +SARs exercised — — — — +Balances, June 29, 2019 493,918 985,416 $ — $ 8.35 1.7 +Shares authorized — — +SARs granted ( 175,000 ) 175,000 4.93 +SARs forfeited 290,833 ( 290,833 ) 7.71 +SARs exercised — — — — +Balances, June 27, 2020 609,751 869,583 $ — $ 7.87 1.9 +Exercisable at June 27, 2020 400,833 $ — $ 9.18 0.6 +Additional information regarding SARs outstanding and exercisable as of June 27, 2020, is as follows: +Range of +Exercise Prices Number Outstanding Weighted Avg. +Remaining +Contractual Life (yrs.) Weighted Avg. +Exercise Price Number +Exercisable Weighted +Avg. Exercise +Price +$4.40 – $7.90 347,500 2.1 $ 6.25 — $ — +7.91 – 9.91 328,750 0.6 8.17 207,500 8.17 +9.92 – 11.34 193,333 0.1 10.26 193,333 10.26 +$4.40 to $11.34 869,583 1.9 $ 7.87 400,833 $ 9.18 +The Company has defined contribution plans available to U.S. employees who have attained age 21. Company contributions to the plans were approximately $ 0.8 million, $ 0.9 million, and $ 0.8 million during fiscal years 2020, 2019 and 2018, respectively. +49 +9. COMMITMENTS AND CONTINGENCIES +Leases : As of June 27, 2020, June 29, 2019 and June 30, 2018, the Company did not have any property and equipment financed under capital leases. Please refer to Note 16 for information regarding operating lease commitments. +Rental expense under operating leases was approximately $ 4.2 million, $ 5.0 million, and $ 7.1 million during fiscal years 2020, 2019 and 2018, respectively. +Warranty Costs : The Company provides warranties on certain product sales, and allowances for estimated warranty costs are recorded during the period of sale. The determination of such allowances requires the Company to make estimates of product return rates and expected costs to repair or to replace the products under warranty. The Company establishes warranty reserves based on historical warranty costs for each product line combined with liability estimates based on the prior twelve months’ sales activities. As of June 27, 2020 and June 29, 2019, the reserve for warranty costs was approximately $ 15,000 and $ 22,000 , respectively. +If actual return rates and/or repair and replacement costs differ significantly from estimates, adjustments to recognize additional cost of sales may be required in future periods. Warranty expense for fiscal years 2020, 2019 and 2018 was related to workmanship claims on certain EMS products. +Litigation : The Company is party to certain lawsuits or claims in the ordinary course of business. The Company does not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on the financial position, results of operations or cash flow of the Company. +Indemnification Rights : Under the Company’s bylaws, the Company’s directors and officers have certain rights to indemnification by the Company against certain liabilities that may arise by reason of their status or service as directors or officers. The Company maintains director and officer insurance, which may cover certain liabilities arising from its obligation to indemnify its directors and officers and former directors in certain circumstances. +10. DERIVATIVE FINANCIAL INSTRUMENTS +As of June 27, 2020, the Company had outstanding foreign currency forward contracts and swaps with a total notional amount of $ 36.7 million. The maturity dates for these contracts and swaps extend through December 2021. As of June 27, 2020, the net amount of unrealized loss expected to be reclassified into earnings within the next 12 months is approximately $ 1.8 million. During the fiscal year ended June 27, 2020, the Company entered into $ 23.8 million of foreign currency forward contracts and settled $ 26.7 million of such contracts. During the fiscal year ended June 29, 2019, the Company entered into $ 19.2 million of foreign currency forward contracts and settled $ 25.9 million of such contracts. During the fiscal year ended June 30, 2018, the Company entered into $ 13.7 million of foreign currency forward contracts and settled $ 28.1 million of such contracts. +As of June 27, 2020, the aggregate notional amount of the Company’s outstanding foreign currency contracts and swaps along with their unrealized gains (losses) are expected to mature as summarized below (in thousands): +Quarter Ending Notional Contracts and Swaps in MXN Notional Contracts and Swaps in USD Estimated Fair Value +September 26, 2020 $ 141,173 $ 6,729 $ ( 623 ) +December 26, 2020 $ 132,773 $ 6,241 $ ( 561 ) +April 3, 2021 $ 148,253 $ 6,682 $ ( 425 ) +July 3, 2021 $ 144,725 $ 6,446 $ ( 367 ) +October 2, 2021 $ 146,373 $ 5,502 $ 564 +January 1, 2022 $ 137,973 $ 5,129 $ 532 +On November 6, 2019, the Company entered into an interest rate swap contract with an effective date of November 6, 2019 and a termination date of September 30, 2022, with a notional amount of $ 15.0 million related to the borrowings outstanding under the term loan. This interest rate swap pays the Company variable interest at the one month LIBOR rate, and the Company pays the counter party a fixed interest rate. The fixed interest rate for the contract is 1.70 % that replaces the one month LIBOR rate component of our contractual interest to be paid to WFB as part of our term loan. Based on the terms of the interest rate swap contract and the underlying borrowings outstanding under the term loan, the interest rate contract was determined to be effective, and thus qualified as a cash flow hedge. As of June 27, 2020, the remaining notional balance of this swap was $ 11.7 million. +50 +On November 6, 2019, the Company entered into an interest rate swap contract with an effective date of November 6, 2019 and a termination date of November 1, 2023, with a notional amount of $ 15.0 million related to the borrowings outstanding under the line of credit. This interest rate swap pays the Company variable interest at the one month LIBOR rate, and the Company pays the counter party a fixed interest rate. The fixed interest rate for the contract is 1.67 % that replaces the one month LIBOR rate component of our contractual interest to be paid to WFB as part of our line of credit. Based on the terms of the interest rate swap contract and the underlying borrowings outstanding under the line of credit, the interest rate contract was determined to be effective, and thus qualified as a cash flow hedge. In conjunction with the new credit facility, the interest rate swap contracts have been terminated. Please refer to footnote 17 Subsequent Event for more information. +The following table summarizes the fair value of derivative instruments in the Consolidated Balance Sheets as of June 27, 2020 and June 29, 2019 (in thousands): +June 27, 2020 June 29, 2019 +Derivatives Designated as Hedging Instruments Balance Sheet Location Fair Value Fair Value +Foreign currency forward contracts & swaps Other current assets $ — $ 2,912 +Foreign currency forward contracts & swaps Other long-term assets $ 1,097 $ 320 +Foreign currency forward contracts & swaps Other current liabilities $ ( 1,960 ) $ — +Foreign currency forward contracts & swaps Other long-term liabilities $ ( 17 ) $ — +Interest rate swaps Other current assets $ — $ 2 +Interest rate swaps Other current liabilities $ ( 347 ) $ — +Interest rate swaps Other long-term liabilities $ ( 610 ) $ — +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2020 (in thousands): +Derivatives Designated as Hedging Instruments Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) AOCI Balance +as of +June 29, 2019 Effective +Portion +Recorded In +AOCI Effective Portion +Reclassified From +AOCI Into Income AOCI Balance +as of +June 27, 2020 +Forward contracts & swaps Cost of sales $ 2,424 $ ( 865 ) $ ( 2,318 ) $ ( 759 ) +Interest rate swap Interest expense 2 ( 782 ) 39 ( 741 ) +Total $ 2,426 $ ( 1,647 ) $ ( 2,279 ) $ ( 1,500 ) +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2019 (in thousands): +Derivatives Designated as Hedging Instruments Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) AOCI Balance +as of +June 30, 2018 Effective +Portion +Recorded In +AOCI Effective Portion +Reclassified From +AOCI Into Income AOCI Balance +as of +June 29, 2019 +Forward contracts & swaps Cost of sales $ ( 988 ) $ 3,332 $ 80 $ 2,424 +Interest rate swap Interest expense 19 2 ( 19 ) 2 +Total $ ( 969 ) $ 3,334 $ 61 $ 2,426 +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2018 (in thousands): +Derivatives Designated as Hedging Instruments Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) AOCI Balance +as of +July 1, 2017 Effective +Portion +Recorded In +AOCI Tax Rate Effect Reclassification Effective Portion +Reclassified From +AOCI Into Income AOCI Balance +as of +June 30, 2018 +Forward contracts & swaps Cost of sales $ ( 2,707 ) $ ( 1,942 ) $ ( 583 ) $ 4,244 $ ( 988 ) +Interest rate swap Interest expense ( 68 ) 20 ( 3 ) 70 19 +Total $ ( 2,775 ) $ ( 1,922 ) $ ( 586 ) $ 4,314 $ ( 969 ) +As of June 27, 2020, the Company does not have any foreign exchange contracts with credit-risk-related contingent features. The Company is subject to the risk of fluctuating interest rates from our line of credit and foreign currency risk resulting from our China operations. The Company does not currently manage these risk exposures by using derivative instruments. +51 +11. FAIR VALUE MEASUREMENTS +The Company has adopted ASC 820, Fair Value Measurements, which defines fair value, establishes a framework for assets and liabilities being measured and reported at fair value and expands disclosures about fair value measurements. There are three levels of fair value hierarchy inputs used to value assets and liabilities which include: Level 1 – inputs are quoted market prices for identical assets or liabilities; Level 2 – inputs other than quoted market prices included in Level 1 that are observable for the asset or liability, either directly or indirectly; and Level 3 – inputs are unobservable inputs for the asset or liability. There have been no changes in the fair value methodologies used at June 27, 2020 and June 29, 2019. +The following table summarizes the fair value of assets (liabilities) of the Company’s derivatives that are required to be measured on a recurring basis as of June 27, 2020 and June 29, 2019 (in thousands): +June 27, 2020 +Level 1 Level 2 Level 3 Total +Fair Value +Financial Assets: +Foreign currency forward contracts & swaps $ — $ 1,097 $ — $ 1,097 +Financial Liabilities: +Interest rate swaps $ — $ ( 957 ) $ — $ ( 957 ) +Foreign currency forward contracts & swaps $ — $ ( 1,977 ) $ — $ ( 1,977 ) +June 29, 2019 +Level 1 Level 2 Level 3 Total +Fair Value +Financial Assets: +Interest rate swaps $ — $ 2 $ — $ 2 +Foreign currency forward contracts & swaps — 3,232 — $ 3,232 +The Company currently has forward contracts to hedge known future cash outflows for expenses denominated in the Mexican peso and an interest rate swap to mitigate risk associated with certain borrowings under the Company’s debt arrangement. These contracts are measured on a recurring basis based on the foreign currency spot rates and forward rates quoted by banks or foreign currency dealers. These contracts are marked to market using level 2 input criteria every quarter with the unrealized gain or loss, net of tax, reported as a component of shareholders’ equity in accumulated other comprehensive income (loss), as they qualify for hedge accounting. +The carrying values of cash and cash equivalents, accounts receivable, current liabilities, and non current lease liability are reflected on the balance sheets at June 27, 2020 and June 29, 2019, reasonably approximate their fair value. +The Company’s long-term debt, which is measured at amortized cost, primarily consists of a revolving line of credit, a term loan and an equipment term loan. These borrowings bear interest at either a “Base Rate” or a “Fixed Rate,” as elected by the Company. Each of these rates is a variable floating rate dependent upon current market conditions and the Company’s current credit risk as discussed in footnote 4. +As a result of the determinable market rate for our revolving line of credit, term loan and equipment term, they are classified within Level 2 of the fair value hierarchy. Further, the carrying value of each of these instruments reasonably approximates their fair value as of June 27, 2020 and June 29, 2019. +Other assets and liabilities held by the Company may be required to be measured at fair value on a non recurring basis. As of June 29, 2019, the customer relationship intangibles were written down to their fair value of $0. This measurement was the result of certain triggering events that occurred during the third quarter of fiscal year 2019. Refer to Note 14 for further discussion of the impairment. +52 +12. ENTERPRISE-WIDE DISCLOSURES +Operating segments are defined in ASC Topic 280, Segment Reporting as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker, or decision making group, in deciding how to allocate resources and in assessing performance. The Company’s chief operating decision maker is its Chief Executive Officer. As of June 27, 2020, the Company operates and internally manages a single operating segment, Electronics Manufacturing Services as this is the only discrete financial information that is regularly reviewed by the chief operating decision maker. This segment provides integrated electronic and mechanical engineering, assembly, sourcing and procurement, logistics, and new product testing for our customers. +Products and Services +Of the revenues for the years ended June 27, 2020, June 29, 2019, and June 30, 2018, EMS sales and services were $ 449.5 million, $ 463.9 million and $ 445.8 million, respectively. Keyboard sales for the years ended June 27, 2020, June 29, 2019, and June 30, 2018 were $ 4,000 , $ 0.1 million and $ 0.5 million, respectively. +Geographic Areas +Net sales and long-lived assets (property, plant, and equipment) by geographic area for the years ended and as of June 27, 2020, June 29, 2019 and June 30, 2018 are summarized in the following table. Net sales set forth below are based on the shipping destination. Long-lived assets information is based on the physical location of the asset. +Fiscal Year Ended +(in thousands) +2020 2019 2018 +Geographic net sales: +Domestic (U.S.) $ 338,766 $ 357,341 $ 329,230 +Foreign 110,714 106,703 117,092 +Total $ 449,480 $ 464,044 $ 446,322 +Long-lived assets: +United States $ 9,213 $ 9,658 $ 7,454 +Mexico 19,325 17,781 19,395 +Vietnam 2,644 1,220 — +China 582 754 699 +Total $ 31,764 $ 29,413 $ 27,548 +Percentage of net sales made to customers located in the following countries: +Fiscal Year Ended +2020 2019 2018 +United States 75 % 77 % 74 % +China 19 19 24 +Other foreign countries (a) +5 3 2 +Canada 1 1 — +Total 100 % 100 % 100 % +(a) No other individual foreign country accounted for 10% or more of the foreign sales in fiscal years 2020, 2019 or 2018. +53 +Significant Customers +The percentage of net sales to and trade accounts receivables from significant customers were as follows: +Percentage of Net +Sales Fiscal Year Percentage of +Trade Accounts Receivable +Fiscal Year +2020 2019 2018 2020 2019 +Customer A 18 % 17 % 19 % 14 % 11 % +Customer B * * * 12 % * +* Current customer amount represents less than 10%. +13. QUARTERLY FINANCIAL DATA (Unaudited) +Fiscal Year Ended June 27, 2020 +First +Quarter Second +Quarter Third +Quarter Fourth +Quarter +(in thousands, except per share amounts) +Net sales $ 105,285 $ 116,722 $ 111,455 $ 116,018 +Gross profit 9,273 8,122 9,248 8,606 +Income before income taxes 1,829 974 1,010 506 +Net income 1,552 824 910 1,472 +Net income per share - basic $ 0.14 $ 0.08 $ 0.08 $ 0.14 +Net income per share - diluted $ 0.14 $ 0.08 $ 0.08 $ 0.14 +Weighted average shares outstanding +Basic 10,760 10,760 10,760 10,760 +Diluted 10,805 10,877 10,885 10,832 +Fiscal Year Ended June 29, 2019 +First +Quarter Second +Quarter Third +Quarter Fourth +Quarter +(in thousands, except per share amounts) +Net sales $ 127,472 $ 123,037 $ 107,954 $ 105,581 +Gross profit 9,533 9,880 6,807 8,381 +Income (loss) before income taxes 1,868 1,916 ( 13,256 ) 732 +Net income (loss) 1,593 1,589 ( 11,981 ) 817 +Net income (loss) per share - basic $ 0.15 $ 0.15 $ ( 1.11 ) $ 0.08 +Net income (loss) per share - diluted $ 0.15 $ 0.15 $ ( 1.11 ) $ 0.08 +Weighted average shares outstanding +Basic 10,760 10,760 10,760 10,760 +Diluted 10,979 10,881 10,760 10,760 +54 +14. GOODWILL AND OTHER INTANGIBLE ASSETS +The Company recorded goodwill in connection with the Ayrshire and Sabre acquisitions resulting primarily from the synergies that resulted from the Company's acquisitions and the assembled workforce. The goodwill is not amortized for financial accounting purposes. +In accordance with accounting guidance on goodwill and other intangible assets, the Company evaluates goodwill for impairment at the reporting unit level annually, and whenever circumstances occur indicating that goodwill might be impaired. Upon adoption of ASU 2017-04, the Company now recognizes an impairment charge (not to exceed the total amount of goodwill allocated to the reporting unit) for the amount by which the carrying amount of a reporting unit exceeds the reporting unit’s fair value. During the third quarter of fiscal year 2019, a goodwill impairment of $ 10.0 million was recognized. +During the third quarter for fiscal year 2019, the Company assessed other finite-lived intangible assets including the Company’s customer relationships and favorable lease agreements due to an indicator of possible impairment being present. As a result of the analysis performed, the Company determined that the carrying value of the customer relationships intangible asset was not recoverable and recorded an impairment for the entire carrying amount during the third quarter of fiscal year 2019. This resulted in an impairment charge related to other intangible assets of $ 2.5 million recognized in the third quarter of fiscal year 2019. The Company’s analysis did not indicate that any of its other long-lived assets were impaired. +During the first quarter of fiscal year 2020, the Company adopted the Accounting Standards Update 2016-02, Leases which supersedes ASC 840 Leases and creates a new topic, ASC 842 Leases. Under ASC 842, any assets or liabilities recognized in accordance with ASC 805 that are related to favorable or unfavorable terms of an operating lease for which an entity is a lessee, the entity should derecognize the asset or liability and commensurately adjust the ROU asset. Refer to footnote 16 for additional disclosure. +As such, the Company derecognized the intangible asset and added the offsetting amount to the ROU asset. Resulting in a reduction of favorable lease agreement intangible of $ 0.7 million, and no adjustment to retained earnings or future P&L impact. +The components of acquired intangible assets are as follows (in thousands): +June 27, 2020 +Amortization Period +in Years Gross Carrying +Amount Accumulated +Amortization Derecognition Favorable Lease per ASC 842 Net Carrying +Amount +Other intangible assets: +Favorable Lease Agreements 4 - 7 2,941 ( 2,284 ) ( 657 ) — +Total $ 2,941 $ ( 2,284 ) $ ( 657 ) $ — +June 29, 2019 +Amortization Period +in Years Gross Carrying +Amount Accumulated +Amortization Impairment +Recognized Net Carrying +Amount +Other intangible assets: +Non-Compete Agreements 3 - 5 $ 568 $ ( 568 ) $ — $ — +Customer Relationships 10 4,803 ( 2,311 ) ( 2,492 ) — +Favorable Lease Agreements 4 - 7 2,941 ( 2,284 ) — 657 +Total $ 8,312 $ ( 5,163 ) $ ( 2,492 ) $ 657 +Amortization expense related to intangible assets was approximately $ 0.6 million and $ 1.1 million for the year ended June 29, 2019, and June 30, 2018; respectively. +55 +15. REVENUE +Revenue Recognition +The Company specializes in services ranging from product manufacturing to engineering and tooling services. The first step in its process for revenue recognition is to identify the contract with a customer. A contract is defined as an agreement between two or more parties that creates enforceable rights and obligations. A contract can be written, oral, or implied. The Company generally enters into manufacturing service agreements (“MSA”) with its customers that outlines the terms of the business relationship between the customer and the Company. This includes matters such as warranty, indemnification, transfer of title and risk of loss, liability for excess and obsolete inventory, pricing, payment terms, etc. The Company will also bid on a program-by-program basis for customers in which an executed MSA may not be in place. In these instances, as well as when we have an MSA in place, we receive customer purchase orders for specific quantities and timing of products. As a result, the Company considers its contract with a customer to be the combination of the MSA and the purchase order. The transaction price is fixed and set forth in each purchase order. In the Company's normal course of business, there are no variable pricing components, or material amounts refunded to customers in the form of refunds or rebates. +The Company assesses whether control of the product or services promised under the contract is transferred to the customer at a point in time (shipment) or over time (as we manufacture the product). The Company is first required to evaluate whether its contracts meet the criteria for 'over-time' or 'point-in-time' recognition. The Company has determined that for the majority of its contracts the Company is manufacturing products for which there is no alternative use due to the unique nature of the customer-specific product, IP and other contract restrictions. The Company has an enforceable right to payment including a reasonable profit for performance completed to date with respect to these contracts. As a result, revenue is recognized under these contracts 'over-time' based on the input cost-to-cost method as it better depicts the transfer of control. This input method is based on the ratio of costs incurred to date as compared to the total estimated costs at completion of the performance obligation. For all other contracts that do not meet these criteria, such as manufacturing contracts for which the terms do not provide an enforceable right to payment for performance completed to date, the Company recognizes revenue when it has transferred control of the related manufactured products which generally occurs upon shipment to the customer. Revenue from engineering services is recognized over time as the services are performed. +The Company’s typical payment terms are 30 to 45 days and its sales arrangements do not contain any significant financing component for its customers. +The Company generally provides a warranty for workmanship on its manufacturing contracts. Historically, the amount of returns for workmanship issues has been de minimis under the Company’s warranties. +The Company elected to not disclose information about remaining performance obligations as they are part of contracts that that have expected durations of one year or less. +The Company has elected to expense costs to obtain contracts as incurred as these costs are immaterial to the financial statements. +During fiscal 2020, no revenues were recognized from performance obligations satisfied or partially satisfied in previous periods. +Contract Balances +A contract asset is recognized when the Company has recognized revenue, but has not issued an invoice for payment. Contract assets are classified separately on the condensed consolidated balance sheet and transferred to receivables when the right to payment becomes unconditional. +The following table summarizes the activity in the Company’s contract assets during the twelve months ended June 27, 2020 (in thousands): +Contract Assets +Beginning balance, June 29, 2019 $ 22,161 +Revenue recognized 441,405 +Amounts collected or invoiced ( 439,813 ) +Ending balance, June 27, 2020 $ 23,753 +56 +The following table summarizes the activity in the Company’s contract assets during the twelve months ended June 29, 2019 (in thousands): +Contract Assets +Beginning balance, June 30, 2018 — +Cumulative effect adjustment at July 1, 2018 11,906 +Revenue recognized 448,003 +Amounts collected or invoiced ( 437,748 ) +Ending balance, June 29, 2019 $ 22,161 +Disaggregation of Revenue +The following table presents the Company’s revenue disaggregated for the twelve months ended June 27, 2020 and the twelve months ended June 29, 21019 (in thousands): +Revenue +Recognition June 27, 2020 June 29, 2019 +Over-Time $ 441,405 $ 458,256 +Point-in-Time 8,075 5,788 +Total $ 449,480 $ 464,044 +Revenues and associated costs from engineering design, development services and tooling, which are performed under contract of short term durations, are recognized over time as the services are performed. Revenue from engineering design, development +services and tooling represented approximately 3.3% of total revenue in fiscal year 2020. +16. LEASES +The Company has several commitments under operating leases for warehouses, manufacturing facilities, office buildings, and equipment with initial terms that expire at various dates during the next 1 year to 11 years. +The Company has some operating leases that include an extension clause. Management has considered the likelihood of exercising each extension option included and estimated the duration of the extension option, for those leases management determined to be reasonably certain, in calculating the lease term for measurement of the right of use asset and liability. +For operating leases, management assumed a discount rate of 4% - 5.9%. The weighted average discount rate is disclosed in the tables below. +The components of lease cost as of June 27, 2020 were (in thousands): +Year Ended +Lease cost Classification June 27, 2020 +Operating lease cost Cost of sales $ 4,511 +Operating lease cost Selling, general and administrative expenses 1,266 +Total lease cost $ 5,777 +57 +Amounts reported in the Consolidated Balance Sheet as of June 27, 2020 were (in thousands, except weighted average lease term and discount rate): +June 27, 2020 +Operating Leases: +Operating lease right of use assets $ 17,568 +Operating lease liabilities (1) +17,173 +Weighted-average remaining lease term (in years) +Operating leases 6.46 +Weighted-average discount rate +Operating leases 4.07 % +(1) The current portion of the total operating lease liabilities of $ 4.5 million is classified under Other Current Liabilities, resulting in $ 12.6 million classified under Operating Lease Liabilities in the Long-term Liabilities section of the consolidated balance sheet. +Other information related to leases was as follows (in thousands): +June 27, 2020 +Cash paid for amounts included in the measurement of lease liabilities: +Operating cash flows from operating leases 4,237 +The Company entered into one new lease during the fiscal year, resulting in a non-cash impact of $0.4 million. +Future lease payments under non-cancellable leases as of June 27, 2020 are as follows (in thousands): +Fiscal Years Ending Operating Leases +2021 $ 4,250 +2022 3,373 +2023 2,598 +2024 2,004 +2025 1,894 +Thereafter 5,674 +Total undiscounted lease payments 19,793 +Less: present value discount 2,620 +Total lease liabilities $ 17,173 +58 +As previously disclosed in our Annual Report on Form 10-K for the fiscal year ended June 29, 2019 and under the previous lease accounting standard ASC 840, the aggregate future minimum payments under non-cancellable operating leases, as of June 29, 2019, are as follows (in thousands): +Fiscal Years Ending Operating Leases +2020 $ 4,777 +2021 3,563 +2022 2,641 +2023 1,866 +2024 1,271 +Thereafter 4,121 +Total minimum lease payments $ 18,239 +The Company identified certain immaterial errors in relation to its computation of its operating lease right-of-use assets and operating lease liabilities upon adoption of ASC 842, which primarily related to the improper exclusion of fixed rent escalation clauses. The errors were considered to be immaterial to previously issued quarterly reports on Form 10-Q as of September 28, 2019, December 28, 2019 and March 28, 2020. The impact of the correction on the respective balance sheets was as follows (in thousands): +September 28, 2019 +Amounts as reported Adjustments Amounts as corrected +Operating lease right-of-use assets, net $ 16,056 $ 4,223 $ 20,279 +Total assets $ 281,127 $ 4,223 $ 285,350 +Operating lease liabilities - Long-term $ 10,885 $ 4,223 $ 15,108 +Total Liabilities $ 165,989 $ 4,223 $ 170,212 +December 28, 2019 +Amounts as reported Adjustments Amounts as corrected +Operating lease right-of-use assets, net $ 14,876 $ 4,223 $ 19,099 +Total assets $ 273,970 $ 4,223 $ 278,193 +Operating lease liabilities - Long-term $ 9,870 $ 4,223 $ 14,093 +Total Liabilities $ 157,163 $ 4,223 $ 161,386 +March 28, 2020 +Amounts as reported Adjustments Amounts as corrected +Operating lease right-of-use assets, net $ 15,347 $ 3,127 $ 18,474 +Total assets $ 288,403 $ 3,127 $ 291,530 +Operating lease liabilities - Long-term $ 10,327 $ 3,127 $ 13,454 +Total Liabilities $ 175,463 $ 3,127 $ 178,590 +59 +17. SUBSEQUENT EVENT +On August 14, 2020, the Company entered into a loan and security agreement (the “Loan Agreement”) with Bank of America. The Loan Agreement replaces the Company’s prior amended and restated credit agreement, as amended, with Wells Fargo Bank, N.A. The Loan Agreement provides for a five-year asset-based senior secured revolving credit facility of up to $93 million, maturing on August 14, 2025. In addition, during the term of the Loan Agreement, the Company may increase the aggregate amount of the Credit Facility by up to an additional $25 million, subject to customary conditions, including obtaining a commitment from the Bank (or another lender, if applicable) to such increase. +The Credit Facility has been used to pay-off the Prior Credit Facility and costs related to the Loan Agreement, and may be used to pay-off certain other existing debt, to issue letters of credit, and for other business purposes, including working capital needs. Based on the Company’s borrowing base and reserve requirements and after paying off the Prior Credit Facility and related fees and expenses relating to the Credit Facility, immediately following the closing of the Loan Agreement, there was approximately $16 million available under the Credit Facility. +The Loan Agreement contains financial covenants as long as commitments or obligations are outstanding under the Loan Agreement, requiring the Company to maintain: (i) a fixed charge coverage ratio of at least 1.25 to 1.0, measured monthly on a trailing 12-month basis; and (ii) a cash flow leverage ratio of no greater than 6.00 to 1.00, which may be subject to adjustments for COVID-19 related cash expenses as approved by the Bank, measured monthly on a trailing 12-month basis. +60 +Item 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES +None +Item 9A: CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +It is the responsibility of our management to establish, maintain, and monitor disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 are recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Additionally, these disclosure controls include controls and procedures that are designed to accumulate and communicate the information required to be disclosed to our Company’s Chief Executive Officer and Chief Financial Officer, allowing for timely decisions regarding required disclosures. As of the end of the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(f). Based on our assessment, we believe that as of June 27, 2020, the Company’s disclosure controls and procedures are effective based on that criteria. +Management’s Report on Internal Control over Financial Reporting +Our management has the responsibility to establish and maintain adequate internal controls over our financial reporting, as defined in Rule 13a-15(f) under the Securities and Exchange Act of 1934. Our internal controls are designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our external financial statements in accordance with generally accepted accounting principles (GAAP). +Due to inherent limitations of any internal control system, management acknowledges that there are limitations as to the effectiveness of internal controls over financial reporting and therefore recognize that only reasonable assurance can be gained from any internal control system. Accordingly, our internal control system may not detect or prevent material misstatements in our financial statements and projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, we have performed an assessment of the effectiveness of our internal controls over financial reporting as of June 27, 2020. This assessment was based on the criteria established in Internal Control-Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that as of June 27, 2020, the Company’s internal control over financial reporting is effective based on that criteria. +The effectiveness of the Company's internal control over financial reporting as of June 27, 2020 has been audited by BDO USA LLP, an independent registered public accounting firm, as stated in their report which is included herein. +Changes in Internal Control over Financial Reporting +There have been no significant changes in our internal controls over financial reporting during our fourth fiscal quarter ended June 27, 2020 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)). +61 +Report of Independent Registered Public Accounting Firm +Shareholders and Board of Directors +Key Tronic Corporation +Spokane Valley, Washington +Opinion on Internal Control over Financial Reporting +We have audited Key Tronic Corporation’s (the “Company’s”) internal control over financial reporting as of June 27, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of June 27, 2020, based on the COSO criteria. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company as of June 27, 2020 and June 29, 2019, the related consolidated statements of income (loss), comprehensive income (loss), shareholders’ equity, and cash flows for each of the three years in the period ended June 27, 2020, and the related notes and schedule and our report dated September 11, 2020 expressed an unqualified opinion thereon. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying “Item 9A, Management’s Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit of internal control over financial reporting in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ BDO USA, LLP +Spokane, Washington +September 11, 2020 +62 +Item 9B: OTHER INFORMATION +None +PART III +Item 10: DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Directors of the Registrant +Information on the nominees for election as Directors of the Company is incorporated by reference from the Company’s definitive proxy statement for the 2020 Annual Meeting of Shareholders to be filed pursuant to Regulation 14A under the Exchange Act no later than 120 days after the end of the Company’s 2020 fiscal year. +Executive Officers of the Registrant +This information is included in a separate item captioned “Executive Officers of the Registrant” in Item 1 of Part 1 of this report pursuant to Instruction G(3) of Form 10-K and Instruction 3 to Item 401(b) of Regulation S-K. +Compliance with Section 16(a) of the Exchange Act: +Incorporated by reference to Key Tronic Corporation’s 2020 Proxy Statement to Shareholders. +Code of Conduct +The Board of Directors has adopted a written Code of Conduct which applies to its directors and employees, including its executive officers. The Code of Conduct is available on the Company’s website at www.keytronic.com . The Company intends to disclose on its website any amendments to or waivers of the Code of Conduct. +Item 11: EXECUTIVE COMPENSATION +Information appearing under the caption “Executive Compensation” in the Company’s 2020 Proxy Statement is incorporated herein by this reference. +Item 12: SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The following table sets forth the aggregate information for the Company’s equity compensation plans in effect as of June 27, 2020. +EQUITY COMPENSATION PLAN INFORMATION +Plan category Number of securities to +be issued upon exercise +of outstanding options, +warrants, and rights +(a) Weighted-average +exercise price of +outstanding options, +warrants, and rights +(b) Number of securities +remaining available for +future issuance under +equity compensation +plans (excluding +securities reflected in +column (a) +(c) +Equity compensation plans approved by security holders (1) +869,583 $ 7.87 609,751 +Equity compensation plans not approved by security holders — $ — — +Total 869,583 $ 7.87 609,751 +(1) Included are the 1,200,000 shares subject to the 2010 Plan, the issuance of which were approved by the shareholders at the 2010 Annual Meeting. During the 2015 Annual Meeting, an additional 1,000,000 shares were approved. As a result of the shareholder approval, the Company made the decision to amend the cash-settled SARs granted during fiscal year 2010 to stock-settled SARs effective October 21, 2011. +Information under the caption “Beneficial Ownership of Securities” in the Company’s 2020 Proxy Statement is incorporated herein by this reference. +63 +Item 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions”, “Compensation Committee Interlocks and Insider Participation”, and “Directors’ Independence” in the Company’s 2020 Proxy Statement is incorporated herein by this reference. +Item 14: PRINCIPAL ACCOUNTING FEES AND SERVICES +Information appearing under the caption “Principal Accountant Fees and Services” in the Company’s 2020 Proxy Statement is incorporated herein by this reference. +PART IV +Item 15: EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +(a) 1. FINANCIAL STATEMENTS +Page in Form 10-K +FINANCIAL STATEMENTS +Report of Independent Registered Public Accounting Firm +30 +Consolidated Balance Sheets +31 +Consolidated Statements of Income (Loss) +32 +Consolidated Statements of Comprehensive Income (Loss) +33 +Consolidated Statements of Cash Flows +34 +Consolidated Statements of Shareholders’ Equity +35 +Notes to Consolidated Financial Statements +36-60 +2. SCHEDULES +II. Consolidated Valuation and Qualifying Accounts 69 +Other schedules are omitted because of the absence of conditions under which they are required, or because required information is given in the financial statements or notes thereto. +64 +3. EXHIBITS +Exhibit No. Description +3.1 +Articles of Incorporation, incorporated by reference to the Exhibit 3.1 to the Company’s form 10-K filed with the SEC for the year ended July 1, 1995 (File No. 2-83898) +3.2 +Bylaws, as amended, incorporated by reference to the Exhibit 3 (iii) to the Company’s Form 10-K for the year ended July 1, 1995 (File No. 2-83898) +10.1* +Amended and Restated 1990 Stock Option Plan for Non-Employee Directors, as amended, incorporated by reference to the Company’s 1997 Proxy Statement dated October 10, 1997 (Proposal 2) +10.2* +1995 Executive Stock Option Plan, incorporated by reference to the Company’s 1995 Proxy Statement, pages 19-22 (Proposal 3) +10.3* +2000 Employee Stock Option Plan, incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.4* +Officers’ Employment Contracts, incorporated by reference to the Company’s 1998 Proxy Statement, pages 10 and 11 +10.5* +Addenda to Officers’ Employment Contracts, incorporated by reference to Exhibits to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.6* +Description of Retention Bonus Plan, incorporated by reference to the Exhibits to the Company’s 10-Q for the quarter ended December 28, 2002 +10.7* +Addenda to Officers’ Employment Contracts, incorporated by reference to Exhibits to the Company’s Form 10-K for the year ended June 29, 2002 +10.8 +Promise to execute a Purchase and Sale Agreement with Key Safety Systems de Mexico, S.A. de C.V., incorporated by reference to the Exhibit to the Company’s Form 8-K filed April 26, 2005 +10.9 +Summary of material terms and conditions of the Purchase and Sale Agreement with Key Safety Systems de Mexico, S.A. de C.V., incorporated by reference to the Exhibit to the Company’s Form 8-K filed June 6, 2005 +10.10* +Summary of Key Tronic Corporation Long Term Incentive Compensation Plan, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed September 27, 2005 +65 +10.11* +Summary of Key Tronic Corporation Incentive Compensation Plan, incorporated by reference to Exhibit 10.23 to the Company’s Form 10-K for the year ended July 2, 2005 +10.12* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2007 and Fiscal Years 2007 – 2009 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 28, 2006 +10.13 +Summary of material terms and conditions of the Purchase and Sale Agreement with Todenko Mexico S.A. de C.V., incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed October 12, 2006 +10.14 +Summary of material terms and conditions of the Purchase and Sale Agreement with Todenko Mexico S.A. de C.V., incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed November 20, 2006 +10.15 +Summary of material terms and conditions of the Sale and Purchase Agreement with Adevco Corporation, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed January 5, 2007 +10.16 +Summary of Second Amendment to Agreement of Sale and Purchase Agreement with Adevco Corporation, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed April 11, 2007 +10.17* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2008 and Fiscal Years 2008-2010 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 27, 2007 +10.18* +Summary of Incentive Compensation Plan Performance Goals and Target payments for Fiscal Year 2009 and Fiscal Years 2009 – 2011 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 24, 2008 +10.19* +Summary of Incentive Compensation Plan Performance Goals and Target payments for Fiscal Year 2010 and Fiscal Years 2010 – 2012 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 23, 2009 +10.20 +Financing Agreement with Wells Fargo Bank, N.A., incorporated by reference to the Exhibits to the Company’s Form 8-K filed on August 24, 2009 +10.21* +2010 Incentive Plan, incorporated by reference to Exhibit 10.36 to the Company’s Form 10-K for the year ended July 3, 2010 +10.22* +Employment Contract with Douglas G. Burkhardt, incorporated by reference to Exhibit 10.37 to the Company’s Form 10-K for the year ended July 3, 2010 +10.23 +Summary of material terms and conditions of the Purchase and Sale Agreement with Autopartes Y Arneses de Mexico S.A. de C.V., incorporated by reference to Exhibit 10.38 to the Company’s Form 10-K for the year ended July 3, 2010 +10.24* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2011 and Fiscal Years 2011 – 2013 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 23, 2010 +10.25* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2012 and Fiscal Years 2012 – 2014 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 2, 2011 +66 +10.26* +Amendment to Employment Contract of Craig D. Gates, dated August 23, 2011; of Ronald F. Klawitter, dated August 23, 2011 and of Douglas G. Burkhardt dated September 6, 2011; incorporated by reference to the Exhibits to the Company’s Form 10-K for the year ended July 2, 2011 filed on September 12, 2011 +10.27 +Second Loan Modification Agreement to the Credit Agreement with Wells Fargo Bank, N.A., incorporated by reference to the Exhibits to the Company’s Form 8-K filed on February 2, 2012 +10.28* +Amendment to Employment Contract of Craig D. Gates, dated May 10, 2012, incorporated by reference to the Exhibits to the Company’s Form 10-Q filed on May 14, 2012 +10.29* +Amendment to Employment Contract of Douglas G. Burkhardt dated May 10, 2012; incorporated by reference to the Exhibits to the Company’s Form 10-Q filed on May 14, 2012 +10.30* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2013 and Fiscal Years 2013 – 2015 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 7, 2012 +10.31* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2014 and Fiscal Years 2014 – 2016 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 6, 2013 +10.32* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2015 and Fiscal Years 2015 – 2017 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 1, 2014 +10.33 +Summary of material terms and conditions of the Stock Purchase Agreement with CDR Manufacturing and Amended and Restated Credit Agreement with Wells Fargo Bank, N. A. incorporated by reference to the Company’s Form 8-K filed September 9, 2014 +10.34* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2016 and Fiscal Years 2016 – 2018 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 30, 2015 +10.35 +First Amendment to Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, incorporated by reference to the Company's Form 8-K filed August 11, 2015 +10.36 +Second Replacement Revolving Line of Credit Note with Wells Fargo Bank, National Association, incorporated by reference to the Company's Form 8-K filed August 11, 2015 +10.37* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2017 and Fiscal Years 2017 – 2019 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 29, 2016 +10.38* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2018 and Fiscal Years 2018 – 2020 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 22, 2017 +10.39 +Announcement of contract awarded with SkyBell Technologies, a global leader in patented Wi-Fi video doorbell technology incorporated by reference to the Company’s Form 8-K filed May 1, 2018 +10.40* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2019 and Fiscal Years 2019 – 2021 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 2, 2018 +67 +10.41 +Announcement of award of $6.7 million following the conclusion of a previously disclosed arbitration proceeding incorporated by reference to the Company's Form 8-K filed September 5, 2018 +10.42 +Announcement that the Company has signed a letter of intent to lease a new facility in Da Nang, Vietnam +10.43* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2020 and Fiscal Years 2020 – 2022 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 30, 2019 +10.44* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2021 and Fiscal Years 2021 – 2023 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 27, 2020 +21 +Subsidiaries of Registrant, submitted herewith +23.1 +Consent of Independent Registered Public Accounting Firm, submitted herewith +31.1 +Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer, submitted herewith +31.2 +Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer, submitted herewith +32.1 +Section 1350 Certification of Chief Executive Officer, submitted herewith +32.2 +Section 1350 Certification of Chief Financial Officer, submitted herewith +101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. +101.SCH XBRL Taxonomy Extension Schema Document ** +101.CAL XBRL Taxonomy Extension Calculation Linkbase Document ** +101.DEF XBRL Taxonomy Extension Definition Linkbase Document ** +101.LAB XBRL Taxonomy Extension Label Linkbase Document ** +101.PRE XBRL Taxonomy Extension Presentation Linkbase Document ** +104 Cover Page Interactive Data File (formatted as inline XBRL with applicable taxonomy extention information contained in Exhibits 101.INS, 101.SCH, 101.CAL, 101.DEF, 101.LAB and 101.PRE) +* Management contract or compensatory plan or arrangement +** Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities and Exchange Act of 1934, as amended and otherwise are not subject to liability under those sections. +68 +SCHEDULE II +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS +FISCAL YEARS ENDED JUNE 27, 2020, JUNE 29, 2019, AND JUNE 30, 2018 +Fiscal Year Ended +2020 2019 2018 +(in thousands) +Allowance for Obsolete Inventory +Balance at beginning of year $ 1,792 $ 1,458 $ 1,306 +Provisions 136 91 31 +Dispositions 40 243 121 +Balance at end of year $ 1,968 $ 1,792 $ 1,458 +Allowance for Doubtful Accounts +Balance at beginning of year $ 58 $ — $ 84 +Provisions (Recovery) 551 58 ( 84 ) +Write-offs — — — +Balance at end of year $ 609 $ 58 $ — +69 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +Dated: September 11, 2020 +KEY TRONIC CORPORATION +By: /s/ Craig D. Gates +Craig D. Gates, President and Chief Executive Officer +(Principal Executive Officer) +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated: +/s/ Craig D. Gates September 11, 2020 +Craig D. Gates Date +Director and President and Chief Executive Officer +(Principal Executive Officer) +/s/ Brett R. Larsen September 11, 2020 +Brett R. Larsen Date +Executive Vice President of Administration, Chief Financial Officer and Treasurer +(Principal Financial Officer) +/s/ Ronald F. Klawitter September 11, 2020 +Ronald F. Klawitter, Director Date +/s/ James R. Bean September 11, 2020 +James R. Bean, Director Date +/s/ Subodh K. Kulkarni September 11, 2020 +Subodh K. Kulkarni, Director Date +/s/ Yacov A. Shamash September 11, 2020 +Yacov A. Shamash, Director Date +/s/ Patrick Sweeney September 11, 2020 +Patrick Sweeney, Director and Chairman of the Board Date +70 \ No newline at end of file diff --git a/raw/filings/0000719733/2020/0000719733-20-000061/filing_metadata.csv b/raw/filings/0000719733/2020/0000719733-20-000061/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..7e904213722ddb8ad75d5b6f1bac28bc85a5d1bd --- /dev/null +++ b/raw/filings/0000719733/2020/0000719733-20-000061/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000719733,KTCC,KEY TRONIC CORP,10-K,2020-09-11,2020-06-27,2020-09-11T18:50:53.000Z,0000719733-20-000061,ktcc-20200627.htm,10-K,11386370,1,1,https://www.sec.gov/Archives/edgar/data/719733/000071973320000061/ktcc-20200627.htm,https://www.sec.gov/Archives/edgar/data/719733/000071973320000061/,2020,2020,1 diff --git a/raw/filings/0000719733/2020/0000719733-20-000061/item1.txt b/raw/filings/0000719733/2020/0000719733-20-000061/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..f9a0b4c0bf2d5fd95f0f24800d807499a01bb5e7 --- /dev/null +++ b/raw/filings/0000719733/2020/0000719733-20-000061/item1.txt @@ -0,0 +1,75 @@ +Item 1. BUSINESS +Background +Key Tronic Corporation (dba: KeyTronicEMS Co.) was organized in 1969, as a Washington corporation that locally manufactured computer keyboards. The ability to design, build and deliver a quality product led us to become a leading independent manufacturer of keyboards for computers in the United States. Our fully integrated design, tooling, and automated manufacturing capabilities enabled us to rapidly respond to customers’ needs for keyboards in production quantities worldwide. We supported our sales growth through the development and purchase of international manufacturing facilities. As the computer keyboard market matured with increasing competition from other international providers, we determined that our business could no longer solely rely on keyboard sales. +After assessing market conditions and our strengths and capabilities, we shifted our focus from keyboard manufacturing to contract manufacturing for a wide range of products. Our unique strategic attributes are based on our core strengths of innovative design and engineering expertise in electronics, mechanical engineering, sheet metal fabrication and stamping, and precision plastics combined with high-quality, low cost production, and assembly on an international basis while providing exceptional customer service. These strengths have made our company a strong competitor in the electronic manufacturing services (EMS) market. +Our Industry and Strategy +The expansion of the EMS industry and our acquisitions have allowed us to continue to expand our customer base and the industries that we serve. The increase in new programs represents a growing portion of our revenue and a promising foundation for our future. In keeping with our long-term strategic objectives, we have been successfully building a more diversified customer portfolio, spanning a wider range of industries. We currently offer our customers the following services: integrated electronic and mechanical engineering, precision plastic molding, sheet metal fabrication, printed circuit board (PCB) and complete product assembly, component selection, sourcing and procurement, worldwide logistics, and new product testing and production all at competitive pricing due to our global footprint. We differentiate ourselves from others our size and larger in the EMS industry by providing vertical integration, a flexible and responsive approach to our customer’s changing supply demand, and complete design engineering support. +We believe that we are well positioned in the EMS industry to continue the expansion of our customer base and achieve long-term growth. Our unique blend of multinational facilities, vertical integration, centralized management, and core strengths continue to support our growth and our customers’ needs. We continue to focus on controlling operating expenses and leveraging the synergistic capabilities of our world-class facilities in the United States, Mexico, China and Vietnam. This international production capability provides our customers with the benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs, and reduced product fulfillment time. Given our competitive advantages and the growing pressure for new potential customers to move forward with their outsourcing strategies, we are strongly positioned to win new business in coming periods and grow our revenue and profits. +4 +The EMS industry is intensely competitive. Although our customer base is growing, we still have less than 1% of the potential global market and our revenue can fluctuate significantly due to reliance on a concentrated base of customers. We are planning for new customer growth in the coming quarters by securing new programs with new and existing customers, increasing our worldwide manufacturing capacity, leveraging further our design engineering capabilities and continuing to improve our manufacturing and procurement processes and capabilities. Ongoing challenges that we face include but are not limited to the following: continuing to win programs from new and existing customers, balancing capital employed, production capacity and key personnel in support of new customer programs, improving operating efficiencies, controlling costs while developing competitive pricing strategies, and successfully transitioning new program wins to full production. +Customers and Marketing +We provide a mix of manufacturing services for outsourced Original Equipment Manufacturing (OEM) products. We provide the following EMS services: product design, surface mount technologies (SMT) and pin through hole capability for printed circuit board assembly, tool making, precision plastic molding, sheet metal fabrication and painting, liquid injection molding, complex assembly, automated tape winding, prototype design and full product assembly. +Sales of the majority of our products have not historically been seasonal in nature, but may be seasonal in the future if there are changes in the types of products manufactured. Sales can, however, fluctuate significantly between quarters from changes in customers and customer demand due to the concentration of sales generated by our largest customers. +For the fiscal years 2020, 2019 and 2018, the five largest customers in each year accounted for 40%, 41% and 42% of combined total net sales, respectively. We continue to diversify our customer base by adding additional programs and customers. We expect net sales to our five largest customers as a percentage of total net sales to approximate current levels going forward. +The following table represents all customers that represented 10% or more of total net sales during the last three fiscal years: +Percentage of Net Sales by Fiscal Year +2020 2019 2018 +Customer A 18% 17% 19% +There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +We market our products and services primarily through our direct sales department which is comprised of strategically located field sales people and distributors. We also maintain relationships with several independent sales organizations to assist in marketing our EMS product lines. +Manufacturing +We have continually made investments in developing and expanding a capital equipment base to achieve vertical integration and efficiencies in our manufacturing processes. We have invested significant capital into SMT for volume manufacturing of complex printed circuit board assemblies and in our metal shop providing precision metal stamping, fabricating, and finishing. We also design and develop tooling for injection molding and sheet metal fabrication and manufacture the majority of plastic and sheet metal parts used in the products we manufacture. Additionally, we have equipment to maintain a controlled clean environment for manufacturing processes that require a high level of precise control. +We use a variety of manual and automated assembly processes in our facilities, depending upon product complexity and degree of customization. Some examples of automated processes include component insertion, SMT, selective soldering, flexible robotic assembly, automated storage tape winding, computerized vision system quality inspection, laser turrets, automated switch and key top installation, robotic welding, automated powder coat application, and automated functional testing. +Our engineering expertise and automated manufacturing processes enable us to work closely with our customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. We use computer-aided design techniques and software to assist in preparation of the tool design layout and component placement, to reduce tooling and production costs, improve component and product quality, and enhance turnaround time during product development. +We purchase materials and components for our products from many different suppliers, including both domestic and international sources. We develop close working relationships with our suppliers, many of whom have been supplying products to us for several years. +5 +Research, Development, and Engineering +As part of our long-term strategy, we are committed to supporting our customers by providing research, development, and engineering services. We have seen an increase in the success of providing design support on existing and potential customers in differentiating ourselves. These services allow us to facilitate in optimizing new product designs, and the production processes of our customers’ programs. +Research, development, and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials costs, depreciation, and allocated information technology and facilities costs. +Competition +The market for the products and services we provide is highly competitive. There are numerous competitors in the EMS industry, many of which have substantially more resources and are more geographically diverse than we are. Some of our competitors have similar international production capabilities, large financial resources and some have substantially greater manufacturing, research and development, and marketing resources. There is also competition from the manufacturing operations of our current and potential customers, who are continually evaluating the merits of manufacturing their products internally versus the advantages of outsourcing. We believe that we can currently compete favorably in these areas primarily on the basis of our international footprint, responsiveness, creativity, vertical production capability, quality, and cost. +Trademarks +Our name and logo are federally registered trademarks, and we believe they are valuable assets of our business. We operate under the trade name “KeyTronicEMS” to better identify our primary business concentration in contract manufacturing in the EMS industry. +Employees +We consider our employees to be our primary strength and we make considerable efforts to maintain a well-qualified workforce. Our employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. We regularly provide transportation, medical services, and meals to all of our employees in foreign locations. The Company also has defined contribution plans available to U.S. employees who have attained age 21 and provide group health, life, and disability insurance plans. We also maintain share based compensation plans and other long-term incentive plans for certain employees and outside directors. +As of June 27, 2020 we had 5,741 full-time employees compared to 4,067 on June 29, 2019, and 4,701 on June 30, 2018. Since we can have significant fluctuations in product demand, we seek to maintain flexibility in our workforce by utilizing skilled temporary labor in some of our manufacturing facilities in addition to full-time employees. +Backlog +On July 25, 2020 our order backlog was valued at approximately $215.3 million, compared to approximately $159.5 million on July 27, 2019. The amount of backlog is not necessarily indicative of future sales but can be indicative of trends in expected future sales revenue. Due to the relationships with our customers, we will occasionally allow orders to be canceled or rescheduled and as a result it is not a meaningful indicator of future financial results. If there are canceled or rescheduled orders, we typically negotiate fees to cover the costs we have incurred. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change due to design modifications, customer forecast changes, or other customer requirements. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in Note 12, “Enterprise-Wide Disclosures” of the consolidated financial statements of this Annual Report on Form 10-K and that information is incorporated herein. +6 +Executive Officers of the Registrant +The table below sets forth the name, current age and current position of our executive officers and other significant employees: +Name Age Positions Held +Executive Officers +Craig D. Gates 61 President and Chief Executive Officer +Brett R. Larsen 47 Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Philip S. Hochberg 58 Executive Vice President of Business Development +Duane D. Mackleit 52 Executive Vice President of Operations +David H. Knaggs 39 Vice President of Quality and Regulatory Affairs +Chad T. Orebaugh 49 Vice President of Engineering +Thomas Despres 58 +Vice President of Southwest Operations +Mark Courtney 54 +Vice President of Supply Chain +Executive Officers +CRAIG D. GATES – President and Chief Executive Officer +Mr. Gates, age 61, has been President and Chief Executive officer of the Company since April 2009. Previously, he was Executive Vice President and General Manager from August 2002 to April 2009. He served as Executive Vice President of Marketing, Engineering and Sales from July 1997 to August 2002 and served as Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of 1994. From 1982 to 1991 he held various engineering and management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. Mr. Gates has a Bachelor of Science Degree in Mechanical Engineering and a Masters in Business Administration from the University of Illinois, Urbana. +BRETT R. LARSEN – Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Mr. Larsen, age 47, has served as Executive Vice President of Administration, Chief Financial Officer, and Treasurer since July 2015. Previously, he was Vice President of Finance and Controller from February 2010 to July 2015. He was Chief Financial Officer of FLSmidth Spokane, Inc. from December 2008 to February 2010. From October 2005 through November 2008, Mr. Larsen served as Controller of Key Tronic Corporation. From May 2004 to October 2005, Mr. Larsen served as Manager of Financial Reporting of Key Tronic Corporation. From 2002 to May 2004, Mr. Larsen was an audit manager for the public accounting firm BDO USA, LLP. He also held various auditing and supervisory positions with Grant Thornton LLP from 1997 to 2002. Mr. Larsen has a Bachelor of Science degree in Accounting and a Masters degree in Accounting from Brigham Young University and is a Certified Public Accountant. +PHILIP S. HOCHBERG – Executive Vice President of Business Development +Mr. Hochberg, age 58, has been Executive Vice President of Business Development since July 2012. Prior to this, Mr. Hochberg served as Vice President of Business Development from October 2009 through June 2012. He was Director of Business Development and Program Management from July 2008 to October 2009. Mr. Hochberg served as Director of Business Development from October 2004 to July 2008 and as Director of EMS Sales and Marketing from July 2000 to October 2004. Prior to joining Key Tronic, Mr. Hochberg worked for Quinton Instrument Company as their Director of Marketing and Product Management from 1992 to 2000. From 1988 to 1992, he was employed by SpaceLabs Medical as their Business Development Marketing Manager. Mr. Hochberg has an MBA from the University of British Columbia, a BA in Psychology, with a minor in Business from Washington University in St. Louis. +7 +DUANE D. MACKLEIT – Executive Vice President of Operations +Mr. Mackleit, age 52, has been Executive Vice President of Operations since December 2019. Prior to this, Mr. Mackleit served as Vice President of Program Management since July 2012. He served as Director of Program Management from July 2008 through June 2012. From May 2006 to July 2008 he served as Principal Program Manager. Prior to that, he served as Program Manager from March 2002 to May 2006 and Associate Program Manager from August 2000 to March 2002. Mr. Mackleit has also held several other positions with Key Tronic Corporation. Mr. Mackleit has an AA in Business from Spokane Falls Community College and a BA in Business/Marketing from Eastern Washington University. He also holds a MBA from Gonzaga University. +DAVID H. KNAGGS – Vice President of Quality and Regulatory Affairs +Mr. Knaggs, age 39, has been Vice President of Quality and Regulatory Affairs since November 2017. Previously he was Vice President of Quality since October 2016. Before joining KeyTronicEMS, Mr. Knaggs worked at Telect, Inc. from 2008 to 2016 as their Director of Engineering. Prior to that, he worked at Isothermal Systems Research as Lead Systems Engineer from 2003 to 2008. He has a Bachelor of Science degree in Mechanical Engineering with a minor in mathematics from the University of Washington. +CHAD T. OREBAUGH – Vice President of Engineering +Mr. Orebaugh, age 49, has been Vice President of Engineering since April 2017. Prior to this, Mr. Orebaugh served as Director of Engineering since May 2013. From April 2010 to May 2013, he served as Manager of Engineering. From January 2000 to April 2010 he served as Lead Mechanical Engineer. Prior to that, he served as Mechanical Engineer from October 1998 to January 2000 and Associate Mechanical Engineer since October 1997. Mr. Orebaugh holds a BA in Mechanical Engineering from Gonzaga University. +THOMAS DESPRES – Vice President of Southwest Operations +Thomas Despres, age 58, has been Vice President of Southwest Operations since November 2017. Prior to joining KeyTronicEMS, Mr. Despres worked for Gates Corporation as Plant General Manager from July 2017 to November 2017. From 2016 to 2017, he was self-employed and from 2012 to 2016 he was employed by Flextronics as Vice President Global Account Management. He has an MBA from Campbell University, and a BBA, Production Management from Ohio University in Athens. +MARK COURTNEY – Vice President of Supply Chain +Mark Courtney, age 54, has been Vice President of Supply Chain of the company since August 2019. Previously, he served as Purchasing Manager and Director of North American Purchasing from September 2015 to August 2019, and as Supply Chain Manager, ERP and Business Operations Manager for Amphenol Telect from August 2007 to September 2015. From March 2006 to August 2007, he served as Senior Buyer/Planner for Honeywell Specialty Materials and from June 2005 to March 2006 as Purchasing Manager for MRV Communications. From May 2000 to June 2005, he served as a Field and Inside Sales Associate for Arrow Electronics and from October 1991 to May 2000 held various positons at Alesis. +Available Information +Our principal executive offices are located at 4424 North Sullivan Road, Spokane Valley, Washington 99216, and our telephone number is (509) 928-8000. Our website is located at http://www.keytronic.com where filings of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or current reports on Form 8-K are available after they have been filed with the Securities and Exchange Commission. The information presented on our website currently and in the future is not considered to be part of this document or any document incorporated by reference in this document. +8 \ No newline at end of file diff --git a/raw/filings/0000719733/2020/0000719733-20-000061/item13.txt b/raw/filings/0000719733/2020/0000719733-20-000061/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..99f25efff492516accd3649d9d9683ebba9bfc4b --- /dev/null +++ b/raw/filings/0000719733/2020/0000719733-20-000061/item13.txt @@ -0,0 +1,2 @@ +Item 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions”, “Compensation Committee Interlocks and Insider Participation”, and “Directors’ Independence” in the Company’s 2020 Proxy Statement is incorporated herein by this reference. \ No newline at end of file diff --git a/raw/filings/0000719733/2020/0000719733-20-000061/item9a.txt b/raw/filings/0000719733/2020/0000719733-20-000061/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..16341a1cda945000d12c25e6e3f74b07371d0449 --- /dev/null +++ b/raw/filings/0000719733/2020/0000719733-20-000061/item9a.txt @@ -0,0 +1,28 @@ +Item 9A: CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +It is the responsibility of our management to establish, maintain, and monitor disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 are recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Additionally, these disclosure controls include controls and procedures that are designed to accumulate and communicate the information required to be disclosed to our Company’s Chief Executive Officer and Chief Financial Officer, allowing for timely decisions regarding required disclosures. As of the end of the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(f). Based on our assessment, we believe that as of June 27, 2020, the Company’s disclosure controls and procedures are effective based on that criteria. +Management’s Report on Internal Control over Financial Reporting +Our management has the responsibility to establish and maintain adequate internal controls over our financial reporting, as defined in Rule 13a-15(f) under the Securities and Exchange Act of 1934. Our internal controls are designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our external financial statements in accordance with generally accepted accounting principles (GAAP). +Due to inherent limitations of any internal control system, management acknowledges that there are limitations as to the effectiveness of internal controls over financial reporting and therefore recognize that only reasonable assurance can be gained from any internal control system. Accordingly, our internal control system may not detect or prevent material misstatements in our financial statements and projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, we have performed an assessment of the effectiveness of our internal controls over financial reporting as of June 27, 2020. This assessment was based on the criteria established in Internal Control-Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that as of June 27, 2020, the Company’s internal control over financial reporting is effective based on that criteria. +The effectiveness of the Company's internal control over financial reporting as of June 27, 2020 has been audited by BDO USA LLP, an independent registered public accounting firm, as stated in their report which is included herein. +Changes in Internal Control over Financial Reporting +There have been no significant changes in our internal controls over financial reporting during our fourth fiscal quarter ended June 27, 2020 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)). +61 +Report of Independent Registered Public Accounting Firm +Shareholders and Board of Directors +Key Tronic Corporation +Spokane Valley, Washington +Opinion on Internal Control over Financial Reporting +We have audited Key Tronic Corporation’s (the “Company’s”) internal control over financial reporting as of June 27, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of June 27, 2020, based on the COSO criteria. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company as of June 27, 2020 and June 29, 2019, the related consolidated statements of income (loss), comprehensive income (loss), shareholders’ equity, and cash flows for each of the three years in the period ended June 27, 2020, and the related notes and schedule and our report dated September 11, 2020 expressed an unqualified opinion thereon. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying “Item 9A, Management’s Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit of internal control over financial reporting in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ BDO USA, LLP +Spokane, Washington +September 11, 2020 +62 \ No newline at end of file diff --git a/raw/filings/0000719733/2020/0000719733-20-000061/rp_note.txt b/raw/filings/0000719733/2020/0000719733-20-000061/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000719733/2020/0000719733-20-000061/rpt_disclosure.txt b/raw/filings/0000719733/2020/0000719733-20-000061/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..d1ddd1a1801f59b5b63c6f8232a9f8846d103611 --- /dev/null +++ b/raw/filings/0000719733/2020/0000719733-20-000061/rpt_disclosure.txt @@ -0,0 +1,6 @@ +Related Person Transactions +In April 2007, the Board of Directors adopted a written policy and procedures for the approval or ratification of Interested Transactions with Related Parties. The policy and procedures supplement the Company’s Code of Conduct. The policy defines an “Interested Transaction” as any transaction, arrangement or relationship or series of similar transactions, arrangements or relationships (including any indebtedness or guarantee of indebtedness) in which (1) the aggregate amount involved will or may be expected to exceed $120,000 in any calendar year, (2) the Company is a participant, and (3) any Related Party has or will have a direct or indirect interest (other than solely as a result of being a director or a less than 10 percent beneficial owner of another entity). +The policy defines a “Related Party” as any (a) person who is or was (since the beginning of the last fiscal year for which the Company has filed a Form 10-K and proxy statement, even if they do not presently serve in that role) an executive officer, director or nominee for election as a director, (b) greater than 5 percent beneficial owner of the Company’s common stock, or (c) immediate family member of any of the foregoing. Immediate family member includes a person’s spouse, parents, stepparents, children, stepchildren, siblings, mothers- and fathers-in-law, sons- and daughters-in-law, and brothers- and sisters-in-law and anyone residing in such person’s home (other than a tenant or employee). +The Audit Committee is responsible for review, approval, ratification or disapproval of Interested Transactions. In determining whether to approve or ratify an Interested Transaction, the Committee will take into account, among other factors it deems appropriate, whether the Interested Transaction is on terms no less favorable than terms generally available to an unaffiliated third party under the same or similar circumstances and the extent of the Related Party’s interest in the Transaction. +During the fiscal years 2020 and 2019, the Company had no transactions with CyberOptics. During fiscal year 2018, the Company purchased surface mount technology inspection equipment from CyberOptics. The purchases by the Company during fiscal year 2018 totaled $159,600. These transactions were conducted at arm’s length in the ordinary course of business of the Company and CyberOptics, and the terms of purchase were no more favorable to the Company than purchases by unaffiliated parties from CyberOptics. +7 \ No newline at end of file diff --git a/raw/filings/0000719733/2021/0000719733-21-000106/filing.txt b/raw/filings/0000719733/2021/0000719733-21-000106/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..ae2d05887f7b17a923c79458ba4751c41be76973 --- /dev/null +++ b/raw/filings/0000719733/2021/0000719733-21-000106/filing.txt @@ -0,0 +1,1592 @@ +ktcc-20210703 +false 2021 FY --06-27 0000719733 10,761,871 78.7 275 609 — — 25,000 25,000 10,762 10,760 10,762 10,760 3 30 1 10 3 5 4.40 7.90 7.91 9.91 4.40 11.34 4 7 0000719733 2020-06-28 2021-07-03 iso4217:USD 0000719733 2020-12-26 xbrli:shares 0000719733 2021-09-09 0000719733 2021-07-03 0000719733 2020-06-27 iso4217:USD xbrli:shares 0000719733 2019-06-30 2020-06-27 0000719733 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+____________________________________________________________ +FORM 10-K +____________________________________________________________ +☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE FISCAL YEAR ENDED JULY 3, 2021 +OR +☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE PERIOD FROM TO +Commission File Number 0-11559 +____________________________________________________________ +KEY TRONIC CORP ORATION +(Exact name of registrant as specified in its charter) +____________________________________________________________ +Washington 91-0849125 +(State or other jurisdiction of +Incorporation or organization) (I.R.S. Employer +Identification No.) +4424 North Sullivan Road Spokane Valley, Washington 99216 +(Address of principal executive offices) (Zip Code) +( 509 ) 928-8000 +(Registrant’s telephone number, including area code) +N/A +(Former name, former address and former fiscal year, if changed since last report) +____________________________________________________________ +Securities Registered Pursuant to Section 12(b) of the Act: +Title of each class Trading Symbol Name of each exchange on which registered +Common stock, no par value KTCC The NASDAQ Stock Market LLC +Securities Registered Pursuant to Section 12(g) of the Act: None +____________________________________________________________ +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ☐ No ☒ +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulations S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. +(Check one): +Large accelerated filer ☐ Accelerated filer ☒ +Non-accelerated filer +☐ +Smaller reporting company ☒ +Emerging growth company ☐ +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ +Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ +State the aggregate market value of the voting and non-voting common equity held by non affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. +As of December 24, 2020, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $ 78.7 million based on the closing price as reported on the NASDAQ. +Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: 10,761,871 shares of common stock were outstanding as of September 9, 2021. +____________________________________________________________ +Documents Incorporated by Reference: +Certain information is incorporated into Part III of this report by reference to the Proxy Statement for the registrant’s 2021 annual meeting of stockholders to be filed with the Securities and Exchange Commission pursuant to Regulation 14A not later than 120 days after the end of the fiscal year covered by this Form 10-K. +KEY TRONIC CORPORATION +2021 FORM 10-K +TABLE OF CONTENTS +Page No. +PART I +Item 1. +Business +4 +Item 1A. +Risk Factors +9 +Item 1B. +Unresolved Staff Comments +16 +Item 2. +Properties +17 +Item 3. +Legal Proceedings +18 +Item 4. +Mine Safety Disclosures +18 +PART II +Item 5. +Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities +18 +Item 6. +Selected Financial Data +20 +Item 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +21 +Item 7A. +Quantitative and Qualitative Disclosures about Market Risk +30 +Item 8. +Financial Statements and Supplementary Data +30 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +59 +Item 9A. +Controls and Procedures +60 +Item 9B. +Other Information +63 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +63 +Item 11. +Executive Compensation +63 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +63 +Item 13. +Certain Relationships and Related Transactions, and Director Independence +64 +Item 14. +Principal Accounting Fees and Services +64 +PART IV +Item 15. +Exhibits and Financial Statement Schedule +64 +Item 16. +Form 10-K Summary +70 +Signatures +71 +3 +FORWARD-LOOKING STATEMENTS +References in this report to “the Company,” “Key Tronic,” “we,” “our,” or “us” mean Key Tronic Corporation together with its subsidiaries, except where the context otherwise requires. +This Annual Report on Form 10-K contains forward-looking statements in addition to historical information. Forward-looking statements include, but are not limited to those including such words as aims, anticipates, believes, continues, could, estimates, expects, hopes, intends, plans, predicts, projects, targets, or will, similar verbs, or nouns corresponding to such verbs, which may be forward looking. Forward-looking statements also include other passages that are relevant to expected future events, performances, and actions or that can only be fully evaluated by events that will occur in the future. Forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those reflected in the forward-looking statements. Risks and uncertainties that might cause such differences include, but are not limited to those outlined in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risks and Uncertainties that May Affect Future Results” and in “Risk Factors.” Readers are cautioned not to place undue reliance on forward-looking statements, which reflect management’s opinions only as of the date hereof. The Company undertakes no obligation to update forward-looking statements to reflect developments or information obtained after the date hereof and disclaims any obligation to do so. Readers should carefully review the risk factors described in periodic reports the Company files from time to time with the Securities and Exchange Commission, including Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. +PART I +Item 1. BUSINESS +Background +Key Tronic Corporation was organized in 1969, as a Washington corporation that locally manufactured computer keyboards. The ability to design, build and deliver a quality product led us to become a leading independent manufacturer of keyboards for computers in the United States. Our fully integrated design, tooling, and automated manufacturing capabilities enabled us to rapidly respond to customers’ needs for keyboards in production quantities worldwide. We supported our sales growth through the development and purchase of international manufacturing facilities. As the computer keyboard market matured with increasing competition from other international providers, we determined that our business could no longer solely rely on keyboard sales. +After assessing market conditions and our strengths and capabilities, we shifted our focus from keyboard manufacturing to contract manufacturing for a wide range of products. Our unique strategic attributes are based on our core strengths of innovative design and engineering expertise in electronics, mechanical engineering, sheet metal fabrication and stamping, and precision plastics combined with high-quality, low cost production, and assembly on an international basis while providing exceptional customer service. These strengths have made our company a strong competitor in the contract manufacturing market. +Our Industry and Strategy +The expansion of the contract manufacturing industry and our acquisitions have allowed us to continue to expand our customer base and the industries that we serve. The increase in new programs represents a growing portion of our revenue and a promising foundation for our future. In keeping with our long-term strategic objectives, we have been successfully building a more diversified customer portfolio, spanning a wider range of industries. We currently offer our customers the following services: integrated electronic and mechanical engineering, precision plastic molding, sheet metal fabrication, printed circuit board (PCB) and complete product assembly, component selection, sourcing and procurement, worldwide logistics, and new product testing and production all at competitive pricing due to our global footprint. We differentiate ourselves from others our size and larger in the contract manufacturing industry by providing vertical integration, a flexible and responsive approach to our customer’s changing supply demand, and complete design engineering support. +We believe that we are well positioned in the contract manufacturing industry to continue the expansion of our customer base and achieve long-term growth. Our unique blend of multinational facilities, vertical integration, centralized management, and core strengths continue to support our growth and our customers’ needs. We continue to focus on controlling operating expenses and leveraging the synergistic capabilities of our world-class facilities in the United States, Mexico, China and Vietnam. This international production capability provides our customers with the benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs, and reduced product fulfillment time. Given our competitive advantages and the growing pressure for new potential customers to move forward with their outsourcing strategies, we feel that we are strongly positioned to win new business in coming periods and grow our revenue and profits. +4 +The contract manufacturing industry is intensely competitive. Although our customer base is growing, we still have less than 1% of the potential global market and our revenue can fluctuate significantly due to reliance on a concentrated base of customers. We are planning for new customer growth in the coming quarters by seeking to secure new programs with new and existing customers, increase our worldwide manufacturing capacity, leverage further our design engineering capabilities and continue to improve our manufacturing and procurement processes and capabilities. Ongoing challenges that we face include but are not limited to the following: continuing to win programs from new and existing customers, balancing capital employed, production capacity and key personnel in support of new customer programs, improving operating efficiencies, controlling costs while developing competitive pricing strategies, and successfully transitioning new program wins to full production. +Customers and Marketing +We provide a mix of manufacturing services for outsourced Original Equipment Manufacturing (OEM) products. We provide the following services: product design, surface mount technologies (SMT) and pin through hole capability for printed circuit board assembly, tool making, precision plastic molding, sheet metal fabrication and painting, liquid injection molding, complex assembly, automated tape winding, prototype design and full product assembly. +Sales of the majority of our products have not historically been seasonal in nature, but may be seasonal in the future if there are changes in the types of products manufactured. Sales can, however, fluctuate significantly between quarters from changes in customers and customer demand due to the concentration of sales generated by our largest customers. +For the fiscal years 2021, 2020 and 2019, the five largest customers in each year accounted for 40%, 40% and 41% of combined total net sales, respectively. We continue to diversify our customer base by adding additional programs and customers. We expect net sales to our five largest customers as a percentage of total net sales to approximate current levels going forward. +The following table represents the only customer that represented 10% or more of total net sales during the last three fiscal years: +Percentage of Net Sales by Fiscal Year +2021 2020 2019 +Customer A 24% 18% 17% +There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +We market our products and services primarily through our direct sales department which is comprised of strategically located field sales people and distributors. We also maintain relationships with several independent sales organizations to assist in marketing our product lines. +Manufacturing +We have continually made investments in developing and expanding a capital equipment base to achieve vertical integration and efficiencies in our manufacturing processes. We have invested significant capital into SMT for volume manufacturing of complex printed circuit board assemblies and in our metal shop providing precision metal stamping, fabricating, and finishing. We also design and develop tooling for injection molding and sheet metal fabrication and manufacture the majority of plastic and sheet metal parts used in the products we manufacture. Additionally, we have equipment to maintain a controlled clean environment for manufacturing processes that require a high level of precise control. +We use a variety of manual and automated assembly processes in our facilities, depending upon product complexity and degree of customization. Some examples of automated processes include component insertion, SMT, selective soldering, flexible robotic assembly, automated storage tape winding, computerized vision system quality inspection, laser turrets, automated switch and key top installation, robotic welding, automated powder coat application, and automated functional testing. +Our engineering expertise and automated manufacturing processes enable us to work closely with our customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. We use computer-aided design techniques and software to assist in preparation of the tool design layout and component placement, to reduce tooling and production costs, improve component and product quality, and enhance turnaround time during product development. +5 +We purchase materials and components for our products from many different suppliers, including both domestic and international sources. We develop close working relationships with our suppliers, many of whom have been supplying products to us for several years. +Research, Development, and Engineering +As part of our long-term strategy, we are committed to supporting our customers by providing research, development, and engineering services. We have seen an increase in the success of providing design support on existing and potential customers in differentiating ourselves. We believe these services allow us to facilitate in optimizing new product designs, and the production processes of our customers’ programs. +Research, development, and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials costs, depreciation, and allocated information technology and facilities costs. +Competition +The market for the products and services we provide is highly competitive. There are numerous competitors in the contract manufacturing industry, many of which have substantially more resources and are more geographically diverse than we are. Some of our competitors have similar international production capabilities, large financial resources and some have substantially greater manufacturing, research and development, and marketing resources. There is also competition from the manufacturing operations of our current and potential customers, who are continually evaluating the merits of manufacturing their products internally versus the advantages of outsourcing. We believe that we can currently compete favorably in these areas primarily on the basis of our international footprint, responsiveness, creativity, vertical production capability, quality, and cost. +Trademarks +Our name and logo are federally registered trademarks, and we believe they are valuable assets of our business. +Employees +We consider our employees to be our primary strength and we make considerable efforts to maintain a well-qualified workforce. Our employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. We regularly provide transportation, medical services, and meals to all of our employees in foreign locations. The Company also has defined contribution plans available to U.S. employees who have attained age 21 and provide group health, life, and disability insurance plans. We also maintain share based compensation plans and other long-term incentive plans for certain employees and outside directors. +As of July 3, 2021 we had 5,450 full-time employees compared to 5,741 on June 27, 2020, and 4,067 on June 29, 2019. Since we can have significant fluctuations in product demand, we seek to maintain flexibility in our workforce by utilizing skilled temporary labor in some of our manufacturing facilities in addition to full-time employees. +Backlog +On July 31, 2021 our order backlog was valued at approximately $303.2 million, compared to approximately $215.3 million on July 25, 2020. The amount of backlog is not necessarily indicative of future sales but can be indicative of trends in expected future sales revenue. Due to the relationships with our customers, we will occasionally allow orders to be canceled or rescheduled and as a result it is not a meaningful indicator of future financial results. If there are canceled or rescheduled orders, we typically negotiate fees to cover the costs we have incurred. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change due to design modifications, customer forecast changes, or other customer requirements. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in Note 12, “Enterprise-Wide Disclosures” of the consolidated financial statements of this Annual Report on Form 10-K and that information is incorporated herein. +Governmental Regulation +Our operations are subject to certain foreign, federal, state and local regulations relating to, among others, environmental, waste management, labor and health and safety matters. We have implemented processes and procedures to help ensure that our operations are in substantial compliance with all applicable regulations. However, material costs and liabilities may arise from these requirements or from new or modified requirements, which could have a material adverse effect on our business and results of operations. +6 +Executive Officers of the Registrant +The table below sets forth the name, current age and current position of our executive officers and other significant employees: +Name Age Positions Held +Executive Officers +Craig D. Gates 62 President and Chief Executive Officer +Brett R. Larsen 48 Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Philip S. Hochberg 59 Executive Vice President of Business Development +Duane D. Mackleit 53 Executive Vice President of Operations +David H. Knaggs 40 Executive Vice President of Quality and Information Systems +Chad T. Orebaugh 50 Vice President of Engineering +Thomas Despres 59 +Vice President of Southwest Operations +Mark Courtney 55 +Vice President of Supply Chain +Executive Officers +CRAIG D. GATES – President and Chief Executive Officer +Mr. Gates, age 62, has been President and Chief Executive officer of the Company since April 2009. Previously, he was Executive Vice President and General Manager from August 2002 to April 2009. He served as Executive Vice President of Marketing, Engineering and Sales from July 1997 to August 2002 and served as Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of 1994. From 1982 to 1991 he held various engineering and management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. Mr. Gates has a Bachelor of Science Degree in Mechanical Engineering and a Masters in Business Administration from the University of Illinois, Urbana. +BRETT R. LARSEN – Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Mr. Larsen, age 48, has served as Executive Vice President of Administration, Chief Financial Officer, and Treasurer since July 2015. Previously, he was Vice President of Finance and Controller from February 2010 to July 2015. He was Chief Financial Officer of FLSmidth Spokane, Inc. from December 2008 to February 2010. From October 2005 through November 2008, Mr. Larsen served as Controller of Key Tronic Corporation. From May 2004 to October 2005, Mr. Larsen served as Manager of Financial Reporting of Key Tronic Corporation. From 2002 to May 2004, Mr. Larsen was an audit manager for the public accounting firm BDO USA, LLP. He also held various auditing and supervisory positions with Grant Thornton LLP from 1997 to 2002. Mr. Larsen has a Bachelor of Science degree in Accounting and a Masters degree in Accounting from Brigham Young University and is a Certified Public Accountant. +PHILIP S. HOCHBERG – Executive Vice President of Business Development +Mr. Hochberg, age 59, has been Executive Vice President of Business Development since July 2012. Prior to this, Mr. Hochberg served as Vice President of Business Development from October 2009 through June 2012. He was Director of Business Development and Program Management from July 2008 to October 2009. Mr. Hochberg served as Director of Business Development from October 2004 to July 2008 and as Director of EMS Sales and Marketing from July 2000 to October 2004. Prior to joining Key Tronic, Mr. Hochberg worked for Quinton Instrument Company as their Director of Marketing and Product Management from 1992 to 2000. From 1988 to 1992, he was employed by SpaceLabs Medical as their Business Development Marketing Manager. Mr. Hochberg has an MBA from the University of British Columbia, a BA in Psychology, with a minor in Business from Washington University in St. Louis. +7 +DUANE D. MACKLEIT – Executive Vice President of Operations +Mr. Mackleit, age 53, has been Executive Vice President of Operations since December 2019. Prior to this, Mr. Mackleit served as Vice President of Program Management since July 2012. He served as Director of Program Management from July 2008 through June 2012. From May 2006 to July 2008 he served as Principal Program Manager. Prior to that, he served as Program Manager from March 2002 to May 2006 and Associate Program Manager from August 2000 to March 2002. Mr. Mackleit has also held several other positions with Key Tronic Corporation. Mr. Mackleit has an AA in Business from Spokane Falls Community College and a BA in Business/Marketing from Eastern Washington University. He also holds a MBA from Gonzaga University. +DAVID H. KNAGGS – Executive Vice President of Quality, Regulatory Affairs and Information Systems +Mr. Knaggs, age 40, has been Executive Vice President of Quality and Information Systems since May 2021. Previously, he was Vice President of Quality and Regulatory Affairs from November 2017 to May 2021. He was Vice President of Quality since October 2016. Before joining Key Tronic, Mr. Knaggs worked at Telect, Inc. from 2008 to 2016 as their Director of Engineering. Prior to that, he worked at Isothermal Systems Research as Lead Systems Engineer from 2003 to 2008. He has a Bachelor of Science degree in Mechanical Engineering with a minor in mathematics from the University of Washington. +CHAD T. OREBAUGH – Vice President of Engineering +Mr. Orebaugh, age 50, has been Vice President of Engineering since April 2017. Prior to this, Mr. Orebaugh served as Director of Engineering since May 2013. From April 2010 to May 2013, he served as Manager of Engineering. From January 2000 to April 2010 he served as Lead Mechanical Engineer. Prior to that, he served as Mechanical Engineer from October 1998 to January 2000 and Associate Mechanical Engineer since October 1997. Mr. Orebaugh holds a BA in Mechanical Engineering from Gonzaga University. +THOMAS DESPRES – Vice President of Southwest Operations +Thomas Despres, age 59, has been Vice President of Southwest Operations since November 2017. Prior to joining Key Tronic, Mr. Despres worked for Gates Corporation as Plant General Manager from July 2017 to November 2017. From 2016 to 2017, he was self-employed and from 2012 to 2016 he was employed by Flextronics as Vice President Global Account Management. He has an MBA from Campbell University, and a BBA, Production Management from Ohio University in Athens. +MARK COURTNEY – Vice President of Supply Chain +Mark Courtney, age 55, has been Vice President of Supply Chain of the company since August 2019. Previously, he served as Purchasing Manager and Director of North American Purchasing from September 2015 to August 2019, and as Supply Chain Manager, ERP and Business Operations Manager for Amphenol Telect from August 2007 to September 2015. From March 2006 to August 2007, he served as Senior Buyer/Planner for Honeywell Specialty Materials and from June 2005 to March 2006 as Purchasing Manager for MRV Communications. From May 2000 to June 2005, he served as a Field and Inside Sales Associate for Arrow Electronics and from October 1991 to May 2000 held various positions at Alesis. +Available Information +Our principal executive offices are located at 4424 North Sullivan Road, Spokane Valley, Washington 99216, and our telephone number is (509) 928-8000. Our website is located at http://www.keytronic.com where filings of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or current reports on Form 8-K are available free of charge after they have been filed with the Securities and Exchange Commission. The information presented on our website currently and in the future is not considered to be part of this document or any document incorporated by reference in this document. +In addition, the SEC maintains an Internet site (at www.sec.gov ) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. +8 +Item 1A. RISK FACTORS +There are risks and uncertainties that could affect our business. These risks and uncertainties include but are not limited to, the risk factors described below, in Item 7A: “Quantitative and Qualitative Disclosures about Market Risk” and elsewhere in this Form 10-K. +RISKS AND UNCERTAINTIES THAT MAY AFFECT FUTURE RESULTS +The following risks and uncertainties could affect our actual results and could cause results to differ materially from past results or those contemplated by our forward-looking statements. When used herein, the words “expects,” “believes,” “anticipates” and other similar expressions are intended to identify forward-looking statements. +RISKS RELATED TO OUR BUSINESS AND STRATEGY +Our operations may be subject to certain risks. +We manufacture product in facilities located in Mexico, China, Vietnam and the United States. These operations may be subject to a number of risks, including: +• difficulties in staffing, turnover and managing onshore and offshore operations; +• political and economic instability (including acts of terrorism, pandemics, civil unrest, forms of violence and outbreaks of war), which could impact our ability to ship, manufacture, and/or receive product; +• unexpected changes in regulatory requirements and laws; +• longer customer payment cycles and difficulty collecting accounts receivable; +• export duties, import controls and trade barriers (including quotas); +• governmental restrictions on the transfer of funds; +• burdens of complying with a wide variety of foreign laws and labor practices; subject to trade wars and tariffs; +• our locations may be impacted by hurricanes, tornadoes, earthquakes, water shortages, tsunamis, floods, typhoons, fires, extreme weather conditions and other natural or man-made disasters; and +• our locations may also be impacted by future temporary closures and labor constraints as a result of COVID-19. +Our operations in certain foreign locations receive favorable income tax treatment in the form of tax credits or other incentives. In the event that such tax incentives are not extended, are repealed, or we no longer qualify for such programs, our taxes may increase, which would reduce our net income. +Additionally, certain foreign jurisdictions restrict the amount of cash that can be transferred to the U.S or impose taxes and penalties on such transfers of cash. To the extent we have excess cash in foreign locations that could be used in, or is needed by, our operations in the United States, we may incur significant penalties and/or taxes to repatriate these funds. +We may experience fluctuations in quarterly results of operations. +Our quarterly operating results have varied in the past and may vary in the future due to a variety of factors, including adverse changes in the U.S. and global macroeconomic environment, volatility in overall demand for our customers’ products, success of customers’ programs, timing of new programs, new product introductions or technological advances by us, our customers and our competitors, and changes in pricing policies by us, our customers, our suppliers, and our competitors. Our customer base is diverse in the markets they serve, however, decreases in demand, particularly from customers in certain industries could affect future quarterly results. Additionally, our customers could be adversely impacted by illiquidity in the credit markets which could directly impact our operating results. +Component procurement, production schedules, personnel and other resource requirements are based on estimates of customer requirements. Occasionally, our customers may request accelerated production that can stress resources and reduce operating margins. Conversely, our customers may abruptly lower or cancel production which may lead to a sudden, unexpected increase in inventory or accounts receivable for which we may not be reimbursed even when under contract with customers. In addition, because many of our operating expenses are relatively fixed, a reduction in customer demand can harm our gross profit and operating results. The products which we manufacture for our customers have relatively short product lifecycles. Therefore, our business, operating results and financial condition are dependent in a significant way on our ability to obtain orders from new customers and new product programs from existing customers. +9 +Operating results can also fluctuate if changes are made to significant estimates and assumptions. Significant estimates and assumptions include the allowance for doubtful receivables, provision for obsolete and non-saleable inventory, stock-based compensation, the valuation allowance on deferred tax assets, impairment of long-lived assets, long-term incentive compensation accrual, the provision for warranty costs, and the impact of hedging activities. +Due to the COVID-19 pandemic, we have seen extreme shifts in demand from our customer base. The possibility of future temporary closures and labor constraints, as well as the inability to predict customer demand, costs, and future supply chain disruptions during the rapidly changing COVID-19 environment can materially impact operating results. +We are exposed to general economic conditions, which could have a material adverse impact on our business, operating results and financial condition. +Adverse economic conditions and uncertainty in the global economy such as unstable global financial and credit markets, inflation, and recession can negatively impact our business. Unfavorable economic conditions could affect the demand for our customers’ products by triggering a reduction in orders as well as a decline in forecasts which could adversely affect our sales in future periods. Additionally, the financial strength of our customers and suppliers and their ability to obtain and rely on credit financing may affect their ability to fulfill their obligations to us and have an adverse effect on our financial results. +Adverse macroeconomic conditions as a result of COVID-19 have and may continue to affect our business. The conditions affect the Company’s ability to predict and plan for future supply chain disruptions, fluctuations in customer demand and costs, and the ability to operate as there is uncertainty over future temporary closures. +The majority of our sales come from a small number of customers and a decline in sales to any of these customers could adversely affect our business. +At present, our customer base is concentrated and could become more or less concentrated. There can be no assurance that our principal customers will continue to purchase products from us at current levels. Moreover, we typically do not enter into long-term volume purchase contracts with our customers, and our customers have certain rights to extend or delay the shipment of their orders. We, however, typically require that our customers contractually agree to buy back inventory purchased within specified lead times to build their products if not used. +The loss of one or more of our major customers, or the reduction, delay or cancellation of orders from such customers, due to economic conditions or other forces, could materially and adversely affect our business, operating results and financial condition. The contraction in demand from certain industries could impact our customer orders and have a negative impact on our operations over the foreseeable future. Additionally, if one or more of our customers were to become insolvent or otherwise unable to pay for the manufacturing services provided by us, our operating results and financial condition would be adversely affected. +We depend on a limited number of suppliers for certain components that are critical to our manufacturing processes. A shortage of these components or an increase in their price could interrupt our operations and result in a significant change in our results of operations. +We are dependent on many suppliers, including sole source suppliers, to provide key components and raw materials used in manufacturing customers’ products. We have seen supply shortages in certain electronic components. In addition, our suppliers' facilities may also experience earthquakes, tsunamis and other natural disasters which may cause a shortage of components. This can result in longer lead times and the inability to meet our customers request for flexible production and extended shipment dates. If demand for components outpaces supply, capacity delays could affect future operations. Delays in deliveries from suppliers or the inability to obtain sufficient quantities of components and raw materials have and may continue to cause delays or reductions in shipment of products to our customers which could adversely affect our operating results and damage customer relationships. +Key Tronic continues to work closely with its employees and key suppliers to ascertain delays attributable to the COVID-19 pandemic. Delays in production and extended transit times of critical parts have and may continue to cause a shortage of components. +We operate in a highly competitive industry; if we are not able to compete effectively in the contract manufacturing industry, our business could be adversely affected. +Competitors may offer customers lower prices on certain high volume programs. This could result in price reductions, reduced margins and loss of market share, all of which would materially and adversely affect our business, operating results, and financial condition. If we were unable to provide comparable or better manufacturing services at a lower cost than our competitors, it could cause sales to decline. In addition, competitors can copy our non-proprietary designs and processes after we have invested in development of products for customers, thereby enabling such competitors to offer lower prices on such products due to savings in development costs. +10 +Fluctuations in foreign currency exchange rates could increase our operating costs. +We have manufacturing operations located in Mexico and China. A significant portion of our operations are denominated in the Mexican peso and the Chinese currency, the renminbi ("RMB"). Currency exchange rates fluctuate daily as a result of a number of factors, including changes in a country's political and economic policies. Volatility in the currencies of our entities and the United States dollar could seriously harm our business, operating results and financial condition. The primary impact of currency exchange fluctuations is on the cash, receivables, payables and expenses of our operating entities. As part of our hedging strategy, we currently use Mexican peso forward contracts to hedge foreign currency fluctuations for a portion of our Mexican peso denominated expenses. We currently do not hedge expenses denominated in RMB. Unexpected losses could occur from increases in the value of these currencies relative to the United States dollar. +As a result of COVID-19, significant currency exchange fluctuations can occur causing unexpected losses. Future temporary closures of production facilities in Mexico could also cause significant changes in our ability to qualify for hedge accounting treatment of our forward contracts to hedge foreign currency fluctuations. However, given the unprecedented nature of the pandemic the FASB staff believes that an entity may apply the exception in paragraph 815-30-40-4 for rare cases caused by extenuating circumstances that are related to the nature of the forecasted transaction and are outside the control or influence of an entity to delays in the timing of the forecasted transactions if those delays are related to the effects of the COVID-19 pandemic and are considered probable to still occur. In addition, the FASB staff believes that it would be acceptable for an entity to determine that missed forecasts related to the effects of the COVID-19 pandemic need not be considered when determining whether it has exhibited a pattern of missing forecasts that would call into question its ability to accurately predict forecasted transactions and the propriety of using cash flow hedge accounting in the future for similar transactions. +Our success will continue to depend to a significant extent on our key personnel. +Our future success depends in large part on the continued service of our key technical, marketing and management personnel and on our ability to continue to attract and retain qualified production employees. There can be no assurance that we will be successful in attracting and retaining such personnel, particularly in our manufacturing locales that may be experiencing high demand for similar key personnel. The loss of key employees could have a material adverse effect on our business, operating results and financial condition. +Start-up costs and inefficiencies related to new or transferred programs can adversely affect our operating results and such costs may not be recoverable if such new programs or transferred programs are canceled or don’t meet expected sales volumes. +Start-up costs, the management of labor and equipment resources in connection with the establishment of new programs and new customer relationships, and the need to obtain required resources in advance can adversely affect our gross margins and operating results. These factors are particularly evident in the ramping stages of new programs. These factors also affect our ability to efficiently use labor and equipment. We are currently managing a number of new programs. Consequently, our exposure to these factors has increased. In addition, if any of these new programs or new customer relationships were terminated, our operating results could be harmed, particularly in the short term. We may not be able to recoup these start-up costs or replace anticipated new program revenues. +Customers may change production timing and demand schedules which makes it difficult for us to schedule production and capital expenditures and to maximize the efficiency of our manufacturing capacity. +Changes in demand for customer products reduce our ability to accurately estimate the future requirements of our customers. This makes it difficult to schedule production and maximize utilization of our manufacturing capacity. We must determine the levels of business that we will seek and accept from customers, set production schedules, commit to procuring inventory, and allocate personnel and resources, based on our estimates of our customers' requirements. Customers can require sudden increases and decreases in production which can put added stress on resources and reduce margins. Sudden decreases in production can lead to excess inventory on hand which may or may not be reimbursed by our customers even when under contract. +Continued growth could further lead to capacity constraints. We may need to transfer production to other facilities, acquire new facilities, or outsource production which could negatively impact gross margin. The Company has been able to manage the arrival of components in an effort to control inventory levels of customers that have seen sharp decreases in demand, as a result of COVID-19. +11 +Compliance or the failure to comply with current and future environmental and health laws or regulations could cause us significant expense. +We are subject to a variety of domestic and foreign environmental regulations relating to the use, storage, and disposal of materials used in our manufacturing processes. In addition, increasing governmental focus on climate change may result in new environmental regulations that may negatively affect us, our vendors or our customers. As a result, we may incur additional costs or obligations in complying with any new environmental and reporting requirements, as well as increased indirect costs resulting from our vendors or customers that get passed on to us. +If we fail to comply with any present or future regulations, we could be subject to future liabilities or the suspension of current manufacturing operations. In addition, such regulations could restrict our ability to expand our operations or could require us to acquire costly equipment, substitute materials, or incur other significant expenses to comply with government regulations. +If our manufacturing processes and services do not comply with applicable statutory and regulatory requirements, or if we manufacture products containing design or manufacturing defects, demand for our services may decline and we may be subject to liability claims. +We manufacture and design products to our customers’ specifications, and, in some cases, our manufacturing processes and facilities may need to comply with applicable statutory and regulatory requirements. For example, medical devices that we manufacture or design, as well as the facilities and manufacturing processes that we use to produce them, are regulated by the Food and Drug Administration and non-U.S. counterparts of this agency. In addition, our customers’ products and the manufacturing processes that we use to produce them often are highly complex. As a result, products that we manufacture may at times contain manufacturing or design defects, and our manufacturing processes may be subject to errors or not be in compliance with applicable statutory and regulatory requirements. Defects in the products we manufacture or design, whether caused by a design, manufacturing or component failure or error, or deficiencies in our manufacturing processes, may result in delayed shipments to customers or reduced or canceled customer orders. If these defects or deficiencies are significant, our business reputation may also be damaged. The failure of the products that we manufacture or our manufacturing processes and facilities to comply with applicable statutory and regulatory requirements may subject us to legal fines or penalties and, in some cases, require us to shut down or incur considerable expense to correct a manufacturing process or facility. Our customers are required to indemnify us against liability associated with designing products to meet their specifications. However, if our customers are responsible for the defects, they may not, or may not have resources to, assume responsibility for any costs or liabilities arising from these defects, which could expose us to additional liability claims. +If we do not manage our growth effectively, our profitability could decline. +Our business is experiencing growth which can place considerable additional demands upon our management team and our operational, financial and management information systems. Our ability to manage growth effectively requires us to continue to implement and improve these systems; avoid cost overruns; maintain customer, supplier and other favorable business relationships during possible transition periods; continue to develop the management skills of our managers and supervisors; and continue to train, motivate and manage our employees. Our failure to effectively manage growth could have a material adverse effect on our results of operations. +Energy price increases may negatively impact our results of operations. +Certain components that we use in our manufacturing process are petroleum-based. In addition, we, along with our suppliers and customers, rely on various energy sources in our transportation activities. While significant uncertainty currently exists about the future levels of energy prices, a significant increase is possible. Increased energy prices could cause an increase to our raw material costs and transportation costs. In addition, increased transportation costs related to certain suppliers and customers could be passed along to us. We may not be able to increase our product prices enough to offset these increased costs. In addition, any increase in our product prices may reduce our future customer orders and profitability. +TECHNOLOGY RISKS +Our operations are subject to cyberattacks that could have a material adverse effect on our business. +We are increasingly dependent on digital technologies and services to conduct our operations. We use these technologies for internal purposes, including data storage, processing and transmissions, as well as in our interactions with vendors and customers. Digital technologies and services are subject to the risk of cybersecurity incidents and some incidents can remain undetected for a period of time. +We routinely monitor our systems for cyber threats and have processes in place to detect and remediate vulnerabilities. Nevertheless, we have experienced attempted security breaches, such as phishing emails and other targeted attacks. We expect that our operations will continue to be subject to cyber threats, and any future cybersecurity incident could significantly disrupt our operations. +12 +Cybersecurity incidents could also result in the misappropriation of proprietary or confidential information of the Company or that of its customers, employees, vendors or customers. We expect to incur costs in the future to mitigate against cybersecurity incidents as threats are expected to continue to become more persistent and sophisticated. If our systems for protecting against cybersecurity incidents prove not to be sufficient, we could be adversely affected by, among other things, loss of or damage to intellectual property, proprietary or confidential information, or employee, vendor or customer data; interruption of our business operations; and increased costs to prevent, respond to or mitigate cybersecurity incidents. These risks could harm our reputation and our relationships with employees, vendors and customers and may result in claims or enforcement actions and investigations against us. +Disruptions to our information systems, including losses of data or outages, could adversely affect our operations. +We rely on information technology networks and systems to process, transmit and store electronic information. In particular, we depend on our information technology infrastructure for a variety of functions, including worldwide financial reporting, inventory management, procurement, invoicing and email communications. Any of these systems may be susceptible to outages due to fire, floods, power loss, telecommunications failures, terrorist attacks and similar events. If we or our vendors are unable to prevent such outages, our operations could be disrupted. +If we are unable to maintain our technological and manufacturing process expertise, our business could be adversely affected. +The markets for our customers’ products are characterized by rapidly changing technology, evolving industry standards, frequent new product introductions and short product life cycles. The introduction of products embodying new technologies or the emergence of new industry standards can render existing products obsolete or unmarketable. Our success will depend upon our customers’ ability to enhance existing products and to develop and introduce, on a timely and cost-effective basis, new products that keep pace with technological developments and emerging industry standards and address evolving and increasingly sophisticated customer requirements. Failure of our customers to do so could substantially harm our customers’ competitive positions. There can be no assurance that our customers will be successful in identifying, developing and marketing products that respond to technological change, emerging industry standards or evolving customer requirements. +RISKS RELATED TO CAPITAL AND FINANCING +Cash and cash equivalents are exposed to concentrations of credit risk. +We place our cash with high credit quality institutions. At times, such balances may be in excess of the federal depository insurance limit or may be on deposit at institutions which are not covered by insurance. If such institutions were to become insolvent during which time it held our cash and cash equivalents in excess of the insurance limit, it could be necessary to obtain other credit financing to operate our facilities. +Our ability to secure and maintain sufficient credit arrangements is key to our continued operations. +There is no assurance that we will be able to retain or renew our credit agreements in the future. In the event the business grows rapidly or there is uncertainty in the macroeconomic climate, additional financing resources could be necessary in the current or future fiscal years. There is no assurance that we will be able to obtain equity or debt financing at acceptable terms, or at all in the future. In addition, we have restrictive covenants with our financial institution which could impact how we manage our business. If we cannot meet our financial covenants, our borrowings could become immediately payable which could have a material adverse impact on our financial statements. For a summary of our banking arrangements, see Note 4 Long-Term Debt of the “Notes to Consolidated Financial Statements.” +An adverse change in the interest rates for our borrowings could adversely affect our financial condition. +We are exposed to interest rate risk under our revolving line of credit and term loan. We currently hedge a portion of our term loan with an interest rate swap. We have not historically hedged the interest rate on our credit facility; therefore, unless we do so, significant changes in interest rates could adversely affect our results of operations. Refer to the discussion in note 4, “Long-Term Debt” to the consolidated financial statements for further details of our debt obligations. +In addition, the U.K.’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021, though the ICE Benchmark Administration, the administrator of LIBOR, announced that it would consider ceasing the publication of the one-week and two-month U.S. dollar LIBOR settings at the end of 2021 and phase out the remaining U.S. dollar LIBOR settings by June 30, 2023. The transition from LIBOR to a new replacement benchmark is uncertain at this time and the consequences of such developments cannot be entirely predicted but could result in an increase in the cost of our borrowings, which could adversely affect our financial condition. +13 +Our stock price is volatile. +Our stock price has and may continue to be subject to wide fluctuations and possible rapid increases or declines over a short time period. These fluctuations may be due to factors specific to us such as our stock's thinly traded nature, variations in quarterly operating results, changes in earnings estimates, or the Audit Committee's internal investigation, or to factors relating to the contract manufacturing industry or to the securities markets in general, which, in recent years, have experienced significant price fluctuations. These fluctuations often have been unrelated to the operating performance of the specific companies whose stocks are traded. In addition, holders of our common stock will suffer immediate dilution to the extent outstanding equity awards are exercised to purchase common stock. +RISKS RELATED TO OUR CONTROLS AND PROCEDURES AND THE INTERNAL INVESTIGATION +We identified a material weakness in our internal control over financial reporting and concluded that our disclosure controls and procedures were not effective as of December 26, 2020 and April 3, 2021. If we fail to properly remediate any future deficiencies or material weaknesses or to maintain proper and effective internal controls, our business and financial condition could be materially adversely impacted. +As described in Item 9a, “Controls and Procedures,” of this Annual Report on Form 10-K, we concluded that our disclosure controls and procedures were not effective as of December 26, 2020 and April 3, 2021, due to the existence of a material weakness in our internal control over financial reporting. While we have undertaken remediation efforts to address the identified deficiencies and have concluded that the material weakness was remediated as of July 3, 2021, we cannot provide assurance that we will be able to conclude that our controls will be effective in the future. We also cannot assure you that additional significant deficiencies or material weaknesses in our internal control over financial reporting will not arise or be identified in the future. We intend to continue our control remediation activities. In doing so, we will continue to incur expenses and expend management time on compliance-related issues. +If additional deficiencies in our internal control over financial reporting are discovered or occur in the future, our consolidated financial statements may contain material misstatements and we could be required to restate our financial results. Moreover, because of the inherent limitations of any control system, material misstatements due to error or fraud may not be prevented or detected on a timely basis, or at all. If we are unable to provide reliable and timely financial reports in the future, our business and reputation may be further harmed. Restated financial statements and failures in internal controls may also cause us to fail to meet additional reporting obligations, negatively affect investor confidence in our management and the accuracy of our financial statements and disclosures, or result in adverse publicity and concerns from investors, any of which could have a negative effect on the price of our common stock, subject us to regulatory investigations and penalties or stockholder litigation, and materially adversely impact our business, financial condition, results of operations and cash flows. +Matters relating to or arising from the subject of the Audit Committee’s internal investigation, including expenses and diversion of personnel and resources, regulatory investigations, and proceedings and litigation matters, could have an adverse effect on our business, results of operations and financial condition. +We have incurred, and may continue to incur, significant expenses related to legal, accounting and other professional services in connection with matters relating to or arising from the subject of the Audit Committee’s internal investigation. As described in Item 9a, “Controls and Procedures,” of this Annual Report on Form 10-K, we have taken and continue to take a number of steps in order to remediate identified deficiencies in our internal control over financial reporting and attempt to reduce the risk of future recurrence. The validation of the efficacy of these remedial steps will result in us incurring additional near term expenses, and to the extent these steps are not successful, we may incur significant additional time and expense. +In addition, we are cooperating with the Securities and Exchange Commission (the “SEC”) regarding matters related to the internal investigation. The completion of the internal investigation will not automatically resolve the SEC’s inquiries. If the SEC or any other regulator were to commence legal action against us, we could be required to pay significant penalties and become subject to injunctions, cease and desist orders or other remedies. We can provide no assurances as to the outcome of any governmental inquiry or investigation. Further, we, our officers and members of our board of directors could be named as defendants in lawsuits asserting claims arising out of the subject matter of the Audit Committee’s internal investigation. As a result of any legal proceedings and any related indemnification requirements to our officers and directors, we could be required to pay monetary damages that may be in excess of our insurance coverage or may have additional penalties or other remedies imposed against us or our officers and directors. +All of these expenses, the delay in timely filing our periodic reports and the diversion of the attention of management and other personnel that has occurred and is expected to continue, could adversely affect our business, financial condition, results of operations and cash flows. +14 +Due to inherent limitations, there can be no assurance that our system of disclosure and internal controls and procedures will be successful in preventing all errors, theft and fraud, or in informing management of all material information in a timely manner. +Management does not expect that our disclosure controls and procedures and internal controls over financial reporting will prevent all errors or fraud. A control system is designed to give reasonable, but not absolute, assurance that the objectives of the control system are met. In addition, any control system reflects resource constraints and the benefits of controls must be considered relative to their costs. Inherent limitations of a control system may include: judgments in decision making may be faulty, breakdowns can occur simply because of error or mistake and controls can be circumvented by collusion or management override. Due to the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and may not be detected. +LEGAL AND ACCOUNTING RISKS +We are involved in various legal proceedings. +In the past, we have been notified of claims relating to various matters including contractual matters, intellectual property rights or other issues arising in the ordinary course of business. In the event of such a claim, we may be required to spend a significant amount of money to defend or otherwise address the claim. Any litigation or dispute resolution, even where a claim is without merit, could result in substantial costs and diversion of resources. Accordingly, the resolution or adjudication of such disputes, even those encountered in the ordinary course of business, could have a material effect on our business, consolidated financial conditions and results of operations. +Changes in securities laws and regulations will increase our costs and risk of noncompliance. +We are subject to additional requirements contained in the Sarbanes-Oxley Act of 2002 (the Sarbanes-Oxley Act) and more recently the Dodd-Frank Act. The Sarbanes-Oxley and Dodd-Frank Acts required or will require changes in some of our corporate governance, securities disclosure and compliance practices. In response to the requirements of the Sarbanes-Oxley and Dodd-Frank Acts, the SEC and NASDAQ promulgated new rules and additional rulemaking is expected in the future. Compliance with these new rules and future rules has increased and may increase further our legal, financial and accounting costs as well as a potential risk of noncompliance. Absent significant changes in related rules, which we cannot assure, we anticipate some level of increased costs related to these new regulations to continue indefinitely. We also expect these developments to make it more difficult and more expensive to obtain director and officer liability insurance, and we may be forced to accept reduced coverage or incur substantially higher costs to obtain coverage. Likewise, these developments may make it more difficult for us to attract and retain qualified members of our Board of Directors or qualified management personnel. Further, the costs associated with the compliance with and implementation of procedures under these and future laws and related rules could have a material impact on our results of operations. In addition, the costs associated with noncompliance with additional securities laws and regulations could also impact our business. +Changes in financial accounting standards may affect our reported financial condition or results of operations as well increase costs related to implementation of new standards and modifications to internal controls. +Our consolidated financial statements are prepared in conformity with accounting standards generally accepted in the United States, or U.S. GAAP. These principles are subject to amendments made primarily by the Financial Accounting Standards Board (FASB) and the Securities and Exchange Commission (SEC). A change in those policies can have a significant effect on our reported results and may affect our reporting of transactions which are completed before a change is announced. Changes to accounting rules or challenges to our interpretation or application of the rules by regulators may have a material adverse effect on our reported financial results or on the way we conduct business. +GENERAL RISKS +Our levels of insurance coverage may not be sufficient for potential damages, claims or losses. +We have various forms of business and liability insurance which we believe are appropriate based on the needs of companies in our industry. As a result, not all of our potential business risks or potential losses would be covered by our insurance policies. If we sustain a significant claim or loss which is not covered by insurance, our net income could be negatively impacted. +15 +We may encounter complications with acquisitions, which could potentially harm our business. +Any current or future acquisitions may require additional equity financing, which could be dilutive to our existing shareholders, or additional debt financing, which could potentially affect our credit ratings. Any downgrades in our credit ratings associated with an acquisition could adversely affect our ability to borrow by resulting in more restrictive borrowing terms. To integrate acquired businesses, we must implement our management information systems, operating systems and internal controls, and assimilate and manage the personnel of the acquired operations. The integration of acquired businesses may be further complicated by difficulties managing operations in geographically dispersed locations. The integration of acquired businesses may not be successful and could result in disruption by diverting management’s attention from the core business. In addition, the integration of acquired businesses may require that we incur significant restructuring charges or other increases in our expenses and working capital requirements, which reduce our return on invested capital. +Acquisitions may involve numerous other risks and challenges including but not limited to: potential loss of key employees and customers of the acquired companies; the potential for deficiencies in internal controls at acquired companies; lack of experience operating in the geographic market or industry sector of the acquired business; constraints on available liquidity, and exposure to unanticipated liabilities of acquired companies. These and other factors could harm our ability to achieve anticipated levels of profitability at acquired operations or realize other anticipated benefits of an acquisition, and could adversely affect our consolidated business and operating results. +Item 1B. UNRESOLVED STAFF COMMENTS +None +16 +Item 2. PROPERTIES AS OF DATE OF FILING +We have manufacturing and sales operations located in the United States, Mexico, China and Vietnam. The table below lists the locations and square footage of our operating facilities: +Location Approx. +Sq. Ft. Type of Interest +(Leased/Owned) Description of Use +Corinth, Mississippi 350,000 Leased Manufacturing and warehouse +El Paso, Texas 80,000 Leased Shipping and warehouse +Fayetteville, Arkansas 105,000 Leased Manufacturing and warehouse +Louisville, Kentucky 2,300 Leased Administration +Oakdale, Minnesota 103,000 Leased Manufacturing and warehouse +Spokane Valley, Washington 95,000 Leased Sales, research, administration and manufacturing +Spokane Valley, Washington 36,000 Leased Manufacturing +Total USA 771,300 +Juarez, Mexico 193,000 Leased Warehouse +Juarez, Mexico 174,000 Owned Manufacturing and warehouse +Juarez, Mexico 115,000 Owned Manufacturing and warehouse +Juarez, Mexico 103,000 Owned Manufacturing and warehouse +Juarez, Mexico 72,000 Leased Manufacturing and warehouse +Juarez, Mexico 66,000 Owned Manufacturing and warehouse +Juarez, Mexico 60,000 Owned Manufacturing and warehouse +Juarez, Mexico 116,000 Leased Manufacturing and warehouse +Total Mexico 899,000 +Shanghai, China 114,000 Leased Manufacturing and warehouse +Shanghai, China 8,000 Leased Manufacturing +Total China 122,000 +Da Nang, Vietnam 133,000 Leased Manufacturing and warehouse +Total Vietnam 133,000 +Grand Total 1,925,300 +(1) +The geographic diversity of these locations allows us to offer services near certain of our customers and major electronics markets with the additional benefit of reduced labor costs. We consider the productive capacity of our current facilities sufficient to carry on our current business. In addition, in Juarez, Mexico one of our buildings includes adjacent vacant land that could be developed into additional manufacturing and warehouse space. +All of our facilities are ISO certified to ISO 9001:2015 standard and to Customs Trade Partnership against Terrorism (CTPAT). In addition, the Juarez, Mexico; Shanghai, China and Spokane, Washington facilities are registered/certified to IATF 16949 automotive standard, ISO 13485:2016 medical devices, ISO 14001:2015 environmental standard, ANSI/ESD S20.20 Electrostatic Discharge Control Program, and ISO 45001 Occupational Health and Safety Management System. +Da Nang, Vietnam is additionally registered to IATF 16949 automotive standard. Oakdale, Minnesota and Corinth, Mississippi are additionally registered to ISO 14001:2015 environmental standard and to ISO 13485:2016 medical devices standard. Oakdale, Minnesota and Fayetteville, Arkansas are additionally registered AS9100D aviation, space and defense standard and have a certified ANSI/ESD S20.20 Electrostatic Discharge Control Program. Oakdale, Minnesota is additionally NADCAP certified. The Spokane, Washington; Corinth, Minnesota and Juarez, Mexico facilities are additionally registered to ISO/IEC 80079-34 explosive atmospheres. The Oakdale, Minnesota; Corinth, Mississippi; Fayetteville, Arkansas and Spokane, Washington facilities are all registered with the U.S. State Department for International Traffic in Arms Regulations (ITAR). +17 +Item 3. LEGAL PROCEEDINGS +We are a party to certain lawsuits or claims in the ordinary course of business. We do not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on our financial position, results of operations or cash flow, although an adverse resolution against the Company in a fiscal quarter or year could have a material adverse effect on the Company’s results of operations in a particular quarter or year . Refer to Commitments and Contingencies footnote for further details on claims in the fiscal year. +Item 4. MINE SAFETY DISCLOSURES +Not Applicable +PART II +Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES +Market Information +Our common stock is traded on the NASDAQ Global Market, formerly the NASDAQ National Market System under the symbol “KTCC.” Quarterly high and low sales prices for our common stock for fiscal years 2021 and 2020 were as follows: +2021 2020 +High Low High Low +First Quarter $ 10.22 $ 5.04 $ 6.62 $ 4.83 +Second Quarter 10.48 7.05 6.48 5.27 +Third Quarter 9.48 6.75 6.99 2.51 +Fourth Quarter 8.35 6.35 5.45 2.59 +High and low stock prices are based on the daily sales prices reported by the NASDAQ Stock Market. These quotations represent prices between dealers without adjustment for markups, markdowns, and commissions, and may not represent actual transactions. +Holders and Dividends +As of July 3, 2021, we had 634 shareholders of common stock on record. As a result of our credit agreements, we are restricted from declaring or paying dividends in cash or stock without the Bank’s prior written consent. We have not paid a cash dividend and do not anticipate payment of dividends in the foreseeable future. +Equity Compensation Plan Information +Information concerning securities authorized for issuance under our equity compensation plans is set forth in Part III, Item 12 of this Annual Report, under the caption “Securities Authorized for Issuance under Equity Compensation Plans”, and that information is incorporated herein by reference. +18 +Performance Graph +Set forth below is a line graph comparing the cumulative total shareholder return on our common stock with the cumulative total return of the NASDAQ Stock Market (U.S. & Foreign) Index and the NASDAQ Electronic Components Index in fiscal 2021. +7/2/2016 7/1/2017 6/30/2018 6/29/2019 6/27/2020 7/3/2021 +Key Tronic Corporation 100.00 95.94 102.57 67.39 71.18 88.63 +NASDAQ Composite 100.00 128.30 158.57 170.91 216.96 315.10 +NASDAQ Electronic Components 100.00 143.41 189.68 189.47 257.25 416.87 +19 +Item 6: SELECTED FINANCIAL DATA +The following selected data is derived from our audited consolidated financial statements and should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” the consolidated financial statements and related notes, and other information included in this report. +Financial Highlights +(In thousands, except for Supplemental Data and Per Share Amounts) +Fiscal Year Ended +July 3, 2021 June 27, 2020 June 29, 2019 June 30, 2018 July 1, 2017 +Consolidated Statements of Operations Data : +Net sales $ 518,698 $ 449,480 $ 464,044 $ 446,322 $ 467,797 +Gross profit 42,039 35,249 34,601 34,169 38,300 +Gross margin percentage 8.1 % 7.8 % 7.5 % 7.7 % 8.2 % +Operating income (loss) 9,526 6,828 (5,958) 1,114 9,544 +Operating margin percentage 1.8 % 1.5 % (1.3) % 0.2 % 2.0 % +Net income (loss) 4,341 4,758 (7,982) (1,325) 5,617 +Net income (loss) per share – diluted 0.39 0.44 (0.74) (0.12) 0.51 +Consolidated Cash Flow Data : +Cash flows provided by (used in) operations (3) +(15,052) (31,004) 919 3,122 2,284 +Capital expenditures 10,602 8,623 8,386 4,523 9,307 +Consolidated Balance Sheet Data : +Net working capital (1) +172,547 130,545 104,695 95,607 100,440 +Total assets 361,846 304,861 238,310 246,528 232,840 +Long-term liabilities 111,436 77,085 30,447 29,534 38,520 +Shareholders’ equity 123,705 115,557 114,459 118,081 116,567 +Book value per share (2) +$ 11.49 $ 10.74 $ 10.64 $ 10.97 $ 10.83 +Supplemental Data : +Number of shares outstanding at year-end 10,761,871 10,759,680 10,759,680 10,759,680 10,759,680 +Number of employees at year-end 5,450 5,741 4,067 4,701 5,038 +Approximate square footage of operational facilities 1,925,300 1,809,300 1,816,300 1,837,300 1,760,000 +(1) Net working capital is defined as total current assets less total current liabilities. Net working capital measures the portion of current assets that are financed by long term funds and is an indicator of short term financial management. +(2) Book value per share is defined as total shareholders’ equity divided by the number of shares outstanding at the end of the fiscal year. +(3) Reflects the retrospective adoption of ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, during the year ended June 29, 2019. Please refer to Capital Resources and Liquidity section for further information. +20 +Item 7: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +Overview +Key Tronic is a leading contract manufacturer offering value-added design and manufacturing services from its facilities in the United States, Mexico, China and Vietnam. We provide full engineering services, materials management, worldwide manufacturing facilities, assembly services, in-house testing, worldwide distribution and unparalleled customer service. It’s customers include some of the world’s leading original equipment manufacturers. Our combined capabilities and vertical integration are proving to be a desirable offering to our expanded customer base. +Our international production capability provides our customers with benefits of improved supply-chain management, reduced inventories, lower transportation costs, and reduced product fulfillment time. We continue to make investments in all of our operating facilities to give us the production capacity, capabilities and logistical advantages to continue to win new business. The following information should be read in conjunction with the consolidated financial statements included herein and with Part II Item 1A, Risk Factors included as part of this filing. +Our mission is to provide our customers with superior manufacturing and engineering services at the lowest total cost for the highest quality products, and create long-term mutually beneficial business relationships by employing our “Trust, Commitment, Results” philosophy. +Executive Summary +During the fourth quarter of fiscal year 2021, we won new programs involving consumer products, exercise equipment, and residential building products. +We reported net sales of $518.7 million for fiscal year 2021, the highest annual revenue in the Company’s fifty-two year history, and up 15% from $449.5 million for fiscal year 2020. While demand has remained strong from both new and existing customers, revenue for the fourth quarter and for the full year of fiscal year 2021 continued to be significantly constrained by issues related to the worldwide pandemic, the supply chain, and transportation and logistics. +Moving into fiscal 2022, the COVID-19 crisis, component shortages and logistic delays continue to present multiple business challenges, but we continue to see the favorable trend of contract manufacturing returning to North America. With our recent investments in new capacity, we’re increasingly well-prepared for long term growth. +For the first quarter of fiscal year 2022, the Company expects to report revenue in the range of $125 million to $135 million. Despite growing customer demand and backlog, we expect that delays in the supply of key components for the Company’s business will continue to significantly limit production and adversely impact operating efficiencies. +We have continued to diversify our customer base by adding additional programs and customers. Our current customer relationships involve a variety of products, including consumer electronics, electronic storage devices, plastics, household products, gaming devices, specialty printers, telecommunications, industrial equipment, military supplies, computer accessories, medical, educational, irrigation, automotive, transportation management, robotics, RFID, power supply, off-road vehicle equipment, fitness equipment, HVAC controls, consumer products, home building products, material handling systems, lighting equipment, consumer security products, smart security, architectural LED lighting, power meters and smart grid, wireless power solutions, sanitizer dispensing, automotive controllers, oil and gas drilling, wireless security and personal healthcare protective equipment. +Gross profit as a percent of net sales was 8.1 percent in fiscal year 2021 compared to 7.8 percent for the prior fiscal year. The increase in gross profit as a percentage of net sales was primarily related to streamlining efforts in the Company’s Juarez facilities partially offset by supply chain constraints, a temporary four-day closure of our Mexico facilities during a late winter storm that caused power disruptions in the region, and continued but lessening expenses related to COVID-19. The level of gross margin is impacted by product mix, timing of the startup of new programs, facility utilization, and pricing within the electronics industry and material costs, which can fluctuate significantly from quarter to quarter and year to year. +Operating income as a percentage of net sales for fiscal year 2021 was 1.8 percent compared to 1.5 percent for fiscal year 2020. The increase in operating income as a percentage of net sales was primarily driven by the increase in gross profit. +Net income for fiscal year 2021 was $4.3 million or $0.39 per share, as compared to $4.8 million or $0.44 per share for fiscal year 2020. Earnings for the fourth quarter of fiscal 2021 continued to be adversely impacted by supply chain and transportation and logistics issues causing both factory downtime and overtime expenses. Earnings for the fourth quarter of fiscal 2021 were also constrained by legal and other professional service expenses related to the previously disclosed internal investigation of approximately $1.0 million during quarter, and we expect some additional expenses to occur prospectively. Additionally, the Company recorded approximately $0.5 million in non-cash tax expense related to expired stock appreciation rights during the fourth quarter of fiscal year 2021. +21 +We maintained a strong balance sheet with a current ratio of 2.4 and a debt to equity ratio of 0.81. Total cash used in operating activities as defined on our cash flow statement was $15.1 million during fiscal year 2021. We maintained sufficient liquidity for our expected future operations. We believe cash flow from operations, our borrowing capacity, and equipment financing should provide adequate capital for planned growth over the long term. +RESULTS OF OPERATIONS +Comparison of the Fiscal Year Ended July 3, 2021 with the Fiscal Year Ended June 27, 2020 +The following table sets forth for the periods indicated certain items of the consolidated statements of income expressed as a percentage of net sales. The financial information and discussion below should be read in conjunction with the consolidated financial statements and notes contained in this Annual Report. +Fiscal Year Ended +July 3, 2021 % of +net sales June 27, 2020 % of +net sales $ change % point +change +Net sales $ 518,698 100.0% $ 449,480 100.0% $ 69,218 — +Cost of sales 476,659 91.9 414,231 92.2 62,428 (0.3) +Gross profit 42,039 8.1 35,249 7.8 6,790 0.3 +Operating expenses: +Research, development and engineering 9,790 1.9 7,391 1.6 2,399 0.3 +Selling, general and administrative 22,723 4.4 21,030 4.7 1,693 (0.3) +Total operating expenses 32,513 6.3 28,421 6.3 4,092 — +Operating income 9,526 1.8 6,828 1.5 2,698 0.3 +Interest expense, net 3,613 0.7 2,509 0.6 1,104 0.1 +Income before income taxes 5,913 1.1 4,319 1.0 1,594 0.1 +Income tax provision (benefit) 1,572 0.3 (439) (0.1) 2,011 0.4 +Net income $ 4,341 0.8% $ 4,758 1.1% $ (417) (0.3) +Effective income tax rate 26.6 % (10.2) % +Net Sales +The increase in net sales of $69.2 million from prior year period was primarily driven by an increase in new program wins and demand for current programs. However, partially offsetting the increase in revenue during fiscal year 2021, the Company’s revenue was constrained by tightening worldwide supply chain and transportation and logistics issues which delayed the arrival of key components, causing factory downtime. +The following table shows the revenue by industry sectors as a percentage of revenue for fiscal years 2021 and 2020: +Fiscal Year Ended +July 3, 2021 June 27, 2020 +Consumer 51% 44% +Industrial 38% 42% +Communication 5 4 +Gaming 3 5 +Transportation 1 2 +Printers 1 2 +Computer and Peripheral 1 1 +Total 100% 100% +We provide services to customers in a number of industries and produce a variety of products for our customers in each industry. Key Tronic does not target any particular industry, but rather seeks to find programs that strategically fit our vertical manufacturing capabilities. As we continue to diversify our customer base and win new customers, we expect to continue to see a change in the industry concentrations of our revenue. +Sales to foreign locations represented 28.2 percent and 24.6 percent of our total net sales in fiscal years 2021 and 2020, respectively. +22 +Cost of Sales +Total cost of sales as a percentage of net sales was 91.9 percent and 92.2 percent in fiscal years 2021 and 2020, respectively. +We provide a reserve for obsolete and non-saleable inventories based on specific identification of inventory against current demand and recent usage. We also consider our customers' ability to pay for inventory whether or not there is a lead-time assurance agreement for a specific program. The amounts charged to expense for these inventories were approximately $753,000 and $136,000 in fiscal years 2021 and 2020, respectively. +We provide warranties on certain products we sell and estimate warranty costs based on historical experience and anticipated product returns. Warranty expense is related to workmanship claims on keyboards and other products. The amounts charged to expense are determined based on an estimate of warranty exposure. The net warranty expense was approximately $145,000 and $121,000 in fiscal years 2021 and 2020, respectively. +Gross Profit +Gross profit as a percentage of net sales was 8.1 percent and 7.8 percent in fiscal years 2021, and 2020, respectively. The 0.3 percentage point increase in gross profit as a percentage of net sales during fiscal year 2021 as compared to fiscal year 2020 is primarily related to streamlining efforts in the Company’s Juarez facilities and material cost reductions, partially offset by supply chain constraints, a temporary four-day closure of our Mexico facilities during a late winter storm that caused power disruptions in the region, and continued but lessening expenses related to COVID-19. +Changes in gross profit margins reflect the impact of a number of factors that can vary from period to period, including product mix, start-up costs and efficiencies associated with new programs, product life cycles, sales volumes, capacity utilization of our resources, management of inventories, component pricing and shortages, end market demand for customers’ products, fluctuations in and timing of customer orders, and competition within the contract manufacturing industry. These and other factors can cause variations in operating results. There can be no assurance that gross margins will not decrease in future periods. +We took early pay discounts to suppliers that totaled approximately $32,000 and $0.1 million in fiscal years 2021 and 2020, respectively. Early pay discounts will fluctuate based on our liquidity and changes in the discounts and terms offered by our suppliers. +Research, Development and Engineering +Research, development and engineering expenses (RD&E) consists principally of employee related costs, third party development costs, program materials, depreciation and allocated information technology and facilities costs. Total RD&E expenses were $9.8 million in fiscal year 2021 and $7.4 million in fiscal year 2020, respectively. The Company invested more in its RD&E in fiscal year 2021 for development and design of customer programs. The Company anticipates higher RD&E costs in the future as the Company continues to offer these services. Total RD&E expenses as a percent of net sales was 1.9 percent in fiscal year 2021 and 1.6 in fiscal year 2020. +Selling, General and Administrative +Selling, general and administrative expenses (SG&A) consist principally of salaries and benefits, advertising and marketing programs, sales commissions, travel expenses, provision for doubtful accounts, facilities costs, and professional services. Total SG&A expenses were $22.7 million and $21.0 million in fiscal years 2021 and 2020, respectively. Total SG&A expenses as a percent of net sales were 4.4 percent and 4.7 percent in fiscal years 2021 and 2020, respectively. This 0.3 percentage point decrease in SG&A as a percentage of net sales is primarily related to an increase in sales year over year and a decrease in travel related expenses due to the COVID-19 pandemic. +23 +Interest Expense +We had net interest expense of $3.6 million and $2.5 million in fiscal years 2021 and 2020, respectively. The increase in interest expense is primarily related to an increase in the average balance outstanding on our line of credit and increased interest rates. +Income Tax Benefit +We had an income tax expense of approximately $1.6 million during fiscal year 2021 and an income tax benefit of approximately $(0.4) million during fiscal year 2020. The income tax expense (benefit) recognized during both fiscal years 2021 and 2020 was primarily a function of U.S. and foreign taxes recognized at statutory rates, the net benefit associated with federal research and development tax credits, the non-cash tax impact of expired stock appreciation rights in fiscal year 2021, and the recognition of previously unrecognized tax benefits for federal research and development tax credits in fiscal year 2020. +We continually review our requirements for liquidity domestically to fund current operations, revenue growth and to look for potential future acquisitions. We anticipate repatriating a portion of our unremitted foreign earnings. The estimated taxes associated with these expected repatriations are included in the income tax calculation. For further information on taxes please review footnote 6 of the “Notes to Consolidated Financial Statements.” +International Subsidiaries +We offer customers a complete global manufacturing solution. Our facilities provide our customers the opportunity to have their products manufactured in the facility that best serves specific cost, product manufacturing and distribution needs. The locations of active foreign subsidiaries are as follows: +• Key Tronic Juarez, SA de CV owns five facilities and leases three facilities in Juarez, Mexico. These facilities include an SMT facility, an assembly and molding facility, a sheet metal fabrication facility, and assembly and warehouse facilities. This subsidiary is primarily used to support our U.S. operations. +• Key Tronic Computer Peripherals (Shanghai) Co., Ltd. leases two facilities with SMT, assembly, global purchasing and warehouse capabilities in Shanghai, China, which began operations in 1999. Its primary function is to provide contract manufacturing services for export. +• Key Tronic Vietnam leases one facility in Da Nang, Vietnam. This facility includes SMT, assembly, and warehouse capabilities. Its primary function is to provide contract manufacturing services for export. +Foreign sales (based on shipping instructions) from our worldwide operations, including domestic exports, were $146.5 million and $110.7 million in fiscal years 2021 and 2020, respectively. Products and manufacturing services provided by our subsidiary operations are often shipped to customers directly by the parent company. +RESULTS OF OPERATIONS +Comparison of the Fiscal Year Ended June 27, 2020 with the Fiscal Year Ended June 29, 2019 +To review the results of operations comparison of the fiscal year ended June 27, 2020 with the fiscal year ended June 29, 2019, please refer to our Form 10-K filed September 11, 2020 with the Securities and Exchange Commission or follow the link below. +https://www.sec.gov/ix?doc=/Archives/edgar/data/719733/000071973320000061/ktcc-20200627.htm +Capital Resources and Liquidity +Operating Cash Flow +Net cash used in operating activities for fiscal year 2021 was $15.1 million compared to net cash used in operating activities of $31.0 million and net cash provided by operating activities of $0.9 million in fiscal years 2020 and 2019, respectively. +The $15.1 million of net cash used in operating activities during fiscal year 2021 is primarily related to $4.3 million of net income adjusted for $6.9 million of depreciation and amortization, $24.3 million increase in accounts receivable, a $23.1 million increase in inventory, a $1.0 million increase in contract assets, a $2.3 million decrease in other assets, partially offset by a $12.6 million increase in accounts payable, an $5.6 million increase in other liabilities, and a $1.0 million increase in accrued compensation and vacation. +The $31.0 million of net cash used in operating activities during fiscal year 2020 was primarily related to $4.8 million of net income adjusted for $5.6 million of depreciation and amortization, $28.3 million increase in accounts receivable, a $14.7 million increase in inventory, a $7.7 million increase in other assets, a $1.6 million increase in contract assets, partially offset by a $6.6 million increase in accounts payable and a $3.7 million increase in accrued compensation and vacation. +24 +The $0.9 million of net cash provided by operating activities during fiscal year 2019 was primarily related to $8.0 million of net loss, $12.4 million impairment of goodwill and intangibles, $7.3 million of depreciation and amortization, $6.7 million of cash received from arbitration settlement, a $3.3 million decrease in accounts receivable, partially offset by a $10.3 million increase in contract assets, a $4.5 million increase in other assets, a $2.6 million increase in accounts payable and a $1.4 million decrease in inventory. +Accounts receivable fluctuates based on the timing of shipments, terms offered and collections. In addition, accounts receivable will fluctuate based upon the amount of accounts receivable sold under our Trade Accounts Receivable Purchase Program. The Company did not sell any accounts receivables during the twelve months ended July 3, 2021. During fiscal years 2020 and 2019, we factored receivables of $41.4 million and $81.0 million, respectively, from accounts receivable sold to financial institutions, which are not included on our Consolidated Balance Sheets. The Company no longer had factored receivables at year end fiscal 2021 or 2020. We purchase inventory based on customer forecasts and orders, and when those forecasts and orders change, the amount of inventory may also fluctuate. Accounts payable fluctuates with changes in inventory levels, volume of inventory purchases, negotiated supplier terms, and taking advantage of early pay discounts. +Investing Cash Flow +Cash flows used in investing activities were $10.6 million for fiscal year 2021. Cash flows used in investing activities were $3.6 million and $1.9 million in fiscal year 2020 and 2019, respectively. Our primary use of cash in investing activities during fiscal years 2021, 2020 and 2019, was purchasing equipment to support increased production levels for new programs. During fiscal years 2020 and 2019, our primary source of cash provided by investing activities came from receipts of the deferred purchase price on factored receivables. +Operating and finance leases under accounting guidance that became effective in fiscal year 2020, and capital leases prior to that date are often utilized when potential technical obsolescence and funding requirement advantages outweigh the benefits of equipment ownership. Capital expenditures and periodic lease payments are expected to be financed with internally generated funds and available borrowing capacities. During fiscal years 2021, 2020 and 2019, we did not receive any cash resulting from the sale and leaseback of equipment under operating leases. +Financing Cash Flow +Cash flows provided by financing activities were $28.6 million, $34.5 million, and $1.2 million in fiscal years 2021, 2020, and 2019. Our primary financing activities during fiscal year 2021, were repayments on our term loans of $11.7 million as well as borrowings and repayments under our revolving line of credit facility. Our primary financing activities during fiscal year 2020 was repayments on our term loans of $7.1 million as well as borrowings and repayments under our revolving line of credit facility. Our primary financing activities during fiscal year 2019 was repayments on our term loans of $5.9 million as well as borrowings and repayments under our revolving line of credit facility. +As of July 3, 2021, the Company had an outstanding balance on the line of credit of $90.9 million. We had availability to borrow an additional $2.1 million under the asset-based revolving credit facility and we were in compliance with our loan covenants. Our cash requirements are affected by the level of current operations and new programs. We believe that projected cash from operations, funds available under the asset-based revolving credit facility and fixed asset financing will be sufficient to meet our working and fixed capital requirements for the foreseeable future. +As of July 3, 2021, we had approximately $2.0 million of cash held by foreign subsidiaries. Under the Tax Cuts and Jobs Act, future cash repatriations from these foreign subsidiaries are no longer subject to U.S. income taxes, but may be subject to foreign withholding taxes. See additional discussion in Footnote 6, Income Taxes. The total amount of foreign withholding taxes required to be paid for the amount of foreign subsidiary cash on hand as of July 3, 2021, would approximate $47,000. The Company also has approximately $23.6 million of foreign earnings that have not been repatriated to the U.S. Of that amount, the Company estimates that $7.5 million is to be repatriated in the future, requiring foreign withholding taxes of $0.8 million that is currently accrued in our deferred tax liabilities. The remaining $16.1 million is considered to be permanently reinvested in Mexico, China and Vietnam. If these amounts were required to be repatriated, we estimate it would create an additional $0.8 million in foreign withholding taxes payable. +25 +Contractual Obligations and Commitments +In the normal course of business, we enter into contracts which obligate us to make payments in the future. The table below sets forth our significant future obligations by fiscal year: +Payments Due by Fiscal Year (in thousands) +Total 2022 2023 2024 2025 2026 Thereafter +Term loans (1) +$ 10,049 $ 2,143 $ 2,190 $ 2,239 $ 2,290 $ 1,187 $ — +Bank of America revolving loan (2) +$ 90,886 $ — $ — $ — $ — $ 90,886 $ — +Operating leases (3) +$ 18,308 $ 4,225 $ 3,140 $ 2,526 $ 2,427 $ 1,865 $ 4,125 +Purchase orders (4) +$ 116,067 +(1) The terms of the Bank of America term loans are discussed in the consolidated financial statements at Note 4, “Long-Term Debt.” The equipment financing facility relating to the Company’s existing U.S. manufacturing equipment is payable in equal monthly payments of approximately $94,000 which commenced on September 14, 2020 and will continue through the maturity of the equipment financing facility on August 14, 2025. The equipment financing facility relating to the Company’s existing Mexico manufacturing equipment is payable in equal monthly payments of approximately $100,000 which commenced on May 24, 2021 and will continue through the maturity of the equipment term loan on April 24, 2026. +(2) The terms of the Bank of America asset-based revolving credit facility are discussed in the consolidated financial statements at Note 4, “Long-Term Debt.” As of July 3, 2021, we were in compliance with our loan covenants. +(3) We maintain vertically integrated manufacturing operations in the United States, Mexico, China and Vietnam. We lease some of our administrative and manufacturing facilities and equipment. A complete discussion of properties can be found in Part 1, Item 2 at “Properties.” Leases have proven to be an acceptable method for us to acquire new or replacement equipment and to maintain facilities with a minimum impact on our short term cash flows for operations. In addition, such operations are heavily dependent upon technically superior manufacturing equipment including molding machines in various tonnages, Surface Mount Technology (SMT) lines, sheet metal fabrication and stamping machines, clean rooms, and automated insertion, and test equipment for the various products we are capable of producing. +(4) As of July 3, 2021, we had open purchase order commitments for materials and other supplies of approximately $116.1 million. Included in the open purchase orders are various blanket orders for annual requirements. Actual needs under these blanket purchase orders fluctuate with our manufacturing levels and as such cannot be broken out between fiscal years. In addition, we have contracts with many of our customers that minimize our exposure to losses for material purchased within lead-times necessary to meet customer forecasts. Purchase orders generally can be cancelled without penalty within specified ranges that are determined in negotiations with our suppliers. These agreements depend in part on the type of materials purchased as well as the circumstances surrounding any requested cancellations. +In addition to the cash requirements presented above, we have various other accruals which are not included in the table above. For example, we owe our suppliers approximately $92.8 million for accounts payable and shipments in transit at the end of the fiscal year. We generally pay our suppliers in a range from 30 to 120 days depending on terms offered. These payments are financed by operating cash flows and our revolving line of credit. +We believe that cash flows generated from operations, factoring, leasing facilities, and funds available under the revolving credit facility will satisfy cash requirements for a period in excess of 12 months and into the foreseeable future. +26 +Critical Accounting Policies and Estimates +Preparation of our consolidated financial statements requires management to make estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses. Note 1 to our consolidated financial statements describes the significant accounting policies used in the preparation of our consolidated financial statements. Management believes the most complex and sensitive judgments, because of their significance to our consolidated financial statements, result primarily from the need to make estimates about effects of matters that are inherently uncertain. The most significant areas involving management judgments are described below. Actual results in these areas could differ from management’s estimates. +Revenue +The Company specializes in services ranging from product manufacturing to engineering and tooling services. The first step in its process for revenue recognition is to identify the contract with a customer. A contract is defined as an agreement between two or more parties that creates enforceable rights and obligations. A contract can be written, oral, or implied. The Company generally enters into manufacturing service agreements (“MSA”) with its customers that outlines the terms of the business relationship between the customer and the Company. This includes matters such as warranty, indemnification, transfer of title and risk of loss, liability for excess and obsolete inventory, pricing, payment terms, etc. The Company will also bid on a program-by-program basis for customers in which an executed MSA may not be in place. In these instances, as well as when we have an MSA in place, we receive customer purchase orders for specific quantities and timing of products. As a result, the Company considers its contract with a customer to be the combination of the MSA and the purchase order. The transaction price is fixed and set forth in each purchase order. In the Company's normal course of business, there are no variable pricing components, or material amounts refunded to customers in the form of refunds or rebates. +The Company assesses whether control of the product or services promised under the contract is transferred to the customer at a point in time (shipment) or over time (as we manufacture the product). The Company is first required to evaluate whether its contracts meet the criteria for 'over-time' or 'point-in-time' recognition. The Company has determined that for the majority of its contracts the Company is manufacturing products for which there is no alternative use due to the unique nature of the customer-specific product, IP and other contract restrictions. Further, the Company has an enforceable right to payment including a reasonable profit for performance completed to date with respect to these contracts. As a result, revenue is recognized under these contracts 'over-time' based on the input cost-to-cost method as it better depicts the transfer of control. This input method is based on the ratio of costs incurred to date as compared to the total estimated costs at completion of the performance obligation. For all other contracts that do not meet these criteria, such as manufacturing contracts for which the terms do not provide an enforceable right to payment for performance completed to date, the Company recognizes revenue when it has transferred control of the related manufactured products which generally occurs upon shipment to the customer. Revenue from engineering services is recognized over time as the services are performed. +Inactive, Obsolete, and Surplus Inventory Reserve +Inventories are stated at the lower of cost or net realizable value. Inventory valuation is determined using the first-in, first-out (FIFO) method. We reserve for inventories that we deem inactive, obsolete or surplus. This reserve is calculated based upon the demand for the products that we produce. Demand is determined by expected sales, customer purchase orders, or customer forecasts. If expected sales do not materialize, then we would have inventory in excess of our reserves and would have to charge the excess against future earnings. In the case where we have purchased material based upon a customer’s forecast or purchase orders, we are usually covered by lead-time assurance agreements or purchase orders with each customer. These contracts state that the financial liability for material purchased within agreed upon lead-time and based upon the customer’s forecasts, lies with the customer. If we purchase material outside the lead-time assurance agreement and the customer’s forecasts do not materialize or if we have no lead-time assurance agreement for a specific program, we would have the financial liability and may have to charge inactive, obsolete or surplus inventory against earnings. We also reserve for inventory related to specific customers covered by lead-time assurance agreements when those customers are experiencing financial difficulties or reimbursement is not reasonably assured. +Allowance for Doubtful Accounts +We value our accounts receivable net of an allowance for doubtful accounts. As of July 3, 2021, the allowance for doubtful accounts was approximately $275,000. As of June 27, 2020, the allowance for doubtful accounts was approximately $609,000. This allowance is based on estimates of the portion of accounts receivable that may not be collected in the future. The estimates used are based primarily on specific identification of potentially uncollectible accounts. Such accounts are identified using publicly available information in conjunction with evaluations of current payment activity. However, if any of our customers were to develop unexpected and immediate financial problems that would prevent payment of open invoices, we could incur additional and possibly material expenses that would negatively impact earnings. +27 +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. We review the adequacy of this accrual quarterly based on historical analysis and anticipated product returns and rework costs. Our warranty period for keyboards is generally longer than that for other products. We only warrant materials and workmanship on products, and we do not warrant design defects for customers. +Income Taxes +Income tax expense includes U.S. and international income taxes and a provisional estimate for U.S. taxes on undistributed earnings of foreign subsidiaries. We do not record foreign withholding taxes on undistributed earnings of international subsidiaries that are deemed to be permanently reinvested. Certain income and expenses are not reported in tax returns and financial statements in the same year. The tax effect of such temporary differences is reported as deferred income taxes. The deferred income taxes are classified as long-term assets or liabilities. The most significant areas involving management judgments include deferred income tax assets and liabilities, uncertain tax positions, and research and development tax credits. Our estimates of the realization of the deferred tax assets related to our tax credits are based upon our estimates of future taxable income which may change. +Stock-Based Compensation +Stock-based compensation is accounted for according to Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 718, Compensation—Stock Compensation . ASC 718 requires us to expense the fair value of employee stock options, stock appreciation rights and other forms of stock-based compensation. Under the fair value recognition provisions of ASC 718, share-based compensation cost is estimated at the grant date based upon the fair value of the award and is recognized as expense ratably over the requisite service period of the award (generally the vesting period). Determining the appropriate fair value model and calculating the fair value of share-based awards requires judgment, including estimating the expected life of the share-based award, the expected stock price volatility over the expected life of the share-based award and forfeitures. +To determine the fair value of stock based awards on the date of grant we use the Black-Scholes option-pricing model. Inherent in this model are assumptions related to expected stock price volatility, option life, risk-free interest rate and dividend yield. The risk-free interest rate is a less-subjective assumption as it is based on factual data derived from public sources. We use a dividend yield of zero as we have never paid cash dividends and have no intention to pay cash dividends in the foreseeable future. The expected stock price volatility and option life assumptions require a greater level of judgment. Our expected stock-price volatility assumption is based upon the historical volatility of our stock which is obtained from public data sources. The expected life represents the weighted average period of time that share-based awards are expected to be outstanding, giving consideration to vesting schedules and historical exercise patterns. We determine the expected life assumption based upon the exercise and post-vesting behavior that has been exhibited historically, adjusted for specific factors that may influence future exercise patterns. If expected volatility or expected life were to increase, that would result in an increase in the fair value of our stock options which would result in higher compensation charges, while a decrease in volatility or the expected life would result in a lower fair value of our stock option awards resulting in lower compensation charges. +We estimate forfeitures for all of our awards based upon historical experience of stock-based pre-vesting forfeitures. We believe that our estimates are based upon outcomes that are reasonably likely to occur. If actual forfeitures are higher than our estimates it would result in lower compensation expense and to the extent the actual forfeitures are lower than our estimate we would record higher compensation expense. +Impairment of Long-Lived Assets +Long-lived assets, such as property, plant, and equipment are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to the estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future cash flows, an impairment charge would be recognized in the amount by which the carrying amount of the asset exceeds the fair value of the asset. +Derivatives and Hedging Activity +Derivatives are recognized on the balance sheet at their estimated fair value. On the date a derivative contract is entered into, the Company designates the derivative as a hedge of a forecasted transaction or of the variability of cash flows to be received or paid related to a recognized asset or liability (a “cash flow” hedge). The Company does not enter into derivatives for speculative purposes. Changes in the fair value of a derivative that qualifies as a cash flow hedge are recorded in “Accumulated Other Comprehensive Income,” until earnings are affected by the variability of cash flows. See Note 10 of the Company’s consolidated financial statements for additional information. +28 +Long-Term Incentive Compensation Accrual +Long-term incentive compensation is recognized as expense ratably over the requisite service period of the award which is generally three years. The Board of Directors approve target performance measures for the three year period for each of the Company’s officers and non-employee Directors. Performance measures are based on a combination of sales growth targets and return on invested capital targets. No cash awards will be made to participants if actual Company performance does not exceed the minimum target performance measures. The calculation used to determine the necessary accrual uses a combination of actual results and projected results. We believe that our estimates are based upon outcomes that are reasonably likely to occur. These estimates and assumptions are based on historical results as well as future expectations. Actual results could vary from our estimates and assumptions. +Impairment of Goodwill +In accordance with ASC 350, Goodwill and Other Intangible Assets , goodwill is not amortized but is required to be reviewed for impairment at least annually or when events or circumstances indicate that carrying value may exceed fair value. The Company is permitted the option to first assess qualitative factors to determine whether the existence of events and circumstances indicates that it is more likely than not that the fair value of any reporting unit is less than its corresponding carrying value. If, after assessing the totality of events and circumstances, the Company concludes that it is not more likely than not that the fair value of any reporting unit is less than its corresponding carrying value then the Company is not required to take further action. However, if the Company concludes otherwise, then it is required to perform a quantitative impairment test, including computing the fair value of the reporting unit and comparing that value to its carrying value. The Company utilized a weighting of the income approach and a market approach in the impairment test. We also considered valuation factors including the Company's market capitalization, future discounted cash flows and an estimated control premium based upon a review of comparable market transactions. Our consideration of discounted future cash flows included assumptions regarding growth rates and margins based on our historical trends. In addition, we applied a market discount rate calculated based upon an analysis of companies similar in size. If our future cash flows do not meet our projections or there is an event that impacts our market capitalization, the assumptions used in our goodwill analysis could be negatively impacted. +Goodwill impairment would be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying value of goodwill. In the event that goodwill is impaired, an impairment charge to earnings would become necessary. The Company also has the option to bypass the qualitative assessment for goodwill in any period and proceed directly to performing the quantitative impairment test. Refer to footnote 14 for discussion of the write-off of goodwill and other intangibles that occurred during fiscal year 2019, as a result of certain triggering events being present. +New and Future Accounting Pronouncements +See Note 1 to our consolidated financial statements. +29 +Item 7A: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Interest Rate Risk +We are subject to the risk of fluctuating interest rates in the normal course of business. Our major market risk relates to our secured debt. Our asset-based senior secured revolving credit facility, and equipment financing facility are secured by substantially all of our assets. The interest rates applicable to our asset-based senior secured revolving credit facility fluctuate with LIBOR rates. There was outstanding $90.9 million in borrowings under our asset-based senior secured revolving credit facility and $10.0 million outstanding on our equipment financing facilities as of July 3, 2021. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity” and Note 4 – “Long-Term Debt” to the Consolidated Financial Statements for additional information regarding our revolving credit facility and term loans. +Foreign Currency Exchange Risk +A significant portion of our operations are in foreign locations. As a result, transactions occur in currencies other than the U.S. dollar. Exchange rate fluctuations among other currencies used by us would directly or indirectly affect our financial results. We currently use Mexican peso forward contracts to hedge foreign currency fluctuations for a portion of our Mexican peso denominated expenses. There was $10.6 million of foreign currency forward contracts outstanding as of July 3, 2021. The fair value of these contracts was approximately $3.6 million. See Note 10 – “Derivative Financial Instruments” to the Consolidated Financial Statements for additional information regarding our derivative instruments. +30 +Item 8: +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Report of Independent Registered Public Accounting Firm +Shareholders and Board of Directors +Key Tronic Corporation +Spokane Valley, Washington +Opinion on the Consolidated Financial Statements +We have audited the accompanying consolidated balance sheets of Key Tronic Corporation (the “Company”) as of July 3, 2021 and June 27, 2020, the related consolidated statements of income (loss), comprehensive income (loss), shareholders’ equity, and cash flows for each of the three years in the period ended July 3, 2021, and the related notes and schedule (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at July 3, 2021 and June 27, 2020, and the results of its operations and its cash flows for each of the three years in the period ended July 3, 2021, in conformity with accounting principles generally accepted in the United States of America. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company's internal control over financial reporting as of July 3, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) and our report dated September 16, 2021 expressed an unqualified opinion thereon. +Change in Accounting Principles +As discussed in Note 1 to the consolidated financial statements, the Company changed its accounting method for accounting for leases in fiscal year 2020 due to the adoption of Topic 842: Leases , using a modified retrospective approach. +Basis for Opinion +These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. +Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. +Critical Audit Matters +The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. +Accounting for Revenue from Contracts with Customers +As described in Notes 1 and 15 to the consolidated financial statements, the Company’s consolidated revenue balance was $519 million for the year ended July 3, 2021, of which $510 million related to revenues recognized over time and $9 million related to revenues recognized at a point in time. Revenues for contracts for manufacturing products and contracts for engineering +31 +services are recognized over-time using the input method based on the ratio of costs incurred to date as compared to the total estimated costs at the completion of the performance obligation or as the services are performed. +We identified revenues recognized over time on contracts for manufacturing products as a critical audit matter. Management’s calculation includes reports with varying elements, for determining the estimated costs incurred to date. Auditing these elements involved especially challenging and subjective auditor judgment due to the nature and extent of audit effort required to address these matters. +The primary procedures we performed to address this critical audit matter included: +• Testing the design and operating effectiveness of controls relating to the inputs of the quarterly calculation of the contract asset for in process contracts for each manufacturing location; +• Evaluating the methodology of estimating costs incurred to date on contracts for manufacturing products and testing the completeness and accuracy of the system reports by recalculating the expected costs on contracts in process; +• Analyzing the margins realized and ratio of costs incurred by comparing the trending historic margins by customer and ratios of completion to prior periods. +Accounting for Inventories +As described in Note 1 and Note 2 to the consolidated financial statements, the Company’s consolidated inventory balance was $137.3 million at July 3, 2021. In January 2021, the Company determined that improper accounting resulted in an understatement of cost of goods sold and an overstatement of inventories. Subsequent to the matter identified in January 2021, additional inventory accounting errors unrelated to the investigation were also identified by management. As discussed in Item 9A, Controls and Procedures, the errors were a result of material weaknesses in internal controls over financial reporting related to the design and operating effectiveness of certain controls over the accounting for inventory as well as the Company’s monitoring activities as it pertains to accounting for inventory at its domestic facilities. As disclosed by the Company, the material weakness was remediated fully at July 3, 2021. +We identified management’s estimates for costs capitalized to inventories, including the Company’s internal investigation of improper inventory accounting, as a critical audit matter. Auditing these elements involved especially challenging auditor judgment due to the nature and extent of audit effort required to address these matters, including the extent of specialized skills and knowledge. In addition, as described in Item 9A, a material weakness in internal controls was disclosed as of December 26, 2020 and April 3, 2021, that relates to this matter. +The primary procedures we performed to address this critical audit matter included: +• Utilizing personnel with specialized knowledge and skills in legal and forensic matters to assist in assessing the reasonableness of the scope, investigative procedures, and findings of the internal investigation supervised by the Audit Committee of the Company’s Board of Directors. +• Testing the design and operating effectiveness of controls relating to inventories and management’s remedial measures of existing controls and implementation of additional controls, including oversight of the East Locations and review by the Corporate office of material account reconciliations and journal entries. +• Analyzing the correction of the errors identified by assessing the estimates used in calculating the corrections of the errors related to costs capitalized to inventories and by evaluating corroborative evidence. +/s/ BDO USA, LLP +We have served as the Company's auditor since 2003 +Spokane, Washington +September 16, 2021 +32 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED BALANCE SHEETS +(In thousands) +July 3, 2021 June 27, 2020 +ASSETS +Current assets: +Cash and cash equivalents $ 3,473 $ 553 +Trade receivables, net of allowance for doubtful accounts of $275 and $609 110,324 86,123 +Contract assets 24,781 23,753 +Inventories, net 137,329 115,020 +Other 23,345 17,315 +Total current assets 299,252 242,764 +Property, plant and equipment, net 35,735 31,764 +Operating lease right-of-use assets, net 15,745 17,568 +Other assets: +Deferred income tax asset 9,656 10,178 +Other 1,458 2,587 +Total other assets 11,114 12,765 +Total assets $ 361,846 $ 304,861 +LIABILITIES AND SHAREHOLDERS ’ EQUITY +Current liabilities: +Accounts payable $ 92,823 $ 80,204 +Accrued compensation and vacation 11,471 10,428 +Current portion of debt, net 2,143 7,508 +Other 20,268 14,079 +Total current liabilities 126,705 112,219 +Long-term liabilities: +Term loans 7,906 3,258 +Revolving loan 90,362 60,094 +Operating lease liabilities 11,428 12,624 +Deferred income tax liability — 234 +Other long-term obligations 1,740 875 +Total long-term liabilities 111,436 77,085 +Total liabilities 238,141 189,304 +Commitments and contingencies (Note 4 and 9) +Shareholders’ equity: +Common stock, no par value—shares authorized 25,000; issued and outstanding 10,762 and 10,760 shares, respectively 47,181 46,946 +Retained earnings 74,452 70,111 +Accumulated other comprehensive (loss) income 2,072 ( 1,500 ) +Total shareholders’ equity 123,705 115,557 +Total liabilities and shareholders’ equity $ 361,846 $ 304,861 +See accompanying notes to consolidated financial statements. +33 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF INCOME (LOSS) +(In thousands, except per share amounts) +Fiscal Year Ended +July 3, 2021 June 27, 2020 June 29, 2019 +Net sales $ 518,698 $ 449,480 $ 464,044 +Cost of sales 476,659 414,231 429,443 +Gross profit 42,039 35,249 34,601 +Research, development and engineering expenses 9,790 7,391 6,555 +Selling, general and administrative expenses 22,723 21,030 21,556 +Impairment of goodwill and intangibles — — 12,448 +Total operating expenses 32,513 28,421 40,559 +Operating income (loss) 9,526 6,828 ( 5,958 ) +Interest expense, net 3,613 2,509 2,782 +Income (loss) before income taxes 5,913 4,319 ( 8,740 ) +Income tax provision (benefit) 1,572 ( 439 ) ( 758 ) +Net income (loss) $ 4,341 $ 4,758 $ ( 7,982 ) +Net income (loss) per share — Basic $ 0.40 $ 0.44 $ ( 0.74 ) +Weighted average shares outstanding — Basic 10,760 10,760 10,760 +Net income (loss) per share — Diluted $ 0.39 $ 0.44 $ ( 0.74 ) +Weighted average shares outstanding — Diluted 11,046 10,816 10,760 +See accompanying notes to consolidated financial statements. +34 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) +(In thousands) +Fiscal Year Ended +July 3, 2021 June 27, 2020 June 29, 2019 +Comprehensive income (loss): +Net income (loss) $ 4,341 $ 4,758 $ ( 7,982 ) +Other comprehensive income (loss): +Unrealized gain (loss) on hedging instruments, net of tax 3,572 ( 3,926 ) 3,395 +Comprehensive income (loss) $ 7,913 $ 832 $ ( 4,587 ) +Other comprehensive income (loss) for fiscal years 2021, 2020, and 2019 is reflected net of tax provision (benefit) of approximately $ 1.2 million, $( 1.1 ) million and $ 1.0 million, respectively. +See accompanying notes to consolidated financial statements. +35 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Fiscal Year Ended +July 3, 2021 June 27, 2020 June 29, 2019 +Operating activities: +Net income (loss) $ 4,341 $ 4,758 $ ( 7,982 ) +Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities: +Goodwill and intangible assets impairment — — 12,448 +Depreciation and amortization 6,856 5,591 7,298 +Amortization of interest rate swap 276 — — +Amortization of deferred loan costs 95 30 30 +Excess tax benefit from exercise of stock options ( 43 ) — — +Provision for obsolete inventory 753 136 91 +Provision for warranty 145 121 83 +Provision for doubtful accounts 117 551 58 +Loss on disposal of assets — 207 3 +Share-based compensation expense 192 266 436 +Deferred income taxes ( 942 ) ( 958 ) ( 1,116 ) +Changes in operating assets and liabilities +Trade receivables ( 24,318 ) ( 28,254 ) 3,344 +Contract assets ( 1,028 ) ( 1,592 ) ( 10,255 ) +Cash received from arbitration settlement — — 6,684 +Inventories ( 23,062 ) ( 14,725 ) ( 1,417 ) +Other assets 2,317 ( 7,728 ) ( 4,490 ) +Accounts payable 12,618 6,632 ( 2,627 ) +Accrued compensation and vacation 1,043 3,669 ( 1,346 ) +Other liabilities 5,588 292 ( 323 ) +Cash provided by (used in) operating activities ( 15,052 ) ( 31,004 ) 919 +Investing activities: +Purchases of property and equipment ( 10,602 ) ( 8,623 ) ( 8,386 ) +Proceeds from sale of fixed assets — 696 22 +Cash receipts from deferred purchase price of factored receivables — 4,350 6,455 +Cash used in investing activities ( 10,602 ) ( 3,577 ) ( 1,909 ) +Financing activities: +Payment of financing costs ( 617 ) ( 84 ) ( 15 ) +Proceeds from issuance of long term debt 11,000 5,000 — +Interest rate swap termination fee ( 925 ) — — +Repayments of long term debt ( 11,720 ) ( 7,121 ) ( 5,871 ) +Borrowings under revolving credit agreement 414,943 177,343 181,688 +Repayments of revolving credit agreement ( 384,150 ) ( 140,605 ) ( 174,554 ) +Excess tax benefit from exercise of stock options 43 — — +Cash provided by financing activities 28,574 34,533 1,248 +Net increase (decrease) in cash and cash equivalents 2,920 ( 48 ) 258 +Cash and cash equivalents, beginning of period 553 601 343 +Cash and cash equivalents, end of period $ 3,473 $ 553 $ 601 +Supplemental cash flow information: +Interest payments $ 3,777 $ 2,483 $ 2,773 +Income tax payments, net of refunds $ 2,014 $ 683 $ ( 511 ) +Recognition of operating lease liabilities and right-of-use assets $ 3,103 $ — $ — +See accompanying notes to consolidated financial statements. +36 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY +(In thousands) +Shares Common +Stock Retained +Earnings Accumulated +Other +Comprehensive +Income (Loss) Total +Shareholders’ +Equity +Balances, June 30, 2018 10,760 $ 46,244 $ 72,806 $ ( 969 ) $ 118,081 +Net loss — — ( 7,982 ) — ( 7,982 ) +ASC 606 opening balance sheet adjustment — — 529 — 529 +Unrealized gain on hedging instruments, net — — — 3,395 3,395 +Share-based compensation — 436 — — 436 +Balances, June 29, 2019 10,760 $ 46,680 $ 65,353 $ 2,426 $ 114,459 +Net income — — 4,758 — 4,758 +Unrealized loss on hedging instruments, net — — — ( 3,926 ) ( 3,926 ) +Share-based compensation — 266 — — 266 +Balances, June 27, 2020 10,760 $ 46,946 $ 70,111 $ ( 1,500 ) $ 115,557 +Net income — — 4,341 — 4,341 +Unrealized gain on hedging instruments, net — — — 3,572 3,572 +Exercise of stock appreciation rights 2 — — — — +Excess tax benefit from exercise of stock options — 43 — — 43 +Share-based compensation — 192 — — 192 +Balances, July 3, 2021 10,762 $ 47,181 $ 74,452 $ 2,072 $ 123,705 +See accompanying notes to consolidated financial statements. +37 +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. SIGNIFICANT ACCOUNTING POLICIES +Business +Key Tronic Corporation and subsidiaries (the Company) is engaged in contract manufacturing for original equipment manufacturers (OEMs) and also manufactures keyboards and other input devices. The Company’s headquarters are located in Spokane Valley, Washington with manufacturing operations in Oakdale, Minnesota; Fayetteville, Arkansas; Corinth, Mississippi; and foreign manufacturing operations in Juarez, Mexico; Shanghai, China; and Da Nang, Vietnam. +Due to the COVID-19 pandemic, the Company has seen extreme shifts in demand from its customer base, supply chain and logistics risks. The possibility of future temporary closures, as well as adverse fluctuations in customer demand, freight and expedite costs, precautionary safety expenses and labor shortages, collectability of accounts, and future supply chain disruptions during the rapidly changing COVID-19 environment can materially impact operating results. Additionally, continued adverse macroeconomic conditions and significant currency exchange fluctuations can also materially impact operating results. +Correction of an Immaterial Errors +The Company previously reported as of June 27, 2020 that its inventory balances included finished goods of $15.3 million and work in process of $17.4 million. Such amounts actually related to raw materials. The Company has revised its disclosure of inventory to reflect these costs as raw material costs. There was no change to the total inventory balance. Refer to corrected disclosure in Note 2. +The Company made an out-of-period tax adjustment in fiscal year 2021 in the amount of $0.4 million decreasing the deferred tax asset related to unexercised stock appreciation rights (SARs), to reflect the fact that certain of the unexercised SARs had expired over several different periods prior to fiscal year 2021. +The Company previously excluded the right of use asset amounts as reported as of June 27, 2020 in Note 12. Refer to corrected disclosures in Note 12. +Principles of Consolidation +The consolidated financial statements include the Company and its wholly owned subsidiaries in the United States, Mexico, China and Vietnam. Intercompany balances and transactions have been eliminated during consolidation. +Use of Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates include the allowance for doubtful receivables, the provision for obsolete and non-saleable inventories, deferred tax assets and liabilities, uncertain tax positions, valuation of goodwill, impairment of long-lived assets, medical self-funded insurance liability, long-term incentive compensation accrual, the provision for warranty costs, the fair value of stock appreciation rights granted under the Company’s share-based compensation plan and purchase price allocation of acquired businesses. Due to uncertainties with respect to the assumptions and estimates, actual results could differ from those estimates. +Cash and Cash Equivalents +The Company considers investments with an original maturity of three months or less to be cash equivalents. Cash equivalents are carried at cost, which approximates fair value. The Company may have cash and cash equivalents at financial institutions that are in excess of federally insured limits from time to time. +Allowance for Doubtful Accounts +The Company evaluates the collectability of accounts receivable and records an allowance for doubtful accounts, which reduces the receivables to an amount that management reasonably estimates will be collected. A specific allowance is recorded against receivables considered to be impaired based on the Company’s knowledge of the financial condition of the customer. In determining the amount of the allowance, the Company considers several factors including the aging of the receivables, the current business environment and historical experience. After all attempts to collect a receivable have failed, the receivable is written off against the allowance. +38 +Inventories +Inventories are stated at the lower of cost or net realizable value. Inventory valuation is determined using the first-in, first-out (FIFO) method. Customer orders are based upon forecasted quantities of product manufactured for shipment over defined periods. Raw material inventories are purchased to fulfill these customer requirements. Within these arrangements, customer demands for products frequently change, sometimes creating excess and obsolete inventories. The Company regularly reviews raw material inventories by customer for both excess and obsolete quantities. Wherever possible, the Company attempts to recover its full cost of excess and obsolete inventories from customers or, in some cases, through other markets. When it is determined that the Company’s carrying cost of such excess and obsolete inventories cannot be recovered in full, a charge is taken against income for the difference between the carrying cost and the estimated realizable amount. We also reserve for inventory related to specific customers covered by lead-time assurance agreements when those customers are experiencing financial difficulties or reimbursement is not reasonably assured. +Property, Plant and Equipment +Property, plant and equipment are carried at cost and depreciated using straight-line methods over the expected useful lives of the assets. Repairs and maintenance costs are expensed as incurred. +Impairment of Goodwill +In accordance with accounting guidance on goodwill and other intangible assets, the Company evaluates goodwill for impairment at the reporting unit level annually, and whenever circumstances occur indicating that goodwill might be impaired. Upon adoption of ASU 2017-04, the Company now recognizes an impairment charge (not to exceed the total amount of goodwill allocated to the reporting unit) for the amount by which the carrying amount of a reporting unit exceeds the reporting unit’s fair value. During the third quarter of fiscal year 2019, a few large programs declined in revenue and two new programs were delayed. This decrease in the Company’s total revenue combined with book value continuing to exceed market capitalization caused a “triggering event” in which to perform a quantitative impairment analysis as of March 30, 2019. To estimate the fair value of the Company’s equity, the Company used both a market approach and an income approach, based on a discounted cash flows analysis. As of March 30, 2019, market related factors increased expected required rates of return, which also increased the Company’s discount rate used to project future cash flows. Further, push outs of the Company’s forecasted future cash flows relating to delays in customer orders adversely impacted the Company’s discounted cash flows model. As a result, a lower estimate in the Company’s fair value using these two valuation methods indicated an impairment charge. +During the third quarter of fiscal year 2019, the Company also assessed other finite-lived intangible assets including the Company’s customer relationships and favorable lease agreements due to an indicator of possible impairment being present, as discussed above. As a result of the analysis performed, the Company determined that the carrying value of the customer relationships intangible asset was not recoverable and recorded an impairment for the entire carrying amount during the third quarter of fiscal year 2019. The Company’s analysis did not indicate that any of its other long-lived assets were impaired. Refer to footnote 14 for impairment analysis for goodwill and other intangibles that occurred during fiscal year 2019, as a result of certain triggering events being present. +Impairment of Long-lived Assets +The Company, using its best estimates based on reasonable and supportable assumptions and projections, reviews assets for impairment whenever events or changes in circumstances have indicated that the carrying amount of its assets might not be recoverable. Impaired assets are reported at the lower of cost or fair value. +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. Management reviews the adequacy of this accrual quarterly based on historical analyses and anticipated product returns. +39 +Self-funded Insurance +The Company self-funds its domestic employee health plans. The Company contracts with a separate administrative service company to supervise and administer the programs and act as its representative. The Company reduces its risk under this self-funded platform by purchasing stop-loss insurance coverage for high dollar individual claims. In addition, if the aggregate annual claims amount to more than 125 percent of expected claims for the plan year this insurance will also pay those claims amounts exceeding that level. +The Company estimates its exposure for claims incurred but not paid at the end of each reporting period and uses historical claims data supplied by the Company’s broker to estimate its self-funded insurance liability. This liability is subject to a total limitation that varies based on employee enrollment and factors that are established at each annual contract renewal. Actual claims experience may differ from the Company’s estimates. Costs related to the administration of the plan and related claims are expensed as incurred. +Revenue Recognition +ASU 2014-09, Revenue from Contracts with Customers (Topic 606) was adopted effective fiscal year 2019. The primary impact was switching to over-time recognition which accelerated the Company's revenue recognition for in-process inventory and the cumulative impact from adoption is reflected in the Statement of Shareholders' Equity. +Subsequent to the adoption of ASU 2014-09, Revenue from Contracts with Customers (Topic 606) during the year ended June 29, 2019, the first step in its process for revenue recognition is to identify the contract with a customer. A contract is defined as an agreement between two or more parties that creates enforceable rights and obligations. A contract can be written, oral, or implied. The Company generally enters into manufacturing service agreements (“MSA”) with its customers that outlines the terms of the business relationship between the customer and the Company. This includes matters such as warranty, indemnification, transfer of title and risk of loss, liability for excess and obsolete inventory, pricing, payment terms, etc. The Company will also bid on a program-by-program basis for customers in which an executed MSA may not be in place. In these instances, as well as when we have an MSA in place, we receive customer purchase orders for specific quantities and timing of products. As a result, the Company considers its contract with a customer to be the combination of the MSA and the purchase order. The transaction price is fixed and set forth in each purchase order. In the Company's normal course of business, there are no variable pricing components, or material amounts refunded to customers in the form of refunds or rebates. +The Company assesses whether control of the product or services promised under the contract is transferred to the customer at a point in time (shipment) or over time (as we manufacture the product). The Company is first required to evaluate whether its contracts meet the criteria for 'over-time' or 'point-in-time' recognition. The Company has determined that for the majority of its contracts the Company is manufacturing products for which there is no alternative use due to the unique nature of the customer-specific product, IP and other contract restrictions. The Company has an enforceable right to payment including a reasonable profit for performance completed to date with respect to these contracts. As a result, revenue is recognized under these contracts 'over-time' based on the input cost-to-cost method as it better depicts the transfer of control. This input method is based on the ratio of costs incurred to date as compared to the total estimated costs at completion of the performance obligation. For all other contracts that do not meet these criteria, such as manufacturing contracts for which the terms do not provide an enforceable right to payment for performance completed to date, the Company recognizes revenue when it has transferred control of the related manufactured products which generally occurs upon shipment to the customer. Revenue from engineering services is recognized over time as the services are performed. +Shipping and Handling Fees +The Company classifies costs associated with shipping and handling fees as a component of cost of goods sold. Customer billings related to shipping and handling fees are reported as revenue. +Research, Development and Engineering +Research, development and engineering expenses include unreimbursed contract manufacturing costs as well as design and engineering costs associated with the production of contract manufacturing programs. Research, development and engineering costs are expensed as incurred. +Income Taxes +Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the estimated future tax consequences and benefits attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities for a change in tax rates is recognized in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amount that is more likely than not to be realized. +40 +We utilize a two-step approach to recognizing and measuring uncertain tax positions. The first step is to evaluate the tax position for recognition by determining if the weight of available evidence indicates it is more likely than not that the position will be sustained on audit, including resolution of related appeals or litigation processes, if any. The second step is to measure the tax benefit as the largest amount which is more than 50 % likely of being realized upon ultimate settlement. We consider many factors when evaluating and estimating our tax positions and tax benefits, which may require periodic adjustments based on new assessments and changes in estimates and which may not accurately forecast actual outcomes. Our policy is to recognize interest and penalties related to the underpayment of income taxes as a component of income tax provision. To date, we have not incurred charges for interest or penalties in relation to the underpayment of income taxes. The tax years 2004 through the present remain open to examination by the major U.S. taxing jurisdictions to which we are subject. Refer to Note 6 for further discussions. +Derivative Instruments and Hedging Activities +The Company has entered into foreign currency forward contracts and an interest rate swap which are accounted for as cash flow hedges in accordance with ASC 815, Derivatives and Hedging . The effective portion of the gain or loss on the derivative is reported as a component of accumulated other comprehensive income (AOCI) and is reclassified into earnings in the same period in which the underlying hedged transaction affects earnings. The derivative’s effectiveness represents the change in fair value of the hedge that offsets the change in fair value of the hedged item. +The Company uses derivatives to manage the variability of foreign currency fluctuations of expenses in our Mexico facilities. The foreign currency forward contracts and interest rate swaps have terms that are matched to the underlying transactions being hedged. As a result, these transactions fully offset the hedged risk and no ineffectiveness has been recorded. +The Company’s foreign currency forward contracts and interest rate swaps potentially expose the Company to credit risk to the extent the counterparties may be unable to meet the terms of the agreement. The Company minimizes such risk by seeking high quality counterparties. The Company’s counterparties to the foreign currency forward contracts and interest rate swaps are major banking institutions. These institutions do not require collateral for the contracts, and the Company believes that the risk of the counterparties failing to meet their contractual obligations is remote. The Company does not enter into derivative instruments for trading or speculative purposes. +Earnings Per Common Share +Basic earnings per common share is computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is computed by dividing net income by the combination of other potentially dilutive weighted average common shares and the weighted average number of common shares outstanding during the period using the treasury stock method. The computation assumes the proceeds from the exercise of stock options were used to repurchase common shares at the average market price during the period. The computation of diluted earnings per common share does not assume conversion, exercise, or contingent issuance of common stock equivalent shares that would have an anti-dilutive effect on earnings per share. +Foreign Currency Transactions +The functional currency of the Company’s subsidiaries in Mexico and China is the U.S. dollar. Realized foreign currency transaction gains and losses for local currency denominated assets and liabilities are included in cost of goods sold. +Fair Value of Financial Instruments +The carrying values of cash and cash equivalents, accounts receivable, current liabilities, and non current operating lease liability are reflected on the balance sheets at July 3, 2021 and June 27, 2020, reasonably approximate their fair value. The Company had an outstanding balance on the line of credit of $ 90.9 million as of July 3, 2021 and $ 60.1 million as of June 27, 2020, with a carrying value that reasonably approximates the fair value. The Company had an outstanding balance on the term loan of $ 4.2 million as of July 3, 2021 and $ 10.0 million as of June 27, 2020, with a carrying value that reasonably approximates the fair value. The equipment term loan was $ 5.8 million as of July 3, 2021 and $ 0.9 million as of June 27, 2020, with a carrying value that reasonably approximates the fair value. +Share-based Compensation +The Company’s incentive plan may provide for equity and liability awards to employees in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, stock units, performance shares, performance units, and other stock-based or cash-based awards. Compensation cost is recognized on a straight-line basis over the requisite employee service period, which is generally the vesting period, and is included in cost of goods sold, research, development and engineering, and selling, general, and administrative expenses. Share-based compensation is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on historical experience and future expectations. +41 +Newly Adopted and Recent Accounting Pronouncements +In January 2021, the Financial Accounting Standards Board (FASB) issued Accounting Standard Update (ASU) 2021-01, Reference Rate Reform (Topic 848) to identify alternative reference rates that are more observable or transaction based and less susceptible to manipulation. The Company is currently assessing the effects on its consolidated financial statements, and if it will elect this optional standard. +In March of 2020, the FASB issued ASU 2020-03, Codification Improvements to Financial Instruments, which clarifies specific issues raised by stakeholders. Specifically, the ASU clarifies the following: 1) that all entities are required to provide the fair value option disclosures in ASC 825, Financial Instruments 2) clarifies that the portfolio exception in ASC 820, Fair Value Measurement, applies to nonfinancial items accounted for as derivatives under ASC 815, Derivatives and Hedging; 3) clarifies that for purposes of measuring expected credit losses on a net investment in a lease in accordance with ASC 326, Financial Instruments - Credit Losses, the lease term determined in accordance with ASC 842, Leases, should be used as the contractual term; 4) clarifies that when an entity regains control of financial assets sold, it should recognize an allowance for credit losses in accordance with ASC 326; and 5) aligns the disclosure requirements for debt securities in ASC 320, Investments - Debt Securities, with the corresponding requirements for depository and lending institutions in ASC 942, Financial Services - Depository and Lending. The amendments in the ASU have various effective dates and transition requirements which are dependent on timing of adoption of ASU 2016-13. The Company is currently assessing the effects on its consolidated financial statements, and it intends to adopt the guidance as they become effective. +In December 2019, the FASB issued ASU 2019-12, Simplifying the Accounting for Income Taxes (Topic 740), which modifies certain provisions of ASC 740, Income Taxes, in an effort to reduce the complexity of accounting for income taxes. ASU 2019-12 is effective for us the first quarter of fiscal year 2022. We are currently evaluating the effects and do not believe this standard will have a material impact on our consolidated financial position, results of operations, or cash flows. +In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” and also issued subsequent amendments to the initial guidance: ASU 2018-19, ASU 2019-04 and ASU 2019-05, which replaces the existing incurred loss impairment model with an expected credit loss model and requires a financial asset measured at amortized cost to be presented at the net amount expected to be collected. The guidance is effective for the Company beginning in the first quarter of fiscal year 2024 with early adoption permitted. The Company is currently assessing the impact on its consolidated financial statements, and it intends to adopt the guidance when it becomes effective in the first quarter of fiscal year 2024. +Fiscal Year +The Company operates on a 52/53 week fiscal year. Fiscal years end on the Saturday nearest June 30. As such, fiscal years 2021, 2020, and 2019, ended on July 3, 2021, June 27, 2020, and June 29, 2019, respectively. Fiscal year 2021 was a 53 week year. Fiscal years 2020 and 2019 were 52 week years. +2. INVENTORIES +Total inventory as of July 3, 2021 is $ 137.3 million which is net of $ 14.9 million of reserves, customer payments, and customer deposits compared to $ 115.0 million which is net of $ 17.3 million in reserves, customer payments, and customer deposits as of June 27, 2020. Substantially all of the Company’s inventory balances are raw materials. +3. PROPERTY, PLANT AND EQUIPMENT +Property, plant and equipment consists of the following: +Life July 3, 2021 June 27, 2020 +(in years) (in thousands) +Land — $ 4,034 $ 4,034 +Buildings and improvements 3 to 30 25,513 23,444 +Equipment 1 to 10 77,509 72,151 +Furniture and fixtures 3 to 5 5,271 4,883 +Total Property, Plant and Equipment 112,327 104,512 +Accumulated depreciation ( 76,592 ) ( 72,748 ) +Property, Plant and Equipment, net $ 35,735 $ 31,764 +42 +4. LONG-TERM DEBT +On August 14, 2020, the Company entered into a loan agreement with Bank of America. The Loan Agreement replaces the Company’s prior amended and restated credit agreement, as amended, with Wells Fargo Bank. The Loan Agreement provides for a five-year asset-based senior secured revolving credit facility of up to $ 93 million, maturing on August 14, 2025. As of July 3, 2021, the Company had an outstanding balance under the asset-based revolving credit facility of $ 90.9 million, $ 0.3 million in outstanding letters of credit and $ 2.1 million available for future borrowings. +As of June 27, 2020, the Company had an outstanding balance under the credit facility with Wells Fargo Bank of $ 60.1 million, $ 0.4 million in outstanding letters of credit and $ 4.5 million available for future borrowings. The Company had an outstanding balance of $ 10.0 million under the term loan with Wells Fargo Bank as of June 27, 2020. +On August 14, 2020, the Company also entered into a $ 5.0 million equipment financing facility with Bank of America relating to the Company’s existing U.S. manufacturing equipment that bears interest at 4.85% and matures on August 14, 2025. Under this loan agreement, equal monthly payments of approximately $ 94,000 commenced on September 14, 2020 and will continue through the maturity of the equipment financing facility on August 14, 2025. As of July 3, 2021, the Company had an outstanding balance of $ 4.2 million. As of June 27, 2020, the Company had an outstanding balance of $ 0.9 million under the Wells Fargo Bank equipment term loan agreement. +Generally, the interest rate applicable to loans under the Bank of America loan agreement are, at the Company’s option: (i)(A) the base rate which is the highest of (1) the prime rate for the applicable day (as such rate is determined from time to time by the Bank), (2) the federal funds rate for the applicable day plus 0.50%, and (3) LIBOR for a 30-day interest period as of the applicable day plus 1.00% (provided that in no event shall the base rate be less than zero), plus the applicable interest margin for base rate loans; and (B) LIBOR rate for an applicable interest period (provided that in no event shall the LIBOR rate be less than 0.50%), plus the applicable interest margin for LIBOR rate loans. Depending on average daily excess borrowing availability over applicable periods under the Credit Facility, applicable interest margins on: (x) base rate loans are 1.25-1.75%; and (y) LIBOR rate loans are 2.25-2.75%, resetting on a quarterly basis. If there is an event of default under the loan agreement, all loans and other obligations will bear interest at a rate of an additional 2.00% on the otherwise applicable interest rates. In addition to interest charges, the Company is required to pay a fee of 0.25% per annum on the unused portion of the Credit Facility, monthly in arrears. +Under the loan agreement with Bank of America, the asset-based revolving credit facility bears interest at LIBOR plus 2.5 %, as elected by the Company. +On November 24, 2020, the Company entered into a $ 6.0 million equipment financing facility related to the Company’s existing manufacturing equipment that bears interest at 5.52% and matures on April 24, 2026. Under this loan agreement, equal monthly payments of $ 100,000 commenced on May 24, 2021 and will continue through the maturity of the equipment financing facility on April 24, 2026. As of July 3, 2021, the Company had an outstanding balance of $ 5.8 million. +On September 3, 2021, the Company entered into an amendment to the Company's current loan agreement with Bank of America. The amendment increases the Company's current credit facility of $ 93 million to $120 million, subject to the Company's borrowing base, maturing on September 3, 2026. +The interest rates on outstanding debt as of July 3, 2021 range from 3.25 % - 5.52 % compared to 2.17 % - 2.18 % as of June 27, 2020. +Debt maturities as of July 3, 2021 for the next five years are as follows (in thousands): +Fiscal Years Ending Amount +2022 $ 2,143 +2023 2,190 +2024 2,239 +2025 2,290 +2026 92,074 +Total debt $ 100,936 +Unamortized debt issuance costs ( 525 ) +Long-term debt, net of debt issuance costs $ 100,411 +43 +The Company must comply with certain financial covenants, including a fixed charge coverage ratio and a cash flow leverage ratio. The credit agreement requires the Company to grant certain inspection rights to Bank of America, limit or restrict the Company’s cash management; limit or restrict the ability of the Company to incur additional liens, make acquisitions or investments, incur additional indebtedness, engage in mergers, consolidations, liquidations, dissolutions, or dispositions, pay dividends or other restricted payments, prepay certain indebtedness, engage in transactions with affiliates, and use proceeds. The Company was in compliance with all financial covenants as of July 3, 2021. +5. TRADE ACCOUNTS RECEIVABLE PURCHASE PROGRAMS +Sale Programs +The Company has utilized an Account Purchase Agreement with Wells Fargo Bank, N.A. ("WFB") which allowed the Company to sell and assign to WFB and WFB to purchase from Company the accounts receivable of certain Company customers in a maximum aggregate amount outstanding of $ 25.0 million. As of July 3, 2021, the Company had no factored receivables with WFB. +The Company did not sell any accounts receivables during the twelve months ended July 3, 2021. Total accounts receivables sold during the twelve months ended June 27, 2020 was approximately $ 41.4 million. There were no accounts receivables sold and not yet collected as of July 3, 2021 or June 27, 2020. The receivables that were sold were removed from the consolidated balance sheets and the cash received is reflected as cash provided by operating activities in the consolidated statements of cash flows. Cash receipts related to the deferred purchase price from receivables factored by the Company is reflected as cash provided by investing activities. +6. INCOME TAXES +Income tax benefit consists of the following: +Fiscal Year Ended +July 3, 2021 June 27, 2020 June 29, 2019 +(in thousands) +Current income tax benefit: +United States $ 1,416 $ 365 $ ( 537 ) +Foreign 1,098 154 895 +2,514 519 358 +Deferred income tax benefit: +United States ( 858 ) ( 1,850 ) ( 910 ) +Foreign ( 84 ) 892 ( 206 ) +( 942 ) ( 958 ) ( 1,116 ) +Total income tax provision (benefit) $ 1,572 $ ( 439 ) $ ( 758 ) +The Company has gross tax credit carryforwards of approximately $ 6.1 million at July 3, 2021 consisting of federal research and development (R&D) tax credits, and approximately $ 1.9 million of net operating loss carryovers in China which expire in fiscal years 2025 and 2026. +Management has reviewed all deferred tax assets for purposes of determining whether or not a valuation allowance may be required. A valuation allowance against deferred tax assets is required if it is more likely than not that some of the deferred tax assets will not be realized. Based upon the Company’s profitability, forecasted income, and evaluation of all other positive and negative evidence, management determined that it is more likely than not that the deferred tax assets will be realized. +On January 27, 2021, the Company received official notice from the Vietnamese tax authorities, confirming tax benefits awarded related to the Company’s principal product line in Vietnam (the “Tax Holiday”). Under the Tax Holiday, the tax rate applied to income derived from this product line will be zero percent for four years beginning with fiscal year 2021, then five percent for nine years, then ten percent for one year (as opposed to the normal twenty percent Vietnamese statutory rate). Consequently, Management has revalued its net operating loss in Vietnam at the zero percent Tax Holiday rate, as the net operating loss carryovers are projected to expire before the end of the Tax Holiday. The Company eliminated the deferred tax assets attributable to the Vietnam net operating loss carryover ($0.2 million) in the third quarter of fiscal year 2021. +The Company evaluated tax law changes and regulatory guidance issued in fiscal year 2021. Such changes and regulations include guidance under Sec. 162(m), Sec. 245A, Sec. 951A, foreign tax credits, and rules relating to consolidated NOL carryback claims. The Company evaluated the ongoing impact of these law and regulatory changes, and which did not have a material impact on its provision for income taxes. +Subsequent to the end of the fiscal year ending June 27, 2020, the Treasury Department issued final regulations applicable to the Company’s position with respect to the U.S. taxability of foreign earnings under the global intangible low taxed income +44 +(also known as “GILTI”) regime and the deductibility of interest expense under IRC Section 163(j). These regulations did not have a material impact to the Company's income tax positions. +On March 27, 2020, the Coronavirus Aid, Relief, and Economic Security Act (CARES Act) was enacted in response to the COVID-19 pandemic. The CARES Act, among other things, permits net operating loss (NOL) carryovers and carrybacks to offset 100% of taxable income for taxable years beginning before 2021. In addition, the CARES Act allows NOLs incurred in 2018, 2019, and 2020 to be carried back to each of the five preceding taxable years to generate a refund of previously paid income taxes. The Company does not expect that the NOL carryback provision of the CARES Act will result in a material cash benefit. In addition, the CARES Act contains modifications on the limitation of business interest for tax years beginning in 2019 and 2020. The modifications to Section 163(j) increase the allowable business interest deduction from 30% of adjusted taxable income to 50% of adjusted taxable income. This modification increased the allowable interest expense deduction of the Company, resulting in less taxable income for fiscal year 2020, but did not have a material impact on the fiscal year 2021 provision for income taxes. Also, under the CARES Act, AMT credits not previously refunded for the 2018 tax year are refundable in the 2019 taxable year rather than in years 2019-2021, and taxpayers can elect to claim 100% of the AMT credits in the first taxable year beginning in 2018 by applying for a tentative refund claim on or before December 31, 2020. The Company has made this election by applying for a tentative refund claim. The Company took advantage of the deferred payment payroll taxes provision, resulting in decreased deductible payroll tax payments, and increased taxable income, in fiscal years 2020 and 2021. Similarly, other aspects of the CARES Act did not have a material impact on the Company’s consolidated financial position, results of operations, or cash flows. +In future years, repatriations of cash will generally be tax-free in the U.S. However, withholding taxes in China may still apply to any such future repatriations. Management has not changed its indefinite investment assertions regarding to the portion of accumulated earnings and profits in China that may be repatriated in the future. Accordingly, management estimates that future repatriations of cash from China may result in approximately $ 0.8 million of withholding tax. There would be no offsetting foreign tax credits in the U.S. and as such, this potential liability is a direct cost associated with actual repatriations. Withholding taxes will not apply to future repatriations from Mexico or Vietnam. +The Company expects to repatriate a portion of its foreign earnings based on increased net sales growth driving additional capital requirements domestically, cash requirements for potential acquisitions and to implement certain tax strategies. The Company expects to repatriate approximately $ 7.5 million from China, in the future. All other unremitted foreign earnings are expected to remain permanently reinvested for planned fixed assets purchases and improvements in foreign locations. +45 +The Company’s effective tax rate differs from the federal tax rate as follows: +Fiscal Year Ended +July 3, 2021 June 27, 2020 June 29, 2019 +(in thousands) +Federal income tax provision (benefit) at statutory rates $ 1,242 $ 907 $ ( 1,836 ) +State income taxes, net of federal tax effect 76 90 ( 158 ) +Foreign tax rate differences ( 36 ) 336 251 +Tax rate change 184 — — +Provisional transition tax on accumulated foreign earnings — — ( 384 ) +Effect of income tax credits ( 413 ) ( 310 ) ( 861 ) +Previously unrecognized tax benefits ( 296 ) ( 1,345 ) — +Effect of repatriation of foreign earnings, net ( 61 ) — ( 42 ) +Goodwill write-off — — 1,726 +Global Intangible Low-Taxed Income (GILTI) tax 34 — 150 +Provision to return reconciliation 50 ( 241 ) 630 +Equity compensation shortfall 572 — — +Other 220 124 ( 234 ) +Income tax provision (benefit) $ 1,572 $ ( 439 ) $ ( 758 ) +The domestic and foreign components of income (loss) before income taxes were: +Fiscal Year Ended +July 3, 2021 June 27, 2020 June 29, 2019 +(in thousands) +Domestic $ 2,839 $ 1,142 $ ( 12,220 ) +Foreign 3,074 3,177 3,480 +Income (loss) before income taxes $ 5,913 $ 4,319 $ ( 8,740 ) +46 +Deferred income tax assets and liabilities consist of the following at: +July 3, 2021 June 27, 2020 +(in thousands) +Deferred tax assets: +Net operating loss $ 465 $ 184 +Tax credit carryforwards, net 3,581 5,961 +Inventory 1,190 1,426 +Identifiable intangibles 432 493 +Accruals 3,132 2,847 +Mart-to-market adjustments — 415 +ASC 606 deferred costs 4,670 1,943 +Lease liabilities 2,909 3,201 +Other 385 212 +Deferred income tax assets $ 16,764 $ 16,682 +Deferred tax liabilities: +Accrued withholding tax - unremitted earnings ( 754 ) ( 820 ) +Fixed assets ( 794 ) ( 566 ) +Right-of-use assets ( 2,930 ) ( 3,290 ) +Mart-to-market adjustments ( 816 ) — +ASC 606 accelerated revenue ( 672 ) ( 1,344 ) +Other ( 1,142 ) ( 718 ) +Deferred income tax liabilities $ ( 7,108 ) $ ( 6,738 ) +Net deferred income tax assets $ 9,656 $ 9,944 +Balance sheet caption reported in: +Long-term deferred income tax asset $ 9,656 $ 10,178 +Long-term deferred income tax liability — ( 234 ) +Net deferred income tax asset $ 9,656 $ 9,944 +Uncertain Tax Positions: +The Company has R&D tax credits that approximate $ 6.1 million that have 20 -year carryforwards before expiring. The Company’s R&D tax credits expire in various fiscal years from 2034 to 2041. +As of July 3, 2021, the Company had unrecognized tax benefits of $ 2.6 million related to its gross R&D tax credits. The unrecognized tax benefits relate to certain R&D tax credits generated from 2004 to 2021. +A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: +Fiscal Year Ended +July 3, 2021 June 27, 2020 June 29, 2019 +(in thousands) +Beginning Balance $ 2,863 $ 4,099 $ 4,011 +Additions based on tax positions related to the current year 193 109 88 +Adjustment to prior year tax positions 2,102 — — +Lapse of statute of limitations ( 295 ) ( 1,345 ) — +Ending Balance $ 4,863 $ 2,863 $ 4,099 +Of the $ 4.863 million of unrecognized tax benefits at the end of fiscal year 2021, $ 2.6 million, if recognized, would reduce the effective tax rate. Management does not anticipate any material changes to this amount during the next 12 months. +The Company recognizes interest accrued related to unrecognized tax benefits and penalties in its income tax provision. The Company has not recognized any interest or penalties in the fiscal years presented in these financial statements. The Company is subject to income tax in the U.S. federal jurisdiction, various state jurisdictions, Mexico, China and Vietnam. Certain years remain subject to examination but there are currently no ongoing exams in any taxing jurisdictions. +47 +7. EARNINGS PER SHARE +Basic earnings per share (EPS) is calculated by dividing net income (the numerator) by the weighted-average number of common shares outstanding (the denominator) during the period. Diluted EPS is computed by including both the weighted-average number of shares outstanding and any dilutive common share equivalents in the denominator. The following table presents a reconciliation of the denominator and the number of antidilutive common share awards that were not included in the diluted earnings per share calculation. These antidilutive securities occur when equity awards outstanding have an option price greater than the average market price for the period: +Fiscal Year Ended +(in thousands, except per share information) +July 3, 2021 June 27, 2020 June 29, 2019 +Net income (loss) $ 4,341 $ 4,758 $ ( 7,982 ) +Weighted average shares outstanding– basic 10,760 10,760 10,760 +Effect of dilutive common stock awards 286 56 — +Weighted average shares outstanding – diluted 11,046 10,816 10,760 +Net income (loss) per share – basic $ 0.40 $ 0.44 $ ( 0.74 ) +Net income (loss) per share – diluted $ 0.39 $ 0.44 $ ( 0.74 ) +Antidilutive SARs not included in diluted earnings per share 314 720 985 +8. STOCK OPTION AND BENEFIT PLANS +The Company’s incentive plan provides for equity and liability awards to employees and non-employee directors in the form of stock options, stock appreciation rights (SARs), restricted stock, restricted stock units, stock awards, stock units, performance shares, performance units, and other stock-based or cash-based awards. Compensation cost is recognized on a straight-line basis over the requisite employee service period, which is generally the vesting period, and is recorded as employee compensation expense in cost of goods sold, research, development and engineering, and selling, general and administrative expenses. Share-based compensation is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on historical experience and future expectations. +In addition to service conditions, these SARs contain a performance condition. The additional performance condition is based upon the achievement of Return on Invested Capital (ROIC) goals relative to a peer group. All awards with performance conditions are measured over the vesting period and are charged to compensation expense over the requisite service period based on the number of shares expected to vest. The SARs cliff vest after a three-year period from date of grant and expire five years from date of grant. +On July 23, 2020, the Company granted 155,000 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $ 6.94 and a grant date fair value of $ 2.32 . As of July 3, 2021, 150,000 remain outstanding. The grant date fair value for the awards granted during fiscal year 2021, were estimated using the Black Scholes option valuation method with the following weighted average assumptions as of July 23, 2020: +Fiscal Year 2021 +July 23, 2020 +Expected dividend yield — % +Risk – free interest rate 0.17 % +Expected volatility 42.85 % +Expected life 4.00 +48 +On July 26, 2019, the Company granted 175,000 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $ 4.93 and a grant date fair value of $ 1.23 . As of July 3, 2021, 140,000 remain outstanding. The grant date fair value for the awards granted during fiscal year 2020, were estimated using the Black Scholes option valuation method with the following weighted average assumptions as of July 26, 2019: +Fiscal Year 2020 +July 26, 2019 +Expected dividend yield — % +Risk – free interest rate 1.54 % +Expected volatility 28.50 % +Expected life 4.00 +On July 27, 2018, the Company granted 161,250 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $ 8.17 and a grant date fair value of $ 2.27 . As of July 3, 2021, 116,250 remain outstanding. The grant date fair value for the awards granted during fiscal year 2019, were estimated using the Black Scholes option valuation method with the following weighted average assumptions as of July 27, 2018: +Fiscal Year 2019 +July 27, 2018 +Expected dividend yield — % +Risk – free interest rate 2.80 % +Expected volatility 29.75 % +Expected life 4.00 +Subsequent to July 3, 2021, the Company granted 165,000 SARs with a strike price of $ 7.17 and a grant date fair value of $ 2.73 . +Share-based compensation expense is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on the Company’s historical experience and future expectations. This forfeiture rate will be revised, if necessary, in subsequent periods if actual forfeitures differ from the amount estimated. Share-based compensation expense for fiscal years ended July 3, 2021, June 27, 2020 and June 29, 2019 was $ 0.2 million, $ 0.3 million and $ 0.4 million, respectively. +The Black-Scholes option valuation model is used by the Company for estimating the fair value of SARs. Option valuation models require the input of highly subjective assumptions, particularly for the expected term and expected stock price volatility. Changes in these assumptions can materially affect the fair value estimates. +There were 20,000 SARs exercised with an immaterial amount of intrinsic value in fiscal year 2021. There were no SARs exercised during fiscal year 2020 or 2019. +As of July 3, 2021, total unrecognized compensation expense related to nonvested share-based compensation arrangements was approximately $ 0.3 million. This expense is expected to be recognized over a weighted-average period of 1.81 years. +49 +The following table summarizes the Company’s Options and SARs activity for all plans from July 1, 2018 through July 3, 2021: +SARs +Available +For Grant SARs +Outstanding Aggregate +Intrinsic +Value (in +thousands) Weighted +Average +Exercise +Price Weighted +Average +Remaining +Contractual +Life (in +years) +Balances, July 1, 2018 404,335 1,074,999 $ 79 $ 8.90 2.3 +Shares authorized — — +SARs granted ( 161,250 ) 161,250 8.17 +SARs forfeited 250,833 ( 250,833 ) 10.59 +SARs exercised — — — — +Balances June 30, 2019 493,918 985,416 $ — $ 8.35 1.7 +Shares authorized — — +SARs granted ( 175,000 ) 175,000 4.93 +SARs forfeited 290,833 ( 290,833 ) 7.71 +SARs exercised — — — — +Balances, June 27, 2020 609,751 869,583 $ — $ 7.87 1.9 +Shares authorized — — +SARs granted ( 155,000 ) 155,000 6.94 +SARs forfeited 213,333 ( 213,333 ) 9.88 +SARs exercised 20,000 ( 20,000 ) — 7.72 +Balances, July 3, 2021 688,084 791,250 $ — $ 7.15 1.9 +Exercisable at July 3, 2021 385,000 $ — $ 7.73 0.6 +Additional information regarding SARs outstanding and exercisable as of July 3, 2021, is as follows: +Range of +Exercise Prices Number Outstanding Weighted Avg. +Remaining +Contractual Life (yrs.) Weighted Avg. +Exercise Price Number +Exercisable Weighted +Avg. Exercise +Price +$4.40 – $7.90 477,500 2.6 $ 6.48 187,500 $ 7.26 +7.91 – 9.91 313,750 0.3 8.17 197,500 8.17 +$4.40 to $11.34 791,250 1.9 $ 7.15 385,000 $ 7.73 +The Company has defined contribution plans available to U.S. employees who have attained age 21. Company contributions to the plans were approximately $ 0.9 million, $ 0.8 million, and $ 0.9 million during fiscal years 2021, 2020 and 2019, respectively. +9. COMMITMENTS AND CONTINGENCIES +Leases : As of July 3, 2021, June 27, 2020 and June 29, 2019, the Company did not have any property and equipment financed under finance leases. Please refer to Note 16 for information regarding operating lease commitments. +Rental expense under operating leases was approximately $ 4.5 million, $ 4.2 million, and $ 5.0 million during fiscal years 2021, 2020 and 2019, respectively. +Warranty Costs : The Company provides warranties on certain product sales, and allowances for estimated warranty costs are recorded during the period of sale. The determination of such allowances requires the Company to make estimates of product return rates and expected costs to repair or to replace the products under warranty. The Company establishes warranty reserves based on historical warranty costs for each product line combined with liability estimates based on the prior twelve months’ sales activities. As of July 3, 2021 and June 27, 2020, the reserve for warranty costs was approximately $ 25,000 and $ 15,000 , respectively. +If actual return rates and/or repair and replacement costs differ significantly from estimates, adjustments to recognize additional cost of sales may be required in future periods. Warranty expense for fiscal years 2021, 2020 and 2019 was related to workmanship claims on certain contract manufacturing products. +50 +Litigation : The Company is party to certain lawsuits or claims in the ordinary course of business. The Company does not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on the financial position, results of operations or cash flow of the Company. +Internal Investigation : During fiscal 2021, the Company’s Audit Committee completed an internal investigation arising from a notification from an employee regarding certain alleged accounting irregularities. In January 2021, the Company determined that improper accounting resulted in an understatement of cost of goods sold and an overstatement of inventories. Subsequent to the matter identified in January 2021, additional inventory accounting errors unrelated to the investigation were also identified by management. The investigation did not result in a restatement of our previously filed financial statements. The Company is cooperating with the Securities and Exchange Commission’s (the “SEC”) inquiries related to the internal investigation. The Company cannot currently form an estimate of any possible loss or range of loss, including any potential monetary penalties; or other remedies potentially imposed by the SEC. +Indemnification Rights : Under the Company’s bylaws, the Company’s directors and officers have certain rights to indemnification by the Company against certain liabilities that may arise by reason of their status or service as directors or officers. The Company maintains director and officer insurance, which may cover certain liabilities arising from its obligation to indemnify its directors and officers and former directors in certain circumstances. +10. DERIVATIVE FINANCIAL INSTRUMENTS +As of July 3, 2021, the Company had outstanding foreign currency forward contracts with a total notional amount of $ 10.6 million. The maturity dates for these contracts and swaps extend through December 2021. As of July 3, 2021, the net amount of unrealized gain expected to be reclassified into earnings within the next 12 months is approximately $ 2.8 million. During the fiscal year ended July 3, 2021, the Company did not enter into any foreign currency forward contracts and settled $ 26.1 million of such contracts. During the fiscal year ended June 27, 2020, the Company entered into $ 23.8 million of foreign currency forward contracts and settled $ 26.7 million of such contracts. During the fiscal year ended June 29, 2019, the Company entered into $ 19.2 million of foreign currency forward contracts and settled $ 25.9 million of such contracts. +Subsequent to July 3, 2021, the Company entered into $ 13.9 million of additional foreign currency forward contracts that extended our hedge position through June 2022. +As of July 3, 2021, the aggregate notional amount of the Company’s outstanding foreign currency contracts along with their unrealized gains (losses) are expected to mature as summarized below (in thousands): +Quarter Ending Notional Contracts and Swaps in MXN Notional Contracts and Swaps in USD Estimated Fair Value +October 2, 2021 $ 146,373 $ 5,502 $ 1,874 +January 1, 2022 $ 137,973 $ 5,129 $ 1,740 +On November 6, 2019, the Company entered into an interest rate swap contract with an effective date of November 6, 2019 and a termination date of September 30, 2022, related to the borrowings outstanding under the term loan with Wells Fargo Bank. This interest rate swap contract was terminated on August 14, 2020 when the Company entered into a loan and security agreement with Bank of America. At date of termination this interest rate swap was in a liability position of $ 148,400 , which will be amortized to interest expense over the original term of the swap. +On November 6, 2019, the Company entered into an interest rate swap contract with an effective date of November 6, 2019 and a termination date of November 1, 2023, related to the borrowings outstanding under the line of credit with Wells Fargo Bank. This interest rate swap contract was terminated on August 14, 2020 when the Company entered into a loan and security agreement with Bank of America. At date of termination this interest rate swap was in a liability position of $ 776,500 , which will be amortized to interest expense over the original term of the swap. +51 +The following table summarizes the fair value of derivative instruments in the Consolidated Balance Sheets as of July 3, 2021 and June 27, 2020 (in thousands): +July 3, 2021 June 27, 2020 +Derivatives Designated as Hedging Instruments Balance Sheet Location Fair Value Fair Value +Foreign currency forward contracts & swaps Other current assets $ 3,614 $ — +Foreign currency forward contracts & swaps Other long-term assets $ — $ 1,097 +Foreign currency forward contracts & swaps Other current liabilities $ — $ ( 1,960 ) +Foreign currency forward contracts & swaps Other long-term liabilities $ — $ ( 17 ) +Interest rate swaps Other current liabilities $ — $ ( 347 ) +Interest rate swaps Other long-term liabilities $ — $ ( 610 ) +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2021 (in thousands): +Derivatives Designated as Hedging Instruments Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) AOCI Balance +as of +June 27, 2020 Effective +Portion +Recorded In +AOCI Effective Portion +Reclassified From +AOCI Into Income AOCI Balance +as of +July 3, 2021 +Forward contracts Cost of sales $ ( 759 ) $ 4,621 $ ( 1,141 ) $ 2,721 +Interest rate swap Interest expense ( 741 ) ( 223 ) 315 ( 649 ) +Total $ ( 1,500 ) $ 4,398 $ ( 826 ) $ 2,072 +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2020 (in thousands): +Derivatives Designated as Hedging Instruments Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) AOCI Balance +as of +June 29, 2019 Effective +Portion +Recorded In +AOCI Effective Portion +Reclassified From +AOCI Into Income AOCI Balance +as of +June 27, 2020 +Forward contracts Cost of sales $ 2,424 $ ( 865 ) $ ( 2,318 ) $ ( 759 ) +Interest rate swap Interest expense 2 ( 782 ) 39 ( 741 ) +Total $ 2,426 $ ( 1,647 ) $ ( 2,279 ) $ ( 1,500 ) +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2019 (in thousands): +Derivatives Designated as Hedging Instruments Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) AOCI Balance +as of +June 30, 2018 Effective +Portion +Recorded In +AOCI Effective Portion +Reclassified From +AOCI Into Income AOCI Balance +as of +June 29, 2019 +Forward contracts & swaps Cost of sales $ ( 988 ) $ 3,332 $ 80 $ 2,424 +Interest rate swap Interest expense 19 2 ( 19 ) 2 +Total $ ( 969 ) $ 3,334 $ 61 $ 2,426 +As of July 3, 2021, the Company does not have any foreign exchange contracts with credit-risk-related contingent features. The Company is subject to the risk of fluctuating interest rates from our line of credit and foreign currency risk resulting from our China operations. The Company does not currently manage these risk exposures by using derivative instruments. +11. FAIR VALUE MEASUREMENTS +The Company has adopted ASC 820, Fair Value Measurements, which defines fair value, establishes a framework for assets and liabilities being measured and reported at fair value and expands disclosures about fair value measurements. There are three levels of fair value hierarchy inputs used to value assets and liabilities which include: Level 1 – inputs are quoted market prices for identical assets or liabilities; Level 2 – inputs other than quoted market prices included in Level 1 that are observable for the asset or liability, either directly or indirectly; and Level 3 – inputs are unobservable inputs for the asset or liability. There have been no changes in the fair value methodologies used at July 3, 2021 and June 27, 2020. +52 +The following table summarizes the fair value of assets (liabilities) of the Company’s derivatives that are required to be measured on a recurring basis as of July 3, 2021 and June 27, 2020 (in thousands): +July 3, 2021 +Level 1 Level 2 Level 3 Total +Fair Value +Financial Assets: +Foreign currency forward contracts $ — $ 3,614 $ — $ 3,614 +June 27, 2020 +Level 1 Level 2 Level 3 Total +Fair Value +Financial Assets: +Foreign currency forward contracts — 1,097 — $ 1,097 +Financial Liabilities: +Interest rate swaps $ — $ ( 957 ) $ — $ ( 957 ) +Foreign currency forward contracts & swaps $ — $ ( 1,977 ) $ — $ ( 1,977 ) +The Company currently has forward contracts to hedge known future cash outflows for expenses denominated in the Mexican peso and had an interest rate swap to mitigate risk associated with certain borrowings under the Company’s debt arrangement. These contracts are measured on a recurring basis based on the foreign currency spot rates and forward rates quoted by banks or foreign currency dealers. These contracts are marked to market using level 2 input criteria every quarter with the unrealized gain or loss, net of tax, reported as a component of shareholders’ equity in accumulated other comprehensive income (loss), as they qualify for hedge accounting. +The carrying values of cash and cash equivalents, accounts receivable, and current liabilities are reflected on the balance sheets at July 3, 2021 and June 27, 2020, reasonably approximate their fair value. +The Company’s long-term debt, which is measured at amortized cost, primarily consists of an asset-based revolving credit facility, lease liability, and equipment loans. These borrowings bear interest at LIBOR plus 2.5% per the loan agreement. Each of these rates is a variable floating rate dependent upon current market conditions and the Company’s current credit risk as discussed in Note 4. +As a result of the determinable market rates for our asset-based revolving credit facility and equipment loans, they are classified within Level 2 of the fair value hierarchy. Further, the carrying value of each of these instruments reasonably approximates their fair value as of July 3, 2021 and June 27, 2020. +53 +12. ENTERPRISE-WIDE DISCLOSURES +Operating segments are defined in ASC Topic 280, Segment Reporting as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker, or decision making group, in deciding how to allocate resources and in assessing performance. The Company’s chief operating decision maker is its Chief Executive Officer. As of July 3, 2021, the Company operates and internally manages a single operating segment, Electronics Manufacturing Services as this is the only discrete financial information that is regularly reviewed by the chief operating decision maker. This segment provides integrated electronic and mechanical engineering, assembly, sourcing and procurement, logistics, and new product testing for our customers. +Products and Services +Of the revenues for the years ended July 3, 2021, June 27, 2020, and June 29, 2019, contract manufacturing sales and services were $ 518.7 million, $ 449.5 million and $ 463.9 million, respectively. Keyboard sales for the years ended July 3, 2021, June 27, 2020, and June 29, 2019 were $ 550 , $ 4,000 and $ 0.1 million, respectively. +Geographic Areas +Net sales and long-lived assets (property, plant, and equipment) by geographic area for the years ended and as of July 3, 2021, June 27, 2020 and June 29, 2019 are summarized in the following table. Net sales set forth below are based on the shipping destination. Long-lived assets information is based on the physical location of the asset and includes property, plant and equipment, net, and operating lease right-of-use assets, net. +Fiscal Year Ended +(in thousands) +2021 2020 2019 +Geographic net sales: +Domestic (U.S.) $ 372,217 $ 338,766 $ 357,341 +Foreign 146,481 110,714 106,703 +Total $ 518,698 $ 449,480 $ 464,044 +Long-lived assets: +United States $ 20,949 $ 21,078 $ 9,658 +Mexico 24,089 20,828 17,781 +Vietnam 5,919 6,567 1,220 +China 523 859 754 +Total $ 51,480 $ 49,332 $ 29,413 +Percentage of net sales made to customers located in the following countries: +Fiscal Year Ended +2021 2020 2019 +United States 72 % 75 % 77 % +China 25 19 19 +Other foreign countries (a) +3 5 3 +Canada — 1 1 +Total 100 % 100 % 100 % +(a) No other individual foreign country accounted for 10% or more of the foreign sales in fiscal years 2021, 2020 or 2019. +54 +Significant Customers +The percentage of net sales to and trade accounts receivables from significant customers were as follows: +Percentage of Net +Sales Fiscal Year Percentage of +Trade Accounts Receivable +Fiscal Year +2021 2020 2019 2021 2020 +Customer A 24 % 18 % 17 % 15 % 14 % +13. QUARTERLY FINANCIAL DATA (Unaudited) +Fiscal Year Ended July 3, 2021 +First +Quarter Second +Quarter Third +Quarter Fourth +Quarter +(in thousands, except per share amounts) +Net sales $ 123,207 $ 128,262 $ 134,600 $ 132,629 +Gross profit 10,015 10,622 11,096 10,306 +Income before income taxes 2,115 1,872 1,556 370 +Net income 1,719 1,580 867 175 +Net income per share - basic $ 0.16 $ 0.15 $ 0.08 $ 0.02 +Net income per share - diluted $ 0.16 $ 0.14 $ 0.08 $ 0.02 +Weighted average shares outstanding +Basic 10,760 10,760 10,760 10,762 +Diluted 11,040 11,385 11,429 11,169 +Fiscal Year Ended June 27, 2020 +First +Quarter Second +Quarter Third +Quarter Fourth +Quarter +(in thousands, except per share amounts) +Net sales $ 105,285 $ 116,722 $ 111,455 $ 116,018 +Gross profit 9,273 8,122 9,248 8,606 +Income before income taxes 1,829 974 1,010 506 +Net income 1,552 824 910 1,472 +Net income per share - basic $ 0.14 $ 0.08 $ 0.08 $ 0.14 +Net income per share - diluted $ 0.14 $ 0.08 $ 0.08 $ 0.14 +Weighted average shares outstanding +Basic 10,760 10,760 10,760 10,760 +Diluted 10,805 10,877 10,885 10,832 +55 +14. GOODWILL AND OTHER INTANGIBLE ASSETS +The Company recorded goodwill in connection with the Ayrshire and Sabre acquisitions resulting primarily from the synergies that resulted from the Company's acquisitions and the assembled workforce. The goodwill is not amortized for financial accounting purposes. +In accordance with accounting guidance on goodwill and other intangible assets, the Company evaluates goodwill for impairment at the reporting unit level annually, and whenever circumstances occur indicating that goodwill might be impaired. Upon adoption of ASU 2017-04, the Company now recognizes an impairment charge (not to exceed the total amount of goodwill allocated to the reporting unit) for the amount by which the carrying amount of a reporting unit exceeds the reporting unit’s fair value. During the third quarter of fiscal year 2019, a goodwill impairment of $ 10.0 million was recognized. +During the third quarter for fiscal year 2019, the Company assessed other finite-lived intangible assets including the Company’s customer relationships and favorable lease agreements due to an indicator of possible impairment being present. As a result of the analysis performed, the Company determined that the carrying value of the customer relationships intangible asset was not recoverable and recorded an impairment for the entire carrying amount during the third quarter of fiscal year 2019. This resulted in an impairment charge related to other intangible assets of $ 2.5 million recognized in the third quarter of fiscal year 2019. The Company’s analysis did not indicate that any of its other long-lived assets were impaired. +During the first quarter of fiscal year 2020, the Company adopted the Accounting Standards Update 2016-02, Leases which supersedes ASC 840 Leases and creates a new topic, ASC 842 Leases. Under ASC 842, any assets or liabilities recognized in accordance with ASC 805 that are related to favorable or unfavorable terms of an operating lease for which an entity is a lessee, the entity should derecognize the asset or liability and commensurately adjust the ROU asset. Refer to footnote 16 for additional disclosure. +As such, the Company derecognized the intangible asset and added the offsetting amount to the ROU asset. Resulting in a reduction of favorable lease agreement intangible of $ 0.7 million, and no adjustment to retained earnings or future P&L impact. +The components of acquired intangible assets are as follows (in thousands): +June 27, 2020 +Amortization Period +in Years Gross Carrying +Amount Accumulated +Amortization Derecognition Favorable Lease per ASC 842 Net Carrying +Amount +Other intangible assets: +Favorable Lease Agreements 4 - 7 2,941 ( 2,284 ) ( 657 ) — +Total $ 2,941 $ ( 2,284 ) $ ( 657 ) $ — +Amortization expense related to intangible assets was approximately $ 0.6 million for the year ended June 29, 2019. +15. REVENUE +Revenue Recognition +The Company specializes in services ranging from product manufacturing to engineering and tooling services. The first step in its process for revenue recognition is to identify the contract with a customer. A contract is defined as an agreement between two or more parties that creates enforceable rights and obligations. A contract can be written, oral, or implied. The Company generally enters into manufacturing service agreements (“MSA”) with its customers that outlines the terms of the business relationship between the customer and the Company. This includes matters such as warranty, indemnification, transfer of title and risk of loss, liability for excess and obsolete inventory, pricing, payment terms, etc. The Company will also bid on a program-by-program basis for customers in which an executed MSA may not be in place. In these instances, as well as when we have an MSA in place, we receive customer purchase orders for specific quantities and timing of products. As a result, the Company considers its contract with a customer to be the combination of the MSA and the purchase order. The transaction price is fixed and set forth in each purchase order. In the Company's normal course of business, there are no variable pricing components, or material amounts refunded to customers in the form of refunds or rebates. +56 +The Company assesses whether control of the product or services promised under the contract is transferred to the customer at a point in time (shipment) or over time (as we manufacture the product). The Company is first required to evaluate whether its contracts meet the criteria for 'over-time' or 'point-in-time' recognition. The Company has determined that for the majority of its contracts the Company is manufacturing products for which there is no alternative use due to the unique nature of the customer-specific product, IP and other contract restrictions. The Company has an enforceable right to payment including a reasonable profit for performance completed to date with respect to these contracts. As a result, revenue is recognized under these contracts 'over-time' based on the input cost-to-cost method as it better depicts the transfer of control. This input method is based on the ratio of costs incurred to date as compared to the total estimated costs at completion of the performance obligation. For all other contracts that do not meet these criteria, such as manufacturing contracts for which the terms do not provide an enforceable right to payment for performance completed to date, the Company recognizes revenue when it has transferred control of the related manufactured products which generally occurs upon shipment to the customer. Revenue from engineering services is recognized over time as the services are performed. +The Company’s typical payment terms are 30 to 45 days and its sales arrangements do not contain any significant financing component for its customers. +The Company generally provides a warranty for workmanship on its manufacturing contracts. Historically, the amount of returns for workmanship issues has been de minimis under the Company’s warranties. +The Company elected to not disclose information about remaining performance obligations as they are part of contracts that that have expected durations of one year or less. +The Company has elected to expense costs to obtain contracts as incurred as these costs are immaterial to the financial statements. +During fiscal 2021, 2020 and 2019, no revenues were recognized from performance obligations satisfied or partially satisfied in previous periods. +Contract Balances +A contract asset is recognized when the Company has recognized revenue, but has not issued an invoice for payment. Contract assets are classified separately on the condensed consolidated balance sheet and transferred to receivables when the right to payment becomes unconditional. +The following table summarizes the activity in the Company’s contract assets during the twelve months ended July 3, 2021 (in thousands): +Contract Assets +Beginning balance, June 27, 2020 +$ 23,753 +Revenue recognized 509,621 +Amounts collected or invoiced ( 508,593 ) +Ending balance, July 3, 2021 +$ 24,781 +The following table summarizes the activity in the Company’s contract assets during the twelve months ended June 27, 2020 (in thousands): +Contract Assets +Beginning balance, June 29, 2019 +22,161 +Revenue recognized 441,405 +Amounts collected or invoiced ( 439,813 ) +Ending balance, June 27, 2020 +$ 23,753 +57 +The Company’s cumulative effect adjustment at July 1, 2018 was $ 11.9 million. Revenue recognized in FY2019 was $ 448.0 million with $ 437.7 million collected or invoiced, resulting in an ending balance of $22.2 million as of June 29, 2019. +Disaggregation of Revenue +The following table presents the Company’s revenue disaggregated for the twelve months ended July 3, 2021 and the twelve months ended June 27, 2020 (in thousands): +Revenue +Recognition July 3, 2021 June 27, 2020 June 29, 2019 +Over-Time $ 509,621 $ 441,405 $ 458,256 +Point-in-Time 9,077 8,075 5,788 +Total $ 518,698 $ 449,480 $ 464,044 +Revenues and associated costs from engineering design, development services and tooling, which are performed under contract of short term durations, are recognized over time as the services are performed. Revenue from engineering design, development +services and tooling represented approximately 5.6 %, 3.3 % and 2.9 % of total revenue in fiscal year 2021, 2020 and 2019, respectively. +16. LEASES +As a result of adopting ASC 842 as of June 30, 2019, the Company recognized an right of use asset of $ 21.4 million, a corresponding lease liability of $ 20.4 million, a reduction in prepaid rent of $0.4 million, a reduction of favorable lease agreement intangible of $0.7 million, and no adjustment to retained earnings or future P&L impact. +The Company has several commitments under operating leases for warehouses, manufacturing facilities, office buildings, and equipment with initial terms that expire at various dates during the next 1 year to 10 years. +The Company has some operating leases that include an extension clause. Management has considered the likelihood of exercising each extension option included and estimated the duration of the extension option, for those leases management determined to be reasonably certain, in calculating the lease term for measurement of the right of use asset and liability. +For operating leases, management assumed a discount rate of 4% - 5.9%. The weighted average discount rate is disclosed in the tables below. +The components of lease expense were as follows as of July 3, 2021 and June 27, 2020 (in thousands): +Year Ended Year Ended +Lease cost Classification July 3, 2021 June 27, 2020 +Operating lease cost Cost of sales $ 4,818 $ 4,511 +Operating lease cost Selling, general and administrative expenses 1,270 1,266 +Total lease cost $ 6,088 $ 5,777 +Fixed lease cost $ 4,943 $ 5,335 +Short-term lease cost $ 1,145 $ 442 +Total lease cost $ 6,088 $ 5,777 +58 +Amounts reported in the Consolidated Balance Sheet as of July 3, 2021 and June 27, 2020 were (in thousands, except weighted average lease term and discount rate): +July 3, 2021 June 27, 2020 +Operating Leases: +Operating lease right of use assets $ 15,745 $ 17,568 +Operating lease liabilities (1) +15,653 17,173 +Weighted-average remaining lease term (in years) +Operating leases 5.95 6.46 +Weighted-average discount rate +Operating leases 4.05 % 4.07 % +(1) For fiscal year 2021 and 2020, the current portion of the total operating lease liabilities is classified under Other Current Liabilities. +Other information related to leases was as follows (in thousands): +July 3, 2021 June 27, 2020 +Cash paid for amounts included in the measurement of lease liabilities: +Operating cash flows from operating leases 4,976 4,237 +Future lease payments under non-cancellable leases as of July 3, 2021 are as follows (in thousands): +Fiscal Years Ending Operating Leases +2022 $ 4,225 +2023 3,140 +2024 2,526 +2025 2,427 +2026 1,865 +Thereafter 4,125 +Total undiscounted lease payments 18,308 +Less: present value discount 2,655 +Total lease liabilities $ 15,653 +Item 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES +None +59 +Item 9A: CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +It is the responsibility of our management to establish, maintain, and monitor disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 (the “Exchange Act”) are recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Additionally, these disclosure controls include controls and procedures that are designed to accumulate and communicate the information required to be disclosed to our Company’s Chief Executive Officer and Chief Financial Officer, allowing for timely decisions regarding required disclosures. +As of the end of the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(f). Based on our assessment, we believe that as of July 3, 2021, the Company’s disclosure controls and procedures are effective based on that criteria. +Management’s Report on Internal Control over Financial Reporting +Our management has the responsibility to establish and maintain adequate internal controls over our financial reporting, as defined in Rule 13a-15(f) under the Securities and Exchange Act of 1934. Our internal controls are designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our external financial statements in accordance with generally accepted accounting principles (GAAP). +Due to inherent limitations of any internal control system, management acknowledges that there are limitations as to the effectiveness of internal controls over financial reporting and therefore recognize that only reasonable assurance can be gained from any internal control system. Accordingly, our internal control system may not detect or prevent material misstatements in our financial statements and projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, we have performed an assessment of the effectiveness of our internal controls over financial reporting as of July 3, 2021. This assessment was based on the criteria established in Internal Control-Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that as of July 3, 2021, the Company’s internal control over financial reporting is effective based on that criteria. +The effectiveness of the Company's internal control over financial reporting as of July 3, 2021 has been audited by BDO USA LLP, an independent registered public accounting firm, as stated in their report which is included herein. +Changes in Internal Control over Financial Reporting +As previously disclosed, in January 2021, the Company determined that improper accounting resulted in an understatement of cost of goods sold and an overstatement of inventory during the fourth quarter of fiscal year 2020 and the first six months of fiscal year 2021. Subsequent to the matter identified in January 2021, additional inventory accounting errors unrelated to the investigation were also identified by management. As a result, we previously disclosed a material weakness in internal control over financial reporting as of December 26, 2020 and April 3, 2021, in our Quarterly Reports on Form 10-Q for such periods. The material weakness related to the design and operating effectiveness of certain controls over the accounting for inventory as well as the Company’s monitoring activities as it pertained to accounting for inventory at its domestic facilities. During the third and fourth quarters of fiscal year 2021, management implemented, and continues to implement, the following actions to remediate the material weakness and help prevent reoccurrence: +• Implemented a control design enhancement by incorporating an additional level of review related to significant balance sheet accounts for each of our production facilities in Arkansas, Minnesota and Mississippi (the “East Locations”); +• implemented additional controls requiring management to (i) analyze certain inventory balances and the related revenue recognized in each period in each of our East Locations, and (ii) review manual journal entries recorded at our East Locations to ensure proper accounting treatment; +• implemented changes in reporting structures for finance and accounting personnel in the Company’s domestic production facilities and East Division; +• provided enhanced training to financial and operational personnel related to accounting principals generally accepted in the United States, with an emphasis in inventory and the ASC 606 revenue recognition standard; +• implementing a system upgrade to simplify the process for determining the cost of inventory items and providing related training to employees regarding the new system functionality; +60 +• continue to provide additional training to control owners performing certain controls over the accounting for inventory; and, +• continue to enhance the design of our monitoring control activities, specifically financial and operational oversight, at each facility. +During the fourth quarter of fiscal year 2021, we completed our testing of operating effectiveness of the remedial actions implemented and found that our controls are designed and operating effectively. As a result, we concluded that the material weakness has been remediated as of July 3, 2021. +Except for the remediation actions with respect to the material weakness described above, there have been no significant changes in our internal controls over financial reporting during our fourth fiscal quarter ended July 3, 2021 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)). +61 +Report of Independent Registered Public Accounting Firm +Shareholders and Board of Directors +Key Tronic Corporation +Spokane Valley, Washington +Opinion on Internal Control over Financial Reporting +We have audited Key Tronic Corporation’s (the “Company’s”) internal control over financial reporting as of July 3, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of July 3, 2021, based on the COSO criteria. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company as of July 3, 2021 and June 27, 2020, the related consolidated statements of income (loss), comprehensive income (loss), shareholders’ equity, and cash flows for each of the three years in the period ended July 3, 2021, and the related notes and schedule and our report dated September 16, 2021 expressed an unqualified opinion thereon. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying “Item 9A, Management’s Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit of internal control over financial reporting in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ BDO USA, LLP +Spokane, Washington +September 16, 2021 +62 +Item 9B: OTHER INFORMATION +None +PART III +Item 10: DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Directors of the Registrant +Information on the nominees for election as Directors of the Company is incorporated by reference from the Company’s definitive proxy statement for the 2021 Annual Meeting of Shareholders to be filed pursuant to Regulation 14A under the Exchange Act no later than 120 days after the end of the Company’s 2021 fiscal year. +Executive Officers of the Registrant +This information is included in a separate item captioned “Executive Officers of the Registrant” in Item 1 of Part 1 of this report pursuant to Instruction G(3) of Form 10-K and Instruction 3 to Item 401(b) of Regulation S-K. +Compliance with Section 16(a) of the Exchange Act: +Information under the caption “Delinquent Section 16(a) Reports” in the Company’s 2021 Proxy Statement is incorporated herein by this reference. +Code of Conduct +The Board of Directors has adopted a written Code of Conduct which applies to its directors and employees, including its executive officers. The Code of Conduct is available on the Company’s website at www.keytronic.com . The Company intends to disclose on its website any amendments to or waivers of the Code of Conduct. +Item 11: EXECUTIVE COMPENSATION +Information appearing under the caption “Executive Compensation” in the Company’s 2021 Proxy Statement is incorporated herein by this reference. +Item 12: SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The following table sets forth the aggregate information for the Company’s equity compensation plans in effect as of July 3, 2021. +EQUITY COMPENSATION PLAN INFORMATION +Plan category Number of securities to +be issued upon exercise +of outstanding options, +warrants, and rights +(a) Weighted-average +exercise price of +outstanding options, +warrants, and rights +(b) Number of securities +remaining available for +future issuance under +equity compensation +plans (excluding +securities reflected in +column (a) +(c) +Equity compensation plans approved by security holders (1) +791,250 $ 7.15 688,084 +Equity compensation plans not approved by security holders — $ — — +Total 791,250 $ 7.15 688,084 +(1) Included are the 1,200,000 shares subject to the 2010 Plan, the issuance of which were approved by the shareholders at the 2010 Annual Meeting. During the 2015 Annual Meeting, an additional 1,000,000 shares were approved. As a result of the shareholder approval, the Company made the decision to amend the cash-settled SARs granted during fiscal year 2010 to stock-settled SARs effective October 21, 2011. +Information under the caption “Beneficial Ownership of Securities” in the Company’s 2021 Proxy Statement is incorporated herein by this reference. +63 +Item 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions” and “Directors’ Independence” in the Company’s 2021 Proxy Statement is incorporated herein by this reference. +Item 14: PRINCIPAL ACCOUNTANT FEES AND SERVICES +Information appearing under the caption “Principal Accountant Fees and Services” in the Company’s 2021 Proxy Statement is incorporated herein by this reference. +PART IV +Item 15: EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +(a) 1. FINANCIAL STATEMENTS +Page in Form 10-K +FINANCIAL STATEMENTS +Report of Independent Registered Public Accounting Firm +31 +Consolidated Balance Sheets +33 +Consolidated Statements of Income (Loss) +34 +Consolidated Statements of Comprehensive Income (Loss) +35 +Consolidated Statements of Cash Flows +36 +Consolidated Statements of Shareholders’ Equity +37 +Notes to Consolidated Financial Statements +3 8 +2. SCHEDULES +II. Consolidated Valuation and Qualifying Accounts +70 +Other schedules are omitted because of the absence of conditions under which they are required, or because required information is given in the financial statements or notes thereto. +64 +3. EXHIBITS +Exhibit No. Description +3.1 +Articles of Incorporation +3.2 +Bylaws, as amended +4.1 +Description of the Compan y ’ s securities +10.1* +Amended and Restated 1990 Stock Option Plan for Non-Employee Directors, as amended, incorporated by reference to the Company’s 1997 Proxy Statement dated October 10, 1997 (Proposal 2) +10.2* +1995 Executive Stock Option Plan, incorporated by reference to the Company’s 1995 Proxy Statement, pages 19-22 (Proposal 3) +10.3* +2000 Employee Stock Option Plan, incorporated by reference to the Exhibits to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.4* +Officers’ Employment Contracts, incorporated by reference to the Company’s 1998 Proxy Statement, pages 10 and 11 +10.5* +Addenda to Officers’ Employment Contracts, incorporated by reference to Exhibits to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.6* +Description of Retention Bonus Plan, incorporated by reference to the Exhibits to the Company’s 10-Q for the quarter ended December 28, 2002 +10.7* +Addenda to Officers’ Employment Contracts, incorporated by reference to Exhibits to the Company’s Form 10-K for the year ended June 29, 2002 +10.8 +Promise to execute a Purchase and Sale Agreement with Key Safety Systems de Mexico, S.A. de C.V., incorporated by reference to the Exhibit to the Company’s Form 8-K filed April 26, 2005 +10.9 +Summary of material terms and conditions of the Purchase and Sale Agreement with Key Safety Systems de Mexico, S.A. de C.V., incorporated by reference to the Exhibit to the Company’s Form 8-K filed June 6, 2005 +10.10* +Summary of Key Tronic Corporation Long Term Incentive Compensation Plan, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed September 27, 2005 +65 +10.11* +Summary of Key Tronic Corporation Incentive Compensation Plan, incorporated by reference to Exhibit 10.23 to the Company’s Form 10-K for the year ended July 2, 2005 +10.12* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2007 and Fiscal Years 2007 – 2009 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 28, 2006 +10.13 +Summary of material terms and conditions of the Purchase and Sale Agreement with Todenko Mexico S.A. de C.V., incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed October 12, 2006 +10.14 +Summary of material terms and conditions of the Purchase and Sale Agreement with Todenko Mexico S.A. de C.V., incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed November 20, 2006 +10.15 +Summary of material terms and conditions of the Sale and Purchase Agreement with Adevco Corporation, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed January 5, 2007 +10.16 +Summary of Second Amendment to Agreement of Sale and Purchase Agreement with Adevco Corporation, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed April 11, 2007 +10.17* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2008 and Fiscal Years 2008-2010 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 27, 2007 +10.18* +Summary of Incentive Compensation Plan Performance Goals and Target payments for Fiscal Year 2009 and Fiscal Years 2009 – 2011 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 24, 2008 +10.19* +Summary of Incentive Compensation Plan Performance Goals and Target payments for Fiscal Year 2010 and Fiscal Years 2010 – 2012 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 23, 2009 +10.20 +Financing Agreement with Wells Fargo Bank, N.A., incorporated by reference to the Exhibits to the Company’s Form 8-K filed on August 24, 2009 +10.21* +2010 Incentive Plan, incorporated by reference to Exhibit 10.36 to the Company’s Form 10-K for the year ended July 3, 2010 +10.22* +Employment Contract with Douglas G. Burkhardt, incorporated by reference to Exhibit 10.37 to the Company’s Form 10-K for the year ended July 3, 2010 +10.23 +Summary of material terms and conditions of the Purchase and Sale Agreement with Autopartes Y Arneses de Mexico S.A. de C.V., incorporated by reference to Exhibit 10.38 to the Company’s Form 10-K for the year ended July 3, 2010 +10.24* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2011 and Fiscal Years 2011 – 2013 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 23, 2010 +10.25* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2012 and Fiscal Years 2012 – 2014 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 2, 2011 +66 +10.26* +Amendment to Employment Contract of Craig D. Gates, dated August 23, 2011; of Ronald F. Klawitter, dated August 23, 2011 and of Douglas G. Burkhardt dated September 6, 2011; incorporated by reference to the Exhibits to the Company’s Form 10-K for the year ended July 2, 2011 filed on September 12, 2011 +10.27 +Second Loan Modification Agreement to the Credit Agreement with Wells Fargo Bank, N.A., incorporated by reference to the Exhibits to the Company’s Form 8-K filed on February 2, 2012 +10.28* +Amendment to Employment Contract of Craig D. Gates, dated May 10, 2012, incorporated by reference to the Exhibits to the Company’s Form 10-Q filed on May 14, 2012 +10.29* +Amendment to Employment Contract of Douglas G. Burkhardt dated May 10, 2012; incorporated by reference to the Exhibits to the Company’s Form 10-Q filed on May 14, 2012 +10.30* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2013 and Fiscal Years 2013 – 2015 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 7, 2012 +10.31* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2014 and Fiscal Years 2014 – 2016 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 6, 2013 +10.32* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2015 and Fiscal Years 2015 – 2017 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 1, 2014 +10.33 +Summary of material terms and conditions of the Stock Purchase Agreement with CDR Manufacturing and Amended and Restated Credit Agreement with Wells Fargo Bank, N. A. incorporated by reference to the Company’s Form 8-K filed September 9, 2014 +10.34* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2016 and Fiscal Years 2016 – 2018 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 30, 2015 +10.35 +First Amendment to Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, incorporated by reference to the Company's Form 8-K filed August 11, 2015 +10.36 +Second Replacement Revolving Line of Credit Note with Wells Fargo Bank, National Association, incorporated by reference to the Company's Form 8-K filed August 11, 2015 +10.37* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2017 and Fiscal Years 2017 – 2019 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 29, 2016 +10.38* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2018 and Fiscal Years 2018 – 2020 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 22, 2017 +10.39 +Announcement of contract awarded with SkyBell Technologies, a global leader in patented Wi-Fi video doorbell technology incorporated by reference to the Company’s Form 8-K filed May 1, 2018 +10.40* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2019 and Fiscal Years 2019 – 2021 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 2, 2018 +67 +10.41 +Announcement of award of $6.7 million following the conclusion of a previously disclosed arbitration proceeding incorporated by reference to the Company's Form 8-K filed September 5, 2018 +10.42 +Announcement that the Company has signed a letter of intent to lease a new facility in Da Nang, Vietnam +10.43* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2020 and Fiscal Years 2020 – 2022 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 30, 2019 +10.44* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2021 and Fiscal Years 2021 – 2023 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 27, 2020 +10.45* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2022 and Fiscal Years 2022 – 2024 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 13, 2021 +10.46 +Loan and Security Agreement, dated August 14, 2020, among the Company, Bank of America, N.A, and certain other parties, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed August 17, 2020 +10.47 +Second Amendment to Loan and Security Agreement, dated September 3, 2021, among the Company, Bank of America, N.A, and certain other parties, incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed September 10, 2021 +21 +Subsidiaries of Registrant, submitted herewith +23.1 +Consent of Independent Registered Public Accounting Firm, submitted herewith +31.1 +Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer, submitted herewith +31.2 +Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer, submitted herewith +32.1 +Section 1350 Certification of Chief Executive Officer, submitted herewith +32.2 +Section 1350 Certification of Chief Financial Officer, submitted herewith +101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. +101.SCH XBRL Taxonomy Extension Schema Document ** +101.CAL XBRL Taxonomy Extension Calculation Linkbase Document ** +101.DEF XBRL Taxonomy Extension Definition Linkbase Document ** +101.LAB XBRL Taxonomy Extension Label Linkbase Document ** +101.PRE XBRL Taxonomy Extension Presentation Linkbase Document ** +68 +104 Cover Page Interactive Data File (formatted as inline XBRL with applicable taxonomy extention information contained in Exhibits 101.INS, 101.SCH, 101.CAL, 101.DEF, 101.LAB and 101.PRE) +* Management contract or compensatory plan or arrangement +69 +SCHEDULE II +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS +FISCAL YEARS ENDED JULY 3, 2021, JUNE 27, 2020, AND JUNE 29, 2019 +Fiscal Year Ended +2021 2020 2019 +(in thousands) +Allowance for Obsolete Inventory +Balance at beginning of year $ 1,968 $ 1,792 $ 1,458 +Provisions 753 136 91 +Dispositions ( 1,296 ) 40 243 +Balance at end of year $ 1,425 $ 1,968 $ 1,792 +Allowance for Doubtful Accounts +Balance at beginning of year $ 609 $ 58 $ — +Provisions (Recovery) 117 551 58 +Write-offs ( 451 ) — — +Balance at end of year $ 275 $ 609 $ 58 +Item 16: FORM 10-K SUMMARY +None +70 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +Dated: September 16, 2021 +KEY TRONIC CORPORATION +By: /s/ Craig D. Gates +Craig D. Gates, President and Chief Executive Officer +(Principal Executive Officer) +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated: +/s/ Craig D. Gates September 16, 2021 +Craig D. Gates Date +Director and President and Chief Executive Officer +(Principal Executive Officer) +/s/ Brett R. Larsen September 16, 2021 +Brett R. Larsen Date +Executive Vice President of Administration, Chief Financial Officer and Treasurer +(Principal Financial Officer) +/s/ Ronald F. Klawitter September 16, 2021 +Ronald F. Klawitter, Director Date +/s/ James R. Bean September 16, 2021 +James R. Bean, Director Date +/s/ Subodh K. Kulkarni September 16, 2021 +Subodh K. Kulkarni, Director Date +/s/ Yacov A. Shamash September 16, 2021 +Yacov A. Shamash, Director Date +/s/ Patrick Sweeney September 16, 2021 +Patrick Sweeney, Director and Chairman of the Board Date +71 \ No newline at end of file diff --git a/raw/filings/0000719733/2021/0000719733-21-000106/filing_metadata.csv b/raw/filings/0000719733/2021/0000719733-21-000106/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..716ff744d9538d57e510273db6ce0d1c83386335 --- /dev/null +++ b/raw/filings/0000719733/2021/0000719733-21-000106/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000719733,KTCC,KEY TRONIC CORP,10-K,2021-09-16,2021-07-03,2021-09-16T20:33:10.000Z,0000719733-21-000106,ktcc-20210703.htm,10-K,19904977,1,1,https://www.sec.gov/Archives/edgar/data/719733/000071973321000106/ktcc-20210703.htm,https://www.sec.gov/Archives/edgar/data/719733/000071973321000106/,2021,2021,1 diff --git a/raw/filings/0000719733/2021/0000719733-21-000106/item1.txt b/raw/filings/0000719733/2021/0000719733-21-000106/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..7ea16afe2ba44d72572ee5492794e0c20eb15695 --- /dev/null +++ b/raw/filings/0000719733/2021/0000719733-21-000106/item1.txt @@ -0,0 +1,78 @@ +Item 1. BUSINESS +Background +Key Tronic Corporation was organized in 1969, as a Washington corporation that locally manufactured computer keyboards. The ability to design, build and deliver a quality product led us to become a leading independent manufacturer of keyboards for computers in the United States. Our fully integrated design, tooling, and automated manufacturing capabilities enabled us to rapidly respond to customers’ needs for keyboards in production quantities worldwide. We supported our sales growth through the development and purchase of international manufacturing facilities. As the computer keyboard market matured with increasing competition from other international providers, we determined that our business could no longer solely rely on keyboard sales. +After assessing market conditions and our strengths and capabilities, we shifted our focus from keyboard manufacturing to contract manufacturing for a wide range of products. Our unique strategic attributes are based on our core strengths of innovative design and engineering expertise in electronics, mechanical engineering, sheet metal fabrication and stamping, and precision plastics combined with high-quality, low cost production, and assembly on an international basis while providing exceptional customer service. These strengths have made our company a strong competitor in the contract manufacturing market. +Our Industry and Strategy +The expansion of the contract manufacturing industry and our acquisitions have allowed us to continue to expand our customer base and the industries that we serve. The increase in new programs represents a growing portion of our revenue and a promising foundation for our future. In keeping with our long-term strategic objectives, we have been successfully building a more diversified customer portfolio, spanning a wider range of industries. We currently offer our customers the following services: integrated electronic and mechanical engineering, precision plastic molding, sheet metal fabrication, printed circuit board (PCB) and complete product assembly, component selection, sourcing and procurement, worldwide logistics, and new product testing and production all at competitive pricing due to our global footprint. We differentiate ourselves from others our size and larger in the contract manufacturing industry by providing vertical integration, a flexible and responsive approach to our customer’s changing supply demand, and complete design engineering support. +We believe that we are well positioned in the contract manufacturing industry to continue the expansion of our customer base and achieve long-term growth. Our unique blend of multinational facilities, vertical integration, centralized management, and core strengths continue to support our growth and our customers’ needs. We continue to focus on controlling operating expenses and leveraging the synergistic capabilities of our world-class facilities in the United States, Mexico, China and Vietnam. This international production capability provides our customers with the benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs, and reduced product fulfillment time. Given our competitive advantages and the growing pressure for new potential customers to move forward with their outsourcing strategies, we feel that we are strongly positioned to win new business in coming periods and grow our revenue and profits. +4 +The contract manufacturing industry is intensely competitive. Although our customer base is growing, we still have less than 1% of the potential global market and our revenue can fluctuate significantly due to reliance on a concentrated base of customers. We are planning for new customer growth in the coming quarters by seeking to secure new programs with new and existing customers, increase our worldwide manufacturing capacity, leverage further our design engineering capabilities and continue to improve our manufacturing and procurement processes and capabilities. Ongoing challenges that we face include but are not limited to the following: continuing to win programs from new and existing customers, balancing capital employed, production capacity and key personnel in support of new customer programs, improving operating efficiencies, controlling costs while developing competitive pricing strategies, and successfully transitioning new program wins to full production. +Customers and Marketing +We provide a mix of manufacturing services for outsourced Original Equipment Manufacturing (OEM) products. We provide the following services: product design, surface mount technologies (SMT) and pin through hole capability for printed circuit board assembly, tool making, precision plastic molding, sheet metal fabrication and painting, liquid injection molding, complex assembly, automated tape winding, prototype design and full product assembly. +Sales of the majority of our products have not historically been seasonal in nature, but may be seasonal in the future if there are changes in the types of products manufactured. Sales can, however, fluctuate significantly between quarters from changes in customers and customer demand due to the concentration of sales generated by our largest customers. +For the fiscal years 2021, 2020 and 2019, the five largest customers in each year accounted for 40%, 40% and 41% of combined total net sales, respectively. We continue to diversify our customer base by adding additional programs and customers. We expect net sales to our five largest customers as a percentage of total net sales to approximate current levels going forward. +The following table represents the only customer that represented 10% or more of total net sales during the last three fiscal years: +Percentage of Net Sales by Fiscal Year +2021 2020 2019 +Customer A 24% 18% 17% +There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +We market our products and services primarily through our direct sales department which is comprised of strategically located field sales people and distributors. We also maintain relationships with several independent sales organizations to assist in marketing our product lines. +Manufacturing +We have continually made investments in developing and expanding a capital equipment base to achieve vertical integration and efficiencies in our manufacturing processes. We have invested significant capital into SMT for volume manufacturing of complex printed circuit board assemblies and in our metal shop providing precision metal stamping, fabricating, and finishing. We also design and develop tooling for injection molding and sheet metal fabrication and manufacture the majority of plastic and sheet metal parts used in the products we manufacture. Additionally, we have equipment to maintain a controlled clean environment for manufacturing processes that require a high level of precise control. +We use a variety of manual and automated assembly processes in our facilities, depending upon product complexity and degree of customization. Some examples of automated processes include component insertion, SMT, selective soldering, flexible robotic assembly, automated storage tape winding, computerized vision system quality inspection, laser turrets, automated switch and key top installation, robotic welding, automated powder coat application, and automated functional testing. +Our engineering expertise and automated manufacturing processes enable us to work closely with our customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. We use computer-aided design techniques and software to assist in preparation of the tool design layout and component placement, to reduce tooling and production costs, improve component and product quality, and enhance turnaround time during product development. +5 +We purchase materials and components for our products from many different suppliers, including both domestic and international sources. We develop close working relationships with our suppliers, many of whom have been supplying products to us for several years. +Research, Development, and Engineering +As part of our long-term strategy, we are committed to supporting our customers by providing research, development, and engineering services. We have seen an increase in the success of providing design support on existing and potential customers in differentiating ourselves. We believe these services allow us to facilitate in optimizing new product designs, and the production processes of our customers’ programs. +Research, development, and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials costs, depreciation, and allocated information technology and facilities costs. +Competition +The market for the products and services we provide is highly competitive. There are numerous competitors in the contract manufacturing industry, many of which have substantially more resources and are more geographically diverse than we are. Some of our competitors have similar international production capabilities, large financial resources and some have substantially greater manufacturing, research and development, and marketing resources. There is also competition from the manufacturing operations of our current and potential customers, who are continually evaluating the merits of manufacturing their products internally versus the advantages of outsourcing. We believe that we can currently compete favorably in these areas primarily on the basis of our international footprint, responsiveness, creativity, vertical production capability, quality, and cost. +Trademarks +Our name and logo are federally registered trademarks, and we believe they are valuable assets of our business. +Employees +We consider our employees to be our primary strength and we make considerable efforts to maintain a well-qualified workforce. Our employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. We regularly provide transportation, medical services, and meals to all of our employees in foreign locations. The Company also has defined contribution plans available to U.S. employees who have attained age 21 and provide group health, life, and disability insurance plans. We also maintain share based compensation plans and other long-term incentive plans for certain employees and outside directors. +As of July 3, 2021 we had 5,450 full-time employees compared to 5,741 on June 27, 2020, and 4,067 on June 29, 2019. Since we can have significant fluctuations in product demand, we seek to maintain flexibility in our workforce by utilizing skilled temporary labor in some of our manufacturing facilities in addition to full-time employees. +Backlog +On July 31, 2021 our order backlog was valued at approximately $303.2 million, compared to approximately $215.3 million on July 25, 2020. The amount of backlog is not necessarily indicative of future sales but can be indicative of trends in expected future sales revenue. Due to the relationships with our customers, we will occasionally allow orders to be canceled or rescheduled and as a result it is not a meaningful indicator of future financial results. If there are canceled or rescheduled orders, we typically negotiate fees to cover the costs we have incurred. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change due to design modifications, customer forecast changes, or other customer requirements. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in Note 12, “Enterprise-Wide Disclosures” of the consolidated financial statements of this Annual Report on Form 10-K and that information is incorporated herein. +Governmental Regulation +Our operations are subject to certain foreign, federal, state and local regulations relating to, among others, environmental, waste management, labor and health and safety matters. We have implemented processes and procedures to help ensure that our operations are in substantial compliance with all applicable regulations. However, material costs and liabilities may arise from these requirements or from new or modified requirements, which could have a material adverse effect on our business and results of operations. +6 +Executive Officers of the Registrant +The table below sets forth the name, current age and current position of our executive officers and other significant employees: +Name Age Positions Held +Executive Officers +Craig D. Gates 62 President and Chief Executive Officer +Brett R. Larsen 48 Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Philip S. Hochberg 59 Executive Vice President of Business Development +Duane D. Mackleit 53 Executive Vice President of Operations +David H. Knaggs 40 Executive Vice President of Quality and Information Systems +Chad T. Orebaugh 50 Vice President of Engineering +Thomas Despres 59 +Vice President of Southwest Operations +Mark Courtney 55 +Vice President of Supply Chain +Executive Officers +CRAIG D. GATES – President and Chief Executive Officer +Mr. Gates, age 62, has been President and Chief Executive officer of the Company since April 2009. Previously, he was Executive Vice President and General Manager from August 2002 to April 2009. He served as Executive Vice President of Marketing, Engineering and Sales from July 1997 to August 2002 and served as Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of 1994. From 1982 to 1991 he held various engineering and management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. Mr. Gates has a Bachelor of Science Degree in Mechanical Engineering and a Masters in Business Administration from the University of Illinois, Urbana. +BRETT R. LARSEN – Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Mr. Larsen, age 48, has served as Executive Vice President of Administration, Chief Financial Officer, and Treasurer since July 2015. Previously, he was Vice President of Finance and Controller from February 2010 to July 2015. He was Chief Financial Officer of FLSmidth Spokane, Inc. from December 2008 to February 2010. From October 2005 through November 2008, Mr. Larsen served as Controller of Key Tronic Corporation. From May 2004 to October 2005, Mr. Larsen served as Manager of Financial Reporting of Key Tronic Corporation. From 2002 to May 2004, Mr. Larsen was an audit manager for the public accounting firm BDO USA, LLP. He also held various auditing and supervisory positions with Grant Thornton LLP from 1997 to 2002. Mr. Larsen has a Bachelor of Science degree in Accounting and a Masters degree in Accounting from Brigham Young University and is a Certified Public Accountant. +PHILIP S. HOCHBERG – Executive Vice President of Business Development +Mr. Hochberg, age 59, has been Executive Vice President of Business Development since July 2012. Prior to this, Mr. Hochberg served as Vice President of Business Development from October 2009 through June 2012. He was Director of Business Development and Program Management from July 2008 to October 2009. Mr. Hochberg served as Director of Business Development from October 2004 to July 2008 and as Director of EMS Sales and Marketing from July 2000 to October 2004. Prior to joining Key Tronic, Mr. Hochberg worked for Quinton Instrument Company as their Director of Marketing and Product Management from 1992 to 2000. From 1988 to 1992, he was employed by SpaceLabs Medical as their Business Development Marketing Manager. Mr. Hochberg has an MBA from the University of British Columbia, a BA in Psychology, with a minor in Business from Washington University in St. Louis. +7 +DUANE D. MACKLEIT – Executive Vice President of Operations +Mr. Mackleit, age 53, has been Executive Vice President of Operations since December 2019. Prior to this, Mr. Mackleit served as Vice President of Program Management since July 2012. He served as Director of Program Management from July 2008 through June 2012. From May 2006 to July 2008 he served as Principal Program Manager. Prior to that, he served as Program Manager from March 2002 to May 2006 and Associate Program Manager from August 2000 to March 2002. Mr. Mackleit has also held several other positions with Key Tronic Corporation. Mr. Mackleit has an AA in Business from Spokane Falls Community College and a BA in Business/Marketing from Eastern Washington University. He also holds a MBA from Gonzaga University. +DAVID H. KNAGGS – Executive Vice President of Quality, Regulatory Affairs and Information Systems +Mr. Knaggs, age 40, has been Executive Vice President of Quality and Information Systems since May 2021. Previously, he was Vice President of Quality and Regulatory Affairs from November 2017 to May 2021. He was Vice President of Quality since October 2016. Before joining Key Tronic, Mr. Knaggs worked at Telect, Inc. from 2008 to 2016 as their Director of Engineering. Prior to that, he worked at Isothermal Systems Research as Lead Systems Engineer from 2003 to 2008. He has a Bachelor of Science degree in Mechanical Engineering with a minor in mathematics from the University of Washington. +CHAD T. OREBAUGH – Vice President of Engineering +Mr. Orebaugh, age 50, has been Vice President of Engineering since April 2017. Prior to this, Mr. Orebaugh served as Director of Engineering since May 2013. From April 2010 to May 2013, he served as Manager of Engineering. From January 2000 to April 2010 he served as Lead Mechanical Engineer. Prior to that, he served as Mechanical Engineer from October 1998 to January 2000 and Associate Mechanical Engineer since October 1997. Mr. Orebaugh holds a BA in Mechanical Engineering from Gonzaga University. +THOMAS DESPRES – Vice President of Southwest Operations +Thomas Despres, age 59, has been Vice President of Southwest Operations since November 2017. Prior to joining Key Tronic, Mr. Despres worked for Gates Corporation as Plant General Manager from July 2017 to November 2017. From 2016 to 2017, he was self-employed and from 2012 to 2016 he was employed by Flextronics as Vice President Global Account Management. He has an MBA from Campbell University, and a BBA, Production Management from Ohio University in Athens. +MARK COURTNEY – Vice President of Supply Chain +Mark Courtney, age 55, has been Vice President of Supply Chain of the company since August 2019. Previously, he served as Purchasing Manager and Director of North American Purchasing from September 2015 to August 2019, and as Supply Chain Manager, ERP and Business Operations Manager for Amphenol Telect from August 2007 to September 2015. From March 2006 to August 2007, he served as Senior Buyer/Planner for Honeywell Specialty Materials and from June 2005 to March 2006 as Purchasing Manager for MRV Communications. From May 2000 to June 2005, he served as a Field and Inside Sales Associate for Arrow Electronics and from October 1991 to May 2000 held various positions at Alesis. +Available Information +Our principal executive offices are located at 4424 North Sullivan Road, Spokane Valley, Washington 99216, and our telephone number is (509) 928-8000. Our website is located at http://www.keytronic.com where filings of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or current reports on Form 8-K are available free of charge after they have been filed with the Securities and Exchange Commission. The information presented on our website currently and in the future is not considered to be part of this document or any document incorporated by reference in this document. +In addition, the SEC maintains an Internet site (at www.sec.gov ) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. +8 \ No newline at end of file diff --git a/raw/filings/0000719733/2021/0000719733-21-000106/item13.txt b/raw/filings/0000719733/2021/0000719733-21-000106/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..bcaabe45f31d5965a78e89eb047d4f401e40623b --- /dev/null +++ b/raw/filings/0000719733/2021/0000719733-21-000106/item13.txt @@ -0,0 +1,2 @@ +Item 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions” and “Directors’ Independence” in the Company’s 2021 Proxy Statement is incorporated herein by this reference. \ No newline at end of file diff --git a/raw/filings/0000719733/2021/0000719733-21-000106/item9a.txt b/raw/filings/0000719733/2021/0000719733-21-000106/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..5287f759bba7fcdce499a77ca33608f8b4eea4d3 --- /dev/null +++ b/raw/filings/0000719733/2021/0000719733-21-000106/item9a.txt @@ -0,0 +1,39 @@ +Item 9A: CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +It is the responsibility of our management to establish, maintain, and monitor disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 (the “Exchange Act”) are recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Additionally, these disclosure controls include controls and procedures that are designed to accumulate and communicate the information required to be disclosed to our Company’s Chief Executive Officer and Chief Financial Officer, allowing for timely decisions regarding required disclosures. +As of the end of the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(f). Based on our assessment, we believe that as of July 3, 2021, the Company’s disclosure controls and procedures are effective based on that criteria. +Management’s Report on Internal Control over Financial Reporting +Our management has the responsibility to establish and maintain adequate internal controls over our financial reporting, as defined in Rule 13a-15(f) under the Securities and Exchange Act of 1934. Our internal controls are designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our external financial statements in accordance with generally accepted accounting principles (GAAP). +Due to inherent limitations of any internal control system, management acknowledges that there are limitations as to the effectiveness of internal controls over financial reporting and therefore recognize that only reasonable assurance can be gained from any internal control system. Accordingly, our internal control system may not detect or prevent material misstatements in our financial statements and projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, we have performed an assessment of the effectiveness of our internal controls over financial reporting as of July 3, 2021. This assessment was based on the criteria established in Internal Control-Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that as of July 3, 2021, the Company’s internal control over financial reporting is effective based on that criteria. +The effectiveness of the Company's internal control over financial reporting as of July 3, 2021 has been audited by BDO USA LLP, an independent registered public accounting firm, as stated in their report which is included herein. +Changes in Internal Control over Financial Reporting +As previously disclosed, in January 2021, the Company determined that improper accounting resulted in an understatement of cost of goods sold and an overstatement of inventory during the fourth quarter of fiscal year 2020 and the first six months of fiscal year 2021. Subsequent to the matter identified in January 2021, additional inventory accounting errors unrelated to the investigation were also identified by management. As a result, we previously disclosed a material weakness in internal control over financial reporting as of December 26, 2020 and April 3, 2021, in our Quarterly Reports on Form 10-Q for such periods. The material weakness related to the design and operating effectiveness of certain controls over the accounting for inventory as well as the Company’s monitoring activities as it pertained to accounting for inventory at its domestic facilities. During the third and fourth quarters of fiscal year 2021, management implemented, and continues to implement, the following actions to remediate the material weakness and help prevent reoccurrence: +• Implemented a control design enhancement by incorporating an additional level of review related to significant balance sheet accounts for each of our production facilities in Arkansas, Minnesota and Mississippi (the “East Locations”); +• implemented additional controls requiring management to (i) analyze certain inventory balances and the related revenue recognized in each period in each of our East Locations, and (ii) review manual journal entries recorded at our East Locations to ensure proper accounting treatment; +• implemented changes in reporting structures for finance and accounting personnel in the Company’s domestic production facilities and East Division; +• provided enhanced training to financial and operational personnel related to accounting principals generally accepted in the United States, with an emphasis in inventory and the ASC 606 revenue recognition standard; +• implementing a system upgrade to simplify the process for determining the cost of inventory items and providing related training to employees regarding the new system functionality; +60 +• continue to provide additional training to control owners performing certain controls over the accounting for inventory; and, +• continue to enhance the design of our monitoring control activities, specifically financial and operational oversight, at each facility. +During the fourth quarter of fiscal year 2021, we completed our testing of operating effectiveness of the remedial actions implemented and found that our controls are designed and operating effectively. As a result, we concluded that the material weakness has been remediated as of July 3, 2021. +Except for the remediation actions with respect to the material weakness described above, there have been no significant changes in our internal controls over financial reporting during our fourth fiscal quarter ended July 3, 2021 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)). +61 +Report of Independent Registered Public Accounting Firm +Shareholders and Board of Directors +Key Tronic Corporation +Spokane Valley, Washington +Opinion on Internal Control over Financial Reporting +We have audited Key Tronic Corporation’s (the “Company’s”) internal control over financial reporting as of July 3, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of July 3, 2021, based on the COSO criteria. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company as of July 3, 2021 and June 27, 2020, the related consolidated statements of income (loss), comprehensive income (loss), shareholders’ equity, and cash flows for each of the three years in the period ended July 3, 2021, and the related notes and schedule and our report dated September 16, 2021 expressed an unqualified opinion thereon. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying “Item 9A, Management’s Report on Internal Control over Financial Reporting”. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit of internal control over financial reporting in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ BDO USA, LLP +Spokane, Washington +September 16, 2021 +62 \ No newline at end of file diff --git a/raw/filings/0000719733/2021/0000719733-21-000106/rp_note.txt b/raw/filings/0000719733/2021/0000719733-21-000106/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000719733/2021/0000719733-21-000106/rpt_disclosure.txt b/raw/filings/0000719733/2021/0000719733-21-000106/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..05efd4920056eacc1b92160645acd90e1115896e --- /dev/null +++ b/raw/filings/0000719733/2021/0000719733-21-000106/rpt_disclosure.txt @@ -0,0 +1,7 @@ +Related Person Transactions +In April 2007, the Board of Directors adopted a written policy and procedures for the approval or ratification of Interested Transactions with Related Parties. The policy and procedures supplement the Company’s Code of Conduct. The policy defines an “Interested Transaction” as any transaction, arrangement or relationship or series of similar transactions, arrangements or relationships (including any indebtedness or guarantee of indebtedness) in which (1) the aggregate amount involved will or may be expected to exceed $120,000 in any calendar year, (2) the Company is a participant, and (3) any Related Party has or will have a direct or indirect interest (other than solely as a result of being a director or a less than 10 percent beneficial owner of another entity). +The policy defines a “Related Party” as any (a) person who is or was (since the beginning of the last fiscal year for which the Company has filed a Form 10-K and proxy statement, even if they do not presently serve in that role) an executive officer, director or nominee for election as a director, (b) greater than 5 percent beneficial owner of the Company’s Common Stock, or (c) immediate family member of any of the foregoing. Immediate family member includes a person’s spouse, parents, stepparents, children, stepchildren, siblings, mothers- and fathers-in-law, sons- and daughters-in-law, and brothers- and sisters-in-law and anyone residing in such person’s home (other than a tenant or employee). +The Audit Committee is responsible for review, approval, ratification or disapproval of Interested Transactions. In determining whether to approve or ratify an Interested Transaction, the Committee will take into account, among other factors it deems appropriate, whether the Interested Transaction is on terms no less favorable than terms generally available to an unaffiliated third party under the same or similar circumstances and the extent of the Related Party’s interest in the Transaction. +During fiscal year 2022, the Company purchased surface mount technology inspection equipment and raw materials from CyberOptics. The purchases by the Company during fiscal year 2022 totaled $382,000. These transactions were conducted at arm’s length in the ordinary course of business of the Company and CyberOptics, and the terms of purchase were no more favorable to the Company than purchases by unaffiliated parties from CyberOptics. +During the fiscal year 2021, the Company had no transactions with CyberOptics or any other Interested Transactions required to be disclosed pursuant to the SEC’s related persons disclosure. +8 \ No newline at end of file diff --git a/raw/filings/0000719733/2022/0000719733-22-000063/filing.txt b/raw/filings/0000719733/2022/0000719733-22-000063/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..0bd443ef05647b15995f1c13bf2aef3d10f120c6 --- /dev/null +++ b/raw/filings/0000719733/2022/0000719733-22-000063/filing.txt @@ -0,0 +1,1434 @@ +ktcc-20220702 +false 2022 FY --06-27 0000719733 10,761,871 63.7 12 275 — — 25,000 25,000 10,762 10,762 10,762 10,762 3 30 1 10 3 5 4.40 7.90 7.91 9.91 4.40 9.91 0000719733 2021-07-04 2022-07-02 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REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE PERIOD FROM TO +Commission File Number 0-11559 +____________________________________________________________ +KEY TRONIC CORP ORATION +(Exact name of registrant as specified in its charter) +____________________________________________________________ +Washington 91-0849125 +(State or other jurisdiction of +Incorporation or organization) (I.R.S. Employer +Identification No.) +4424 North Sullivan Road Spokane Valley, Washington 99216 +(Address of principal executive offices) (Zip Code) +( 509 ) 928-8000 +(Registrant’s telephone number, including area code) +N/A +(Former name, former address and former fiscal year, if changed since last report) +____________________________________________________________ +Securities Registered Pursuant to Section 12(b) of the Act: +Title of each class Trading Symbol Name of each exchange on which registered +Common stock, no par value KTCC The NASDAQ Stock Market LLC +Securities Registered Pursuant to Section 12(g) of the Act: None +____________________________________________________________ +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ☐ No ☒ +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulations S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. +(Check one): +Large accelerated filer ☐ Accelerated filer ☒ +Non-accelerated filer +☐ +Smaller reporting company ☒ +Emerging growth company ☐ +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ +Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ +State the aggregate market value of the voting and non-voting common equity held by non affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. +As of December 31, 2021, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $ 63.7 million based on the closing price as reported on the NASDAQ. +Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: 10,761,871 shares of common stock were outstanding as of September 9, 2022. +____________________________________________________________ +Documents Incorporated by Reference: +Certain information is incorporated into Part III of this report by reference to the Proxy Statement for the registrant’s 2022 annual meeting of stockholders to be filed with the Securities and Exchange Commission pursuant to Regulation 14A not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. +KEY TRONIC CORPORATION +2022 FORM 10-K +TABLE OF CONTENTS +Page No. +PART I +Item 1. +Business +4 +Item 1A. +Risk Factors +8 +Item 1B. +Unresolved Staff Comments +16 +Item 2. +Properties +16 +Item 3. +Legal Proceedings +17 +Item 4. +Mine Safety Disclosures +17 +PART II +Item 5. +Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities +17 +Item 6. +[Reserved] +19 +Item 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +19 +Item 7A. +Quantitative and Qualitative Disclosures about Market Risk +26 +Item 8. +Financial Statements and Supplementary Data +27 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +55 +Item 9A. +Controls and Procedures +55 +Item 9B. +Other Information +58 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +58 +Item 11. +Executive Compensation +58 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +58 +Item 13. +Certain Relationships and Related Transactions, and Director Independence +59 +Item 14. +Principal Accounting Fees and Services +59 +PART IV +Item 15. +Exhibits and Financial Statement Schedule +59 +Item 16. +Form 10-K Summary +62 +Signatures +63 +3 +FORWARD-LOOKING STATEMENTS +References in this report to “the Company,” “Key Tronic,” “we,” “our,” or “us” mean Key Tronic Corporation together with its subsidiaries, except where the context otherwise requires. +This Annual Report on Form 10-K contains forward-looking statements in addition to historical information. Forward-looking statements include, but are not limited to those including such words as aims, anticipates, believes, continues, could, estimates, expects, hopes, intends, plans, predicts, projects, targets, or will, similar verbs, or nouns corresponding to such verbs, which may be forward looking. Forward-looking statements also include other passages that are relevant to expected future events, performances, and actions or that can only be fully evaluated by events that will occur in the future. Forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those reflected in the forward-looking statements. Risks and uncertainties that might cause such differences include, but are not limited to those outlined in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risks and Uncertainties that May Affect Future Results” and in “Risk Factors.” Readers are cautioned not to place undue reliance on forward-looking statements, which reflect management’s opinions only as of the date hereof. The Company undertakes no obligation to update forward-looking statements to reflect developments or information obtained after the date hereof and disclaims any obligation to do so. Readers should carefully review the risk factors described in periodic reports the Company files from time to time with the Securities and Exchange Commission, including Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. +PART I +Item 1. BUSINESS +Background +Key Tronic Corporation was organized in 1969, as a Washington corporation that locally manufactured computer keyboards. The ability to design, build and deliver a quality product led us to become a leading independent manufacturer of keyboards for computers in the United States. Our fully integrated design, tooling, and automated manufacturing capabilities enabled us to rapidly respond to customers’ needs for keyboards in production quantities worldwide. We supported our sales growth through the development and purchase of international manufacturing facilities. As the computer keyboard market matured with increasing competition from other international providers, we determined that our business could no longer solely rely on keyboard sales. +After assessing market conditions and our strengths and capabilities, we shifted our focus from keyboard manufacturing to contract manufacturing for a wide range of products. Our unique strategic attributes are based on our core strengths of innovative design and engineering expertise in electronics, mechanical engineering, sheet metal fabrication and stamping, and precision plastics combined with high-quality, low cost production, and assembly on an international basis while providing exceptional customer service. These strengths have made our company a strong competitor in the contract manufacturing market. +Our Industry and Strategy +The expansion of the contract manufacturing industry and our acquisitions have allowed us to continue to expand our customer base and the industries that we serve. The increase in new programs represents a growing portion of our revenue and a promising foundation for our future. In keeping with our long-term strategic objectives, we have been successfully building a more diversified customer portfolio, spanning a wider range of industries. We currently offer our customers the following services: integrated electronic and mechanical engineering, precision plastic molding, sheet metal fabrication, printed circuit board (PCB) and complete product assembly, component selection, sourcing and procurement, worldwide logistics, and new product testing and production all at competitive pricing due to our global footprint. We differentiate ourselves from others our size and larger in the contract manufacturing industry by providing vertical integration, a flexible and responsive approach to our customer’s changing supply demand, and complete design engineering support. +We believe that we are well positioned in the contract manufacturing industry to continue the expansion of our customer base and achieve long-term growth. Our unique blend of multinational facilities, vertical integration, centralized management, and core strengths continue to support our growth and our customers’ needs. We continue to focus on controlling operating expenses and leveraging the synergistic capabilities of our world-class facilities in the United States, Mexico, China and Vietnam. This international production capability provides our customers with the benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs, and reduced product fulfillment time. Given our competitive advantages and the growing pressure for new potential customers to move forward with their outsourcing strategies, we feel that we are strongly positioned to win new business in coming periods and grow our revenue and profits. +4 +The contract manufacturing industry is intensely competitive. Although our customer base is growing, we still have less than 1% of the potential global market and our revenue can fluctuate significantly due to reliance on a concentrated base of customers. We are planning for new customer growth in the coming quarters by seeking to secure new programs with new and existing customers, increase our worldwide manufacturing capacity, leverage further our design engineering capabilities and continue to improve our manufacturing and procurement processes and capabilities. Ongoing challenges that we face include but are not limited to the following: continuing to win programs from new and existing customers, balancing capital employed, production capacity and key personnel in support of new customer programs, improving operating efficiencies, controlling costs while developing competitive pricing strategies, and successfully transitioning new program wins to full production. +Customers and Marketing +We provide a mix of manufacturing services for outsourced Original Equipment Manufacturing (OEM) products. We provide the following services: product design, surface mount technologies (SMT) and pin through hole capability for printed circuit board assembly, tool making, precision plastic molding, sheet metal fabrication and painting, liquid injection molding, complex assembly, prototype design and full product assembly. +Sales of the majority of our products have not historically been seasonal in nature, but may be seasonal in the future if there are changes in the types of products manufactured. Sales can, however, fluctuate significantly between quarters from changes in customers and customer demand due to the concentration of sales generated by our largest customers. +For the fiscal years 2022, 2021 and 2020, the five largest customers in each year accounted for 40%, 40% and 41% of combined total net sales, respectively. We continue to diversify our customer base by adding additional programs and customers. We expect net sales to our five largest customers as a percentage of total net sales to approximate current levels going forward. +The following table summarizes the customers that represented 10% or more of total net sales during the last three fiscal years: +Percentage of Net Sales by Fiscal Year +2022 2021 2020 +Customer A 13% * * +Customer B 12% 24% 18% +There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +We market our products and services primarily through our direct sales department which is comprised of strategically located field sales people and distributors. We also maintain relationships with several independent sales organizations to assist in marketing our product lines. +Manufacturing +We have continually made investments in developing and expanding a capital equipment base to achieve vertical integration and efficiencies in our manufacturing processes. We have invested significant capital into SMT for volume manufacturing of complex printed circuit board assemblies and in our metal shop providing precision metal stamping, fabricating, and finishing. We also design and develop tooling for injection molding and sheet metal fabrication and manufacture the majority of plastic and sheet metal parts used in the products we manufacture. Additionally, we have equipment to maintain a controlled clean environment for manufacturing processes that require a high level of precise control. +We use a variety of manual and automated assembly processes in our facilities, depending upon product complexity and degree of customization. Some examples of automated processes include component insertion, SMT, selective soldering, flexible robotic assembly, computerized vision system quality inspection, laser turrets, automated switch and key top installation, robotic welding, automated powder coat application, and automated functional testing. +Our engineering expertise and automated manufacturing processes enable us to work closely with our customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. We use computer-aided design techniques and software to assist in preparation of the tool design layout and component placement, to reduce tooling and production costs, improve component and product quality, and enhance turnaround time during product development. +5 +We purchase materials and components for our products from many different suppliers, including both domestic and international sources. We develop close working relationships with our suppliers, many of whom have been supplying products to us for several years. +Research, Development, and Engineering +As part of our long-term strategy, we are committed to supporting our customers by providing research, development, and engineering services. We have seen an increase in the success of providing design support on existing and potential customers in differentiating ourselves. We believe these services allow us to facilitate in optimizing new product designs, and the production processes of our customers’ programs. +Research, development, and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials costs, depreciation, and allocated information technology and facilities costs. +Competition +The market for the products and services we provide is highly competitive. There are numerous competitors in the contract manufacturing industry, many of which have substantially more resources and are more geographically diverse than we are. Some of our competitors have similar international production capabilities, large financial resources and some have substantially greater manufacturing, research and development, and marketing resources. There is also competition from the manufacturing operations of our current and potential customers, who are continually evaluating the merits of manufacturing their products internally versus the advantages of outsourcing. We believe that we can currently compete favorably in these areas primarily on the basis of our international footprint, responsiveness, creativity, vertical production capability, quality, and cost. +Trademarks +Our name and logo are federally registered trademarks, and we believe they are valuable assets of our business. +Employees +We consider our employees to be our primary strength and we make considerable efforts to maintain a well-qualified workforce. Our employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. We regularly provide transportation, medical services, and meals to all of our employees in foreign locations. The Company also has defined contribution plans available to U.S. employees who have attained age 21 and provide group health, life, and disability insurance plans. We also maintain share based compensation plans and other long-term incentive plans for certain employees and outside directors. +As of July 2, 2022, we had 4,897 full-time employees compared to 5,450 on July 3, 2021, and 5,741 on June 27, 2020. Since we can have significant fluctuations in product demand, we seek to maintain flexibility in our workforce by utilizing skilled temporary labor in some of our manufacturing facilities in addition to full-time employees. +Backlog +On July 30, 2022, our order backlog was valued at approximatel y $407.8 million, compared to approximately $303.2 million on July 31, 2021. The amount of backlog is not necessarily indicative of future sales but can be indicative of trends in expected future sales revenue. Due to the relationships with our customers, we will occasionally allow orders to be canceled or rescheduled and as a result it is not a meaningful indicator of future financial results. If there are canceled or rescheduled orders, we typically negotiate fees to cover the costs we have incurred. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change due to design modifications, customer forecast changes, or other customer requirements. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in Footnote “Enterprise-Wide Disclosures” of the “Notes to Consolidated Financial Statements” of this Annual Report on Form 10-K and that information is incorporated herein by reference. +Governmental Regulation +Our operations are subject to certain foreign, federal, state and local regulations relating to, among others, environmental, waste management, labor and health and safety matters. We have implemented processes and procedures to help ensure that our operations are in substantial compliance with all applicable regulations. However, material costs and liabilities may arise from these requirements or from new or modified requirements, which could have a material adverse effect on our business and results of operations. +6 +Information about Our Executive Officers. +The table below sets forth the name, current age and current position of our executive officers and other significant employees: +Name Age Positions Held +Executive Officers +Craig D. Gates 63 President and Chief Executive Officer +Brett R. Larsen 49 Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Philip S. Hochberg 60 Executive Vice President of Business Development +Duane D. Mackleit 54 Executive Vice President of Operations +David H. Knaggs 41 Executive Vice President of Quality and Information Systems +Chad T. Orebaugh 51 Executive Vice President of Engineering +Mark Courtney 56 +Vice President of Supply Chain +Executive Officers +CRAIG D. GATES – President and Chief Executive Officer +Mr. Gates, age 63, has been President and Chief Executive officer of the Company since April 2009. Previously, he was Executive Vice President and General Manager from August 2002 to April 2009. He served as Executive Vice President of Marketing, Engineering and Sales from July 1997 to August 2002 and served as Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of 1994. From 1982 to 1991 he held various engineering and management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. Mr. Gates has a Bachelor of Science Degree in Mechanical Engineering and a Master’s in Business Administration from the University of Illinois, Urbana. +BRETT R. LARSEN – Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Mr. Larsen, age 49, has served as Executive Vice President of Administration, Chief Financial Officer, and Treasurer since July 2015. Previously, he was Vice President of Finance and Controller from February 2010 to July 2015. He was Chief Financial Officer of FLSmidth Spokane, Inc. from December 2008 to February 2010. From October 2005 through November 2008, Mr. Larsen served as Controller of Key Tronic Corporation. From May 2004 to October 2005, Mr. Larsen served as Manager of Financial Reporting of Key Tronic Corporation. From 2002 to May 2004, Mr. Larsen was an audit manager for the public accounting firm BDO USA, LLP. He also held various auditing and supervisory positions with Grant Thornton LLP from 1997 to 2002. Mr. Larsen has a Bachelor of Science degree in Accounting and a Masters degree in Accounting from Brigham Young University and is a Certified Public Accountant. +PHILIP S. HOCHBERG – Executive Vice President of Business Development +Mr. Hochberg, age 60, has been Executive Vice President of Business Development since July 2012. Prior to this, Mr. Hochberg served as Vice President of Business Development from October 2009 through June 2012. He was Director of Business Development and Program Management from July 2008 to October 2009. Mr. Hochberg served as Director of Business Development from October 2004 to July 2008 and as Director of EMS Sales and Marketing from July 2000 to October 2004. Prior to joining Key Tronic, Mr. Hochberg worked for Quinton Instrument Company as their Director of Marketing and Product Management from 1992 to 2000. From 1988 to 1992, he was employed by SpaceLabs Medical as their Business Development Marketing Manager. Mr. Hochberg has an MBA from the University of British Columbia, a BA in Psychology, with a minor in Business from Washington University in St. Louis. +7 +DUANE D. MACKLEIT – Executive Vice President of Operations +Mr. Mackleit, age 54, has been Executive Vice President of Operations since December 2019. Prior to this, Mr. Mackleit served as Vice President of Program Management since July 2012. He served as Director of Program Management from July 2008 through June 2012. From May 2006 to July 2008 he served as Principal Program Manager. Prior to that, he served as Program Manager from March 2002 to May 2006 and Associate Program Manager from August 2000 to March 2002. Mr. Mackleit has also held several other positions with Key Tronic Corporation. Mr. Mackleit has an AA in Business from Spokane Falls Community College and a BA in Business/Marketing from Eastern Washington University. He also holds a MBA from Gonzaga University. +DAVID H. KNAGGS – Executive Vice President of Quality, Regulatory Affairs and Information Systems +Mr. Knaggs, age 41, has been Executive Vice President of Quality and Information Systems since May 2021. Previously, he was Vice President of Quality and Regulatory Affairs from November 2017 to May 2021. He was Vice President of Quality since October 2016. Before joining Key Tronic, Mr. Knaggs worked at Telect, Inc. from 2008 to 2016 as their Director of Engineering. Prior to that, he worked at Isothermal Systems Research as Lead Systems Engineer from 2003 to 2008. He has a Bachelor of Science degree in Mechanical Engineering with a minor in mathematics from the University of Washington. +CHAD T. OREBAUGH – Executive Vice President of Engineering +Mr. Orebaugh, age 51, has been Executive Vice President of Engineering since September 2021. Previously he served as Vice President of Engineering since April 2017. Prior to this, Mr. Orebaugh served as Director of Engineering since May 2013. From April 2010 to May 2013, he served as Manager of Engineering. From January 2000 to April 2010 he served as Lead Mechanical Engineer. Prior to that, he served as Mechanical Engineer from October 1998 to January 2000 and Associate Mechanical Engineer since October 1997. Mr. Orebaugh holds a BA in Mechanical Engineering from Gonzaga University. +MARK COURTNEY – Vice President of Supply Chain +Mark Courtney, age 56, has been Vice President of Supply Chain of the company since August 2019. Previously, he served as Purchasing Manager and Director of North American Purchasing from September 2015 to August 2019, and as Supply Chain Manager, ERP and Business Operations Manager for Amphenol Telect from August 2007 to September 2015. From March 2006 to August 2007, he served as Senior Buyer/Planner for Honeywell Specialty Materials and from June 2005 to March 2006 as Purchasing Manager for MRV Communications. From May 2000 to June 2005, he served as a Field and Inside Sales Associate for Arrow Electronics and from October 1991 to May 2000 held various positions at Alesis. +Available Information +Our principal executive offices are located at 4424 North Sullivan Road, Spokane Valley, Washington 99216, and our telephone number is (509) 928-8000. Our website is located at http://www.keytronic.com where filings of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or current reports on Form 8-K are available free of charge after they have been filed with the Securities and Exchange Commission. The information presented on our website currently and in the future is not considered to be part of this document or any document incorporated by reference in this document. +In addition, the SEC maintains an Internet site (at www.sec.gov ) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. +Item 1A. RISK FACTORS +There are risks and uncertainties that could affect our business. These risks and uncertainties include but are not limited to, the risk factors described below, in Item 7A: “Quantitative and Qualitative Disclosures about Market Risk” and elsewhere in this Annual Report on Form 10-K. +8 +RISKS AND UNCERTAINTIES THAT MAY AFFECT FUTURE RESULTS +The following risks and uncertainties could affect our actual results and could cause results to differ materially from past results or those contemplated by our forward-looking statements. When used herein, the words “expects,” “believes,” “anticipates” and other similar expressions are intended to identify forward-looking statements. +RISKS RELATED TO OUR BUSINESS AND STRATEGY +Our operations may be subject to certain risks. +We manufacture product in facilities located in Mexico, China, Vietnam and the United States. These operations may be subject to a number of risks, including: +• difficulties in staffing, turnover and managing onshore and offshore operations; +• political and economic instability (including acts of terrorism, pandemics, civil unrest, forms of violence and outbreaks of war), which could impact our ability to ship, manufacture, and/or receive product; +• unexpected changes in regulatory requirements and laws, including those related to climate change; +• longer customer payment cycles and difficulty collecting accounts receivable; +• export duties, import controls and trade barriers (including quotas); +• governmental restrictions on the transfer of funds; +• burdens of complying with a wide variety of foreign laws and labor practices; subject to trade wars and tariffs; +• our locations are subject to physical and operational risks from natural disasters, severe weather events, and climate change; and +• our locations may also be impacted by future temporary closures and labor constraints as a result of COVID-19. +Our operations in certain foreign locations receive favorable income tax treatment in the form of tax credits or other incentives. In the event that such tax incentives are not extended, are repealed, or we no longer qualify for such programs, our taxes may increase, which would reduce our net income. +Additionally, certain foreign jurisdictions restrict the amount of cash that can be transferred to the U.S. or impose taxes and penalties on such transfers of cash. To the extent we have excess cash in foreign locations that could be used in, or is needed by, our operations in the United States, we may incur significant penalties and/or taxes to repatriate these funds. +We may experience fluctuations in quarterly results of operations. +Our quarterly operating results have varied in the past and may vary in the future due to a variety of factors, including adverse changes in the U.S. and global macroeconomic environment, volatility in overall demand for our customers’ products, success of customers’ programs, timing of new programs, new product introductions or technological advances by us, our customers and our competitors, and changes in pricing policies by us, our customers, our suppliers, and our competitors. Our customer base is diverse in the markets they serve, however, decreases in demand, particularly from customers in certain industries could affect future quarterly results. Additionally, our customers could be adversely impacted by illiquidity in the credit markets which could directly impact our operating results. +Component procurement, production schedules, personnel and other resource requirements are based on estimates of customer requirements. Occasionally, our customers may request accelerated production that can stress resources and reduce operating margins. Conversely, our customers may abruptly lower or cancel production which may lead to a sudden, unexpected increase in inventory or accounts receivable for which we may not be reimbursed even when under contract with customers. In addition, because many of our operating expenses are relatively fixed, a reduction in customer demand can harm our gross profit and operating results. The products which we manufacture for our customers have relatively short product lifecycles. Therefore, our business, operating results and financial condition are dependent in a significant way on our ability to obtain orders from new customers and new product programs from existing customers. +Operating results can also fluctuate if changes are made to significant estimates and assumptions. Significant estimates and assumptions include the allowance for doubtful receivables, provision for obsolete and non-saleable inventory, stock-based compensation, the valuation allowance on deferred tax assets, impairment of long-lived assets, long-term incentive compensation accrual, the provision for warranty costs, and the impact of hedging activities. +Due to the COVID-19 pandemic, we have seen extreme shifts in demand from our customer base. The possibility of future temporary closures and labor constraints, as well as the inability to predict customer demand, costs, and future supply chain disruptions during the rapidly changing COVID-19 environment can materially impact operating results. +9 +We are exposed to general economic conditions, which could have a material adverse impact on our business, operating results and financial condition. +Adverse economic conditions and uncertainty in the global economy such as unstable global financial and credit markets, inflation, and recession can negatively impact our business. Unfavorable economic conditions could affect the demand for our customers’ products by triggering a reduction in orders as well as a decline in forecasts which could adversely affect our sales in future periods. Additionally, the financial strength of our customers and suppliers and their ability to obtain and rely on credit financing may affect their ability to fulfill their obligations to us and have an adverse effect on our financial results. +Adverse macroeconomic conditions as a result of COVID-19 have and may continue to affect our business. The conditions affect the Company’s ability to predict and plan for future supply chain disruptions, fluctuations in customer demand and costs, and the ability to operate as there is uncertainty over future temporary closures. Inflation has also risen globally to historically high levels. If the inflation rate continues to increase, the costs of labor and other expenses could also increase. We may not be able to increase our product prices enough to offset these increased costs. In addition, any increase in our product prices may reduce our future customer orders and profitability. Inflation may further exacerbate other risk factors discussed in this Annual Report on Form 10-K, including disruptions to international operations. +The majority of our sales come from a small number of customers and a decline in sales to any of these customers could adversely affect our business. +At present, our customer base is concentrated and could become more or less concentrated. There can be no assurance that our principal customers will continue to purchase products from us at current levels. Moreover, we typically do not enter into long-term volume purchase contracts with our customers, and our customers have certain rights to extend or delay the shipment of their orders. We, however, typically require that our customers contractually agree to buy back inventory purchased within specified lead times to build their products if not used. +The loss of one or more of our major customers, or the reduction, delay or cancellation of orders from such customers, due to economic conditions or other forces, could materially and adversely affect our business, operating results and financial condition. The contraction in demand from certain industries could impact our customer orders and have a negative impact on our operations over the foreseeable future. Additionally, if one or more of our customers were to become insolvent or otherwise unable to pay for the manufacturing services provided by us, our operating results and financial condition would be adversely affected. +We depend on a limited number of suppliers for certain components that are critical to our manufacturing processes. A shortage of these components or an increase in their price could interrupt our operations and result in a significant change in our results of operations. +We are dependent on many suppliers, including sole source suppliers, to provide key components and raw materials used in manufacturing customers’ products. We have seen supply shortages in certain electronic components. In addition, our suppliers' facilities may also experience earthquakes, tsunamis and other natural disasters which may cause a shortage of components. This can result in longer lead times and the inability to meet our customers request for flexible production and extended shipment dates. If demand for components outpaces supply, capacity delays could affect future operations. Delays in deliveries from suppliers or the inability to obtain sufficient quantities of components and raw materials have and may continue to cause delays or reductions in shipment of products to our customers which could adversely affect our operating results and damage customer relationships. +Key Tronic continues to work closely with its employees and key suppliers to ascertain delays attributable to the COVID-19 pandemic. Delays in production and extended transit times of critical parts have and may continue to cause a shortage of components. +We operate in a highly competitive industry; if we are not able to compete effectively in the contract manufacturing industry, our business could be adversely affected. +Competitors may offer customers lower prices on certain high volume programs. This could result in price reductions, reduced margins and loss of market share, all of which would materially and adversely affect our business, operating results, and financial condition. If we were unable to provide comparable or better manufacturing services at a lower cost than our competitors, it could cause sales to decline. In addition, competitors can copy our non-proprietary designs and processes after we have invested in development of products for customers, thereby enabling such competitors to offer lower prices on such products due to savings in development costs. +10 +Fluctuations in foreign currency exchange rates could increase our operating costs. +We have manufacturing operations located in Mexico and China. A significant portion of our operations are denominated in the Mexican peso and the Chinese currency, the renminbi ("RMB"). Currency exchange rates fluctuate daily as a result of a number of factors, including changes in a country's political and economic policies. Volatility in the currencies of our entities and the United States dollar, as well as inflationary costs, could seriously harm our business, operating results and financial condition. The primary impact of currency exchange fluctuations is on the cash, receivables, payables and expenses of our operating entities. As part of our hedging strategy, we currently use Mexican peso forward contracts to hedge foreign currency fluctuations for a portion of our Mexican peso denominated expenses. We currently do not hedge expenses denominated in RMB. Unexpected losses could occur from increases in the value of these currencies relative to the United States dollar. +As a result of COVID-19, significant currency exchange fluctuations can occur causing unexpected losses. Future temporary closures of production facilities in Mexico could also cause significant changes in our ability to qualify for hedge accounting treatment of our forward contracts to hedge foreign currency fluctuations. However, given the unprecedented nature of the pandemic the FASB staff believes that an entity may apply the exception in paragraph 815-30-40-4 for rare cases caused by extenuating circumstances that are related to the nature of the forecasted transaction and are outside the control or influence of an entity to delays in the timing of the forecasted transactions if those delays are related to the effects of the COVID-19 pandemic and are considered probable to still occur. In addition, the FASB staff believes that it would be acceptable for an entity to determine that missed forecasts related to the effects of the COVID-19 pandemic need not be considered when determining whether it has exhibited a pattern of missing forecasts that would call into question its ability to accurately predict forecasted transactions and the propriety of using cash flow hedge accounting in the future for similar transactions. +Our success will continue to depend to a significant extent on our key personnel. +Our future success depends in large part on the continued service of our key technical, marketing and management personnel and on our ability to continue to attract and retain qualified production employees. There can be no assurance that we will be successful in attracting and retaining such personnel, particularly in our manufacturing locales that may be experiencing high demand for similar key personnel. The loss of key employees could have a material adverse effect on our business, operating results and financial condition. +Start-up costs and inefficiencies related to new or transferred programs can adversely affect our operating results and such costs may not be recoverable if such new programs or transferred programs are canceled or don’t meet expected sales volumes. +Start-up costs, the management of labor and equipment resources in connection with the establishment of new programs and new customer relationships, and the need to obtain required resources in advance can adversely affect our gross margins and operating results. These factors are particularly evident in the ramping stages of new programs. These factors also affect our ability to efficiently use labor and equipment. We are currently managing a number of new programs. Consequently, our exposure to these factors has increased. In addition, if any of these new programs or new customer relationships were terminated, our operating results could be harmed, particularly in the short term. We may not be able to recoup these start-up costs or replace anticipated new program revenues. +Customers may change production timing and demand schedules which makes it difficult for us to schedule production and capital expenditures and to maximize the efficiency of our manufacturing capacity. +Changes in demand for customer products reduce our ability to accurately estimate the future requirements of our customers. This makes it difficult to schedule production and maximize utilization of our manufacturing capacity. We must determine the levels of business that we will seek and accept from customers, set production schedules, commit to procuring inventory, and allocate personnel and resources, based on our estimates of our customers' requirements. Customers can require sudden increases and decreases in production which can put added stress on resources and reduce margins. Sudden decreases in production can lead to excess inventory on hand which may or may not be reimbursed by our customers even when under contract. +Continued growth could further lead to capacity constraints. We may need to transfer production to other facilities, acquire new facilities, or outsource production which could negatively impact gross margin. The Company has been able to manage the arrival of components in an effort to control inventory levels of customers that have seen sharp decreases in demand as a result of COVID-19. +11 +Compliance or the failure to comply with current and future environmental and health laws or regulations could cause us significant expense. +We are subject to a variety of domestic and foreign environmental regulations relating to the use, storage, and disposal of materials used in our manufacturing processes. In addition, increasing governmental focus on climate change may result in new environmental regulations that may negatively affect us, our vendors or our customers. As a result, we may incur additional costs or obligations in complying with any new environmental and reporting requirements, as well as increased indirect costs resulting from our vendors or suppliers that get passed on to us. +If we fail to comply with any present or future regulations, we could be subject to future liabilities or the suspension of current manufacturing operations. In addition, such regulations could restrict our ability to expand our operations or could require us to acquire costly equipment, substitute materials, or incur other significant expenses to comply with government regulations. +If our manufacturing processes and services do not comply with applicable statutory and regulatory requirements, or if we manufacture products containing design or manufacturing defects, demand for our services may decline and we may be subject to liability claims. +We manufacture and design products to our customers’ specifications, and, in some cases, our manufacturing processes and facilities may need to comply with applicable statutory and regulatory requirements. For example, medical devices that we manufacture or design, as well as the facilities and manufacturing processes that we use to produce them, are regulated by the Food and Drug Administration and non-U.S. counterparts of this agency. In addition, our customers’ products and the manufacturing processes that we use to produce them often are highly complex. As a result, products that we manufacture may at times contain manufacturing or design defects, and our manufacturing processes may be subject to errors or not be in compliance with applicable statutory and regulatory requirements. Defects in the products we manufacture or design, whether caused by a design, manufacturing or component failure or error, or deficiencies in our manufacturing processes, may result in delayed shipments to customers or reduced or canceled customer orders. If these defects or deficiencies are significant, our reputation may also be damaged. The failure of the products that we manufacture or our manufacturing processes and facilities to comply with applicable statutory and regulatory requirements may subject us to legal fines or penalties and, in some cases, require us to shut down or incur considerable expense to correct a manufacturing process or facility. Our customers are required to indemnify us against liability associated with designing products to meet their specifications. However, if our customers are responsible for the defects, they may not, or may not have resources to, assume responsibility for any costs or liabilities arising from these defects, which could expose us to additional liability claims. +If we do not manage our growth effectively, our profitability could decline. +Our business is experiencing growth which can place considerable additional demands upon our management team and our operational, financial and management information systems. Our ability to manage growth effectively requires us to continue to implement and improve these systems; avoid cost overruns; maintain customer, supplier and other favorable business relationships during possible transition periods; continue to develop the management skills of our managers and supervisors; and continue to train, motivate and manage our employees. Our failure to effectively manage growth could have a material adverse effect on our results of operations. +Energy price increases may negatively impact our results of operations. +Certain components that we use in our manufacturing process are petroleum-based. In addition, we, along with our suppliers and customers, rely on various energy sources in our transportation activities. While significant uncertainty currently exists about the future of energy prices, a significant increase, such as the increased fuel prices experienced in fiscal year 2022, is possible. Increased energy prices could cause an increase to our raw material and transportation costs. In addition, increased transportation costs related to certain suppliers and customers could be passed along to us. We may not be able to increase our product prices enough to offset these increased costs. In addition, any increase in our product prices may reduce our future customer orders and profitability. +TECHNOLOGY RISKS +Our operations are subject to cyberattacks that could have a material adverse effect on our business. +We are increasingly dependent on digital technologies and services to conduct our operations. We use these technologies for internal purposes, including data storage, processing and transmissions, as well as in our interactions with vendors and customers. Digital technologies and services are subject to the risk of cybersecurity incidents and some incidents can remain undetected for a period of time. +We routinely monitor our systems for cyber threats and have processes in place to detect and remediate vulnerabilities. Nevertheless, we have experienced attempted security breaches, such as phishing emails and other targeted attacks. We expect that our operations will continue to be subject to cyber threats, and any future cybersecurity incident could significantly disrupt our operations. +12 +Cybersecurity incidents could also result in the misappropriation of proprietary or confidential information of the Company or that of its customers, employees, vendors or suppliers. We expect to incur costs in the future to mitigate against cybersecurity incidents as threats are expected to continue and to become more persistent and sophisticated. If our systems for protecting against cybersecurity incidents prove to be insufficient, we could be adversely affected by, among other things, loss of or damage to intellectual property, proprietary or confidential information, or employee, vendor or customer data; interruption of our business operations; and increased costs to prevent, respond to or mitigate cybersecurity incidents. These risks could harm our reputation and our relationships with employees, vendors and customers and may result in claims or enforcement actions and investigations against us. +Disruptions to our information systems, including losses of data or outages, could adversely affect our operations. +We rely on information technology networks and systems to process, transmit and store electronic information. In particular, we depend on our information technology infrastructure for a variety of functions, including worldwide financial reporting, inventory management, procurement, invoicing and email communications. Any of these systems may be susceptible to outages due to fire, floods, power loss, telecommunications failures, terrorist attacks and similar events. If we or our vendors are unable to prevent such outages, our operations could be disrupted. +If we are unable to maintain our technological and manufacturing process expertise, our business could be adversely affected. +The markets for our customers’ products are characterized by rapidly changing technology, evolving industry standards, frequent new product introductions and short product life cycles. The introduction of products embodying new technologies or the emergence of new industry standards can render existing products obsolete or unmarketable. Our success will depend upon our customers’ ability to enhance existing products and to develop and introduce, on a timely and cost-effective basis, new products that keep pace with technological developments and emerging industry standards and address evolving and increasingly sophisticated customer requirements. Failure of our customers to do so could substantially harm our customers’ competitive positions. There can be no assurance that our customers will be successful in identifying, developing and marketing products that respond to technological change, emerging industry standards or evolving customer requirements. +RISKS RELATED TO CAPITAL AND FINANCING +Cash and cash equivalents are exposed to concentrations of credit risk. +We place our cash with high credit quality institutions. At times, such balances may be in excess of the federal depository insurance limit or may be on deposit at institutions which are not covered by insurance. If such institutions were to become insolvent during which time it held our cash and cash equivalents in excess of the insurance limit, it could be necessary to obtain other credit financing to operate our facilities. +Our ability to secure and maintain sufficient credit arrangements is key to our continued operations. +There is no assurance that we will be able to retain or renew our credit agreements in the future. In the event the business grows rapidly or there is uncertainty in the macroeconomic climate, additional financing resources could be necessary. There is no assurance that we will be able to obtain equity or debt financing at acceptable terms, or at all in the future. In addition, we have restrictive covenants with our financial institution which could impact how we manage our business. If we cannot meet our financial covenants, our borrowings could become immediately payable which could have a material adverse impact on our financial statements. For a summary of our banking arrangements, see Footnote “Long-Term Debt” of the “Notes to Consolidated Financial Statements.” +An adverse change in the interest rates for our borrowings could adversely affect our financial condition. +We are exposed to interest rate risk under our revolving line of credit and term loan. We have not historically hedged the interest rate on our credit facility; therefore, unless we do so, significant changes in interest rates could adversely affect our results of operations. For a summary of our debt obligations, see Footnote “Long-Term Debt” of the “Notes to Consolidated Financial Statements.” +In addition, the U.K.’s Financial Conduct Authority, which regulates LIBOR, has confirmed that LIBOR-indexed rates will cease after June 30, 2023, with the remaining IBOR-indexed rates ceasing on December 31, 2021. The Federal Reserve Board and the Federal Reserve Bank of New York identified Secured Overnight Financing Rate (“SOFR”) as its preferred alternative rate for LIBOR for debt and derivative financial instruments. +13 +Our stock price is volatile. +Our stock price has and may continue to be subject to wide fluctuations and possible rapid increases or declines over a short time period. These fluctuations may be due to factors specific to us such as our stock's thinly traded nature, variations in quarterly operating results, changes in earnings estimates, or to factors relating to the contract manufacturing industry or to the securities markets in general, which, in recent years, have experienced significant price fluctuations. These fluctuations often have been unrelated to the operating performance of the specific companies whose stocks are traded. In addition, holders of our common stock will suffer immediate dilution to the extent outstanding equity awards are exercised to purchase common stock. +RISKS RELATED TO OUR CONTROLS AND PROCEDURES AND THE INTERNAL INVESTIGATION +We identified a material weakness in our internal control over financial reporting and concluded that our disclosure controls and procedures were not effective as of December 26, 2020 and April 3, 2021. If we fail to properly remediate any future deficiencies or material weaknesses or to maintain proper and effective internal controls, our business and financial condition could be materially adversely impacted. +As described in Item 9a, “Controls and Procedures,” of this Annual Report on Form 10-K, in fiscal year 2022, we concluded that our disclosure controls and procedures were not effective as of December 26, 2020 and April 3, 2021, due to the existence of a material weakness in our internal control over financial reporting. While we undertook remediation efforts to address the identified deficiencies and have concluded that the material weakness was remediated as of July 3, 2021, we cannot provide assurance that we will be able to conclude that our controls will be effective in the future. We also cannot guarantee that additional significant deficiencies or material weaknesses in our internal control over financial reporting will not arise or be identified in the future. +If additional deficiencies in our internal control over financial reporting are discovered or occur in the future, our consolidated financial statements may contain material misstatements and we could be required to restate our financial results and incur the additional costs and expenses associated therewith. Moreover, because of the inherent limitations of any control system, material misstatements due to error or fraud may not be prevented or detected on a timely basis, or at all. If we are unable to provide reliable and timely financial reports in the future, our business and reputation may be further harmed. Restated financial statements and failures in internal controls may also cause us to fail to meet additional reporting obligations, negatively affect investor confidence in our management and the accuracy of our financial statements and disclosures, or result in adverse publicity and concerns from investors, any of which could have a negative effect on the price of our common stock, subject us to regulatory investigations and penalties or stockholder litigation, and materially adversely impact our business, financial condition, results of operations and cash flows. +Matters relating to or arising from the subject of the Audit Committee’s internal investigation, including expenses and diversion of personnel and resources, regulatory investigations, and proceedings and litigation matters, could have an adverse effect on our business, results of operations and financial condition. +We have incurred, and may continue to incur, significant expenses related to legal, accounting and other professional services in connection with matters relating to or arising from the subject of the Audit Committee’s internal investigation. We have taken and continue to take a number of steps in order to remediate identified deficiencies in our internal control over financial reporting and attempt to reduce the risk of future recurrence. The validation of the efficacy of these remedial steps will result in us incurring additional near term expenses, and to the extent these steps are not successful, we may incur significant additional time and expense. +In addition, we are cooperating with the Securities and Exchange Commission (the “SEC”) regarding matters related to the internal investigation. The completion of the internal investigation will not automatically resolve the SEC’s inquiries. If the SEC or any other regulator were to commence legal action against us, we could be required to pay significant penalties and become subject to injunctions, cease and desist orders or other remedies. We can provide no assurances as to the outcome of any governmental inquiry or investigation. Further, we, our officers and members of our board of directors could be named as defendants in lawsuits asserting claims arising out of the subject matter of the Audit Committee’s internal investigation. As a result of any legal proceedings and any related indemnification requirements to our officers and directors, we could be required to pay monetary damages that may be in excess of our insurance coverage or may have additional penalties or other remedies imposed against us or our officers and directors. +All of these expenses, and the diversion of the attention of management and other personnel that has occurred and is expected to continue, could adversely affect our business, financial condition, results of operations and cash flows. +14 +Due to inherent limitations, there can be no assurance that our system of disclosure and internal controls and procedures will be successful in preventing all errors, theft and fraud, or in informing management of all material information in a timely manner. +Management does not expect that our disclosure controls and procedures and internal controls over financial reporting will prevent all errors or fraud. A control system is designed to give reasonable, but not absolute, assurance that the objectives of the control system are met. In addition, any control system reflects resource constraints and the benefits of controls must be considered relative to their costs. Inherent limitations of a control system may include: judgments in decision making may be faulty, breakdowns can occur simply because of error or mistake and controls can be circumvented by collusion or management override. Due to the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and may not be detected. +LEGAL AND ACCOUNTING RISKS +We are involved in various legal proceedings. +In the past, we have been notified of claims relating to various matters including contractual matters, intellectual property rights or other issues arising in the ordinary course of business. In the event of such a claim, we may be required to spend a significant amount of money to defend or otherwise address the claim. Any litigation or dispute resolution, even where a claim is without merit, could result in substantial costs and diversion of resources. Accordingly, the resolution or adjudication of such disputes, even those encountered in the ordinary course of business, could have a material effect on our business, consolidated financial conditions and results of operations. +Changes in securities laws and regulations will increase our costs and risk of noncompliance. +We are subject to additional requirements contained in the Sarbanes-Oxley Act of 2002 (the Sarbanes-Oxley Act) and more recently the Dodd-Frank Act. The Sarbanes-Oxley and Dodd-Frank Acts required or will require changes in some of our corporate governance, securities disclosure and compliance practices. In response to the requirements of the Sarbanes-Oxley and Dodd-Frank Acts, the SEC and NASDAQ promulgated new rules and additional rulemaking is expected in the future. Compliance with these new rules and future rules has increased and may increase further our legal, financial and accounting costs as well as a potential risk of noncompliance. Absent significant changes in related rules, which we cannot assure, we anticipate some level of increased costs related to these new regulations to continue indefinitely. We also expect these developments to make it more difficult and more expensive to obtain director and officer liability insurance, and we may be forced to accept reduced coverage or incur substantially higher costs to obtain coverage. Likewise, these developments may make it more difficult for us to attract and retain qualified members of our Board of Directors or qualified management personnel. Further, the costs associated with the compliance with and implementation of procedures under these and future laws and related rules could have a material impact on our results of operations. In addition, the costs associated with noncompliance with additional securities laws and regulations could also impact our business. +Changes in financial accounting standards may affect our reported financial condition or results of operations as well as increase costs related to implementation of new standards and modifications to internal controls. +Our consolidated financial statements are prepared in conformity with accounting standards generally accepted in the United States, or U.S. GAAP. These principles are subject to amendments made primarily by the Financial Accounting Standards Board (FASB) and the SEC. A change in those policies can have a significant effect on our reported results and may affect our reporting of transactions which are completed before a change is announced. Changes to accounting rules or challenges to our interpretation or application of the rules by regulators may have a material adverse effect on our reported financial results or on the way we conduct business. +GENERAL RISKS +Our levels of insurance coverage may not be sufficient for potential damages, claims or losses. +We have various forms of business and liability insurance which we believe are appropriate based on the needs of companies in our industry. As a result, not all of our potential business risks or potential losses would be covered by our insurance policies. If we sustain a significant claim or loss which is not covered by insurance, our net income could be negatively impacted. +15 +We may encounter complications with acquisitions, which could potentially harm our business. +Any current or future acquisitions may require additional equity financing, which could be dilutive to our existing shareholders, or additional debt financing, which could potentially affect our credit ratings. Any downgrades in our credit ratings associated with an acquisition could adversely affect our ability to borrow by resulting in more restrictive borrowing terms. To integrate acquired businesses, we must implement our management information systems, operating systems and internal controls, and assimilate and manage the personnel of the acquired operations. The integration of acquired businesses may be further complicated by difficulties managing operations in geographically dispersed locations. The integration of acquired businesses may not be successful and could result in disruption by diverting management’s attention from the core business. In addition, the integration of acquired businesses may require that we incur significant restructuring charges or other increases in our expenses and working capital requirements, which reduce our return on invested capital. +Acquisitions may involve numerous other risks and challenges including but not limited to: potential loss of key employees and customers of the acquired companies; the potential for deficiencies in internal controls at acquired companies; lack of experience operating in the geographic market or industry sector of the acquired business; constraints on available liquidity, and exposure to unanticipated liabilities of acquired companies. These and other factors could harm our ability to achieve anticipated levels of profitability at acquired operations or realize other anticipated benefits of an acquisition, and could adversely affect our consolidated business and operating results. +Item 1B. UNRESOLVED STAFF COMMENTS +None +Item 2. PROPERTIES AS OF DATE OF FILING +We have manufacturing and sales operations located in the United States, Mexico, China and Vietnam. The table below lists the locations and square footage of our operating facilities: +Location Approx. +Sq. Ft. Type of Interest +(Leased/Owned) Description of Use +Corinth, Mississippi 350,000 Leased Manufacturing and warehouse +El Paso, Texas 80,000 Leased Shipping and warehouse +Fayetteville, Arkansas 105,000 Leased Manufacturing and warehouse +Oakdale, Minnesota 103,000 Leased Manufacturing and warehouse +Spokane Valley, Washington 95,000 Leased Sales, research, administration and manufacturing +Spokane Valley, Washington 36,000 Leased Manufacturing +Total USA 769,000 +Juarez, Mexico 193,000 Leased Warehouse +Juarez, Mexico 174,000 Owned Manufacturing and warehouse +Juarez, Mexico 115,000 Owned Manufacturing and warehouse +Juarez, Mexico 103,000 Owned Manufacturing and warehouse +Juarez, Mexico 72,000 Leased Manufacturing and warehouse +Juarez, Mexico 66,000 Owned Manufacturing and warehouse +Juarez, Mexico 60,000 Owned Manufacturing and warehouse +Juarez, Mexico 116,000 Leased Manufacturing and warehouse +Juarez, Mexico 159,000 Leased Manufacturing and warehouse +Total Mexico 1,058,000 +Shanghai, China 103,000 Leased Manufacturing and warehouse +Total China 103,000 +Da Nang, Vietnam 133,000 Leased Manufacturing and warehouse +Total Vietnam 133,000 +Grand Total 2,063,000 +The geographic diversity of these locations allows us to offer services near certain of our customers and major electronics markets with the additional benefit of reduced labor costs. We consider the productive capacity of our current facilities sufficient to carry on our current business. In addition, in Juarez, Mexico one of our buildings includes adjacent vacant land that could be developed into additional manufacturing and warehouse space. +16 +All our facilities are ISO certified to ISO 9001:2015 standard and to Customs Trade Partnership against Terrorism (CTPAT). +• The Spokane, Washington facility is registered to IATF 16949 automotive standard, ISO 13485:2016 medical devices, ISO 14001:2015 environmental standard, and ISO 45001 Occupational Health and Safety Management System. +• The Juarez, Mexico facility is registered to IATF 16949 automotive standard, ISO 13485:2016 medical devices, ISO 14001:2015 environmental standard, ISO 45001 Occupational Health and Safety Management System, and has a certified ANSI/ESD S20.20 Electrostatic Discharge Program. +• The Da Nang, Vietnam facility is additionally registered to IATF 16949 automotive standard. +• The Shanghai, China facility is additionally registered to IATF 16949 automotive standard, ISO 14001:2015 environmental standard, and has a certified ANSI/ESD S20.20 Electrostatic Discharge Program. +• The Oakdale, Minnesota facility is additionally registered to ISO 13485:2016 medical devices standard, AS9100D aviation, space and defense standard, has a certified ANSI/ESD S20.20 Electrostatic Discharge Control Program, and is NADCAP certified. +• The Fayetteville, Arkansas facility is additionally registered to AS9100D aviation, space and defense standard and have a certified ANSI/ESD S20.20 Electrostatic Discharge Control Program. +• The Corinth, Mississippi facility is additionally registered to ISO 14001:2015 and ISO/IEC 80079-34 explosive atmospheres. +• The Oakdale, Minnesota; Corinth, Mississippi; Fayetteville, Arkansas and Spokane, Washington facilities are all registered with the U.S. State Department for International Traffic in Arms Regulations (ITAR). +Item 3. LEGAL PROCEEDINGS +We are a party to certain lawsuits or claims in the ordinary course of business. We do not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on our financial position, results of operations or cash flow, although an adverse resolution against the Company in a fiscal quarter or year could have a material adverse effect on the Company’s results of operations in a particular quarter or year. For further details on claims, see Footnote “Commitments and Contingencies” of the “Notes to Consolidated Financial Statements.” +Item 4. MINE SAFETY DISCLOSURES +Not Applicable +PART II +Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES +Market Information +Our common stock is traded on the NASDAQ Global Market, formerly the NASDAQ National Market System under the symbol “KTCC.” Quarterly high and low sales prices for our common stock for fiscal years 2022 and 2021 were as follows: +2022 2021 +High Low High Low +First Quarter $ 7.48 $ 6.45 $ 10.22 $ 5.04 +Second Quarter 6.73 5.95 10.48 7.05 +Third Quarter 6.55 5.26 9.48 6.75 +Fourth Quarter 5.74 4.27 8.35 6.35 +High and low stock prices are based on the daily sales prices reported by the NASDAQ Stock Market. These quotations represent prices between dealers without adjustment for markups, markdowns, and commissions, and may not represent actual transactions. +Holders and Dividends +As of July 2, 2022, we had 582 shareholders of common stock on record. As a result of our credit agreements, we are restricted from declaring or paying dividends in cash or stock without Bank of America’s prior written consent. We have not paid a cash dividend and do not anticipate payment of dividends in the foreseeable future. +17 +Equity Compensation Plan Information +Information concerning securities authorized for issuance under our equity compensation plans is set forth in Part III, Item 12 of this Annual Report on Form 10-K, under the caption “Equity Compensation Plan Information,” and that information is incorporated herein by reference. +Performance Graph +Set forth below is a line graph comparing the cumulative total shareholder return on our common stock with the cumulative total return of the NASDAQ Stock Market (U.S. & Foreign) Index and the NASDAQ Electronic Components Index in fiscal 2022. +6/30/2017 6/30/2018 6/29/2019 6/27/2020 7/3/2021 7/2/2022 +Key Tronic Corporation 100.00 106.91 70.24 74.19 92.38 60.23 +NASDAQ Composite 100.00 123.60 133.22 169.11 245.60 188.07 +NASDAQ Electronic Components 100.00 130.95 128.24 174.60 286.71 221.70 +18 +Item 6: [RESERVED] +Item 7: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +Overview +Key Tronic is a leading contract manufacturer offering value-added design and manufacturing services from its facilities in the United States, Mexico, China and Vietnam. We provide full engineering services, materials management, worldwide manufacturing facilities, assembly services, in-house testing, worldwide distribution and unparalleled customer service. It’s customers include some of the world’s leading original equipment manufacturers. Our combined capabilities and vertical integration are proving to be a desirable offering to our expanded customer base. +Our international production capability provides our customers with benefits of improved supply-chain management, reduced inventories, lower transportation costs, and reduced product fulfillment time. We continue to make investments in all of our operating facilities to give us the production capacity, capabilities and logistical advantages to continue to win new business. The following information should be read in conjunction with the consolidated financial statements included herein and with Part II Item 1A, Risk Factors included as part of this filing. +Our mission is to provide our customers with superior manufacturing and engineering services at the lowest total cost for the highest quality products, and create long-term mutually beneficial business relationships by employing our “Trust, Commitment, Results” philosophy. +Executive Summary +During the fourth quarter of fiscal year 2022, we won new programs involving audio products, GPS devices, utility meters, personal safety devices, and innovative internet solutions. +We reported net sales of $531.8 million for fiscal year 2022, the highest annual revenue in the Company’s history, and up 3% from $518.7 million for fiscal year 2021. While demand has remained strong from both new and existing customers, revenue for the fourth quarter and for the full year of fiscal year 2022 continued to be constrained by issues related to the supply chain, transportation and logistics and the worldwide pandemic. +During the fourth quarter of fiscal year 2022, the results were impacted by intermittent parts supply and factory downtime. The Company’s facilities in Shanghai, China were closed for most of the fourth quarter due to a government mandated COVID-19 shutdown. While the reopening of the Company’s China facility took longer than anticipated, operations have since resumed. +Moving into fiscal 2023, the global supply chain and COVID-19 crises continue to present uncertainty and multiple business challenges. At the same time, global logistics problems and heightened assurance of supply concerns continue to drive the favorable trend of contract manufacturing returning to North America. +For the first quarter of fiscal year 2023, the Company expects to report revenue in the range of $125 million to $135 million. Despite growing customer demand and backlog, we expect that the ongoing disruptions from the global supply chain and COVID-19 issues will continue to significantly limit production and adversely impact operating efficiencies, particularly for our China-based facilities. +We have continued to diversify our customer base by adding additional programs and customers. Our current customer relationships involve a variety of products, including consumer electronics, electronic storage devices, plastics, household products, gaming devices, specialty printers, telecommunications, industrial equipment, military supplies, computer accessories, medical, educational, irrigation, automotive, transportation management, robotics, RFID, power supply, off-road vehicle equipment, fitness equipment, HVAC controls, consumer products, home building products, material handling systems, lighting equipment, consumer security products, smart security, architectural LED lighting, power meters and smart grid, wireless power solutions, sanitizer dispensing, automotive controllers, oil and gas drilling, power equipment and wireless security. +Gross profit as a percent of net sales was 8.1 percent in both fiscal year 2022 and 2021. The level of gross margin is impacted by product mix, timing of the startup of new programs, facility utilization, and pricing within the electronics industry and material costs, which can fluctuate significantly from quarter to quarter and year to year. +Operating income as a percentage of net sales for fiscal year 2022 was 1.7 percent compared to 1.8 percent for fiscal year 2021. The decrease in operating income as a percentage of net sales was primarily driven by the increase in legal expenses related specifically to the SEC’s review of last year’s whistleblower complaint. +Net income for fiscal year 2022 was $3.4 million or $0.31 per share, as compared to $4.3 million or $0.39 per share for fiscal year 2021. Earnings for fiscal 2022 continued to be adversely impacted by supply chain and transportation and logistics issues, legal and other professional service expenses related specifically to the SEC’s review of last year’s whistleblower complaint, and increased interest expense. +19 +We maintained a strong balance sheet with a current ratio of 2.1 and a debt to equity ratio of 0.86. Total cash used in operating activities as defined on our cash flow statement was $4.9 million during fiscal year 2022. We maintained sufficient liquidity for our expected future operations. We believe cash flow from operations, our borrowing capacity, and equipment financing should provide adequate capital for planned growth over the long term. +RESULTS OF OPERATIONS +Comparison of the Fiscal Year Ended July 2, 2022 with the Fiscal Year Ended July 3, 2021 +The following table sets forth for the periods indicated certain items of the consolidated statements of income expressed as a percentage of net sales. The financial information and discussion below should be read in conjunction with the consolidated financial statements and Footnotes contained in this Annual Report on Form 10-K. +Fiscal Year Ended +July 2, 2022 % of +net sales July 3, 2021 % of +net sales $ change % point +change +Net sales $ 531,815 100.0% $ 518,698 100.0% $ 13,117 — +Cost of sales 488,601 91.9 476,659 91.9 11,942 — +Gross profit 43,214 8.1 42,039 8.1 1,175 — +Operating expenses: +Research, development and engineering 9,821 1.8 9,790 1.9 31 (0.1) +Selling, general and administrative 24,598 4.6 22,723 4.4 1,875 0.2 +Total operating expenses 34,419 6.4 32,513 6.3 1,906 0.1 +Operating income 8,795 1.7 9,526 1.8 (731) (0.1) +Interest expense, net 5,104 1.0 3,613 0.7 1,491 0.3 +Income before income taxes 3,691 0.7 5,913 1.1 (2,222) (0.4) +Income tax provision 314 0.1 1,572 0.3 (1,258) (0.2) +Net income $ 3,377 0.6% $ 4,341 0.8% $ (964) (0.2) +Effective income tax rate 8.5 % 26.6 % +Net Sales +The increase in net sales of $13.1 million from prior year period was primarily driven by an increase in new program wins and demand for current programs. However, partially offsetting the increase in revenue during fiscal year 2022, the Company’s revenue was constrained by the global supply chain and transportation issues that continued to limit production throughout the year and to a lesser extent the Chinese government mandated COVID-19 shutdown of our Shanghai, China facilities for most of the fourth quarter. +The following table shows the revenue by industry sectors as a percentage of revenue for fiscal years 2022 and 2021: +Fiscal Year Ended +July 2, 2022 July 3, 2021 +Consumer 48 51 +Industrial 41 38 +Communication 7 5 +Gaming 1 3 +Transportation 1 1 +Printers 1 1 +Computer and Peripheral 1 1 +Total 100% 100% +We provide services to customers in a number of industries and produce a variety of products for our customers in each industry. Key Tronic does not target any particular industry, but rather seeks to find programs that strategically fit our vertical manufacturing capabilities. As we continue to diversify our customer base and win new customers, we expect to continue to see a change in the industry concentrations of our revenue. +20 +Sales to foreign locations represented 17.6 percent and 28.2 percent of our total net sales in fiscal years 2022 and 2021, respectively. +Cost of Sales +Total cost of sales as a percentage of net sales was 91.9 percent in both fiscal years 2022 and 2021. +We record our inventories at net realizable value based on specific identification of inventory against current demand and recent usage. We also consider our customers' ability to pay for inventory whether or not there is a lead-time assurance agreement for a specific program. The amounts charged to expense for these inventories were approximately $950,000 and $753,000 in fiscal years 2022 and 2021, respectively. +We provide warranties on certain products we sell and estimate warranty costs based on historical experience and anticipated product returns. Warranty expense is related to workmanship claims on keyboards and other products. The amounts charged to expense are determined based on an estimate of warranty exposure. The net warranty expense was approximately $446,000 and $145,000 in fiscal years 2022 and 2021, respectively. +Gross Profit +Gross profit as a percentage of net sales was 8.1 percent in both fiscal years 2022, and 2021. +Changes in gross profit margins reflect the impact of a number of factors that can vary from period to period, including product mix, start-up costs and efficiencies associated with new programs, product life cycles, sales volumes, capacity utilization of our resources, management of inventories, component pricing and shortages, end market demand for customers’ products, fluctuations in and timing of customer orders, and competition within the contract manufacturing industry. These and other factors can cause variations in operating results. There can be no assurance that gross margins will not decrease in future periods. +Research, Development and Engineering +Research, development and engineering expenses (RD&E) consists principally of employee related costs, third party development costs, program materials, depreciation and allocated information technology and facilities costs. Total RD&E expenses were $9.8 million in both fiscal years 2022 and 2021. Total RD&E expenses as a percent of net sales was 1.8 percent in fiscal year 2022 and 1.9 percent in fiscal year 2021. +Selling, General and Administrative +Selling, general and administrative expenses (SG&A) consist principally of salaries and benefits, advertising and marketing programs, sales commissions, travel expenses, provision for doubtful accounts, facilities costs, and professional services. Total SG&A expenses were $24.6 million and $22.7 million in fiscal years 2022 and 2021, respectively. Total SG&A expenses as a percent of net sales were 4.6 percent and 4.4 percent in fiscal years 2022 and 2021, respectively. This 0.2 percentage point increase in SG&A as a percentage of net sales is primarily related to an increase in legal expenses related specifically to the SEC’s review of last year’s whistleblower complaint. +Interest Expense +We had net interest expense of $5.1 million and $3.6 million in fiscal years 2022 and 2021, respectively. The increase in interest expense is primarily related to an increase in the average balance outstanding on our line of credit, increased interest rates and financing leases. +Income Tax Provision +We had an income tax expense of approximately $0.3 million during fiscal year 2022 and an income tax expense of approximately $1.6 million during fiscal year 2021. The income tax expense recognized during both fiscal years 2022 and 2021 was primarily a function of U.S. and foreign taxes recognized at statutory rates, the net benefit associated with federal research and development tax credits, the benefit of carrying back the fiscal year 2021 net operating tax losses to years with higher federal tax rates in fiscal year 2022, the non-cash tax impact of expired stock appreciation rights in fiscal year 2021, and the recognition of previously unrecognized tax benefits for federal research and development tax credits in fiscal year 2020. +We continually review our requirements for liquidity domestically to fund current operations, revenue growth and to look for potential future acquisitions. We anticipate repatriating a portion of our unremitted foreign earnings. The estimated taxes associated with these expected repatriations are included in the income tax calculation. For further information on taxes please review Footnote “Income Taxes” of the “Notes to Consolidated Financial Statements.” +21 +International Subsidiaries +We offer customers a complete global manufacturing solution. Our facilities provide our customers the opportunity to have their products manufactured in the facility that best serves specific cost, product manufacturing and distribution needs. The locations of active foreign subsidiaries are as follows: +• Key Tronic Juarez, SA de CV owns five facilities and leases four facilities in Juarez, Mexico. These facilities include an SMT facility, an assembly and molding facility, a sheet metal fabrication facility, and assembly and warehouse facilities. This subsidiary is primarily used to support our U.S. operations. +• Key Tronic Computer Peripherals (Shanghai) Co., Ltd. leases one facility with SMT, assembly, global purchasing and warehouse capabilities in Shanghai, China, which began operations in 1999. Its primary function is to provide contract manufacturing services. +• Key Tronic Vietnam leases one facility in Da Nang, Vietnam. This facility includes SMT, assembly, and warehouse capabilities. Its primary function is to provide contract manufacturing services for export. +Foreign sales (based on shipping instructions) from our worldwide operations, including domestic exports, were $93.8 million and $146.5 million in fiscal years 2022 and 2021, respectively. Products and manufacturing services provided by our subsidiary operations are often shipped to customers directly by the parent company. +RESULTS OF OPERATIONS +Comparison of the Fiscal Year Ended July 3, 2021 with the Fiscal Year Ended June 27, 2020 +To review the results of operations comparison of the fiscal year ended July 3, 2021 with the fiscal year ended June 27, 2020, please refer to our Annual Report on Form 10-K filed September 16, 2021 with the Securities and Exchange Commission or follow the link below. +https://www.sec.gov/ix?doc=/Archives/edgar/data/719733/000071973321000106/ktcc-20210703.htm +Capital Resources and Liquidity +Operating Cash Flow +Net cash used in operating activities for fiscal year 2022 was $4.9 million compared to $15.1 million and $31.0 million in fiscal years 2021 and 2020, respectively. +The $4.9 million of net cash used in operating activities during fiscal year 2022 is primarily related to $3.4 million of net income adjusted for $7.6 million of depreciation and amortization, $25.6 million increase in accounts receivable, a $19.4 million increase in inventory, a $3.6 million increase in other liabilities, partially offset by a $28.6 million increase in accounts payable, and a $2.8 million decrease in contract assets. +The $15.1 million of net cash used in operating activities during fiscal year 2021 was primarily related to $4.3 million of net income adjusted for $6.9 million of depreciation and amortization, $24.3 million increase in accounts receivable, a $23.1 million increase in inventory, a $1.0 million increase in contract assets, a $2.3 million decrease in other assets, partially offset by a $12.6 million increase in accounts payable, a $5.6 million increase in other liabilities, and a $1.0 million increase in accrued compensation and vacation. +The $31.0 million of net cash used in operating activities during fiscal year 2020 was primarily related to $4.8 million of net income adjusted for $5.6 million of depreciation and amortization, $28.3 million increase in accounts receivable, a $14.7 million increase in inventory, a $7.7 million increase in other assets, a $1.6 million increase in contract assets, partially offset by a $6.6 million increase in accounts payable and a $3.7 million increase in accrued compensation and vacation. +Accounts receivable fluctuates based on the timing of shipments, terms offered and collections. We purchase inventory based on customer forecasts and orders, and when those forecasts and orders change, the amount of inventory may also fluctuate. Accounts payable fluctuates with changes in inventory levels, volume of inventory purchases, negotiated supplier terms, and taking advantage of early pay discounts. +Investing Cash Flow +Cash flows used in investing activities were $8.1 million for fiscal year 2022. Cash flows used in investing activities were $10.6 million and $3.6 million in fiscal year 2021 and 2020, respectively. Our primary use of cash in investing activities during fiscal years 2022, 2021 and 2020, was purchasing equipment to support increased production levels for new programs. During fiscal year 2022, cash flows used in investing activities also included prepayments on finance lease obligations. During fiscal year 2020, our primary source of cash provided by investing activities came from receipts of the deferred purchase price on factored receivables. +22 +Leases are often utilized when potential technical obsolescence and funding requirement advantages outweigh the benefits of equipment ownership. Capital expenditures and periodic lease payments are expected to be financed with internally generated funds as well as our revolving line of credit facility and equipment term loan . +Financing Cash Flow +Cash flows provided by financing activities were $11.2 million, $28.6 million, and $34.5 million in fiscal years 2022, 2021, and 2020. Our primary financing activities during fiscal year 2022, were proceeds from capital equipment finance leases and borrowings and repayments under our revolving line of credit facility; partially offset by repayments on our term loans and principal payments on finance leases. Our primary financing activities during fiscal year 2021 was repayments on our term loans of $11.7 million as well as borrowings and repayments under our revolving line of credit facility. Our primary financing activities during fiscal year 2020 was repayments on our term loans of $7.1 million as well as borrowings and repayments under our revolving line of credit facility. +As of July 2, 2022, the Company had an outstanding balance on the line of credit of $95.1 million. We had availability to borrow an additional $10.8 million under the asset-based revolving credit facility and we were in compliance with our loan covenants. Our cash requirements are affected by the level of current operations and new programs. We believe that projected cash from operations, funds available under the asset-based revolving credit facility and fixed asset financing will be sufficient to meet our working and fixed capital requirements for the foreseeable future. +As of July 2, 2022, we had approximately $1.7 million of cash held by foreign subsidiaries. Under the Tax Cuts and Jobs Act, future cash repatriations from these foreign subsidiaries are no longer subject to U.S. income taxes, but may be subject to foreign withholding taxes. See additional discussion in Footnote “Income Taxes” of the “Notes to Consolidated Financial Statements.” The total amount of foreign withholding taxes required to be paid for the amount of foreign subsidiary cash on hand as of July 2, 2022, would approximate $8,000. The Company also has approximately $28.9 million of foreign earnings that have not been repatriated to the U.S. Of that amount, the Company estimates that $7.1 million is to be repatriated in the future, requiring foreign withholding taxes of $0.7 million that is currently accrued in our deferred tax liabilities. The remaining $21.8 million is considered to be permanently reinvested in Mexico, China and Vietnam. If these amounts were required to be repatriated, we estimate it would create an additional $0.7 million in foreign withholding taxes payable. +Contractual Obligations +In the normal course of business, we enter into contracts which obligate us to make payments in the future. We have certain contractual obligations that extend beyond fiscal year 2023 under lease obligations and debt arrangements. +As of July 2, 2022, we had open purchase order commitments for materials and other supplies. Actual needs under these blanket purchase orders fluctuate with our manufacturing levels and as such cannot be broken out between fiscal years. In addition, we have contracts with many of our customers that minimize our exposure to losses for material purchased within lead-times necessary to meet customer forecasts. Purchase orders generally can be cancelled without penalty within specified ranges that are determined in negotiations with our suppliers. These agreements depend in part on the type of materials purchased as well as the circumstances surrounding any requested cancellations. We do not use off-balance sheet financing techniques other than traditional operating leases, and we have not guaranteed the obligations of any entity that is not one of our wholly owned subsidiaries. +For a summary of our lease obligations as of July 2, 2022, please refer to Footnote “Leases” of the “Notes to Consolidated Financial Statements.” +For a summary of our long-term debt obligations as of July 2, 2022, please refer to Footnote “Long-Term Debt” of the “Notes to Consolidated Financial Statements.” +23 +Critical Accounting Policies and Estimates +Preparation of our consolidated financial statements requires management to make estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses. Footnote “Significant Accounting Policies” of the “Notes to Consolidated Financial Statements” describes the significant accounting policies used in the preparation of our consolidated financial statements. Management believes the most complex and sensitive judgments, because of their significance to our consolidated financial statements, result primarily from the need to make estimates about effects of matters that are inherently uncertain. The most significant areas involving management judgments are described below. Actual results in these areas could differ from management’s estimates. +Revenue +The Company specializes in services ranging from product manufacturing to engineering and tooling services. The first step in its process for revenue recognition is to identify the contract with a customer. A contract is defined as an agreement between two or more parties that creates enforceable rights and obligations. A contract can be written, oral, or implied. The Company generally enters into manufacturing service agreements (“MSA”) with its customers that outlines the terms of the business relationship between the customer and the Company. This includes matters such as warranty, indemnification, transfer of title and risk of loss, liability for excess and obsolete inventory, pricing, payment terms, etc. The Company will also bid on a program-by-program basis for customers in which an executed MSA may not be in place. In these instances, as well as when we have an MSA in place, we receive customer purchase orders for specific quantities and timing of products. As a result, the Company considers its contract with a customer to be the combination of the MSA and the purchase order. The transaction price is fixed and set forth in each purchase order. In the Company's normal course of business, there are no variable pricing components, or material amounts refunded to customers in the form of refunds or rebates. +The Company assesses whether control of the product or services promised under the contract is transferred to the customer at a point in time (shipment) or over time (as we manufacture the product). The Company is first required to evaluate whether its contracts meet the criteria for 'over-time' or 'point-in-time' recognition. The Company has determined that for the majority of its contracts the Company is manufacturing products for which there is no alternative use due to the unique nature of the customer-specific product, IP and other contract restrictions. Further, the Company has an enforceable right to payment including a reasonable profit for performance completed to date with respect to these contracts. As a result, revenue is recognized under these contracts 'over-time' based on the input cost-to-cost method as it better depicts the transfer of control. This input method is based on the ratio of costs incurred to date as compared to the total estimated costs at completion of the performance obligation. For all other contracts that do not meet these criteria, such as manufacturing contracts for which the terms do not provide an enforceable right to payment for performance completed to date, the Company recognizes revenue when it has transferred control of the related manufactured products which generally occurs upon shipment to the customer. Revenue from engineering services is recognized over time as the services are performed. +Inactive, Obsolete, and Surplus Inventory Valuation +Inventories are stated at the lower of cost or net realizable value. Inventory valuation is determined using the first-in, first-out (FIFO) method. We write down inventories that we deem inactive, obsolete or surplus to net realizable value. The write down is calculated based upon the demand for the products that we produce to value this related inventory at net realizable value. Demand is determined by expected sales, customer purchase orders, or customer forecasts. If expected sales do not materialize, excess inventory would be the result and a write down of that inventory against earnings would occur. In the case where we have purchased material based upon a customer’s forecast or purchase orders, we are usually covered by lead-time assurance agreements or purchase orders with each customer. These contracts state that the financial liability for material purchased within agreed upon lead-time and based upon the customer’s forecasts, lies with the customer. If we purchase material outside the lead-time assurance agreement and the customer’s forecasts do not materialize or if we have no lead-time assurance agreement for a specific program, we would have the financial liability and may have to charge inactive, obsolete or surplus inventory against earnings. We also write down inventory values related to specific customers covered by lead-time assurance agreements when those customers are experiencing financial difficulties or reimbursement is not reasonably assured. +Allowance for Doubtful Accounts +We value our accounts receivable net of an allowance for doubtful accounts. As of July 2, 2022, the allowance for doubtful accounts was approximately $12,000. As of July 3, 2021, the allowance for doubtful accounts was approximately $275,000. This allowance is based on estimates of the portion of accounts receivable that may not be collected in the future. The estimates used are based primarily on specific identification of potentially uncollectible accounts. Such accounts are identified using publicly available information in conjunction with evaluations of current payment activity. However, if any of our customers were to develop unexpected and immediate financial problems that would prevent payment of open invoices, we could incur additional and possibly material expenses that would negatively impact earnings. +24 +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. We review the adequacy of this accrual quarterly based on historical analysis and anticipated product returns and rework costs. Our warranty period for keyboards is generally longer than that for other products. We only warrant materials and workmanship on products, and we do not warrant design defects for customers. +Income Taxes +Income tax expense includes U.S. and international income taxes and a provisional estimate for U.S. taxes on undistributed earnings of foreign subsidiaries. We do not record foreign withholding taxes on undistributed earnings of international subsidiaries that are deemed to be permanently reinvested. Certain income and expenses are not reported in tax returns and financial statements in the same year. The tax effect of such temporary differences is reported as deferred income taxes. The deferred income taxes are classified as long-term assets or liabilities. The most significant areas involving management judgments include deferred income tax assets and liabilities, uncertain tax positions, and research and development tax credits. Our estimates of the realization of the deferred tax assets related to our tax credits are based upon our estimates of future taxable income which may change. +Stock-Based Compensation +Stock-based compensation is accounted for according to FASB Accounting Standards Codification (ASC) 718, Compensation—Stock Compensation . ASC 718 requires us to expense the fair value of employee stock options, stock appreciation rights and other forms of stock-based compensation. Under the fair value recognition provisions of ASC 718, share-based compensation cost is estimated at the grant date based upon the fair value of the award and is recognized as expense ratably over the requisite service period of the award (generally the vesting period). Determining the appropriate fair value model and calculating the fair value of share-based awards requires judgment, including estimating the expected life of the share-based award, the expected stock price volatility over the expected life of the share-based award and forfeitures. +To determine the fair value of stock based awards on the date of grant we use the Black-Scholes option-pricing model. Inherent in this model are assumptions related to expected stock price volatility, option life, risk-free interest rate and dividend yield. The risk-free interest rate is a less-subjective assumption as it is based on factual data derived from public sources. We use a dividend yield of zero as we have never paid cash dividends and have no intention to pay cash dividends in the foreseeable future. The expected stock price volatility and option life assumptions require a greater level of judgment. Our expected stock-price volatility assumption is based upon the historical volatility of our stock which is obtained from public data sources. The expected life represents the weighted average period of time that share-based awards are expected to be outstanding, giving consideration to vesting schedules and historical exercise patterns. We determine the expected life assumption based upon the exercise and post-vesting behavior that has been exhibited historically, adjusted for specific factors that may influence future exercise patterns. If expected volatility or expected life were to increase, that would result in an increase in the fair value of our stock options which would result in higher compensation charges, while a decrease in volatility or the expected life would result in a lower fair value of our stock option awards resulting in lower compensation charges. +We estimate forfeitures for all of our awards based upon historical experience of stock-based pre-vesting forfeitures. We believe that our estimates are based upon outcomes that are reasonably likely to occur. If actual forfeitures are higher than our estimates it would result in lower compensation expense and to the extent the actual forfeitures are lower than our estimate we would record higher compensation expense. +Long-Term Incentive Compensation Accrual +Long-term incentive compensation is recognized as expense ratably over the requisite service period of the award which is generally three years. The Board of Directors approve target performance measures for the three year period for each of the Company’s officers and non-employee Directors. Performance measures are based on a combination of sales growth targets and return on invested capital targets. No cash awards will be made to participants if actual Company performance does not exceed the minimum target performance measures. The calculation used to determine the necessary accrual uses a combination of actual results and projected results. We believe that our estimates are based upon outcomes that are reasonably likely to occur. These estimates and assumptions are based on historical results as well as future expectations. Actual results could vary from our estimates and assumptions. +New and Future Accounting Pronouncements +See Footnote “Significant Accounting Policies” of the “Notes to Consolidated Financial Statements.” +25 +Item 7A: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Interest Rate Risk +We are subject to the risk of fluctuating interest rates in the normal course of business. Our major market risk relates to our secured debt. Our asset-based senior secured revolving credit facility, and equipment financing facility are secured by substantially all of our assets. The interest rates applicable to our asset-based senior secured revolving credit facility fluctuate with SOFR rates. There was outstanding $95.1 million in borrowings under our asset-based senior secured revolving credit facility and $7.9 million outstanding on our equipment financing facilities as of July 2, 2022. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity”in this Annual Report on Form 10-K and the Footnote “Long-Term Debt” of the “Notes to Consolidated Financial Statements” for additional information regarding our revolving credit facility and term loans. +Foreign Currency Exchange Risk +A significant portion of our operations are in foreign locations. As a result, transactions occur in currencies other than the U.S. dollar. Exchange rate fluctuations among other currencies used by us would directly or indirectly affect our financial results. We use Mexican peso forward contracts to hedge foreign currency fluctuations for a portion of our Mexican peso denominated expenses. There were no foreign currency forward contracts outstanding as of July 2, 2022. For additional information regarding our derivative instruments, please refer to Footnote “Derivative Financial Instruments” of the “Notes to Consolidated Financial Statements.” +26 +Item 8: +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Report of Independent Registered Public Accounting Firm +To the Shareholders and the Board of Directors of +Key Tronic Corporation +Opinion on the Financial Statements +We have audited the accompanying consolidated balance sheet of Key Tronic Corporation (the “Company”) as of July 2, 2022, the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for the year then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of July 2, 2022, and the consolidated results of its operations and its cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of July 2, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated September 13, 2022 expressed an unqualified opinion on the Company’s internal control over financial reporting. +Basis for Opinion +These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audit provides a reasonable basis for our opinion. +Critical Audit Matter +The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. +The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. +As described in Notes 1 and 13 to the consolidated financial statements, the Company reported revenue of $531.8 million for the year ended July 2, 2022, of which $515.8 million related to revenue recognized over time. The Company has determined that for the majority of its contracts the Company is manufacturing products for which there is no alternative use due to the unique nature of the customer-specific product, intellectual property, and other contract restrictions. The Company has an enforceable right to payment including a reasonable profit for performance completed to date with respect to these contracts. As a result, revenue is recognized under these contracts over-time based on the input cost-to-cost method as it better depicts the transfer of control. This input method is based on the ratio of costs incurred to date as compared to the total estimated costs at completion of the performance obligation. +We identified revenue recognized over time on contracts for manufacturing products as a critical audit matter. Management’s calculation includes reports with varying elements, to estimate costs incurred to date for various performance obligations. Auditing management’s estimates used in the calculation of revenue recognized over time involved especially challenging and subjective auditor judgment. +27 +The primary procedures we performed to address this critical audit matter included: +• Testing the design, implementation, and operating effectiveness of controls relating to revenue recognized over time, including controls over the quarterly calculation of in-process contracts, and the related contract assets. +• Evaluating the methodology of estimating costs incurred to date on in-process contracts and testing the completeness and accuracy of the system generated reports used to estimate costs incurred by recalculating the expected costs on in-process contracts, vouching to source documents, tracing in-process orders to subsequent sales and shipping documentation within a reasonable period after year-end, identifying and testing significant assumptions used in the revenue calculation, and performing data validation procedures. +• Comparing margins realized to trending historic margins, and comparing total revenue recognized to independent expectations of total revenues disaggregated by revenue stream. +• Performing cutoff procedures to test that revenue transactions were recorded in the appropriate period. +/s/ Moss Adams LLP +Seattle, Washington +September 14, 2022 +We have served as the Company’s auditor since 2021. +28 +Report of Independent Registered Public Accounting Firm +Shareholders and Board of Directors +Key Tronic Corporation +Spokane Valley, Washington +Opinion on the Consolidated Financial Statements +We have audited the accompanying consolidated balance sheets of Key Tronic Corporation (the “Company”) as of July 3, 2021, the related consolidated statements of income and comprehensive income, stockholders’ equity, and cash flows for each of the two years in the period ended July 3, 2021, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at July 3, 2021, and the results of its operations and its cash flows for each of the two years in the period ended July 3, 2021 , in conformity with accounting principles generally accepted in the United States of America. +Change in Accounting Principles +As discussed in Note 1 to the consolidated financial statements, the Company changed its accounting method for accounting for leases in fiscal year 2020 due to the adoption of Topic 842: Leases, using a modified retrospective approach. +Basis for Opinion +These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. +Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. +/s/ BDO USA, LLP +We have served as the Company's auditor from 2003 through 2021. +Spokane, Washington +September 16, 2021 +29 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED BALANCE SHEETS +(In thousands) +July 2, 2022 July 3, 2021 +ASSETS +Current assets: +Cash and cash equivalents $ 1,707 $ 3,473 +Trade receivables, net of allowance for doubtful accounts of $12 and $275 135,876 110,324 +Contract assets 21,974 24,781 +Inventories, net 155,741 137,329 +Other 24,710 23,345 +Total current assets 340,008 299,252 +Property, plant and equipment, net 26,012 35,735 +Operating lease right-of-use assets, net 16,731 15,745 +Other assets: +Deferred income tax asset 10,055 9,656 +Other 14,117 1,458 +Total other assets 24,172 11,114 +Total assets $ 406,923 $ 361,846 +LIABILITIES AND SHAREHOLDERS ’ EQUITY +Current liabilities: +Accounts payable $ 121,393 $ 92,823 +Accrued compensation and vacation 11,836 11,471 +Current portion of debt, net 7,402 2,143 +Other 23,036 20,268 +Total current liabilities 163,667 126,705 +Long-term liabilities: +Term loans 5,716 7,906 +Revolving loan 94,577 90,362 +Operating lease liabilities 12,023 11,428 +Deferred income tax liability 64 — +Other long-term obligations 5,998 1,740 +Total long-term liabilities 118,378 111,436 +Total liabilities 282,045 238,141 +Commitments and contingencies (Note 4 and 8) +Shareholders’ equity: +Common stock, no par value—shares authorized 25,000; issued and outstanding 10,762 and 10,762 shares, respectively 47,474 47,181 +Retained earnings 77,829 74,452 +Accumulated other comprehensive (loss) income ( 425 ) 2,072 +Total shareholders’ equity 124,878 123,705 +Total liabilities and shareholders’ equity $ 406,923 $ 361,846 +See accompanying notes to consolidated financial statements. +30 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF INCOME +(In thousands, except per share amounts) +Fiscal Year Ended +July 2, 2022 July 3, 2021 June 27, 2020 +Net sales $ 531,815 $ 518,698 $ 449,480 +Cost of sales 488,601 476,659 414,231 +Gross profit 43,214 42,039 35,249 +Research, development and engineering expenses 9,821 9,790 7,391 +Selling, general and administrative expenses 24,598 22,723 21,030 +Total operating expenses 34,419 32,513 28,421 +Operating income 8,795 9,526 6,828 +Interest expense, net 5,104 3,613 2,509 +Income before income taxes 3,691 5,913 4,319 +Income tax provision (benefit) 314 1,572 ( 439 ) +Net income $ 3,377 $ 4,341 $ 4,758 +Net income per share — Basic $ 0.31 $ 0.40 $ 0.44 +Weighted average shares outstanding — Basic 10,762 10,760 10,760 +Net income per share — Diluted $ 0.31 $ 0.39 $ 0.44 +Weighted average shares outstanding — Diluted 11,063 11,046 10,816 +See accompanying notes to consolidated financial statements. +31 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME +(In thousands) +Fiscal Year Ended +July 2, 2022 July 3, 2021 June 27, 2020 +Comprehensive income: +Net income $ 3,377 $ 4,341 $ 4,758 +Other comprehensive income: +Unrealized gain (loss) on hedging instruments, net of tax ( 2,497 ) 3,572 ( 3,926 ) +Comprehensive income $ 880 $ 7,913 $ 832 +Other comprehensive income for fiscal years 2022, 2021, and 2020 is reflected net of tax provision (benefit) of approximately $( 0.8 ) million, $ 1.2 million and $( 1.1 ) million, respectively. +See accompanying notes to consolidated financial statements. +32 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Fiscal Year Ended +July 2, 2022 July 3, 2021 June 27, 2020 +Operating activities: +Net income $ 3,377 $ 4,341 $ 4,758 +Adjustments to reconcile net income to cash used in operating activities: +Depreciation and amortization 7,562 6,856 5,591 +Amortization of interest rate swap 301 276 — +Amortization of deferred loan costs 143 95 30 +Excess tax benefit from exercise of stock options — ( 43 ) — +Inventory write-down to net realizable value 950 753 136 +Provision for warranty 446 145 121 +Provision for doubtful accounts 67 117 551 +(Gain) loss on disposal of assets ( 12 ) — 207 +Share-based compensation expense 293 192 266 +Deferred income taxes 481 ( 942 ) ( 958 ) +Changes in operating assets and liabilities +Trade receivables ( 25,619 ) ( 24,318 ) ( 28,254 ) +Contract assets 2,807 ( 1,028 ) ( 1,592 ) +Inventories ( 19,362 ) ( 23,062 ) ( 14,725 ) +Other assets ( 1,651 ) 2,317 ( 7,728 ) +Accounts payable 28,569 12,618 6,632 +Accrued compensation and vacation 365 1,043 3,669 +Other liabilities ( 3,624 ) 5,588 292 +Cash used in operating activities ( 4,907 ) ( 15,052 ) ( 31,004 ) +Investing activities: +Purchases of property and equipment ( 6,813 ) ( 10,602 ) ( 8,623 ) +Proceeds from sale of fixed assets 14 — 696 +Prepayments on finance lease obligations ( 1,252 ) — — +Cash receipts from deferred purchase price of factored receivables — — 4,350 +Cash used in investing activities ( 8,051 ) ( 10,602 ) ( 3,577 ) +Financing activities: +Payment of financing costs ( 118 ) ( 617 ) ( 84 ) +Proceeds from issuance of long term debt 11,594 11,000 5,000 +Interest rate swap termination fee — ( 925 ) — +Repayments of long term debt ( 2,143 ) ( 11,720 ) ( 7,121 ) +Borrowings under revolving credit agreement 581,893 414,943 177,343 +Repayments of revolving credit agreement ( 577,703 ) ( 384,150 ) ( 140,605 ) +Principal payments on finance leases ( 2,331 ) — — +Excess tax benefit from exercise of stock options — 43 — +Cash provided by financing activities 11,192 28,574 34,533 +Net increase (decrease) in cash and cash equivalents ( 1,766 ) 2,920 ( 48 ) +Cash and cash equivalents, beginning of period 3,473 553 601 +Cash and cash equivalents, end of period $ 1,707 $ 3,473 $ 553 +Supplemental cash flow information: +Interest payments $ 5,110 $ 3,777 $ 2,483 +Income tax payments, net of refunds $ 1,315 $ 2,014 $ 683 +Recognition of operating lease liabilities and right-of-use assets $ 5,247 $ 3,103 $ — +Recognition of financing lease liabilities and right-of-use assets $ 13,096 $ — $ — +See accompanying notes to consolidated financial statements. +33 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY +(In thousands) +Shares Common +Stock Retained +Earnings Accumulated +Other +Comprehensive +Income (Loss) Total +Shareholders’ +Equity +Balances, June 29, 2019 10,760 $ 46,680 $ 65,353 $ 2,426 $ 114,459 +Net income — — 4,758 — 4,758 +Unrealized loss on hedging instruments, net of tax — — — ( 3,926 ) ( 3,926 ) +Share-based compensation — 266 — — 266 +Balances, June 27, 2020 10,760 $ 46,946 $ 70,111 $ ( 1,500 ) $ 115,557 +Net income — — 4,341 — 4,341 +Unrealized gain on hedging instruments, net of tax — — — 3,572 3,572 +Exercise of stock appreciation rights 2 — — — — +Excess tax benefit from exercise of stock options 43 43 +Share-based compensation — 192 — — 192 +Balances, July 3, 2021 10,762 $ 47,181 $ 74,452 $ 2,072 $ 123,705 +Net income — — 3,377 — 3,377 +Unrealized loss on hedging instruments, net of tax — — — ( 2,497 ) ( 2,497 ) +Share-based compensation — 293 — — 293 +Balances, July 2, 2022 10,762 $ 47,474 $ 77,829 $ ( 425 ) $ 124,878 +See accompanying notes to consolidated financial statements. +34 +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. SIGNIFICANT ACCOUNTING POLICIES +Business +Key Tronic Corporation and subsidiaries (the Company) is engaged in contract manufacturing for original equipment manufacturers (OEMs) and also manufactures keyboards and other input devices. The Company’s headquarters are located in Spokane Valley, Washington with manufacturing operations in Oakdale, Minnesota; Fayetteville, Arkansas; Corinth, Mississippi; and foreign manufacturing operations in Juarez, Mexico; Shanghai, China; and Da Nang, Vietnam. +Due to the COVID-19 pandemic, the Company has seen extreme shifts in demand from its customer base, supply chain and logistics risks. The possibility of future temporary closures, as well as adverse fluctuations in customer demand, freight and expedite costs, precautionary safety expenses and labor shortages, collectability of accounts, and future supply chain disruptions during the rapidly changing COVID-19 environment can materially impact operating results. Additionally, continued adverse macroeconomic conditions and significant currency exchange fluctuations can also materially impact operating results. +Correction of an Immaterial Error +The Company made an out-of-period tax adjustment in fiscal year 2021 in the amount of $0.4 million decreasing the deferred tax asset related to unexercised stock appreciation rights (SARs), to reflect the fact that certain of the unexercised SARs had expired over several different periods prior to fiscal year 2021. +Principles of Consolidation +The consolidated financial statements include the Company and its wholly owned subsidiaries in the United States, Mexico, China and Vietnam. Intercompany balances and transactions have been eliminated during consolidation. +Use of Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates include the allowance for doubtful receivables, calculating inventory impairments related to obsolete and non-saleable inventories to value at net realizable value, deferred tax assets and liabilities, uncertain tax positions, impairment of long-lived assets, medical self-funded insurance liability, long-term incentive compensation accrual, the provision for warranty costs, and the fair value of stock appreciation rights granted under the Company’s share-based compensation plan. Due to uncertainties with respect to the assumptions and estimates, actual results could differ from those estimates. +Cash and Cash Equivalents +The Company considers investments with an original maturity of three months or less to be cash equivalents. Cash equivalents are carried at cost, which approximates fair value. The Company may have cash and cash equivalents at financial institutions that are in excess of federally insured limits from time to time. +Allowance for Doubtful Accounts +The Company evaluates the collectability of accounts receivable and records an allowance for doubtful accounts, which reduces the receivables to an amount that management reasonably estimates will be collected. A specific allowance is recorded against receivables considered to be impaired based on the Company’s knowledge of the financial condition of the customer. In determining the amount of the allowance, the Company considers several factors including the aging of the receivables, the current business environment and historical experience. After all attempts to collect a receivable have failed, the receivable is written off against the allowance. +Inventories +Inventories are stated at the lower of cost or net realizable value. Inventory valuation is determined using the first-in, first-out (FIFO) method. Customer orders are based upon forecasted quantities of product manufactured for shipment over defined periods. Raw material inventories are purchased to fulfill these customer requirements. Within these arrangements, customer demands for products frequently change, sometimes creating excess and obsolete inventories. The Company regularly reviews raw material inventories by customer for both excess and obsolete quantities. Wherever possible, the Company attempts to recover its full cost of excess and obsolete inventories from customers or, in some cases, through other markets. When it is determined that the Company’s carrying cost of such excess and obsolete inventories cannot be recovered in full, a charge is taken against income for the difference between the carrying cost and the estimated realizable amount. We also reserve for inventory related to specific customers covered by lead-time assurance agreements when those customers are experiencing financial difficulties or reimbursement is not reasonably assured. +35 +Property, Plant and Equipment +Property, plant and equipment are carried at cost and depreciated using straight-line methods over the expected useful lives of the assets. Repairs and maintenance costs are expensed as incurred. +Leases +Lease assets and liabilities are initially recognized based on the present value of lease payments over the lease term calculated using the Company’s incremental borrowing rate, unless the implicit rate is readily determinable. Our incremental borrowing rate represents the rate of interest that we would have to pay to borrow on a collateralized basis over a similar term in a similar economic environment. Lease assets also include any lease prepayments. Lease terms include options to extend or terminate the lease when it is reasonably certain that those options will be exercised. Leases are classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the consolidated statements of income. For further information, please refer to Footnote “Leases” of the “Notes to Consolidated Financial Statements.” +Impairment of Long-lived Assets +The Company, using its best estimates based on reasonable and supportable assumptions and projections, reviews assets for impairment whenever events or changes in circumstances have indicated that the carrying amount of its assets might not be recoverable. Impaired assets are reported at the lower of cost or fair value. +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. Management reviews the adequacy of this accrual quarterly based on historical analyses and anticipated product returns. +Self-funded Insurance +The Company self-funds its domestic employee health plans. The Company contracts with a separate administrative service company to supervise and administer the programs and act as its representative. The Company reduces its risk under this self-funded platform by purchasing stop-loss insurance coverage for high dollar individual claims. In addition, if the aggregate annual claims amount to more than 125 percent of expected claims for the plan year this insurance will also pay those claims amounts exceeding that level. +The Company estimates its exposure for claims incurred but not paid at the end of each reporting period and uses historical claims data supplied by the Company’s broker to estimate its self-funded insurance liability. This liability is subject to a total limitation that varies based on employee enrollment and factors that are established at each annual contract renewal. Actual claims experience may differ from the Company’s estimates. Costs related to the administration of the plan and related claims are expensed as incurred. +Revenue Recognition +The first step in its process for revenue recognition is to identify the contract with a customer. A contract is defined as an agreement between two or more parties that creates enforceable rights and obligations. A contract can be written, oral, or implied. The Company generally enters into manufacturing service agreements (“MSA”) with its customers that outlines the terms of the business relationship between the customer and the Company. This includes matters such as warranty, indemnification, transfer of title and risk of loss, liability for excess and obsolete inventory, pricing, payment terms, etc. The Company will also bid on a program-by-program basis for customers in which an executed MSA may not be in place. In these instances, as well as when we have an MSA in place, we receive customer purchase orders for specific quantities and timing of products. As a result, the Company considers its contract with a customer to be the combination of the MSA and the purchase order. The transaction price is fixed and set forth in each purchase order. In the Company's normal course of business, there are no variable pricing components, or material amounts refunded to customers in the form of refunds or rebates. +The Company assesses whether control of the product or services promised under the contract is transferred to the customer at a point in time (shipment) or over time (as we manufacture the product). The Company is first required to evaluate whether its contracts meet the criteria for 'over-time' or 'point-in-time' recognition. The Company has determined that for the majority of its contracts the Company is manufacturing products for which there is no alternative use due to the unique nature of the customer-specific product, IP and other contract restrictions. The Company has an enforceable right to payment including a reasonable profit for performance completed to date with respect to these contracts. As a result, revenue is recognized under these contracts 'over-time' based on the input cost-to-cost method as it better depicts the transfer of control. This input method is based on the ratio of costs incurred to date as compared to the total estimated costs at completion of the performance obligation. For all other contracts that do not meet these criteria, such as manufacturing contracts for which the terms do not provide an enforceable right to payment for performance completed to date, the Company recognizes revenue when it has transferred control of the related manufactured products which generally occurs upon shipment to the customer. Revenue from engineering services is recognized over time as the services are performed. +36 +Shipping and Handling Fees +The Company classifies costs associated with shipping and handling fees as a component of cost of goods sold. Customer billings related to shipping and handling fees are reported as revenue. +Research, Development and Engineering +Research, development and engineering expenses include unreimbursed contract manufacturing costs as well as design and engineering costs associated with the production of contract manufacturing programs. Research, development and engineering costs are expensed as incurred. +Income Taxes +Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the estimated future tax consequences and benefits attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities for a change in tax rates is recognized in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amount that is more likely than not to be realized. +We utilize a two-step approach to recognizing and measuring uncertain tax positions. The first step is to evaluate the tax position for recognition by determining if the weight of available evidence indicates it is more likely than not that the position will be sustained on audit, including resolution of related appeals or litigation processes, if any. The second step is to measure the tax benefit as the largest amount which is more than 50 % likely of being realized upon ultimate settlement. We consider many factors when evaluating and estimating our tax positions and tax benefits, which may require periodic adjustments based on new assessments and changes in estimates and which may not accurately forecast actual outcomes. Our policy is to recognize interest and penalties related to the underpayment of income taxes as a component of income tax provision. The tax years 2001 through the present remain open to examination by the major U.S. taxing jurisdictions to which we are subject. For further discussions, please refer to Footnote “Income Taxes” of the “Notes to Consolidated Financial Statements.” +Derivative Instruments and Hedging Activities +The Company has previously entered into foreign currency forward contracts and an interest rate swap which are accounted for as cash flow hedges in accordance with ASC 815, Derivatives and Hedging . The effective portion of the gain or loss on the derivative is reported as a component of accumulated other comprehensive income (AOCI) and is reclassified into earnings in the same period in which the underlying hedged transaction affects earnings. The derivative’s effectiveness represents the change in fair value of the hedge that offsets the change in fair value of the hedged item. As of July 2, 2022, the Company did not have any outstanding foreign currency forward contracts. +The Company uses derivatives to manage the variability of foreign currency fluctuations of expenses in our Mexico facilities. The foreign currency forward contracts and interest rate swaps have terms that are matched to the underlying transactions being hedged. As a result, these transactions fully offset the hedged risk and no ineffectiveness has been recorded. +The Company’s foreign currency forward contracts and interest rate swaps potentially expose the Company to credit risk to the extent the counterparties may be unable to meet the terms of the agreement. The Company minimizes such risk by seeking high quality counterparties. The Company’s counterparties to the foreign currency forward contracts and interest rate swaps are major banking institutions. These institutions do not require collateral for the contracts, and the Company believes that the risk of the counterparties failing to meet their contractual obligations is remote. The Company does not enter into derivative instruments for trading or speculative purposes. +Earnings Per Common Share +Basic earnings per common share is computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is computed by dividing net income by the combination of other potentially dilutive weighted average common shares and the weighted average number of common shares outstanding during the period using the treasury stock method. The computation assumes the proceeds from the exercise of stock options were used to repurchase common shares at the average market price during the period. The computation of diluted earnings per common share does not assume conversion, exercise, or contingent issuance of common stock equivalent shares that would have an anti-dilutive effect on earnings per share. +Foreign Currency Transactions +The functional currency of the Company’s subsidiaries in Mexico, China and Vietnam is the U.S. dollar. Realized foreign currency transaction gains and losses for local currency denominated assets and liabilities are included in cost of goods sold. +37 +Fair Value of Financial Instruments +The carrying values of cash and cash equivalents, accounts receivable, current liabilities, and non-current operating lease liability are reflected on the balance sheets at July 2, 2022 and July 3, 2021, reasonably approximate their fair value. The Company had an outstanding balance on the line of credit of $ 95.1 million as of July 2, 2022 and $ 90.9 million as of July 3, 2021, with a carrying value that reasonably approximates the fair value. The Company had an outstanding balance on the term loan of $ 3.3 million as of July 2, 2022 and $ 4.2 million as of July 3, 2021, with a carrying value that reasonably approximates the fair value. The equipment term loan was $ 4.6 million as of July 2, 2022 and $ 5.8 million as of July 3, 2021, with a carrying value that reasonably approximates the fair value. +Share-based Compensation +The Company’s incentive plan may provide for equity awards to employees in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, stock units, performance shares, performance units, and other stock-based awards. Compensation cost is recognized on a straight-line basis over the requisite employee service period, which is generally the vesting period, and is included in cost of goods sold, research, development and engineering, and selling, general, and administrative expenses. Share-based compensation is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on historical experience and future expectations. +Newly Adopted and Recent Accounting Pronouncements +In January 2021, FASB issued Accounting Standard Update (ASU) 2021-01, Reference Rate Reform (Topic 848) to identify alternative reference rates that are more observable or transaction based and less susceptible to manipulation. The Company is currently assessing the effects on its consolidated financial statements, and if it will elect this optional standard. +In March of 2020, the FASB issued ASU 2020-03, Codification Improvements to Financial Instruments, which clarifies specific issues raised by stakeholders. Specifically, the ASU clarifies the following: 1) that all entities are required to provide the fair value option disclosures in ASC 825, Financial Instruments 2) clarifies that the portfolio exception in ASC 820, Fair Value Measurement, applies to nonfinancial items accounted for as derivatives under ASC 815, Derivatives and Hedging; 3) clarifies that for purposes of measuring expected credit losses on a net investment in a lease in accordance with ASC 326, Financial Instruments - Credit Losses, the lease term determined in accordance with ASC 842, Leases, should be used as the contractual term; 4) clarifies that when an entity regains control of financial assets sold, it should recognize an allowance for credit losses in accordance with ASC 326; and 5) aligns the disclosure requirements for debt securities in ASC 320, Investments - Debt Securities, with the corresponding requirements for depository and lending institutions in ASC 942, Financial Services - Depository and Lending. The amendments in the ASU have various effective dates and transition requirements which are dependent on timing of adoption of ASU 2016-13. The Company is currently assessing the effects on its consolidated financial statements, and it intends to adopt the guidance as they become effective. +In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” and also issued subsequent amendments to the initial guidance: ASU 2018-19, ASU 2019-04 and ASU 2019-05, which replaces the existing incurred loss impairment model with an expected credit loss model and requires a financial asset measured at amortized cost to be presented at the net amount expected to be collected. The guidance is effective for the Company beginning in the first quarter of fiscal year 2024 with early adoption permitted. The Company is currently assessing the impact on its consolidated financial statements, and it intends to adopt the guidance when it becomes effective in the first quarter of fiscal year 2024. +As a result of adopting ASC 842, Leases , using a modified retrospective approach as of June 30, 2019, the Company recognized a right of use asset of $21.4 million, a corresponding lease liability of $20.4 million, a reduction in prepaid rent of $0.4 million, a reduction of favorable lease agreement intangible of $0.7 million, and no adjustment to retained earnings or future P&L impact. +Fiscal Year +The Company operates on a 52/53 week fiscal year. Fiscal years end on the Saturday nearest June 30. As such, fiscal years 2022, 2021, and 2020, ended on July 2, 2022, July 3, 2021, and June 27, 2020, respectively. Fiscal year 2021 was a 53 week year. Fiscal years 2022 and 2020 were 52 week years. +2. INVENTORIES +Net inventory as of July 2, 2022 is $ 155.7 million compared to $ 137.3 million as of July 3, 2021. Substantially all of the Company’s inventory balances are raw materials. +38 +3. PROPERTY, PLANT AND EQUIPMENT +Property, plant and equipment consists of the following: +Life July 2, 2022 July 3, 2021 +(in years) (in thousands) +Land — $ 4,034 $ 4,034 +Buildings and improvements 3 to 30 25,841 25,513 +Equipment 1 to 10 71,180 77,509 +Furniture and fixtures 3 to 5 5,286 5,271 +Total Property, Plant and Equipment 106,341 112,327 +Accumulated depreciation ( 80,329 ) ( 76,592 ) +Property, Plant and Equipment, net $ 26,012 $ 35,735 +Fiscal Year Ended +July 2, 2022 July 3, 2021 June 27, 2020 +(in thousands) +Depreciation expense $ 4,940 $ 6,631 $ 5,369 +4. LONG-TERM DEBT +On August 14, 2020, the Company entered into a loan agreement with Bank of America. The Loan Agreement replaces the Company’s prior amended and restated credit agreement, as amended, with Wells Fargo Bank. The Loan Agreement provides for a five-year asset-based senior secured revolving credit facility of up to $ 93 million, maturing on August 14, 2025. +Subsequent to July 2, 2022, the company entered into a third amendment to the loan agreement with Bank of America. The amendment removed the cash flow leverage ratio covenant and increased the interest rate by 25 basis points. +As of July 2, 2022, the Company had an outstanding balance under the asset-based revolving credit facility of $ 95.1 million, $ 0.3 million in outstanding letters of credit and $ 10.8 million available for future borrowings. +As of July 3, 2021, the Company had an outstanding balance under the asset-based revolving credit facility of $ 90.9 million, $ 0.3 million in outstanding letters of credit and $ 2.1 million available for future borrowings. +On August 14, 2020, the Company also entered into a $ 5.0 million equipment financing facility with Bank of America relating to the Company’s existing U.S. manufacturing equipment that bears interest at 4.85% and matures on August 14, 2025. Under this loan agreement, equal monthly payments of approximately $ 94,000 commenced on September 14, 2020 and will continue through the maturity of the equipment financing facility on August 14, 2025. As of July 2, 2022, the Company had an outstanding balance of $ 3.3 million. As of July 3, 2021, the Company had an outstanding balance of $ 4.2 million. +Generally, the interest rate applicable to loans under the Bank of America loan agreement are, at the Company’s option: (i)(A) the base rate which is the highest of (1) the prime rate for the applicable day (as such rate is determined from time to time by the Bank), (2) the federal funds rate for the applicable day plus 0.50%, and (3) LIBOR for a 30-day interest period as of the applicable day plus 1.00% (provided that in no event shall the base rate be less than zero), plus the applicable interest margin for base rate loans; and (B) LIBOR rate for an applicable interest period (provided that in no event shall the LIBOR rate be less than 0.50%), plus the applicable interest margin for LIBOR rate loans. Depending on average daily excess borrowing availability over applicable periods under the Credit Facility, applicable interest margins on: (x) base rate loans are 1.25-1.75%; and (y) LIBOR rate loans are 2.25-2.75%, resetting on a quarterly basis. If there is an event of default under the loan agreement, all loans and other obligations will bear interest at a rate of an additional 2.00% on the otherwise applicable interest rates. In addition to interest charges, the Company is required to pay a fee of 0.25% per annum on the unused portion of the Credit Facility, monthly in arrears. +Under the loan agreement with Bank of America, the asset-based revolving credit facility bears interest at LIBOR plus 2.5 %, as elected by the Company. +39 +On November 24, 2020, the Company entered into a $ 6.0 million equipment financing facility related to the Company’s existing manufacturing equipment that bears interest at 5.52% and matures on April 24, 2026. Under this loan agreement, equal monthly payments of $ 100,000 commenced on May 24, 2021 and will continue through the maturity of the equipment financing facility on April 24, 2026. The Company had an outstanding balance of $ 4.6 million and $ 5.8 million as of July 2, 2022 and July 3, 2021, respectively. +On September 3, 2021, the Company entered into an amendment to the Company's current loan agreement with Bank of America. The amendment increases the Company's current credit facility of $ 93 million to $120 million, subject to the Company's borrowing base, maturing on September 3, 2026. +The interest rates on outstanding debt as of July 2, 2022 range from 4.50 % - 5.52 % compared to 3.25 % - 5.52 % as of July 3, 2021. +Debt maturities as of July 2, 2022 for the next five years are as follows (in thousands): +Fiscal Years Ending Amount +2023 $ 2,190 +2024 2,239 +2025 2,290 +2026 1,187 +2027 95,077 +Total debt $ 102,983 +Unamortized debt issuance costs ( 499 ) +Long-term debt, net of debt issuance costs $ 102,484 +The Company must comply with certain financial covenants, including a fixed charge coverage ratio and a cash flow leverage ratio. The credit agreement requires the Company to grant certain inspection rights to Bank of America, limit or restrict the Company’s cash management; limit or restrict the ability of the Company to incur additional liens, make acquisitions or investments, incur additional indebtedness, engage in mergers, consolidations, liquidations, dissolutions, or dispositions, pay dividends or other restricted payments, prepay certain indebtedness, engage in transactions with affiliates, and use proceeds. Management believes the Company was in compliance with all financial covenants as of July 2, 2022. +5. TRADE ACCOUNTS RECEIVABLE PURCHASE PROGRAMS +Sale Programs +The Company has utilized an Account Purchase Agreement with Wells Fargo Bank, N.A. ("WFB") which allowed the Company to sell and assign to WFB and WFB to purchase from Company the accounts receivable of certain Company customers in a maximum aggregate amount outstanding of $ 25.0 million. As of July 2, 2022, the Company had no factored receivables with WFB. +The Company did not sell any accounts receivables during the twelve months ended July 2, 2022 or July 3, 2021. There were no accounts receivables sold and not yet collected as of July 2, 2022 or July 3, 2021. The receivables that were sold were removed from the consolidated balance sheets and the cash received is reflected as cash provided by operating activities in the consolidated statements of cash flows. Cash receipts related to the deferred purchase price from receivables factored by the Company is reflected as cash provided by investing activities. +40 +6. INCOME TAXES +Income tax benefit consists of the following: +Fiscal Year Ended +July 2, 2022 July 3, 2021 June 27, 2020 +(in thousands) +Current income tax benefit: +United States $ ( 2,179 ) $ 1,416 $ 365 +Foreign 2,012 1,098 154 +( 167 ) 2,514 519 +Deferred income tax benefit: +United States 443 ( 858 ) ( 1,850 ) +Foreign 38 ( 84 ) 892 +481 ( 942 ) ( 958 ) +Total income tax provision (benefit) $ 314 $ 1,572 $ ( 439 ) +The Company has gross tax credit carryforwards of approximately $ 11.0 million at July 2, 2022 consisting of federal research and development (R&D) tax credits, and approximately $ 1.9 million of net operating loss carryovers in China which expire in fiscal years 2025 through 2027. +Management has reviewed all deferred tax assets for purposes of determining whether or not a valuation allowance may be required. A valuation allowance against deferred tax assets is required if it is more likely than not that some of the deferred tax assets will not be realized. Based upon the Company’s profitability, forecasted income, and evaluation of all other positive and negative evidence, management determined that it is more likely than not that the deferred tax assets will be realized. +In the fourth quarter of fiscal year 2022, the Company, with its fiscal year 2021 federal income tax return, made automatic changes in tax accounting methods that created a fiscal year 2021 tax net operating loss. This loss is permitted to be carried back to the tax years ending in 2016, 2017, and 2019, resulting in a tax benefit of $0.6 million due to the higher federal income tax rate in effect in the years ending in 2016 and 2017. +On January 27, 2021, the Company received official notice from the Vietnamese tax authorities, confirming tax benefits awarded related to the Company’s principal product line in Vietnam (the “Tax Holiday”). Under the Tax Holiday, the tax rate applied to income derived from this product line will be zero percent for four years beginning with fiscal year 2021, then five percent for nine years, then ten percent for one year (as opposed to the normal twenty percent Vietnamese statutory rate). Consequently, Management has revalued its net operating loss in Vietnam at the zero percent Tax Holiday rate, as the net operating loss carryovers are projected to expire before the end of the Tax Holiday. The Company eliminated the deferred tax assets attributable to the Vietnam net operating loss carryover ($0.2 million) in the third quarter of fiscal year 2021. +The Company evaluated tax law changes and regulatory guidance issued through the quarter. Such changes and regulations include guidance under Sec. 162(m), Sec. 245A, Sec. 951A, foreign tax credits, and rules relating to consolidated NOL carryback claims. The Company evaluated the ongoing impact of these law and regulatory changes, which did not have a material impact on its provision for income taxes. Subsequent to the end of the fiscal year ending July 2, 2022, on August 16, 2022, the Inflation Reduction Act of 2022 was signed into law. This act includes a new book minimum tax on certain large corporations and an excise tax on corporate stock buybacks among other provisions. The Company is evaluating the impacts of this act, and at this time the Company does not believe they will have a material impact on our consolidated financial position, results of operations, or cash flows. +Subsequent to the end of the fiscal year ending June 27, 2020, the Treasury Department issued final regulations applicable to the Company’s position with respect to the U.S. taxability of foreign earnings under the global intangible low taxed income (also known as “GILTI”) regime and the deductibility of interest expense under IRC Section 163(j). These regulations did not have a material impact to the Company's income tax positions. +41 +On March 27, 2020, the Coronavirus Aid, Relief, and Economic Security Act (CARES Act) was enacted in response to the COVID-19 pandemic. The CARES Act, among other things, permits net operating loss (NOL) carryovers and carrybacks to offset 100% of taxable income for taxable years beginning before 2021. In addition, the CARES Act allows NOLs incurred in years beginning in 2018, 2019, and 2020 to be carried back to each of the five preceding taxable years to generate a refund of previously paid income taxes. The Company is taking advantage of this NOL carryback provision by carrying back the fiscal year 2021 NOL to the fiscal 2016 and 2017 years, as described above. In addition, the CARES Act contains modifications on the limitation of business interest for tax years beginning in 2019 and 2020. The modifications to Section 163(j) increase the allowable business interest deduction from 30% of adjusted taxable income to 50% of adjusted taxable income. This modification did not have a material impact on the fiscal year 2020 or fiscal year 2021 provisions for income taxes. Also, under the CARES Act, AMT credits not previously refunded for the tax year beginning in 2018 are refundable in the tax year beginning in 2019 rather than in years beginning in 2019-2021, and taxpayers can elect to claim 100% of the AMT credits in the first taxable year beginning in 2018 by applying for a tentative refund claim on or before December 31, 2020. The Company has made this election by applying for a tentative refund claim. The Company took advantage of the deferred payment payroll taxes provision, resulting in decreased deductible payroll tax payments, and increased taxable income, in fiscal years 2020 and 2021. Other aspects of the CARES Act did not have a material impact on the Company’s consolidated financial position, results of operations, or cash flows. +In future years, repatriations of cash will generally be tax-free in the U.S. However, withholding taxes in China may still apply to any such future repatriations. Management has not changed its indefinite investment assertions regarding to the portion of accumulated earnings and profits in China that may be repatriated in the future. Accordingly, management estimates that future repatriations of cash from China may result in approximately $ 0.7 million of withholding tax. There would be no offsetting foreign tax credits in the U.S. and as such, this potential liability is a direct cost associated with actual repatriations. Withholding taxes will not apply to future repatriations from Mexico or Vietnam. +The Company expects to repatriate a portion of its foreign earnings based on increased net sales growth driving additional capital requirements domestically, cash requirements for potential acquisitions and to implement certain tax strategies. The Company expects to repatriate approximately $ 7.1 million from China, in the future. All other unremitted foreign earnings are expected to remain permanently reinvested for planned fixed assets purchases and improvements in foreign locations. +42 +The Company’s effective tax rate differs from the federal tax rate as follows: +Fiscal Year Ended +July 2, 2022 July 3, 2021 June 27, 2020 +(in thousands) +Federal income tax provision at statutory rates $ 775 $ 1,242 $ 907 +State income taxes, net of federal tax effect 86 76 90 +Foreign tax rate differences 336 ( 36 ) 336 +Tax rate change — 184 — +Federal rate differences applied to net operating loss carryback +( 593 ) — — +Effect of income tax credits ( 920 ) ( 413 ) ( 310 ) +Previously unrecognized tax benefits 146 ( 296 ) ( 1,345 ) +Effect of repatriation of foreign earnings, net — ( 61 ) — +Tax penalties & interest 179 — — +Global Intangible Low-Taxed Income (GILTI) tax 59 34 — +Provision to return reconciliation ( 32 ) 50 ( 241 ) +Equity compensation shortfall 104 572 — +Other 174 220 124 +Income tax provision (benefit) $ 314 $ 1,572 $ ( 439 ) +The domestic and foreign components of income before income taxes were: +Fiscal Year Ended +July 2, 2022 July 3, 2021 June 27, 2020 +(in thousands) +Domestic $ ( 2,890 ) $ 2,839 $ 1,142 +Foreign 6,581 3,074 3,177 +Income before income taxes $ 3,691 $ 5,913 $ 4,319 +43 +Deferred income tax assets and liabilities consist of the following at: +July 2, 2022 July 3, 2021 +(in thousands) +Deferred tax assets: +Net operating loss $ 486 $ 465 +Tax credit carryforwards, net 7,990 3,581 +Inventory 247 1,190 +Identifiable intangibles 370 432 +Accruals 2,406 3,132 +Fixed assets 1,200 — +ASC 606 deferred costs 4,216 4,670 +Lease liabilities 3,671 2,909 +Interest expense deduction carryforward 580 — +Other 465 385 +Deferred income tax assets $ 21,631 $ 16,764 +Deferred tax liabilities: +Accrued withholding tax - unremitted earnings ( 754 ) ( 754 ) +Fixed assets — ( 794 ) +Right-of-use assets ( 3,663 ) ( 2,930 ) +Tax capital lease liabilities ( 2,385 ) — +Mark-to-market adjustments — ( 816 ) +ASC 606 accelerated revenue ( 3,736 ) ( 672 ) +Other ( 1,102 ) ( 1,142 ) +Deferred income tax liabilities $ ( 11,640 ) $ ( 7,108 ) +Net deferred income tax assets $ 9,991 $ 9,656 +Balance sheet caption reported in: +Long-term deferred income tax asset $ 10,055 $ 9,656 +Long-term deferred income tax liability ( 64 ) — +Net deferred income tax asset $ 9,991 $ 9,656 +Uncertain Tax Positions: +The Company has R&D tax credits that approximate $ 11.0 million that have 20 -year carryforwards before expiring. The Company’s R&D tax credits expire in various fiscal years from 2025 to 2042. +As of July 2, 2022, the Company had unrecognized tax benefits of $ 3.0 million related to its gross R&D tax credits. The unrecognized tax benefits relate to certain R&D tax credits generated from 2001 to 2022. +A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: +Fiscal Year Ended +July 2, 2022 July 3, 2021 June 27, 2020 +(in thousands) +Beginning Balance $ 4,863 $ 2,863 $ 4,099 +Additions based on tax positions related to the current year 286 193 109 +Adjustment to prior year tax positions & amended tax returns ( 2,296 ) 2,102 — +Lapse of statute of limitations 145 ( 295 ) ( 1,345 ) +Ending Balance $ 2,998 $ 4,863 $ 2,863 +The $ 2.998 million of unrecognized tax benefits at the end of fiscal year 2022, if recognized, would reduce the effective tax rate. Management does not anticipate any material changes to this amount during the next 12 months. +44 +The Company recognizes interest accrued related to unrecognized tax benefits and penalties in its income tax provision. The Company has not recognized any interest or penalties in the fiscal years presented in these financial statements, except for $0.2 million in fiscal year 2022. The Company is subject to income tax in the U.S. federal jurisdiction, various state jurisdictions, Mexico, China and Vietnam. Certain years remain subject to examination but there are currently no ongoing exams in any taxing jurisdiction. +7. EARNINGS PER SHARE +Basic earnings per share (EPS) is calculated by dividing net income (the numerator) by the weighted-average number of common shares outstanding (the denominator) during the period. Diluted EPS is computed by including both the weighted-average number of shares outstanding and any dilutive common share equivalents in the denominator. The following table presents a reconciliation of the denominator and the number of antidilutive common share awards that were not included in the diluted earnings per share calculation. These antidilutive securities occur when equity awards outstanding have an option price greater than the average market price for the period: +Fiscal Year Ended +(in thousands, except per share information) +July 2, 2022 July 3, 2021 June 27, 2020 +Net income $ 3,377 $ 4,341 $ 4,758 +Weighted average shares outstanding– basic 10,762 10,760 10,760 +Effect of dilutive common stock awards 301 286 56 +Weighted average shares outstanding – diluted 11,063 11,046 10,816 +Net income per share – basic $ 0.31 $ 0.40 $ 0.44 +Net income per share – diluted $ 0.31 $ 0.39 $ 0.44 +Antidilutive SARs not included in diluted earnings per share 619 314 720 +8. STOCK OPTION AND BENEFIT PLANS +The Company’s incentive plan provides for equity and liability awards to employees and non-employee directors in the form of stock options, stock appreciation rights (SARs), restricted stock, restricted stock units, stock awards, stock units, performance shares, performance units, and other stock-based or cash-based awards. Compensation cost is recognized on a straight-line basis over the requisite employee service period, which is generally the vesting period, and is recorded as employee compensation expense in cost of goods sold, research, development and engineering, and selling, general and administrative expenses. Share-based compensation is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on historical experience and future expectations. +In addition to service conditions, these SARs contain a performance condition. The additional performance condition is based upon the achievement of Return on Invested Capital (ROIC) goals relative to a peer group. All awards with performance conditions are measured over the vesting period and are charged to compensation expense over the requisite service period based on the number of shares expected to vest. The SARs cliff vest after a three-year period from date of grant and expire five years from date of grant. +On August 9, 2021, the Compa ny granted 165,000 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $ 7.17 and a grant date fair value of $ 2.73 . As of July 2, 2022, 165,000 remain outstanding. The grant date fair value for the awards granted during fiscal year 2022, were estimated using the Black Scho les option valuation method with the following weighted average assumptions as of August 9, 2021: +Fiscal Year 2022 +August 9, 2021 +Expected dividend yield — % +Risk – free interest rate 0.62 % +Expected volatility 48.58 % +Expected life 4.00 +45 +On July 23, 2020, the Company granted 155,000 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $ 6.94 and a grant date fair value of $ 2.32 . As of July 2, 2022, 150,000 remain outstanding. The grant date fair value for the awards granted during fiscal year 2021, were estimated using the Black Scholes option valuation method with the following weighted average assumptions as of July 23, 2020: +Fiscal Year 2021 +July 23, 2020 +Expected dividend yield — % +Risk – free interest rate 0.17 % +Expected volatility 42.85 % +Expected life 4.00 +On July 26, 2019, the Company granted 175,000 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $ 4.93 and a grant date fair value of $ 1.23 . As of July 2, 2022, 140,000 remain outstanding. The grant date fair value for the awards granted during fiscal year 2020, were estimated using the Black Scholes option valuation method with the following weighted average assumptions as of July 26, 2019: +Fiscal Year 2020 +July 26, 2019 +Expected dividend yield — % +Risk – free interest rate 1.54 % +Expected volatility 28.50 % +Expected life 4.00 +Subsequent to July 2, 2022, the Company granted 145,000 SARs with a strike price of $ 5.10 and a grant date fair value of $ 2.09 . +Share-based compensation expense is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on the Company’s historical experience and future expectations. This forfeiture rate will be revised, if necessary, in subsequent periods if actual forfeitures differ from the amount estimated. Share-based compensation expense for fiscal years ended July 2, 2022, July 3, 2021 and June 27, 2020 was $ 0.3 million, $ 0.2 million and $ 0.3 million, respectively. +The Black-Scholes option valuation model is used by the Company for estimating the fair value of SARs. Option valuation models require the input of highly subjective assumptions, particularly for the expected term and expected stock price volatility. Changes in these assumptions can materially affect the fair value estimates. +There were no SARs exercised during fiscal year 2022. There were 20,000 SARs exercised with an immaterial amount of intrinsic value in fiscal year 2021. There were no SARs exercised during fiscal year 2020. +As of July 2, 2022, total unrecognized compensation expense related to nonvested share-based compensation arrangements was approximately $ 0.4 million. This expense is expected to be recognized over a weighted-average period of 1.79 years. +46 +The following table summarizes the Company’s Options and SARs activity for all plans from June 30, 2019 through July 2, 2022: +SARs +Available +For Grant SARs +Outstanding Aggregate +Intrinsic +Value (in +thousands) Weighted +Average +Exercise +Price Weighted +Average +Remaining +Contractual +Life (in +years) +Balances, June 30, 2019 493,918 985,416 $ — $ 8.35 1.7 +Shares authorized — — +SARs granted ( 175,000 ) 175,000 4.93 +SARs forfeited 290,833 ( 290,833 ) 7.71 +SARs exercised — — — — +Balances June 27, 2020 609,751 869,583 $ — $ 7.87 1.9 +Shares authorized — — +SARs granted ( 155,000 ) 155,000 6.94 +SARs forfeited 213,333 ( 213,333 ) 9.88 +SARs exercised 20,000 ( 20,000 ) — 7.72 +Balances, July 3, 2021 688,084 791,250 $ — $ 7.15 1.9 +Shares authorized — — +SARs granted ( 165,000 ) 165,000 7.17 +SARs forfeited 197,500 ( 197,500 ) 8.17 +SARs exercised — — — — +Balances, July 2, 2022 720,584 758,750 $ — $ 6.89 2.1 +Exercisable at July 2, 2022 187,500 $ — $ 7.26 0.1 +Additional information regarding SARs outstanding and exercisable as of July 2, 2022, is as follows: +Range of +Exercise Prices Number Outstanding Weighted Avg. +Remaining +Contractual Life (yrs.) Weighted Avg. +Exercise Price Number +Exercisable Weighted +Avg. Exercise +Price +$4.40 – $7.90 642,500 2.2 $ 6.65 187,500 $ 7.26 +7.91 – 9.91 116,250 0.9 8.17 — — +$4.40 to $9.91 758,750 2.1 $ 6.89 187,500 $ 7.26 +The Company has defined contribution plans available to U.S. employees who have attained age 21. Company contributions to the plans were approximately $ 0.9 million, $ 0.9 million, and $ 0.8 million during fiscal years 2022, 2021 and 2020, respectively. +9. COMMITMENTS AND CONTINGENCIES +Leases : As of July 3, 2021 and June 27, 2020, the Company did not have any property and equipment financed under finance leases. Please refer to Footnote “Leases” of the “Notes to Consolidated Financial Statements” for information regarding lease commitments. +Warranty Costs : The Company provides warranties on certain product sales, and allowances for estimated warranty costs are recorded during the period of sale. The determination of such allowances requires the Company to make estimates of product return rates and expected costs to repair or to replace the products under warranty. The Company establishes warranty reserves based on historical warranty costs for each product line combined with liability estimates based on the prior twelve months’ sales activities. As of July 2, 2022 and July 3, 2021, the reserve for warranty costs was approximately $ 31,000 and $ 25,000 , respectively. +If actual return rates and/or repair and replacement costs differ significantly from estimates, adjustments to recognize additional cost of sales may be required in future periods. Warranty expense for fiscal years 2022, 2021 and 2020 was related to workmanship claims on certain contract manufacturing products. +47 +Litigation : The Company is party to certain lawsuits or claims in the ordinary course of business. The Company does not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on the financial position, results of operations or cash flow of the Company. +Internal Investigation : During fiscal 2021, the Company’s Audit Committee completed an internal investigation arising from a notification from an employee regarding certain alleged accounting irregularities. In January 2021, the Company determined that improper accounting resulted in an understatement of cost of goods sold and an overstatement of inventories. Subsequent to the matter identified in January 2021, additional inventory accounting errors unrelated to the investigation were also identified by management. The investigation did not result in a restatement of our previously filed financial statements. The Company is cooperating with the Securities and Exchange Commission’s (the “SEC”) inquiries related to the internal investigation. The Company cannot currently form an estimate of any possible loss or range of loss, including any potential monetary penalties; or other remedies potentially imposed by the SEC. +Indemnification Rights : Under the Company’s bylaws, the Company’s directors and officers have certain rights to indemnification by the Company against certain liabilities that may arise by reason of their status or service as directors or officers. The Company maintains director and officer insurance, which may cover certain liabilities arising from its obligation to indemnify its directors and officers and former directors in certain circumstances. +10. DERIVATIVE FINANCIAL INSTRUMENTS +As of July 2, 2022, the Company did not have any outstanding foreign currency forward contracts. During the fiscal year ended July 2, 2022, the Company entered into $ 13.9 million of foreign currency forward contracts and settled $ 24.6 million of such contracts. During the fiscal year ended July 3, 2021, the Company did not enter into any foreign currency forward contracts and settled $ 26.1 million of such contracts. During the fiscal year ended June 27, 2020, the Company entered into $ 23.8 million of foreign currency forward contracts and settled $ 26.7 million of such contracts. +On November 6, 2019, the Company entered into an interest rate swap contract with an effective date of November 6, 2019 and a termination date of September 30, 2022, related to the borrowings outstanding under the term loan with Wells Fargo Bank. This interest rate swap contract was terminated on August 14, 2020 when the Company entered into a loan and security agreement with Bank of America. At date of termination this interest rate swap was in a liability position of $ 148,400 , which will be amortized to interest expense over the original term of the swap. +On November 6, 2019, the Company entered into an interest rate swap contract with an effective date of November 6, 2019 and a termination date of November 1, 2023, related to the borrowings outstanding under the line of credit with Wells Fargo Bank. This interest rate swap contract was terminated on August 14, 2020 when the Company entered into a loan and security agreement with Bank of America. At date of termination this interest rate swap was in a liability position of $ 776,500 , which will be amortized to interest expense over the original term of the swap. +The following table summarizes the fair value of derivative instruments in the Consolidated Balance Sheets as of July 2, 2022 and July 3, 2021 (in thousands): +July 2, 2022 July 3, 2021 +Derivatives Designated as Hedging Instruments Balance Sheet Location Fair Value Fair Value +Foreign currency forward contracts & swaps Other current assets $ — $ 3,614 +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2022 (in thousands): +Derivatives Designated as Hedging Instruments Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) AOCI Balance +as of +July 3, 2021 Effective +Portion +Recorded In +AOCI Effective Portion +Reclassified From +AOCI Into Income AOCI Balance +as of +July 2, 2022 +Forward contracts Cost of sales $ 2,721 $ 950 $ ( 3,750 ) $ ( 79 ) +Interest rate swap Interest expense ( 649 ) — 303 ( 346 ) +Total $ 2,072 $ 950 $ ( 3,447 ) $ ( 425 ) +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2021 (in thousands): +48 +Derivatives Designated as Hedging Instruments Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) AOCI Balance +as of +June 27, 2020 Effective +Portion +Recorded In +AOCI Effective Portion +Reclassified From +AOCI Into Income AOCI Balance +as of +July 3, 2021 +Forward contracts Cost of sales $ ( 759 ) $ 4,621 $ ( 1,141 ) $ 2,721 +Interest rate swap Interest expense ( 741 ) ( 223 ) 315 ( 649 ) +Total $ ( 1,500 ) $ 4,398 $ ( 826 ) $ 2,072 +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2020 (in thousands): +Derivatives Designated as Hedging Instruments Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) AOCI Balance +as of +June 29, 2019 Effective +Portion +Recorded In +AOCI Effective Portion +Reclassified From +AOCI Into Income AOCI Balance +as of +June 27, 2020 +Forward contracts & swaps Cost of sales $ 2,424 $ ( 865 ) $ ( 2,318 ) $ ( 759 ) +Interest rate swap Interest expense 2 ( 782 ) 39 ( 741 ) +Total $ 2,426 $ ( 1,647 ) $ ( 2,279 ) $ ( 1,500 ) +As of July 2, 2022, the Company does not have any foreign exchange contracts with credit-risk-related contingent features. The Company is subject to the risk of fluctuating interest rates from our line of credit and foreign currency risk resulting from our China operations. The Company does not currently manage these risk exposures by using derivative instruments. +11. FAIR VALUE MEASUREMENTS +The Company has adopted ASC 820, Fair Value Measurements, which defines fair value, establishes a framework for assets and liabilities being measured and reported at fair value and expands disclosures about fair value measurements. There are three levels of fair value hierarchy inputs used to value assets and liabilities which include: Level 1 – inputs are quoted market prices for identical assets or liabilities; Level 2 – inputs other than quoted market prices included in Level 1 that are observable for the asset or liability, either directly or indirectly; and Level 3 – inputs are unobservable inputs for the asset or liability. There have been no changes in the fair value methodologies used at July 2, 2022 and July 3, 2021. +The following table summarizes the fair value of assets (liabilities) of the Company’s derivatives that are required to be measured on a recurring basis as of July 3, 2021 (in thousands): +July 3, 2021 +Level 1 Level 2 Level 3 Total +Fair Value +Financial Assets: +Foreign currency forward contracts — 3,614 — $ 3,614 +The Company had forward contracts to hedge known future cash outflows for expenses denominated in the Mexican peso and had an interest rate swap to mitigate risk associated with certain borrowings under the Company’s debt arrangement. These contracts were measured on a recurring basis based on the foreign currency spot rates and forward rates quoted by banks or foreign currency dealers. These contracts were marked to market using level 2 input criteria every quarter with the unrealized gain or loss, net of tax, reported as a component of shareholders’ equity in accumulated other comprehensive income (loss), as they qualified for hedge accounting. +The carrying values of cash and cash equivalents, accounts receivable, contract assets, and current liabilities are reflected on the balance sheets at July 2, 2022 and July 3, 2021, reasonably approximate their fair value. +The Company’s long-term debt, which is measured at amortized cost, primarily consists of an asset-based revolving credit facility, lease liability, and equipment loans. These borrowings bear interest at LIBOR plus 2.5% per the loan agreement. Each of these rates is a variable floating rate dependent upon current market conditions and the Company’s current credit risk as discussed in Footnote “Long-Term Debt” of the “Notes to Consolidated Financial Statements.” +As a result of the determinable market rates for our asset-based revolving credit facility and equipment loans, they are classified within Level 2 of the fair value hierarchy. Further, the carrying value of each of these instruments reasonably approximates their fair value as of July 2, 2022 and July 3, 2021. +49 +12. ENTERPRISE-WIDE DISCLOSURES +Operating segments are defined in ASC Topic 280, Segment Reporting as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker, or decision making group, in deciding how to allocate resources and in assessing performance. The Company’s chief operating decision maker is its Chief Executive Officer. As of July 2, 2022, the Company operates and internally manages a single operating segment, Electronics Manufacturing Services as this is the only discrete financial information that is regularly reviewed by the chief operating decision maker. This segment provides integrated electronic and mechanical engineering, assembly, sourcing and procurement, logistics, and new product testing for our customers. +Products and Services +Of the revenues for the years ended July 2, 2022, July 3, 2021, and June 27, 2020, contract manufacturing sales and services were $ 531.8 million, $ 518.7 million and $ 449.5 million, respectively. +Geographic Areas +Net sales and long-lived assets (property, plant, and equipment) by geographic area for the years ended and as of July 2, 2022, July 3, 2021 and June 27, 2020 are summarized in the following table. Net sales set forth below are based on the shipping destination. Long-lived assets information is based on the physical location of the asset and includes property, plant and equipment, net, and operating lease right-of-use assets, net. +Fiscal Year Ended +(in thousands) +2022 2021 2020 +Geographic net sales: +Domestic (U.S.) $ 438,018 $ 372,217 $ 338,766 +Foreign 93,797 146,481 110,714 +Total $ 531,815 $ 518,698 $ 449,480 +Long-lived assets: +United States $ 14,440 $ 20,949 $ 21,078 +Mexico 22,473 24,089 20,828 +Vietnam 5,229 5,919 6,567 +China 601 523 859 +Total $ 42,743 $ 51,480 $ 49,332 +Percentage of net sales made to customers located in the following countries: +Fiscal Year Ended +2022 2021 2020 +United States 82 % 72 % 75 % +China 16 25 19 +Other foreign countries (a) +2 3 5 +Canada — — 1 +Total 100 % 100 % 100 % +(a) No other individual foreign country accounted for 10% or more of the foreign sales in fiscal years 2021, 2020 or 2019. +50 +Significant Customers +The percentage of net sales to and trade accounts receivables from significant customers were as follows: +Percentage of Net Sales +Fiscal Year Percentage of Trade Accounts Receivable +Fiscal Year +2022 2021 2020 2022 2021 +Customer A 13 % * * 5 % * +Customer B 12 % 24 % 18 % 13 % 15 % +13. QUARTERLY FINANCIAL DATA (Unaudited) +Fiscal Year Ended July 2, 2022 +First +Quarter Second +Quarter Third +Quarter Fourth +Quarter +(in thousands, except per share amounts) +Net sales $ 132,762 $ 134,456 $ 138,391 $ 126,206 +Gross profit 10,138 9,808 11,508 11,760 +Income before income taxes 1,102 556 1,238 795 +Net income 815 587 1,007 968 +Net income per share - basic $ 0.08 $ 0.05 $ 0.09 $ 0.09 +Net income per share - diluted $ 0.07 $ 0.05 $ 0.09 $ 0.09 +Weighted average shares outstanding +Basic 10,762 10,762 10,762 10,762 +Diluted 11,052 11,057 11,062 11,071 +Fiscal Year Ended July 3, 2021 +First +Quarter Second +Quarter Third +Quarter Fourth +Quarter +(in thousands, except per share amounts) +Net sales $ 123,207 $ 128,262 $ 134,600 $ 132,629 +Gross profit 10,015 10,622 11,096 10,306 +Income before income taxes 2,115 1,872 1,556 370 +Net income 1,719 1,580 867 175 +Net income per share - basic $ 0.16 $ 0.15 $ 0.08 $ 0.02 +Net income per share - diluted $ 0.16 $ 0.14 $ 0.08 $ 0.02 +Weighted average shares outstanding +Basic 10,760 10,760 10,760 10,762 +Diluted 11,040 11,385 11,429 11,169 +14. REVENUE +Revenue Recognition +The Company specializes in services ranging from product manufacturing to engineering and tooling services. The first step in its process for revenue recognition is to identify the contract with a customer. A contract is defined as an agreement between two or more parties that creates enforceable rights and obligations. A contract can be written, oral, or implied. The Company generally enters into manufacturing service agreements (“MSA”) with its customers that outlines the terms of the business relationship between the customer and the Company. This includes matters such as warranty, indemnification, transfer of title and risk of loss, liability for excess and obsolete inventory, pricing, payment terms, etc. The Company will also bid on a program-by-program basis for customers in which an executed MSA may not be in place. In these instances, as well as when we have an MSA in place, we receive customer purchase orders for specific quantities and timing of products. As a result, the Company considers its contract with a customer to be the combination of the MSA and the purchase order. The transaction price is fixed and set forth in each purchase order. In the Company's normal course of business, there are no variable pricing components, or material amounts refunded to customers in the form of refunds or rebates. +51 +The Company assesses whether control of the product or services promised under the contract is transferred to the customer at a point in time (shipment) or over time (as we manufacture the product). The Company is first required to evaluate whether its contracts meet the criteria for 'over-time' or 'point-in-time' recognition. The Company has determined that for the majority of its contracts the Company is manufacturing products for which there is no alternative use due to the unique nature of the customer-specific product, IP and other contract restrictions. The Company has an enforceable right to payment including a reasonable profit for performance completed to date with respect to these contracts. As a result, revenue is recognized under these contracts 'over-time' based on the input cost-to-cost method as it better depicts the transfer of control. This input method is based on the ratio of costs incurred to date as compared to the total estimated costs at completion of the performance obligation. For all other contracts that do not meet these criteria, such as manufacturing contracts for which the terms do not provide an enforceable right to payment for performance completed to date, the Company recognizes revenue when it has transferred control of the related manufactured products which generally occurs upon shipment to the customer. Revenue from engineering services is recognized over time as the services are performed. +The Company’s typical payment terms are 30 to 45 days and its sales arrangements do not contain any significant financing component for its customers. +The Company generally provides a warranty for workmanship on its manufacturing contracts. Although we offer warranties on our products, our warranties are considered to be assurance-type in nature and do not cover anything beyond ensuring that the product is functioning as intended. Based on the guidance in ASC 606, assurance-type warranties do not represent separate performance obligations; therefore, the primary performance obligation in the majority of our contracts is the delivery of a specific good through the purchase order submitted by our customer. +The Company elected to not disclose information about remaining performance obligations as they are part of contracts that that have expected durations of one year or less. +The Company has elected to expense costs to obtain contracts as incurred as these costs are immaterial to the financial statements. +During fiscal 2022, 2021 and 2020, no revenues were recognized from performance obligations satisfied or partially satisfied in previous periods. +Contract Balances +A contract asset is recognized when the Company has recognized revenue, but has not issued an invoice for payment. Contract assets are classified separately on the condensed consolidated balance sheet and transferred to receivables when the right to payment becomes unconditional. +The following table summarizes the activity in the Company’s contract assets during the twelve months ended July 2, 2022 (in thousands): +Contract Assets +Beginning balance, July 3, 2021 +$ 24,781 +Revenue recognized 515,831 +Amounts collected or invoiced ( 518,638 ) +Ending balance, July 2, 2022 +$ 21,974 +The following table summarizes the activity in the Company’s contract assets during the twelve months ended July 3, 2021 (in thousands): +Contract Assets +Beginning balance, June 27, 2020 +23,753 +Revenue recognized 509,621 +Amounts collected or invoiced ( 508,593 ) +Ending balance, July 3, 2021 +$ 24,781 +52 +Disaggregation of Revenue +The following table presents the Company’s revenue disaggregated for the twelve months ended July 2, 2022 and the twelve months ended July 3, 2021 (in thousands): +Revenue +Recognition July 2, 2022 July 3, 2021 June 27, 2020 +Over-Time $ 515,831 $ 509,621 $ 441,405 +Point-in-Time 15,984 9,077 8,075 +Total $ 531,815 $ 518,698 $ 449,480 +Revenues and associated costs from engineering design, development services and tooling, which are performed under contract of short term durations, are recognized over time as the services are performed. Revenue from engineering design, development +services and tooling represented approximately 9.6 %, 5.6 % and 3.3 % of total revenue in fiscal year 2022, 2021 and 2020, respectively. +15. LEASES +The Company has several commitments under operating and financing leases for warehouses, manufacturing facilities, office buildings, and equipment with initial terms that expire at various dates during the next 1 year to 10 years. +The Company has some leases that include an extension clause. Management has considered the likelihood of exercising each extension option included and estimated the duration of the extension option, for those leases management determined to be reasonably certain, in calculating the lease term for measurement of the right of use asset and liability. +For operating leases, management assumed a discount rate of 4%. The weighted average discount rate is disclosed in the tables below. +The components of lease cost were as follows as of July 2, 2022, July 3, 2021 and June 27, 2020 (in thousands): +Year Ended Year Ended Year Ended +Lease cost Classification July 2, 2022 July 3, 2021 June 27, 2020 +Operating lease cost Cost of sales $ 6,442 $ 4,818 $ 4,511 +Operating lease cost Selling, general and administrative expenses 929 1,270 1,266 +Financing lease cost Cost of sales $ 2,054 $ — $ — +Financing lease cost Selling, general and administrative expenses $ 64 $ — $ — +Total lease cost $ 9,489 $ 6,088 $ 5,777 +Fixed lease cost $ 7,941 $ 4,943 $ 5,335 +Short-term lease cost $ 1,548 $ 1,145 $ 442 +Total lease cost $ 9,489 $ 6,088 $ 5,777 +53 +Amounts reported in the Consolidated Balance Sheet as of July 2, 2022 and July 3, 2021 were (in thousands, except weighted average lease term and discount rate): +July 2, 2022 July 3, 2021 +Operating Leases: +Operating lease right of use assets $ 16,731 $ 15,745 +Operating lease liabilities (1) +16,731 15,653 +Weighted-average remaining lease term (in years) +Operating leases 5.28 5.95 +Weighted-average discount rate +Operating leases 4.00 % 4.05 % +Financing Leases (2) : +Financing lease right of use assets $ 12,464 $ — +Financing lease liabilities 11,211 — +Weighted-average remaining lease term (in years) +Financing leases 2.56 0.00 +Weighted-average discount rate +Financing leases 8.82 % — % +(1) For fiscal year 2022 and 2021, the current portion of the total operating lease liabilities is classified under Other Current Liabilities. +(2) The total finance lease right of use assets of $12.5 million is classified under Other Long-term Assets. The current portion of the total finance lease liabilities of $5.2 million is classified under Current portion of debt, net, resulting in $6.0 million classified in Other Long-term Liabilities section of the condensed consolidated balance sheet. +54 +Other information related to leases was as follows (in thousands): +July 2, 2022 July 3, 2021 June 27, 2020 +Cash paid for amounts included in the measurement of lease liabilities: +Operating cash flows from operating leases 4,261 4,976 4,237 +Financing cash flows used in financing leases 2,331 — — +Future lease payments under non-cancellable leases as of July 2, 2022 are as follows (in thousands): +Fiscal Years Ending Operating Leases Finance Leases +2023 $ 4,709 $ 5,213 +2024 3,811 3,960 +2025 2,972 2,539 +2026 2,351 107 +2027 1,450 71 +Thereafter 3,071 — +Total undiscounted lease payments 18,364 11,890 +Less: present value discount 1,633 679 +Total lease liabilities $ 16,731 $ 11,211 +Item 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES +None +Item 9A: CONTROLS AND PROCEDURES +55 +Evaluation of Disclosure Controls and Procedures +It is the responsibility of our management to establish, maintain, and monitor disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 (the “Exchange Act”) are recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Additionally, these disclosure controls include controls and procedures that are designed to accumulate and communicate the information required to be disclosed to our Company’s Chief Executive Officer and Chief Financial Officer, allowing for timely decisions regarding required disclosures. +As of the end of the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(f). Based on our assessment, we believe that as of July 2, 2022, the Company’s disclosure controls and procedures are effective based on that criteria. +Management’s Report on Internal Control over Financial Reporting +Our management has the responsibility to establish and maintain adequate internal controls over our financial reporting, as defined in Rule 13a-15(f) under the Securities and Exchange Act of 1934. Our internal controls are designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our external financial statements in accordance with generally accepted accounting principles (GAAP). +Due to inherent limitations of any internal control system, management acknowledges that there are limitations as to the effectiveness of internal controls over financial reporting and therefore recognize that only reasonable assurance can be gained from any internal control system. Accordingly, our internal control system may not detect or prevent material misstatements in our financial statements and projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, we have performed an assessment of the effectiveness of our internal controls over financial reporting as of July 2, 2022. This assessment was based on the criteria established in Internal Control-Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that as of July 2, 2022, the Company’s internal control over financial reporting is effective based on that criteria. +The effectiveness of the Company's internal control over financial reporting as of July 2, 2022 has been audited by Moss Adams LLP, an independent registered public accounting firm, as stated in their report which is included herein. +Changes in Internal Control over Financial Reporting +There have been no significant changes in our internal controls over financial reporting during our fourth fiscal quarter ended July 2, 2022 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)). +56 +Report of Independent Registered Public Accounting Firm +To the Shareholders and the Board of Directors of +Key Tronic Corporation +Opinion on Internal Control over Financial Reporting +We have audited Key Tronic Corporation’s (the “Company”) internal control over financial reporting as of July 2, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of July 2, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheet of Key Tronic Corporation as of July 2, 2022, the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for the year then ended, and the related notes (collectively referred to as the “consolidated financial statements”) and our report dated September 14, 2022 expressed an unqualified opinion on those consolidated financial statements. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control Over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ Moss Adams LLP +Seattle, Washington +September 14, 2022 +We have served as the Company’s auditor since 2021. +57 +Item 9B: OTHER INFORMATION +None +Item 9C: +DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS +Not applicable. +PART III +Item 10: DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Directors of the Registrant +Information on the nominees for election as Directors of the Company is incorporated herein by reference from the Company’s definitive proxy statement for the 2022 Annual Meeting of Shareholders to be filed pursuant to Regulation 14A under the Exchange Act no later than 120 days after the end of the Company’s 2022 fiscal year (the “2022 Proxy Statement”). +Executive Officers of the Registrant +This information is included in a separate item captioned “Executive Officers of the Registrant” in Item 1 of Part 1 of this Annual Report on Form 10-K pursuant to Instruction G(3) of Form 10-K and Instruction 3 to Item 401(b) of Regulation S-K and is incorporated herein by reference. +Compliance with Section 16(a) of the Exchange Act: +Information under the caption “Delinquent Section 16(a) Reports” in the Company’s 2022 Proxy Statement is incorporated herein by this reference. +Code of Conduct +The Board of Directors has adopted a written Code of Conduct which applies to its directors and employees, including its executive officers. The Code of Conduct is available on the Company’s website at www.keytronic.com . The Company intends to disclose on its website any amendments to or waivers of the Code of Conduct. +Item 11: EXECUTIVE COMPENSATION +Information appearing under the caption “Executive Compensation” in the Company’s 2022 Proxy Statement is incorporated herein by this reference. +Item 12: SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The following table sets forth the aggregate information for the Company’s equity compensation plans in effect as of July 2, 2022. +EQUITY COMPENSATION PLAN INFORMATION +Plan category Number of securities to +be issued upon exercise +of outstanding options, +warrants, and rights +(a) Weighted-average +exercise price of +outstanding options, +warrants, and rights +(b) Number of securities +remaining available for +future issuance under +equity compensation +plans (excluding +securities reflected in +column (a) +(c) +Equity compensation plans approved by security holders (1) +758,750 $ 6.89 720,584 +Equity compensation plans not approved by security holders — $ — — +Total 758,750 $ 6.89 720,584 +(1) Included are the 1,200,000 shares subject to the 2010 Plan, the issuance of which were approved by the shareholders at the 2010 Annual Meeting. During the 2015 Annual Meeting, an additional 1,000,000 shares were approved. As a result of the shareholder approval, the Company made the decision to amend the cash-settled SARs granted during fiscal year 2010 to stock-settled SARs effective October 21, 2011. +Information under the caption “Beneficial Ownership of Securities” in the Company’s 2022 Proxy Statement is incorporated herein by this reference. +58 +Item 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions” and “Directors’ Independence” in the Company’s 2022 Proxy Statement is incorporated herein by this reference. +Item 14: PRINCIPAL ACCOUNTANT FEES AND SERVICES +Our independent registered public accounting firm is Moss Adams LLP , Seattle, Washington , Auditor Firm ID: 659 . +Information appearing under the caption “Principal Accountant Fees and Services” in the Company’s 2022 Proxy Statement is incorporated herein by this reference. +PART IV +Item 15: EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +(a) 1. FINANCIAL STATEMENTS +Page in Form 10-K +FINANCIAL STATEMENTS +Report of Independent Registered Public Accounting Firm (Moss Adams, LLP) +27 +Report of Independent Registered Public Accounting Firm (BDO USA, LLP) (BDO USA, LLP; Spokane, Washington; PCAOB ID#243) +29 +Consolidated Balance Sheets +30 +Consolidated Statements of Income +31 +Consolidated Statements of Comprehensive Income +32 +Consolidated Statements of Cash Flows +33 +Consolidated Statements of Shareholders’ Equity +34 +Notes to Consolidated Financial Statements +35 +59 +3. EXHIBITS +Exhibit No. Description +3.1 +Articles of Incorporation +3.2 +Bylaws, as amended +4.1 +Description of the Company’s securities +10.1* +2010 Incentive Plan, incorporated by reference to Exhibit 10.36 to the Company’s Form 10-K for the year ended July 3, 2010 +10.2* +Description of Employment Contact of Craig D. Gates, incorporated by reference to the Company’s 1998 Proxy Statement, pages 10 and 11 +10.3* +Addenda to Employment Contract of Craig D. Gates, incorporated by reference to Exhibit 10.4 to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.4* +Addenda to Employment Contract of Craig D. Gates, incorporated by reference to Exhibit 10.2 to the Company’s Form 10-K for the year ended June 29, 2002 +10.5* +Amendment to Employment Contract of Craig D. Gates, dated August 23, 2011 incorporated by reference to Exhibit 10.40 to the Company’s Form 10-K for the year ended July 2, 2011 +10.6* +Amendment to Employment Contract of Craig D. Gates, dated May 10, 2012, incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q for the quarter ended March 31, 2012 +10.7* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2019 and Fiscal Years 2019 – 2021 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 2, 2018 +10.8* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2020 and Fiscal Years 2020 – 2022 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 30, 2019 +10.9* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2021 and Fiscal Years 2021 – 2023 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 27, 2020 +10.10* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2022 and Fiscal Years 2022 – 2024 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 13, 2021 +10.11* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2023 and Fiscal Years 2023 – 2025 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 4, 2022 +10.12 +Announcement that the Company has signed a letter of intent to lease a new facility in Da Nang, Vietnam +60 +10.13 +Stock Purchase Agreement, dated September 3, 2014, by and among the Company, CDR Manufacturing Inc. and the sellers signatory thereto, incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K filed on September 9, 2014 +10.14 +Loan and Security Agreement, dated August 14, 2020, among the Company, Bank of America, N.A, and certain other parties, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed August 17, 2020 +10.15 +First Amendment to Loan and Security Agreement, dated November 10, 2020, among the Company, Bank of America, N.A, and certain other parties, submitted herewith +10.16 +Second Amendment to Loan and Security Agreement, dated September 3, 2021, among the Company, Bank of America, N.A, and certain other parties, incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed September 10, 2021 +10.17 +Third Amendment to Loan and Security Agreement, dated August 26, 2022, among the Company, Bank of America, N.A, and certain other parties, incorporated by reference to Exhibit 10.2, submitted herewith +21.1 +Subsidiaries of Registrant, submitted herewith +23.1 +Consent of Independent Registered Public Accounting Firm - Moss Adams LLP, submitted herewith +23.2 +Consent of Independent Registered Public Accounting Firm - BDO USA, LLP, submitted herewith +31.1 +Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer, submitted herewith +31.2 +Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer, submitted herewith +32.1 +Section 1350 Certification of Chief Executive Officer, submitted herewith +32.2 +Section 1350 Certification of Chief Financial Officer, submitted herewith +101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. +101.SCH XBRL Taxonomy Extension Schema Document ** +101.CAL XBRL Taxonomy Extension Calculation Linkbase Document ** +101.DEF XBRL Taxonomy Extension Definition Linkbase Document ** +101.LAB XBRL Taxonomy Extension Label Linkbase Document ** +101.PRE XBRL Taxonomy Extension Presentation Linkbase Document ** +104 Cover Page Interactive Data File (formatted as inline XBRL with applicable taxonomy extention information contained in Exhibits 101.INS, 101.SCH, 101.CAL, 101.DEF, 101.LAB and 101.PRE) +* Management contract or compensatory plan or arrangement +61 +Item 16: FORM 10-K SUMMARY +None +62 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +Dated: September 14, 2022 +KEY TRONIC CORPORATION +By: /s/ Craig D. Gates +Craig D. Gates, President and Chief Executive Officer +(Principal Executive Officer) +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated: +/s/ Craig D. Gates September 14, 2022 +Craig D. Gates Date +Director and President and Chief Executive Officer +(Principal Executive Officer) +/s/ Brett R. Larsen September 14, 2022 +Brett R. Larsen Date +Executive Vice President of Administration, Chief Financial Officer and Treasurer +(Principal Financial Officer and Principal Accounting Officer) +/s/ Ronald F. Klawitter September 14, 2022 +Ronald F. Klawitter, Director Date +/s/ James R. Bean September 14, 2022 +James R. Bean, Director Date +/s/ Subodh K. Kulkarni September 14, 2022 +Subodh K. Kulkarni, Director Date +/s/ Yacov A. Shamash September 14, 2022 +Yacov A. Shamash, Director Date +/s/ Patrick Sweeney September 14, 2022 +Patrick Sweeney, Director and Chairman of the Board Date +63 \ No newline at end of file diff --git a/raw/filings/0000719733/2022/0000719733-22-000063/filing_metadata.csv b/raw/filings/0000719733/2022/0000719733-22-000063/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..36b2a2f5884caa20ec41d40469ce3dbb1fcf6a71 --- /dev/null +++ b/raw/filings/0000719733/2022/0000719733-22-000063/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000719733,KTCC,KEY TRONIC CORP,10-K,2022-09-14,2022-07-02,2022-09-14T20:28:31.000Z,0000719733-22-000063,ktcc-20220702.htm,10-K,14528079,1,1,https://www.sec.gov/Archives/edgar/data/719733/000071973322000063/ktcc-20220702.htm,https://www.sec.gov/Archives/edgar/data/719733/000071973322000063/,2022,2022,1 diff --git a/raw/filings/0000719733/2022/0000719733-22-000063/item1.txt b/raw/filings/0000719733/2022/0000719733-22-000063/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..bb35e548fb1391591db59c47fe0fdc12fcd10f1c --- /dev/null +++ b/raw/filings/0000719733/2022/0000719733-22-000063/item1.txt @@ -0,0 +1,74 @@ +Item 1. BUSINESS +Background +Key Tronic Corporation was organized in 1969, as a Washington corporation that locally manufactured computer keyboards. The ability to design, build and deliver a quality product led us to become a leading independent manufacturer of keyboards for computers in the United States. Our fully integrated design, tooling, and automated manufacturing capabilities enabled us to rapidly respond to customers’ needs for keyboards in production quantities worldwide. We supported our sales growth through the development and purchase of international manufacturing facilities. As the computer keyboard market matured with increasing competition from other international providers, we determined that our business could no longer solely rely on keyboard sales. +After assessing market conditions and our strengths and capabilities, we shifted our focus from keyboard manufacturing to contract manufacturing for a wide range of products. Our unique strategic attributes are based on our core strengths of innovative design and engineering expertise in electronics, mechanical engineering, sheet metal fabrication and stamping, and precision plastics combined with high-quality, low cost production, and assembly on an international basis while providing exceptional customer service. These strengths have made our company a strong competitor in the contract manufacturing market. +Our Industry and Strategy +The expansion of the contract manufacturing industry and our acquisitions have allowed us to continue to expand our customer base and the industries that we serve. The increase in new programs represents a growing portion of our revenue and a promising foundation for our future. In keeping with our long-term strategic objectives, we have been successfully building a more diversified customer portfolio, spanning a wider range of industries. We currently offer our customers the following services: integrated electronic and mechanical engineering, precision plastic molding, sheet metal fabrication, printed circuit board (PCB) and complete product assembly, component selection, sourcing and procurement, worldwide logistics, and new product testing and production all at competitive pricing due to our global footprint. We differentiate ourselves from others our size and larger in the contract manufacturing industry by providing vertical integration, a flexible and responsive approach to our customer’s changing supply demand, and complete design engineering support. +We believe that we are well positioned in the contract manufacturing industry to continue the expansion of our customer base and achieve long-term growth. Our unique blend of multinational facilities, vertical integration, centralized management, and core strengths continue to support our growth and our customers’ needs. We continue to focus on controlling operating expenses and leveraging the synergistic capabilities of our world-class facilities in the United States, Mexico, China and Vietnam. This international production capability provides our customers with the benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs, and reduced product fulfillment time. Given our competitive advantages and the growing pressure for new potential customers to move forward with their outsourcing strategies, we feel that we are strongly positioned to win new business in coming periods and grow our revenue and profits. +4 +The contract manufacturing industry is intensely competitive. Although our customer base is growing, we still have less than 1% of the potential global market and our revenue can fluctuate significantly due to reliance on a concentrated base of customers. We are planning for new customer growth in the coming quarters by seeking to secure new programs with new and existing customers, increase our worldwide manufacturing capacity, leverage further our design engineering capabilities and continue to improve our manufacturing and procurement processes and capabilities. Ongoing challenges that we face include but are not limited to the following: continuing to win programs from new and existing customers, balancing capital employed, production capacity and key personnel in support of new customer programs, improving operating efficiencies, controlling costs while developing competitive pricing strategies, and successfully transitioning new program wins to full production. +Customers and Marketing +We provide a mix of manufacturing services for outsourced Original Equipment Manufacturing (OEM) products. We provide the following services: product design, surface mount technologies (SMT) and pin through hole capability for printed circuit board assembly, tool making, precision plastic molding, sheet metal fabrication and painting, liquid injection molding, complex assembly, prototype design and full product assembly. +Sales of the majority of our products have not historically been seasonal in nature, but may be seasonal in the future if there are changes in the types of products manufactured. Sales can, however, fluctuate significantly between quarters from changes in customers and customer demand due to the concentration of sales generated by our largest customers. +For the fiscal years 2022, 2021 and 2020, the five largest customers in each year accounted for 40%, 40% and 41% of combined total net sales, respectively. We continue to diversify our customer base by adding additional programs and customers. We expect net sales to our five largest customers as a percentage of total net sales to approximate current levels going forward. +The following table summarizes the customers that represented 10% or more of total net sales during the last three fiscal years: +Percentage of Net Sales by Fiscal Year +2022 2021 2020 +Customer A 13% * * +Customer B 12% 24% 18% +There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +We market our products and services primarily through our direct sales department which is comprised of strategically located field sales people and distributors. We also maintain relationships with several independent sales organizations to assist in marketing our product lines. +Manufacturing +We have continually made investments in developing and expanding a capital equipment base to achieve vertical integration and efficiencies in our manufacturing processes. We have invested significant capital into SMT for volume manufacturing of complex printed circuit board assemblies and in our metal shop providing precision metal stamping, fabricating, and finishing. We also design and develop tooling for injection molding and sheet metal fabrication and manufacture the majority of plastic and sheet metal parts used in the products we manufacture. Additionally, we have equipment to maintain a controlled clean environment for manufacturing processes that require a high level of precise control. +We use a variety of manual and automated assembly processes in our facilities, depending upon product complexity and degree of customization. Some examples of automated processes include component insertion, SMT, selective soldering, flexible robotic assembly, computerized vision system quality inspection, laser turrets, automated switch and key top installation, robotic welding, automated powder coat application, and automated functional testing. +Our engineering expertise and automated manufacturing processes enable us to work closely with our customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. We use computer-aided design techniques and software to assist in preparation of the tool design layout and component placement, to reduce tooling and production costs, improve component and product quality, and enhance turnaround time during product development. +5 +We purchase materials and components for our products from many different suppliers, including both domestic and international sources. We develop close working relationships with our suppliers, many of whom have been supplying products to us for several years. +Research, Development, and Engineering +As part of our long-term strategy, we are committed to supporting our customers by providing research, development, and engineering services. We have seen an increase in the success of providing design support on existing and potential customers in differentiating ourselves. We believe these services allow us to facilitate in optimizing new product designs, and the production processes of our customers’ programs. +Research, development, and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials costs, depreciation, and allocated information technology and facilities costs. +Competition +The market for the products and services we provide is highly competitive. There are numerous competitors in the contract manufacturing industry, many of which have substantially more resources and are more geographically diverse than we are. Some of our competitors have similar international production capabilities, large financial resources and some have substantially greater manufacturing, research and development, and marketing resources. There is also competition from the manufacturing operations of our current and potential customers, who are continually evaluating the merits of manufacturing their products internally versus the advantages of outsourcing. We believe that we can currently compete favorably in these areas primarily on the basis of our international footprint, responsiveness, creativity, vertical production capability, quality, and cost. +Trademarks +Our name and logo are federally registered trademarks, and we believe they are valuable assets of our business. +Employees +We consider our employees to be our primary strength and we make considerable efforts to maintain a well-qualified workforce. Our employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. We regularly provide transportation, medical services, and meals to all of our employees in foreign locations. The Company also has defined contribution plans available to U.S. employees who have attained age 21 and provide group health, life, and disability insurance plans. We also maintain share based compensation plans and other long-term incentive plans for certain employees and outside directors. +As of July 2, 2022, we had 4,897 full-time employees compared to 5,450 on July 3, 2021, and 5,741 on June 27, 2020. Since we can have significant fluctuations in product demand, we seek to maintain flexibility in our workforce by utilizing skilled temporary labor in some of our manufacturing facilities in addition to full-time employees. +Backlog +On July 30, 2022, our order backlog was valued at approximatel y $407.8 million, compared to approximately $303.2 million on July 31, 2021. The amount of backlog is not necessarily indicative of future sales but can be indicative of trends in expected future sales revenue. Due to the relationships with our customers, we will occasionally allow orders to be canceled or rescheduled and as a result it is not a meaningful indicator of future financial results. If there are canceled or rescheduled orders, we typically negotiate fees to cover the costs we have incurred. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change due to design modifications, customer forecast changes, or other customer requirements. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in Footnote “Enterprise-Wide Disclosures” of the “Notes to Consolidated Financial Statements” of this Annual Report on Form 10-K and that information is incorporated herein by reference. +Governmental Regulation +Our operations are subject to certain foreign, federal, state and local regulations relating to, among others, environmental, waste management, labor and health and safety matters. We have implemented processes and procedures to help ensure that our operations are in substantial compliance with all applicable regulations. However, material costs and liabilities may arise from these requirements or from new or modified requirements, which could have a material adverse effect on our business and results of operations. +6 +Information about Our Executive Officers. +The table below sets forth the name, current age and current position of our executive officers and other significant employees: +Name Age Positions Held +Executive Officers +Craig D. Gates 63 President and Chief Executive Officer +Brett R. Larsen 49 Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Philip S. Hochberg 60 Executive Vice President of Business Development +Duane D. Mackleit 54 Executive Vice President of Operations +David H. Knaggs 41 Executive Vice President of Quality and Information Systems +Chad T. Orebaugh 51 Executive Vice President of Engineering +Mark Courtney 56 +Vice President of Supply Chain +Executive Officers +CRAIG D. GATES – President and Chief Executive Officer +Mr. Gates, age 63, has been President and Chief Executive officer of the Company since April 2009. Previously, he was Executive Vice President and General Manager from August 2002 to April 2009. He served as Executive Vice President of Marketing, Engineering and Sales from July 1997 to August 2002 and served as Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of 1994. From 1982 to 1991 he held various engineering and management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. Mr. Gates has a Bachelor of Science Degree in Mechanical Engineering and a Master’s in Business Administration from the University of Illinois, Urbana. +BRETT R. LARSEN – Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Mr. Larsen, age 49, has served as Executive Vice President of Administration, Chief Financial Officer, and Treasurer since July 2015. Previously, he was Vice President of Finance and Controller from February 2010 to July 2015. He was Chief Financial Officer of FLSmidth Spokane, Inc. from December 2008 to February 2010. From October 2005 through November 2008, Mr. Larsen served as Controller of Key Tronic Corporation. From May 2004 to October 2005, Mr. Larsen served as Manager of Financial Reporting of Key Tronic Corporation. From 2002 to May 2004, Mr. Larsen was an audit manager for the public accounting firm BDO USA, LLP. He also held various auditing and supervisory positions with Grant Thornton LLP from 1997 to 2002. Mr. Larsen has a Bachelor of Science degree in Accounting and a Masters degree in Accounting from Brigham Young University and is a Certified Public Accountant. +PHILIP S. HOCHBERG – Executive Vice President of Business Development +Mr. Hochberg, age 60, has been Executive Vice President of Business Development since July 2012. Prior to this, Mr. Hochberg served as Vice President of Business Development from October 2009 through June 2012. He was Director of Business Development and Program Management from July 2008 to October 2009. Mr. Hochberg served as Director of Business Development from October 2004 to July 2008 and as Director of EMS Sales and Marketing from July 2000 to October 2004. Prior to joining Key Tronic, Mr. Hochberg worked for Quinton Instrument Company as their Director of Marketing and Product Management from 1992 to 2000. From 1988 to 1992, he was employed by SpaceLabs Medical as their Business Development Marketing Manager. Mr. Hochberg has an MBA from the University of British Columbia, a BA in Psychology, with a minor in Business from Washington University in St. Louis. +7 +DUANE D. MACKLEIT – Executive Vice President of Operations +Mr. Mackleit, age 54, has been Executive Vice President of Operations since December 2019. Prior to this, Mr. Mackleit served as Vice President of Program Management since July 2012. He served as Director of Program Management from July 2008 through June 2012. From May 2006 to July 2008 he served as Principal Program Manager. Prior to that, he served as Program Manager from March 2002 to May 2006 and Associate Program Manager from August 2000 to March 2002. Mr. Mackleit has also held several other positions with Key Tronic Corporation. Mr. Mackleit has an AA in Business from Spokane Falls Community College and a BA in Business/Marketing from Eastern Washington University. He also holds a MBA from Gonzaga University. +DAVID H. KNAGGS – Executive Vice President of Quality, Regulatory Affairs and Information Systems +Mr. Knaggs, age 41, has been Executive Vice President of Quality and Information Systems since May 2021. Previously, he was Vice President of Quality and Regulatory Affairs from November 2017 to May 2021. He was Vice President of Quality since October 2016. Before joining Key Tronic, Mr. Knaggs worked at Telect, Inc. from 2008 to 2016 as their Director of Engineering. Prior to that, he worked at Isothermal Systems Research as Lead Systems Engineer from 2003 to 2008. He has a Bachelor of Science degree in Mechanical Engineering with a minor in mathematics from the University of Washington. +CHAD T. OREBAUGH – Executive Vice President of Engineering +Mr. Orebaugh, age 51, has been Executive Vice President of Engineering since September 2021. Previously he served as Vice President of Engineering since April 2017. Prior to this, Mr. Orebaugh served as Director of Engineering since May 2013. From April 2010 to May 2013, he served as Manager of Engineering. From January 2000 to April 2010 he served as Lead Mechanical Engineer. Prior to that, he served as Mechanical Engineer from October 1998 to January 2000 and Associate Mechanical Engineer since October 1997. Mr. Orebaugh holds a BA in Mechanical Engineering from Gonzaga University. +MARK COURTNEY – Vice President of Supply Chain +Mark Courtney, age 56, has been Vice President of Supply Chain of the company since August 2019. Previously, he served as Purchasing Manager and Director of North American Purchasing from September 2015 to August 2019, and as Supply Chain Manager, ERP and Business Operations Manager for Amphenol Telect from August 2007 to September 2015. From March 2006 to August 2007, he served as Senior Buyer/Planner for Honeywell Specialty Materials and from June 2005 to March 2006 as Purchasing Manager for MRV Communications. From May 2000 to June 2005, he served as a Field and Inside Sales Associate for Arrow Electronics and from October 1991 to May 2000 held various positions at Alesis. +Available Information +Our principal executive offices are located at 4424 North Sullivan Road, Spokane Valley, Washington 99216, and our telephone number is (509) 928-8000. Our website is located at http://www.keytronic.com where filings of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or current reports on Form 8-K are available free of charge after they have been filed with the Securities and Exchange Commission. The information presented on our website currently and in the future is not considered to be part of this document or any document incorporated by reference in this document. +In addition, the SEC maintains an Internet site (at www.sec.gov ) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. \ No newline at end of file diff --git a/raw/filings/0000719733/2022/0000719733-22-000063/item13.txt b/raw/filings/0000719733/2022/0000719733-22-000063/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..8d13afb0b62f6a8307f5e5f8f649f8438d29cb9c --- /dev/null +++ b/raw/filings/0000719733/2022/0000719733-22-000063/item13.txt @@ -0,0 +1,2 @@ +Item 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions” and “Directors’ Independence” in the Company’s 2022 Proxy Statement is incorporated herein by this reference. \ No newline at end of file diff --git a/raw/filings/0000719733/2022/0000719733-22-000063/item9a.txt b/raw/filings/0000719733/2022/0000719733-22-000063/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..c20e45413853264b6936500e69ed0346303c526c --- /dev/null +++ b/raw/filings/0000719733/2022/0000719733-22-000063/item9a.txt @@ -0,0 +1,30 @@ +Item 9A: CONTROLS AND PROCEDURES +55 +Evaluation of Disclosure Controls and Procedures +It is the responsibility of our management to establish, maintain, and monitor disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 (the “Exchange Act”) are recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Additionally, these disclosure controls include controls and procedures that are designed to accumulate and communicate the information required to be disclosed to our Company’s Chief Executive Officer and Chief Financial Officer, allowing for timely decisions regarding required disclosures. +As of the end of the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(f). Based on our assessment, we believe that as of July 2, 2022, the Company’s disclosure controls and procedures are effective based on that criteria. +Management’s Report on Internal Control over Financial Reporting +Our management has the responsibility to establish and maintain adequate internal controls over our financial reporting, as defined in Rule 13a-15(f) under the Securities and Exchange Act of 1934. Our internal controls are designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our external financial statements in accordance with generally accepted accounting principles (GAAP). +Due to inherent limitations of any internal control system, management acknowledges that there are limitations as to the effectiveness of internal controls over financial reporting and therefore recognize that only reasonable assurance can be gained from any internal control system. Accordingly, our internal control system may not detect or prevent material misstatements in our financial statements and projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, we have performed an assessment of the effectiveness of our internal controls over financial reporting as of July 2, 2022. This assessment was based on the criteria established in Internal Control-Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that as of July 2, 2022, the Company’s internal control over financial reporting is effective based on that criteria. +The effectiveness of the Company's internal control over financial reporting as of July 2, 2022 has been audited by Moss Adams LLP, an independent registered public accounting firm, as stated in their report which is included herein. +Changes in Internal Control over Financial Reporting +There have been no significant changes in our internal controls over financial reporting during our fourth fiscal quarter ended July 2, 2022 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)). +56 +Report of Independent Registered Public Accounting Firm +To the Shareholders and the Board of Directors of +Key Tronic Corporation +Opinion on Internal Control over Financial Reporting +We have audited Key Tronic Corporation’s (the “Company”) internal control over financial reporting as of July 2, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of July 2, 2022, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO. +We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheet of Key Tronic Corporation as of July 2, 2022, the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for the year then ended, and the related notes (collectively referred to as the “consolidated financial statements”) and our report dated September 14, 2022 expressed an unqualified opinion on those consolidated financial statements. +Basis for Opinion +The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. +Definition and Limitations of Internal Control Over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +/s/ Moss Adams LLP +Seattle, Washington +September 14, 2022 +We have served as the Company’s auditor since 2021. +57 \ No newline at end of file diff --git a/raw/filings/0000719733/2022/0000719733-22-000063/rp_note.txt b/raw/filings/0000719733/2022/0000719733-22-000063/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000719733/2022/0000719733-22-000063/rpt_disclosure.txt b/raw/filings/0000719733/2022/0000719733-22-000063/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..05efd4920056eacc1b92160645acd90e1115896e --- /dev/null +++ b/raw/filings/0000719733/2022/0000719733-22-000063/rpt_disclosure.txt @@ -0,0 +1,7 @@ +Related Person Transactions +In April 2007, the Board of Directors adopted a written policy and procedures for the approval or ratification of Interested Transactions with Related Parties. The policy and procedures supplement the Company’s Code of Conduct. The policy defines an “Interested Transaction” as any transaction, arrangement or relationship or series of similar transactions, arrangements or relationships (including any indebtedness or guarantee of indebtedness) in which (1) the aggregate amount involved will or may be expected to exceed $120,000 in any calendar year, (2) the Company is a participant, and (3) any Related Party has or will have a direct or indirect interest (other than solely as a result of being a director or a less than 10 percent beneficial owner of another entity). +The policy defines a “Related Party” as any (a) person who is or was (since the beginning of the last fiscal year for which the Company has filed a Form 10-K and proxy statement, even if they do not presently serve in that role) an executive officer, director or nominee for election as a director, (b) greater than 5 percent beneficial owner of the Company’s Common Stock, or (c) immediate family member of any of the foregoing. Immediate family member includes a person’s spouse, parents, stepparents, children, stepchildren, siblings, mothers- and fathers-in-law, sons- and daughters-in-law, and brothers- and sisters-in-law and anyone residing in such person’s home (other than a tenant or employee). +The Audit Committee is responsible for review, approval, ratification or disapproval of Interested Transactions. In determining whether to approve or ratify an Interested Transaction, the Committee will take into account, among other factors it deems appropriate, whether the Interested Transaction is on terms no less favorable than terms generally available to an unaffiliated third party under the same or similar circumstances and the extent of the Related Party’s interest in the Transaction. +During fiscal year 2022, the Company purchased surface mount technology inspection equipment and raw materials from CyberOptics. The purchases by the Company during fiscal year 2022 totaled $382,000. These transactions were conducted at arm’s length in the ordinary course of business of the Company and CyberOptics, and the terms of purchase were no more favorable to the Company than purchases by unaffiliated parties from CyberOptics. +During the fiscal year 2021, the Company had no transactions with CyberOptics or any other Interested Transactions required to be disclosed pursuant to the SEC’s related persons disclosure. +8 \ No newline at end of file diff --git a/raw/filings/0000719733/2023/0000719733-23-000032/filing.txt b/raw/filings/0000719733/2023/0000719733-23-000032/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..4cd34e062d3a90b67119f615f5ed7894c369aba4 --- /dev/null +++ b/raw/filings/0000719733/2023/0000719733-23-000032/filing.txt @@ -0,0 +1,1330 @@ +ktcc-20230701 +false 2023 FY 0000719733 http://fasb.org/us-gaap/2023#OtherLiabilities http://fasb.org/us-gaap/2023#OtherAssetsNoncurrent http://fasb.org/us-gaap/2023#OtherAssetsNoncurrent 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us-gaap:SellingGeneralAndAdministrativeExpensesMember 2021-07-04 2022-07-02 0000719733 us-gaap:DebtMember 2023-07-01 +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +____________________________________________________________ +FORM 10-K +____________________________________________________________ +☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE FISCAL YEAR ENDED JULY 1 , 2023 +OR +☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934 +FOR THE PERIOD FROM TO +Commission File Number 0-11559 +____________________________________________________________ +KEY TRONIC CORP ORATION +(Exact name of registrant as specified in its charter) +____________________________________________________________ +Washington 91-0849125 +(State or other jurisdiction of +Incorporation or organization) (I.R.S. Employer +Identification No.) +4424 North Sullivan Road Spokane Valley, Washington 99216 +(Address of principal executive offices) (Zip Code) +( 509 ) 928-8000 +(Registrant’s telephone number, including area code) +____________________________________________________________ +Securities Registered Pursuant to Section 12(b) of the Act: +Title of each class Trading Symbol Name of each exchange on which registered +Common stock, no par value KTCC The NASDAQ Stock Market LLC +Securities Registered Pursuant to Section 12(g) of the Act: None +____________________________________________________________ +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ☐ No ☒ +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ +Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulations S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act. +(Check one): +Large accelerated filer ☐ Accelerated filer ☐ +Non-accelerated filer ☒ Smaller reporting company ☒ +Emerging growth company ☐ +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ +Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐ +If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐ +Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to § 240.10D-1(b). ☐ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ +State the aggregate market value of the voting and non-voting common equity held by non affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. +As of December 31, 2022, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $ 44.1 million based on the closing price as reported on the NASDAQ. +Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: 10,761,871 shares of common stock were outstanding as of September 14, 2023. +____________________________________________________________ +Documents Incorporated by Reference: +Certain information is incorporated into Part III of this report by reference to the Proxy Statement for the registrant’s 2023 annual meeting of stockholders to be filed with the Securities and Exchange Commission pursuant to Regulation 14A not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. +KEY TRONIC CORPORATION +2023 FORM 10-K +TABLE OF CONTENTS +Page No. +PART I +Item 1. +Business +4 +Item 1A. +Risk Factors +8 +Item 1B. +Unresolved Staff Comments +15 +Item 2. +Properties +15 +Item 3. +Legal Proceedings +17 +Item 4. +Mine Safety Disclosures +17 +PART II +Item 5. +Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities +17 +Item 6. +[Reserved] +18 +Item 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +18 +Item 7A. +Quantitative and Qualitative Disclosures about Market Risk +25 +Item 8. +Financial Statements and Supplementary Data +26 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +51 +Item 9A. +Controls and Procedures +51 +Item 9B. +Other Information +53 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +53 +Item 11. +Executive Compensation +53 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +53 +Item 13. +Certain Relationships and Related Transactions, and Director Independence +54 +Item 14. +Principal Accounting Fees and Services +54 +PART IV +Item 15. +Exhibits and Financial Statement Schedule +54 +Item 16. +Form 10-K Summary +57 +Signatures +58 +3 +FORWARD-LOOKING STATEMENTS +References in this report to “the Company,” “Key Tronic,” “we,” “our,” or “us” mean Key Tronic Corporation together with its subsidiaries, except where the context otherwise requires. +This Annual Report on Form 10-K contains forward-looking statements in addition to historical information. Forward-looking statements include, but are not limited to those including such words as aims, anticipates, believes, continues, could, estimates, expects, hopes, intends, plans, predicts, projects, targets, or will, similar verbs, or nouns corresponding to such verbs, which may be forward looking. Forward-looking statements also include other passages that are relevant to expected future events, performances, and actions or that can only be fully evaluated by events that will occur in the future. Forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those reflected in the forward-looking statements. Risks and uncertainties that might cause such differences include, but are not limited to those outlined in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risks and Uncertainties that May Affect Future Results” and in “Risk Factors.” Readers are cautioned not to place undue reliance on forward-looking statements, which reflect management’s opinions only as of the date hereof. The Company undertakes no obligation to update forward-looking statements to reflect developments or information obtained after the date hereof and disclaims any obligation to do so. Readers should carefully review the risk factors described in periodic reports the Company files from time to time with the Securities and Exchange Commission, including Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. +PART I +Item 1. BUSINESS +Background +Key Tronic Corporation was organized in 1969, as a Washington corporation that locally manufactured computer keyboards. The ability to design, build and deliver a quality product led us to become a leading independent manufacturer of keyboards for computers in the United States. Our fully integrated design, tooling, and automated manufacturing capabilities enabled us to rapidly respond to customers’ needs for keyboards in production quantities worldwide. We supported our sales growth through the development and purchase of international manufacturing facilities. As the computer keyboard market matured with increasing competition from other international providers, we determined that our business could no longer solely rely on keyboard sales. +After assessing market conditions and our strengths and capabilities, we shifted our focus from keyboard manufacturing to contract manufacturing for a wide range of products. Our unique strategic attributes are based on our core strengths of innovative design and engineering expertise in electronics, mechanical engineering, sheet metal fabrication and stamping, and precision plastics combined with high-quality, low cost production, and assembly on an international basis while providing exceptional customer service. These strengths have made our company a strong competitor in the contract manufacturing market. +Our Industry and Strategy +The expansion of the contract manufacturing industry and our acquisitions have allowed us to continue to expand our customer base and the industries that we serve. The increase in new programs represents a growing portion of our revenue and a promising foundation for our future. In keeping with our long-term strategic objectives, we have been successfully building a more diversified customer portfolio, spanning a wider range of industries. We currently offer our customers the following services: integrated electronic and mechanical engineering, precision plastic molding, sheet metal fabrication, printed circuit board (PCB) and complete product assembly, component selection, sourcing and procurement, worldwide logistics, and new product testing and production all at competitive pricing due to our global footprint. We differentiate ourselves from others our size and larger in the contract manufacturing industry by providing vertical integration, a flexible and responsive approach to our customer’s changing supply demand, and complete design engineering support. +We believe that we are well positioned in the contract manufacturing industry to continue the expansion of our customer base and achieve long-term growth. Our unique blend of multinational facilities, vertical integration, centralized management, and core strengths continue to support our growth and our customers’ needs. We continue to focus on controlling operating expenses and leveraging the synergistic capabilities of our world-class facilities in the United States, Mexico, China and Vietnam. This international production capability provides our customers with the benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs, and reduced product fulfillment time. Given our competitive advantages and the growing pressure for new potential customers to move forward with their outsourcing strategies, we feel that we are strongly positioned to win new business in coming periods and grow our revenue and profits. +4 +The contract manufacturing industry is intensely competitive. Although our customer base is growing, we still have less than 1% of the potential global market and our revenue can fluctuate significantly due to reliance on a concentrated base of customers. We are planning for new customer growth in the coming quarters by seeking to secure new programs with new and existing customers, increase our worldwide manufacturing capacity, leverage further our design engineering capabilities and continue to improve our manufacturing and procurement processes and capabilities. Ongoing challenges that we face include but are not limited to the following: continuing to win programs from new and existing customers, balancing capital employed, production capacity and key personnel in support of new customer programs, improving operating efficiencies, controlling costs while developing competitive pricing strategies, and successfully transitioning new program wins to full production. +Customers and Marketing +We provide a mix of manufacturing services for outsourced Original Equipment Manufacturing (OEM) products. We provide the following services: product design, surface mount technologies (SMT) and pin through hole capability for printed circuit board assembly, tool making, precision plastic molding, sheet metal fabrication and painting, liquid injection molding, complex assembly, prototype design and full product assembly. +Sales of the majority of our products have not historically been seasonal in nature, but may be seasonal in the future if there are changes in the types of products manufactured. Sales can, however, fluctuate significantly between quarters from changes in customers and customer demand due to the concentration of sales generated by our largest customers. +For the fiscal years 2023 and 2022, the five largest customers in each year accounted for 36% and 40% of combined total net sales, respectively. We continue to diversify our customer base by adding additional programs and customers. We expect net sales to our five largest customers as a percentage of total net sales to approximate current levels going forward. +The following table summarizes the customers that represented 10% or more of total net sales during the last two fiscal years: +Percentage of Net Sales by Fiscal Year +2023 2022 +Customer A 12% 12% +There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +We market our products and services primarily through our direct sales department which is comprised of strategically located field sales people and distributors. We also maintain relationships with several independent sales organizations to assist in marketing our product lines. +Manufacturing +We have continually made investments in developing and expanding a capital equipment base to achieve vertical integration and efficiencies in our manufacturing processes. We have invested significant capital into SMT for volume manufacturing of complex printed circuit board assemblies and in our metal shop providing precision metal stamping, fabricating, and finishing. We also design and develop tooling for injection molding and sheet metal fabrication and manufacture the majority of plastic and sheet metal parts used in the products we manufacture. Additionally, we have equipment to maintain a controlled clean environment for manufacturing processes that require a high level of precise control. +We use a variety of manual and automated assembly processes in our facilities, depending upon product complexity and degree of customization. Some examples of automated processes include component insertion, SMT, selective soldering, flexible robotic assembly, computerized vision system quality inspection, laser turrets, automated switch and key top installation, robotic welding, automated powder coat application, and automated functional testing. +Our engineering expertise and automated manufacturing processes enable us to work closely with our customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. We use computer-aided design techniques and software to assist in preparation of the tool design layout and component placement, to reduce tooling and production costs, improve component and product quality, and enhance turnaround time during product development. +We purchase materials and components for our products from many different suppliers, including both domestic and international sources. We develop close working relationships with our suppliers, many of whom have been supplying products to us for several years. +5 +Research, Development, and Engineering +As part of our long-term strategy, we are committed to supporting our customers by providing research, development, and engineering services. We have seen an increase in the success of providing design support on existing and potential customers in differentiating ourselves. We believe these services allow us to facilitate in optimizing new product designs, and the production processes of our customers’ programs. +Research, development, and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials costs, depreciation, and allocated information technology and facilities costs. +Competition +The market for the products and services we provide is highly competitive. There are numerous competitors in the contract manufacturing industry, many of which have substantially more resources and are more geographically diverse than we are. Some of our competitors have similar international production capabilities, large financial resources and some have substantially greater manufacturing, research and development, and marketing resources. There is also competition from the manufacturing operations of our current and potential customers, who are continually evaluating the merits of manufacturing their products internally versus the advantages of outsourcing. We believe that we can currently compete favorably in these areas primarily on the basis of our international footprint, responsiveness, creativity, vertical production capability, quality, and cost. +Trademarks +Our name and logo are federally registered trademarks, and we believe they are valuable assets of our business. +Employees +We consider our employees to be our primary strength and we make considerable efforts to maintain a well-qualified workforce. Our employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. We regularly provide transportation, medical services, and meals to all of our employees in foreign locations. The Company also has defined contribution plans available to U.S. employees who have attained age 21 and provide group health, life, and disability insurance plans. We also maintain share based compensation plans and other long-term incentive plans for certain employees and outside directors. +As of July 1, 2023, we had 5,447 full-time employees compared to 4,897 on July 2, 2022. Since we can have significant fluctuations in product demand, we seek to maintain flexibility in our workforce by utilizing skilled temporary labor in some of our manufacturing facilities in addition to full-time employees. +Backlog +On July 29, 2023, our order backlog was valued at approximatel y $343.0 million, compared to approximately $407.8 million on July 30, 2022. The amount of backlog is not necessarily indicative of future sales but can be indicative of trends in expected future sales revenue. Due to the relationships with our customers, we will occasionally allow orders to be canceled or rescheduled and as a result it is not a meaningful indicator of future financial results. If there are canceled or rescheduled orders, we typically negotiate fees to cover the costs we have incurred. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change due to design modifications, customer forecast changes, or other customer requirements. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in Footnote “Enterprise-Wide Disclosures” of the “Notes to Consolidated Financial Statements” of this Annual Report on Form 10-K and that information is incorporated herein by reference. +Governmental Regulation +Our operations are subject to certain foreign, federal, state and local regulations relating to, among others, environmental, waste management, labor and health and safety matters. We have implemented processes and procedures to help ensure that our operations are in substantial compliance with all applicable regulations. However, material costs and liabilities may arise from these requirements or from new or modified requirements, which could have a material adverse effect on our business and results of operations. +Information about Our Executive Officers. +6 +The table below sets forth the name, current age and current position of our executive officers and other significant employees: +Name Age Positions Held +Executive Officers +Craig D. Gates 64 President and Chief Executive Officer +Brett R. Larsen 50 Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Philip S. Hochberg 61 Executive Vice President of Business Development +Duane D. Mackleit 55 Executive Vice President of Operations +David H. Knaggs 42 Executive Vice President of Quality and Information Systems +Chad T. Orebaugh 52 Executive Vice President of Engineering +Mark Courtney 57 +Vice President of Supply Chain +Executive Officers +CRAIG D. GATES – President and Chief Executive Officer +Mr. Gates, age 64, has been President and Chief Executive officer of the Company since April 2009. Previously, he was Executive Vice President and General Manager from August 2002 to April 2009. He served as Executive Vice President of Marketing, Engineering and Sales from July 1997 to August 2002 and served as Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of 1994. From 1982 to 1991 he held various engineering and management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. Mr. Gates has a Bachelor of Science Degree in Mechanical Engineering and a Master’s in Business Administration from the University of Illinois, Urbana. +BRETT R. LARSEN – Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Mr. Larsen, age 50, has served as Executive Vice President of Administration, Chief Financial Officer, and Treasurer since July 2015. Previously, he was Vice President of Finance and Controller from February 2010 to July 2015. He was Chief Financial Officer of FLSmidth Spokane, Inc. from December 2008 to February 2010. From October 2005 through November 2008, Mr. Larsen served as Controller of Key Tronic Corporation. From May 2004 to October 2005, Mr. Larsen served as Manager of Financial Reporting of Key Tronic Corporation. From 2002 to May 2004, Mr. Larsen was an audit manager for the public accounting firm BDO USA, LLP. He also held various auditing and supervisory positions with Grant Thornton LLP from 1997 to 2002. Mr. Larsen has a Bachelor of Science degree in Accounting and a Masters degree in Accounting from Brigham Young University and is a Certified Public Accountant. +PHILIP S. HOCHBERG – Executive Vice President of Business Development +Mr. Hochberg, age 61, has been Executive Vice President of Business Development since July 2012. Prior to this, Mr. Hochberg served as Vice President of Business Development from October 2009 through June 2012. He was Director of Business Development and Program Management from July 2008 to October 2009. Mr. Hochberg served as Director of Business Development from October 2004 to July 2008 and as Director of EMS Sales and Marketing from July 2000 to October 2004. Prior to joining Key Tronic, Mr. Hochberg worked for Quinton Instrument Company as their Director of Marketing and Product Management from 1992 to 2000. From 1988 to 1992, he was employed by SpaceLabs Medical as their Business Development Marketing Manager. Mr. Hochberg has an MBA from the University of British Columbia, a BA in Psychology, with a minor in Business from Washington University in St. Louis. +DUANE D. MACKLEIT – Executive Vice President of Operations +Mr. Mackleit, age 55, has been Executive Vice President of Operations since December 2019. Prior to this, Mr. Mackleit served as Vice President of Program Management since July 2012. He served as Director of Program Management from July 2008 through June 2012. From May 2006 to July 2008 he served as Principal Program Manager. Prior to that, he served as Program Manager from March 2002 to May 2006 and Associate Program Manager from August 2000 to March 2002. Mr. Mackleit has also held several other positions with Key Tronic Corporation. Mr. Mackleit has an AA in Business from Spokane Falls Community College and a BA in Business/Marketing from Eastern Washington University. He also holds a MBA from Gonzaga University. +DAVID H. KNAGGS – Executive Vice President of Quality, Regulatory Affairs and Information Systems +Mr. Knaggs, age 42, has been Executive Vice President of Quality and Information Systems since May 2021. Previously, he was Vice President of Quality and Regulatory Affairs from November 2017 to May 2021. He was Vice President of Quality since October 2016. Before joining Key Tronic, Mr. Knaggs worked at Telect, Inc. from 2008 to 2016 as their Director of +7 +Engineering. Prior to that, he worked at Isothermal Systems Research as Lead Systems Engineer from 2003 to 2008. He has a Bachelor of Science degree in Mechanical Engineering with a minor in mathematics from the University of Washington. +CHAD T. OREBAUGH – Executive Vice President of Engineering +Mr. Orebaugh, age 52, has been Executive Vice President of Engineering since September 2021. Previously he served as Vice President of Engineering since April 2017. Prior to this, Mr. Orebaugh served as Director of Engineering since May 2013. From April 2010 to May 2013, he served as Manager of Engineering. From January 2000 to April 2010 he served as Lead Mechanical Engineer. Prior to that, he served as Mechanical Engineer from October 1998 to January 2000 and Associate Mechanical Engineer since October 1997. Mr. Orebaugh holds a BA in Mechanical Engineering from Gonzaga University. +MARK COURTNEY – Vice President of Supply Chain +Mark Courtney, age 57, has been Vice President of Supply Chain of the company since August 2019. Previously, he served as Purchasing Manager and Director of North American Purchasing from September 2015 to August 2019, and as Supply Chain Manager, ERP and Business Operations Manager for Amphenol Telect from August 2007 to September 2015. From March 2006 to August 2007, he served as Senior Buyer/Planner for Honeywell Specialty Materials and from June 2005 to March 2006 as Purchasing Manager for MRV Communications. From May 2000 to June 2005, he served as a Field and Inside Sales Associate for Arrow Electronics and from October 1991 to May 2000 held various positions at Alesis. +Available Information +Our principal executive offices are located at 4424 North Sullivan Road, Spokane Valley, Washington 99216, and our telephone number is (509) 928-8000. Our website is located at http://www.keytronic.com where filings of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or current reports on Form 8-K are available free of charge after they have been filed with the Securities and Exchange Commission. The information presented on our website currently and in the future is not considered to be part of this document or any document incorporated by reference in this document. +In addition, the SEC maintains an Internet site (at www.sec.gov ) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. +Item 1A. RISK FACTORS +There are risks and uncertainties that could affect our business. These risks and uncertainties include but are not limited to, the risk factors described below, in Item 7A: “Quantitative and Qualitative Disclosures about Market Risk” and elsewhere in this Annual Report on Form 10-K. +8 +RISKS AND UNCERTAINTIES THAT MAY AFFECT FUTURE RESULTS +The following risks and uncertainties could affect our actual results and could cause results to differ materially from past results or those contemplated by our forward-looking statements. When used herein, the words “expects,” “believes,” “anticipates” and other similar expressions are intended to identify forward-looking statements. +RISKS RELATED TO OUR BUSINESS AND STRATEGY +Our operations may be subject to certain risks. +We manufacture product in facilities located in Mexico, China, Vietnam and the United States. These operations may be subject to a number of risks, including: +• difficulties in staffing, turnover and managing onshore and offshore operations; +• political and economic instability (including acts of terrorism, pandemics, civil unrest, forms of violence and outbreaks of war), which could impact our ability to ship, manufacture, and/or receive product; +• unexpected changes in regulatory requirements and laws, including those related to climate change; +• longer customer payment cycles and difficulty collecting accounts receivable; +• cash liquidity, the ability to acquire new debt capacity, and capital constraints; +• export duties, import controls and trade barriers (including quotas); +• governmental restrictions on the transfer of funds; +• burdens of complying with a wide variety of foreign laws and labor practices; subject to trade wars and tariffs; +• our locations are subject to physical and operational risks from natural disasters, severe weather events, and climate change; and +• our locations may also be impacted by future temporary closures and labor constraints as a result of local mandates for medical, climate, and unforeseen emergencies. +Our operations in certain foreign locations receive favorable income tax treatment in the form of tax credits or other incentives. In the event that such tax incentives are not extended, are repealed, or we no longer qualify for such programs, our taxes may increase, which would reduce our net income. +Additionally, certain foreign jurisdictions restrict the amount of cash that can be transferred to the U.S. or impose taxes and penalties on such transfers of cash. To the extent we have excess cash in foreign locations that could be used in, or is needed by, our operations in the United States, we may incur significant penalties and/or taxes to repatriate these funds. +We may experience fluctuations in quarterly results of operations. +Our quarterly operating results have varied in the past and may vary in the future due to a variety of factors, including adverse changes in the U.S. and global macroeconomic environment, volatility in overall demand for our customers’ products, success of customers’ programs, timing of new programs, new product introductions or technological advances by us, our customers and our competitors, and changes in pricing policies by us, our customers, our suppliers, and our competitors. Our customer base is diverse in the markets they serve, however, decreases in demand, particularly from customers in certain industries could affect future quarterly results. Additionally, our customers could be adversely impacted by illiquidity in the credit markets which could directly impact our operating results. +Component procurement, production schedules, personnel and other resource requirements are based on estimates of customer requirements. Occasionally, our customers may request accelerated production that can stress resources and reduce operating margins. Conversely, our customers may abruptly lower or cancel production which may lead to a sudden, unexpected increase in inventory or accounts receivable for which we may not be reimbursed even when under contract with customers. In addition, because many of our operating expenses are relatively fixed, a reduction in customer demand can harm our gross profit and operating results. The products which we manufacture for our customers have relatively short product lifecycles. Therefore, our business, operating results and financial condition are dependent in a significant way on our ability to obtain orders from new customers and new product programs from existing customers. +9 +Operating results can also fluctuate if changes are made to significant estimates and assumptions. Significant estimates and assumptions include the allowance for doubtful receivables, net realizable inventory, revenue recognition, and the valuation allowance on deferred tax assets. +Due to the COVID-19 pandemic, we have seen extreme shifts in demand from our customer base. The possibility of future temporary closures and labor constraints, as well as the inability to predict customer demand, costs, and future supply chain disruptions during the rapidly changing COVID-19 environment can materially impact operating results. +We are exposed to general economic conditions, which could have a material adverse impact on our business, operating results and financial condition. +Adverse economic conditions and uncertainty in the global economy such as unstable global financial and credit markets, inflation, and recession can negatively impact our business. Unfavorable economic conditions could affect the demand for our customers’ products by triggering a reduction in orders as well as a decline in forecasts which could adversely affect our sales in future periods. Additionally, the financial strength of our customers and suppliers and their ability to obtain and rely on credit financing may affect their ability to fulfill their obligations to us and have an adverse effect on our financial results. +Adverse macroeconomic conditions, such as those that were a result of COVID-19 have and may continue to affect our business. The conditions affect the Company’s ability to predict and plan for future supply chain disruptions, fluctuations in customer demand and costs, and the ability to operate as there is uncertainty over future temporary closures. Inflation has also risen globally to historically high levels. If the inflation rate continues to increase, the costs of labor and other expenses could also increase. We may not be able to increase our product prices enough to offset these increased costs. In addition, any increase in our product prices may reduce our future customer orders and profitability. Inflation may further exacerbate other risk factors discussed in this Annual Report on Form 10-K, including disruptions to international operations. +The majority of our sales come from a small number of customers and a decline in sales to any of these customers could adversely affect our business. +At present, our customer base is concentrated and could become more or less concentrated. There can be no assurance that our principal customers will continue to purchase products from us at current levels. Moreover, we typically do not enter into long-term volume purchase contracts with our customers, and our customers have certain rights to extend or delay the shipment of their orders. We, however, typically require that our customers contractually agree to buy back inventory purchased within specified lead times to build their products if not used. +The loss of one or more of our major customers, or the reduction, delay or cancellation of orders from such customers, due to economic conditions or other forces, could materially and adversely affect our business, operating results and financial condition. The contraction in demand from certain industries could impact our customer orders and have a negative impact on our operations over the foreseeable future. Additionally, if one or more of our customers were to become insolvent or otherwise unable to pay for the manufacturing services provided by us, our operating results and financial condition would be adversely affected. +We depend on a limited number of suppliers for certain components that are critical to our manufacturing processes. A shortage of these components or an increase in their price could interrupt our operations and result in a significant change in our results of operations. +We are dependent on many suppliers, including sole source suppliers, to provide key components and raw materials used in manufacturing customers’ products. We have seen supply shortages in certain electronic components. In addition, our suppliers' facilities may also experience earthquakes, tsunamis and other natural disasters which may cause a shortage of components. This can result in longer lead times and the inability to meet our customers request for flexible production and extended shipment dates. If demand for components outpaces supply, capacity delays could affect future operations. Delays in deliveries from suppliers or the inability to obtain sufficient quantities of components and raw materials have and may continue to cause delays or reductions in shipment of products to our customers which could adversely affect our operating results and damage customer relationships. +Key Tronic continues to work closely with its employees and key suppliers to ascertain delays attributable to the COVID-19 pandemic. Delays in production and extended transit times of critical parts have and may continue to cause a shortage of components. +We operate in a highly competitive industry; if we are not able to compete effectively in the contract manufacturing industry, our business could be adversely affected. +Competitors may offer customers lower prices on certain high volume programs. This could result in price reductions, reduced margins and loss of market share, all of which would materially and adversely affect our business, operating results, and financial condition. If we were unable to provide comparable or better manufacturing services at a lower cost than our competitors, it could cause sales to decline. In addition, competitors can copy our non-proprietary designs and processes after +10 +we have invested in development of products for customers, thereby enabling such competitors to offer lower prices on such products due to savings in development costs. +Fluctuations in foreign currency exchange rates could increase our operating costs. +We have manufacturing operations located in Mexico and China. A significant portion of our operations are denominated in the Mexican peso and the Chinese currency, the renminbi ("RMB"). Currency exchange rates fluctuate daily as a result of a number of factors, including changes in a country's political and economic policies. Volatility in the currencies of our entities and the United States dollar, as well as inflationary costs, could seriously harm our business, operating results and financial condition. The primary impact of currency exchange fluctuations is on the cash, receivables, payables and expenses of our operating entities. As part of our hedging strategy, we may use Mexican peso forward contracts to hedge future foreign currency fluctuations for a portion of our Mexican peso denominated expenses. We currently do not hedge expenses denominated in RMB. Unexpected losses could occur from increases in the value of these currencies relative to the United States dollar. +Global economic and political events, including as a result of COVID-19, can lead to significant currency exchange fluctuations can occur causing unexpected losses. Future temporary closures of production facilities in Mexico could also cause significant changes in our ability to qualify for hedge accounting treatment of our forward contracts to hedge foreign currency fluctuations. However, given the unprecedented nature of the pandemic the FASB staff believes that an entity may apply the exception in paragraph 815-30-40-4 for rare cases caused by extenuating circumstances that are related to the nature of the forecasted transaction and are outside the control or influence of an entity to delays in the timing of the forecasted transactions if those delays are related to the effects of the COVID-19 pandemic and are considered probable to still occur. In addition, the FASB staff believes that it would be acceptable for an entity to determine that missed forecasts related to the effects of the COVID-19 pandemic need not be considered when determining whether it has exhibited a pattern of missing forecasts that would call into question its ability to accurately predict forecasted transactions and the propriety of using cash flow hedge accounting in the future for similar transactions. +Our success will continue to depend to a significant extent on our key personnel. +Our future success depends in large part on the continued service of our key technical, marketing and management personnel and on our ability to continue to attract and retain qualified production employees. There can be no assurance that we will be successful in attracting and retaining such personnel, particularly in our manufacturing locales that may be experiencing high demand for similar key personnel. The loss of key employees could have a material adverse effect on our business, operating results and financial condition. +Start-up costs and inefficiencies related to new or transferred programs can adversely affect our operating results and such costs may not be recoverable if such new programs or transferred programs are canceled or don’t meet expected sales volumes. +Start-up costs, the management of labor and equipment resources in connection with the establishment of new programs and new customer relationships, and the need to obtain required resources in advance can adversely affect our gross margins and operating results. These factors are particularly evident in the ramping stages of new programs. These factors also affect our ability to efficiently use labor and equipment. We are currently managing a number of new programs. Consequently, our exposure to these factors has increased. In addition, if any of these new programs or new customer relationships were terminated, our operating results could be harmed, particularly in the short term. We may not be able to recoup these start-up costs or replace anticipated new program revenues. +Customers may change production timing and demand schedules which makes it difficult for us to schedule production and capital expenditures and to maximize the efficiency of our manufacturing capacity. +Changes in demand for customer products reduce our ability to accurately estimate the future requirements of our customers. This makes it difficult to schedule production and maximize utilization of our manufacturing capacity. We must determine the levels of business that we will seek and accept from customers, set production schedules, commit to procuring inventory, and allocate personnel and resources, based on our estimates of our customers' requirements. Customers can require sudden increases and decreases in production which can put added stress on resources and reduce margins. Sudden decreases in production can lead to excess inventory on hand which may or may not be reimbursed by our customers even when under contract. +Continued growth could further lead to capacity constraints. We may need to transfer production to other facilities, acquire new facilities, or outsource production which could negatively impact gross margin. The Company has been able to manage the arrival of components in an effort to control inventory levels of customers that have seen sharp decreases in demand as a result of market conditions. +11 +Compliance or the failure to comply with current and future environmental and health laws or regulations could cause us significant expense. +We are subject to a variety of domestic and foreign environmental regulations relating to the use, storage, and disposal of materials used in our manufacturing processes. In addition, increasing governmental focus on climate change may result in new environmental regulations that may negatively affect us, our vendors or our customers. As a result, we may incur additional costs or obligations in complying with any new environmental and reporting requirements, as well as increased indirect costs resulting from our vendors or suppliers that get passed on to us. +If we fail to comply with any present or future regulations, we could be subject to future liabilities or the suspension of current manufacturing operations. In addition, such regulations could restrict our ability to expand our operations or could require us to acquire costly equipment, substitute materials, or incur other significant expenses to comply with government regulations. +If our manufacturing processes and services do not comply with applicable statutory and regulatory requirements, or if we manufacture products containing design or manufacturing defects, demand for our services may decline and we may be subject to liability claims. +We manufacture and design products to our customers’ specifications, and, in some cases, our manufacturing processes and facilities may need to comply with applicable statutory and regulatory requirements. For example, medical devices that we manufacture or design, as well as the facilities and manufacturing processes that we use to produce them, are regulated by the Food and Drug Administration and non-U.S. counterparts of this agency. In addition, our customers’ products and the manufacturing processes that we use to produce them often are highly complex. As a result, products that we manufacture may at times contain manufacturing or design defects, and our manufacturing processes may be subject to errors or not be in compliance with applicable statutory and regulatory requirements. Defects in the products we manufacture or design, whether caused by a design, manufacturing or component failure or error, or deficiencies in our manufacturing processes, may result in delayed shipments to customers or reduced or canceled customer orders. If these defects or deficiencies are significant, our reputation may also be damaged. The failure of the products that we manufacture or our manufacturing processes and facilities to comply with applicable statutory and regulatory requirements may subject us to legal fines or penalties and, in some cases, require us to shut down or incur considerable expense to correct a manufacturing process or facility. Our customers are required to indemnify us against liability associated with designing products to meet their specifications. However, if our customers are responsible for the defects, they may not, or may not have resources to, assume responsibility for any costs or liabilities arising from these defects, which could expose us to additional liability claims. +If we do not manage our growth effectively, our profitability could decline. +Our business is experiencing growth which can place considerable additional demands upon our management team and our operational, financial and management information systems. Our ability to manage growth effectively requires us to continue to implement and improve these systems; avoid cost overruns; maintain customer, supplier and other favorable business relationships during possible transition periods; manage appropriate inventory levels; continue to develop the management skills of our managers and supervisors; and continue to train, motivate and manage our employees. Our failure to effectively manage growth could have a material adverse effect on our results of operations. +Energy price increases may negatively impact our results of operations. +Certain components that we use in our manufacturing process are petroleum-based. In addition, we, along with our suppliers and customers, rely on various energy sources in our transportation activities. While significant uncertainty currently exists about the future of energy prices, a significant increase, such as the increased fuel prices experienced in fiscal year 2023, is possible. Increased energy prices could cause an increase to our raw material and transportation costs. In addition, increased transportation costs related to certain suppliers and customers could be passed along to us. We may not be able to increase our product prices enough to offset these increased costs. In addition, any increase in our product prices may reduce our future customer orders and profitability. +TECHNOLOGY RISKS +Our operations are subject to cyberattacks that could have a material adverse effect on our business. +We are increasingly dependent on digital technologies and services to conduct our operations. We use these technologies for internal purposes, including data storage, processing and transmissions, as well as in our interactions with vendors and customers. Digital technologies and services are subject to the risk of cybersecurity incidents and some incidents can remain undetected for a period of time. +We routinely monitor our systems for cyber threats and have processes in place to detect and remediate vulnerabilities. Nevertheless, we have experienced security breaches, such as phishing emails and other targeted attacks. We expect that our operations will continue to be subject to cyber threats, and any future cybersecurity incident could significantly disrupt our operations. +12 +Cybersecurity incidents could also result in the misappropriation of proprietary or confidential information of the Company or that of its customers, employees, vendors or suppliers. We expect to incur costs in the future to mitigate against cybersecurity incidents as threats are expected to continue and to become more persistent and sophisticated. If our systems for protecting against cybersecurity incidents prove to be insufficient, we could be adversely affected by, among other things, loss of or damage to intellectual property, proprietary or confidential information, or employee, vendor or customer data; interruption of our business operations; and increased costs to prevent, respond to or mitigate cybersecurity incidents. These risks could harm our reputation and our relationships with employees, vendors and customers and may result in claims or enforcement actions and investigations against us. +Disruptions to our information systems, including losses of data or outages, could adversely affect our operations. +We rely on information technology networks and systems to process, transmit and store electronic information. In particular, we depend on our information technology infrastructure for a variety of functions, including worldwide financial reporting, inventory management, procurement, invoicing and email communications. Any of these systems may be susceptible to outages due to fire, floods, power loss, telecommunications failures, terrorist attacks and similar events. If we or our vendors are unable to prevent such outages, our operations could be disrupted. +If we are unable to maintain our technological and manufacturing process expertise, our business could be adversely affected. +The markets for our customers’ products are characterized by rapidly changing technology, evolving industry standards, frequent new product introductions and short product life cycles. The introduction of products embodying new technologies or the emergence of new industry standards can render existing products obsolete or unmarketable. Our success will depend upon our customers’ ability to enhance existing products and to develop and introduce, on a timely and cost-effective basis, new products that keep pace with technological developments and emerging industry standards and address evolving and increasingly sophisticated customer requirements. Failure of our customers to do so could substantially harm our customers’ competitive positions. There can be no assurance that our customers will be successful in identifying, developing and marketing products that respond to technological change, emerging industry standards or evolving customer requirements. +RISKS RELATED TO CAPITAL AND FINANCING +Cash and cash equivalents are exposed to concentrations of credit risk. +We place our cash with high credit quality institutions. At times, such balances may be in excess of the federal depository insurance limit or may be on deposit at institutions which are not covered by insurance. If such institutions were to become insolvent during which time it held our cash and cash equivalents in excess of the insurance limit, it could be necessary to obtain other credit financing to operate our facilities. +Our ability to secure and maintain sufficient credit arrangements is key to our continued operations. +There is no assurance that we will be able to retain or replace our credit agreements in the future or obtain sufficient capital for operating requirements. In the event the business grows rapidly or there is uncertainty in the macroeconomic climate, additional financing resources could be necessary. There is no assurance that we will be able to obtain equity or debt financing at acceptable terms, maintain sufficient borrowing capacity on the existing revolver, or at all in the future. In addition, we have restrictive covenants with our financial institution which could impact how we manage our business. If we cannot meet our financial covenants, our borrowings could become immediately payable which could have a material adverse impact on our financial statements. For a summary of our banking arrangements, see Footnote “Long-Term Debt” of the “Notes to Consolidated Financial Statements.” +An adverse change in the interest rates for our borrowings could adversely affect our financial condition. +We are exposed to interest rate risk under our revolving line of credit and term loan. We have not historically hedged the interest rate on our credit facility; therefore, unless we do so, significant changes in interest rates could adversely affect our results of operations. For a summary of our debt obligations, see Footnote “Long-Term Debt” of the “Notes to Consolidated Financial Statements.” +Our stock price is volatile. +Our stock price has and may continue to be subject to wide fluctuations and possible rapid increases or declines over a short time period. These fluctuations may be due to factors specific to us such as our stock's thinly traded nature, variations in quarterly operating results, changes in earnings estimates, or to factors relating to the contract manufacturing industry or to the securities markets in general, which, in recent years, have experienced significant price fluctuations. These fluctuations often have been unrelated to the operating performance of the specific companies whose stocks are traded. In addition, holders of our common stock will suffer immediate dilution to the extent outstanding equity awards are exercised to purchase common stock. +13 +RISKS RELATED TO OUR CONTROLS AND PROCEDURES AND THE INTERNAL INVESTIGATION +If we fail to maintain proper and effective internal controls, our business and financial condition could be materially adversely impacted. +We have previously identified a material weakness in our internal control over financial reporting, and undertook remediation efforts to address the identified deficiencies and concluded that the material weakness was remediated as of July 3, 2021. If other deficiencies in our internal control over financial reporting are discovered or occur in the future, our consolidated financial statements may contain material misstatements and we could be required to restate our financial results and incur the additional costs and expenses associated therewith. Moreover, because of the inherent limitations of any control system, material misstatements due to error or fraud may not be prevented or detected on a timely basis, or at all. As of July 2, 2023, we are a non-accelerated filer under the Exchange Act and are not required to comply with the auditor attestation requirements of Section 404(b) of the Sarbanes-Oxley Act of 2002 (the Sarbanes-Oxley Act). Therefore, our internal controls over financial reporting will not receive the level of review provided by the process relating to the auditor attestation included in annual reports of issuers that are subject to the auditor attestation requirements. +If we are unable to provide reliable and timely financial reports in the future, our business and reputation may be further harmed. Restated financial statements and failures in internal controls may also cause us to fail to meet additional reporting obligations, negatively affect investor confidence in our management and the accuracy of our financial statements and disclosures, or result in adverse publicity and concerns from investors, any of which could have a negative effect on the price of our common stock, subject us to regulatory investigations and penalties or stockholder litigation, and materially adversely impact our business, financial condition, results of operations and cash flows. +Matters relating to or arising from the subject of the Audit Committee’s internal investigation, including expenses and diversion of personnel and resources, regulatory investigations, and proceedings and litigation matters, could have an adverse effect on our business, results of operations and financial condition. +We have incurred, and may continue to incur, significant expenses related to legal, accounting and other professional services in connection with matters relating to or arising from the subject of the Audit Committee’s internal investigation. We have taken steps in order to remediate identified deficiencies in our internal control over financial reporting and attempt to reduce the risk of future recurrence. To the extent these steps were not successful, we may incur significant additional time and expense. +In addition, we are cooperating with the Securities and Exchange Commission (the “SEC”) regarding matters related to the internal investigation. The completion of the internal investigation did not automatically resolve the SEC’s inquiries. If the SEC or any other regulator were to commence legal action against us, we could be required to pay significant penalties and become subject to injunctions, cease and desist orders or other remedies. We can provide no assurances as to the outcome of any governmental inquiry or investigation. Further, we, our officers and members of our board of directors could be named as defendants in lawsuits asserting claims arising out of the subject matter of the Audit Committee’s internal investigation. As a result of any legal proceedings and any related indemnification requirements to our officers and directors, we could be required to pay monetary damages that may be in excess of our insurance coverage or may have additional penalties or other remedies imposed against us or our officers and directors. +All of these expenses, and the diversion of the attention of management and other personnel that has occurred and is expected to continue, could adversely affect our business, financial condition, results of operations and cash flows. +Due to inherent limitations, there can be no assurance that our system of disclosure and internal controls and procedures will be successful in preventing all errors, theft and fraud, or in informing management of all material information in a timely manner. +Management does not expect that our disclosure controls and procedures and internal controls over financial reporting will prevent all errors or fraud. A control system is designed to give reasonable, but not absolute, assurance that the objectives of the control system are met. In addition, any control system reflects resource constraints and the benefits of controls must be considered relative to their costs. Inherent limitations of a control system may include: judgments in decision making may be faulty, breakdowns can occur simply because of error or mistake and controls can be circumvented by collusion or management override. Due to the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and may not be detected. +LEGAL AND ACCOUNTING RISKS +We are involved in various legal proceedings. +In the past, we have been notified of claims relating to various matters including contractual matters, intellectual property rights or other issues arising in the ordinary course of business. In the event of such a claim, we may be required to spend a significant amount of money to defend or otherwise address the claim. Any litigation or dispute resolution, even where a claim is without merit, could result in substantial costs and diversion of resources. Accordingly, the resolution or adjudication of such disputes, +14 +even those encountered in the ordinary course of business, could have a material effect on our business, consolidated financial conditions and results of operations. +Changes in securities laws and regulations will increase our costs and risk of noncompliance. +We are subject to requirements contained in the U.S. federal securities laws, including provisions of the Sarbanes-Oxley Act and the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act). The Sarbanes-Oxley and Dodd-Frank Acts required or will require changes in some of our corporate governance, securities disclosure and compliance practices. The SEC and NASDAQ Global Market (“Nasdaq”) have promulgated new rules and additional rulemaking is expected in the future. Compliance with these new rules and future rules has increased and is expected to increase further our legal, financial and accounting costs as well as a potential risk of noncompliance. Absent significant changes in related rules, which we cannot assure, we anticipate some level of increased costs related to these new regulations to continue indefinitely. We also expect these developments to make it more difficult and more expensive to obtain director and officer liability insurance, and we may be forced to accept reduced coverage or incur substantially higher costs to obtain coverage. Likewise, these developments may make it more difficult for us to attract and retain qualified members of our Board of Directors or qualified management personnel. Further, the costs associated with the compliance with and implementation of procedures under these and future laws and related rules could have a material impact on our results of operations. In addition, the costs associated with noncompliance with additional securities laws and regulations could also impact our business. +Changes in financial accounting standards may affect our reported financial condition or results of operations as well as increase costs related to implementation of new standards and modifications to internal controls. +Our consolidated financial statements are prepared in conformity with accounting standards generally accepted in the United States, or U.S. GAAP. These principles are subject to amendments made primarily by the Financial Accounting Standards Board (FASB) and the SEC. A change in those policies can have a significant effect on our reported results and may affect our reporting of transactions which are completed before a change is announced. Changes to accounting rules or challenges to our interpretation or application of the rules by regulators may have a material adverse effect on our reported financial results or on the way we conduct business. +GENERAL RISKS +Our levels of insurance coverage may not be sufficient for potential damages, claims or losses. +We have various forms of business and liability insurance which we believe are appropriate based on the needs of companies in our industry. As a result, not all of our potential business risks or potential losses would be covered by our insurance policies. If we sustain a significant claim or loss which is not covered by insurance, our net income could be negatively impacted. +We may encounter complications with acquisitions, which could potentially harm our business. +Any current or future acquisitions may require additional equity financing, which could be dilutive to our existing shareholders, or additional debt financing, which could potentially affect our credit ratings. Any downgrades in our credit ratings associated with an acquisition could adversely affect our ability to borrow by resulting in more restrictive borrowing terms. To integrate acquired businesses, we must implement our management information systems, operating systems and internal controls, and assimilate and manage the personnel of the acquired operations. The integration of acquired businesses may be further complicated by difficulties managing operations in geographically dispersed locations. The integration of acquired businesses may not be successful and could result in disruption by diverting management’s attention from the core business. In addition, the integration of acquired businesses may require that we incur significant restructuring charges or other increases in our expenses and working capital requirements, which reduce our return on invested capital. +Acquisitions may involve numerous other risks and challenges including but not limited to: potential loss of key employees and customers of the acquired companies; the potential for deficiencies in internal controls at acquired companies; lack of experience operating in the geographic market or industry sector of the acquired business; constraints on available liquidity, and exposure to unanticipated liabilities of acquired companies. These and other factors could harm our ability to achieve anticipated levels of profitability at acquired operations or realize other anticipated benefits of an acquisition, and could adversely affect our consolidated business and operating results. +Item 1B. UNRESOLVED STAFF COMMENTS +None +Item 2. PROPERTIES AS OF DATE OF FILING +15 +We have manufacturing and sales operations located in the United States, Mexico, China and Vietnam. The table below lists the locations and square footage of our operating facilities: +Location Approx. +Sq. Ft. Type of Interest +(Leased/Owned) Description of Use +Corinth, Mississippi 350,000 Leased Manufacturing and warehouse +El Paso, Texas 80,000 Leased Shipping and warehouse +Fayetteville, Arkansas 105,000 Leased Manufacturing and warehouse +Oakdale, Minnesota 103,000 Leased Manufacturing and warehouse +Spokane Valley, Washington 95,000 Leased Sales, research, administration and manufacturing +Spokane Valley, Washington 36,000 Leased Manufacturing +Total USA 769,000 +Juarez, Mexico 193,000 Leased Warehouse +Juarez, Mexico 174,000 Owned Manufacturing and warehouse +Juarez, Mexico 115,000 Owned Manufacturing and warehouse +Juarez, Mexico 103,000 Owned Manufacturing and warehouse +Juarez, Mexico 72,000 Leased Manufacturing and warehouse +Juarez, Mexico 66,000 Owned Manufacturing and warehouse +Juarez, Mexico 60,000 Owned Manufacturing and warehouse +Juarez, Mexico 116,000 Leased Manufacturing and warehouse +Juarez, Mexico 159,000 Leased Manufacturing and warehouse +Total Mexico 1,058,000 +Shanghai, China 9,000 Leased Manufacturing and warehouse +Total China 9,000 +Da Nang, Vietnam 133,000 Leased Manufacturing and warehouse +Total Vietnam 133,000 +Grand Total 1,969,000 +The geographic diversity of these locations allows us to offer services near certain of our customers and major electronics markets with the additional benefit of reduced labor costs. We consider the productive capacity of our current facilities sufficient to carry on our current business. In addition, in Juarez, Mexico one of our buildings includes adjacent vacant land that could be developed into additional manufacturing and warehouse space. +All our facilities are ISO certified to ISO 9001:2015 standard and to Customs Trade Partnership against Terrorism (CTPAT). +• The Spokane, Washington facility is registered to IATF 16949 automotive standard, ISO 13485:2016 medical devices, ISO 14001:2015 environmental standard, and ISO 45001 Occupational Health and Safety Management System. +• The Juarez, Mexico facility is registered to IATF 16949 automotive standard, ISO 13485:2016 medical devices, ISO 14001:2015 environmental standard, ISO 45001 Occupational Health and Safety Management System, and has a certified ANSI/ESD S20.20 Electrostatic Discharge Program. +• The Da Nang, Vietnam facility is additionally registered to IATF 16949 automotive standard. +• The Shanghai, China facility is additionally registered to IATF 16949 automotive standard, ISO 45001 Occupational Health and Safety Management System, ISO 14001:2015 environmental standard, and has a certified ANSI/ESD S20.20 Electrostatic Discharge Program. +• The Oakdale, Minnesota facility is additionally registered to ISO 13485:2016 medical devices standard, AS9100D aviation, space and defense standard, has a certified ANSI/ESD S20.20 Electrostatic Discharge Control Program, and is NADCAP certified. +• The Fayetteville, Arkansas facility is additionally registered to AS9100D aviation, space and defense standard and have a certified ANSI/ESD S20.20 Electrostatic Discharge Control Program. +• The Corinth, Mississippi facility is additionally registered to ISO 14001:2015 and ISO/IEC 80079-34 explosive atmospheres. +16 +• The Oakdale, Minnesota; Corinth, Mississippi; Fayetteville, Arkansas and Spokane, Washington facilities are all registered with the U.S. State Department for International Traffic in Arms Regulations (ITAR). +Item 3. LEGAL PROCEEDINGS +We are a party to certain lawsuits or claims in the ordinary course of business. We do not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on our financial position, results of operations or cash flow, although an adverse resolution against the Company in a fiscal quarter or year could have a material adverse effect on the Company’s results of operations in a particular quarter or year. For further details on claims, see Note 9. Commitments and Contingencies in the Notes to Consolidated Financial Statements. +Item 4. MINE SAFETY DISCLOSURES +Not Applicable +PART II +Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES +Market Information +Our common stock is traded on the NASDAQ Global Market under the symbol “KTCC.” Quarterly high and low sales prices for our common stock for fiscal year 2023 and fiscal year 2022 were as follows: +2023 2022 +High Low High Low +First Quarter $ 5.50 $ 4.00 $ 7.48 $ 6.45 +Second Quarter 5.18 4.03 6.73 5.95 +Third Quarter 7.50 4.33 6.55 5.26 +Fourth Quarter 7.53 5.18 5.74 4.27 +High and low stock prices are based on the daily sales prices reported by the NASDAQ Stock Market. These quotations represent prices between dealers without adjustment for markups, markdowns, and commissions, and may not represent actual transactions. +Holders and Dividends +As of July 1, 2023, we had 569 shareholders of common stock on record. As a result of our credit agreements, we are restricted from declaring or paying dividends in cash or stock without Bank of America’s prior written consent. We have not paid a cash dividend and do not anticipate payment of dividends in the foreseeable future. +Equity Compensation Plan Information +Information concerning securities authorized for issuance under our equity compensation plans is set forth in Part III, Item 12 of this Annual Report on Form 10-K, under the caption “Equity Compensation Plan Information,” and that information is incorporated herein by reference. +Performance Graph +We are a smaller reporting company as defined in Item 10(f)(1) of Regulation S-K and therefore are not required to provide the performance graph required in paragraph (e) of Item 201 of Regulation S-K. +17 +Item 6: [RESERVED] +Item 7: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +Overview +Key Tronic is a leading contract manufacturer offering value-added design and manufacturing services from its facilities in the United States, Mexico, China and Vietnam. We provide full engineering services, materials management, worldwide manufacturing facilities, assembly services, in-house testing, worldwide distribution and unparalleled customer service. Our customers include some of the world’s leading original equipment manufacturers, and our combined capabilities and vertical integration are proving to be a desirable offering to our expanded customer base. +Our domestic and international production capability provides our customers with benefits of improved supply-chain management, reduced inventories, lower transportation costs, and reduced product fulfillment time. We continue to make investments in all of our operating facilities to give us the production capacity, capabilities and logistical advantages to continue to win new business. The following information should be read in conjunction with the consolidated financial statements included herein and with Part II Item 1A, Risk Factors included as part of this filing. +Our mission is to provide our customers with superior manufacturing and engineering services at the lowest total cost for the highest quality products, and create long-term mutually beneficial business relationships by employing our “Trust, Commitment, Results” philosophy. +Executive Summary +During the fourth quarter of fiscal year 2023, we won new programs involving inventory control, clean energy, and distribution monitoring equipment. +We reported net sales of $588.1 million for fiscal year 2023, the highest annual revenue in the Company’s history, and up 11% from $531.8 million for fiscal year 2022. Record annual revenue and strong earnings in fiscal year 2023 was driven by successful new program ramps and increased demand from a number of longstanding customer programs. +Moving into fiscal 2024, we expect a strong Mexican Peso valuation to the US Dollar and relatively high interest expense to constrain our bottom line. At the same time, global logistics problems and heightened assurance of supply concerns continue to drive the favorable trend of contract manufacturing returning to North America. +For the first quarter of fiscal year 2024, the Company expects to report revenue in the range of $140 million to $150 million. We continue to see a trend of contract manufacturing returning to North America and a growing number of potential customers evaluating a migration of their China-based manufacturing to our facility in Vietnam. We move into fiscal year 2024 with a strong backlog and pipeline of potential new business, our inventory more in line with our revenue levels, and continuing improvement in the global supply issues and lower labor turnover. However, we are also seeing some softening in demand from several large customers and one large customer is pausing production during the next quarter to resolve certain of their design issues. Over the longer term, we are well positioned for continued growth and profitability. +We have continued to diversify our customer base by adding additional programs and customers. Our current customer relationships involve a variety of products including consumer electronics, electronic storage devices, plastics, household products, gaming devices, specialty printers, telecommunications, industrial equipment, military supplies, computer accessories, medical, educational, irrigation, automotive, transportation management, robotics, RFID, power supply, off-road vehicle equipment, fitness equipment, HVAC controls, consumer products, home building products, material handling systems, lighting equipment, consumer security products, smart security, architectural LED lighting, power meters and smart grid, wireless power solutions, sanitizer dispensing, automotive controllers, oil and gas drilling, power equipment, and wireless security. +Gross profit as a percentage of net sales was 8.1 percent in both fiscal year 2023 and 2022, respectively. During fiscal year 2023, the gross margins benefited by increased revenue levels along with some stabilization in the labor market. However, our gross margin was also adversely impacted by the strengthening of the Mexican Peso relative to the US Dollar. The level of gross margin is impacted by product mix, timing of the startup of new programs, facility utilization, and pricing within the electronics industry and material costs, which can fluctuate significantly from quarter-to-quarter and year-to-year. +Operating income as a percentage of net sales for fiscal year 2023 was 2.8 percent compared to 1.7 percent for fiscal year 2022. The increase in operating income as a percentage of net sales was primarily driven by the gains on insurance proceeds from the claim on a lightning strike at our Arkansas production facility. +Net income for fiscal year 2023 was $5.2 million or $0.47 per share, as compared to $3.4 million or $0.31 per share for fiscal year 2022. Earnings for fiscal 2023 continued to be adversely impacted by supply chain, transportation and logistics issues, and increased interest expense. +18 +We maintained a strong balance sheet with a current ratio of 2.3 and a debt-to-equity ratio of 0.99. Total cash used in operating activities as defined on our cash flow statement was $11.3 million during fiscal year 2023, as working capital has increased to support increased revenue. We believe we maintain sufficient liquidity for our expected future operations, dependent upon executing projected cash flows from operations and potentially adding additional credit capacities through refinancing current credit agreements or pursuing additional debt structures. +RESULTS OF OPERATIONS +Comparison of the Fiscal Year Ended July 1, 2023 with the Fiscal Year Ended July 2, 2022 +The following table sets forth for the periods indicated certain items of the consolidated statements of income expressed as a percentage of net sales. The financial information and discussion below should be read in conjunction with the consolidated financial statements and Footnotes contained in this Annual Report on Form 10-K. +Fiscal Year Ended +July 1, 2023 % of +net sales July 2, 2022 % of +net sales $ change % point +change +Net sales $ 588,135 100.0% $ 531,815 100.0% $ 56,320 — +Cost of sales 540,663 91.9 488,601 91.9 52,062 — +Gross profit 47,472 8.1 43,214 8.1 4,258 — +Operating expenses: +Research, development and engineering 9,735 1.7 9,821 1.8 (86) (0.1) +Selling, general and administrative 25,715 4.4 24,598 4.6 1,117 (0.2) +Gain on insurance proceeds, net of losses (4,301) (0.7) — (4,301) (0.7) +Total operating expenses 31,149 5.4 34,419 6.4 (3,270) (1.0) +Operating income 16,323 2.8 8,795 1.7 7,528 1.1 +Interest expense, net 10,023 1.7 5,104 1.0 4,919 0.7 +Income before income taxes 6,300 1.1 3,691 0.7 2,609 0.4 +Income tax provision 1,143 0.2 314 0.1 829 0.1 +Net income $ 5,157 0.9% $ 3,377 0.6% $ 1,780 0.3 +Effective income tax rate 18.1 % 8.5 % +Net Sales +The increase in net sales of $56.3 million from the prior fiscal year was primarily due to the successful ramp of new customer programs and increased demand from existing customers. However, the Company's revenue was constrained by tightening worldwide supply chain and transportation and logistics issues, which delayed the arrival of certain key components, causing factory downtime and overtime expenses. +The following table shows the revenue by industry sectors as a percentage of revenue for fiscal years 2023 and 2022: +Fiscal Year Ended +July 1, 2023 July 2, 2022 +Consumer 45 48 +Industrial 41 41 +Communication 9 7 +Transportation 3 1 +Gaming 1 1 +Medical 1 — +Printers — 1 +Computer and Peripheral — 1 +Total 100% 100% +19 +We provide services to customers in a number of industries and produce a variety of products for our customers in each industry. Key Tronic does not target any particular industry, but rather seeks to find programs that strategically fit our vertical manufacturing capabilities. As we continue to diversify our customer base and win new customers, we expect to continue to see a change in the industry concentrations of our revenue. +Sales to foreign locations represented 14.60% percent and 17.64% percent of our total net sales in fiscal years 2023 and 2022, respectively. +Cost of Sales +Total cost of sales as a percentage of net sales was 91.9 percent in fiscal year 2023 and 91.9 percent in fiscal year 2022. +We record our inventories at net realizable value based on specific identification of inventory against current demand and recent usage. We also consider our customers' ability to pay for inventory whether or not there is a lead-time assurance agreement for a specific program. The amounts charged to expense for these inventories were approximately $427,000 and $950,000 in fiscal years 2023 and 2022, respectively. +We provide warranties on certain products we sell and estimate warranty costs based on historical experience and anticipated product returns. Warranty expense is related to workmanship claims. The amounts charged to expense are determined based on an estimate of warranty exposure. The net warranty expense was approximately $313,000 and $446,000 in fiscal years 2023 and 2022, respectively. +Gross Profit +Gross profit as a percentage of net sales was 8.1 percent in fiscal years 2023 and 2022. During fiscal year 2023, the gross margins benefited by increased revenue levels along with some stabilization in the labor market. However, our gross margin was also adversely impacted by the strengthening of the Mexican Peso relative to the US Dollar. +Changes in gross profit margins reflect the impact of a number of factors that can vary from period to period, including product mix, start-up costs and efficiencies associated with new programs, product life cycles, sales volumes, capacity utilization of our resources, management of inventories, component pricing and shortages, end market demand for customers’ products, fluctuations in and timing of customer orders, and competition within the contract manufacturing industry. These and other factors can cause variations in operating results. There can be no assurance that gross margins will not decrease in future periods. +Research, Development and Engineering +Research, development and engineering expenses (RD&E) consist principally of employee related costs, third-party development costs, program materials, depreciation, and allocated information technology and facilities costs. Total RD&E expenses were $9.7 million and $9.8 million in fiscal years 2023 and 2022, respectively. Total RD&E expenses as a percent of net sales was 1.7 percent in fiscal year 2023 and 1.8 percent in fiscal year 2022. +Selling, General and Administrative +Selling, general, and administrative expenses (SG&A) consist principally of salaries and benefits, advertising and marketing programs, sales commissions, travel expenses, provision for doubtful accounts, facilities costs, and professional services. Total SG&A expenses were $25.7 million and $24.6 million in fiscal years 2023 and 2022, respectively. Total SG&A expenses as a percent of net sales were 4.4 percent and 4.6 percent in fiscal years 2023 and 2022, respectively. This 0.2 percentage point decrease in SG&A as a percentage of net sales is primarily related to an increase in legal expenses related specifically to the SEC’s review of the whistleblower complaint in fiscal year 2021. +20 +Interest Expense +We had net interest expense of $10.0 million and $5.1 million in fiscal years 2023 and 2022, respectively. The increase in interest expense is primarily related to increased interest rates, an increase in the average balance outstanding on our line of credit, and financing leases. +Income Tax Provision +We had an income tax expense of approximately $1.1 million during fiscal year 2023 and an income tax expense of approximately $0.3 million during fiscal year 2022. The income tax expense recognized during both fiscal years 2023 and 2022 was primarily a function of U.S. and foreign taxes recognized at statutory rates, the net benefit associated with federal research and development tax credits, the impact of foreign exchange gains in fiscal year 2023, and the net benefit of carrying back the fiscal year 2021 net operating tax losses to years with higher federal tax rates in fiscal year 2022. +We continually review our requirements for liquidity domestically to fund current operations, revenue growth, and to look for potential future acquisitions. We anticipate repatriating a portion of our unremitted foreign earnings. The estimated taxes associated with these expected repatriations are included in the income tax calculation. For further information on taxes, please review Footnote " Income Taxes” of the “Notes to Consolidated Financial Statements”. +International Subsidiaries +We offer customers a complete global manufacturing solution. Our facilities provide our customers the opportunity to have their products manufactured in the facility that best serves specific cost, product manufacturing, and distribution needs. The locations of our active foreign subsidiaries are as follows: +• Key Tronic Juarez, SA de CV owns five facilities and leases four facilities in Juarez, Mexico. These facilities include an SMT facility, an assembly and molding facility, a sheet metal fabrication facility, and assembly and warehouse facilities. This subsidiary primarily supports our U.S. operations. +• Key Tronic Computer Peripherals (Shanghai) Co., Ltd. leases one facility with SMT, assembly, global purchasing, and warehouse capabilities in Shanghai, China, which began operations in 1999. Its primary function is to provide contract manufacturing services. +• Key Tronic Vietnam leases one facility in Da Nang, Vietnam. This facility includes SMT, assembly, and warehouse capabilities. Its primary function is to provide contract manufacturing services for export. +Foreign sales (based on shipping instructions) from our worldwide operations, including domestic exports, were $85.9 million and $93.8 million in fiscal years 2023 and 2022, respectively. Products and manufacturing services provided by our subsidiary operations are often shipped to customers directly by the parent company. +RESULTS OF OPERATIONS +Comparison of the Fiscal Year Ended July 2, 2022 with the Fiscal Year Ended July 3, 2021 +To review the results of operations comparison of the fiscal year ended July 2, 2022 with the fiscal year ended July 3, 2021, please refer to our Annual Report on Form 10-K filed September 14, 2022 with the Securities and Exchange Commission or follow the link below. +https://www.sec.gov/ix?doc=/Archives/edgar/data/719733/000071973322000063/ktcc-20220702.htm +Capital Resources and Liquidity +Operating Cash Flow +Net cash used in operating activities for fiscal year 2023 was $11.3 million compared to $4.9 million in fiscal year 2022. The additional cash used in fiscal year 2023 was predominately used for revenue growth that required additional working capital in increased receivables and paying down supplier payables during the year. +The $11.3 million of net cash used in operating activities during fiscal year 2023 is primarily related to $5.2 million of net income adjusted for $9.5 million of depreciation and amortization, $14.8 million increase in accounts receivable, a $17.4 million decrease in inventory, a $16.0 million increase in other liabilities, partially offset by a $5.5 million decrease in accounts payable, $8.0 million increase in contract assets, and a $1.5 million increase in accrued compensation and vacation. +The $4.9 million of net cash used in operating activities during fiscal year 2022 was primarily related to $3.4 million of net income adjusted for $7.6 million of depreciation and amortization, $25.6 million increase in accounts receivable, a $19.4 million increase in inventory, a $3.6 million increase in other liabilities, partially offset by a $28.6 million increase in accounts payable, and a $2.8 million decrease in contract assets. +21 +Accounts receivable fluctuates based on the timing of shipments, terms offered, and collections. We purchase inventory based on customer forecasts and orders. When those forecasts and orders change, the amount of inventory may also fluctuate. Accounts payable fluctuates with changes in inventory levels, volume of inventory purchases, negotiated supplier terms, and taking advantage of early pay discounts. +Investing Cash Flow +Cash flows used in investing activities were $4.5 million for fiscal year 2023. Cash flows used in investing activities were $8.1 million in fiscal year 2022. Our primary use of cash in investing activities during fiscal years 2023 and 2022 was purchasing equipment to support increased production levels for new programs. During fiscal year 2023, cash flows used in investing activities also included prepayments on finance lease obligations. During fiscal year 2023, the source of cash provided by investing activities came from insurance claims paid for replacing equipment and facility repairs in our Arkansas facility related to a lightning strike and water damage. +Leases are often utilized when potential technical obsolescence and funding requirement advantages outweigh the benefits of equipment ownership. Capital expenditures and periodic lease payments are expected to be financed with internally generated funds as well as our revolving line of credit facility and equipment term loan . +Financing Cash Flow +Cash flows provided by financing activities were $17.7 million and $11.2 million in fiscal years 2023 and 2022, respectively. Our primary financing activities during fiscal year 2023 were proceeds from capital equipment finance leases and borrowings and repayments under our revolving line of credit facility; partially offset by repayments on our term loans and principal payments on finance leases. Our primary financing activities during fiscal year 2022 were repayments on our term loans as well as borrowings and repayments under our revolving line of credit facility. +As of July 1, 2023, approximately $4.6 million was available under the asset-based revolving credit facility and we were in compliance with our loan covenants. +Our cash requirements are affected by the level of current operations and new programs. We believe that projected cash from operations, funds available under the revolving credit facility and potential additional debt capacity will be sufficient to meet our working and fixed capital requirements for the foreseeable future. The Company further notes projected cash from operations is projected to improve in the coming quarters as supply chain availability will boost additional inventory turns and existing inventory is consumed by fulfilling customer backlog. As of July 1, 2023, we had approximately $3.6 million of cash held by foreign subsidiaries. If cash is to be repatriated in the future from these foreign subsidiaries, the Company would be subject to certain withholding taxes in the foreign jurisdictions. The total amount of tax payments required for the amount of foreign subsidiary cash on hand as of July 1, 2023 would approximate $64,000. +The Company also has approximately $33.2 million of foreign earnings that have not been repatriated to the U.S. Of that amount, the Company estimates that $7.6 million is to be repatriated in the future, requiring foreign withholding taxes of $0.8 million that is currently accrued in our deferred tax liabilities. The remaining $25.6 million is considered to be permanently reinvested in Mexico, China and Vietnam. If these amounts were required to be repatriated, we estimate it would create an additional $0.8 million in foreign withholding taxes payable. +We have accrued withholding taxes for expected future repatriation of foreign earnings as discussed in Note 6 of the “Notes to Consolidated Financial Statements”. +Off-Balance Sheet Arrangements and Contractual Obligations +In the normal course of business, we enter into contracts which obligate us to make payments in the future. We have certain contractual obligations that extend beyond fiscal year 2023 under lease obligations and debt arrangements. +As of July 1, 2023, we had open purchase order commitments for materials and other supplies. Actual needs under these blanket purchase orders fluctuate with our manufacturing levels and as such cannot be broken out between fiscal years. In addition, we have contracts with many of our customers that minimize our exposure to losses for material purchased within lead-times necessary to meet customer forecasts. Purchase orders generally can be cancelled without penalty within specified ranges that are determined in negotiations with our suppliers. These agreements depend in part on the type of materials purchased as well as the circumstances surrounding any requested cancellations. We do not use off-balance sheet financing techniques other than traditional operating leases, and we have not guaranteed the obligations of any entity that is not one of our wholly owned subsidiaries. +For a summary of our lease obligations as of July 1, 2023, please refer to Note 15 “Leases” of the “Notes to Consolidated Financial Statements.” +22 +For a summary of our long-term debt obligations as of July 1, 2023, please refer to Note 4 “Long-Term Debt” of the “Notes to Consolidated Financial Statements.” +Critical Accounting Policies and Estimates +Preparation of our consolidated financial statements requires management to make estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses. Note 1 “Significant Accounting Policies” of the “Notes to Consolidated Financial Statements” describes the significant accounting policies used in the preparation of our consolidated financial statements. Management believes the most complex and sensitive judgments, because of their significance to our consolidated financial statements, result primarily from the need to make estimates about effects of matters that are inherently uncertain. The most significant areas involving management judgments are described below. Actual results in these areas could differ from management’s estimates. +Revenue +The Company specializes in services ranging from product manufacturing to engineering and tooling services. The first step in its process for revenue recognition is to identify the contract with a customer. A contract is defined as an agreement between two or more parties that creates enforceable rights and obligations. A contract can be written, oral, or implied. The Company generally enters into manufacturing service agreements (“MSA”) with its customers that outlines the terms of the business relationship between the customer and the Company. This includes matters such as warranty, indemnification, transfer of title and risk of loss, liability for excess and obsolete inventory, pricing, payment terms, etc. The Company will also bid on a program-by-program basis for customers in which an executed MSA may not be in place. In these instances, as well as when we have an MSA in place, we receive customer purchase orders for specific quantities and timing of products. As a result, the Company considers its contract with a customer to be the combination of the MSA and the purchase order. The transaction price is fixed and set forth in each purchase order. In the Company's normal course of business, there are no variable pricing components, or material amounts refunded to customers in the form of refunds or rebates. +The Company assesses whether control of the product or services promised under the contract is transferred to the customer at a point in time (shipment) or over time (as we manufacture the product). The Company is first required to evaluate whether its contracts meet the criteria for 'over-time' or 'point-in-time' recognition. The Company has determined that for the majority of its contracts the Company is manufacturing products for which there is no alternative use due to the unique nature of the customer-specific product, IP and other contract restrictions. Further, the Company has an enforceable right to payment including a reasonable profit for performance completed to date with respect to these contracts. As a result, revenue is recognized under these contracts 'over-time' based on the input cost-to-cost method as it better depicts the transfer of control. This input method is based on the ratio of costs incurred to date as compared to the total estimated costs at completion of the performance obligation. For all other contracts that do not meet these criteria, such as manufacturing contracts for which the terms do not provide an enforceable right to payment for performance completed to date, the Company recognizes revenue when it has transferred control of the related manufactured products which generally occurs upon shipment to the customer. Revenue from engineering services is recognized over time as the services are performed. +Inactive, Obsolete, and Surplus Inventory Valuation +Inventories are stated at the lower of cost or net realizable value. Inventory valuation is determined using the first-in, first-out (FIFO) method. We write down inventories that we deem inactive, obsolete, or surplus to net realizable value. The write down is calculated based upon the demand for the products that we produce to value this related inventory at net realizable value. Demand is determined by expected sales, customer purchase orders, or customer forecasts. If expected sales do not materialize, excess inventory would be the result and a write down of that inventory against earnings would occur. In the case where we have purchased material based upon a customer’s forecast or purchase orders, we are usually covered by lead-time assurance agreements or purchase orders with each customer. These contracts state that the financial liability for material purchased within agreed upon lead-time and based upon the customer’s forecasts, lies with the customer. If we purchase material outside the lead-time assurance agreement and the customer’s forecasts do not materialize or if we have no lead-time assurance agreement for a specific program, we would have the financial liability and may have to charge inactive, obsolete or surplus inventory against earnings. We also write down inventory values related to specific customers covered by lead-time assurance agreements when those customers are experiencing financial difficulties or reimbursement is not reasonably assured. +23 +Allowance for Doubtful Accounts +We value our accounts receivable net of an allowance for doubtful accounts. As of July 1, 2023, the allowance for doubtful accounts was approximately $23,000. As of July 2, 2022, the allowance for doubtful accounts was approximately $12,000. This allowance is based on estimates of the portion of accounts receivable that may not be collected in the future. The estimates used are based primarily on specific identification of potentially uncollectible accounts. Such accounts are identified using publicly available information in conjunction with evaluations of current payment activity. However, if any of our customers were to develop unexpected and immediate financial problems that would prevent payment of open invoices, we could incur additional and possibly material expenses that would negatively impact earnings. +Income Taxes +Income tax expense includes U.S. and international income taxes and a provisional estimate for U.S. taxes on undistributed earnings of foreign subsidiaries. We do not record foreign withholding taxes on undistributed earnings of international subsidiaries that are deemed to be permanently reinvested. Certain income and expenses are not reported in tax returns and financial statements in the same year. The tax effect of such temporary differences is reported as deferred income taxes. The deferred income taxes are classified as long-term assets or liabilities. The most significant areas involving management judgments include deferred income tax assets and liabilities, uncertain tax positions, and research and development tax credits. Our estimates of the realization of the deferred tax assets related to our tax credits are based upon our estimates of future taxable income which may change. +New and Future Accounting Pronouncements +See Note 1 “Significant Accounting Policies” of the “Notes to Consolidated Financial Statements.” +24 +Item 7A: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Interest Rate Risk +We are subject to the risk of fluctuating interest rates in the normal course of business. Our major market risk relates to our secured debt. Our asset-based senior secured revolving credit facility, and equipment financing facility are secured by substantially all of our assets. The interest rates applicable to our asset-based senior secured revolving credit facility fluctuate with SOFR rates. There was outstanding $115.4 million in borrowings under our asset-based senior secured revolving credit facility and $9.9 million outstanding on our equipment financing facil ities as of July 1, 2023. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity”in this Annual Report on Form 10-K and Note 4 “Long-Term Debt” of the “Notes to Consolidated Financial Statements” for additional information regarding our revolving credit facility and term loans. +Foreign Currency Exchange Risk +A significant portion of our operations are in foreign locations. As a result, transactions occur in currencies other than the U.S. dollar. Exchange rate fluctuations among other currencies used by us directly and indirectly affect our financial results. We may use Mexican peso forward contracts to hedge future foreign currency fluctuations for a portion of our Mexican peso denominated expenses. There were no foreign currency forward contracts outstanding as of July 1, 2023. For additional information regarding our derivative instruments, please refer to Note 10 “Derivative Financial Instruments” of the “Notes to Consolidated Financial Statements.” +25 +Item 8: +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Report of Independent Registered Public Accounting Firm +To the Shareholders and the Board of Directors of +Key Tronic Corporation +Opinion on the Financial Statements +We have audited the accompanying consolidated balance sheets of Key Tronic Corporation (the “Company”) as of July 1, 2023 and July 2, 2022, the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of July 1, 2023 and July 2, 2022, and the consolidated results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America. +Basis for Opinion +These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. +Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. +Critical Audit Matter +The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. +As described in Notes 1 and 12 to the consolidated financial statements, the Company reported revenue of $588.1 million for the year ended July 1, 2023, of which $573.4 million related to revenue recognized over time. The Company has determined that for the majority of its contracts the Company is manufacturing products for which there is no alternative use due to the unique nature of the customer-specific product, intellectual property, and other contract restrictions. The Company has an enforceable right to payment including a reasonable profit for performance completed to date with respect to these contracts. As a result, revenue is recognized under these contracts over-time based on the input cost-to-cost method as it better depicts the transfer of control. This input method is based on the ratio of costs incurred to date as compared to the total estimated costs at completion of the performance obligation. +We identified revenue recognized over time on contracts for manufacturing products as a critical audit matter. Management’s calculation includes reports with varying elements, to estimate costs incurred to date for various performance obligations. Auditing management’s estimates used in the calculation of revenue recognized over time involved especially challenging and subjective auditor judgment when performing audit procedures and evaluating the results of those procedures. +The primary procedures we performed to address this critical audit matter included: +26 +• Testing the design, implementation, and operating effectiveness of internal controls relating to revenue recognized over time, including controls over the quarterly calculation of in-process contracts, and the related contract assets. +• Evaluating the methodology of estimating costs incurred to date on in-process contracts and testing the completeness and accuracy of the system generated reports used to estimate costs incurred by recalculating the expected costs on in-process contracts, vouching to source documents, tracing in-process orders to subsequent sales and shipping documentation within a reasonable period after year-end, identifying and testing significant assumptions used in the revenue calculation, and performing data validation procedures. +• Comparing margins realized to trending historic margins, and comparing total revenue recognized to independent expectations of total revenues disaggregated by revenue stream. +• Performing cutoff procedures to test that revenue transactions were recorded in the appropriate period. +/s/ Moss Adams LLP +Seattle, Washington +September 26, 2023 +We have served as the Company’s auditor since 2021 . +27 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED BALANCE SHEETS +(In thousands) +July 1, 2023 July 2, 2022 +ASSETS +Current assets: +Cash and cash equivalents $ 3,603 $ 1,707 +Trade receivables, net of allowance for doubtful accounts of $ 23 and $ 12 +150,600 135,876 +Contract assets 29,925 21,974 +Inventories, net 137,911 155,741 +Other 27,510 24,710 +Total current assets 349,549 340,008 +Property, plant and equipment, net 28,870 26,012 +Operating lease right-of-use assets, net 16,202 16,731 +Other assets: +Deferred income tax asset 12,254 10,055 +Other 11,397 14,117 +Total other assets 23,651 24,172 +Total assets $ 418,272 $ 406,923 +LIABILITIES AND SHAREHOLDERS ’ EQUITY +Current liabilities: +Accounts payable $ 115,899 $ 121,393 +Accrued compensation and vacation 13,351 11,836 +Current portion of debt, net 7,849 7,402 +Other 14,867 23,036 +Total current liabilities 151,966 163,667 +Long-term liabilities: +Term loans 6,726 5,716 +Revolving loan 114,805 94,577 +Operating lease liabilities 10,317 12,023 +Deferred income tax liability 274 64 +Other long-term obligations 3,567 5,998 +Total long-term liabilities 135,689 118,378 +Total liabilities 287,655 282,045 +Commitments and contingencies (Note 9) +Shareholders’ equity: +Common stock, no par value—shares authorized 25,000 ; issued and outstanding 10,762 and 10,762 shares, respectively +47,728 47,474 +Retained earnings 82,986 77,829 +Accumulated other comprehensive (loss) income ( 97 ) ( 425 ) +Total shareholders’ equity 130,617 124,878 +Total liabilities and shareholders’ equity $ 418,272 $ 406,923 +See accompanying notes to consolidated financial statements. +28 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF INCOME +(In thousands, except per share amounts) +Fiscal Year Ended +July 1, 2023 July 2, 2022 +Net sales $ 588,135 $ 531,815 +Cost of sales 540,663 488,601 +Gross profit 47,472 43,214 +Research, development and engineering expenses 9,735 9,821 +Selling, general and administrative expenses 25,715 24,598 +Gain on insurance proceeds, net of losses ( 4,301 ) — +Total operating expenses 31,149 34,419 +Operating income 16,323 8,795 +Interest expense, net 10,023 5,104 +Income before income taxes 6,300 3,691 +Income tax provision 1,143 314 +Net income $ 5,157 $ 3,377 +Net income per share — Basic $ 0.48 $ 0.31 +Weighted average shares outstanding — Basic 10,762 10,762 +Net income per share — Diluted $ 0.47 $ 0.31 +Weighted average shares outstanding — Diluted 10,938 11,063 +See accompanying notes to consolidated financial statements. +29 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME +(In thousands) +Fiscal Year Ended +July 1, 2023 July 2, 2022 +Comprehensive income: +Net income $ 5,157 $ 3,377 +Other comprehensive income: +Unrealized gain (loss) on hedging instruments, net of tax 328 ( 2,497 ) +Comprehensive income $ 5,485 $ 880 +Other comprehensive income for fiscal years 2023 and 2022 is reflected net of tax provision (benefit) of approximately $ 0 and $( 0.8 ) million, respectively. +See accompanying notes to consolidated financial statements. +30 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Fiscal Year Ended +July 1, 2023 July 2, 2022 +Operating activities: +Net income $ 5,157 $ 3,377 +Adjustments to reconcile net income to cash used in operating activities: +Depreciation and amortization 9,542 7,562 +Amortization of interest rate swap 328 301 +Amortization of deferred loan costs 154 143 +Noncash lease expense 5,712 4,261 +Inventory write-down to net realizable value 427 950 +Provision for warranty 313 446 +Provision for doubtful accounts 37 67 +Gain on disposal of assets ( 21 ) ( 12 ) +Gain on insurance proceeds, net of losses ( 4,301 ) — +Share-based compensation expense 254 293 +Deferred income taxes ( 1,989 ) 481 +Changes in operating assets and liabilities +Trade receivables ( 14,760 ) ( 25,619 ) +Contract assets ( 7,951 ) 2,807 +Inventories 17,403 ( 19,362 ) +Other assets ( 1,684 ) ( 5,912 ) +Accounts payable ( 5,494 ) 28,569 +Accrued compensation and vacation 1,515 365 +Other liabilities ( 15,953 ) ( 3,624 ) +Cash used in operating activities ( 11,311 ) ( 4,907 ) +Investing activities: +Purchases of property and equipment ( 9,771 ) ( 6,813 ) +Proceeds from sale of fixed assets 1,925 14 +Prepayments on finance lease obligations ( 188 ) ( 1,252 ) +Proceeds from insurance 3,500 — +Cash used in investing activities ( 4,534 ) ( 8,051 ) +Financing activities: +Payment of financing costs ( 245 ) ( 118 ) +Proceeds from issuance of long term debt 4,375 11,594 +Repayments of long-term debt ( 2,417 ) ( 2,143 ) +Borrowings under revolving credit agreement 596,121 581,893 +Repayments of revolving credit agreement ( 575,802 ) ( 577,703 ) +Principal payments on finance leases ( 4,291 ) ( 2,331 ) +Cash provided by financing activities 17,741 11,192 +Net increase (decrease) in cash and cash equivalents 1,896 ( 1,766 ) +Cash and cash equivalents, beginning of period 1,707 3,473 +Cash and cash equivalents, end of period $ 3,603 $ 1,707 +Supplemental cash flow information: +Interest payments $ 802 $ 5,110 +Income tax payments, net of refunds $ 1,414 $ 1,315 +Recognition of operating lease liabilities and right-of-use assets $ 5,184 $ 5,247 +Recognition of financing lease liabilities and right-of-use assets $ 1,940 $ 13,096 +See accompanying notes to consolidated financial statements. +31 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY +(In thousands) +Shares Common +Stock Retained +Earnings Accumulated +Other +Comprehensive +Income (Loss) Total +Shareholders’ +Equity +Balances, July 3, 2021 10,762 47,181 74,452 2,072 $ 123,705 +Net income — — 3,377 — 3,377 +Unrealized gain on hedging instruments, net of tax — — — ( 2,497 ) ( 2,497 ) +Share-based compensation — 293 — — 293 +Balances, July 2, 2022 10,762 $ 47,474 $ 77,829 $ ( 425 ) $ 124,878 +Net income — 5,157 — 5,157 +Unrealized loss on hedging instruments, net of tax — — — 328 328 +Share-based compensation — 254 — — 254 +Balances, July 1, 2023 10,762 $ 47,728 $ 82,986 $ ( 97 ) $ 130,617 +See accompanying notes to consolidated financial statements. +32 +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. SIGNIFICANT ACCOUNTING POLICIES +Business +Key Tronic Corporation and subsidiaries (the Company) is engaged in contract manufacturing for original equipment manufacturers (OEMs) and also manufactures keyboards and other input devices. The Company’s headquarters are located in Spokane Valley, Washington with manufacturing operations in Oakdale, Minnesota; Fayetteville, Arkansas; Corinth, Mississippi; and foreign manufacturing operations in Juarez, Mexico; Shanghai, China; and Da Nang, Vietnam. +Due to the COVID-19 pandemic, the Company has seen extreme shifts in demand from its customer base, supply chain and logistics risks. The possibility of future temporary closures, as well as adverse fluctuations in customer demand, freight and expedite costs, precautionary safety expenses and labor shortages, collectability of accounts, and future supply chain disruptions during the rapidly changing COVID-19 environment can materially impact operating results. Additionally, continued adverse macroeconomic conditions and significant currency exchange fluctuations can also materially impact operating results. +Liquidity +Historically, we have financed operations and met our capital expenditure requirements primarily through cash flows provided by operations and borrowings under our credit facilities. We generated operating and net income of $ 16.3 million and $ 5.2 million, respectively, during the 12-month period ended July 1, 2023 and have positive working capital of $ 197.6 million as of July 1, 2023. Due to the timing between the procurement of raw materials, production cycle and payment from our customers, we have relied on borrowings on our credit facilities to fund operations as the Company increased its revenues and backlog during fiscal year 2023. Based on current projections, we anticipate generating cash from operations as revenue slightly decreases in the first quarter of fiscal year 2024 and decreasing working capital requirements as existing backlog is manufactured and shipped. +As of July 1, 2023, we have limited additional borrowing capacity on our credit facility. We are in discussions with multiple financial institutions to extend the borrowing capacity on our credit facility. If we are unable to meet projected operating results or extend our borrowing capacity, we may need to delay the purchase of raw materials or require our customers to fund inventory raw material costs ahead of production. Other options to increase our liquidity include factoring receivables or leveraging foreign owned assets for additional borrowing capacity. We believe that projected cash from operations, funds available under our asset-based revolving credit facility and additional financing options will be sufficient to meet our working and fixed capital requirements for at least the next 12 months. +Reclassifications +Certain prior period reclassifications were made to conform with the current period presentation. These reclassifications had no effect on reported income, comprehensive income, cash flows, total assets, or shareholders' equity as previously reported. +Principles of Consolidation +The consolidated financial statements include the Company and its wholly owned subsidiaries in the United States, Mexico, China and Vietnam. Intercompany balances and transactions have been eliminated during consolidation. +Use of Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates include the allowance for doubtful receivables, calculating inventory impairments related to obsolete and non-saleable inventories to value at net realizable value, deferred tax assets and liabilities, uncertain tax positions, impairment of long-lived assets, medical self-funded insurance liability, long-term incentive compensation accrual, the provision for warranty costs, and the fair value of stock appreciation rights granted under the Company’s share-based compensation plan. Due to uncertainties with respect to the assumptions and estimates, actual results could differ from those estimates. +Cash and Cash Equivalents +The Company considers investments with an original maturity of three months or less to be cash equivalents. Cash equivalents are carried at cost, which approximates fair value. The Company may have cash and cash equivalents at financial institutions that are in excess of federally insured limits from time to time. +Allowance for Doubtful Accounts +33 +The Company evaluates the collectability of accounts receivable and records an allowance for doubtful accounts, which reduces the receivables to an amount that management reasonably estimates will be collected. A specific allowance is recorded against receivables considered to be impaired based on the Company’s knowledge of the financial condition of the customer. In determining the amount of the allowance, the Company considers several factors including the aging of the receivables, the current business environment and historical experience. After all attempts to collect a receivable have failed, the receivable is written off against the allowance. +Inventories +Inventories are stated at the lower of cost or net realizable value. Inventory valuation is determined using the first-in, first-out (FIFO) method. Customer orders are based upon forecasted quantities of product manufactured for shipment over defined periods. Raw material inventories are purchased to fulfill these customer requirements. Within these arrangements, customer demands for products frequently change, sometimes creating excess and obsolete inventories. The Company regularly reviews raw material inventories by customer for both excess and obsolete quantities. Wherever possible, the Company attempts to recover its full cost of excess and obsolete inventories from customers or, in some cases, through other markets. When it is determined that the Company’s carrying cost of such excess and obsolete inventories cannot be recovered in full, a charge is taken against income for the difference between the carrying cost and the estimated realizable amount. We also reserve for inventory related to specific customers covered by lead-time assurance agreements when those customers are experiencing financial difficulties or reimbursement is not reasonably assured. +Property, Plant and Equipment +Property, plant and equipment are carried at cost and depreciated using straight-line methods over the expected useful lives of the assets. Repairs and maintenance costs are expensed as incurred. +Leases +Lease assets and liabilities are initially recognized based on the present value of lease payments over the lease term calculated using the Company’s incremental borrowing rate, unless the implicit rate is readily determinable. Our incremental borrowing rate represents the rate of interest that we would have to pay to borrow on a collateralized basis over a similar term in a similar economic environment. Lease assets also include any lease prepayments. Lease terms include options to extend or terminate the lease when it is reasonably certain that those options will be exercised. Leases are classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the consolidated statements of income. For further information, please refer to Footnote “Leases” of the “Notes to Consolidated Financial Statements.” +Impairment of Long-lived Assets +The Company, using its best estimates based on reasonable and supportable assumptions and projections, reviews assets for impairment whenever events or changes in circumstances have indicated that the carrying amount of its assets might not be recoverable. Impaired assets are reported at the lower of cost or fair value. +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. Management reviews the adequacy of this accrual quarterly based on historical analyses and anticipated product returns. +Self-funded Insurance +The Company self-funds its domestic employee health plans. The Company contracts with a separate administrative service company to supervise and administer the programs and act as its representative. The Company reduces its risk under this self-funded platform by purchasing stop-loss insurance coverage for high dollar individual claims. In addition, if the aggregate annual claims amount to more than 125 percent of expected claims for the plan year this insurance will also pay those claims amounts exceeding that level. +The Company estimates its exposure for claims incurred but not paid at the end of each reporting period and uses historical claims data supplied by the Company’s broker to estimate its self-funded insurance liability. This liability is subject to a total limitation that varies based on employee enrollment and factors that are established at each annual contract renewal. Actual claims experience may differ from the Company’s estimates. Costs related to the administration of the plan and related claims are expensed as incurred. +Revenue Recognition +The first step in its process for revenue recognition is to identify the contract with a customer. A contract is defined as an agreement between two or more parties that creates enforceable rights and obligations. A contract can be written, oral, or implied. The Company generally enters into manufacturing service agreements (“MSA”) with its customers that outlines the terms of the business relationship between the customer and the Company. This includes matters such as warranty, +34 +indemnification, transfer of title and risk of loss, liability for excess and obsolete inventory, pricing, payment terms, etc. The Company will also bid on a program-by-program basis for customers in which an executed MSA may not be in place. In these instances, as well as when we have an MSA in place, we receive customer purchase orders for specific quantities and timing of products. As a result, the Company considers its contract with a customer to be the combination of the MSA and the purchase order. The transaction price is fixed and set forth in each purchase order. In the Company's normal course of business, there are no variable pricing components, or material amounts refunded to customers in the form of refunds or rebates. +The Company assesses whether control of the product or services promised under the contract is transferred to the customer at a point in time (shipment) or over time (as we manufacture the product). The Company is first required to evaluate whether its contracts meet the criteria for 'over-time' or 'point-in-time' recognition. The Company has determined that for the majority of its contracts the Company is manufacturing products for which there is no alternative use due to the unique nature of the customer-specific product, IP and other contract restrictions. The Company has an enforceable right to payment including a reasonable profit for performance completed to date with respect to these contracts. As a result, revenue is recognized under these contracts 'over-time' based on the input cost-to-cost method as it better depicts the transfer of control. This input method is based on the ratio of costs incurred to date as compared to the total estimated costs at completion of the performance obligation. For all other contracts that do not meet these criteria, such as manufacturing contracts for which the terms do not provide an enforceable right to payment for performance completed to date, the Company recognizes revenue when it has transferred control of the related manufactured products which generally occurs upon shipment to the customer. Revenue from engineering services is recognized over time as the services are performed. +Shipping and Handling Fees +The Company classifies costs associated with shipping and handling fees as a component of cost of goods sold. Customer billings related to shipping and handling fees are reported as revenue. +Research, Development and Engineering +Research, development and engineering expenses include unreimbursed contract manufacturing costs as well as design and engineering costs associated with the production of contract manufacturing programs. Research, development and engineering costs are expensed as incurred. +Income Taxes +Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the estimated future tax consequences and benefits attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities for a change in tax rates is recognized in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amount that is more likely than not to be realized. +We utilize a two-step approach to recognizing and measuring uncertain tax positions. The first step is to evaluate the tax position for recognition by determining if the weight of available evidence indicates it is more likely than not that the position will be sustained on audit, including resolution of related appeals or litigation processes, if any. The second step is to measure the tax benefit as the largest amount which is more than 50% likely of being realized upon ultimate settlement. We consider many factors when evaluating and estimating our tax positions and tax benefits, which may require periodic adjustments based on new assessments and changes in estimates and which may not accurately forecast actual outcomes. Our policy is to recognize interest and penalties related to the underpayment of income taxes as a component of income tax provision. The tax years 2003 through the present remain open to examination by the major U.S. taxing jurisdictions to which we are subject. For further discussions, please refer to Footnote “Income Taxes” of the “Notes to Consolidated Financial Statements.” +Derivative Instruments and Hedging Activities +The Company has previously entered into foreign currency forward contracts and an interest rate swap which are accounted for as cash flow hedges in accordance with ASC 815, Derivatives and Hedging . The effective portion of the gain or loss on the derivative is reported as a component of accumulated other comprehensive income (AOCI) and is reclassified into earnings in the same period in which the underlying hedged transaction affects earnings. The derivative’s effectiveness represents the change in fair value of the hedge that offsets the change in fair value of the hedged item. As of July 1, 2023, the Company did not have any outstanding foreign currency forward contracts. +Earnings Per Common Share +Basic earnings per common share is computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is computed by dividing net income by the combination of other potentially dilutive weighted average common shares and the weighted average number of common shares outstanding +35 +during the period using the treasury stock method. The computation assumes the proceeds from the exercise of stock options were used to repurchase common shares at the average market price during the period. The computation of diluted earnings per common share does not assume conversion, exercise, or contingent issuance of common stock equivalent shares that would have an anti-dilutive effect on earnings per share. +Foreign Currency Transactions +The functional currency of the Company’s subsidiaries in Mexico, China and Vietnam is the U.S. dollar. Realized foreign currency transaction gains and losses for local currency denominated assets and liabilities are included in cost of goods sold. +Fair Value of Financial Instruments +The carrying values of cash and cash equivalents, accounts receivable, current liabilities, and non-current operating lease liability are reflected on the balance sheets at July 1, 2023 and July 2, 2022, reasonably approximate their fair value. The Company had an outstanding balance on the line of credit of $ 115.4 million as of July 1, 2023 and $ 95.1 million as of July 2, 2022, with a carrying value that reasonably approximates the fair value. The Company had an outstanding balance on the term loan of $ 3.4 million as of July 1, 2023 and $ 4.6 million as of July 2, 2022, with a carrying value that reasonably approximates the fair value. The equipment term loans were $ 6.5 million as of July 1, 2023 and $ 3.3 million as of July 2, 2022, with a carrying value that reasonably approximates the fair value. +Share-based Compensation +The Company’s incentive plan may provide for equity awards to employees in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, stock units, performance shares, performance units, and other stock-based awards. Compensation cost is recognized on a straight-line basis over the requisite employee service period, which is generally the vesting period, and is included in cost of goods sold, research, development and engineering, and selling, general, and administrative expenses. Share-based compensation is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on historical experience and future expectations. +Newly Adopted and Recent Accounting Pronouncements +In January 2021, FASB issued Accounting Standard Update (ASU) 2021-01, Reference Rate Reform (Topic 848) to identify alternative reference rates that are more observable or transaction based and less susceptible to manipulation. The Company is currently assessing the effects on its consolidated financial statements, and it intends to adopt the guidance as it becomes effective. +In March of 2020, the FASB issued ASU 2020-03, Codification Improvements to Financial Instruments, which clarifies specific issues raised by stakeholders. Specifically, the ASU clarifies the following: 1) that all entities are required to provide the fair value option disclosures in ASC 825, Financial Instruments 2) clarifies that the portfolio exception in ASC 820, Fair Value Measurement, applies to nonfinancial items accounted for as derivatives under ASC 815, Derivatives and Hedging; 3) clarifies that for purposes of measuring expected credit losses on a net investment in a lease in accordance with ASC 326, Financial Instruments - Credit Losses, the lease term determined in accordance with ASC 842, Leases, should be used as the contractual term; 4) clarifies that when an entity regains control of financial assets sold, it should recognize an allowance for credit losses in accordance with ASC 326; and 5) aligns the disclosure requirements for debt securities in ASC 320, Investments - Debt Securities, with the corresponding requirements for depository and lending institutions in ASC 942, Financial Services - Depository and Lending. The amendments in the ASU have various effective dates and transition requirements which are dependent on timing of adoption of ASU 2016-13. The Company is currently assessing the effects on its consolidated financial statements, and it intends to adopt the guidance as they become effective. +In June 2016, the FASB issued ASU 2016-13 “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” and also issued subsequent amendments to the initial guidance: ASU 2018-19, ASU 2019-04 and ASU 2019-05, which replaces the existing incurred loss impairment model with an expected credit loss model and requires a financial asset measured at amortized cost to be presented at the net amount expected to be collected. The guidance is effective for the Company beginning in the first quarter of fiscal year 2024 with early adoption permitted. The Company is currently assessing the impact on its consolidated financial statements, and it intends to adopt the guidance when it becomes effective in the first quarter of fiscal year 2024. +Fiscal Year +The Company operates on a 52/53 week fiscal year. Fiscal years end on the Saturday nearest June 30. As such, fiscal years 2023 and 2022 ended on July 1, 2023 and July 2, 2022, respectively. Fiscal years 2022 and 2023 were 52 week years. +36 +2. INVENTORIES +Net inventory as of July 1, 2023 is $ 137.9 million compared to $ 155.7 million as of July 2, 2022. Substantially all of the Company’s inventory balances are raw materials. +3. PROPERTY, PLANT AND EQUIPMENT +Property, plant and equipment consists of the following: +Life July 1, 2023 July 2, 2022 +(in years) (in thousands) +Land — $ 4,034 $ 4,034 +Buildings and improvements +3 to 30 +26,459 25,841 +Equipment +1 to 10 +77,823 71,180 +Furniture and fixtures +3 to 5 +5,418 5,286 +Total Property, Plant and Equipment 113,734 106,341 +Accumulated depreciation ( 84,864 ) ( 80,329 ) +Property, Plant and Equipment, net $ 28,870 $ 26,012 +Fiscal Year Ended +July 1, 2023 July 2, 2022 +(in thousands) +Depreciation expense $ 4,700 $ 4,940 +4. LONG-TERM DEBT +On August 14, 2020, the Company entered into a loan agreement with Bank of America. The Loan Agreement replaces the Company’s prior amended and restated credit agreement, as amended, with Wells Fargo Bank. The Loan Agreement provides for a five-year asset-based senior secured revolving credit facility of up to $ 93 million, maturing on August 14, 2025. +On September 3, 2021, the Company entered into an amendment to the Company's current loan agreement with Bank of America. The amendment increases the Company's current credit facility of $ 93 million to $ 120 million, subject to the Company's borrowing base, maturing on September 3, 2026. +On August 26, 2022, the Company entered into a third amendment to the loan agreement with Bank of America. The amendment removed the cash flow leverage ratio covenant and increased the interest rate by 25 basis points. +In the third quarter of fiscal year 2023, the Company entered into equipment financing agreements with Ameris Bank dba Balboa Capital ("Balboa Capital") totaling $ 4.4 million related to the Company’s existing manufacturing equipment that bears an interest rate range of 6 % - 8 % and matures in the third quarter of fiscal 2029. Under these agreements, equal monthly payments of $ 75,000 commenced in the third quarter of fiscal year 2023 and will continue through the maturity of the equipment financing facility in the third quarter of fiscal 2029. The Company had an outstanding balance $ 4.1 million as of July 1, 2023. +As of July 1, 2023, the Company had an outstanding balance under the asset-based revolving credit facility of $ 115.4 million, $ 0.3 million in outstanding letters of credit and $ 4.6 million available for future borrowings. +As of July 2, 2022, the Company had an outstanding balance under the asset-based revolving credit facility of $ 95.1 million, $ 0.3 million in outstanding letters of credit and $ 10.8 million available for future borrowings. +On August 14, 2020, the Company also entered into a $ 5.0 million equipment financing facility with Bank of America relating to the Company’s existing U.S. manufacturing equipment that bears interest at 4.85 % and matures on August 14, 2025. Under this loan agreement, equal monthly payments of approximately $ 94,000 commenced on September 14, 2020 and will continue through the maturity of the equipment financing facility on August 14, 2025. As of July 1, 2023, the Company had an outstanding balance of $ 2.3 million. As of July 2, 2022, the Company had an outstanding balance of $ 3.3 million. +Generally, the interest rate applicable to loans under the Bank of America loan agreement will be, at the Company’s option: (i)(A) the base rate which is the highest of (a) the Prime Rate for such day, (b) the Federal Funds Rate for such day plus 0.50 %, or (c) Term SOFR for a one month interest period as of such day, plus 1.00 % (provided that in no event shall the base rate be less than zero), plus the applicable interest margin for base rate loans; and (B) SOFR rate for an applicable interest period, plus +37 +the applicable interest margin for SOFR rate loans. Depending on average daily excess borrowing availability over applicable periods under the Credit Facility, applicable interest margins on: (x) base rate loans will be 1.50 - 2.00 %; and (y) SOFR rate loans will be 2.50 - 3.00 %, resetting on a quarterly basis beginning in early 2021. If there is an event of default under the loan agreement, all loans and other obligations will bear interest at a rate of an additional 2.00 % on the last change rates above otherwise applicable interest rates. In addition to interest charges, the Company is required to pay a fee of 0.25 % per annum on the unused portion of the Credit Facility, monthly in arrears. +On November 24, 2020, the Company entered into a $ 6.0 million financing facility related to the Company’s existing real estate located in Mexico that bears interest at 5.52 % and matures on April 24, 2026. Under this loan agreement, equal monthly payments of $ 100,000 commenced on May 24, 2021 and will continue through the maturity of the financing facility on April 24, 2026. The Company had an outstanding balance of $ 3.4 million and $ 4.6 million as of July 1, 2023 and July 2, 2022, respectively. +The interest rates on outstanding debt as of July 1, 2023 range from 4.85 % - 8.22 % compared to 4.50 % - 5.52 % as of July 2, 2022. +Debt maturities as of July 1, 2023 for the next five years are as follows (in thousands): +Fiscal Years Ending Amount +2024 $ 2,862 +2025 2,959 +2026 1,905 +2027 116,166 +2028 - Thereafter $ 1,367 +Total debt $ 125,259 +Unamortized debt issuance costs 591 +Long-term debt, net of debt issuance costs $ 124,668 +The Company must comply with certain financial covenants, including a fixed charge coverage ratio and a cash flow leverage ratio. The credit agreement requires the Company to grant certain inspection rights to Bank of America, limit or restrict the Company’s cash management; limit or restrict the ability of the Company to incur additional liens, make acquisitions or investments, incur additional indebtedness, engage in mergers, consolidations, liquidations, dissolutions, or dispositions, pay dividends or other restricted payments, prepay certain indebtedness, engage in transactions with affiliates, and use proceeds. Management believes the Company was in compliance with all financial covenants as of July 1, 2023. +5. INCOME TAXES +Income tax benefit consists of the following: +Fiscal Year Ended +July 1, 2023 July 2, 2022 +(in thousands) +Current income tax provision (benefit): +United States $ 998 $ ( 2,179 ) +Foreign 2,134 2,012 +3,132 ( 167 ) +Deferred income tax provision (benefit): +United States ( 2,130 ) 443 +Foreign 141 38 +( 1,989 ) 481 +Total income tax provision $ 1,143 $ 314 +The Company has gross tax credit carryforwards of approximately $ 9.8 million at July 1, 2023 consisting of federal research and development (R&D) tax credits. +Management has reviewed all deferred tax assets for purposes of determining whether a valuation allowance may be required. A valuation allowance against deferred tax assets is required if it is more likely than not that some of the deferred tax assets will not be realized. Based upon the Company’s profitability, forecasted income, and evaluation of all other positive and negative evidence, management determined that it is more likely than not that the deferred tax assets will be realized. +38 +In the fourth quarter of fiscal year 2022, the Company, with its fiscal year 2021 federal income tax return, made automatic changes in tax accounting methods that created a fiscal year 2021 tax net operating loss. This loss was carried back to the tax years ending in 2016, 2017, and 2019, resulting in a tax benefit of $ 0.6 million due to the higher federal income tax rate in effect in the years ending in 2016 and 2017. +On January 27, 2021, the Company received official notice from the Vietnamese tax authorities, confirming tax benefits awarded related to the Company’s principal product line in Vietnam (the “Tax Holiday”). Under the Tax Holiday, the tax rate applied to income derived from this product line will be zero percent for four years beginning with fiscal year 2021, then five percent for nine years, then ten percent for one year (as opposed to the normal twenty percent Vietnamese statutory rate). +The Company evaluated tax law changes and regulatory guidance issued through the quarter. Such changes and regulations include guidance under Sec. 162(m), Sec. 245A, Sec. 951A, foreign tax credits, and rules relating to consolidated NOL carryback claims, a new book minimum tax on certain large corporations, and an excise tax on corporate stock buybacks among other provisions. The Company evaluated the ongoing impact of these law and regulatory changes, which did not have a material impact on its provision for income taxes. +Subsequent to the end of the fiscal year ending June 27, 2020, the Treasury Department issued final regulations applicable to the Company’s position with respect to the U.S. taxability of foreign earnings under the global intangible low taxed income (also known as “GILTI”) regime and the deductibility of interest expense under IRC Section 163(j). These regulations did not have a material impact to the Company's income tax positions. +The 2017 Tax Cuts and Jobs Act (TCJA) mandated that, for tax years after fiscal year 2022, certain costs incurred for research and development (R&D) activities would no longer be allowed for immediate deduction but would be capitalized and amortized over 5 years (for R&D activities performed domestically) or 15 years (for R&D activities performed abroad). The Company began capitalizing and amortizing such costs in fiscal year 2023, resulting in an increase to income taxes payable that was largely offset by the utilization of R&D credit carryovers. +On March 27, 2020, the Coronavirus Aid, Relief, and Economic Security Act (CARES Act) was enacted in response to the COVID-19 pandemic. The CARES Act, among other things, permits net operating loss (NOL) carryovers and carrybacks to offset 100% of taxable income for taxable years beginning before 2021. In addition, the CARES Act allows NOLs incurred in years beginning in 2018, 2019, and 2020 to be carried back to each of the five preceding taxable years to generate a refund of previously paid income taxes. The Company is taking advantage of this NOL carryback provision by carrying back the fiscal year 2021 NOL to the fiscal 2016 and 2017 years, as described above. In addition, the CARES Act contains modifications on the limitation of business interest for tax years beginning in 2019 and 2020. The modifications to Section 163(j) increase the allowable business interest deduction from 30% of adjusted taxable income to 50% of adjusted taxable income. This modification did not have a material impact on the fiscal year 2020 or fiscal year 2021 provisions for income taxes. Also, under the CARES Act, AMT credits not previously refunded for the tax year beginning in 2018 are refundable in the tax year beginning in 2019 rather than in years beginning in 2019-2021, and taxpayers can elect to claim 100% of the AMT credits in the first taxable year beginning in 2018 by applying for a tentative refund claim on or before December 31, 2020. The Company has made this election by applying for a tentative refund claim. The Company took advantage of the deferred payment payroll taxes provision, resulting in decreased deductible payroll tax payments, and increased taxable income, in fiscal years 2020 and 2021. Other aspects of the CARES Act did not have a material impact on the Company’s consolidated financial position, results of operations, or cash flows. +In future years, repatriations of cash will generally be tax-free in the U.S. However, withholding taxes in China may still apply to any such future repatriations. Management has not changed its indefinite investment assertions regarding to the portion of accumulated earnings and profits in China that may be repatriated in the future. Accordingly, management estimates that future repatriations of cash from China may result in approximately $ 0.8 million of withholding tax. There would be no offsetting foreign tax credits in the U.S. and as such, this potential liability is a direct cost associated with actual repatriations. Withholding taxes will not apply to future repatriations from Mexico or Vietnam. +The Company expects to repatriate a portion of its foreign earnings based on increased net sales growth driving additional capital requirements domestically, cash requirements for potential acquisitions and to implement certain tax strategies. The Company expects to repatriate approximately $ 7.6 million from China, in the future. All other unremitted foreign earnings are expected to remain permanently reinvested for planned fixed assets purchases and improvements in foreign locations. +39 +The Company’s effective tax rate differs from the federal tax rate as follows: +Fiscal Year Ended +July 1, 2023 July 2, 2022 +(in thousands) +Federal income tax provision at statutory rates $ 1,322 $ 775 +State income taxes, net of federal tax effect ( 25 ) 86 +Foreign tax rate differences 137 336 +Federal rate differences applied to net operating loss carryback +— ( 593 ) +Effect of income tax credits ( 1,020 ) ( 920 ) +Previously unrecognized tax benefits ( 75 ) 146 +Inflation adjustments 118 178 +Tax penalties & interest — 179 +Global Intangible Low-Taxed Income (GILTI) tax 33 59 +Provision to return reconciliation 52 ( 91 ) +Equity compensation shortfall 73 104 +Foreign Exchange Gains/Losses Unrealized for Tax Purposes 277 23 +Other 251 32 +Income tax provision (benefit) $ 1,143 $ 314 +Prior year presentation of certain items in the above table has been adjusted to reflect current year classification. +The domestic and foreign components of income before income taxes were: +Fiscal Year Ended +July 1, 2023 July 2, 2022 +(in thousands) +Domestic $ ( 1,086 ) $ ( 2,890 ) +Foreign 7,386 6,581 +Income before income taxes $ 6,300 $ 3,691 +40 +Deferred income tax assets and liabilities consist of the following at: +July 1, 2023 July 2, 2022 +(in thousands) +Deferred tax assets: +Net operating loss $ — $ 486 +Tax credit carryforwards, net 6,812 7,990 +Inventory 267 247 +Identifiable intangibles 308 370 +Accruals 2,421 2,406 +PPE 1,328 1,200 +ASC 606 deferred costs 4,802 4,216 +Lease liabilities 3,775 3,671 +Interest expense deduction carryforward 977 580 +Research and development expenses 3,860 — +Other 271 465 +Deferred income tax assets $ 24,821 $ 21,631 +Deferred tax liabilities: +Accrued withholding tax - unremitted earnings ( 754 ) ( 754 ) +Right-of-use assets ( 3,857 ) ( 3,663 ) +Tax capital lease liabilities ( 2,832 ) ( 2,385 ) +ASC 606 accelerated revenue ( 4,599 ) ( 3,736 ) +Other ( 799 ) ( 1,102 ) +Deferred income tax liabilities $ ( 12,841 ) $ ( 11,640 ) +Net deferred income tax assets $ 11,980 $ 9,991 +Balance sheet caption reported in: +Long-term deferred income tax asset $ 12,254 $ 10,055 +Long-term deferred income tax liability ( 274 ) ( 64 ) +Net deferred income tax asset $ 11,980 $ 9,991 +Uncertain Tax Positions: +The Company has R&D tax credits that approximate $ 9.8 million that have 20 -year carryforwards before expiring. The Company’s R&D tax credits expire in various fiscal years from 2032 to 2043. +As of July 1, 2023, the Company had unrecognized tax benefits of $ 3.0 million related to its gross R&D tax credits. The unrecognized tax benefits relate to certain R&D tax credits generated from 2003 to 2023. +A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: +Fiscal Year Ended +July 1, 2023 July 2, 2022 +(in thousands) +Beginning Balance $ 2,998 $ 4,863 +Additions based on tax positions related to the current year 120 286 +Adjustment to prior year tax positions & amended tax returns ( 15 ) ( 2,296 ) +Lapse of statute of limitations ( 75 ) 145 +Ending Balance $ 3,028 $ 2,998 +The $ 3.0 million of unrecognized tax benefits at the end of fiscal year 2023, if recognized, would reduce the effective tax rate. Management does not anticipate any material changes to this amount during the next 12 months. +The Company recognizes interest accrued related to unrecognized tax benefits and penalties in its income tax provision. The Company has not recognized any interest or penalties in the fiscal years presented in these financial statements, except for +41 +$ 0.2 million in fiscal year 2022. The Company is subject to income tax in the U.S. federal jurisdiction, various state jurisdictions, Mexico, China and Vietnam. Certain years remain subject to examination but there are currently no ongoing exams in any taxing jurisdiction. +6. EARNINGS PER SHARE +Basic earnings per share (EPS) is calculated by dividing net income (the numerator) by the weighted-average number of common shares outstanding (the denominator) during the period. Diluted EPS is computed by including both the weighted-average number of shares outstanding and any dilutive common share equivalents in the denominator. The following table presents a reconciliation of the denominator and the number of antidilutive common share awards that were not included in the diluted earnings per share calculation. These antidilutive securities occur when equity awards outstanding have an option price greater than the average market price for the period: +Fiscal Year Ended +(in thousands, except per share information) +July 1, 2023 July 2, 2022 +Net income $ 5,157 $ 3,377 +Weighted average shares outstanding– basic 10,762 10,762 +Effect of dilutive common stock awards 176 301 +Weighted average shares outstanding – diluted 10,938 11,063 +Net income per share – basic $ 0.48 $ 0.31 +Net income per share – diluted $ 0.47 $ 0.31 +Antidilutive SARs not included in diluted earnings per share 376 619 +7. STOCK OPTION AND BENEFIT PLANS +The Company’s incentive plan provides for equity and liability awards to employees and non-employee directors in the form of stock options, stock appreciation rights (SARs), restricted stock, restricted stock units, stock awards, stock units, performance shares, performance units, and other stock-based or cash-based awards. Compensation cost is recognized on a straight-line basis over the requisite employee service period, which is generally the vesting period, and is recorded as employee compensation expense in cost of goods sold, research, development and engineering, and selling, general and administrative expenses. Share-based compensation is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on historical experience and future expectations. +In addition to service conditions, these SARs contain a performance condition. The additional performance condition is based upon the achievement of Return on Invested Capital (ROIC) goals relative to a peer group. All awards with performance conditions are measured over the vesting period and are charged to compensation expense over the requisite service period based on the number of shares expected to vest. The SARs cliff vest after a three-year period from date of grant and expire five years from date of grant. +On July 29, 2022, the Compa ny granted 145,000 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $ 5.10 and a grant date fair value of $ 2.09 . As of July 1, 2023, 140,000 remain outstanding. The grant date fair value for the awards granted during fiscal year 2023, were estimated using the Black Scho les option valuation method with the following weighted average assumptions as of July 29, 2022: +Fiscal Year 2023 +July 29, 2022 +Expected dividend yield — % +Risk – free interest rate 3.01 % +Expected volatility 48.56 % +Expected life 4.00 +On August 9, 2021, the Compa ny granted 165,000 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $ 7.17 and a grant date fair value of $ 2.73 . As of July 1, 2023, 140,000 remain outstanding. The grant date fair value for the awards granted during fiscal year 2022, were estimated using the Black Scho les option valuation method with the following weighted average assumptions as of August 9, 2021: +42 +Fiscal Year 2022 +August 9, 2021 +Expected dividend yield — % +Risk – free interest rate 0.62 % +Expected volatility 48.58 % +Expected life 4.00 +On July 23, 2020, the Company granted 155,000 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $ 6.94 and a grant date fair value of $ 2.32 . As of July 1, 2023, 130,000 remain outstanding. The grant date fair value for the awards granted during fiscal year 2021, were estimated using the Black Scholes option valuation method with the following weighted average assumptions as of July 23, 2020: +Fiscal Year 2021 +July 23, 2020 +Expected dividend yield — % +Risk – free interest rate 0.17 % +Expected volatility 42.85 % +Expected life 4.00 +Share-based compensation expense is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on the Company’s historical experience and future expectations. This forfeiture rate will be revised, if necessary, in subsequent periods if actual forfeitures differ from the amount estimated. Share-based compensation expense for fiscal years ended July 1, 2023 and July 2, 2022 was $ 0.3 million and $ 0.3 million, respectively. +The Black-Scholes option valuation model is used by the Company for estimating the fair value of SARs. Option valuation models require the input of highly subjective assumptions, particularly for the expected term and expected stock price volatility. Changes in these assumptions can materially affect the fair value estimates. +There were no SARs exercised during fiscal year 2023 and fiscal year 2022. +As of July 1, 2023, total unrecognized compensation expense related to nonvested share-based compensation arrangements was approximately $ 0.3 million. This expense is expected to be recognized over a weighted-average period of 1.90 years. +43 +The following table summarizes the Company’s Options and SARs activity for all plans from July 3, 2022 through July 1, 2023: +SARs +Available +For Grant SARs +Outstanding Aggregate +Intrinsic +Value (in +thousands) Weighted +Average +Exercise +Price Weighted +Average +Remaining +Contractual +Life (in +years) +Balances, July 3, 2021 688,084 791,250 $ — $ 7.15 1.9 +Shares authorized — $ — +SARs granted ( 165,000 ) 165,000 $ 7.17 +SARs forfeited 197,500 ( 197,500 ) $ 8.17 +SARs exercised +Balances, July 2, 2022 720,584 758,750 $ — $ 6.89 2.1 +Shares authorized — — +SARs granted ( 145,000 ) 145,000 5.10 +SARs forfeited 277,500 ( 277,500 ) 7.03 +SARs exercised — — — — +Balances, July 1, 2023 853,084 626,250 $ — $ 6.41 2.2 +Exercisable at July 1, 2023 226,250 $ — $ 6.45 0.6 +Additional information regarding SARs outstanding and exercisable as of July 1, 2023, is as follows: +Range of +Exercise Prices Number Outstanding Weighted Avg. +Remaining +Contractual Life (yrs.) Weighted Avg. +Exercise Price Number +Exercisable Weighted +Avg. Exercise +Price +$ 4.93 – $ 7.43 +525,000 2.1 $ 6.06 120,000 $ 4.93 +$ 7.44 – $ 9.44 +101,250 14.6 8.17 106,250 8.17 +$ 4.93 to $ 9.44 +626,250 2.2 $ 6.41 226,250 $ 6.45 +The Company has defined contribution plans available to U.S. employees who have attained age 21. Company contributions to the plans were approximately $ 1.1 million and $ 0.9 million during fiscal years 2023 and 2022, respectively. +8. COMMITMENTS AND CONTINGENCIES +Litigation and Other Matters +The Company is party to certain lawsuits or claims in the ordinary course of business. The Company does not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on the financial position, results of operations or cash flow of the Company. +Warranties +The Company provides warranties on certain product sales. Allowances for estimated warranty costs are recorded during the period of sale. The determination of such allowances requires the Company to make estimates of product return rates and expected costs to repair or to replace the products under warranty. If actual return rates and/or repair and replacement costs differ significantly from management's estimates, adjustments to recognize additional cost of sales may be required in future periods. As of July 1, 2023 and July 2, 2022, the reserve for warranty costs was approximately $ 29,000 and $ 31,000 , respectively. +Leases +Please refer to Footnote “Leases” of the “Notes to Consolidated Financial Statements” for information regarding lease commitments. +44 +Internal Investigation +During fiscal year 2021, the Company’s Audit Committee completed an internal investigation arising from a notification from an employee regarding certain alleged accounting irregularities. In January 2021, the Company determined that improper accounting resulted in an understatement of cost of goods sold and an overstatement of inventories. Subsequent to the matter identified in January 2021, additional inventory accounting errors unrelated to the investigation were also identified by management. The investigation did not result in a restatement of our previously filed financial statements. The Company is cooperating with the Securities and Exchange Commission’s (the “SEC”) inquiries related to the internal investigation. The Company cannot currently form an estimate of any possible loss or range of loss, including any potential monetary penalties; or other remedies potentially imposed by the SEC. +Indemnification Rights +Under the Company’s bylaws, the Company’s directors and officers have certain rights to indemnification by the Company against certain liabilities that may arise by reason of their status or service as directors or officers. The Company maintains director and officer insurance, which may cover certain liabilities arising from its obligation to indemnify its directors and officers and former directors in certain circumstances. +9. DERIVATIVE FINANCIAL INSTRUMENTS +As of July 1, 2023, the Company did not have any outstanding foreign currency forward contracts. During the fiscal year ended July 2, 2022, the Company entered into $ 13.9 million of foreign currency forward contracts and settled $ 24.6 million of such contracts. +On November 6, 2019, the Company entered into an interest rate swap contract with an effective date of November 6, 2019 and a termination date of September 30, 2022, related to the borrowings outstanding under the term loan with Wells Fargo Bank. This interest rate swap contract was terminated on August 14, 2020 when the Company entered into a loan and security agreement with Bank of America. At date of termination this interest rate swap was in a liability position of $ 148,400 , which will be amortized to interest expense over the original term of the swap. +On November 6, 2019, the Company entered into an interest rate swap contract with an effective date of November 6, 2019 and a termination date of November 1, 2023, related to the borrowings outstanding under the line of credit with Wells Fargo Bank. This interest rate swap contract was terminated on August 14, 2020 when the Company entered into a loan and security agreement with Bank of America. At date of termination this interest rate swap was in a liability position of $ 776,500 , which will be amortized to interest expense over the original term of the swap. +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2023 (in thousands): +Derivatives Designated as Hedging Instruments Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) AOCI Balance +as of +July 2, 2022 Effective +Portion +Recorded In +AOCI Effective Portion +Reclassified From +AOCI Into Income AOCI Balance +as of +July 1, 2023 +Forward contracts Cost of sales $ ( 79 ) $ — $ 79 $ — +Interest rate swap Interest expense ( 346 ) — 249 ( 97 ) +Total $ ( 425 ) $ — $ 328 $ ( 97 ) +The following table summarizes the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Income for the fiscal year 2022 (in thousands): +Derivatives Designated as Hedging Instruments Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) AOCI Balance +as of +July 3, 2021 Effective +Portion +Recorded In +AOCI Effective Portion +Reclassified From +AOCI Into Income AOCI Balance +as of +July 2, 2022 +Forward contracts Cost of sales $ 2,721 $ 950 $ ( 3,750 ) $ ( 79 ) +Interest rate swap Interest expense ( 649 ) — 303 ( 346 ) +Total $ 2,072 $ 950 $ ( 3,447 ) $ ( 425 ) +As of July 1, 2023, the Company does not have any foreign exchange contracts with credit-risk-related contingent features. The Company is subject to the risk of fluctuating interest rates from our line of credit and foreign currency risk resulting from our China operations. The Company does not currently manage these risk exposures by using derivative instruments. +45 +10. FAIR VALUE MEASUREMENTS +The Company has adopted ASC 820, Fair Value Measurements, which defines fair value, establishes a framework for assets and liabilities being measured and reported at fair value and expands disclosures about fair value measurements. There are three levels of fair value hierarchy inputs used to value assets and liabilities which include: Level 1 – inputs are quoted market prices for identical assets or liabilities; Level 2 – inputs other than quoted market prices included in Level 1 that are observable for the asset or liability, either directly or indirectly; and Level 3 – inputs are unobservable inputs for the asset or liability. There have been no changes in the fair value methodologies used at July 1, 2023 and July 2, 2022. +The carrying values of cash and cash equivalents, accounts receivable, contract assets, and current liabilities are reflected on the balance sheets at July 1, 2023 and July 2, 2022, reasonably approximate their fair value. +The Company’s long-term debt, which is measured at amortized cost, primarily consists of an asset-based revolving credit facility, lease liability, and equipment loans. These borrowings bear interest at SOFR plus 2.5 % per the loan agreement. Each of these rates is a variable floating rate dependent upon current market conditions and the Company’s current credit risk as discussed in Footnote “Long-Term Debt” of the “Notes to Consolidated Financial Statements.” +As a result of the determinable market rates for our asset-based revolving credit facility and equipment loans, they are classified within Level 2 of the fair value hierarchy. Further, the carrying value of each of these instruments reasonably approximates their fair value as of July 1, 2023 and July 2, 2022. +46 +11. ENTERPRISE-WIDE DISCLOSURES +Operating segments are defined in ASC Topic 280, Segment Reporting as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker, or decision making group, in deciding how to allocate resources and in assessing performance. The Company’s chief operating decision maker is its Chief Executive Officer. As of July 1, 2023, the Company operates and internally manages a single operating segment, Electronics Manufacturing Services as this is the only discrete financial information that is regularly reviewed by the chief operating decision maker. This segment provides integrated electronic and mechanical engineering, assembly, sourcing and procurement, logistics, and new product testing for our customers. +Products and Services +Of the revenues for the years ended July 1, 2023 and July 2, 2022, contract manufacturing sales and services were $ 588.1 million and $ 531.8 million, respectively. +Geographic Areas +Net sales and long-lived assets (property, plant, and equipment) by geographic area for the years ended and as of July 1, 2023 and July 2, 2022 are summarized in the following table. Net sales set forth below are based on the shipping destination. Long-lived assets information is based on the physical location of the asset and includes property, plant and equipment, net, and operating lease right-of-use assets, net. +Fiscal Year Ended +(in thousands) +2023 2022 +Geographic net sales: +Domestic (U.S.) $ 502,274 $ 438,018 +Foreign $ 85,861 $ 93,797 +Total $ 588,135 $ 531,815 +Long-lived assets: +United States $ 21,799 $ 14,440 +Mexico $ 18,203 22,473 +Vietnam $ 4,547 5,228 +China $ 523 601 +Total $ 45,072 $ 42,742 +Percentage of net sales made to customers located in the following countries: +Fiscal Year Ended +2023 2022 +United States 85 % 82 % +China 14 16 +Other foreign countries (a) +1 2 +Canada — — +Total 100 % 100 % +(a) No other individual foreign country accounted for 10% or more of the foreign sales in fiscal years 2023 or 2022. +Significant Customers +The percentage of net sales to and trade accounts receivables from significant customers were as follows: +Percentage of Net Sales +Fiscal Year Percentage of Trade Accounts Receivable +Fiscal Year +2023 2022 2023 2022 +Customer A 12 % 12 % 16 % 13 % +47 +12. REVENUE +Revenue Recognition +The Company specializes in services ranging from product manufacturing to engineering and tooling services. The first step in its process for revenue recognition is to identify the contract with a customer. A contract is defined as an agreement between two or more parties that creates enforceable rights and obligations. A contract can be written, oral, or implied. The Company generally enters into manufacturing service agreements (“MSA”) with its customers that outlines the terms of the business relationship between the customer and the Company. This includes matters such as warranty, indemnification, transfer of title and risk of loss, liability for excess and obsolete inventory, pricing, payment terms, etc. The Company will also bid on a program-by-program basis for customers in which an executed MSA may not be in place. In these instances, as well as when we have an MSA in place, we receive customer purchase orders for specific quantities and timing of products. As a result, the Company considers its contract with a customer to be the combination of the MSA and the purchase order. The transaction price is fixed and set forth in each purchase order. In the Company's normal course of business, there are no variable pricing components, or material amounts refunded to customers in the form of refunds or rebates. +The Company assesses whether control of the product or services promised under the contract is transferred to the customer at a point in time (shipment) or over time (as we manufacture the product). The Company is first required to evaluate whether its contracts meet the criteria for 'over-time' or 'point-in-time' recognition. The Company has determined that for the majority of its contracts the Company is manufacturing products for which there is no alternative use due to the unique nature of the customer-specific product, IP and other contract restrictions. The Company has an enforceable right to payment including a reasonable profit for performance completed to date with respect to these contracts. As a result, revenue is recognized under these contracts 'over-time' based on the input cost-to-cost method as it better depicts the transfer of control. This input method is based on the ratio of costs incurred to date as compared to the total estimated costs at completion of the performance obligation. For all other contracts that do not meet these criteria, such as manufacturing contracts for which the terms do not provide an enforceable right to payment for performance completed to date, the Company recognizes revenue when it has transferred control of the related manufactured products which generally occurs upon shipment to the customer. Revenue from engineering services is recognized over time as the services are performed. +The Company’s typical payment terms are 30 to 45 days and its sales arrangements do not contain any significant financing component for its customers. +The Company generally provides a warranty for workmanship on its manufacturing contracts. Although we offer warranties on our products, our warranties are considered to be assurance-type in nature and do not cover anything beyond ensuring that the product is functioning as intended. Based on the guidance in ASC 606, assurance-type warranties do not represent separate performance obligations; therefore, the primary performance obligation in the majority of our contracts is the delivery of a specific good through the purchase order submitted by our customer. +The Company elected to not disclose information about remaining performance obligations as they are part of contracts that that have expected durations of one year or less. +The Company has elected to expense costs to obtain contracts as incurred as these costs are immaterial to the financial statements. +During fiscal 2023 and 2022, no revenues were recognized from performance obligations satisfied or partially satisfied in previous periods. +Contract Balances +A contract asset is recognized when the Company has recognized revenue, but has not issued an invoice for payment. Contract assets are classified separately on the condensed consolidated balance sheet and transferred to receivables when the right to payment becomes unconditional. +The following table summarizes the activity in the Company’s contract assets during the twelve months ended July 1, 2023 (in thousands): +Contract Assets +Beginning balance, July 2, 2022 +$ 21,974 +Revenue recognized 573,444 +Amounts collected or invoiced ( 565,493 ) +Ending balance, July 1, 2023 +$ 29,925 +48 +The following table summarizes the activity in the Company’s contract assets during the twelve months ended July 2, 2022 (in thousands): +Contract Assets +Beginning balance, July 3, 2021 +24,781 +Revenue recognized 515,831 +Amounts collected or invoiced ( 518,638 ) +Ending balance, July 2, 2022 +$ 21,974 +Disaggregation of Revenue +The following table presents the Company’s revenue disaggregated for the twelve months ended July 1, 2023 and the twelve months ended July 2, 2022 (in thousands): +Revenue +Recognition July 1, 2023 July 2, 2022 +Over-Time $ 573,444 $ 515,831 +Point-in-Time 14,691 15,984 +Total 588,135 $ 531,815 +Revenues and associated costs from engineering design, development services and tooling, which are performed under contract of short term durations, are recognized over time as the services are performed. Revenue from engineering design, development +services and tooling represented approximately 6.6 % and 9.6 % of total revenue in fiscal year 2023 and 2022, respectively. +13. LEASES +The Company has several commitments under operating and financing leases for warehouses, manufacturing facilities, office buildings, and equipment with initial terms that expire at various dates during the next 1 year to 10 years. +The Company has some leases that include an extension clause. Management has considered the likelihood of exercising each extension option included and estimated the duration of the extension option, for those leases management determined to be reasonably certain, in calculating the lease term for measurement of the right of use asset and liability. +For operating leases, management assumed a discount rate of 4 %. The weighted average discount rate is disclosed in the tables below. +The components of lease cost were as follows as of July 1, 2023 and July 2, 2022 (in thousands): +Year Ended Year Ended +Lease cost Classification July 1, 2023 July 2, 2022 +Operating lease cost Cost of sales $ 4,519 $ 6,442 +Operating lease cost Selling, general and administrative expenses 737 929 +Financing lease cost Cost of sales $ 3,891 $ 2,054 +Financing lease cost Selling, general and administrative expenses $ 161 $ 64 +Total lease cost $ 9,308 $ 9,489 +Fixed lease cost $ 8,171 $ 7,941 +Short-term lease cost $ 1,137 $ 1,548 +Total lease cost $ 9,308 $ 9,489 +49 +Amounts reported in the Consolidated Balance Sheet as of July 1, 2023 and July 2, 2022 were (in thousands, except weighted average lease term and discount rate): +July 1, 2023 July 2, 2022 +Operating Leases: +Operating lease right of use assets $ 16,202 $ 16,731 +Operating lease liabilities (1) +16,202 16,731 +Weighted-average remaining lease term (in years) +Operating leases 4.55 5.28 +Weighted-average discount rate +Operating leases 4.00 % 4.00 % +Financing Leases (2) : +Financing lease right of use assets $ 9,718 $ 12,464 +Financing lease liabilities 8,278 11,211 +Weighted-average remaining lease term (in years) +Financing leases 1.89 2.56 +Weighted-average discount rate +Financing leases 9.96 % 8.82 % +(1) For fiscal year 2023 and 2022, the current portion of the total operating lease liabilities is classified under Other Current Liabilities . +(2) The total finance lease right of use assets of $ 9.7 million is classified under Other Long-term Assets . The current portion of the total finance lease liabilities of $ 4.7 million is classified under Current portion of debt, net, resulting in $ 3.6 million classified in Other Long-term Liabilities section of the condensed consolidated balance sheet. +50 +Other information related to leases was as follows (in thousands): +July 1, 2023 July 2, 2022 +Cash paid for amounts included in the measurement of lease liabilities: +Operating cash flows from operating leases 5,714 4,261 +Financing cash flows used in financing leases 4,291 2,331 +Future lease payments under non-cancellable leases as of July 1, 2023 are as follows (in thousands): +Fiscal Years Ending Operating Leases Finance Leases +2024 $ 5,134 $ 4,711 +2025 3,987 3,290 +2026 3,365 670 +2027 2,464 71 +2028 1,551 — +Thereafter 1,689 — +Total undiscounted lease payments 18,190 8,742 +Less: present value discount 1,988 464 +Total lease liabilities $ 16,202 $ 8,278 +Item 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES +None +Item 9A: CONTROLS AND PROCEDURES +51 +Evaluation of Disclosure Controls and Procedures +It is the responsibility of our management to establish, maintain, and monitor disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 (the “Exchange Act”) are recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Additionally, these disclosure controls include controls and procedures that are designed to accumulate and communicate the information required to be disclosed to our Company’s Chief Executive Officer and Chief Financial Officer, allowing for timely decisions regarding required disclosures. +As of the end of the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(f). Based on our assessment, we believe that as of July 1, 2023, the Company’s disclosure controls and procedures are effective based on that criteria. +Management’s Report on Internal Control over Financial Reporting +Our management has the responsibility to establish and maintain adequate internal controls over our financial reporting, as defined in Rule 13a-15(f) under the Securities and Exchange Act of 1934. Our internal controls are designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our external financial statements in accordance with generally accepted accounting principles (GAAP). +Due to inherent limitations of any internal control system, management acknowledges that there are limitations as to the effectiveness of internal controls over financial reporting and therefore recognize that only reasonable assurance can be gained from any internal control system. Accordingly, our internal control system may not detect or prevent material misstatements in our financial statements and projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, we have performed an assessment of the effectiveness of our internal controls over financial reporting as of July 1, 2023. This assessment was based on the criteria established in Internal Control-Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that as of July 1, 2023, the Company’s internal control over financial reporting is effective based on that criteria. +Changes in Internal Control over Financial Reporting +There have been no significant changes in our internal controls over financial reporting during our fourth fiscal quarter ended July 1, 2023 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)). +52 +Item 9B: OTHER INFORMATION +None +Item 9C: +DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS +Not applicable. +PART III +Item 10: DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Directors of the Registrant +Information on the nominees for election as Directors of the Company is incorporated herein by reference from the Company’s definitive proxy statement for the 2023 Annual Meeting of Shareholders to be filed pursuant to Regulation 14A under the Exchange Act no later than 120 days after the end of the Company’s 2023 fiscal year (the “2023 Proxy Statement”). +Executive Officers of the Registrant +This information is included in a separate item captioned “Executive Officers of the Registrant” in Item 1 of Part 1 of this Annual Report on Form 10-K pursuant to Instruction G(3) of Form 10-K and Instruction 3 to Item 401(b) of Regulation S-K and is incorporated herein by reference. +Compliance with Section 16(a) of the Exchange Act: +Information under the caption “Delinquent Section 16(a) Reports” in the Company’s 2023 Proxy Statement is incorporated herein by this reference. +Code of Conduct +The Board of Directors has adopted a written Code of Conduct which applies to its directors and employees, including its executive officers. The Code of Conduct is available on the Company’s website at www.keytronic.com . The Company intends to disclose on its website any amendments to or waivers of the Code of Conduct. +Item 11: EXECUTIVE COMPENSATION +Information appearing under the caption “Executive Compensation” in the Company’s 2023 Proxy Statement is incorporated herein by this reference. +Item 12: SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The following table sets forth the aggregate information for the Company’s equity compensation plans in effect as of July 1, 2023. +EQUITY COMPENSATION PLAN INFORMATION +Plan category Number of securities to +be issued upon exercise +of outstanding options, +warrants, and rights +(a) Weighted-average +exercise price of +outstanding options, +warrants, and rights +(b) Number of securities +remaining available for +future issuance under +equity compensation +plans (excluding +securities reflected in +column (a) +(c) +Equity compensation plans approved by security holders (1) +626,250 $ 6.41 853,084 +Equity compensation plans not approved by security holders — $ — — +Total 626,250 $ 6.41 853,084 +(1) Included are the 1,200,000 shares subject to the 2010 Plan, the issuance of which were approved by the shareholders at the 2010 Annual Meeting. During the 2015 Annual Meeting, an additional 1,000,000 shares were approved. As a result of the shareholder approval, the Company made the decision to amend the cash-settled SARs granted during fiscal year 2010 to stock-settled SARs effective October 21, 2011. +Information under the caption “Beneficial Ownership of Securities” in the Company’s 2023 Proxy Statement is incorporated herein by this reference. +53 +Item 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions” and “Directors’ Independence” in the Company’s 2023 Proxy Statement is incorporated herein by this reference. +Item 14: PRINCIPAL ACCOUNTANT FEES AND SERVICES +Our independent registered public accounting firm is Moss Adams LLP , Seattle, Washington , Auditor Firm ID: 659 . +Information appearing under the caption “Principal Accountant Fees and Services” in the Company’s 2023 Proxy Statement is incorporated herein by this reference. +PART IV +Item 15: EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +(a) 1. FINANCIAL STATEMENTS +Page in Form 10-K +FINANCIAL STATEMENTS +Report of Independent Registered Public Accounting Firm (Moss Adams, LLP) +26 +Consolidated Balance Sheets +28 +Consolidated Statements of Income +29 +Consolidated Statements of Comprehensive Income +30 +Consolidated Statements of Cash Flows +31 +Consolidated Statements of Shareholders’ Equity +32 +Notes to Consolidated Financial Statements +35 +54 +3. EXHIBITS +Exhibit No. Description +3.1 +Articles of Incorporation +3.2 +Bylaws, as amended +4.1 +Description of the Company’s securities +10.1* +2010 Incentive Plan, incorporated by reference to Exhibit 10.36 to the Company’s Form 10-K for the year ended July 3, 2010 +10.2* +Description of Employment Contact of Craig D. Gates, incorporated by reference to the Company’s 1998 Proxy Statement, pages 10 and 11 +10.3* +Addenda to Employment Contract of Craig D. Gates, incorporated by reference to Exhibit 10.4 to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.4* +Addenda to Employment Contract of Craig D. Gates, incorporated by reference to Exhibit 10.2 to the Company’s Form 10-K for the year ended June 29, 2002 +10.5* +Amendment to Employment Contract of Craig D. Gates, dated August 23, 2011 incorporated by reference to Exhibit 10.40 to the Company’s Form 10-K for the year ended July 2, 2011 +10.6* +Amendment to Employment Contract of Craig D. Gates, dated May 10, 2012, incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q for the quarter ended March 31, 2012 +10.7* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2019 and Fiscal Years 2019 – 2021 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 2, 2018 +10.8* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2020 and Fiscal Years 2020 – 2022 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 30, 2019 +10.9* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2021 and Fiscal Years 2021 – 2023 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 27, 2020 +10.10* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2022 and Fiscal Years 2022 – 2024 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 13, 2021 +10.11* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2023 and Fiscal Years 2023 – 2025 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 4, 2022 +10.12* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2024 and Fiscal Years 2024 – 2026 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 17, 2023 +55 +10.13 +Announcement that the Company has signed a letter of intent to lease a new facility in Da Nang, Vietnam +10.14 +Stock Purchase Agreement, dated September 3, 2014, by and among the Company, CDR Manufacturing Inc. and the sellers signatory thereto, incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K filed on September 9, 2014 +10.15 +Loan and Security Agreement, dated August 14, 2020, among the Company, Bank of America, N.A, and certain other parties, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed August 17, 2020 +10.16 +First Amendment to Loan and Security Agreement, dated November 10, 2020, among the Company, Bank of America, N.A, and certain other parties, submitted herewith +10.17 +Second Amendment to Loan and Security Agreement, dated September 3, 2021, among the Company, Bank of America, N.A, and certain other parties, incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed September 10, 2021 +10.18 +Third Amendment to Loan and Security Agreement, dated August 26, 2022, among the Company, Bank of America, N.A, and certain other parties, incorporated by reference to Exhibit 10.2, submitted herewith +21.1 +Subsidiaries of Registrant, submitted herewith +23.1 +Consent of Independent Registered Public Accounting Firm - Moss Adams LLP, submitted herewith +31.1 +Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer, submitted herewith +31.2 +Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer, submitted herewith +32.1 +Section 1350 Certification of Chief Executive Officer, submitted herewith +32.2 +Section 1350 Certification of Chief Financial Officer, submitted herewith +101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. +101.SCH XBRL Taxonomy Extension Schema Document ** +101.CAL XBRL Taxonomy Extension Calculation Linkbase Document ** +101.DEF XBRL Taxonomy Extension Definition Linkbase Document ** +101.LAB XBRL Taxonomy Extension Label Linkbase Document ** +101.PRE XBRL Taxonomy Extension Presentation Linkbase Document ** +104 Cover Page Interactive Data File (formatted as inline XBRL with applicable taxonomy extention information contained in Exhibits 101.INS, 101.SCH, 101.CAL, 101.DEF, 101.LAB and 101.PRE) +56 +* Management contract or compensatory plan or arrangement +** Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities and Exchange Act of 1934, as amended and otherwise are not subject to liability under those sections. +Item 16: FORM 10-K SUMMARY +None +57 +22 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +Dated: September 26, 2023 +KEY TRONIC CORPORATION +By: /s/ Craig D. Gates +Craig D. Gates, President and Chief Executive Officer +(Principal Executive Officer) +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated: +/s/ Craig D. Gates September 26, 2023 +Craig D. Gates Date +Director and President and Chief Executive Officer +(Principal Executive Officer) +/s/ Brett R. Larsen September 26, 2023 +Brett R. Larsen Date +Executive Vice President of Administration, Chief Financial Officer and Treasurer +(Principal Financial Officer and Principal Accounting Officer) +/s/ Ronald F. Klawitter September 26, 2023 +Ronald F. Klawitter, Director Date +/s/ James R. Bean September 26, 2023 +James R. Bean, Director Date +/s/ Subodh K. Kulkarni September 26, 2023 +Subodh K. Kulkarni, Director Date +/s/ Yacov A. Shamash September 26, 2023 +Yacov A. Shamash, Director Date +/s/ Patrick Sweeney September 26, 2023 +Patrick Sweeney, Director and Chairman of the Board Date +58 \ No newline at end of file diff --git a/raw/filings/0000719733/2023/0000719733-23-000032/filing_metadata.csv b/raw/filings/0000719733/2023/0000719733-23-000032/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..fb3b05eaaa80696f02b19a09f8f912e017fe4b43 --- /dev/null +++ b/raw/filings/0000719733/2023/0000719733-23-000032/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000719733,KTCC,KEY TRONIC CORP,10-K,2023-09-26,2023-07-01,2023-09-26T20:38:08.000Z,0000719733-23-000032,ktcc-20230701.htm,10-K,12915146,1,1,https://www.sec.gov/Archives/edgar/data/719733/000071973323000032/ktcc-20230701.htm,https://www.sec.gov/Archives/edgar/data/719733/000071973323000032/,2023,2023,1 diff --git a/raw/filings/0000719733/2023/0000719733-23-000032/item1.txt b/raw/filings/0000719733/2023/0000719733-23-000032/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..c143b5109a60091e1c1342d80141fdd1fc694c9b --- /dev/null +++ b/raw/filings/0000719733/2023/0000719733-23-000032/item1.txt @@ -0,0 +1,74 @@ +Item 1. BUSINESS +Background +Key Tronic Corporation was organized in 1969, as a Washington corporation that locally manufactured computer keyboards. The ability to design, build and deliver a quality product led us to become a leading independent manufacturer of keyboards for computers in the United States. Our fully integrated design, tooling, and automated manufacturing capabilities enabled us to rapidly respond to customers’ needs for keyboards in production quantities worldwide. We supported our sales growth through the development and purchase of international manufacturing facilities. As the computer keyboard market matured with increasing competition from other international providers, we determined that our business could no longer solely rely on keyboard sales. +After assessing market conditions and our strengths and capabilities, we shifted our focus from keyboard manufacturing to contract manufacturing for a wide range of products. Our unique strategic attributes are based on our core strengths of innovative design and engineering expertise in electronics, mechanical engineering, sheet metal fabrication and stamping, and precision plastics combined with high-quality, low cost production, and assembly on an international basis while providing exceptional customer service. These strengths have made our company a strong competitor in the contract manufacturing market. +Our Industry and Strategy +The expansion of the contract manufacturing industry and our acquisitions have allowed us to continue to expand our customer base and the industries that we serve. The increase in new programs represents a growing portion of our revenue and a promising foundation for our future. In keeping with our long-term strategic objectives, we have been successfully building a more diversified customer portfolio, spanning a wider range of industries. We currently offer our customers the following services: integrated electronic and mechanical engineering, precision plastic molding, sheet metal fabrication, printed circuit board (PCB) and complete product assembly, component selection, sourcing and procurement, worldwide logistics, and new product testing and production all at competitive pricing due to our global footprint. We differentiate ourselves from others our size and larger in the contract manufacturing industry by providing vertical integration, a flexible and responsive approach to our customer’s changing supply demand, and complete design engineering support. +We believe that we are well positioned in the contract manufacturing industry to continue the expansion of our customer base and achieve long-term growth. Our unique blend of multinational facilities, vertical integration, centralized management, and core strengths continue to support our growth and our customers’ needs. We continue to focus on controlling operating expenses and leveraging the synergistic capabilities of our world-class facilities in the United States, Mexico, China and Vietnam. This international production capability provides our customers with the benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs, and reduced product fulfillment time. Given our competitive advantages and the growing pressure for new potential customers to move forward with their outsourcing strategies, we feel that we are strongly positioned to win new business in coming periods and grow our revenue and profits. +4 +The contract manufacturing industry is intensely competitive. Although our customer base is growing, we still have less than 1% of the potential global market and our revenue can fluctuate significantly due to reliance on a concentrated base of customers. We are planning for new customer growth in the coming quarters by seeking to secure new programs with new and existing customers, increase our worldwide manufacturing capacity, leverage further our design engineering capabilities and continue to improve our manufacturing and procurement processes and capabilities. Ongoing challenges that we face include but are not limited to the following: continuing to win programs from new and existing customers, balancing capital employed, production capacity and key personnel in support of new customer programs, improving operating efficiencies, controlling costs while developing competitive pricing strategies, and successfully transitioning new program wins to full production. +Customers and Marketing +We provide a mix of manufacturing services for outsourced Original Equipment Manufacturing (OEM) products. We provide the following services: product design, surface mount technologies (SMT) and pin through hole capability for printed circuit board assembly, tool making, precision plastic molding, sheet metal fabrication and painting, liquid injection molding, complex assembly, prototype design and full product assembly. +Sales of the majority of our products have not historically been seasonal in nature, but may be seasonal in the future if there are changes in the types of products manufactured. Sales can, however, fluctuate significantly between quarters from changes in customers and customer demand due to the concentration of sales generated by our largest customers. +For the fiscal years 2023 and 2022, the five largest customers in each year accounted for 36% and 40% of combined total net sales, respectively. We continue to diversify our customer base by adding additional programs and customers. We expect net sales to our five largest customers as a percentage of total net sales to approximate current levels going forward. +The following table summarizes the customers that represented 10% or more of total net sales during the last two fiscal years: +Percentage of Net Sales by Fiscal Year +2023 2022 +Customer A 12% 12% +There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +We market our products and services primarily through our direct sales department which is comprised of strategically located field sales people and distributors. We also maintain relationships with several independent sales organizations to assist in marketing our product lines. +Manufacturing +We have continually made investments in developing and expanding a capital equipment base to achieve vertical integration and efficiencies in our manufacturing processes. We have invested significant capital into SMT for volume manufacturing of complex printed circuit board assemblies and in our metal shop providing precision metal stamping, fabricating, and finishing. We also design and develop tooling for injection molding and sheet metal fabrication and manufacture the majority of plastic and sheet metal parts used in the products we manufacture. Additionally, we have equipment to maintain a controlled clean environment for manufacturing processes that require a high level of precise control. +We use a variety of manual and automated assembly processes in our facilities, depending upon product complexity and degree of customization. Some examples of automated processes include component insertion, SMT, selective soldering, flexible robotic assembly, computerized vision system quality inspection, laser turrets, automated switch and key top installation, robotic welding, automated powder coat application, and automated functional testing. +Our engineering expertise and automated manufacturing processes enable us to work closely with our customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. We use computer-aided design techniques and software to assist in preparation of the tool design layout and component placement, to reduce tooling and production costs, improve component and product quality, and enhance turnaround time during product development. +We purchase materials and components for our products from many different suppliers, including both domestic and international sources. We develop close working relationships with our suppliers, many of whom have been supplying products to us for several years. +5 +Research, Development, and Engineering +As part of our long-term strategy, we are committed to supporting our customers by providing research, development, and engineering services. We have seen an increase in the success of providing design support on existing and potential customers in differentiating ourselves. We believe these services allow us to facilitate in optimizing new product designs, and the production processes of our customers’ programs. +Research, development, and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials costs, depreciation, and allocated information technology and facilities costs. +Competition +The market for the products and services we provide is highly competitive. There are numerous competitors in the contract manufacturing industry, many of which have substantially more resources and are more geographically diverse than we are. Some of our competitors have similar international production capabilities, large financial resources and some have substantially greater manufacturing, research and development, and marketing resources. There is also competition from the manufacturing operations of our current and potential customers, who are continually evaluating the merits of manufacturing their products internally versus the advantages of outsourcing. We believe that we can currently compete favorably in these areas primarily on the basis of our international footprint, responsiveness, creativity, vertical production capability, quality, and cost. +Trademarks +Our name and logo are federally registered trademarks, and we believe they are valuable assets of our business. +Employees +We consider our employees to be our primary strength and we make considerable efforts to maintain a well-qualified workforce. Our employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. We regularly provide transportation, medical services, and meals to all of our employees in foreign locations. The Company also has defined contribution plans available to U.S. employees who have attained age 21 and provide group health, life, and disability insurance plans. We also maintain share based compensation plans and other long-term incentive plans for certain employees and outside directors. +As of July 1, 2023, we had 5,447 full-time employees compared to 4,897 on July 2, 2022. Since we can have significant fluctuations in product demand, we seek to maintain flexibility in our workforce by utilizing skilled temporary labor in some of our manufacturing facilities in addition to full-time employees. +Backlog +On July 29, 2023, our order backlog was valued at approximatel y $343.0 million, compared to approximately $407.8 million on July 30, 2022. The amount of backlog is not necessarily indicative of future sales but can be indicative of trends in expected future sales revenue. Due to the relationships with our customers, we will occasionally allow orders to be canceled or rescheduled and as a result it is not a meaningful indicator of future financial results. If there are canceled or rescheduled orders, we typically negotiate fees to cover the costs we have incurred. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change due to design modifications, customer forecast changes, or other customer requirements. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in Footnote “Enterprise-Wide Disclosures” of the “Notes to Consolidated Financial Statements” of this Annual Report on Form 10-K and that information is incorporated herein by reference. +Governmental Regulation +Our operations are subject to certain foreign, federal, state and local regulations relating to, among others, environmental, waste management, labor and health and safety matters. We have implemented processes and procedures to help ensure that our operations are in substantial compliance with all applicable regulations. However, material costs and liabilities may arise from these requirements or from new or modified requirements, which could have a material adverse effect on our business and results of operations. +Information about Our Executive Officers. +6 +The table below sets forth the name, current age and current position of our executive officers and other significant employees: +Name Age Positions Held +Executive Officers +Craig D. Gates 64 President and Chief Executive Officer +Brett R. Larsen 50 Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Philip S. Hochberg 61 Executive Vice President of Business Development +Duane D. Mackleit 55 Executive Vice President of Operations +David H. Knaggs 42 Executive Vice President of Quality and Information Systems +Chad T. Orebaugh 52 Executive Vice President of Engineering +Mark Courtney 57 +Vice President of Supply Chain +Executive Officers +CRAIG D. GATES – President and Chief Executive Officer +Mr. Gates, age 64, has been President and Chief Executive officer of the Company since April 2009. Previously, he was Executive Vice President and General Manager from August 2002 to April 2009. He served as Executive Vice President of Marketing, Engineering and Sales from July 1997 to August 2002 and served as Vice President and General Manager of New Business Development from October 1995 to July 1997. He joined the Company as Vice President of Engineering in October of 1994. From 1982 to 1991 he held various engineering and management positions within the Microswitch Division of Honeywell, Inc., in Freeport, Illinois, and from 1991 to October 1994 he served as Director of Operations, Electronics for Microswitch. Mr. Gates has a Bachelor of Science Degree in Mechanical Engineering and a Master’s in Business Administration from the University of Illinois, Urbana. +BRETT R. LARSEN – Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Mr. Larsen, age 50, has served as Executive Vice President of Administration, Chief Financial Officer, and Treasurer since July 2015. Previously, he was Vice President of Finance and Controller from February 2010 to July 2015. He was Chief Financial Officer of FLSmidth Spokane, Inc. from December 2008 to February 2010. From October 2005 through November 2008, Mr. Larsen served as Controller of Key Tronic Corporation. From May 2004 to October 2005, Mr. Larsen served as Manager of Financial Reporting of Key Tronic Corporation. From 2002 to May 2004, Mr. Larsen was an audit manager for the public accounting firm BDO USA, LLP. He also held various auditing and supervisory positions with Grant Thornton LLP from 1997 to 2002. Mr. Larsen has a Bachelor of Science degree in Accounting and a Masters degree in Accounting from Brigham Young University and is a Certified Public Accountant. +PHILIP S. HOCHBERG – Executive Vice President of Business Development +Mr. Hochberg, age 61, has been Executive Vice President of Business Development since July 2012. Prior to this, Mr. Hochberg served as Vice President of Business Development from October 2009 through June 2012. He was Director of Business Development and Program Management from July 2008 to October 2009. Mr. Hochberg served as Director of Business Development from October 2004 to July 2008 and as Director of EMS Sales and Marketing from July 2000 to October 2004. Prior to joining Key Tronic, Mr. Hochberg worked for Quinton Instrument Company as their Director of Marketing and Product Management from 1992 to 2000. From 1988 to 1992, he was employed by SpaceLabs Medical as their Business Development Marketing Manager. Mr. Hochberg has an MBA from the University of British Columbia, a BA in Psychology, with a minor in Business from Washington University in St. Louis. +DUANE D. MACKLEIT – Executive Vice President of Operations +Mr. Mackleit, age 55, has been Executive Vice President of Operations since December 2019. Prior to this, Mr. Mackleit served as Vice President of Program Management since July 2012. He served as Director of Program Management from July 2008 through June 2012. From May 2006 to July 2008 he served as Principal Program Manager. Prior to that, he served as Program Manager from March 2002 to May 2006 and Associate Program Manager from August 2000 to March 2002. Mr. Mackleit has also held several other positions with Key Tronic Corporation. Mr. Mackleit has an AA in Business from Spokane Falls Community College and a BA in Business/Marketing from Eastern Washington University. He also holds a MBA from Gonzaga University. +DAVID H. KNAGGS – Executive Vice President of Quality, Regulatory Affairs and Information Systems +Mr. Knaggs, age 42, has been Executive Vice President of Quality and Information Systems since May 2021. Previously, he was Vice President of Quality and Regulatory Affairs from November 2017 to May 2021. He was Vice President of Quality since October 2016. Before joining Key Tronic, Mr. Knaggs worked at Telect, Inc. from 2008 to 2016 as their Director of +7 +Engineering. Prior to that, he worked at Isothermal Systems Research as Lead Systems Engineer from 2003 to 2008. He has a Bachelor of Science degree in Mechanical Engineering with a minor in mathematics from the University of Washington. +CHAD T. OREBAUGH – Executive Vice President of Engineering +Mr. Orebaugh, age 52, has been Executive Vice President of Engineering since September 2021. Previously he served as Vice President of Engineering since April 2017. Prior to this, Mr. Orebaugh served as Director of Engineering since May 2013. From April 2010 to May 2013, he served as Manager of Engineering. From January 2000 to April 2010 he served as Lead Mechanical Engineer. Prior to that, he served as Mechanical Engineer from October 1998 to January 2000 and Associate Mechanical Engineer since October 1997. Mr. Orebaugh holds a BA in Mechanical Engineering from Gonzaga University. +MARK COURTNEY – Vice President of Supply Chain +Mark Courtney, age 57, has been Vice President of Supply Chain of the company since August 2019. Previously, he served as Purchasing Manager and Director of North American Purchasing from September 2015 to August 2019, and as Supply Chain Manager, ERP and Business Operations Manager for Amphenol Telect from August 2007 to September 2015. From March 2006 to August 2007, he served as Senior Buyer/Planner for Honeywell Specialty Materials and from June 2005 to March 2006 as Purchasing Manager for MRV Communications. From May 2000 to June 2005, he served as a Field and Inside Sales Associate for Arrow Electronics and from October 1991 to May 2000 held various positions at Alesis. +Available Information +Our principal executive offices are located at 4424 North Sullivan Road, Spokane Valley, Washington 99216, and our telephone number is (509) 928-8000. Our website is located at http://www.keytronic.com where filings of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or current reports on Form 8-K are available free of charge after they have been filed with the Securities and Exchange Commission. The information presented on our website currently and in the future is not considered to be part of this document or any document incorporated by reference in this document. +In addition, the SEC maintains an Internet site (at www.sec.gov ) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. \ No newline at end of file diff --git a/raw/filings/0000719733/2023/0000719733-23-000032/item13.txt b/raw/filings/0000719733/2023/0000719733-23-000032/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..25de5f285cf08d40c6939e03bf1519edd5845623 --- /dev/null +++ b/raw/filings/0000719733/2023/0000719733-23-000032/item13.txt @@ -0,0 +1,2 @@ +Item 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions” and “Directors’ Independence” in the Company’s 2023 Proxy Statement is incorporated herein by this reference. \ No newline at end of file diff --git a/raw/filings/0000719733/2023/0000719733-23-000032/item9a.txt b/raw/filings/0000719733/2023/0000719733-23-000032/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..0631b24b29c094a3de70d32852c381b39a24db7d --- /dev/null +++ b/raw/filings/0000719733/2023/0000719733-23-000032/item9a.txt @@ -0,0 +1,12 @@ +Item 9A: CONTROLS AND PROCEDURES +51 +Evaluation of Disclosure Controls and Procedures +It is the responsibility of our management to establish, maintain, and monitor disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 (the “Exchange Act”) are recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Additionally, these disclosure controls include controls and procedures that are designed to accumulate and communicate the information required to be disclosed to our Company’s Chief Executive Officer and Chief Financial Officer, allowing for timely decisions regarding required disclosures. +As of the end of the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(f). Based on our assessment, we believe that as of July 1, 2023, the Company’s disclosure controls and procedures are effective based on that criteria. +Management’s Report on Internal Control over Financial Reporting +Our management has the responsibility to establish and maintain adequate internal controls over our financial reporting, as defined in Rule 13a-15(f) under the Securities and Exchange Act of 1934. Our internal controls are designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our external financial statements in accordance with generally accepted accounting principles (GAAP). +Due to inherent limitations of any internal control system, management acknowledges that there are limitations as to the effectiveness of internal controls over financial reporting and therefore recognize that only reasonable assurance can be gained from any internal control system. Accordingly, our internal control system may not detect or prevent material misstatements in our financial statements and projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, we have performed an assessment of the effectiveness of our internal controls over financial reporting as of July 1, 2023. This assessment was based on the criteria established in Internal Control-Integrated Framework (2013), issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment, we believe that as of July 1, 2023, the Company’s internal control over financial reporting is effective based on that criteria. +Changes in Internal Control over Financial Reporting +There have been no significant changes in our internal controls over financial reporting during our fourth fiscal quarter ended July 1, 2023 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a – 15(f) and 15d – 15(f)). +52 \ No newline at end of file diff --git a/raw/filings/0000719733/2023/0000719733-23-000032/rp_note.txt b/raw/filings/0000719733/2023/0000719733-23-000032/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000719733/2023/0000719733-23-000032/rpt_disclosure.txt b/raw/filings/0000719733/2023/0000719733-23-000032/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..ccb0158bf4be6c99e50cfb88df715c568465e5ce --- /dev/null +++ b/raw/filings/0000719733/2023/0000719733-23-000032/rpt_disclosure.txt @@ -0,0 +1,7 @@ +Related Person Transactions +In April 2007, the Board of Directors adopted a written policy and procedures for the approval or ratification of Interested Transactions with Related Parties. The policy and procedures supplement the Company’s Code of Conduct. The policy defines an “Interested Transaction” as any transaction, arrangement or relationship or series of similar transactions, arrangements or relationships (including any indebtedness or guarantee of indebtedness) in which (1) the aggregate amount involved will or may be expected to exceed $120,000 in any calendar year, (2) the Company is a participant, and (3) any Related Party has or will have a direct or indirect interest (other than solely as a result of being a director or a less than 10 percent beneficial owner of another entity). +The policy defines a “Related Party” as any (a) person who is or was (since the beginning of the last fiscal year for which the Company has filed a Form 10-K and proxy statement, even if they do not presently serve in that role) an executive officer, director or nominee for election as a director, (b) greater than 5 percent beneficial owner of the Company’s Common Stock, or (c) immediate family member of any of the foregoing. Immediate family member includes a person’s spouse, parents, stepparents, children, stepchildren, siblings, mothers- and fathers-in-law, sons- and daughters-in-law, and brothers- and sisters-in-law and anyone residing in such person’s home (other than a tenant or employee). +The Audit Committee is responsible for review, approval, ratification or disapproval of Interested Transactions. In determining whether to approve or ratify an Interested Transaction, the Committee will take into account, among other factors it deems appropriate, whether the Interested Transaction is on terms no less favorable than terms generally available to an unaffiliated third party under the same or similar circumstances and the extent of the Related Party’s interest in the Transaction. +During fiscal year 2023, the Company had no Interested Transactions required to be disclosed pursuant to the SEC’s related persons disclosure. +During fiscal year 2022, the Company purchased surface mount technology inspection equipment and raw materials from CyberOptics. The purchases by the Company during fiscal year 2022 totaled $382,000. These transactions were conducted at arm’s length in the ordinary course of business of the Company and CyberOptics, and the terms of purchase were no more favorable to the Company than purchases by unaffiliated parties from CyberOptics. +8 \ No newline at end of file diff --git a/raw/filings/0000719733/2024/0000719733-24-000113/filing.txt b/raw/filings/0000719733/2024/0000719733-24-000113/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..d3877e51a97adec2c24dafba49e6b4a69338d5db --- /dev/null +++ b/raw/filings/0000719733/2024/0000719733-24-000113/filing.txt @@ -0,0 +1,1633 @@ +ktcc-20240629 +false 2024 FY 0000719733 10,761,871 44.0 http://fasb.org/us-gaap/2024#AccountingStandardsUpdate201613Member http://fasb.org/us-gaap/2024#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2024#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2024#OtherLiabilitiesCurrent http://fasb.org/us-gaap/2024#OperatingLeaseLiabilityNoncurrent 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+____________________________________________________________ +KEY TRONIC CORP ORATION +(Exact name of registrant as specified in its charter) +____________________________________________________________ +Washington 91-0849125 +(State or other jurisdiction of +Incorporation or organization) (I.R.S. Employer +Identification No.) +4424 North Sullivan Road Spokane Valley, Washington 99216 +(Address of principal executive offices) (Zip Code) +( 509 ) 928-8000 +(Registrant’s telephone number, including area code) +____________________________________________________________ +Securities Registered Pursuant to Section 12(b) of the Act: +Title of each class Trading Symbol Name of each exchange on which registered +Common stock, no par value KTCC The NASDAQ Stock Market LLC +Securities Registered Pursuant to Section 12(g) of the Act: None +____________________________________________________________ +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ☐ No ☒ +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ +Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulations S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”, “smaller reporting company” and "emerging growth company" in Rule 12b-2 of the Exchange Act. +(Check one): +Large accelerated filer ☐ Accelerated filer ☐ +Non-accelerated filer ☒ Smaller reporting company ☒ +Emerging growth company ☐ +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ +Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐ +If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☒ +Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to § 240.10D-1(b). ☒ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ +State the aggregate market value of the voting and non-voting common equity held by non affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter. +As of December 30, 2023, the aggregate market value of the registrant’s common stock held by non-affiliates of the registrant was $ 44.0 million based on the closing price as reported on the NASDAQ. +Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: 10,761,871 shares of common stock were outstanding as of October 11, 2024. +____________________________________________________________ +Documents Incorporated by Reference: +Certain information is incorporated into Part III of this report by reference to the Proxy Statement for the registrant’s 2024 annual meeting of stockholders to be filed with the Securities and Exchange Commission pursuant to Regulation 14A not later than 120 days after the end of the fiscal year covered by this Annual Report on Form 10-K. +KEY TRONIC CORPORATION +2024 FORM 10-K +TABLE OF CONTENTS +Page No. +PART I +Item 1. +Business +5 +Item 1A. +Risk Factors +9 +Item 1B. +Unresolved Staff Comments +17 +Item 1C. +Cybersecurity +16 +Item 2. +Properties +19 +Item 3. +Legal Proceedings +20 +Item 4. +Mine Safety Disclosures +20 +PART II +Item 5. +Market for the Registrant’s Common Equity, Related Stockholder Matters, and Issuer Purchases of Equity Securities +20 +Item 6. +[Reserved] +21 +Item 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +21 +Item 7A. +Quantitative and Qualitative Disclosures about Market Risk +31 +Item 8. +Financial Statements and Supplementary Data +32 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +64 +Item 9A. +Controls and Procedures +64 +Item 9B. +Other Information +66 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance +66 +Item 11. +Executive Compensation +66 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +66 +Item 13. +Certain Relationships and Related Transactions, and Director Independence +67 +Item 14. +Principal Accounting Fees and Services +67 +PART IV +Item 15. +Exhibits and Financial Statement Schedule +67 +Item 16. +Form 10-K Summary +70 +Signatures +71 +3 +EXPLANATORY NOTE +In connection with the preparation of this Annual Report on Form 10-K, Key Tronic Corporation (the “Company”) concluded that cost recovery of material price variances was not being consistently recorded across its facilities. Material price variance occurs when the price the Company pays for materials exceeds the price quoted to customers, and the Company typically recovers the excess cost from customers through a sales price adjustment. Per Company policy, this cost recovery should be recorded as revenue when inventory enters the production process, however, certain of the Company’s facilities were recording the cost recovery as a reduction to cost of goods sold. These errors resulted in an understatement of both revenue and cost of goods sold in fiscal 2024 and prior periods. +On October 9, 2024, the Company’s Audit Committee of the Board of Directors, after discussion with Company management and the Company’s independent registered public accounting firm, concluded that the following previously issued financial statements of the Company should no longer be relied upon because of the errors related to the recording of cost recovery: (1) the consolidated financial statements as of and for the years ended July 1, 2023 and July 2, 2022 included in the Company’s Annual Report on Form 10-K for the fiscal year ended July 1, 2023 and (2) the unaudited consolidated statements of operations for the quarters ended March 30, 2024, December 30, 2023, September 30, 2023, April 1, 2023, December 31, 2022, October 1, 2022, April 2, 2022, January 1, 2022, and October 2, 2021 included in the Company’s Quarterly Reports on Form 10-Q for such periods. +Also in connection with preparing this Annual Report on Form 10-K, the Company concluded that it had not recorded an adjustment related to its adoption on July 2, 2023 of ASU 2016-13 Financial Instruments - Credit Losses (ASU 326): Measurement of Credit Losses on Financial Instruments. As of July 2, 2023, the Company should have performed an assessment and recorded any adjustment as a modified retrospective adjustment through its opening retained earnings balance. This error resulted in an overstatement of accounts receivable, contract assets, other assets and retained earnings in the unaudited consolidated balance sheets as of March 30, 2024, December 30, 2023 and September 30, 2023 (the “2024 Interim Balance Sheets”). Management concluded that the errors were immaterial to the previously issued 2024 Interim Balance Sheets and, as a result, the 2024 Interim Balance Sheets have been revised within Note 15 - "Restatement and Revision of Interim Financial Information." +This Annual Report on Form 10-K includes restated consolidated financial statements as of and for the years ended July 1, 2023 and July 2, 2022, restated unaudited consolidated statements of operations for the quarters ended March 30, 2024, December 30, 2023, September 30, 2023, April 1, 2023, December 31, 2022, October 1, 2022, April 2, 2022, January 1, 2022, and October 2, 2021 and revised unaudited consolidated balance sheets as of March 30, 2024, December 30, 2023 and September 30, 2023. For additional information, see Note 14 - “Restatement of Previously Issued Financial Statements” and Note 15 - "Restatement and Revision of Interim Financial Information" of the Notes to Consolidated Financial Statements of this Annual Report on Form 10-K. In addition, the following items of this Annual Report on Form 10-K have been restated, as appropriate, to correct the errors noted above: Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations; Part II, Item 8. Financial Statements and Supplementary Data. +In connection with the restatement and revisions, Company management determined there were deficiencies in the Company’s internal control over financial reporting and the Company’s disclosure controls and procedures that constituted material weaknesses as of June 29, 2024, July 1, 2023 and July 2, 2022. As a result, and as further discussed in Part II, Item 9A. Controls and Procedures of this Annual Report on Form 10-K, Company management has concluded that the Company did not maintain effective disclosure controls and procedures and internal control over financial reporting as of June 29, 2024. +FORWARD-LOOKING STATEMENTS +References in this report to “the Company,” “Key Tronic,” “we,” “our,” or “us” mean Key Tronic Corporation together with its subsidiaries, except where the context otherwise requires. +This Annual Report on Form 10-K contains forward-looking statements in addition to historical information. Forward-looking statements include, but are not limited to those including such words as aims, anticipates, believes, continues, could, estimates, expects, hopes, intends, plans, predicts, projects, targets, or will, similar verbs, or nouns corresponding to such verbs, which may be forward looking. Forward-looking statements also include other passages that are relevant to expected future events, performances, and actions or that can only be fully evaluated by events that will occur in the future. Forward-looking statements are subject to certain risks and uncertainties that could cause actual results to differ materially from those reflected in the forward-looking statements. Risks and uncertainties that might cause such differences include, but are not limited to those outlined in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risks and Uncertainties that May Affect Future Results” and in “Risk Factors.” Readers are cautioned not to place undue reliance on forward-looking statements, which reflect management’s opinions only as of the date hereof. The Company undertakes no obligation to update forward-looking statements to reflect developments or information obtained after the date hereof and disclaims any obligation to do so. Readers should carefully review the risk factors described in periodic reports the Company +4 +files from time to time with the Securities and Exchange Commission, including Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. +PART I +Item 1. BUSINESS +Background +Key Tronic Corporation was organized in 1969, as a Washington corporation that locally manufactured computer keyboards. The ability to design, build and deliver a quality product led us to become a leading independent manufacturer of keyboards for computers in the United States. Our fully integrated design, tooling, and automated manufacturing capabilities enabled us to rapidly respond to customers’ needs for keyboards in production quantities worldwide. We supported our sales growth through the development and purchase of international manufacturing facilities. As the computer keyboard market matured with increasing competition from other international providers, we determined that our business could no longer solely rely on keyboard sales. +After assessing market conditions and our strengths and capabilities, we shifted our focus from keyboard manufacturing to contract manufacturing for a wide range of products. Our unique strategic attributes are based on our core strengths of innovative design and engineering expertise in electronics, mechanical engineering, sheet metal fabrication and stamping, and precision plastics combined with high-quality, low cost production, and assembly on an international basis while providing exceptional customer service. These strengths have made our company a strong competitor in the contract manufacturing market. +Our Industry and Strategy +The expansion of the contract manufacturing industry and our acquisitions have allowed us to continue to expand our customer base and the industries that we serve. The increase in new programs represents a growing portion of our revenue and a promising foundation for our future. In keeping with our long-term strategic objectives, we have been successfully building a more diversified customer portfolio, spanning a wider range of industries. We currently offer our customers the following services: integrated electronic and mechanical engineering, precision plastic molding, sheet metal fabrication, printed circuit board (PCB) and complete product assembly, component selection, sourcing and procurement, worldwide logistics, and new product testing and production all at competitive pricing due to our global footprint. We differentiate ourselves from others our size and larger in the contract manufacturing industry by providing vertical integration, a flexible and responsive approach to our customer’s changing supply demand, and complete design engineering support. +We believe that we are well positioned in the contract manufacturing industry to continue the expansion of our customer base and achieve long-term growth. Our unique blend of multinational facilities, vertical integration, centralized management, and core strengths continue to support our growth and our customers’ needs. We continue to focus on controlling operating expenses and leveraging the synergistic capabilities of our world-class facilities in the United States, Mexico, China, and Vietnam. This international production capability provides our customers with the benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs, and reduced product fulfillment time. Given our competitive advantages and the growing pressure for new potential customers to move forward with their outsourcing strategies, we feel that we are strongly positioned to win new business in coming periods and grow our revenue and profits. +The contract manufacturing industry is intensely competitive. Although our customer base is growing, we still have less than 1% of the potential global market and our revenue can fluctuate significantly due to reliance on a concentrated base of customers. We are planning for new customer growth in the coming quarters by seeking to secure new programs with new and existing customers, increase our worldwide manufacturing capacity, leverage further our design engineering capabilities and continue to improve our manufacturing and procurement processes and capabilities. Ongoing challenges that we face include but are not limited to the following: continuing to win programs from new and existing customers, balancing capital employed, production capacity and key personnel in support of new customer programs, improving operating efficiencies, controlling costs while developing competitive pricing strategies, and successfully transitioning new program wins to full production. +Customers and Marketing +We provide a mix of manufacturing services for outsourced Original Equipment Manufacturing (OEM) products. We provide the following services: product design, surface mount technologies (SMT) and pin through hole capability for printed circuit board assembly, tool making, precision plastic molding, sheet metal fabrication and painting, liquid injection molding, complex assembly, prototype design and full product assembly. +Sales of the majority of our products have not historically been seasonal in nature, but may be seasonal in the future if there are changes in the types of products manufactured. Sales can, however, fluctuate significantly between quarters from changes in customers and customer demand due to the concentration of sales generated by our largest customers. +5 +For the fiscal years 2024, 2023, and 2022, the five largest customers in each year accounted for 34 percent, 35 percent, and 39 percent of combined total net sales, respectively. We aim to diversify our customer base by adding additional programs and customers. We expect net sales to our five largest customers as a percentage of total net sales to approximate current levels going forward. +The following table summarizes the customers that represented 10 percent or more of total net sales during the last two fiscal years: +Percentage of Net Sales by Fiscal Year +2024 2023 2022 +Customer A 20% 12% 12% +Customer B * * 13% +There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +We market our products and services primarily through our direct sales department which is comprised of strategically located field sales people and distributors. We also maintain relationships with several independent sales organizations to assist in marketing our product lines. +Manufacturing +We have continually made investments in developing and expanding a capital equipment base to achieve vertical integration and efficiencies in our manufacturing processes. We have invested significant capital into SMT for volume manufacturing of complex printed circuit board assemblies and in our metal shop providing precision metal stamping, fabricating, and finishing. We also design and develop tooling for injection molding and sheet metal fabrication and manufacture the majority of plastic and sheet metal parts used in the products we manufacture. Additionally, we have equipment to maintain a controlled clean environment for manufacturing processes that require a high level of precise control. +We use a variety of manual and automated assembly processes in our facilities, depending upon product complexity and degree of customization. Some examples of automated processes include component insertion, SMT, selective soldering, flexible robotic assembly, computerized vision system quality inspection, laser turrets, automated switch and key top installation, robotic welding, automated powder coat application, and automated functional testing. +Our engineering expertise and automated manufacturing processes enable us to work closely with our customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. We use computer-aided design techniques and software to assist in preparation of the tool design layout and component placement, to reduce tooling and production costs, improve component and product quality, and enhance turnaround time during product development. +We purchase materials and components for our products from many different suppliers, including both domestic and international sources. We develop close working relationships with our suppliers, many of whom have been supplying products to us for several years. +Research, Development, and Engineering +As part of our long-term strategy, we are committed to supporting our customers by providing research, development, and engineering services. We have seen an increase in the success of providing design support on existing and potential customers in differentiating ourselves. We believe these services allow us to facilitate in optimizing new product designs, and the production processes of our customers’ programs. +Research, development, and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials costs, depreciation, and allocated information technology and facilities costs. +Competition +The market for the products and services we provide is highly competitive. There are numerous competitors in the contract manufacturing industry, many of which have substantially more resources and are more geographically diverse than we are. Some of our competitors have similar international production capabilities, large financial resources and some have +6 +substantially greater manufacturing, research and development, and marketing resources. There is also competition from the manufacturing operations of our current and potential customers, who are continually evaluating the merits of manufacturing their products internally versus the advantages of outsourcing. We believe that we can currently compete favorably in these areas primarily on the basis of our international footprint, responsiveness, creativity, vertical production capability, quality, and cost. +Trademarks +Our name and logo are federally registered trademarks, and we believe they are valuable assets of our business. +Employees +We consider our employees to be our primary strength and we make considerable efforts to maintain a well-qualified workforce. Our employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. We regularly provide transportation, medical services, and meals to all of our employees in foreign locations. The Company also has defined contribution plans available to U.S. employees who have attained age 21 and provide group health, life, and disability insurance plans. We also maintain share-based compensation plans and other long-term incentive plans for certain employees and outside directors. +As of June 29, 2024, we had 4,122 full-time employees compared to 5,447 on July 1, 2023. Since we can have significant fluctuations in product demand, we seek to maintain flexibility in our workforce by utilizing skilled temporary labor in some of our manufacturing facilities in addition to full-time employees. +Backlog +On June 29, 2024, our order backlog was valued at approximatel y $249.6 million, compared to approximately $343.0 million on July 1, 2023. The amount of backlog is not necessarily indicative of future sales but can be indicative of trends in expected future sales revenue. Due to the relationships with our customers, we will occasionally allow orders to be canceled or rescheduled and as a result it is not a meaningful indicator of future financial results. If there are canceled or rescheduled orders, we typically negotiate fees to cover the costs we have incurred. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change due to design modifications, customer forecast changes, or other customer requirements. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in Note 11 - “Enterprise-Wide Disclosures” of the “Notes to Consolidated Financial Statements” of this Annual Report on Form 10-K and that information is incorporated herein by reference. +Governmental Regulation +Our operations are subject to certain foreign, federal, state and local regulations relating to, among others, environmental, waste management, labor and health and safety matters. We have implemented processes and procedures to help ensure that our operations are in substantial compliance with all applicable regulations. However, material costs and liabilities may arise from these requirements or from new or modified requirements, which could have a material adverse effect on our business and results of operations. +Information about Our Executive Officers +The table below sets forth the name, current age, and current position of our executive officers and other significant employees: +Name Age Positions Held +Executive Officers +Brett R. Larsen 51 President and Chief Executive Officer +Anthony G. Voorhees 50 Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Philip S. Hochberg 62 Executive Vice President of Customer Relations and Integration +Duane D. Mackleit 56 Executive Vice President of Operations +David H. Knaggs 43 Executive Vice President of Quality, Regulatory Affairs, and Information Systems +Chad T. Orebaugh 53 Executive Vice President of Engineering +Mark Courtney 58 Vice President of Supply Chain +7 +Executive Officers +BRETT R. LARSEN – President and Chief Executive Officer +Mr. Larsen, age 51, has served as President and Chief Executive Officer since July 2024. Previously he was the Executive Vice President of Administration, Chief Financial Officer, and Treasurer from July 2015 through June 2024. He was Vice President of Finance and Controller from February 2010 to July 2015. He was Chief Financial Officer of FLSmidth Spokane, Inc. from December 2008 to February 2010. From October 2005 through November 2008, Mr. Larsen served as Controller of Key Tronic Corporation. From May 2004 to October 2005, Mr. Larsen served as Manager of Financial Reporting of Key Tronic Corporation. From 2002 to May 2004, Mr. Larsen was an audit manager for the public accounting firm BDO USA, LLP. He also held various auditing and supervisory positions with Grant Thornton LLP from 1997 to 2002. Mr. Larsen has a Bachelor of Science degree in Accounting and a Masters degree in Accounting from Brigham Young University and is a Certified Public Accountant. +ANTHONY G. VOORHEES - Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Mr. Voorhees, age 50, has served as Executive Vice President of Administration, Chief Financial Officer, and Treasurer since July 2024. Previously, he was Vice President of Finance and Controller from November 2021 to June 2024, Senior Manager of Corporate Finance from July 2015, and Manager of Financial Reporting since April 2010. Prior to joining Key Tronic, Mr. Voorhees worked at Coldwater Creek from August 2007 to March 2010 as a Senior Financial Reporting Accountant. Prior to that, he worked at Moss Adams, LLP as a Senior Assurance Associate from November 2004 to August 2007. Between September 2001 and August 2004, Mr. Voorhees held senior level accounting positions at Boise State University and Idaho State Department of Agriculture. Mr. Voorhees has a bachelor degree in Accounting from the University of Idaho and is a Certified Public Accountant. +PHILIP S. HOCHBERG – Executive Vice President of Customer Relations and Integration +Mr. Hochberg, age 62, has been Executive Vice President of Customer Relations and Integration since July 2012. Prior to this, Mr. Hochberg served as Vice President of Business Development from October 2009 through June 2012. He was Director of Business Development and Program Management from July 2008 to October 2009. Mr. Hochberg served as Director of Business Development from October 2004 to July 2008 and as Director of EMS Sales and Marketing from July 2000 to October 2004. Prior to joining Key Tronic, Mr. Hochberg worked for Quinton Instrument Company as their Director of Marketing and Product Management from 1992 to 2000. From 1988 to 1992, he was employed by SpaceLabs Medical as their Business Development Marketing Manager. Mr. Hochberg has an MBA from the University of British Columbia, a BA in Psychology, with a minor in Business from Washington University in St. Louis. +DUANE D. MACKLEIT – Executive Vice President of Operations +Mr. Mackleit, age 56, has been Executive Vice President of Operations since December 2019. Prior to this, Mr. Mackleit served as Vice President of Program Management since July 2012. He served as Director of Program Management from July 2008 through June 2012. From May 2006 to July 2008 he served as Principal Program Manager. Prior to that, he served as Program Manager from March 2002 to May 2006 and Associate Program Manager from August 2000 to March 2002. Mr. Mackleit has also held several other positions with Key Tronic Corporation. Mr. Mackleit has an AA in Business from Spokane Falls Community College and a BA in Business/Marketing from Eastern Washington University. He also holds a MBA from Gonzaga University. +DAVID H. KNAGGS – Executive Vice President of Quality, Regulatory Affairs, and Information Systems +Mr. Knaggs, age 43, has been Executive Vice President of Quality, Regulatory Affairs, and Information Systems since May 2021. Previously, he was Vice President of Quality and Regulatory Affairs from November 2017 to May 2021. He was Vice President of Quality since October 2016. Before joining Key Tronic, Mr. Knaggs worked at Telect, Inc. from 2008 to 2016 as their Director of Engineering. Prior to that, he worked at Isothermal Systems Research as Lead Systems Engineer from 2003 to 2008. He has a Bachelor of Science degree in Mechanical Engineering with a minor in mathematics from the University of Washington. +CHAD T. OREBAUGH – Executive Vice President of Engineering +Mr. Orebaugh, age 53, has been Executive Vice President of Engineering since September 2021. Previously he served as Vice President of Engineering since April 2017. Prior to this, Mr. Orebaugh served as Director of Engineering since May 2013. From April 2010 to May 2013, he served as Manager of Engineering. From January 2000 to April 2010 he served as Lead Mechanical Engineer. Prior to that, he served as Mechanical Engineer from October 1998 to January 2000 and Associate Mechanical Engineer since October 1997. Mr. Orebaugh holds a BA in Mechanical Engineering from Gonzaga University. +MARK COURTNEY – Vice President of Supply Chain +8 +Mark Courtney, age 58, has been Vice President of Supply Chain of the company since August 2019. Previously, he served as Purchasing Manager and Director of North American Purchasing from September 2015 to August 2019, and as Supply Chain Manager, ERP and Business Operations Manager for Amphenol Telect from August 2007 to September 2015. From March 2006 to August 2007, he served as Senior Buyer/Planner for Honeywell Specialty Materials and from June 2005 to March 2006 as Purchasing Manager for MRV Communications. From May 2000 to June 2005, he served as a Field and Inside Sales Associate for Arrow Electronics and from October 1991 to May 2000 held various positions at Alesis. +Available Information +Our principal executive offices are located at 4424 North Sullivan Road, Spokane Valley, Washington 99216, and our telephone number is (509) 928-8000. Our website is located at http://www.keytronic.com where filings of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or current reports on Form 8-K are available free of charge after they have been filed with the Securities and Exchange Commission. The information presented on our website currently and in the future is not considered to be part of this document or any document incorporated by reference in this document. +In addition, the SEC maintains an Internet site (at www.sec.gov ) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. +Item 1A. RISK FACTORS +There are risks and uncertainties that could affect our business. These risks and uncertainties include but are not limited to, the risk factors described below, in Item 7A: “Quantitative and Qualitative Disclosures about Market Risk” and elsewhere in this Annual Report on Form 10-K. +RISKS AND UNCERTAINTIES THAT MAY AFFECT FUTURE RESULTS +The following risks and uncertainties could affect our actual results and could cause results to differ materially from past results or those contemplated by our forward-looking statements. When used herein, the words “expects,” “believes,” “anticipates” and other similar expressions are intended to identify forward-looking statements. +RISKS RELATED TO OUR BUSINESS AND STRATEGY +Our operations may be subject to certain risks. +We manufacture product in facilities located in Mexico, China, Vietnam and the United States. These operations may be subject to a number of risks, including: +• difficulties in staffing, turnover and managing onshore and offshore operations; +• political and economic instability (including acts of terrorism, pandemics, civil unrest, forms of violence and outbreaks of war), which could impact our ability to ship, manufacture, and/or receive product; +• unexpected changes in regulatory requirements and laws, including those related to climate change; +• longer customer payment cycles and difficulty collecting accounts receivable; +• cash liquidity, the ability to acquire new debt capacity, and capital constraints; +• export duties, import controls and trade barriers (including quotas); +• governmental restrictions on the transfer of funds; +• burdens of complying with a wide variety of foreign laws and labor practices; subject to trade wars and tariffs; +• our locations are subject to physical and operational risks from natural disasters, severe weather events, and climate change +• our locations may also be impacted by future temporary closures and labor constraints as a result of local mandates for medical, climate, and unforeseen emergencies; and +• our locations may be impacted by future temporary closure related to cyberattacks. +Our operations in certain foreign locations receive favorable income tax treatment in the form of tax credits or other incentives. In the event that such tax incentives are not extended, are repealed, or we no longer qualify for such programs, our taxes may increase, which would reduce our net income. +Additionally, certain foreign jurisdictions restrict the amount of cash that can be transferred to the U.S. or impose taxes and penalties on such transfers of cash. To the extent we have excess cash in foreign locations that could be used in, or is needed by, our operations in the United States, we may incur significant penalties and/or taxes to repatriate these funds. +9 +We may experience fluctuations in quarterly results of operations. +Our quarterly operating results have varied in the past and may vary in the future due to a variety of factors, including adverse changes in the U.S. and global macroeconomic environment, volatility in overall demand for our customers’ products, success of customers’ programs, timing of new programs, new product introductions or technological advances by us, our customers and our competitors, and changes in pricing policies by us, our customers, our suppliers, and our competitors. Our customer base is diverse in the markets they serve, however, decreases in demand, particularly from customers in certain industries could affect future quarterly results. Additionally, our customers could be adversely impacted by illiquidity in the credit markets which could directly impact our operating results. +Component procurement, production schedules, personnel and other resource requirements are based on estimates of customer requirements. Occasionally, our customers may request accelerated production that can stress resources and reduce operating margins. Conversely, our customers may abruptly lower or cancel production which may lead to a sudden, unexpected increase in inventory or accounts receivable for which we may not be reimbursed even when under contract with customers. In addition, because many of our operating expenses are relatively fixed, a reduction in customer demand can harm our gross profit and operating results. The products which we manufacture for our customers have relatively short product lifecycles. Therefore, our business, operating results and financial condition are dependent in a significant way on our ability to obtain orders from new customers and new product programs from existing customers. +Operating results can also fluctuate if changes are made to significant estimates and assumptions. Significant estimates and assumptions include the allowance for credit losses, provision for inactive, obsolete, and surplus inventory, stock-based compensation, the valuation allowance on deferred tax assets, impairment of long-lived assets, long-term incentive compensation accrual, the provision for warranty costs, and the impact of hedging activities. +Due to the COVID-19 pandemic, we have seen extreme shifts in demand from our customer base. The possibility of future temporary closures and labor constraints, as well as the inability to predict customer demand, costs, and future supply chain disruptions during pandemics can materially impact operating results. +We are exposed to general economic conditions, which could have a material adverse impact on our business, operating results and financial condition. +Adverse economic conditions and uncertainty in the global economy such as unstable global financial and credit markets, inflation, and recession can negatively impact our business. Unfavorable economic conditions could affect the demand for our customers’ products by triggering a reduction in orders as well as a decline in forecasts which could adversely affect our sales in future periods. Additionally, the financial strength of our customers and suppliers and their ability to obtain and rely on credit financing may affect their ability to fulfill their obligations to us and have an adverse effect on our financial results. +Adverse macroeconomic conditions, such as those that were a result of COVID-19 have and may continue to affect our business. The conditions affect the Company’s ability to predict and plan for future supply chain disruptions, fluctuations in customer demand and costs, and the ability to operate as there is uncertainty over future temporary closures. Inflation has also risen globally to historically high levels. As the inflation rate continues to increase, the costs of labor and other expenses have and may continue to increase. We may not be able to increase our product prices enough to offset these increased costs. In addition, any increase in our product prices may reduce our future customer orders and profitability. Inflation may further exacerbate other risk factors discussed in this Annual Report on Form 10-K, including disruptions to international operations. +The majority of our sales come from a small number of customers, and a decline in sales to any of these customers could adversely affect our business. +At present, our customer base is concentrated and could become more or less concentrated. There can be no assurance that our principal customers will continue to purchase products from us at current levels. Moreover, we typically do not enter into long-term volume purchase contracts with our customers, and our customers have certain rights to extend or delay the shipment of their orders. We, however, typically require that our customers contractually agree to buy back inventory purchased within specified lead times to build their products if not used. +The loss of one or more of our principal customers, or the reduction, delay or cancellation of orders from such customers, due to economic conditions or other forces, could materially and adversely affect our business, operating results and financial condition. The contraction in demand from certain industries could impact our customer orders and have a negative impact on our operations over the foreseeable future. +Our inability to enforce contracts with, or the bankruptcy or insolvency of, any of our principal customers could adversely affect our business. +We rely on timely and regular payments from our customers, and the inability or failure of our principal customers to meet their obligations to us or their bankruptcy, insolvency or liquidation may adversely affect our business, financial condition and results of operations. Financial difficulties experienced by one or more of our customers could negatively affect our business by +10 +decreasing demand from such customers and through the potential inability of these companies to make full payment on amounts owed to us. Customer bankruptcies also entail the risk of potential recovery by the bankruptcy estate of amounts previously paid to us that are deemed a preference under bankruptcy laws. There can be no assurance that customers will not declare bankruptcy or suffer financial distress, in which case our future revenues, net income and cash flow could be reduced. +In addition, we structure our agreements with customers to mitigate our risks related to obsolete, aged, or unsold inventory. However, enforcement of these contracts may result in material expense and delay in payment for inventory. If any of our significant customers become unable or unwilling to purchase such inventory, our business may be materially harmed. +We depend on a limited number of suppliers for certain components that are critical to our manufacturing processes. A shortage of these components or an increase in their price could interrupt our operations and result in a significant change in our results of operations. +We are dependent on many suppliers, including sole source suppliers, to provide key components and raw materials used in manufacturing customers’ products. We have seen supply shortages in certain electronic components. In addition, our suppliers' facilities may also experience closures or limited production due to natural disasters or other reasons, which may cause a shortage of components. This can result in longer lead times and the inability to meet our customers' requests for flexible production and extended shipment dates. If demand for components outpaces supply, capacity delays could affect future operations. Delays in deliveries from suppliers or the inability to obtain sufficient quantities of components and raw materials have and may continue to cause delays or reductions in shipment of products to our customers which could adversely affect our operating results and damage customer relationships. +We operate in a highly competitive industry; if we are not able to compete effectively in the contract manufacturing industry, our business could be adversely affected. +Competitors may offer customers lower prices on certain high volume programs. This could result in price reductions, reduced margins and loss of market share, all of which would materially and adversely affect our business, operating results, and financial condition. If we were unable to provide comparable or better manufacturing services at a lower cost than our competitors, it could cause sales to decline. In addition, competitors can copy our non-proprietary designs and processes after we have invested in development of products for customers, thereby enabling such competitors to offer lower prices on such products due to savings in development costs. +Fluctuations in foreign currency exchange rates have increased and could continue to increase our operating costs. +We have manufacturing operations located in Mexico and China. A significant portion of our operations are denominated in the Mexican Peso and the Chinese currency, the renminbi ("RMB"). Currency exchange rates fluctuate daily as a result of a number of factors, including changes in a country's political and economic policies. Volatility in the currencies of our entities and the United States dollar, as well as inflationary costs, could seriously harm our business, operating results and financial condition. The primary impact of currency exchange fluctuations is on the cash, receivables, payables and expenses of our operating entities. As part of our hedging strategy, we currently use Mexican Peso forward contracts to hedge future foreign currency fluctuations for a portion of our Mexican Peso denominated expenses. We currently do not hedge expenses denominated in RMB and have occasionally also been unable to hedge expenses denominated in Mexican Peso. Losses have occurred from increases in the value of these currencies relative to the United States dollar and further losses could occur, which could be material to our business, financial results or operations. +Global economic and political events or significant currency exchange fluctuations, can occur, and cause further unexpected losses. Future temporary closures of production facilities in Mexico could also cause significant changes in our ability to qualify for hedge accounting treatment of our forward contracts to hedge foreign currency fluctuations. +Our success will continue to depend to a significant extent on our key personnel and our ability to execute our management succession plans. +Our future success depends in large part on the continued service of our key technical, marketing and management personnel and on our ability to continue to attract and retain qualified production employees. There can be no assurance that we will be successful in attracting and retaining such personnel, particularly in our manufacturing locales that may be experiencing high demand for similar key personnel. The loss of key employees could have a material adverse effect on our business, operating results and financial condition. +In addition, we must successfully manage transition issues that may result from the departure or retirement of members of our leadership team. For example, our Chief Executive Officer retired at the end of fiscal year 2024 and is succeeded by our former Chief Financial Officer. Any significant leadership change or senior management transition involves inherent risks and any failure to ensure a smooth transition could hinder our strategic planning, business execution, and future performance. We cannot provide assurances that any changes of management personnel will not cause disruption to operations or customer relationships or a decline in our operating results. +11 +Start-up costs and inefficiencies related to new or transferred programs can adversely affect our operating results and such costs may not be recoverable if such new programs or transferred programs are canceled or don’t meet expected sales volumes. +Start-up costs, the management of labor and equipment resources in connection with the establishment of new programs and new customer relationships, and the need to obtain required resources in advance can adversely affect our gross margins and operating results. These factors are particularly evident in the ramping stages of new programs. These factors also affect our ability to efficiently use labor and equipment. We continuously manage a number of new programs. Consequently, our exposure to these factors is consistently elevated. In addition, if any of these new programs or new customer relationships were terminated, our operating results could be harmed, particularly in the short term. We may not be able to recoup these start-up costs or replace anticipated new program revenues. +Customers may change production timing and demand schedules which makes it difficult for us to schedule production and capital expenditures and to maximize the efficiency of our manufacturing capacity. +Changes in demand for customer products reduce our ability to accurately estimate the future requirements of our customers. This makes it difficult to schedule production and maximize utilization of our manufacturing capacity. We must determine the levels of business that we will seek and accept from customers, set production schedules, commit to procuring inventory, and allocate personnel and resources, based on our estimates of our customers' requirements. Customers can require sudden increases and decreases in production which can put added stress on resources and reduce margins. Sudden decreases in production can lead to excess inventory on hand which may or may not be reimbursed by our customers even when under contract. +Continued growth could further lead to capacity constraints. We may need to transfer production to other facilities, acquire new facilities, or outsource production which could negatively impact gross margin. +Compliance or the failure to comply with current and future environmental and health laws or regulations could cause us significant expense. +We are subject to a variety of domestic and foreign environmental regulations relating to the use, storage, and disposal of materials used in our manufacturing processes. In addition, increasing governmental focus on climate change may result in new environmental regulations that may negatively affect us, our vendors or our customers. As a result, we may incur additional costs or obligations in complying with any new environmental and reporting requirements, as well as increased indirect costs resulting from our vendors or suppliers that get passed on to us. +If we fail to comply with any present or future regulations, we could be subject to future liabilities or the suspension of current manufacturing operations. In addition, such regulations could restrict our ability to expand our operations or could require us to acquire costly equipment, substitute materials, or incur other significant expenses to comply with government regulations. +If our manufacturing processes and services do not comply with applicable statutory and regulatory requirements, or if we manufacture products containing design or manufacturing defects, demand for our services may decline and we may be subject to liability claims. +We manufacture and design products to our customers’ specifications, and, in some cases, our manufacturing processes and facilities may need to comply with applicable statutory and regulatory requirements. For example, medical devices that we manufacture or design, as well as the facilities and manufacturing processes that we use to produce them, are regulated by the Food and Drug Administration and non-U.S. counterparts of this agency. In addition, our customers’ products and the manufacturing processes that we use to produce them often are highly complex. As a result, products that we manufacture may at times contain manufacturing or design defects, and our manufacturing processes may be subject to errors or not be in compliance with applicable statutory and regulatory requirements. Defects in the products we manufacture or design, whether caused by a design, manufacturing or component failure or error, or deficiencies in our manufacturing processes, may result in delayed shipments to customers or reduced or canceled customer orders. If these defects or deficiencies are significant, our business reputation may also be damaged. The failure of the products that we manufacture or our manufacturing processes and facilities to comply with applicable statutory and regulatory requirements may subject us to legal fines or penalties and, in some cases, require us to shut down or incur considerable expense to correct a manufacturing process or facility. Our customers are required to indemnify us against liability associated with designing products to meet their specifications. However, if our customers are responsible for the defects, they may not, or may not have resources to, assume responsibility for any costs or liabilities arising from these defects, which could expose us to additional liability claims. +If we do not manage our growth effectively, our profitability could decline. +When our business is experiencing growth, such growth can place considerable additional demands upon our management team and our operational, financial and management information systems. Our ability to manage growth effectively requires us to continue to implement and improve these systems; avoid cost overruns; maintain customer, supplier and other favorable +12 +business relationships during possible transition periods; continue to develop the management skills of our managers and supervisors; and continue to train, motivate and manage our employees. Our failure to effectively manage growth could have a material adverse effect on our results of operations. +Energy price increases may negatively impact our results of operations. +Certain components that we use in our manufacturing process are petroleum-based. In addition, we, along with our suppliers and customers, rely on various energy sources in our transportation activities. While significant uncertainty currently exists about the future levels of energy prices, a significant increase, such as the increased fuel prices experienced in fiscal year 2022, is possible. Increased energy prices could cause an increase to our raw material costs and transportation costs. In addition, increased transportation costs related to certain suppliers and customers could be passed along to us. We may not be able to increase our product prices enough to offset these increased costs. In addition, any increase in our product prices may reduce our future customer orders and profitability. +TECHNOLOGY RISKS +Our operations are subject to cyberattacks that have had and could have a material adverse effect on our business. +We are increasingly dependent on digital technologies and services to conduct our operations. We use these technologies for internal purposes, including data storage, processing and transmissions, as well as in our interactions with vendors and customers. Digital technologies and services are subject to the risk of cybersecurity incidents and some incidents can remain undetected for a period of time. +We routinely monitor our systems for cyber threats and believe we have sufficient processes in place to detect and remediate vulnerabilities. Nevertheless, we have experienced attempted security breaches, such as phishing emails and other targeted attacks. For example, as previously disclosed in our Form 8-K filed with the SEC on May 10, 2024, as amended, we became aware of unauthorized access to our IT systems that resulted in a material impact on our financial condition and results of operations during the fourth quarter ending June 29, 2024 (the "Previously Disclosed Cyber Incident"). We expect that our operations will continue to be subject to cyber threats, and any future cybersecurity incident could significantly disrupt our operations. +The threat actor in the Previously Disclosed Cyber Incident exfiltrated certain personally identifiable information, and future cybersecurity incidents could also result in the misappropriation of proprietary or confidential information of the Company or that of its customers, employees, vendors or suppliers. We have incurred and expect to continue to incur costs to mitigate against the Previously Disclosed Cyber Incident and other cybersecurity incidents as threats are expected to continue to become more persistent and sophisticated. If our systems for protecting against cybersecurity incidents, including the Previously Disclosed Cyber Incident, prove not to be sufficient, we could be adversely affected by, among other things, loss of or damage to intellectual property, proprietary or confidential information, or employee, vendor or customer data; interruption of our business operations; and increased costs to prevent, respond to or mitigate cybersecurity incidents. In addition, our investigation of the Previously Disclosed Cyber Incident is ongoing, and we may discover other impacts or new events related to this incident that could affect the Company, including our business, financial condition or results of operations. Any of these risks could harm our reputation and our relationships with employees, vendors and customers and may result in claims or enforcement actions and investigations against us. +Disruptions to our information systems, including losses of data or outages, could adversely affect our operations. +We rely on information technology networks and systems to process, transmit and store electronic information. In particular, we depend on our information technology infrastructure for a variety of functions, including worldwide financial reporting, inventory management, procurement, invoicing and email communications. Any of these systems may be susceptible to outages due to fire, floods, power loss, telecommunications failures, terrorist attacks and similar events. If we or our vendors are unable to prevent such outages, our operations could be disrupted. +If we are unable to maintain our technological and manufacturing process expertise, our business could be adversely affected. +The markets for our customers’ products are characterized by rapidly changing technology, evolving industry standards, frequent new product introductions and short product life cycles. The introduction of products embodying new technologies or the emergence of new industry standards can render existing products obsolete or unmarketable. Our success will depend upon our customers’ ability to enhance existing products and to develop and introduce, on a timely and cost-effective basis, new products that keep pace with technological developments and emerging industry standards and address evolving and increasingly sophisticated customer requirements. Failure of our customers to do so could substantially harm our customers’ competitive positions. There can be no assurance that our customers will be successful in identifying, developing and marketing products that respond to technological change, emerging industry standards or evolving customer requirements. +13 +RISKS RELATED TO CAPITAL AND FINANCING +Our failure to comply with the covenants in our credit arrangements could materially and adversely affect our financial condition. +We have restrictive covenants with our financial institutions that impact how we manage our business. We have not always met these covenants in the past and have had to obtain waivers and amend our Loan Agreement, including for events of default related to breaches of the fixed charge coverage ratio for fiscal quarter ended March 30, 2024 and the periods ended June 29, 2024 and July 27, 2024. The amendment waiving the event of default for fiscal quarter ended March 30, 2024 resulted in an increase in interest rates and shortened the maturity date to September 3, 2025.In addition, this amendment reduced the minimum requirement for the fixed charge coverage ratio from 1.25:1.00 to 1.00:1.00 as of March 30, 2024, with the minimum requirement to increase as follows: 1.05:1.00 on July 27, 2024, 1.15:1.00 on October 26, 2024, 1.20:1.00 on January 25, 2025 and 1.25:1.00 on and after March 29, 2025. As noted above, we were unable to meet this ratio for the periods ended June 29, 2024 and July 27, 2024, and we also breached a covenant requiring us to deliver audited financial statements to the lender within 90 days of the Company’s fiscal year-end. As a result, we had to further amend our Loan Agreement on October 9, 2024. The amendment waiving these events of default resulted in an increase in interest rates and increased the availability block, which reduces the calculated borrowing base under the Loan Agreement, from $8 million to $10 million, with further increases to $11 million and $12 million to be effective on December 31, 2024 and March 31, 2025, respectively. +We may not meet the minimum fixed charge coverage ratio or comply with other covenants in the future and may not be able to obtain waivers or amendments from the relevant lenders on terms acceptable to us, or at all. In the event we breach any covenant that results in an event of default, our lenders could choose to accelerate payment of the amounts owed by the Company. Under those circumstances our borrowings could become immediately payable. The amendment of our credit arrangements on unfavorable terms or the acceleration of our payment obligations thereunder, would have a material adverse effect on our business, financial condition, results of operations and cash flows. For a summary of our debt obligations, see Note 4 - “Long-Term Debt” of the Notes to Consolidated Financial Statements. +Our ability to secure and maintain sufficient credit arrangements is key to our continued operations. +There is no assurance that we will be able to retain, renew, or refinance our credit arrangements on terms acceptable to us, or at all. As noted in the prior risk factor, a recent amendment to our Loan Agreement shortened the maturity date to September 3, 2025. On September 27, 2024, in connection with the preparation of this Annual Report on Form 10-K, we entered into an additional amendment to the Loan Agreement to extend the maturity date by three months to December 3, 2025. Because our Loan Agreement terminates on December 3, 2025, we need to extend, renew or refinance this agreement in the coming months. The terms available to us may be less favorable than the terms of our existing Loan Agreement. Our inability to extend, renew, or refinance our indebtedness on a timely basis could also result in unfavorable accounting treatment. This could include management and our independent auditors concluding on risks over the Company's ability to continue as a going concern. Our inability to extend, renew or refinance our credit arrangements could have a material adverse impact on our business, financial condition, results of operations and cash flows. +Additionally, in the event that our business grows rapidly or there is uncertainty in the macroeconomic climate, additional financing resources could be necessary in the current or future fiscal years. There is no assurance that we will be able to obtain equity or debt financing at acceptable terms, or at all, in the future. +Adverse changes in the interest rates of our borrowings could adversely affect our financial condition. +We are exposed to interest rate risk under our revolving line of credit and term loans. We have not historically hedged the interest rate on our credit facility; therefore, unless we do so, significant changes in interest rates could adversely affect our results of operations. For a summary of our debt obligations, see Note 4 - “Long-Term Debt” of the Notes to Consolidated Financial Statements. +Cash and cash equivalents are exposed to concentrations of credit risk. +We place our cash with high credit quality institutions. At times, such balances may be in excess of the federal depository insurance limit or may be on deposit at institutions which are not covered by insurance. If such institutions were to become insolvent during which time it held our cash and cash equivalents in excess of the insurance limit, it could be necessary to obtain other credit financing to operate our facilities. +Our stock price is volatile. +Our stock price has and may continue to be subject to wide fluctuations and possible rapid increases or declines over a short time period. These fluctuations may be due to factors specific to us such as our stock's thinly traded nature, variations in quarterly operating results, changes in earnings estimates, matters arising from the subject matter of the Audit Committee's internal investigation, or to factors relating to the contract manufacturing industry or to the securities markets in general, which, in recent years, have experienced significant price fluctuations. These fluctuations often have been unrelated to the operating performance of the specific companies whose stocks are traded. In addition, holders of our common stock will suffer immediate dilution to the extent outstanding equity awards are exercised to purchase common stock. +14 +RISKS RELATED TO OUR CONTROLS AND PROCEDURES AND THE INTERNAL INVESTIGATION +We have concluded that our internal control over financial reporting and our disclosure controls and procedures were not effective as of June 29, 2024 due to material weaknesses, which has adversely affected our ability to report our financial results in a timely and accurate manner and could have a material adverse impact our business and financial condition. +We are required to evaluate the effectiveness of our disclosure controls and procedures and our internal control over financial reporting on a periodic basis and publicly disclose the results of these evaluations and related matters in accordance with the requirements of Section 404 of the Sarbanes-Oxley Act of 2002. As described in Item 9A. Controls and Procedures of this Annual Report on Form 10-K, we have identified a material weakness in the design and implementation of effective controls over the accounting for revenue recognition relating to cost recovery of material price variances. We have also identified a material weakness in the design and implementation of effective controls over the adoption of new accounting standards. As a result of these material weaknesses, our management concluded that our internal control over financial reporting and disclosure controls and procedures were not effective as of June 29, 2024. +We are engaged in developing and implementing a remediation plan, as described in Item 9A. Controls and Procedures of this Annual Report on Form 10-K, designed to address the material weaknesses, but our remediation efforts are not complete and are ongoing. Although we are working to remedy the ineffectiveness of the Company’s internal control over financial reporting, there can be no assurance as to when the remediation plan will be fully developed, when it will be fully implemented or the aggregate cost of implementation. Until our remediation plan is fully implemented, our management will continue to devote time and attention to these efforts. If we do not complete our remediation in a timely fashion, or at all, or if our remediation plan is inadequate, there will continue to be an increased risk that we will be unable to timely file future periodic reports with the SEC and that our future consolidated financial statements could contain errors that will be undetected. If we are unable to report our results in a timely and accurate manner, our stock may be delisted from the NASDAQ Global Market and we will not be able to comply with the applicable covenants in our financing arrangements, including our Loan Agreement, as described in —Risks Related to Capital and Financing—“Our failure to comply with the covenants in our credit arrangements could materially and adversely affect our financial condition.” In addition, we could be subject to regulatory investigations and penalties or stockholder litigation. Any of these risks could have a material adverse impact on our business and financial condition. +If we fail to maintain proper and effective internal controls, our business and financial condition could be materially adversely impacted. +We cannot assure you that we will not discover additional deficiencies in our internal control over financial reporting. Moreover, as discussed in the following risk factor, because of the inherent limitations of any control system, material misstatements due to error or fraud may not be prevented or detected on a timely basis, or at all. As of June 29, 2024, we are a non-accelerated filer under the Exchange Act and are not required to comply with the auditor attestation requirements of Section 404(b) of the Sarbanes-Oxley Act of 2002 (the Sarbanes-Oxley Act). Therefore, our internal controls over financial reporting will not receive the level of review provided by the process relating to the auditor attestation included in annual reports of issuers that are subject to the auditor attestation requirements. +Further and continued determinations that there are deficiencies in the effectiveness of the Company’s internal control over financial reporting could result in another restatement of our consolidated financial statements, cause us to fail to meet our reporting obligations, reduce our ability to obtain financing, negatively affect investor confidence in our management and the accuracy of our financial statements and disclosures, or result in adverse publicity and concerns from investors, any of which could have a negative effect on the price of our common stock, subject us to regulatory investigations and penalties or stockholder litigation, and materially adversely impact our business, financial condition, results of operations and cash flows. +Due to inherent limitations, there can be no assurance that our system of disclosure and internal controls and procedures will be successful in preventing all errors, theft and fraud, or in informing management of all material information in a timely manner. +Management does not expect that our disclosure controls and procedures and internal controls over financial reporting will prevent all errors or fraud. A control system is designed to give reasonable, but not absolute, assurance that the objectives of the control system are met. In addition, any control system reflects resource constraints and the benefits of controls must be considered relative to their costs. Inherent limitations of a control system may include: judgments in decision making may be faulty, breakdowns can occur simply because of error or mistake and controls can be circumvented by collusion or management override. Due to the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and may not be detected. +Matters relating to or arising from the subject of the Audit Committee’s internal investigation, including expenses and diversion of personnel and resources, regulatory investigations, and proceedings and litigation matters, could have an adverse effect on our business, results of operations and financial condition. +15 +We have incurred, and may continue to incur, significant expenses related to legal, accounting and other professional services in connection with matters relating to or arising from the subject of the Audit Committee’s internal investigation in fiscal year 2022. To the extent these steps taken to remediate identified deficiencies in our internal controls over financial reporting were not successful, we may incur significant additional time and expense. +In addition, we continue to cooperate with the Securities and Exchange Commission (the “SEC”) regarding matters related to the internal investigation. The completion of the internal investigation in fiscal year 2022 did not automatically resolve the SEC’s inquiries. If the SEC or any other regulator were to commence legal action against us, we could be required to pay significant penalties and become subject to injunctions, cease and desist orders or other remedies. We can provide no assurances as to the outcome of any governmental inquiry or investigation. Further, we, our officers and members of our Board of Directors could be named as defendants in lawsuits asserting claims arising out of the subject matter of the Audit Committee’s internal investigation. As a result of any legal proceedings and any related indemnification requirements to our officers and directors, we could be required to pay monetary damages that may be in excess of our insurance coverage or may have additional penalties or other remedies imposed against us or our officers and directors. +All of these expenses, and the diversion of the attention of management and other personnel that has occurred and is expected to continue, could adversely affect our business, financial condition, results of operations and cash flows. +LEGAL AND ACCOUNTING RISKS +We have restated certain of our prior consolidated financial statements, which has resulted in unanticipated costs and may lead to additional risks and uncertainties, including loss of investor confidence, regulatory action or litigation. +In this Annual Report on Form 10-K, we have restated or revised certain of our previously issued financial statements. This process has been time-consuming and expensive, including unanticipated costs for accounting and legal fees. The restatement and revisions also expose us to additional risks that could adversely affect our business and financial condition, such as litigation, regulatory action or loss of investor confidence. Lawsuits or regulatory investigations may invoke federal and state securities law claims, contractual claims or other claims arising from the restatement, revisions and material weaknesses in our internal control over financial reporting. We may incur substantial defense costs regardless of the outcome of any litigation or regulatory investigation, and such events might cause a diversion of our management’s time and attention. If we do not prevail in any litigation or regulatory action, we could be required to pay substantial damages, penalties or settlement costs. In addition, the restatement and revisions may lead to a loss of investor confidence and have negative impacts on the trading price of our common stock. +We are involved in various legal proceedings. +In the past, we have been notified of claims relating to various matters including contractual matters, intellectual property rights or other issues arising in the ordinary course of business. In the event of such a claim, we may be required to spend a significant amount of money to defend or otherwise address the claim. Any litigation or dispute resolution, even where a claim is without merit, could result in substantial costs and diversion of resources. Accordingly, the resolution or adjudication of such disputes, even those encountered in the ordinary course of business, could have a material effect on our business, consolidated financial conditions and results of operations. +Changes in securities laws and regulations will increase our costs and risk of noncompliance. +We are subject to additional requirements contained in the U.S. federal securities laws, including the Sarbanes-Oxley Act and the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act). The Sarbanes-Oxley and Dodd-Frank Acts required or will require changes in some of our corporate governance, securities disclosure and compliance practices. The SEC and NASDAQ Global Market have promulgated new rules and additional rulemaking is expected in the future. Compliance with these new rules and future rules has increased and may increase further our legal, financial and accounting costs as well as a potential risk of noncompliance. Absent significant changes in related rules, which we cannot assure, we anticipate some level of increased costs related to these new regulations to continue indefinitely. We also expect these developments to make it more difficult and more expensive to obtain director and officer liability insurance, and we may be forced to accept reduced coverage or incur substantially higher costs to obtain coverage. Likewise, these developments may make it more difficult for us to attract and retain qualified members of our Board of Directors or qualified management personnel. Further, the costs associated with the compliance with and implementation of procedures under these and future laws and related rules could have a material impact on our results of operations. In addition, the costs associated with noncompliance with additional securities laws and regulations could also impact our business. +Changes in financial accounting standards may affect our reported financial condition or results of operations as well as increase costs related to implementation of new standards and modifications to internal controls. +Our consolidated financial statements are prepared in conformity with accounting standards generally accepted in the United States, or U.S. GAAP. These principles are subject to amendments made primarily by the Financial Accounting Standards Board (FASB) and the SEC. A change in those policies can have a significant effect on our reported results and may affect our +16 +reporting of transactions which are completed before a change is announced. Changes to accounting rules or challenges to our interpretation or application of the rules by regulators may have a material adverse effect on our reported financial results or on the way we conduct business. +GENERAL RISKS +Our levels of insurance coverage may not be sufficient for potential damages, claims or losses. +We have various forms of business and liability insurance which we believe are appropriate based on the needs of companies in our industry. As a result, not all of our potential business risks or potential losses would be covered by our insurance policies. If we sustain a significant claim or loss which is not covered by insurance, our net income could be negatively impacted. +We may encounter complications with acquisitions, which could potentially harm our business. +Any current or future acquisitions may require additional equity financing, which could be dilutive to our existing shareholders, or additional debt financing, which could potentially affect our credit ratings. Any downgrades in our credit ratings associated with an acquisition could adversely affect our ability to borrow by resulting in more restrictive borrowing terms. To integrate acquired businesses, we must implement our management information systems, operating systems and internal controls, and assimilate and manage the personnel of the acquired operations. The integration of acquired businesses may be further complicated by difficulties managing operations in geographically dispersed locations. The integration of acquired businesses may not be successful and could result in disruption by diverting management’s attention from the core business. In addition, the integration of acquired businesses may require that we incur significant restructuring charges or other increases in our expenses and working capital requirements, which reduce our return on invested capital. +Acquisitions may involve numerous other risks and challenges including but not limited to: potential loss of key employees and customers of the acquired companies; the potential for deficiencies in internal controls at acquired companies; lack of experience operating in the geographic market or industry sector of the acquired business; constraints on available liquidity, and exposure to unanticipated liabilities of acquired companies. These and other factors could harm our ability to achieve anticipated levels of profitability at acquired operations or realize other anticipated benefits of an acquisition, and could adversely affect our consolidated business and operating results. +Item 1B. UNRESOLVED STAFF COMMENTS +None +Item 1C. CYBERSECURITY +Risk Management and Strategy +We have developed and implemented cybersecurity processes to assess, identify and manage material risks from cybersecurity threats. These processes are based on the National Institute of Standards and Technology Cybersecurity Framework (NIST CSF) and are designed to protect the integrity and security of our information systems. Our cybersecurity processes are a part of our risk management system, sharing governance processes and reporting structures with other components of our enterprise-wide system. Our cybersecurity processes include security monitoring and threat hunting through a third-party managed vendor and mandatory, Company-wide employee training. Our cybersecurity processes also extend to the oversight and identification of risks associated with our vendors and customers if their computer systems interface with our information systems. Upon detection of a potentially material cybersecurity incident, such as the Previously Disclosed Cyber Incident, we activate our cyber incident procedure to investigate, contain and remediate the incident. Depending on the extent and severity of the incident, we have, and may in the future, engage third-party cybersecurity consultants to assist with our cyber incident procedure. +Risks from cybersecurity threats, including as a result of the Previously Disclosed Cyber Incident, have materially affected us, including our results of operations and financial condition. We continue to face risks from this and other cybersecurity threats that, if realized, are reasonably likely to materially affect us, including our business strategy, results of operations, or financial condition. See “Risk Factors – Technology Risks.” +Governance +Our Board of Directors is responsible for the oversight of risk management for the Company, including the review and assessment of the Company’s enterprise risk management approach and processes. Our Board of Directors has delegated certain responsibility for the oversight of risks from cybersecurity threats to the Audit Committee. At each regularly scheduled quarterly meeting, and more frequently as necessary, management provides updates to the Audit Committee and our Board of Directors regarding the risks from cybersecurity threats. These updates include information regarding cybersecurity strategies, management structure, mitigation activities and an analysis of any actual or potential cybersecurity incidents. +17 +Our management team, including our Chief Executive Officer and Executive Vice President of Quality and Information Systems, is responsible for assessing and managing our material risks from cybersecurity threats. In particular, our EVP of Quality and Information Systems, who reports directly to our Chief Executive Officer, oversees the implementation of controls designed to prevent, detect, mitigate and recover from cybersecurity threats and cybersecurity incidents. Our current EVP of Quality and Information Systems has a Bachelor of Science degree in Mechanical Engineering and over 14 years of experience building and executing information system strategies. The other members of our management team do not have specialized information systems or cybersecurity backgrounds but have general experience managing financial, legal and operational risks. Our EVP of Quality and Information Systems, along with his team, routinely monitors the Company’s information systems for cybersecurity threats and will be notified upon the occurrence of a potential cybersecurity incident. +Upon detection of a potentially material cybersecurity incident, such as the Previously Disclosed Cyber Incident, management will inform the Audit Committee and/or our Board of Directors and, if the incident is deemed material, will disclose the incident pursuant to SEC rules and regulations. +18 +Item 2. PROPERTIES AS OF DATE OF FILING +We have manufacturing and sales operations located in the United States, Mexico, China and Vietnam. The table below lists the locations and square footage of our operating facilities: +Location Approx. +Sq. Ft. Type of Interest +(Leased/Owned) Description of Use +Corinth, Mississippi 350,000 Leased Manufacturing and warehouse +El Paso, Texas 80,000 Leased Shipping and warehouse +Fayetteville, Arkansas 105,000 Leased Manufacturing and warehouse +Oakdale, Minnesota 103,000 Leased Manufacturing and warehouse +Spokane Valley, Washington 95,000 Leased Sales, research, administration and manufacturing +Spokane Valley, Washington 36,000 Leased Manufacturing +Total USA 769,000 +Juarez, Mexico 193,000 Leased Warehouse +Juarez, Mexico 174,000 Owned Manufacturing and warehouse +Juarez, Mexico 115,000 Owned Manufacturing and warehouse +Juarez, Mexico 103,000 Owned Manufacturing and warehouse +Juarez, Mexico 72,000 Leased Manufacturing and warehouse +Juarez, Mexico 66,000 Owned Manufacturing and warehouse +Juarez, Mexico 60,000 Owned Manufacturing and warehouse +Juarez, Mexico 116,000 Leased Manufacturing and warehouse +Total Mexico 899,000 +Shanghai, China 103,000 Leased Manufacturing and warehouse +Total China 103,000 +Da Nang, Vietnam 133,000 Leased Manufacturing and warehouse +Total Vietnam 133,000 +Grand Total 1,904,000 +The geographic diversity of these locations allows us to offer services near certain of our customers and major electronics markets with the additional benefit of reduced labor costs. We consider the productive capacity of our current facilities sufficient to carry on our current business. In addition, in Juarez, Mexico one of our buildings includes adjacent vacant land that could be developed into additional manufacturing and warehouse space. +All our facilities are ISO certified to ISO 9001:2015 standard and to Customs Trade Partnership against Terrorism (CTPAT). +• The Spokane, Washington facility is registered to IATF 16949 automotive standard, ISO 13485:2016 medical devices, ISO 14001:2015 environmental standard, and ISO 45001 Occupational Health and Safety Management System. +• The Juarez, Mexico facility is registered to IATF 16949 automotive standard, ISO 13485:2016 medical devices, ISO 14001:2015 environmental standard, ISO 45001 Occupational Health and Safety Management System, and has a certified ANSI/ESD S20.20 Electrostatic Discharge Program. +• The Da Nang, Vietnam facility is additionally registered to IATF 16949 automotive standard. +• The Shanghai, China facility is additionally registered to ISO 45001 Occupational Health and has a certified ANSI/ESD S20.20 Electrostatic Discharge Control Program. +• The Oakdale, Minnesota facility is additionally registered to ISO 13485:2016 medical devices standard, AS9100D aviation, space and defense standard, and has a certified ANSI/ESD S20.20 Electrostatic Discharge Control Program. +• The Fayetteville, Arkansas facility is additionally registered to AS9100D aviation, space and defense standard and has a certified ANSI/ESD S20.20 Electrostatic Discharge Control Program. +• The Corinth, Mississippi facility is additionally registered to ISO 14001:2015 and ISO/IEC 80079-34 explosive atmospheres. +19 +• The Oakdale, Minnesota; and Spokane, Washington facilities are registered with the U.S. State Department for International Traffic in Arms Regulations (ITAR). +Item 3. LEGAL PROCEEDINGS +We are a party to certain lawsuits or claims in the ordinary course of business. We do not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on our financial position, results of operations or cash flow, although an adverse resolution against the Company in a fiscal quarter or year could have a material adverse effect on the Company’s results of operations in a particular quarter or year. For further details on claims, see Note 8. Commitments and Contingencies in the Notes to Consolidated Financial Statements. +Item 4. MINE SAFETY DISCLOSURES +Not Applicable +PART II +Item 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED SHAREHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES +Market Information +Our common stock is traded on the NASDAQ Global Market under the symbol “KTCC.” Quarterly high and low sales prices for our common stock for fiscal year 2024 and fiscal year 2023 were as follows: +2024 2023 +High Low High Low +First Quarter $ 6.24 $ 4.32 $ 5.50 $ 4.00 +Second Quarter $ 4.50 $ 3.72 $ 5.18 $ 4.03 +Third Quarter $ 5.14 $ 4.04 $ 7.50 $ 4.33 +Fourth Quarter $ 4.85 $ 3.69 $ 7.53 $ 5.18 +High and low stock prices are based on the daily sales prices reported by the NASDAQ Stock Market. These quotations represent prices between dealers without adjustment for markups, markdowns, and commissions, and may not represent actual transactions. +Holders and Dividends +As of June 29, 2024, we had 561 shareholders of common stock on record. As a result of our credit agreements, we are restricted from declaring or paying dividends in cash or stock without Bank of America’s prior written consent. We have not paid a cash dividend and do not anticipate payment of dividends in the foreseeable future. +Performance Graph +We are a smaller reporting company as defined in Item 10(f)(1) of Regulation S-K and therefore are not required to provide the performance graph required in paragraph (e) of Item 201 of Regulation S-K. +20 +Item 6: [RESERVED] +Item 7: MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS +Restatement +This Management’s Discussion and Analysis of Financial Condition and Results of Operations gives effect to the restatement of the Company’s previously issued consolidated financial statements as of and for the years ended July 1, 2023 and July 2, 2022. The restatement was due to errors in recording cost recovery related to material price variances in certain of the Company’s facilities. These errors led to an understatement of both revenue and cost of goods sold during the impacted periods. For additional information, see Note 14 - "Restatement of Previously Issued Financial Statements" in the Notes to Consolidated Financial Statements of this Annual Report on Form 10-K. The Company’s previously issued unaudited interim consolidated statements of operations for the quarters ended March 30, 2024, December 30, 2023, September 30, 2023, April 1, 2023, December 31, 2022, October 1, 2022, April 2, 2022, January 1, 2022, and October 2, 2021 have also been restated due to these errors, and the Company's previously issued unaudited interim balance sheets as of March 30, 2024, December 30, 2023, September 30, 2023 have been revised due to errors related to the adoption of ASU 326. For additional information regarding these interim periods, see Note 15 – “Restatement and Revision of Interim Financial Information” of the Notes to Consolidated Financial Statements of this Annual Report on Form 10-K. +Overview +Key Tronic is a leading contract manufacturer offering value-added design and manufacturing services from its facilities in the United States, Mexico, China, and Vietnam. The Company provides its customers full engineering services, materials management, worldwide manufacturing facilities, assembly services, in-house testing, and worldwide distribution. Its customers include some of the world’s leading original equipment manufacturers. Our combined capabilities and vertical integration are proving to be a desirable offering to our expanded customer base. +Our domestic and international production capability provides our customers with benefits of improved supply-chain management, reduced inventories, lower transportation costs, and reduced product fulfillment time. We continue to make investments in all of our operating facilities to give us the production capacity, capabilities and logistical advantages to continue to win new business. The following information should be read in conjunction with the consolidated financial statements included herein and with Part II Item 1A, Risk Factors included as part of this filing. +Our mission is to provide our customers with superior manufacturing and engineering services at the lowest total cost for the highest quality products, and create long-term mutually beneficial business relationships by employing our “Trust, Commitment, Results” philosophy. +Executive Summary +During the fourth quarter of fiscal year 2024, we won new programs involving medical devices, sheet metal fabrication, and consumer products. +We reported net sales of $566.9 million for fiscal year 2024, down 6.3 percent from $605.3 million for fiscal year 2023. The decrease in fiscal year 2024 was driven by softer demand from Mexico-based programs, and production stoppages due to a cybersecurity incident that occurred in the fourth quarter, as previously reported. +Moving into fiscal year 2025, we expect revenue and earnings to rebound as production has resumed across our facilities. Additionally, the Company is beginning to realize operational efficiencies as a result of headcount reductions announced in the third quarter of fiscal year 2024, coupled with a favorable weakening of the Mexican Peso to the US dollar of approximately 10% beginning in June. We continue to win new programs and reduce inventories to be more aligned with current revenue levels. +For the first quarter of fiscal year 2025, we believe global logistics problems, China-US political tensions and continued supply-chain concerns will continue to drive the favorable trend of contract manufacturing returning to North America, as well as to our expanding Vietnam facilities. We continue to see improvement across the metrics associated with business development, including a significant increase in the number of active quotes with prospective customers. +We aim to diversify our customer base by adding additional programs and customers. Our current customer relationships involve a variety of products including sheet metal fabrication, medical devices and components, water purification products, consumer security products, aerospace and defense products, recreational and outdoor equipment, and plastics. +Gross profit as a percentage of net sales was 7.0 percent in fiscal year 2024, down from 7.8 percent in 2023. During fiscal year 2024, our gross margin was also adversely impacted by a cybersecurity incident late in the year, and continued increases in +21 +Mexican wages as well as the strengthening of the Mexican Peso relative to the US Dollar. Additionally, as previously disclosed, a restructuring of our Mexico-based facility to focus on higher volume manufacturing resulted in severance expenses incurred late in the year which we expect to provide benefits to the gross profit margin in future periods. The level of gross margin is impacted by product mix, timing of the startup of new programs, facility utilization, and pricing within the electronics industry and material costs, which can fluctuate significantly from quarter-to-quarter and year-to-year. +Operating income as a percentage of net sales for fiscal year 2024 was 1.2 percent compared to 2.7 percent for fiscal year 2023. In addition to the factors discussed above, we incurred expenses related to the cybersecurity incident late in the year, and our 2023 results included a significant gain on insurance related to losses incurred from storm damage to the Company's Arkansas facility in 2022. +Net loss for fiscal year 2024 was $2.8 million or $0.26 per share, as compared to net income of $5.2 million or $0.47 per share for fiscal year 2023. Earnings for fiscal 2024 continued to be adversely impacted by increased interest expense and were also impacted by the cybersecurity incident, and severance expenses. +We maintained a strong balance sheet with a current ratio of 2.8 and a debt-to-equity ratio of 0.96. Total cash provided by operating activities as defined on our cash flow statement was $13.8 million during fiscal year 2024, as we have continued to focus on decreasing accounts receivable and inventory balances. We believe we maintain sufficient liquidity for our expected future operations, dependent upon executing projected cash flows from operations and potentially adding additional credit capacities through refinancing current credit agreements or pursuing additional debt structures. +RESULTS OF OPERATIONS +Comparison of the Fiscal Year Ended June 29, 2024 with the Fiscal Year Ended July 1, 2023 +The following table sets forth for the periods indicated certain items of the consolidated statements of income expressed as a percentage of net sales. The financial information and discussion below should be read in conjunction with the consolidated financial statements and Footnotes contained in this Annual Report on Form 10-K. +Fiscal Year Ended +(in thousands) June 29, 2024 % of +net sales July 1, 2023 % of +net sales $ change % point +change +(Restated) +Net sales $ 566,942 100.0% $ 605,315 100.0% $ (38,373) — +Cost of sales 527,063 93.0 557,843 92.2 (30,780) 0.8 +Gross profit 39,879 7.0 47,472 7.8 (7,593) (0.8) +Operating expenses: +Research, development and engineering 8,333 1.5 9,735 1.6 (1,402) (0.1) +Selling, general and administrative 25,219 4.4 25,715 4.2 (496) 0.2 +Gain on insurance proceeds, net of losses (431) (0.1) (4,301) (0.7) 3,870 0.6 +Total operating expenses 33,121 5.8 31,149 5.1 1,972 0.7 +Operating income 6,758 1.2 16,323 2.7 (9,565) (1.5) +Interest expense, net 11,945 2.1 10,023 1.7 1,922 0.4 +Income (loss) before income taxes (5,187) (0.9) 6,300 1.0 (11,487) (1.9) +Income tax provision (benefit) (2,400) (0.4) 1,143 0.2 (3,543) (0.6) +Net income (loss) $ (2,787) (0.5)% $ 5,157 0.9% $ (7,944) (1.4) +Effective income tax rate 46.3 % 18.1 % +Net Sales +The decrease in net sales of $38.4 million from the prior fiscal year was primarily due to production stoppages due to the cybersecurity incident which caused the company to be unable to fulfill approximately $15 million of revenue during the fourth quarter of fiscal year 2024, as well as softer demand from Mexico-based programs. +22 +The following table shows the revenue by industry sectors as a percentage of revenue for fiscal years 2024 and 2023: +Fiscal Year Ended +June 29, 2024 July 1, 2023 +Industrial 46 42 +Consumer 45 44 +Communication 4 9 +Medical 3 1 +Gaming 1 1 +Transportation 1 3 +Total 100% 100% +We provide services to customers in a number of industries and produce a variety of products for our customers in each industry. Key Tronic does not target any particular industry, but rather seeks to find programs that strategically fit our vertical manufacturing capabilities. As a result, we expect to continue to see a change in the industry concentrations of our revenue over time. +Sales to foreign locations represented 22.5 percent and 14.3 percent of our total net sales in fiscal years 2024 and 2023, respectively. +Cost of Sales +Total cost of sales as a percentage of net sales was 93.0 percent in fiscal year 2024 and 92.2 percent in fiscal year 2023. +We record our inventories at net realizable value based on specific identification of inventory against current demand and recent usage. We also consider our customers' ability to pay for inventory whether or not there is a lead-time assurance agreement for a specific program. The amounts charged to expense for these inventories were approximately $0.3 million and $0.4 million in fiscal years 2024 and 2023, respectively. +We provide warranties on certain products we sell and estimate warranty costs based on historical experience and anticipated product returns. Warranty expense is related to workmanship claims. The amounts charged to expense are determined based on an estimate of warranty exposure. The net warranty expense was approximately $0.3 million and $0.3 million in fiscal years 2024 and 2023, respectively. +Gross Profit +Gross profit as a percentage of net sales was 7.0 percent in fiscal year 2024 and 7.8 percent in fiscal year 2023. During fiscal year 2024, we incurred expenses related to a cybersecurity incident late in the year of approximately $2.3 million. Additionally, we incurred severance expenses related to a headcount reduction in our Mexico based facilities, and starting in the fourth quarter of fiscal year 2024, we are beginning to realize the operational efficiencies as a result of these headcount reductions. +Changes in gross profit margins reflect the impact of a number of factors that can vary from period to period, including product mix, start-up costs and efficiencies associated with new programs, product life cycles, sales volumes, capacity utilization of our resources, management of inventories, component pricing and shortages, end market demand for customers’ products, fluctuations in and timing of customer orders, and competition within the contract manufacturing industry. These and other factors can cause variations in operating results. There can be no assurance that gross margins will not decrease in future periods. +Research, Development and Engineering +Research, development and engineering expenses (RD&E) consist principally of employee related costs, third-party development costs, program materials, depreciation, and allocated information technology and facilities costs. Total RD&E expenses were $8.3 million and $9.7 million in fiscal years 2024 and 2023, respectively. Total RD&E expenses as a percent of net sales was 1.5 percent in fiscal year 2024 and 1.6 percent in fiscal year 2023. +Selling, General and Administrative +Selling, general, and administrative expenses (SG&A) consist principally of salaries and benefits, advertising and marketing programs, sales commissions, travel expenses, provision for credit losses, facilities costs, and professional services. Total SG&A expenses were $25.2 million and $25.7 million in fiscal years 2024 and 2023, respectively. Total SG&A expenses as a percent of net sales were 4.4 percent and 4.2 percent in fiscal years 2024 and 2023, respectively. +23 +Interest Expense +We had net interest expense of $11.9 million and $10.0 million in fiscal years 2024 and 2023, respectively. The increase in interest expense is primarily related to increased interest rates due to the amended line of credit agreement, and an increase in the average balance outstanding throughout the year. +Income Tax Provision +We had an income tax benefit of approximately $2.4 million during fiscal year 2024 and an income tax expense of approximately $1.1 million during fiscal year 2023. The income tax benefit/expense recognized during both fiscal years 2024 and 2023 was primarily a function of U.S. and foreign taxes recognized at statutory rates, the net benefit associated with federal research and development tax credits, and the impact of foreign exchange gains in fiscal year 2023. +We continually review our requirements for liquidity domestically to fund current operations, revenue growth, and potential future acquisitions. We anticipate repatriating a portion of our unremitted foreign earnings. The estimated taxes associated with these expected repatriations are included in the income tax calculation. For further information on taxes, please review Footnote " Income Taxes” of the “Notes to Consolidated Financial Statements”. +Non-GAAP Financial Measures +To supplement our consolidated financial statements, which are prepared in accordance with generally accepted accounting principles in the United States (GAAP), we use certain non-GAAP financial measures, adjusted net income and adjusted net income per share, diluted. Beginning with the full year of fiscal year 2024, we provide these non-GAAP financial measures because we believe they provide greater transparency related to our core operations and represent supplemental information used by management in its financial and operational decision making. We exclude (or include) certain items in our non-GAAP financial measures as we believe the net result is a measure of our core business. We believe this facilitates operating performance comparisons from period to period by eliminating potential differences caused by the existence and timing of certain income and expense items that would not otherwise be apparent on a GAAP basis. Non-GAAP performance measures should be considered in addition to, and not as a substitute for, results prepared in accordance with GAAP. The non-GAAP financial measures disclosed below should be read in conjunction with the remainder of this Annual Report on Form 10-K, including the consolidated financial statements and footnotes thereto. Our non-GAAP financial measures may be different from those reported by other companies. See the table below for reconciliations of adjusted net income to the most directly comparable GAAP measure, which are GAAP net income and the computation of adjusted net income per share, diluted. +Twelve Months Ended +(in thousands, except per share amounts) June 29, 2024 July 1, 2023 +GAAP net income (loss) $ (2,787) $ 5,157 +Cybersecurity expenses 2,340 — +Severance expenses (benefit) 945 354 +Gain on insurance proceeds (net of losses) (431) (4,301) +Stock-based compensation expense (444) 254 +Income tax effect of non-GAAP adjustments (1) (482) 739 +Adjusted net income (loss): $ (859) $ 2,203 +Adjusted net income (loss) per share — non-GAAP Diluted $ (0.08) $ 0.20 +Weighted average shares outstanding — Diluted 10,762 10,938 +(1) Income tax effects are calculated using an effective tax rate of 20%, which approximates the statutory tax rates for the presented periods. +24 +International Subsidiaries +We offer customers a complete global manufacturing solution. Our facilities provide our customers the opportunity to have their products manufactured in the facility that best serves specific cost, product manufacturing, and distribution needs. The locations of our active foreign subsidiaries are as follows: +• Key Tronic Juarez, SA de CV owns five facilities and leases three facilities in Juarez, Mexico. These facilities include an SMT facility, an assembly and molding facility, a sheet metal fabrication facility, and assembly and warehouse facilities. This subsidiary primarily supports our U.S. operations. +• Key Tronic Computer Peripherals (Shanghai) Co., Ltd. leases one facility with SMT, assembly, global purchasing, and warehouse capabilities in Shanghai, China, which began operations in 1999. Its primary function is to provide contract manufacturing services. +• Key Tronic Vietnam leases one facility in Da Nang, Vietnam. This facility includes SMT, assembly, and warehouse capabilities. Its primary function is to provide contract manufacturing services for export. +Foreign sales (based on shipping instructions) from our worldwide operations, including domestic exports, were $127.6 million and $86.5 million in fiscal years 2024 and 2023, respectively. Products and manufacturing services provided by our subsidiary operations are often shipped to customers directly by the parent company. +RESULTS OF OPERATIONS +Comparison of the Fiscal Year Ended July 1, 2023 with the Fiscal Year Ended July 2, 2022 +The following table sets forth for the periods indicated certain items of the consolidated statements of income expressed as a percentage of net sales. The financial information and discussion below should be read in conjunction with the consolidated financial statements and Footnotes contained in this Annual Report on Form 10-K. +Fiscal Year Ended +(in thousands) July 1, 2023 % of +net sales July 2, 2022 % of +net sales $ change % point +change +(Restated) (Restated) +Net sales $ 605,315 100.0% $ 544,177 100.0% $ 61,138 — +Cost of sales 557,843 92.2 500,963 92.1 56,880 0.1 +Gross profit 47,472 7.8 43,214 7.9 4,258 (0.1) +Operating expenses: +Research, development and engineering 9,735 1.6 9,821 1.8 (86) (0.2) +Selling, general and administrative 25,715 4.2 24,598 4.5 1,117 (0.3) +Gain on insurance proceeds, net of losses (4,301) (0.7) — — (4,301) (0.7) +Total operating expenses 31,149 5.1 34,419 6.3 (3,270) (1.2) +Operating income 16,323 2.7 8,795 1.6 7,528 1.1 +Interest expense, net 10,023 1.7 5,104 0.9 4,919 0.8 +Income before income taxes 6,300 1.0 3,691 0.7 2,609 0.3 +Income tax provision 1,143 0.2 314 0.1 829 0.1 +Net income $ 5,157 0.8% $ 3,377 0.6% $ 1,780 0.2 +Effective income tax rate 18.1 % 8.5 % +25 +Net Sales +The increase in net sales of $61.1 million from the prior fiscal year was primarily due to the successful ramp of new customer programs and increased demand from existing customers. However, the Company's revenue was constrained by tightening worldwide supply chain and transportation and logistics issues, which delayed the arrival of certain key components, causing factory downtime and overtime expenses. +The following table shows the revenue by industry sectors as a percentage of revenue for fiscal years 2023 and 2022: +Fiscal Year Ended +July 1, 2023 July 2, 2022 +Consumer 44 50 +Industrial 42 42 +Communication 9 8 +Medical 3 — +Gaming 1 1 +Transportation 1 — +Printers — 1 +Computer and Peripheral — 1 +Total 56% 53% +We provide services to customers in a number of industries and produce a variety of products for our customers in each industry. Key Tronic does not target any particular industry, but rather seeks to find programs that strategically fit our vertical manufacturing capabilities. As we continue to diversify our customer base and win new customers, we expect to continue to see a change in the industry concentrations of our revenue. +Sales to foreign locations represented 14.3 percent and 17.2 percent of our total net sales in fiscal years 2023 and 2022, respectively. +Cost of Sales +Total cost of sales as a percentage of net sales was 92.2 percent in fiscal year 2023 and 92.1 percent in fiscal year 2022. +We record our inventories at net realizable value based on specific identification of inventory against current demand and recent usage. We also consider our customers' ability to pay for inventory whether or not there is a lead-time assurance agreement for a specific program. The amounts charged to expense for these inventories were approximately $427,000 and $950,000 in fiscal years 2023 and 2022, respectively. +We provide warranties on certain products we sell and estimate warranty costs based on historical experience and anticipated product returns. Warranty expense is related to workmanship claims. The amounts charged to expense are determined based on an estimate of warranty exposure. The net warranty expense was approximately $313,000 and $446,000 in fiscal years 2023 and 2022, respectively. +Gross Profit +Gross profit as a percentage of net sales was 7.8 percent in fiscal year 2023 and 7.9 percent in fiscal year 2022. During fiscal year 2023, the gross margins benefited by increased revenue levels along with some stabilization in the labor market. However, our gross margin was also adversely impacted by the strengthening of the Mexican Peso relative to the US Dollar. +Changes in gross profit margins reflect the impact of a number of factors that can vary from period to period, including product mix, start-up costs and efficiencies associated with new programs, product life cycles, sales volumes, capacity utilization of our resources, management of inventories, component pricing and shortages, end market demand for customers’ products, fluctuations in and timing of customer orders, and competition within the contract manufacturing industry. These and other factors can cause variations in operating results. There can be no assurance that gross margins will not decrease in future periods. +Research, Development and Engineering +Research, development and engineering expenses (RD&E) consist principally of employee related costs, third-party development costs, program materials, depreciation, and allocated information technology and facilities costs. Total RD&E expenses were $9.7 million and $9.8 million in fiscal years 2023 and 2022, respectively. Total RD&E expenses as a percent of net sales was 1.6 percent in fiscal year 2023 and 1.8 percent in fiscal year 2022. +26 +Selling, General and Administrative +Selling, general, and administrative expenses (SG&A) consist principally of salaries and benefits, advertising and marketing programs, sales commissions, travel expenses, provision for doubtful accounts, facilities costs, and professional services. Total SG&A expenses were $25.7 million and $24.6 million in fiscal years 2023 and 2022, respectively. Total SG&A expenses as a percent of net sales were 4.2 percent and 4.5 percent in fiscal years 2023 and 2022, respectively. This 0.3 percentage point decrease in SG&A as a percentage of net sales is primarily related to an increase in legal expenses related specifically to the SEC’s review of the whistleblower complaint in fiscal year 2021. +Interest Expense +We had net interest expense of $10.0 million and $5.1 million in fiscal years 2023 and 2022, respectively. The increase in interest expense is primarily related to increased interest rates, an increase in the average balance outstanding on our line of credit, and financing leases. +Income Tax Provision +We had an income tax expense of approximately $1.1 million during fiscal year 2023 and an income tax expense of approximately $0.3 million during fiscal year 2022. The income tax expense recognized during both fiscal years 2023 and 2022 was primarily a function of U.S. and foreign taxes recognized at statutory rates, the net benefit associated with federal research and development tax credits, the impact of foreign exchange gains in fiscal year 2023, and the net benefit of carrying back the fiscal year 2021 net operating tax losses to years with higher federal tax rates in fiscal year 2022. +We continually review our requirements for liquidity domestically to fund current operations, revenue growth, and to look for potential future acquisitions. We anticipate repatriating a portion of our unremitted foreign earnings. The estimated taxes associated with these expected repatriations are included in the income tax calculation. For further information on taxes, please review Footnote "Income Taxes” of the “Notes to Consolidated Financial Statements”. +International Subsidiaries +We offer customers a complete global manufacturing solution. Our facilities provide our customers the opportunity to have their products manufactured in the facility that best serves specific cost, product manufacturing, and distribution needs. The locations of our active foreign subsidiaries are as follows: +• Key Tronic Juarez, SA de CV owns five facilities and leases three facilities in Juarez, Mexico. These facilities include an SMT facility, an assembly and molding facility, a sheet metal fabrication facility, and assembly and warehouse facilities. This subsidiary primarily supports our U.S. operations. +• Key Tronic Computer Peripherals (Shanghai) Co., Ltd. leases one facility with SMT, assembly, global purchasing, and warehouse capabilities in Shanghai, China, which began operations in 1999. Its primary function is to provide contract manufacturing services. +• Key Tronic Vietnam leases one facility in Da Nang, Vietnam. This facility includes SMT, assembly, and warehouse capabilities. Its primary function is to provide contract manufacturing services for export. +Foreign sales (based on shipping instructions) from our worldwide operations, including domestic exports, were $86.5 million and $93.8 million in fiscal years 2023 and 2022, respectively. Products and manufacturing services provided by our subsidiary operations are often shipped to customers directly by the parent company. +Capital Resources and Liquidity +Operating Cash Flow +Net cash provided by operating activities for fiscal year 2024 was $13.8 million compared to net cash used in operating activities of $11.3 million in fiscal year 2023. The additional cash provided in fiscal year 2024 was due to a focus on collecting accounts receivable and working down inventory balances to be in line with current revenue levels. +The $13.8 million of net cash provided by operating activities during fiscal year 2024 is primarily related to $2.8 million of net loss adjusted for $11.0 million of depreciation and amortization, $15.8 million decrease in accounts receivable, a $32.5 million decrease in inventory, an $8.7 million decrease in contract assets partially offset by a $36.5 million decrease in accounts payable, a $2.9 million decrease in accrued compensation and vacation, $0.6 million increase in other assets and a $8.1 million decrease in other liabilities. +The $11.3 million of net cash used in operating activities during fiscal year 2023 was primarily related to $5.2 million of net income adjusted for $9.5 million of depreciation and amortization, $14.8 million increase in accounts receivable, a $16.0 +27 +million decrease in other liabilities, a $5.5 million decrease in accounts payable, a $8.0 million increase in contract assets partially offset by a $17.4 million decrease in inventory, and a $1.5 million increase in accrued compensation and vacation. +Accounts receivable fluctuates based on the timing of shipments, terms offered, and collections. We purchase inventory based on customer forecasts and orders. When those forecasts and orders change, the amount of inventory may also fluctuate. Accounts payable fluctuates with changes in inventory levels, volume of inventory purchases, negotiated supplier terms, and taking advantage of early pay discounts. +Investing Cash Flow +Cash flows used in investing activities were $2.1 million for fiscal year 2024. Cash flows used in investing activities were $4.5 million in fiscal year 2023. Our primary use of cash in investing activities during fiscal years 2024 and 2023 was purchasing equipment to support increased production levels for new programs. During fiscal year 2024, the source of cash provided by investing activities came from insurance claims paid for replacing equipment and facility repairs in our Arkansas facility related to a lightning strike and water damage. +Leases are often utilized when potential technical obsolescence and funding requirement advantages outweigh the benefits of equipment ownership. Capital expenditures and periodic lease payments are expected to be financed with internally generated funds as well as our revolving line of credit facility and equipment term loan . +Financing Cash Flow +Cash flows used in financing activities were $10.5 million in fiscal year 2024 and cash flows provided by financing activities were $17.7 million in fiscal year 2023. Our primary financing activities during both fiscal year 2024 and fiscal year 2023 were borrowings and repayments under our revolving line of credit facility as well as repayments on our term loans and principal payments on finance leases. In fiscal year 2024, there was a significantly higher percentage of repayments against the borrowings on the revolving line of credit. +As of June 29, 2024, approximately $12.9 million was available under the asset-based revolving credit facility. Due to corrections made to our financial statements as part of the restatement process described in this Annual Report, we determined that as of June 29, 2024 and July 27, 2024, we were not in compliance with the minimum fixed charge coverage ratio of 1.00:1.00 and 1.05:1:00, respectively, required under our Loan Agreement for the revolving credit facility. As a result, we obtained a waiver from the lender for these events of default, which was effective as of October 9, 2024, and amended our Loan Agreement. As previously disclosed, we also had to obtain a waiver for breaches of the fixed charge coverage ratio for fiscal quarter ended March 30, 2024 and amend the Loan Agreement to covenant relief for the fixed charge coverage ratio, reducing the minimum requirement from 1.25:1.00 to 1.00:1.00 as of March 30, 2024, with increases as follows: 1.05:1.00 on July 27, 2024, 1.15:1.00 on October 26, 2024, 1.20:1.00 on January 25, 2025 and 1.25:1.00 on and after March 29, 2025. These breaches and subsequent amendments have resulted in an increase in interest rates, an increase in the availability block, which limits available borrowing under the Loan Agreement, and a shortened maturity date to September 3, 2025 (extended to December 3, 2025). We believe we are in compliance with the minimum fixed charge coverage ratio of 1.05:1.00 as of the end of August 2024 and have not yet finalized our calculation for September of 2024 to determine if we are in compliance with the minimum fixed charge coverage ratio of 1.05:1.00. In addition, we may not be able to comply with the increased minimum fixed charge coverage ratio of 1.15:1:00 as of October 26, 2024 or in future periods. If we are unable to comply with restrictive covenants on the Loan Agreement, including the fixed charge coverage ratio, we will need to negotiate additional waivers and amendments, which may further increase interest rates, limit our borrowing availability, shorten the maturity date or impose other adverse consequences. As a result, and due to the upcoming maturity of the Loan Agreement on December 3, 2025, we are in discussions with financial institutions to refinance our revolving line of credit. The terms available to us may be less favorable than the terms of our existing Loan Agreement. For additional information, see Note 1 - “Significant Accounting Policies-Liquidity” of the Notes to Consolidated Financial Statements of this Annual Report on Form 10-K and Part I, Item 1A. Risk Factors “Risks Related to Capital and Financing “⸻Our failure to comply with the covenants in our credit arrangements could materially and adversely affect our financial condition” and “⸻Our ability to secure and maintain sufficient credit arrangements is key to our continued operations.” +Our cash requirements are affected by the level of current operations and new programs. We believe that projected cash from operations, funds available under the revolving credit facility and potential additional debt capacity will be sufficient to meet our working and fixed capital requirements for at least twelve months beyond issuance of our financial statements, and our current asset-based senior secured revolving credit facility does not mature until December 3, 2025. The Company further notes projected cash from operations is projected to improve in the coming quarters as supply chain availability will boost additional inventory turns and existing inventory is consumed by fulfilling customer backlog. As of June 29, 2024, we had approximately $4.7 million of cash held by foreign subsidiaries. If cash is to be repatriated in the future from these foreign subsidiaries, the Company would be subject to certain withholding taxes in the foreign jurisdictions. The total amount of tax payments required for the amount of foreign subsidiary cash on hand as of June 29, 2024 would approximate $15,893. +28 +The Company also has approximately $38.5 million of foreign earnings that have not been repatriated to the U.S. of that amount, the Company estimates that $8.0 million is to be repatriated in the future, requiring foreign withholding taxes of $0.8 million that is currently accrued in our deferred tax liabilities. The remaining $30.5 million is considered to be permanently reinvested in Mexico, China and Vietnam. If these amounts were required to be repatriated, we estimate it would create an additional $0.8 million in foreign withholding taxes payable. +We have accrued withholding taxes for expected future repatriation of foreign earnings as discussed in Note 5 “Income Taxes” of the “Notes to Consolidated Financial Statements”. +Off-Balance Sheet Arrangements and Contractual Obligations +In the normal course of business, we enter into contracts which obligate us to make payments in the future. We have certain contractual obligations that extend beyond fiscal year 2024 under lease obligations and debt arrangements. +As of June 29, 2024, we had open purchase order commitments for materials and other supplies. Actual needs under these blanket purchase orders fluctuate with our manufacturing levels and as such cannot be broken out between fiscal years. In addition, we have contracts with many of our customers that minimize our exposure to losses for material purchased within lead-times necessary to meet customer forecasts. Purchase orders generally can be cancelled without penalty within specified ranges that are determined in negotiations with our suppliers. These agreements depend in part on the type of materials purchased as well as the circumstances surrounding any requested cancellations. We do not use off-balance sheet financing techniques other than traditional operating leases, and we have not guaranteed the obligations of any entity that is not one of our wholly owned subsidiaries. +For a summary of our lease obligations as of June 29, 2024, please refer to Note 13 “Leases” of the “Notes to Consolidated Financial Statements”. +For a summary of our long-term debt obligations as of June 29, 2024, please refer to Note 4 “Long-Term Debt” of the “Notes to Consolidated Financial Statements”. +Critical Accounting Policies and Estimates +Preparation of our consolidated financial statements requires management to make estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses. Note 1 “Significant Accounting Policies” of the “Notes to Consolidated Financial Statements” describes the significant accounting policies used in the preparation of our consolidated financial statements. Management believes the most complex and sensitive judgments, because of their significance to our consolidated financial statements, result primarily from the need to make estimates about effects of matters that are inherently uncertain. The most significant areas involving management judgments are described below. Actual results in these areas could differ from management’s estimates. +Revenue +The Company specializes in services ranging from product manufacturing to engineering and tooling services. The first step in its process for revenue recognition is to identify the contract with a customer. A contract is defined as an agreement between two or more parties that creates enforceable rights and obligations. A contract can be written, oral, or implied. The Company generally enters into manufacturing service agreements (“MSA”) with its customers that outlines the terms of the business relationship between the customer and the Company. This includes matters such as warranty, indemnification, transfer of title and risk of loss, liability for excess and obsolete inventory, pricing, payment terms, etc. The Company will also bid on a program-by-program basis for customers in which an executed MSA may not be in place. In these instances, as well as when we have an MSA in place, we receive customer purchase orders for specific quantities and timing of products. As a result, the Company considers its contract with a customer to be the combination of the MSA and the purchase order. The transaction price is fixed and set forth in each purchase order. In the Company's normal course of business, there are no variable pricing components, or material amounts refunded to customers in the form of refunds or rebates. +The Company assesses whether control of the product or services promised under the contract is transferred to the customer at a point in time (shipment) or over time (as we manufacture the product). The Company is first required to evaluate whether its contracts meet the criteria for 'over-time' or 'point-in-time' recognition. The Company has determined that for the majority of its contracts the Company is manufacturing products for which there is no alternative use due to the unique nature of the customer-specific product, IP and other contract restrictions. Further, the Company has an enforceable right to payment including a reasonable profit for performance completed to date with respect to these contracts. As a result, revenue is recognized under these contracts 'over-time' based on the input cost-to-cost method as it better depicts the transfer of control. This input method is based on the ratio of costs incurred to date as compared to the total estimated costs at completion of the performance obligation. For all other contracts that do not meet these criteria, such as manufacturing contracts for which the terms do not provide an enforceable right to payment for performance completed to date, the Company recognizes revenue when it has transferred control of the related manufactured products which generally occurs upon shipment to the customer. Revenue from engineering +29 +services is recognized over time as costs related to the services are incurred, which approximates proportional performance of the service. This method is used because management considers it to be the best available measure of progress on the contracts. Revenue from scrap and excess inventory sales is recognized at the point-in-time of scrap at the customers direction, or, if applicable, shipment of the material to the customer. +Inactive, Obsolete, and Surplus Inventory Valuation +Inventories are stated at the lower of cost or net realizable value. Inventory valuation is determined using the first-in, first-out (FIFO) method. We write down inventories that we deem inactive, obsolete, or surplus to net realizable value. The write down is calculated based upon the demand for the products that we produce to value this related inventory at net realizable value. Demand is determined by expected sales, customer purchase orders, or customer forecasts. If expected sales do not materialize, excess inventory would be the result and a write down of that inventory against earnings would occur. In the case where we have purchased material based upon a customer’s forecast or purchase orders, we are usually covered by lead-time assurance agreements or purchase orders with each customer. These contracts state that the financial liability for material purchased within agreed upon lead-time and based upon the customer’s forecasts, lies with the customer. If we purchase material outside the lead-time assurance agreement and the customer’s forecasts do not materialize or if we have no lead-time assurance agreement for a specific program, we would have the financial liability and may have to charge inactive, obsolete or surplus inventory against earnings. We also write down inventory values related to specific customers covered by lead-time assurance agreements when those customers are experiencing financial difficulties or reimbursement is not reasonably assured. +Allowance for Credit Losses +We value our accounts receivable net of an allowance for credit losses. As of June 29, 2024, the allowance for credit losses was approximately $2.9 million. As of July 1, 2023, the allowance for credit losses was approximately $23,000. The increase during fiscal year 2024 relates to the adoption of ASC 326, which was adopted on a modified retrospective basis. This allowance is based on estimates of the portion of accounts receivable that may not be collected in the future. The estimates used are based on specific identification of potentially uncollectible accounts as well as a general calculation based on the company's collection history. Such accounts are identified using publicly available information in conjunction with evaluations of current payment activity. However, if any of our customers were to develop unexpected and immediate financial problems that would prevent payment of open invoices, we could incur additional and possibly material expenses that would negatively impact earnings. +Income Taxes +Income tax expense includes U.S. and international income taxes and a provisional estimate for U.S. taxes on undistributed earnings of foreign subsidiaries. We do not record foreign withholding taxes on undistributed earnings of international subsidiaries that are deemed to be permanently reinvested. Certain income and expenses are not reported in tax returns and financial statements in the same year. The tax effect of such temporary differences is reported as deferred income taxes. The deferred income taxes are classified as long-term assets or liabilities. The most significant areas involving management judgments include deferred income tax assets and liabilities, uncertain tax positions, and research and development tax credits. Our estimates of the realization of the deferred tax assets related to our tax credits are based upon our estimates of future taxable income which may change. +New and Future Accounting Pronouncements +See Note 1 “Significant Accounting Policies” of the “Notes to Consolidated Financial Statements.” +30 +Item 7A: QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Interest Rate Risk +We are subject to the risk of fluctuating interest rates in the normal course of business. Our major market risk relates to our secured debt. Our asset-based senior secured revolving credit facility, line of credit facility, and equipment financing facility are secured by substantially all of our assets. The interest rates applicable to our asset-based senior secured revolving credit facility fluctuate with SOFR rates. The interest rates applicable to our asset-based secured line of credit facility fluctuate with Iterbancaria de Equilibrio Interest Rate. There was outstanding $107.1 million in borrowings under our asset-based senior secured revolving credit facility, MXN99 million ($5.4 million USD) outstanding in borrowing under our line of credit, and $8.0 million outstanding on our equipment financing facilities as of June 29, 2024. +See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Resources and Liquidity” in this Annual Report on Form 10-K and Note 4 “Long-Term Debt” of the “Notes to Consolidated Financial Statements” for additional information regarding our revolving credit facility and term loans. +Foreign Currency Exchange Risk +A significant portion of our operations are in foreign locations. As a result, transactions occur in currencies other than the U.S. dollar. Exchange rate fluctuations among other currencies used by us would directly or indirectly affect our financial results. From time to time, we use Mexican Peso forward contracts to hedge foreign currency fluctuations for a portion of our Mexican Peso denominated expenses. There was $12.5 million of foreign currency forward contracts outstanding as of June 29, 2024. See Note 9 - “Derivative Financial Instruments” to the Notes to Consolidated Financial Statements for additional information regarding our derivative instruments. +31 +Item 8: +FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA +Report of Independent Registered Public Accounting Firm +To the Shareholders and the Board of Directors of +Key Tronic Corporation +Opinion on the Financial Statements +We have audited the accompanying consolidated balance sheets of Key Tronic Corporation (the “Company”) as of June 29, 2024, July 1, 2023, and July 2, 2022, the related consolidated statements of operations, comprehensive income (loss), cash flows, and shareholders’ equity for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of June 29, 2024, July 1, 2023, and July 2, 2022, and the consolidated results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America. +Restatement of Previously Issued Financial Statements +As discussed in Note 14 to the consolidated financial statements, the consolidated financial statements for the years ended July 1, 2023 and July 2, 2022, have been restated to correct misstatements. +Basis for Opinion +These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. +Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion. +Critical Audit Matter +The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. +As described in Notes 1 and 12 to the consolidated financial statements, the Company reported revenue of $567 million for the year ended June 29, 2024, of which $497 million related to revenue recognized over time. The Company has determined that for the majority of its contracts, the Company is manufacturing products for which there is no alternative use due to the unique nature of the customer-specific product, intellectual property, and other contract restrictions. The Company has an enforceable right to payment including a reasonable profit for performance completed to date with respect to these contracts. As a result, revenue is recognized under these contracts over-time based on the input cost-to-cost method as it better depicts the transfer of +32 +control. This input method is based on the ratio of costs incurred to date as compared to the total estimated costs at completion of the performance obligation. +We identified the auditing of revenue recognized over time on contracts for manufacturing products, including the total estimated costs at completion of the performance obligation as a critical audit matter. Auditing management’s estimates used in the calculation of revenue recognized over time involved significant audit effort, as well as especially challenging and subjective auditor judgment when performing audit procedures and evaluating the results of those procedures. +Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. Our audit procedures related to auditing revenue recognized over time on contracts for manufacturing products, including the total estimated costs at completion of the performance obligation, included the following, among others: +• Evaluating the methodology of estimating costs incurred to date on in-process contracts, testing the completeness and accuracy of the system generated reports used to estimate costs incurred, and performing data validation procedures. +• Recalculating the expected costs on in-process contracts, testing a selection of contracts to source documents, and tracing in-process orders to subsequent sales and shipping documentation within a reasonable period after year-end. +• Identifying and testing significant assumptions used in the revenue calculation, including the ratio of costs incurred to date as compared to the total estimated costs at completion of the performance obligations. +• Comparing margins realized to trending historic margins, and comparing total revenue recognized to independent expectations of total revenues disaggregated by revenue stream. +• Performing cutoff procedures to test that revenue transactions were recorded in the appropriate period. +/s/ Moss Adams LLP +Seattle, Washington +October 15, 2024 +We have served as the Company’s auditor since 2021. +33 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED BALANCE SHEETS +(In thousands) +June 29, 2024 July 1, 2023 July 2, 2022 +ASSETS +Current assets: +Cash and cash equivalents $ 4,752 $ 3,603 $ 1,707 +Trade receivables, net of credit losses of $ 2,918 , $ 23 and $ 12 +132,559 150,600 135,876 +Contract assets 21,250 29,925 21,974 +Inventories 105,099 137,911 155,741 +Other, net of credit losses of $ 1,679 , $ 0 , and $ 0 +24,739 27,510 24,710 +Total current assets 288,399 349,549 340,008 +Property, plant and equipment, net 28,806 28,870 26,012 +Operating lease right-of-use assets, net 15,416 16,202 16,731 +Other assets: +Deferred income tax asset 17,376 12,254 10,055 +Other 5,346 11,397 14,117 +Total other assets 22,722 23,651 24,172 +Total assets $ 355,343 $ 418,272 $ 406,923 +LIABILITIES AND SHAREHOLDERS ’ EQUITY +Current liabilities: +Accounts payable $ 79,394 $ 115,899 121,393 +Accrued compensation and vacation 6,510 13,351 11,836 +Current portion of long-term debt 3,123 3,138 2,190 +Other 15,149 19,578 28,248 +Total current liabilities 104,176 151,966 163,667 +Long-term liabilities: +Long-term debt, net 116,383 121,531 100,293 +Operating lease liabilities 10,312 10,317 12,023 +Deferred income tax liability 263 274 64 +Other long-term obligations 219 3,567 5,998 +Total long-term liabilities 127,177 135,689 118,378 +Total liabilities 231,353 287,655 282,045 +Commitments and contingencies (Note 9) +Shareholders’ equity: +Common stock, no par value—shares authorized 25,000 ; issued and outstanding 10,762 , 10,762 , and 10,762 shares, respectively +47,284 47,728 47,474 +Retained earnings 76,921 82,986 77,829 +Accumulated other comprehensive (loss) income ( 215 ) ( 97 ) ( 425 ) +Total shareholders’ equity 123,990 130,617 124,878 +Total liabilities and shareholders’ equity $ 355,343 $ 418,272 $ 406,923 +See accompanying notes to consolidated financial statements. +34 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share amounts) +Fiscal Year Ended +Restated Restated +June 29, 2024 July 1, 2023 July 2, 2022 +Net sales $ 566,942 $ 605,315 $ 544,177 +Cost of sales 527,063 557,843 500,963 +Gross profit 39,879 47,472 43,214 +Research, development and engineering expenses 8,333 9,735 9,821 +Selling, general and administrative expenses 25,219 25,715 24,598 +Gain on insurance proceeds, net of losses ( 431 ) ( 4,301 ) — +Total operating expenses 33,121 31,149 34,419 +Operating income 6,758 16,323 8,795 +Interest expense, net 11,945 10,023 5,104 +Income (loss) before income taxes ( 5,187 ) 6,300 3,691 +Income tax provision (benefit) ( 2,400 ) 1,143 314 +Net income (loss) $ ( 2,787 ) $ 5,157 $ 3,377 +Net income (loss) per share — Basic $ ( 0.26 ) $ 0.48 $ 0.31 +Weighted average shares outstanding — Basic 10,762 10,762 10,762 +Net income (loss) per share — Diluted $ ( 0.26 ) $ 0.47 $ 0.31 +Weighted average shares outstanding — Diluted 10,762 10,938 11,063 +See accompanying notes to consolidated financial statements. +35 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) +(In thousands) +Fiscal Year Ended +June 29, 2024 July 1, 2023 July 2, 2022 +Comprehensive income: +Net income (loss) $ ( 2,787 ) $ 5,157 $ 3,377 +Other comprehensive income: +Unrealized gain (loss) on hedging instruments, net of tax ( 118 ) 328 ( 2,497 ) +Comprehensive income (loss) $ ( 2,905 ) $ 5,485 $ 880 +Other comprehensive income for fiscal years 2024, 2023, and 2022 is reflected net of tax provision (benefit) of approximately $( 0.1 ) million, $ 0.0 million , and $( 0.8 ) million, respectively. +See accompanying notes to consolidated financial statements. +36 +KEY TRONIC CORPORATION AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In thousands) +Fiscal Year Ended +June 29, 2024 July 1, 2023 July 2, 2022 +Operating activities: +Net income (loss) $ ( 2,787 ) $ 5,157 $ 3,377 +Adjustments to reconcile net income (loss) to cash provided by (used in) operating activities: +Depreciation and amortization 11,038 9,542 7,562 +Amortization of interest rate swap 97 328 301 +Amortization of deferred loan costs 339 154 143 +Noncash lease expense 5,663 5,712 4,261 +Inventory write-down to net realizable value 322 427 950 +Provision for warranty 320 313 446 +Provision for credit losses ( 84 ) 37 67 +Gain on disposal of assets ( 32 ) ( 21 ) ( 12 ) +Gain on insurance proceeds, net of losses ( 431 ) ( 4,301 ) — +Share-based compensation expense ( 444 ) 254 293 +Deferred income taxes ( 5,132 ) ( 1,989 ) 481 +Noncash accrued compensation benefit ( 3,925 ) — — +Changes in operating assets and liabilities +Trade receivables 15,818 ( 14,760 ) ( 25,619 ) +Contract assets 8,656 ( 7,951 ) 2,807 +Inventories 32,490 17,403 ( 19,362 ) +Other assets ( 587 ) ( 1,684 ) ( 5,912 ) +Accounts payable ( 36,505 ) ( 5,494 ) 28,569 +Accrued compensation and vacation ( 2,917 ) 1,515 365 +Other liabilities ( 8,123 ) ( 15,953 ) ( 3,624 ) +Cash provided by (used in) operating activities 13,776 ( 11,311 ) ( 4,907 ) +Investing activities: +Purchases of property and equipment ( 3,958 ) ( 9,771 ) ( 6,813 ) +Proceeds from sale of fixed assets — 1,925 14 +Prepayments on finance lease obligations — ( 188 ) ( 1,252 ) +Proceeds from insurance 1,850 3,500 — +Cash used in investing activities ( 2,108 ) ( 4,534 ) ( 8,051 ) +Financing activities: +Payment of financing costs ( 807 ) ( 245 ) ( 118 ) +Proceeds from issuance of long term debt 1,178 4,375 11,594 +Repayments of long-term debt ( 2,977 ) ( 2,417 ) ( 2,143 ) +Borrowings under revolving credit agreement 521,088 596,121 581,893 +Repayments of revolving credit agreement ( 523,931 ) ( 575,802 ) ( 577,703 ) +Principal payments on finance leases ( 5,070 ) ( 4,291 ) ( 2,331 ) +Cash provided by (used in) financing activities ( 10,519 ) 17,741 11,192 +Net increase (decrease) in cash and cash equivalents 1,149 1,896 ( 1,766 ) +Cash and cash equivalents, beginning of period 3,603 1,707 3,473 +Cash and cash equivalents, end of period $ 4,752 $ 3,603 $ 1,707 +Supplemental cash flow information: +Interest payments $ 10,269 $ 9,256 $ 5,110 +Income tax payments, net of refunds $ 2,402 $ 1,414 $ 1,315 +ASC 326 Opening Balance Sheet Adjustment $ 3,278 $ — $ — +Recognition of operating lease liabilities and right-of-use assets $ 4,877 $ 5,184 $ 5,247 +Recognition of financing lease liabilities and right-of-use assets $ — $ 1,940 $ 13,096 +See accompanying notes to consolidated financial statements. +37 +KEY TRONIC CORPORATION AND SUBSIDIARIES +CONSOLIDATED STATEMENT OF SHAREHOLDERS’ EQUITY +(In thousands) +Shares Common +Stock Retained +Earnings Accumulated +Other +Comprehensive +Income (Loss) Total +Shareholders’ +Equity +Balances, July 3, 2021 10,762 47,181 74,452 2,072 $ 123,705 +Net income 3,377 — 3,377 +Unrealized loss on hedging instruments, net of tax — — — ( 2,497 ) ( 2,497 ) +Share-based compensation — 293 — — 293 +Balances, July 2, 2022 10,762 47,474 77,829 ( 425 ) $ 124,878 +Net income — — 5,157 — 5,157 +Unrealized gain on hedging instruments, net of tax — — — 328 328 +Share-based compensation — 254 — — 254 +Balances, July 1, 2023 10,762 $ 47,728 $ 82,986 $ ( 97 ) $ 130,617 +Net loss — ( 2,787 ) — ( 2,787 ) +CECL opening balance sheet adjustment, net of tax — — ( 3,278 ) — ( 3,278 ) +Unrealized loss on hedging instruments, net of tax — — — ( 118 ) ( 118 ) +Share-based compensation — ( 444 ) — — ( 444 ) +Balances, June 29, 2024 10,762 $ 47,284 $ 76,921 $ ( 215 ) $ 123,990 +See accompanying notes to consolidated financial statements. +38 +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. SIGNIFICANT ACCOUNTING POLICIES +Business +Key Tronic Corporation and subsidiaries (the Company) is engaged in contract manufacturing for original equipment manufacturers (OEMs). The Company’s headquarters are located in Spokane Valley, Washington with manufacturing operations in Oakdale, Minnesota; Fayetteville, Arkansas; Corinth, Mississippi; and foreign manufacturing operations in Juarez, Mexico; Shanghai, China; and Da Nang, Vietnam. +Liquidity +Historically, due to the timing between the procurement of raw materials, production cycle and payment from our customers, we have financed operations and met our capital expenditure requirements primarily through cash flows provided by operations and borrowings under our credit facilities. We generated operating and net income of $ 6.8 million and $( 2.8 ) million respectively, during the 12-month period ended June 29, 2024 and have positive working capital of $ 184.2 million as of June 29, 2024. Due to the timing between the procurement of raw materials, production cycle and payment from our customers, we have relied on borrowings on our credit facilities to fund operations during fiscal year 2024. Based on current projections, we anticipate generating cash from operations as revenue increases in the first quarter of fiscal year 2025. +As of June 29, 2024, we have limited additional borrowing capacity on our credit facility, which matures on December 3, 2025. We are in discussions with multiple financial institutions to extend the borrowing capacity on our credit facility. If we are unable to meet projected operating results or extend our borrowing capacity, we may need to delay the purchase of raw materials or require our customers to fund inventory raw material costs ahead of production. Other options to increase our liquidity include factoring receivables or leveraging foreign owned assets for additional borrowing capacity. We believe that projected cash from operations, funds available under our asset-based revolving credit facility and additional financing options will be sufficient to meet our working and fixed capital requirements for at least the next 12 months. +Reclassifications +Certain prior period reclassifications were made to conform with the current period presentation. These reclassifications had no effect on reported income, comprehensive income, cash flows, total assets, or shareholders' equity as previously reported. +Principles of Consolidation +The consolidated financial statements include the Company and its wholly owned subsidiaries in the United States, Mexico, China and Vietnam. Intercompany balances and transactions have been eliminated during consolidation. +Use of Estimates +The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates include the allowance for credit losses, calculating inventory impairments related to obsolete and non-saleable inventories to value at net realizable value, deferred tax assets and liabilities, uncertain tax positions, impairment of long-lived assets, medical self-funded insurance liability, long-term incentive compensation accrual, the provision for warranty costs, and the fair value of stock appreciation rights granted under the Company’s share-based compensation plan. Due to uncertainties with respect to the assumptions and estimates, actual results could differ from those estimates. +Cash and Cash Equivalents +The Company considers investments with an original maturity of three months or less to be cash equivalents. Cash equivalents are carried at cost, which approximates fair value. The Company may have cash and cash equivalents at financial institutions that are in excess of federally insured limits from time to time. +Allowance for Credit Losses +The Company evaluates the collectability of accounts receivable and records an allowance for credit losses, which reduces the receivables to an amount that management reasonably estimates will be collected. A specific allowance is recorded against receivables considered to be impaired based on the Company’s knowledge of the financial condition of the customer, and a general allowance is calculated and applied to remaining receivables based on the Company's historical collection experience. In determining the amount of the allowance, the Company considers several factors including the aging of the receivables, the current business environment and historical experience. After all attempts to collect a receivable have failed, the receivable is written off against the allowance. +39 +Inventories +Inventories are stated at the lower of cost or net realizable value. Inventory valuation is determined using the first-in, first-out (FIFO) method. Customer orders are based upon forecasted quantities of product manufactured for shipment over defined periods. Raw material inventories are purchased to fulfill these customer requirements. Within these arrangements, customer demands for products frequently change, sometimes creating excess and obsolete inventories. The Company regularly reviews raw material inventories by customer for both excess and obsolete quantities. Wherever possible, the Company attempts to recover its full cost of excess and obsolete inventories from customers or, in some cases, through other markets. When it is determined that the Company’s carrying cost of such excess and obsolete inventories cannot be recovered in full, a charge is taken against income for the difference between the carrying cost and the estimated realizable amount. We also reserve for inventory related to specific customers covered by lead-time assurance agreements when those customers are experiencing financial difficulties or reimbursement is not reasonably assured. +Property, Plant and Equipment +Property, plant and equipment are carried at cost and depreciated using straight-line methods over the expected useful lives of the assets. Repairs and maintenance costs are expensed as incurred. +Leases +Lease assets and liabilities are initially recognized based on the present value of lease payments over the lease term calculated using the Company’s incremental borrowing rate, unless the implicit rate is readily determinable. Our incremental borrowing rate represents the rate of interest that we would have to pay to borrow on a collateralized basis over a similar term in a similar economic environment. Lease assets also include any lease prepayments. Lease terms include options to extend or terminate the lease when it is reasonably certain that those options will be exercised. Leases are classified as finance or operating, with classification affecting the pattern and classification of expense recognition in the consolidated statements of income. For further information, please refer to Footnote “Leases” of the “Notes to Consolidated Financial Statements.” +Impairment of Long-lived Assets +The Company, using its best estimates based on reasonable and supportable assumptions and projections, reviews assets for impairment whenever events or changes in circumstances have indicated that the carrying amount of its assets might not be recoverable. Impaired assets are reported at the lower of cost or fair value. +Accrued Warranty +An accrual is made for expected warranty costs, with the related expense recognized in cost of goods sold. Management reviews the adequacy of this accrual quarterly based on historical analyses and anticipated product returns. +Self-funded Insurance +The Company self-funds its domestic employee health plans. The Company contracts with a separate administrative service company to supervise and administer the programs and act as its representative. The Company reduces its risk under this self-funded platform by purchasing stop-loss insurance coverage for high dollar individual claims. In addition, if the aggregate annual claims amount to more than 125 percent of expected claims for the plan year this insurance will also pay those claims amounts exceeding that level. +The Company estimates its exposure for claims incurred but not paid at the end of each reporting period and uses historical claims data supplied by the Company’s broker to estimate its self-funded insurance liability. This liability is subject to a total limitation that varies based on employee enrollment and factors that are established at each annual contract renewal. Actual claims experience may differ from the Company’s estimates. Costs related to the administration of the plan and related claims are expensed as incurred. +Revenue Recognition +The first step in its process for revenue recognition is to identify the contract with a customer. A contract is defined as an agreement between two or more parties that creates enforceable rights and obligations. A contract can be written, oral, or implied. The Company generally enters into manufacturing service agreements (“MSA”) with its customers that outlines the terms of the business relationship between the customer and the Company. This includes matters such as warranty, indemnification, transfer of title and risk of loss, liability for excess and obsolete inventory, pricing, payment terms, etc. The Company will also bid on a program-by-program basis for customers in which an executed MSA may not be in place. In these instances, as well as when we have an MSA in place, we receive customer purchase orders for specific quantities and timing of products. As a result, the Company considers its contract with a customer to be the combination of the MSA and the purchase order. The transaction price is fixed and set forth in each purchase order. In the Company's normal course of business, there are no variable pricing components, or material amounts refunded to customers in the form of refunds or rebates. +40 +The Company assesses whether control of the product or services promised under the contract is transferred to the customer at a point in time (shipment) or over time (as we manufacture the product). The Company is first required to evaluate whether its contracts meet the criteria for 'over-time' or 'point-in-time' recognition. The Company has determined that for the majority of its contracts the Company is manufacturing products for which there is no alternative use due to the unique nature of the customer-specific product, IP and other contract restrictions. The Company has an enforceable right to payment including a reasonable profit for performance completed to date with respect to these contracts. As a result, revenue is recognized under these contracts 'over-time' based on the input cost-to-cost method as it better depicts the transfer of control. This input method is based on the ratio of costs incurred to date as compared to the total estimated costs at completion of the performance obligation. For all other contracts that do not meet these criteria, such as manufacturing contracts for which the terms do not provide an enforceable right to payment for performance completed to date, the Company recognizes revenue when it has transferred control of the related manufactured products which generally occurs upon shipment to the customer. Revenue from engineering services is recognized over time as costs related to the services are incurred, which approximates proportional performance of the service. This method is used because management considers it to be the best available measure of progress on the contracts. Revenue from scrap and excess inventory sales is recognized at the point-in-time of scrap at the customers direction, or, if applicable, shipment of the material to the customer. +Shipping and Handling Fees +The Company classifies costs associated with shipping and handling fees as a component of cost of goods sold. Customer billings related to shipping and handling fees are reported as revenue. +Research, Development and Engineering +Research, development and engineering expenses include unreimbursed contract manufacturing costs as well as design and engineering costs associated with the production of contract manufacturing programs. Research, development and engineering costs are expensed as incurred. +Income Taxes +Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the estimated future tax consequences and benefits attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, as well as tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences and carryforwards are expected to be recovered or settled. The effect on deferred tax assets and liabilities for a change in tax rates is recognized in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amount that is more likely than not to be realized. +We utilize a two-step approach to recognizing and measuring uncertain tax positions. The first step is to evaluate the tax position for recognition by determining if the weight of available evidence indicates it is more likely than not that the position will be sustained on audit, including resolution of related appeals or litigation processes, if any. The second step is to measure the tax benefit as the largest amount which is more than 50% likely of being realized upon ultimate settlement. We consider many factors when evaluating and estimating our tax positions and tax benefits, which may require periodic adjustments based on new assessments and changes in estimates and which may not accurately forecast actual outcomes. Our policy is to recognize interest and penalties related to the underpayment of income taxes as a component of income tax provision. The tax years 2005 through the present remain open to examination by the major U.S. taxing jurisdictions to which we are subject. For further discussions, please refer to Footnote “Income Taxes” of the “Notes to Consolidated Financial Statements.” +Derivative Instruments and Hedging Activities +The Company has previously entered into foreign currency forward contracts and an interest rate swap which are accounted for as cash flow hedges in accordance with ASC 815, Derivatives and Hedging . The effective portion of the gain or loss on the derivative is reported as a component of accumulated other comprehensive income (AOCI) and is reclassified into earnings in the same period in which the underlying hedged transaction affects earnings. The derivative’s effectiveness represents the change in fair value of the hedge that offsets the change in fair value of the hedged item. As of June 29, 2024, the Company had outstanding foreign currency forward contracts with a notional amount of $ 12.5 million. +Earnings Per Common Share +Basic earnings per common share is computed by dividing net income by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is computed by dividing net income by the combination of other potentially dilutive weighted average common shares and the weighted average number of common shares outstanding during the period using the treasury stock method. The computation assumes the proceeds from the exercise of stock options were used to repurchase common shares at the average market price during the period. The computation of diluted earnings per +41 +common share does not assume conversion, exercise, or contingent issuance of common stock equivalent shares that would have an anti-dilutive effect on earnings per share. +Foreign Currency Transactions +The functional currency of the Company’s subsidiaries in Mexico, China and Vietnam is the U.S. dollar. Realized foreign currency transaction gains and losses for local currency denominated assets and liabilities are included in cost of goods sold. +Fair Value of Financial Instruments +The carrying values of cash and cash equivalents, accounts receivable, current liabilities, and non-current operating lease liability are reflected on the balance sheets at June 29, 2024, July 1, 2023, and July 2, 2022 , reasonably approximate their fair value. The Company had an outstanding balance on its lines of credit of $ 112.6 million as of June 29, 2024, $ 115.4 million as of July 1, 2023, and $ 95.1 million as of July 2, 2022 with a carrying value that reasonably approximates the fair value. The Company had an outstanding balance on its foreign term loan of MXN 40.5 million ($ 2.2 million USD) as of June 29, 2024, MXN 58.2 million ($ 3.4 million USD) as of July 1, 2023, and MXN 93.3 million ($ 4.6 million USD) as of July 2, 2022 with a carrying value that reasonably approximates the fair value. The domestic equipment term loans were $ 5.8 million as of June 29, 2024, $ 6.5 million as of July 1, 2023, and $ 3.3 million as of July 2, 2022 with a carrying value that reasonably approximates the fair value. +Share-based Compensation +The Company’s incentive plan may provide for equity awards to employees in the form of stock options, stock appreciation rights, restricted stock, restricted stock units, stock awards, stock units, performance shares, performance units, and other stock-based awards. Compensation cost is recognized on a straight-line basis over the requisite employee service period, which is generally the vesting period, and is included in cost of goods sold, research, development and engineering, and selling, general, and administrative expenses. Share-based compensation is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on historical experience and future expectations. +Newly Adopted and Recent Accounting Pronouncements +On December 14, 2023, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (“ASU”) 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The ASU requires entities to disclose more detailed information relating to their reconciliation of statutory tax rate to effective tax rate, income taxes paid by jurisdiction, pretax income (or loss) from continuing operations, and income tax expense (or benefit). The ASU applies to the Company’s annual reporting period beginning in fiscal year 2026. The Company does not anticipate early adoption of the new disclosure standards. +In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (ASU 2023-07), which requires public entities to disclose information about their reportable segments' oversight and significant expenses on an interim and annual basis. The ASU is effective for the annual reporting period beginning in fiscal year 2025 and for interim periods beginning in fiscal year 2026. Early adoption is permitted. The Company is currently evaluating the guidance and its impact to the financial statements. +In September 2022, the FASB issued ASU No. 2022-04, Liabilities—Supplier Finance Programs (Subtopic 405-50). This standard requires disclosure of the key terms of outstanding supplier finance programs and a roll forward of the related obligations. The new standard does not affect the recognition, measurement or financial statement presentation of supplier finance program obligations. The ASU became effective for the Company July 2, 2023, except for the roll forward requirement, which becomes effective June 30, 2024. This ASU, except for the roll forward requirement, was adopted retrospectively as of July 2, 2023 and did not have a material impact on our consolidated financial statements. +In October 2021, the FASB issued ASU 2021-08 amending Business Combination: (Topic 805), which was necessary due to 2014-09, Revenue from Contracts with Customers (Topic 606). The FASB issued this ASU to improve the accounting for acquired revenue contracts with customers in a business combination by addressing diversity in practice and inconsistency related to (1) recognition of an acquired contract liability and (2) payment terms and their effect on subsequent revenue recognized by the acquirer. The Company adopted these amendments as of the effective date of July 2, 2023. These amendments are to be applied prospectively to business combinations occurring on or after the effective date of the amendments. The Company plans to apply the practical expedients as needed for any future acquisitions. The practical expedients cover contracts that were modified prior to acquisition date as well as determining which date an acquirer would have to determine the standalone selling price of each performance obligation in an acquired contract. This ASU did not have a material impact on our consolidated financial statements. +In March of 2020, the FASB issued ASU 2020-03, Codification Improvements to Financial Instruments, which clarifies specific issues raised by stakeholders. Specifically, the ASU clarifies the following: 1) that all entities are required to provide the fair value option disclosures in ASC 825, Financial Instruments 2) clarifies that the portfolio exception in ASC 820, Fair +42 +Value Measurement, applies to nonfinancial items accounted for as derivatives under ASC 815, Derivatives and Hedging; 3) clarifies that for purposes of measuring expected credit losses on a net investment in a lease in accordance with ASC 326, Financial Instruments - Credit Losses, the lease term determined in accordance with ASC 842, Leases, should be used as the contractual term; 4) clarifies that when an entity regains control of financial assets sold, it should recognize an allowance for credit losses in accordance with ASC 326; and 5) aligns the disclosure requirements for debt securities in ASC 320, Investments - Debt Securities, with the corresponding requirements for depository and lending institutions in ASC 942, Financial Services - Depository and Lending. The amendments in the ASU have various effective dates and transition requirements which are dependent on timing of adoption of ASU 2016-13. The Company adopted this amendment as of the effective date of July 2, 2023 on a modified retrospective basis. This ASU did not have a material impact on our consolidated financial statements. +In June 2016, the FASB issued ASU 2016-13 Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments and also issued subsequent amendments to the initial guidance: ASU 2018-19, ASU 2019-04 and ASU 2019-05, which replaces the existing incurred loss impairment model with an expected credit loss model and requires a financial asset measured at amortized cost to be presented at the net amount expected to be collected. The guidance was effective for the Company beginning in the first quarter of fiscal year 2024. The Company adopted this amendment as of the effective date of July 2, 2023, and the impacts are disclosed in opening retained earnings on the Consolidated Statement of Shareholders' Equity. Refer to further discussion in Note 15 - "Restatement of Interim Financial Information" +Fiscal Year +The Company operates on a 52/53 week fiscal year. Fiscal years end on the Saturday nearest June 30. As such, fiscal years 2024 and 2023 ended on June 29, 2024 and July 1, 2023, respectively. Fiscal years 2022, 2023 and 2024 were 52 week years. +2. INVENTORIES +Inventory as of June 29, 2024 is $ 105.1 million compared to $ 137.9 million as of July 1, 2023 and $ 155.7 million as of July 2, 2022. The components of inventories consist of the following (in thousands): +June 29, 2024 July 1, 2023 July 2, 2022 +(in thousands) +Raw materials and supplies $ 80,570 $ 109,078 $ 131,980 +Work-in-process 24,529 28,833 23,761 +Inventories $ 105,099 $ 137,911 $ 155,741 +3. PROPERTY, PLANT AND EQUIPMENT +Property, plant and equipment consists of the following: +Life June 29, 2024 July 1, 2023 July 2, 2022 +(in years) (in thousands) +Land — $ 4,034 $ 4,034 $ 4,034 +Buildings and improvements +3 to 30 +27,821 26,459 25,841 +Equipment +1 to 10 +80,049 77,823 71,180 +Furniture and fixtures +3 to 5 +6,660 5,418 5,286 +Total property, plant and equipment 118,564 113,734 106,341 +Accumulated depreciation ( 89,758 ) ( 84,864 ) ( 80,329 ) +Property, plant and equipment, net $ 28,806 $ 28,870 $ 26,012 +Fiscal Year Ended +June 29, 2024 July 1, 2023 July 2, 2022 +(in thousands) +Depreciation expense $ 5,270 $ 4,700 $ 4,940 +43 +4. LONG-TERM DEBT +Debt consists of the following: +Maturity Date Interest Rate June 29, 2024 July 1, 2023 July 2, 2022 +(in thousands) +Asset-based senior secured revolving credit facility (1) December 3, 2025 9.5 % $ 107,149 $ 115,395 $ 95,077 +Foreign line of credit (2) December 11, 2026 14.0 % 5,403 — — +Domestic term loan - Balboa (3) September 19, 2030 +6 % to 8 % +4,535 4,148 — +Foreign term loan - Banorte (4) April 24, 2026 5.5 % $ 2,200 $ 3,400 $ 4,600 +Domestic term loan - Bank of America (5) August 14, 2025 4.9 % $ 1,277 $ 2,316 $ 3,305 +Total debt 120,564 125,259 102,982 +Less: current portion of debt ( 3,123 ) ( 3,138 ) ( 2,190 ) +Less: unamortized financing costs ( 1,059 ) ( 590 ) ( 499 ) +Long-term debt, net $ 116,382 $ 121,531 $ 100,293 +(1) On August 14, 2020, the Company entered into a loan agreement with Bank of America (“Loan Agreement”). The Loan Agreement replaced the Company’s prior amended and restated credit agreement, as amended, with Wells Fargo Bank. The Loan Agreement provides for an asset-based senior secured revolving credit facility with an original availability of up to $ 93 million. +On September 3, 2021, the Company entered into an amendment to the Loan Agreement, which increased the availability under the credit facility to $ 120 million, subject to the Company’s borrowing base, and set the maturity date to September 3, 2026. On August 26, 2022, the Company entered into a third amendment to the Loan Agreement, which removed the cash flow leverage ratio covenant and increased the interest rate by 25 basis points. On May 7, 2024, the Company entered into a fourth amendment to the Loan Agreement, effective as of March 29, 2024, which amendment modified debt covenant provisions to reduce the minimum requirement for the fixed charge coverage ratio from 1.25 :1.00 to 1.00 :1.00 as of March 30, 2024 and allow for the add back of severance expenses incurred during the quarter ended March 30, 2024. The minimum requirement for the fixed charge coverage ratio will increase as follows: 1.05 :1.00 on July 27, 2024, 1.15 :1.00 on October 26, 2024, 1.20 :1.00 on January 25, 2025, and 1.25 :1.00 on and after March 29, 2025. In addition, the amendment increased the interest rate by 100 basis points beginning on March 29, 2024 and moved forward the maturity date by one year to September 3, 2025. On September 27, 2024, the Company entered into a fifth amendment to the Loan Agreement, which extended the maturity date by three months to December 3, 2025. On October 9, 2024, the Company entered into a sixth amendment to the Loan Agreement, The Amendment waived existing events of default relating to non-compliance with (a) prescribed fixed charge coverage ratios for the periods ending June 29, 2024 and July 27, 2024 and (b) delivering audited financial statements within 90 days of the Company's fiscal year-end. The Amendment increased the interest rate by 50 basis points beginning on October 9, 2024 so that the applicable margin on base rate loans is 3.50 % and term SOFR loans is 4.50 %. In addition, the Amendment increased the availability block, which reduces the calculated borrowing base under the Loan Agreement, from $ 8 million to $ 10 million, with further increases to $ 11 million and $ 12 million to be effective on December 31, 2024 and March 31, 2025, respectively. +As of June 29, 2024, the Company had an outstanding balance under the asset-based revolving credit facility of $ 107.1 million, $ 0.3 million in outstanding letters of credit and $ 12.9 million available for future borrowings. +As of July 1, 2023, the Company had an outstanding balance under the asset-based revolving credit facility of $ 115.4 million, $ 0.3 million in outstanding letters of credit and $ 4.6 million available for future borrowings. +As of July 2, 2022, the Company had an outstanding balance under the asset-based revolving credit facility of $ 95.1 million, $ 0.3 million in outstanding letters of credit and $ 10.8 million available for future borrowings. +Generally, the interest rate applicable to loans under the Bank of America loan agreement will be, at the Company’s option: (i) the base rate which is the highest of (a) the Prime Rate for such day, (b) the Federal Funds Rate for such day plus 0.50 %, and (c) Term SOFR for a one month interest period as of such day, plus 1.00 % (provided that in no event shall the base rate be less than zero), plus the applicable interest margin for base rate loans; or (ii) SOFR rate for an applicable interest period, plus the applicable interest margin for SOFR rate loans. As modified by the sixth amendment to the Loan Agreement, the applicable interest margin on: (x) base rate loans is 3.50 % and (y) SOFR rate loans is 4.50 %, resetting on a quarterly basis. If there is an event of default that is not waived under the Loan Agreement, all loans and other obligations will bear interest at a rate of an +44 +additional 2.00 % on the otherwise applicable interest rates. In addition to interest charges, the Company is required to pay a fee of 0.25 % per annum on the unused portion of the Credit Facility, monthly in arrears. +As of June 29, 2024, the interest rate on the asset-based revolving credit facility with Bank of America was 9.46 %. +(2) On December 11, 2023, the Company entered into a loan agreement in Mexican peso with Banorte Financial Group. The agreement provides for a three-year secured line of credit up to MXN 100 million, subject to the Company’s borrowing base, maturing on December 11, 2026. The credit facility bears interest at Iterbancario de Equilibrio Interest Rate plus 2.75 %, and as of June 29, 2024, was 13.99 %. As of June 29, 2024, the Company had an outstanding balance under the revolving credit facility of MXN 99 million ($ 5.4 USD) and MXN 1 million ($ 0.1 million USD) available for future borrowings. +(3) On September 19, 2023, the Company entered into a $ 1.1 million equipment financing agreement with Ameris Bank dba Balboa Capital ("Balboa Capital"). Combining with other equipment financing agreements entered in the third quarter of fiscal year 2023, a total of $ 5.5 million relates to the Company’s existing manufacturing equipment that bears an interest rate range of 6 % - 8 % and matures in the first quarter of fiscal 2030. Under these loan agreements, equal monthly payments of $ 94,000 commenced in the fourth quarter of fiscal year 2024 and will continue through the maturity of the equipment financing facility in the first quarter of fiscal 2030. The Company had an outstanding balance $ 4.5 million as of June 29, 2024. +(4) On November 24, 2020, the Company entered into a $ 6.0 million equipment financing facility related to the Company’s existing manufacturing equipment that bears interest at 5.52 % and matures on April 24, 2026. Under this loan agreement, equal monthly payments of $ 100,000 commenced on May 24, 2021 and will continue through the maturity of the equipment financing facility on April 24, 2026. As of June 29, 2024, the Company had an outstanding balance of $ 2.2 million. As of July 1, 2023, the Company had an outstanding balance of $ 3.4 million. As of July 2, 2022, the Company had an outstanding balance of $ 4.6 million. +(5) On August 14, 2020, the Company entered into a $ 5.0 million equipment financing facility with Bank of America relating to the Company’s existing U.S. manufacturing equipment that bears interest at 4.85 % and matures on August 14, 2025. Under this loan agreement, equal monthly payments of approximately $ 94,000 commenced on September 14, 2020 and will continue through the maturity of the equipment financing facility on August 14, 2025. As of June 29, 2024, the Company had an outstanding balance of $ 1.3 million. As of July 1, 2023, the Company had an outstanding balance of $ 2.3 million. As of July 2, 2022, the Company had an outstanding balance of $ 3.3 million. +Debt maturities as of June 29, 2024 for the next five years are as follows (in thousands): +Fiscal Years Ending Amount +2025 $ 3,123 +2026 109,230 +2027 6,363 +2028 1,032 +2029 816 +2030 - Thereafter — +Total debt 120,564 +Unamortized financing costs ( 1,059 ) +Long-term debt, net of unamortized financing costs $ 119,505 +The Company must comply with certain financial covenants, including a fixed charge coverage ratio. The credit agreement requires the Company to grant certain inspection rights to Bank of America, limit or restrict the Company’s cash management; limit or restrict the ability of the Company to incur additional liens, make acquisitions or investments, incur additional indebtedness, engage in mergers, consolidations, liquidations, dissolutions, or dispositions, pay dividends or other restricted payments, prepay certain indebtedness, engage in transactions with affiliates, and use proceeds. As of June 29, 2024, The Company was not in compliance with the fixed coverage charge ratio. On October 9, 2024, the Company executed a sixth amendment to the Loan Agreement which waived existing events of default as of that date . +45 +5. INCOME TAXES +Income tax benefit consists of the following: +Fiscal Year Ended +June 29, 2024 July 1, 2023 July 2, 2022 +(in thousands) +Current income tax provision (benefit): +United States $ 263 $ 998 $ ( 2,179 ) +Foreign 1,451 2,134 2,012 +1,714 3,132 ( 167 ) +Deferred income tax provision (benefit): +United States ( 4,322 ) ( 2,130 ) 443 +Foreign 208 141 38 +( 4,114 ) ( 1,989 ) 481 +Total income tax provision $ ( 2,400 ) $ 1,143 $ 314 +The Company has gross tax credit carryforwards of approximately $ 10.4 million at June 29, 2024 consisting of federal research and development (R&D) tax credits. +Management has reviewed all deferred tax assets for purposes of determining whether a valuation allowance may be required. A valuation allowance against deferred tax assets is required if it is more likely than not that some of the deferred tax assets will not be realized. Based upon the Company’s profitability, forecasted income, and evaluation of all other positive and negative evidence, management determined that it is more likely than not that the deferred tax assets will be realized. +On January 27, 2021, the Company received official notice from the Vietnamese tax authorities, confirming tax benefits awarded related to the Company’s principal product line in Vietnam (the “Tax Holiday”). Under the Tax Holiday, the tax rate applied to income derived from this product line will be zero percent for four years beginning with fiscal year 2021, then five percent for nine years, then ten percent for one year (as opposed to the normal twenty percent Vietnamese statutory rate). +The Company continuously evaluates impact of tax law and regulatory changes. The Company noted no changes during the current quarter or fiscal year that would have a material impact on its provision for income taxes or overall income tax position. +The 2017 Tax Cuts and Jobs Act (TCJA) mandated that, for tax years after fiscal year 2022, certain costs incurred for research and development (R&D) activities would no longer be allowed for immediate deduction but would be capitalized and amortized over 5 years (for R&D activities performed domestically) or 15 years (for R&D activities performed abroad). The Company began capitalizing and amortizing such costs in fiscal year 2023, resulting in an increase to income taxes payable that was largely offset by the utilization of R&D credit carryovers. +In future years, repatriations of cash will generally be tax-free in the U.S. However, withholding taxes in China may still apply to any such future repatriations. Management has not changed its indefinite investment assertions regarding to the portion of accumulated earnings and profits in China that may be repatriated in the future. Accordingly, management estimates that future repatriations of cash from China may result in approximately $ 0.8 million of withholding tax. There would be no offsetting foreign tax credits in the U.S. and as such, this potential liability is a direct cost associated with actual repatriations. Withholding taxes will not apply to future repatriations from Mexico or Vietnam. +The Company expects to repatriate a portion of its foreign earnings based on increased net sales growth driving additional capital requirements domestically, cash requirements for potential acquisitions and to implement certain tax strategies. The Company expects to repatriate approximately $ 8.0 million from China, in the future. All other unremitted foreign earnings are expected to remain permanently reinvested for planned fixed assets purchases and improvements in foreign locations. +46 +The Company’s effective tax rate differs from the federal tax rate as follows: +Fiscal Year Ended +June 29, 2024 July 1, 2023 July 2, 2022 +(in thousands) +Federal income tax provision at statutory rates $ ( 1,089 ) $ 1,322 $ 775 +State income taxes, net of federal tax effect ( 145 ) ( 25 ) 86 +Foreign tax rate differences ( 71 ) 137 336 +Net operating loss carryback — — ( 593 ) +Effect of income tax credits ( 929 ) ( 1,020 ) ( 920 ) +Previously unrecognized tax benefits ( 232 ) ( 75 ) 146 +Inflation adjustments 132 118 178 +Tax penalties & interest included in tax provision — — 179 +Global Intangible Low-Taxed Income (GILTI) tax 53 33 59 +Provision to return reconciliation ( 68 ) 52 ( 91 ) +Equity compensation shortfall 51 73 104 +Foreign Exchange Gains/Losses Unrealized for Tax Purposes ( 126 ) 277 23 +Other 24 251 32 +Income tax provision (benefit) $ ( 2,400 ) $ 1,143 $ 314 +The domestic and foreign components of income before income taxes were: +Fiscal Year Ended +June 29, 2024 July 1, 2023 July 2, 2022 +(in thousands) +Domestic $ ( 13,539 ) $ ( 1,086 ) $ ( 2,890 ) +Foreign 8,352 7,386 6,581 +Income before income taxes $ ( 5,187 ) $ 6,300 $ 3,691 +47 +Deferred income tax assets and liabilities consist of the following at: +June 29, 2024 July 1, 2023 July 2, 2022 +(in thousands) +Deferred tax assets: +Tax credit carryforwards, net $ 7,544 $ 6,812 $ 7,990 +Net operating loss — — 486 +Inventory 252 267 247 +Identifiable intangibles 247 308 370 +Accruals 2,340 2,421 2,406 +Property, plant, and equipment — 1,328 1,200 +ASC 606 deferred costs 3,852 4,802 4,216 +Lease liabilities 3,542 3,775 3,671 +Interest expense deduction carryforward 2,765 977 580 +Research and development expenses 6,042 3,860 — +Other 505 271 465 +Deferred income tax assets $ 27,089 $ 24,821 $ 21,631 +Deferred tax liabilities: +Accrued withholding tax - unremitted earnings ( 796 ) ( 754 ) ( 754 ) +Property, plant, and equipment ( 127 ) — — +Right-of-use assets ( 3,609 ) ( 3,857 ) ( 3,663 ) +Tax capital lease liabilities ( 764 ) ( 2,832 ) ( 2,385 ) +ASC 606 accelerated revenue ( 3,882 ) ( 4,599 ) ( 3,736 ) +Other ( 798 ) ( 799 ) ( 1,102 ) +Deferred income tax liabilities $ ( 9,976 ) $ ( 12,841 ) $ ( 11,640 ) +Net deferred income tax assets $ 17,113 $ 11,980 $ 9,991 +Balance sheet caption reported in: +Long-term deferred income tax asset $ 17,376 $ 12,254 $ 10,055 +Long-term deferred income tax liability ( 263 ) ( 274 ) ( 64 ) +Net deferred income tax asset $ 17,113 $ 11,980 $ 9,991 +Uncertain Tax Positions: +The Company has R&D tax credits that approximate $ 10.4 million that have 20 -year carryforwards before expiring. The Company’s R&D tax credits expire in various fiscal years from 2033 to 2044. +As of June 29, 2024, the Company had unrecognized tax benefits of $ 2.9 million related to its gross R&D tax credits. The unrecognized tax benefits relate to certain R&D tax credits generated from 2005 to 2024. +A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows: +Fiscal Year Ended +June 29, 2024 July 1, 2023 July 2, 2022 +(in thousands) +Beginning Balance $ 3,028 $ 2,998 $ 4,863 +Additions based on tax positions related to the current year 110 120 286 +Adjustment to prior year tax positions & amended tax returns ( 7 ) ( 15 ) ( 2,296 ) +Lapse of statute of limitations ( 232 ) ( 75 ) 145 +Ending Balance $ 2,899 $ 3,028 $ 2,998 +The $ 2.9 million of unrecognized tax benefits at the end of fiscal year 2024, if recognized, would reduce the effective tax rate. Management does not anticipate any material changes to this amount during the next 12 months. +48 +The Company recognizes interest accrued related to unrecognized tax benefits and penalties in its income tax provision. The Company has not recognized any interest or penalties in the fiscal years presented in these financial statements. The Company is subject to income tax in the U.S. federal jurisdiction, various state jurisdictions, Mexico, China and Vietnam. Certain years remain subject to examination but there are currently no ongoing exams in any taxing jurisdiction. +6. EARNINGS PER SHARE +Basic earnings per share (EPS) is calculated by dividing net income (the numerator) by the weighted-average number of common shares outstanding (the denominator) during the period. Diluted EPS is computed by including both the weighted-average number of shares outstanding and any dilutive common share equivalents in the denominator. The following table presents a reconciliation of the denominator and the number of antidilutive common share awards that were not included in the diluted earnings per share calculation. These antidilutive securities occur when equity awards outstanding have an option price greater than the average market price for the period: +Fiscal Year Ended (in thousands, except per share information) +June 29, 2024 July 1, 2023 July 2, 2022 +Net income (loss) $ ( 2,787 ) $ 5,157 $ 3,377 +Weighted average shares outstanding—basic 10,762 10,762 10,762 +Effect of dilutive common stock awards — 176 301 +Weighted average shares outstanding—diluted 10,762 10,938 11,063 +Net income (loss) per share—basic $ ( 0.26 ) $ 0.48 $ 0.31 +Net income (loss) per share—diluted $ ( 0.26 ) $ 0.47 $ 0.31 +Antidilutive SARs not included in diluted earnings per share 515 376 619 +7. STOCK-BASED COMPENSATION AND BENEFIT PLANS +The Company’s incentive plan provides for equity and liability awards to employees and non-employee directors in the form of stock options, stock appreciation rights (SARs), restricted stock, restricted stock units, stock awards, stock units, performance shares, performance units, and other stock-based or cash-based awards. Compensation cost is recognized on a straight-line basis over the requisite employee service period, which is generally the vesting period, and is recorded as employee compensation expense in cost of goods sold, research, development and engineering, and selling, general and administrative expenses. Share-based compensation is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on historical experience and future expectations. +In addition to service conditions, these SARs contain a performance condition. The additional performance condition is based upon the achievement of Return on Invested Capital (ROIC) goals relative to a peer group. All awards with performance conditions are measured over the vesting period and are charged to compensation expense over the requisite service period based on the number of shares expected to vest. The SARs cliff vest after a three-year period from date of grant based on the performance metric and expire five years from date of grant. +On July 29, 2022, the Compa ny granted 145,000 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $ 5.10 and a grant date fair value of $ 2.09 . As of June 29, 2024, 136,250 remain outstanding. The grant date fair value for the awards granted during fiscal year 2023, were estimated using the Black Scho les option valuation method with the following weighted average assumptions as of July 29, 2022: +Fiscal Year 2023 +July 29, 2022 +Expected dividend yield — % +Risk-free interest rate 3.01 % +Expected volatility 48.56 % +Expected life 4.00 +On August 9, 2021, the Compa ny granted 165,000 SARs under the 2010 Incentive Plan to certain key employees and outside directors at a strike price of $ 7.17 and a grant date fair value of $ 2.73 . As of June 29, 2024, 136,250 remain outstanding. The grant date fair value for the awards granted during fiscal year 2022, were estimated using the Black Scho les option valuation method with the following weighted average assumptions as of August 9, 2021: +49 +Fiscal Year 2022 +August 9, 2021 +Expected dividend yield — % +Risk-free interest rate 0.62 % +Expected volatility 48.58 % +Expected life 4.00 +The Black-Scholes option valuation model is used by the Company for estimating the fair value of SARs. Option valuation models require the input of highly subjective assumptions, particularly for the expected term and expected stock price volatility. Changes in these assumptions can materially affect the fair value estimates. +Share-based compensation expense is recognized only for those awards that are expected to vest, with forfeitures estimated at the date of grant based on the Company’s historical experience and future expectations. This forfeiture rate will be revised, if necessary, in subsequent periods if actual forfeitures differ from the amount estimated. Share-based compensation expense for fiscal years ended June 29, 2024, July 1, 2023 and July 2, 2022 was $( 0.4 ) million, $ 0.3 million and $ 0.3 million, respectively. The fiscal year 2024 amount relates to reversal of prior expense for which performance metrics were not ultimately attained. +There were no SARs exercised during fiscal year 2024, fiscal year 2023 and fiscal year 2022. +As of June 29, 2024, total unrecognized compensation expense related to nonvested share-based compensation arrangements was approximately $ 0.1 million. This expense is expected to be recognized over a weighted-average period of 1.0 years. +The following table summarizes the Company’s SARs activity from July 3, 2021 through June 29, 2024: +SARs +Available +For Grant SARs +Outstanding Aggregate +Intrinsic +Value (in +thousands) Weighted +Average +Exercise +Price Weighted +Average +Remaining +Contractual +Life (in +years) +Balances, July 3, 2021 688,084 791,250 $ 7.15 1.9 +SARs granted ( 165,000 ) 165,000 $ 7.17 +SARs expired 197,500 ( 197,500 ) $ 8.17 +Balances, July 2, 2022 720,584 758,750 $ — $ 6.89 2.1 +SARs granted ( 145,000 ) 145,000 $ 5.10 +SARs forfeited 90,000 ( 90,000 ) $ 6.55 +SARs expired 187,500 ( 187,500 ) $ 7.26 +Balances, July 1, 2023 853,084 626,250 $ — $ 6.41 2.2 +SARs forfeited 137,500 ( 137,500 ) $ 6.90 +SARs expired 101,250 ( 101,250 ) $ 8.17 +Balances, June 29, 2024 1,091,834 387,500 $ — $ 5.78 1.8 +Exercisable at June 29, 2024 115,000 $ — $ 4.93 0.1 +The Company has defined contribution plans available to U.S. employees who have attained age 21. Company contributions to the plans were approximately $ 1.3 million, $ 1.1 million and $ 0.9 million during fiscal years 2024, 2023 and 2022, respectively. +8. COMMITMENTS AND CONTINGENCIES +Litigation and Other Matters +The Company is party to certain lawsuits or claims in the ordinary course of business. The Company does not believe that these proceedings, individually or in the aggregate, will have a material adverse effect on the financial position, results of operations or cash flow of the Company. +Warranties +The Company provides warranties on certain product sales. Allowances for estimated warranty costs are recorded during the period of sale. The determination of such allowances requires the Company to make estimates of product return rates and expected costs to repair or to replace the products under warranty. If actual return rates and/or repair and replacement costs +50 +differ significantly from management's estimates, adjustments to recognize additional cost of sales may be required in future periods. As of June 29, 2024, July 1, 2023, and July 2, 2022 the reserve for warranty costs was approximately $ 164,000 , $ 29,000 , and $ 31,000 respectively. +Leases +Please refer to Footnote “Leases” of the “Notes to Consolidated Financial Statements” for information regarding lease commitments. +Internal Investigation +During fiscal year 2021, the Company’s Audit Committee completed an internal investigation arising from a notification from an employee regarding certain alleged accounting irregularities. In January 2021, the Company determined that improper accounting resulted in an understatement of cost of goods sold and an overstatement of inventories. Subsequent to the matter identified in January 2021, additional inventory accounting errors unrelated to the investigation were also identified by management. The investigation did not result in a restatement of our previously filed financial statements. The Company is cooperating with the Securities and Exchange Commission’s (the “SEC”) inquiries related to the internal investigation. The Company cannot currently form an estimate of any possible loss or range of loss, including any potential monetary penalties; or other remedies potentially imposed by the SEC. +Indemnification Rights +Under the Company’s bylaws, the Company’s directors and officers have certain rights to indemnification by the Company against certain liabilities that may arise by reason of their status or service as directors or officers. The Company maintains director and officer insurance, which may cover certain liabilities arising from its obligation to indemnify its directors and officers and former directors in certain circumstances. +9. DERIVATIVE FINANCIAL INSTRUMENTS +As of June 29, 2024, the Company had outstanding foreign currency forward contracts with a total notional amount of $ 12.5 million. The maturity dates for these contracts extend through December 2024. For the three months ended June 29, 2024, the Company entered into $ 12.5 million of foreign currency forward contracts and did not settle any of contracts. During the same period of the previous year, the Company did not enter or settle any foreign currency forward contracts. +For the twelve months ended June 29, 2024, the Company entered into $ 19.0 million of foreign currency forward contracts and settled $ 6.5 million of contracts. During the same period of the previous year, the Company did not enter into or settle any foreign currency forward contracts. +On November 6, 2019, the Company entered into an interest rate swap contract with an effective date of November 6, 2019 and a termination date of September 30, 2022, related to the borrowings outstanding under the term loan with Wells Fargo Bank. This interest rate swap contract was terminated on August 14, 2020 when the Company entered into a loan and security agreement with Bank of America. At date of termination this interest rate swap was in a liability position of $ 148,400 , which was amortized to interest expense over the original term of the swap. +On November 6, 2019, the Company entered into an interest rate swap contract with an effective date of November 6, 2019 and a termination date of November 1, 2023, related to the borrowings outstanding under the line of credit with Wells Fargo Bank. This interest rate swap contract was terminated on August 14, 2020 when the Company entered into a loan and security agreement with Bank of America. At date of termination this interest rate swap was in a liability position of $ 776,500 , which was amortized to interest expense over the original term of the swap. +The following table summarizes the fair value of the derivative instruments in the Consolidated Balance Sheets as of June 29, 2024, July 1, 2023 and July 2, 2022 (in thousands): +Fair Value +Derivatives designated as hedging instruments under Subtopic 815-20 Balance Sheet Location June 29, 2024 July 1, 2023 July 2, 2022 +Foreign currency forward contracts Other current liabilities $ 277 $ — $ — +51 +The following tables summarize the gain (loss) on derivative instruments, net of tax, on the Consolidated Statements of Operations for the fiscal year 2024, 2023 and 2022, respectively (in thousands): +Derivatives Designated as Hedging Instruments Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) AOCI Balance +as of +July 1, 2023 Effective +Portion +Recorded In +AOCI Effective Portion +Reclassified From +AOCI Into +Income AOCI Balance +as of +June 29, 2024 +Forward contracts Cost of sales — 287 ( 72 ) 215 +Interest rate swap Interest expense ( 97 ) — 97 — +Total $ ( 97 ) 287 25 215 +Derivatives Designated as Hedging Instruments Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) AOCI Balance +as of +July 2, 2022 Effective +Portion +Recorded In +AOCI Effective Portion +Reclassified From +AOCI Into +Income AOCI Balance +as of +July 1, 2023 +Forward contracts Cost of sales $ ( 79 ) $ — $ 79 $ — +Interest rate swap Interest expense ( 346 ) — 249 ( 97 ) +Total $ ( 425 ) $ — $ 328 $ ( 97 ) +Derivatives Designated as Hedging Instruments Classification of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion) AOCI Balance +as of +June 28, 2021 Effective +Portion +Recorded In +AOCI Effective Portion +Reclassified From +AOCI Into +Income AOCI Balance +as of +July 2, 2022 +Forward contracts Cost of sales $ 2,721 $ 950 ( 3,750 ) $ ( 79 ) +Interest rate swap Interest expense ( 649 ) — 303 ( 346 ) +Total $ 2,072 $ 950 $ ( 3,447 ) $ ( 425 ) +As of June 29, 2024, the Company does not have any foreign exchange contracts with credit-risk-related contingent features. The Company is subject to the risk of fluctuating interest rates from our line of credit and foreign currency risk resulting from our China operations. The Company does not currently manage these risk exposures by using derivative instruments. +10. FAIR VALUE MEASUREMENTS +The Company has adopted ASC 820, Fair Value Measurements, which defines fair value, establishes a framework for assets and liabilities being measured and reported at fair value and expands disclosures about fair value measurements. There are three levels of fair value hierarchy inputs used to value assets and liabilities which include: Level 1 – inputs are quoted market prices for identical assets or liabilities; Level 2 – inputs other than quoted market prices included in Level 1 that are observable for the asset or liability, either directly or indirectly; and Level 3 – inputs are unobservable inputs for the asset or liability. There have been no changes in the fair value methodologies used at June 29, 2024, July 1, 2023, and July 2, 2022 . +The carrying values of cash and cash equivalents, accounts receivable, contract assets, and current liabilities are reflected on the balance sheets at June 29, 2024, July 1, 2023, and July 2, 2022 and reasonably approximate their fair value. +The Company’s long-term debt, which is measured at amortized cost, primarily consists of an asset-based revolving credit facility, and equipment loans. These borrowings bear interest at SOFR plus 4.5 % per the loan agreement. Each of these rates is a variable floating rate dependent upon current market conditions and the Company’s current credit risk as discussed in Footnote “Long-Term Debt” of the “Notes to Consolidated Financial Statements.” +As a result of the determinable market rates for our asset-based revolving credit facility and equipment loans, they are classified within Level 2 of the fair value hierarchy. Further, the carrying value of each of these instruments reasonably approximates their fair value as of June 29, 2024, July 1, 2023, and July 2, 2022. +52 +11. ENTERPRISE-WIDE DISCLOSURES +Operating segments are defined in ASC Topic 280, Segment Reporting as components of an enterprise for which separate financial information is available that is evaluated regularly by the chief operating decision maker, or decision making group, in deciding how to allocate resources and in assessing performance. The Company’s chief operating decision maker is its Chief Executive Officer. As of June 29, 2024, the Company operates and internally manages a single operating segment, Electronics Manufacturing Services as this is the only discrete financial information that is regularly reviewed by the chief operating decision maker. This segment provides integrated electronic and mechanical engineering, assembly, sourcing and procurement, logistics, and new product testing for our customers. +Products and Services +Of the revenues for the years ended June 29, 2024, July 1, 2023, and July 2, 2022 contract manufacturing sales and services were $ 566.9 million, $ 605.3 million, and $ 544.2 million respectively. +Geographic Areas +Net sales and long-lived assets (property, plant, and equipment) by geographic area for the years ended and as of June 29, 2024, July 1, 2023, and July 2, 2022 are summarized in the following table. Net sales set forth below are based on the shipping destination. Long-lived assets information is based on the physical location of the asset and includes property, plant and equipment, net, and operating lease right-of-use assets, net. +Fiscal Year Ended +(in thousands) +Restated Restated +2024 2023 2022 +Geographic net sales: +Domestic (U.S.) $ 439,334 $ 518,819 $ 450,380 +Foreign 127,608 86,496 93,797 +Total $ 566,942 $ 605,315 $ 544,177 +Long-lived assets: +United States $ 24,497 $ 21,799 $ 14,440 +Mexico 15,531 18,203 22,473 +Vietnam 3,780 4,547 5,228 +China 414 523 601 +Total $ 44,222 $ 45,072 $ 42,742 +Percentage of net sales made to customers located in the following countries: +Fiscal Year Ended +2024 2023 2022 +United States 77 % 86 % 83 % +China 22 % 13 % 15 % +Other foreign countries (a) +1 % 1 % 2 % +Total 100 % 100 % 100 % +(a) No other individual foreign country accounted for 10% or more of the foreign sales in fiscal years 2024 or 2023. +53 +Significant Customers +The percentage of net sales to and trade accounts receivables from significant customers were as follows: +Percentage of Net Sales +Fiscal Year Percentage of Trade Receivables +Fiscal Year +2024 2023 2022 2024 2023 2022 +Customer A 20 % 12 % 12 % 21 % 16 % 13 % +Customer B * * 13 % * * * +12. REVENUE +Revenue Recognition +The Company specializes in services ranging from product manufacturing to engineering and tooling services. The first step in its process for revenue recognition is to identify the contract with a customer. A contract is defined as an agreement between two or more parties that creates enforceable rights and obligations. A contract can be written, oral, or implied. The Company generally enters into manufacturing service agreements (“MSA”) with its customers that outlines the terms of the business relationship between the customer and the Company. This includes matters such as warranty, indemnification, transfer of title and risk of loss, liability for excess and obsolete inventory, pricing, payment terms, etc. The Company will also bid on a program-by-program basis for customers in which an executed MSA may not be in place. In these instances, as well as when we have an MSA in place, we receive customer purchase orders for specific quantities and timing of products. As a result, the Company considers its contract with a customer to be the combination of the MSA and the purchase order. The transaction price is fixed and set forth in each purchase order. In the Company's normal course of business, there are no variable pricing components, or material amounts refunded to customers in the form of refunds or rebates. +The Company assesses whether control of the product or services promised under the contract is transferred to the customer at a point in time (shipment) or over time (as we manufacture the product). The Company is first required to evaluate whether its contracts meet the criteria for 'over-time' or 'point-in-time' recognition. The Company has determined that for the majority of its contracts the Company is manufacturing products for which there is no alternative use due to the unique nature of the customer-specific product, IP and other contract restrictions. The Company has an enforceable right to payment including a reasonable profit for performance completed to date with respect to these contracts. As a result, revenue is recognized under these contracts 'over-time' based on the input cost-to-cost method as it better depicts the transfer of control. This input method is based on the ratio of costs incurred to date as compared to the total estimated costs at completion of the performance obligation. For all other contracts that do not meet these criteria, such as manufacturing contracts for which the terms do not provide an enforceable right to payment for performance completed to date, the Company recognizes revenue when it has transferred control of the related manufactured products which generally occurs upon shipment to the customer. Revenue from engineering services is recognized over time as costs related to the services are incurred, which approximates proportional performance of the service. This method is used because management considers it to be the best available measure of progress on the contracts. Revenue from scrap and excess inventory sales is recognized at the point-in-time of scrap at the customers direction, or, if applicable, shipment of the material to the customer. +The Company’s typical payment terms are 30 to 45 days and its sales arrangements do not contain any significant financing component for its customers. +The Company generally provides a warranty for workmanship on its manufacturing contracts. Although we offer warranties on our products, our warranties are considered to be assurance-type in nature and do not cover anything beyond ensuring that the product is functioning as intended. Based on the guidance in ASC 606, assurance-type warranties do not represent separate performance obligations; therefore, the primary performance obligation in the majority of our contracts is the delivery of a specific good through the purchase order submitted by our customer. +The Company elected to not disclose information about remaining performance obligations as they are part of contracts that that have expected durations of one year or less. +The Company has elected to expense costs to obtain contracts as incurred as these costs are immaterial to the financial statements. +During fiscal 2024, 2023 and 2022, no revenues were recognized from performance obligations satisfied or partially satisfied in previous periods. +54 +Contract Balances +A contract asset is recognized when the Company has recognized revenue, but has not issued an invoice for payment. Contract assets are classified separately on the condensed consolidated balance sheet and transferred to receivables when the right to payment becomes unconditional. +The following table summarizes the activity in the Company’s contract assets during the twelve months ended June 29, 2024 (in thousands): +Contract Assets +Beginning balance, July 1, 2023 +$ 29,925 +Revenue recognized 497,348 +Amounts collected or invoiced ( 506,023 ) +Ending balance, June 29, 2024 +$ 21,250 +The following table summarizes the activity in the Company’s contract assets during the twelve months ended July 1, 2023 (in thousands): +Contract Assets +Beginning balance, July 2, 2022 +$ 21,974 +Revenue recognized 590,624 +Amounts collected or invoiced ( 582,673 ) +Ending balance, July 1, 2023 +$ 29,925 +The following table summarizes the activity in the Company’s contract assets during the twelve months ended July 2, 2022 (in thousands): +Contract Assets +Beginning balance, July 3, 2021 +$ 24,781 +Revenue recognized 528,204 +Amounts collected or invoiced ( 531,011 ) +Ending balance, July 2, 2022 +$ 21,974 +Disaggregation of Revenue +The following table presents the Company’s revenue disaggregated for the twelve months ended June 29, 2024, the twelve months ended July 1, 2023, and the twelve months ended July 2, 2022 (in thousands): +Revenue +Recognition June 29, 2024 July 1, 2023 (Restated) July 2, 2022 (Restated) +Over-Time $ 497,348 $ 590,624 $ 528,193 +Point-in-Time 69,594 14,691 15,984 +Total $ 566,942 $ 605,315 $ 544,177 +Revenues and associated costs from engineering design, development services and tooling, which are performed under contract of short term durations, are recognized over time as the services are performed. +55 +13. LEASES +The Company has several commitments under operating and financing leases for warehouses, manufacturing facilities, office buildings, and equipment with initial terms that expire at various dates during the next 1 year to 10 years. +The Company has some leases that include an extension clause. Management has considered the likelihood of exercising each extension option included and estimated the duration of the extension option, for those leases management determined to be reasonably certain, in calculating the lease term for measurement of the right of use asset and liability. +For operating leases, management assumed a discount rate of 4.0 %. The weighted average discount rate is disclosed in the tables below. +The components of lease cost were as follows as of June 29, 2024, July 1, 2023 and July 2, 2022 (in thousands): +Year Ended Year Ended Year Ended +Lease cost Classification June 29, 2024 July 1, 2023 July 2, 2022 +Operating lease cost Cost of sales $ 4,814 $ 4,519 $ 6,442 +Operating lease cost Selling, general and administrative expenses $ 734 $ 737 $ 929 +Financing lease cost Cost of sales $ 4,865 $ 3,891 $ 2,054 +Financing lease cost Selling, general and administrative expenses $ 206 $ 161 $ 64 +Total lease cost $ 10,619 $ 9,308 $ 9,489 +Fixed lease cost $ 6,169 $ 8,171 $ 7,941 +Short-term lease cost 4,450 1,137 1,548 +Total lease cost $ 10,619 $ 9,308 $ 9,489 +56 +Amounts reported in the Consolidated Balance Sheet as of June 29, 2024, July 1, 2023 and July 2, 2022 were (in thousands, except weighted average lease term and discount rate): +June 29, 2024 July 1, 2023 July 2, 2022 +Operating Leases: +Operating lease right of use assets $ 15,416 $ 16,202 $ 16,731 +Operating lease liabilities (1) $ 15,416 $ 16,202 $ 16,731 +Weighted-average remaining lease term (in years) +Operating leases 3.97 4.55 5.28 +Weighted-average discount rate +Operating leases 4.00 % 4.00 % 4.00 % +Financing Leases (2): +Financing lease right of use assets $ 3,569 $ 9,718 $ 12,464 +Financing lease liabilities $ 2,128 $ 8,278 $ 11,211 +Weighted-average remaining lease term (in years) +Financing leases 1.06 1.89 2.56 +Weighted-average discount rate +Financing leases 11.18 % 9.96 % 8.82 % +(1) The current portion of the total operating lease liabilities of $ 5.1 million is classified under Other Current Liabilities , resulting in $ 10.3 million classified under Operating Lease Liabilities in the Long-term Liabilities section of the condensed consolidated balance sheet. +(2) The total finance lease right of use assets of $ 3.6 million is classified under Other Long-term Assets . The current portion of the total finance lease liabilities of $ 1.9 million is classified under Other Current Liabilities , resulting in $ 0.2 million classified in Other Long-term Liabilities section of the condensed consolidated balance sheet. +Future lease payments under non-cancellable leases as of June 29, 2024 are as follows (in thousands): +Fiscal Years Ending Operating Leases Finance Leases +2025 $ 5,104 $ 1,909 +2026 4,147 501 +2027 3,238 — +2028 2,281 — +2029 1,051 — +Thereafter 822 — +Total undiscounted lease payments 16,643 2,410 +Less: present value discount ( 1,227 ) ( 282 ) +Total lease liabilities $ 15,416 $ 2,128 +14. RESTATEMENT OF PREVIOUSLY ISSUED FINANCIAL STATEMENTS +In connection with the preparation of the Company's consolidated financial statements as of and for the year ended June 29, 2024, the Company concluded that cost recovery of material price variances was not being consistently recorded across its facilities. Material price variance occurs when the price the Company pays for materials exceeds the price quoted to customers, and the Company typically recovers the excess cost from customers through a sales price adjustment. Per Company policy, this +57 +cost recovery should be recorded as net sales when inventory enters the production process, however, certain of the Company’s facilities were recording the cost recovery as a reduction to cost of sales. These errors resulted in an understatement of both net sales and cost of sales for the years ended July 1, 2023 and July 2, 2022 (the "impacted annual periods"). As a result, the Company has restated its consolidated statements of operations for the impacted annual periods presented herein. The nature of the restatement adjustments shown below and their impact on the previously issued consolidated statements of operations is to increase net sales and increase cost of sales to appropriately reflect these transactions as sales price adjustments. +Fiscal Year Ended 7/1/2023 +CORRECTED CONSOLIDATED STATEMENT OF OPERATIONS (in thousands, except per share information) As previously reported Adjustments As restated +Net sales $ 588,135 $ 17,180 $ 605,315 +Cost of sales 540,663 17,180 557,843 +Gross profit 47,472 — 47,472 +Research, development and engineering expenses 9,735 — 9,735 +Selling, general and administrative expenses 25,715 — 25,715 +Gain on insurance proceeds, net of losses ( 4,301 ) — ( 4,301 ) +Total operating expenses 31,149 — 31,149 +Operating income 16,323 — 16,323 +Interest expense, net 10,023 — 10,023 +Income before income taxes 6,300 — 6,300 +Income tax provision 1,143 — 1,143 +Net income $ 5,157 $ — $ 5,157 +Net income per share — Basic $ 0.48 $ — $ 0.48 +Weighted average shares outstanding — Basic 10,762 — 10,762 +Net income per share — Diluted $ 0.47 $ — $ 0.47 +Weighted average shares outstanding — Diluted 10,938 — 10,938 +Fiscal Year Ended 7/2/2022 +CORRECTED CONSOLIDATED STATEMENT OF OPERATIONS (in thousands, except per share information) As previously reported Adjustments As restated +Net sales $ 531,815 $ 12,362 $ 544,177 +Cost of sales 488,601 12,362 500,963 +Gross profit 43,214 — 43,214 +Research, development and engineering expenses 9,821 — 9,821 +Selling, general and administrative expenses 24,598 — 24,598 +Gain on insurance proceeds, net of losses — — — +Total operating expenses 34,419 — 34,419 +Operating income 8,795 — 8,795 +Interest expense, net 5,104 — 5,104 +Income before income taxes 3,691 — 3,691 +Income tax provision 314 — 314 +Net income $ 3,377 $ — $ 3,377 +Net income per share — Basic $ 0.31 $ — $ 0.31 +Weighted average shares outstanding — Basic 10,762 — 10,762 +Net income per share — Diluted $ 0.31 $ — $ 0.31 +Weighted average shares outstanding — Diluted 11,063 — 11,063 +All referenced amounts for prior periods in these financial statements and the notes herein reflect the balances and amounts on a restated basis. +58 +15. RESTATEMENT AND REVISION OF INTERIM FINANCIAL INFORMATION +Restatement of Unaudited Consolidated Statements of Operations +In connection with the preparation of the Company’s consolidated financial statements as of and for the year ended June 29, 2024, the Company concluded that cost recovery of material price variances was not being consistently recorded across its facilities. Material price variance occurs when the price the Company pays for materials exceeds the price quoted to customers, and the Company typically recovers the excess cost from customers through a sales price adjustment. Per Company policy, this cost recovery should be recorded as net sales when inventory enters the production process, however, certain of the Company’s facilities were recording the cost recovery as a reduction to cost of sales. These errors resulted in an understatement of both net revenues and cost of sales for the quarters ended March 30, 2024, December 30, 2023, September 30, 2023, April 1, 2023, December 31, 2022, October 1, 2022, April 2, 2022, January 1, 2022, and October 2, 2022 (the “impacted quarterly periods”). As a result of these errors, the Company has restated its unaudited consolidated statements of operations for the impacted quarterly periods in the following tables. The unaudited consolidated balance sheets, statements of comprehensive income, shareholders’ equity and cash flows for the impacted quarters were not impacted by the errors noted above and have not been restated; provided, that the unaudited consolidated balance sheets as of March 30, 2024, December 30, 2023, September 30, 2023 have been revised as a result of error related to the adoption of ASU 326 as discussed below under "Revision of Unaudited Consolidated Balance Sheets." +59 +Interim periods - fiscal year 2024 (in thousands, except per share information) +CORRECTED CONSOLIDATED STATEMENT OF OPERATIONS As restated - three months ended 9/30/23 As restated - three months ended 12/30/23 As restated - three months ended 3/30/24 Three months ended 6/29/24 Twelve months ended 6/29/24 +Net sales $ 150,112 [1] $ 147,847 [2] $ 142,427 [3] $ 126,556 $ 566,942 +Cost of sales 139,250 [1] 136,084 [2] 134,346 [3] 117,383 527,063 +Gross profit 10,862 11,763 8,081 9,173 39,879 +Research, development and engineering expenses 2,241 1,758 2,234 2,100 8,333 +Selling, general and administrative expenses 5,784 6,057 6,422 6,956 25,219 +Gain on insurance proceeds, net of losses ( 431 ) — — — ( 431 ) +Total operating expenses 7,594 7,815 8,656 9,056 33,121 +Operating income 3,268 3,948 ( 575 ) 117 6,758 +Interest expense, net 3,011 2,961 2,800 3,173 11,945 +Income (loss) before income taxes 257 987 ( 3,375 ) ( 3,056 ) ( 5,187 ) +Income tax provision (benefit) ( 78 ) ( 97 ) ( 1,154 ) ( 1,071 ) ( 2,400 ) +Net income (loss) $ 335 $ 1,084 $ ( 2,221 ) $ ( 1,985 ) $ ( 2,787 ) +Net income (loss) per share — Basic $ 0.03 $ 0.10 $ ( 0.21 ) $ ( 0.18 ) $ ( 0.26 ) +Weighted average shares outstanding — Basic 10,762 10,762 10,762 10,762 10,762 +Net income (loss) per share — Diluted $ 0.03 $ 0.10 $ ( 0.21 ) $ ( 0.18 ) $ ( 0.26 ) +Weighted average shares outstanding — Diluted 11,003 10,889 10,762 10,762 10,762 +[1] - Includes an increase of $ 2,349 over amounts previously reported in the Net Sales and Cost of Sales lines, respectively. +[2] - Includes an increase of $ 2,430 over amounts previously reported in the Net Sales and Cost of Sales lines, respectively. +[3] - Includes an increase of $ 1,900 over amounts previously reported in the Net Sales and Cost of Sales lines, respectively. +60 +Interim periods - fiscal year 2023 (in thousands, except per share information) +CORRECTED CONSOLIDATED STATEMENT OF OPERATIONS As restated - three months ended 10/1/22 As restated - three months ended 12/31/22 As restated - three months ended 4/1/23 As restated - three months ended 7/1/23 As restated - twelve months ended 7/1/23 +Net sales $ 140,971 [1] $ 127,592 [2] $ 167,758 [3] $ 168,994 [4] $ 605,315 +Cost of sales 130,592 [1] 118,672 [2] 153,482 [3] 155,096 [4] 557,843 +Gross profit 10,379 8,920 14,276 13,898 47,472 +Research, development and engineering expenses 2,296 2,287 2,580 2,573 9,735 +Selling, general and administrative expenses 5,656 5,735 6,961 7,363 25,715 +Gain on insurance proceeds, net of losses ( 934 ) ( 2,710 ) ( 396 ) ( 261 ) ( 4,301 ) +Total operating expenses 7,018 5,312 9,145 9,675 31,149 +Operating income 3,361 3,608 5,131 4,223 16,323 +Interest expense, net 1,887 2,507 2,688 2,941 10,023 +Income before income taxes 1,474 1,101 2,443 1,282 6,300 +Income tax provision 322 134 467 220 1,143 +Net income $ 1,152 $ 967 $ 1,976 $ 1,062 $ 5,157 +Net income per share — Basic $ 0.11 $ 0.09 $ 0.18 $ 0.10 $ 0.48 +Weighted average shares outstanding — Basic 10,762 10,762 10,762 10,762 10,762 +Net income per share — Diluted $ 0.11 $ 0.09 $ 0.18 $ 0.10 $ 0.47 +Weighted average shares outstanding — Diluted 10,832 10,832 10,865 10,996 10,938 +[1] - Includes an increase of $ 3,708 over amounts previously reported in the Net Sales and Cost of Sales lines, respectively. +[2] - Includes an increase of $ 3,884 over amounts previously reported in the Net Sales and Cost of Sales lines, respectively. +[3] - Includes an increase of $ 3,205 over amounts previously reported in the Net Sales and Cost of Sales lines, respectively. +[4] - Includes an increase of $ 6,384 over amounts previously reported in the Net Sales and Cost of Sales lines, respectively. +61 +Interim periods - fiscal year 2022 (in thousands, except per share information) +CORRECTED CONSOLIDATED STATEMENT OF OPERATIONS As restated - three months ended 10/2/21 As restated - three months ended 1/1/22 As restated - three months ended 4/2/22 As restated - three months ended 7/2/22 As restated - twelve months ended 7/2/22 +Net sales $ 133,130 [1] $ 136,407 [2] $ 140,714 [3] $ 133,926 [4] $ 544,177 +Cost of sales 122,992 [1] 126,599 [2] 129,206 [3] 122,166 [4] 500,963 +Gross profit 10,138 9,808 11,508 11,760 43,214 +Research, development and engineering expenses 2,449 2,498 2,526 2,348 9,821 +Selling, general and administrative expenses 5,595 5,659 6,193 7,151 24,598 +Gain on insurance proceeds, net of losses — — — — — +Total operating expenses 8,044 8,157 8,719 9,499 34,419 +Operating income 2,094 1,651 2,789 2,261 8,795 +Interest expense, net 992 1,095 1,551 1,466 5,104 +Income before income taxes 1,102 556 1,238 795 3,691 +Income tax provision (benefit) 287 ( 31 ) 231 ( 173 ) 314 +Net income $ 815 $ 587 $ 1,007 $ 968 $ 3,377 +Net income per share — Basic $ 0.08 $ 0.05 $ 0.09 $ 0.09 $ 0.31 +Weighted average shares outstanding — Basic 10,762 10,762 10,762 10,762 10,762 +Net income per share — Diluted $ 0.07 $ 0.05 $ 0.09 $ 0.09 $ 0.31 +Weighted average shares outstanding — Diluted 11,052 11,057 11,062 11,071 11,063 +[1] - Includes an increase of $ 368 over amounts previously reported in the Net Sales and Cost of Sales lines, respectively. +[2] - Includes an increase of $ 1,951 over amounts previously reported in the Net Sales and Cost of Sales lines, respectively. +[3] - Includes an increase of $ 2,323 over amounts previously reported in the Net Sales and Cost of Sales lines, respectively. +[4] - Includes an increase of $ 7,720 over amounts previously reported in the Net Sales and Cost of Sales lines, respectively. +Revision of Unaudited Consolidated Balance Sheets +In addition, in connection with the preparation of the Company’s consolidated financial statements as of and for the year ended June 29, 2024, the Company concluded that it had not recorded an immaterial adjustment related to its adoption on July 2, 2023 of ASU 2016-13 Financial Instruments - Credit Losses (ASU 326): Measurement of Credit Losses on Financial Instruments . As of July 2, 2023, the Company should have performed an assessment and recorded any adjustment as a modified retrospective adjustment through its opening retained earnings balance. The error resulted in an immaterial overstatement of accounts receivable, contract assets, other assets and retained earnings as of March 30, 2024, December 30, 2023 and September 30, 2023. Given the restatement described above, the Company elected to revise its unaudited consolidated balance sheets as of March 30, 2024, December 30, 2023 and September 30, 2023 in the following tables. The related unaudited consolidated statements of operations, statements of comprehensive income, shareholders’ equity and cash flows were not materially impacted by this error and have not been revised for this matter. +62 +CORRECTED CONSOLIDATED BALANCE SHEETS (in thousands) As revised - as of 9/30/23 As revised - as of 12/30/23 As revised - as of 3/30/24 +ASSETS +Current assets: +Cash and cash equivalents $ 3,574 $ 2,953 $ 5,255 +Trade receivables, net of credit losses [1] 138,463 $ 131,913 $ 132,663 +Contract assets [1] 32,878 $ 27,745 $ 28,594 +Inventories 126,778 $ 124,054 $ 115,115 +Other [1] 21,700 $ 21,382 $ 20,994 +Total current assets 323,393 $ 308,047 $ 302,621 +Property, plant and equipment, net 28,085 $ 28,935 $ 29,046 +Operating lease right-of-use assets, net 15,928 $ 18,104 $ 16,790 +Other assets: +Deferred income tax asset [1] 14,161 $ 14,117 $ 15,533 +Other 7,500 $ 6,243 $ 6,109 +Total other assets 21,661 $ 20,360 $ 21,642 +Total assets $ 389,067 $ 375,446 $ 370,099 +LIABILITIES AND SHAREHOLDERS ’ EQUITY +Current liabilities: +Accounts payable $ 101,638 $ 91,358 $ 82,198 +Accrued compensation and vacation 11,860 $ 5,677 $ 7,071 +Current portion of long-term debt 2,886 $ 3,068 $ 3,094 +Other 16,640 $ 18,263 $ 17,040 +Total current liabilities 133,024 $ 118,366 $ 109,403 +Long-term liabilities: +Long-term debt, net 115,789 $ 114,894 $ 122,193 +Operating lease liabilities 10,939 $ 12,380 $ 11,351 +Deferred income tax liability 324 22 $ 19 +Other long-term obligations 1,201 627 $ 336 +Total long-term liabilities 128,253 127,923 $ 133,899 +Total liabilities 261,277 246,289 $ 243,302 +Commitments and contingencies (Note 9) +Shareholders’ equity: +Common stock, no par value—shares authorized 25,000 ; issued and outstanding 10,762 , 10,762 , and 10,762 shares, respectively +47,786 47,839 47,891 +Retained earnings [1] 80,043 81,127 78,906 +Accumulated other comprehensive (loss) income ( 39 ) 191 — +Total shareholders’ equity 127,790 129,157 126,797 +Total liabilities and shareholders’ equity $ 389,067 $ 375,446 370,099 +[1] - Each presented period includes a reduction for expected credit losses of $( 2,979 ) related to receivables, $( 1,230 ) related to Other, $( 25 ) related to Contract Assets, $ 956 related to deferred income tax asset, and $( 3,278 ) related to Retained Earnings. These adjustments serve to reflect a modified retrospective adoption of ASC 326 - Financial Instruments, Credit Losses. The related tax-effects and subsequent inter-period adjustments are considered immaterial for presentation on an interim basis. +63 +Item 9: CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES +None +Item 9A: CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +It is the responsibility of our management to establish, maintain, and monitor disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 (the “Exchange Act”) are recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Additionally, these disclosure controls include controls and procedures that are designed to accumulate and communicate the information required to be disclosed to our Chief Executive Officer and Chief Financial Officer, allowing for timely decisions regarding required disclosures. +As of the end of the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b). +Based on our assessment, we believe that as of June 29, 2024, the Company’s disclosure controls and procedures were not effective as a result of the material weaknesses in internal control over financial reporting discussed below. +Management’s Report on Internal Control over Financial Reporting +Our management has the responsibility to establish and maintain adequate internal control over our financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. Our internal controls are designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our external financial statements in accordance with generally accepted accounting principles (GAAP). +Due to inherent limitations of any internal control system, management acknowledges that there are limitations as to the effectiveness of internal controls over financial reporting and therefore recognize that only reasonable assurance can be gained from any internal control system. Accordingly, our internal control system may not detect or prevent material misstatements in our financial statements and projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, we have performed an assessment of the effectiveness of our internal controls over financial reporting as of June 29, 2024. This assessment was based on the criteria established in Internal Control-Integrated Framework (2013), issued by the Committee of Sponsoring Organizations (“COSO”) of the Treadway Commission. Based on our assessment, management concluded that the Company's internal control over financial reporting was not effective as of June 29, 2024 due to the material weaknesses described below. +A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weaknesses have been identified: +The Company did not fully maintain components of the COSO framework, including elements of the control environment, risk assessment, control activities, and monitoring activities components, relating to: (i) sufficiency of processes to identify and analyze risks to the achievement of objectives across the entity, (ii) sufficiency of competent personnel with appropriate levels of knowledge, experience, and training in accounting, and internal control matters to perform assigned responsibilities and have appropriate accountability for the design and operation of internal control over financial reporting; (iii) sufficiency of procedures to select and develop control activities that contribute to the mitigation of risks, and (iv) performing ongoing evaluations to ascertain whether the components of internal control are present and functioning. +The entity level material weaknesses contributed to material weaknesses within the Company’s financial close and reporting processes as follows: +• The Company did not design and implement effective controls over the adoption of new accounting standards. +• The Company did not design and implement effective controls over the accounting for revenue recognition relating to cost recovery of material price variances. +64 +These material weaknesses resulted in the restatement of our consolidated financial statements as of and for the years ended July 1, 2023 and July 2, 2022 and our unaudited consolidated statements of operations for the quarters ended March 30, 2024, December 30, 2023, September 30, 2023, April 1, 2023, December 31, 2022, October 1, 2022, April 2, 2022, January 1, 2022 and October 2, 2021, and revision of our unaudited consolidated balance sheets as of March 30, 2024, December 30, 2023, and September 30, 2023. +As a result of this determination, management has taken, and is in the process of taking, the following actions to remediate the identified material weaknesses in its internal control over financial reporting: +• Training related to the proper accounting for material price variances +• Enhancing closing process documentation related to material price variances +• Hiring of technical accounting finance staff with US GAAP knowledge and experience; and +• Enhance closing process documentation related to adoption of new accounting standards +We will continue to assess the effectiveness of our controls and remediation efforts in connection with our future assessments of the effectiveness of internal control over financial reporting and disclosure controls and procedures. +Changes in Internal Control over Financial Reporting +There have been no significant changes in our internal control over financial reporting during our fourth fiscal quarter ended June 29, 2024 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f)). +65 +Item 9B: OTHER INFORMATION +During the fiscal year ended June 29, 2024, none of our directors or officers adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as defined in Regulation S-K, Item 408. +Item 9C: +DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS +Not applicable. +PART III +Item 10: DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE +Directors of the Registrant +Information on the nominees for election as Directors of the Company is incorporated herein by reference from the Company’s definitive proxy statement for the 2024 Annual Meeting of Shareholders to be filed pursuant to Regulation 14A under the Exchange Act no later than 120 days after the end of the Company’s 2024 fiscal year (the “2024 Proxy Statement”). +Executive Officers of the Registrant +This information is included in a separate item captioned “Executive Officers of the Registrant” in Item 1 of Part 1 of this Annual Report on Form 10-K pursuant to Instruction G(3) of Form 10-K and Instruction 3 to Item 401(b) of Regulation S-K and is incorporated herein by reference. +Compliance with Section 16(a) of the Exchange Act: +Information under the caption “Delinquent Section 16(a) Reports” in the Company’s 2024 Proxy Statement is incorporated herein by this reference. +Code of Conduct +The Board of Directors has adopted a written Code of Conduct which applies to its directors and employees, including its executive officers. The Code of Conduct is available on the Company’s website at www.keytronic.com . The Company intends to disclose on its website any amendments to or waivers of the Code of Conduct. +Item 11: EXECUTIVE COMPENSATION +Information appearing under the caption “Executive Compensation” in the Company’s 2024 Proxy Statement is incorporated herein by this reference. +Item 12: SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +Information under the captions “Beneficial Ownership of Securities” and "Equity Compensation Plan Information" in the Company’s 2024 Proxy Statement is incorporated herein by this reference. +66 +Item 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions” and “Directors’ Independence” in the Company’s 2024 Proxy Statement is incorporated herein by this reference. +Item 14: PRINCIPAL ACCOUNTANT FEES AND SERVICES +Our independent registered public accounting firm is Moss Adams LLP , Seattle, Washington , Auditor Firm ID: 659 . +Information appearing under the caption “Principal Accountant Fees and Services” in the Company’s 2024 Proxy Statement is incorporated herein by this reference. +PART IV +Item 15: EXHIBITS AND FINANCIAL STATEMENT SCHEDULES +(a) 1. FINANCIAL STATEMENTS +Page in Form 10-K +FINANCIAL STATEMENTS +Report of Independent Registered Public Accounting Firm (Moss Adams, LLP) +32 +Consolidated Balance Sheets +34 +Consolidated Statements of Income +35 +Consolidated Statements of Comprehensive Income +36 +Consolidated Statements of Cash Flows +37 +Consolidated Statements of Shareholders’ Equity +38 +Notes to Consolidated Financial Statements +35 +67 +3. EXHIBITS +Exhibit No. Description +3.1 +Articles of Incorporation, incorporated by reference to Exhibit 3.1 to the Company’s Form 10-K for the year ended July 3, 2021 , +3.2 +Bylaws, as amended, incorporated by reference to Exhibit 3.2 to the Company’s Form 10-K for the year ended July 3, 2021 +4.1 +Description of the Company’s securities, incorporated by reference to Exhibit 4.1 to the Company’s Form 10-K for the year ended July 3, 2021 +10.1* +2010 Incentive Plan, as amended and restated October 23, 2014, incorporated by reference to Appendix A to the Company’s 2014 Proxy Statement +10.2* +Form of Restricted Stock Unit Grant Notice and Agreement, submitted herewith +10.3* +Description of Employment Cont r act of Craig D. Gates, incorporated by reference to the Company’s 1998 Proxy Statement, pages 10 and 11 +10.4* +Addenda to Employment Contract of Craig D. Gates, incorporated by reference to Exhibit 10.4 to the Company’s Form 10-Q for the quarter ended January 1, 2000 +10.5* +Addenda to Employment Contract of Craig D. Gates, incorporated by reference to Exhibit 10.2 to the Company’s Form 10-K for the year ended June 29, 2002 +10.6* +Amendment to Employment Contract of Craig D. Gates, dated August 23, 2011 incorporated by reference to Exhibit 10.40 to the Company’s Form 10-K for the year ended July 2, 2011 +10.7* +Amendment to Employment Contract of Craig D. Gates, dated May 10, 2012, incorporated by reference to Exhibit 10.1 to the Company’s Form 10-Q for the quarter ended March 31, 2012 +10.8* +Consulting Agreement of Craig D. Gates, dated June 20, 2024, submitted herewith +10.9* +Employment Contract of Brett R. Larsen, dated April 22, 2010, including the Amendment to Employment Contract, dated August 23, 2011, and the Amendment to Employment Contract, dated May 11, 2012, submitted herewith +10.10* +Employment Contract of Anthony G. Voorhees, dated August 3, 2022, submitted herewith +10.11* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2020 and Fiscal Years 2020 – 2022 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 30, 2019 +10.12* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2021 and Fiscal Years 2021 – 2023 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed July 27, 2020 +10.13* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2022 and Fiscal Years 2022 – 2024 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 13, 2021 +68 +10.14* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2023 and Fiscal Years 2023 – 2025 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 4, 2022 +10.15* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2024 and Fiscal Years 2024 – 2026 Long Term Incentive Plan Performance Measures and Awards incorporated by reference to the Company’s Form 8-K filed August 17, 2023 +10.16* +Summary of Incentive Compensation Plan Performance Goals and Target Payments for Fiscal Year 2025 and Fiscal Years 2025-2027 Long Term Incentive Plan Performance Measures and Awards, incorporated by reference to the Company’s Form 8-K filed on September 9, 2024 +10.17 +Announcement that the Company has signed a letter of intent to lease a new facility in Da Nang, Vietnam +10.18 +Stock Purchase Agreement, dated September 3, 2014, by and among the Company, CDR Manufacturing Inc. and the sellers signatory thereto, incorporated by reference to Exhibit 2.1 to the Company’s Form 8-K filed on September 9, 2014 +10.19 +Loan and Security Agreement, dated August 14, 2020, among the Company, Bank of America, N.A, and certain other parties, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed August 17, 2020 +10.20 +First Amendment to Loan and Security Agreement, dated November 10, 2020, among the Company, Bank of America, N.A, and certain other parties, incorporated by reference to Exhibit 10.1 to the Company’s Form 10-K for the year ended July 2, 2022 +10.21 +Second Amendment to Loan and Security Agreement, dated September 3, 2021, among the Company, Bank of America, N.A, and certain other parties, incorporated by reference to Exhibit 10.2 to the Company’s Form 8-K filed September 10, 2021 +10.22 +Third Amendment to Loan and Security Agreement, dated August 26, 2022, among the Company, Bank of America, N.A, and certain other parties, incorporated by reference to Exhibit 10.2 to the Company’s Form 10-K for the year ended July 2, 2022 +10.23 +Fourth Amendment to Loan, Guaranty and Security Agreement, dated March 29, 2024, among the Company, Bank of America, N.A., and certain other parties, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed May 13, 2024 +10.24 +Fifth Amendment to Loan, Guaranty and Security Agreement, dated September 27, 2024, among the Company, Bank of America, N.A., and certain other parties, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed October 1, 2024 +10.25 +Sixth Amendment to Loan, Guaranty and Security Agreement, dated October 9, 2024, among the Company, Bank of America, N.A., and certain other parties, incorporated by reference to Exhibit 10.1 to the Company’s Form 8-K filed October 10, 2024 +21.1 +Subsidiaries of Registrant, submitted herewith +23.1 +Consent of Independent Registered Public Accounting Firm - Moss Adams LLP, submitted herewith +31.1 +Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer, submitted herewith +31.2 +Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer, submitted herewith +69 +32.1 +Section 1350 Certification of Chief Executive Officer, submitted herewith +32.2 +Section 1350 Certification of Chief Financial Officer, submitted herewith +97.1 +Policy Relating to Recovery of Erroneously Awarded Compensation, submitted herewith +101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. +101.SCH XBRL Taxonomy Extension Schema Document ** +101.CAL XBRL Taxonomy Extension Calculation Linkbase Document ** +101.DEF XBRL Taxonomy Extension Definition Linkbase Document ** +101.LAB XBRL Taxonomy Extension Label Linkbase Document ** +101.PRE XBRL Taxonomy Extension Presentation Linkbase Document ** +104 Cover Page Interactive Data File (formatted as inline XBRL with applicable taxonomy extension information contained in Exhibits 101.INS, 101.SCH, 101.CAL, 101.DEF, 101.LAB and 101.PRE) +* Management contract or compensatory plan or arrangement +** Pursuant to Rule 406T of Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, or Section 18 of the Securities and Exchange Act of 1934, as amended and otherwise are not subject to liability under those sections. +Item 16: FORM 10-K SUMMARY +None +70 +22 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +Dated: October 15, 2024 +KEY TRONIC CORPORATION +By: /s/ Brett R. Larsen +Brett R. Larsen, President and Chief Executive Officer +(Principal Executive Officer) +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated: +/s/ Brett R. Larsen October 15, 2024 +Brett R. Larsen Date +President and Chief Executive Officer +(Principal Executive Officer) +/s/ Anthony G. Voorhees October 15, 2024 +Anthony G. Voorhees Date +Executive Vice President of Administration, Chief Financial Officer and Treasurer +(Principal Financial Officer and Principal Accounting Officer) +/s/ Ronald F. Klawitter October 15, 2024 +Ronald F. Klawitter, Director and Chairman of the Board Date +/s/ Craig D. Gates October 15, 2024 +Craig D. Gates, Director Date +/s/ James R. Bean October 15, 2024 +James R. Bean, Director Date +/s/ Subodh K. Kulkarni October 15, 2024 +Subodh K. Kulkarni, Director Date +/s/ Yacov A. Shamash October 15, 2024 +Yacov A. Shamash, Director Date +/s/ Cheryl Beranek October 15, 2024 +Cheryl Beranek, Director Date +71 \ No newline at end of file diff --git a/raw/filings/0000719733/2024/0000719733-24-000113/filing_metadata.csv b/raw/filings/0000719733/2024/0000719733-24-000113/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..6cbe6db447c91a09908fbd230f4b65a71a775574 --- /dev/null +++ b/raw/filings/0000719733/2024/0000719733-24-000113/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0000719733,KTCC,KEY TRONIC CORP,10-K,2024-10-15,2024-06-29,2024-10-15T19:37:24.000Z,0000719733-24-000113,ktcc-20240629.htm,10-K,11325854,1,1,https://www.sec.gov/Archives/edgar/data/719733/000071973324000113/ktcc-20240629.htm,https://www.sec.gov/Archives/edgar/data/719733/000071973324000113/,2024,2024,1 diff --git a/raw/filings/0000719733/2024/0000719733-24-000113/item1.txt b/raw/filings/0000719733/2024/0000719733-24-000113/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..1b44ae5ddbc3f018d8eb434977728955e88b7aca --- /dev/null +++ b/raw/filings/0000719733/2024/0000719733-24-000113/item1.txt @@ -0,0 +1,74 @@ +Item 1. BUSINESS +Background +Key Tronic Corporation was organized in 1969, as a Washington corporation that locally manufactured computer keyboards. The ability to design, build and deliver a quality product led us to become a leading independent manufacturer of keyboards for computers in the United States. Our fully integrated design, tooling, and automated manufacturing capabilities enabled us to rapidly respond to customers’ needs for keyboards in production quantities worldwide. We supported our sales growth through the development and purchase of international manufacturing facilities. As the computer keyboard market matured with increasing competition from other international providers, we determined that our business could no longer solely rely on keyboard sales. +After assessing market conditions and our strengths and capabilities, we shifted our focus from keyboard manufacturing to contract manufacturing for a wide range of products. Our unique strategic attributes are based on our core strengths of innovative design and engineering expertise in electronics, mechanical engineering, sheet metal fabrication and stamping, and precision plastics combined with high-quality, low cost production, and assembly on an international basis while providing exceptional customer service. These strengths have made our company a strong competitor in the contract manufacturing market. +Our Industry and Strategy +The expansion of the contract manufacturing industry and our acquisitions have allowed us to continue to expand our customer base and the industries that we serve. The increase in new programs represents a growing portion of our revenue and a promising foundation for our future. In keeping with our long-term strategic objectives, we have been successfully building a more diversified customer portfolio, spanning a wider range of industries. We currently offer our customers the following services: integrated electronic and mechanical engineering, precision plastic molding, sheet metal fabrication, printed circuit board (PCB) and complete product assembly, component selection, sourcing and procurement, worldwide logistics, and new product testing and production all at competitive pricing due to our global footprint. We differentiate ourselves from others our size and larger in the contract manufacturing industry by providing vertical integration, a flexible and responsive approach to our customer’s changing supply demand, and complete design engineering support. +We believe that we are well positioned in the contract manufacturing industry to continue the expansion of our customer base and achieve long-term growth. Our unique blend of multinational facilities, vertical integration, centralized management, and core strengths continue to support our growth and our customers’ needs. We continue to focus on controlling operating expenses and leveraging the synergistic capabilities of our world-class facilities in the United States, Mexico, China, and Vietnam. This international production capability provides our customers with the benefits of improved supply-chain management, reduced inventory, lower labor costs, lower transportation costs, and reduced product fulfillment time. Given our competitive advantages and the growing pressure for new potential customers to move forward with their outsourcing strategies, we feel that we are strongly positioned to win new business in coming periods and grow our revenue and profits. +The contract manufacturing industry is intensely competitive. Although our customer base is growing, we still have less than 1% of the potential global market and our revenue can fluctuate significantly due to reliance on a concentrated base of customers. We are planning for new customer growth in the coming quarters by seeking to secure new programs with new and existing customers, increase our worldwide manufacturing capacity, leverage further our design engineering capabilities and continue to improve our manufacturing and procurement processes and capabilities. Ongoing challenges that we face include but are not limited to the following: continuing to win programs from new and existing customers, balancing capital employed, production capacity and key personnel in support of new customer programs, improving operating efficiencies, controlling costs while developing competitive pricing strategies, and successfully transitioning new program wins to full production. +Customers and Marketing +We provide a mix of manufacturing services for outsourced Original Equipment Manufacturing (OEM) products. We provide the following services: product design, surface mount technologies (SMT) and pin through hole capability for printed circuit board assembly, tool making, precision plastic molding, sheet metal fabrication and painting, liquid injection molding, complex assembly, prototype design and full product assembly. +Sales of the majority of our products have not historically been seasonal in nature, but may be seasonal in the future if there are changes in the types of products manufactured. Sales can, however, fluctuate significantly between quarters from changes in customers and customer demand due to the concentration of sales generated by our largest customers. +5 +For the fiscal years 2024, 2023, and 2022, the five largest customers in each year accounted for 34 percent, 35 percent, and 39 percent of combined total net sales, respectively. We aim to diversify our customer base by adding additional programs and customers. We expect net sales to our five largest customers as a percentage of total net sales to approximate current levels going forward. +The following table summarizes the customers that represented 10 percent or more of total net sales during the last two fiscal years: +Percentage of Net Sales by Fiscal Year +2024 2023 2022 +Customer A 20% 12% 12% +Customer B * * 13% +There can be no assurance that the Company’s principal customers will continue to purchase products from the Company at current levels. Moreover, the Company typically does not enter into long-term volume purchase contracts with its customers, and the Company’s customers have certain rights to extend or delay the shipment of their orders. The loss of one or more of the Company’s major customers, or the reduction, delay or cancellation of orders from such customers, could materially and adversely affect the Company’s business, operating results and financial condition. +We market our products and services primarily through our direct sales department which is comprised of strategically located field sales people and distributors. We also maintain relationships with several independent sales organizations to assist in marketing our product lines. +Manufacturing +We have continually made investments in developing and expanding a capital equipment base to achieve vertical integration and efficiencies in our manufacturing processes. We have invested significant capital into SMT for volume manufacturing of complex printed circuit board assemblies and in our metal shop providing precision metal stamping, fabricating, and finishing. We also design and develop tooling for injection molding and sheet metal fabrication and manufacture the majority of plastic and sheet metal parts used in the products we manufacture. Additionally, we have equipment to maintain a controlled clean environment for manufacturing processes that require a high level of precise control. +We use a variety of manual and automated assembly processes in our facilities, depending upon product complexity and degree of customization. Some examples of automated processes include component insertion, SMT, selective soldering, flexible robotic assembly, computerized vision system quality inspection, laser turrets, automated switch and key top installation, robotic welding, automated powder coat application, and automated functional testing. +Our engineering expertise and automated manufacturing processes enable us to work closely with our customers during the design and prototype stages of production and to jointly increase productivity and reduce response time to the marketplace. We use computer-aided design techniques and software to assist in preparation of the tool design layout and component placement, to reduce tooling and production costs, improve component and product quality, and enhance turnaround time during product development. +We purchase materials and components for our products from many different suppliers, including both domestic and international sources. We develop close working relationships with our suppliers, many of whom have been supplying products to us for several years. +Research, Development, and Engineering +As part of our long-term strategy, we are committed to supporting our customers by providing research, development, and engineering services. We have seen an increase in the success of providing design support on existing and potential customers in differentiating ourselves. We believe these services allow us to facilitate in optimizing new product designs, and the production processes of our customers’ programs. +Research, development, and engineering (RD&E) expenses consist principally of employee related costs, third party development costs, program materials costs, depreciation, and allocated information technology and facilities costs. +Competition +The market for the products and services we provide is highly competitive. There are numerous competitors in the contract manufacturing industry, many of which have substantially more resources and are more geographically diverse than we are. Some of our competitors have similar international production capabilities, large financial resources and some have +6 +substantially greater manufacturing, research and development, and marketing resources. There is also competition from the manufacturing operations of our current and potential customers, who are continually evaluating the merits of manufacturing their products internally versus the advantages of outsourcing. We believe that we can currently compete favorably in these areas primarily on the basis of our international footprint, responsiveness, creativity, vertical production capability, quality, and cost. +Trademarks +Our name and logo are federally registered trademarks, and we believe they are valuable assets of our business. +Employees +We consider our employees to be our primary strength and we make considerable efforts to maintain a well-qualified workforce. Our employee benefits include bonus programs involving periodic payments to all employees based on meeting quarterly or fiscal year performance targets. We regularly provide transportation, medical services, and meals to all of our employees in foreign locations. The Company also has defined contribution plans available to U.S. employees who have attained age 21 and provide group health, life, and disability insurance plans. We also maintain share-based compensation plans and other long-term incentive plans for certain employees and outside directors. +As of June 29, 2024, we had 4,122 full-time employees compared to 5,447 on July 1, 2023. Since we can have significant fluctuations in product demand, we seek to maintain flexibility in our workforce by utilizing skilled temporary labor in some of our manufacturing facilities in addition to full-time employees. +Backlog +On June 29, 2024, our order backlog was valued at approximatel y $249.6 million, compared to approximately $343.0 million on July 1, 2023. The amount of backlog is not necessarily indicative of future sales but can be indicative of trends in expected future sales revenue. Due to the relationships with our customers, we will occasionally allow orders to be canceled or rescheduled and as a result it is not a meaningful indicator of future financial results. If there are canceled or rescheduled orders, we typically negotiate fees to cover the costs we have incurred. Order backlog consists of purchase orders received for products expected to be shipped approximately within the next twelve months, although shipment dates are subject to change due to design modifications, customer forecast changes, or other customer requirements. +Foreign Markets +Information concerning net sales and long-lived assets (property, plant, and equipment) by geographic areas is set forth in Note 11 - “Enterprise-Wide Disclosures” of the “Notes to Consolidated Financial Statements” of this Annual Report on Form 10-K and that information is incorporated herein by reference. +Governmental Regulation +Our operations are subject to certain foreign, federal, state and local regulations relating to, among others, environmental, waste management, labor and health and safety matters. We have implemented processes and procedures to help ensure that our operations are in substantial compliance with all applicable regulations. However, material costs and liabilities may arise from these requirements or from new or modified requirements, which could have a material adverse effect on our business and results of operations. +Information about Our Executive Officers +The table below sets forth the name, current age, and current position of our executive officers and other significant employees: +Name Age Positions Held +Executive Officers +Brett R. Larsen 51 President and Chief Executive Officer +Anthony G. Voorhees 50 Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Philip S. Hochberg 62 Executive Vice President of Customer Relations and Integration +Duane D. Mackleit 56 Executive Vice President of Operations +David H. Knaggs 43 Executive Vice President of Quality, Regulatory Affairs, and Information Systems +Chad T. Orebaugh 53 Executive Vice President of Engineering +Mark Courtney 58 Vice President of Supply Chain +7 +Executive Officers +BRETT R. LARSEN – President and Chief Executive Officer +Mr. Larsen, age 51, has served as President and Chief Executive Officer since July 2024. Previously he was the Executive Vice President of Administration, Chief Financial Officer, and Treasurer from July 2015 through June 2024. He was Vice President of Finance and Controller from February 2010 to July 2015. He was Chief Financial Officer of FLSmidth Spokane, Inc. from December 2008 to February 2010. From October 2005 through November 2008, Mr. Larsen served as Controller of Key Tronic Corporation. From May 2004 to October 2005, Mr. Larsen served as Manager of Financial Reporting of Key Tronic Corporation. From 2002 to May 2004, Mr. Larsen was an audit manager for the public accounting firm BDO USA, LLP. He also held various auditing and supervisory positions with Grant Thornton LLP from 1997 to 2002. Mr. Larsen has a Bachelor of Science degree in Accounting and a Masters degree in Accounting from Brigham Young University and is a Certified Public Accountant. +ANTHONY G. VOORHEES - Executive Vice President of Administration, Chief Financial Officer, and Treasurer +Mr. Voorhees, age 50, has served as Executive Vice President of Administration, Chief Financial Officer, and Treasurer since July 2024. Previously, he was Vice President of Finance and Controller from November 2021 to June 2024, Senior Manager of Corporate Finance from July 2015, and Manager of Financial Reporting since April 2010. Prior to joining Key Tronic, Mr. Voorhees worked at Coldwater Creek from August 2007 to March 2010 as a Senior Financial Reporting Accountant. Prior to that, he worked at Moss Adams, LLP as a Senior Assurance Associate from November 2004 to August 2007. Between September 2001 and August 2004, Mr. Voorhees held senior level accounting positions at Boise State University and Idaho State Department of Agriculture. Mr. Voorhees has a bachelor degree in Accounting from the University of Idaho and is a Certified Public Accountant. +PHILIP S. HOCHBERG – Executive Vice President of Customer Relations and Integration +Mr. Hochberg, age 62, has been Executive Vice President of Customer Relations and Integration since July 2012. Prior to this, Mr. Hochberg served as Vice President of Business Development from October 2009 through June 2012. He was Director of Business Development and Program Management from July 2008 to October 2009. Mr. Hochberg served as Director of Business Development from October 2004 to July 2008 and as Director of EMS Sales and Marketing from July 2000 to October 2004. Prior to joining Key Tronic, Mr. Hochberg worked for Quinton Instrument Company as their Director of Marketing and Product Management from 1992 to 2000. From 1988 to 1992, he was employed by SpaceLabs Medical as their Business Development Marketing Manager. Mr. Hochberg has an MBA from the University of British Columbia, a BA in Psychology, with a minor in Business from Washington University in St. Louis. +DUANE D. MACKLEIT – Executive Vice President of Operations +Mr. Mackleit, age 56, has been Executive Vice President of Operations since December 2019. Prior to this, Mr. Mackleit served as Vice President of Program Management since July 2012. He served as Director of Program Management from July 2008 through June 2012. From May 2006 to July 2008 he served as Principal Program Manager. Prior to that, he served as Program Manager from March 2002 to May 2006 and Associate Program Manager from August 2000 to March 2002. Mr. Mackleit has also held several other positions with Key Tronic Corporation. Mr. Mackleit has an AA in Business from Spokane Falls Community College and a BA in Business/Marketing from Eastern Washington University. He also holds a MBA from Gonzaga University. +DAVID H. KNAGGS – Executive Vice President of Quality, Regulatory Affairs, and Information Systems +Mr. Knaggs, age 43, has been Executive Vice President of Quality, Regulatory Affairs, and Information Systems since May 2021. Previously, he was Vice President of Quality and Regulatory Affairs from November 2017 to May 2021. He was Vice President of Quality since October 2016. Before joining Key Tronic, Mr. Knaggs worked at Telect, Inc. from 2008 to 2016 as their Director of Engineering. Prior to that, he worked at Isothermal Systems Research as Lead Systems Engineer from 2003 to 2008. He has a Bachelor of Science degree in Mechanical Engineering with a minor in mathematics from the University of Washington. +CHAD T. OREBAUGH – Executive Vice President of Engineering +Mr. Orebaugh, age 53, has been Executive Vice President of Engineering since September 2021. Previously he served as Vice President of Engineering since April 2017. Prior to this, Mr. Orebaugh served as Director of Engineering since May 2013. From April 2010 to May 2013, he served as Manager of Engineering. From January 2000 to April 2010 he served as Lead Mechanical Engineer. Prior to that, he served as Mechanical Engineer from October 1998 to January 2000 and Associate Mechanical Engineer since October 1997. Mr. Orebaugh holds a BA in Mechanical Engineering from Gonzaga University. +MARK COURTNEY – Vice President of Supply Chain +8 +Mark Courtney, age 58, has been Vice President of Supply Chain of the company since August 2019. Previously, he served as Purchasing Manager and Director of North American Purchasing from September 2015 to August 2019, and as Supply Chain Manager, ERP and Business Operations Manager for Amphenol Telect from August 2007 to September 2015. From March 2006 to August 2007, he served as Senior Buyer/Planner for Honeywell Specialty Materials and from June 2005 to March 2006 as Purchasing Manager for MRV Communications. From May 2000 to June 2005, he served as a Field and Inside Sales Associate for Arrow Electronics and from October 1991 to May 2000 held various positions at Alesis. +Available Information +Our principal executive offices are located at 4424 North Sullivan Road, Spokane Valley, Washington 99216, and our telephone number is (509) 928-8000. Our website is located at http://www.keytronic.com where filings of our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q or current reports on Form 8-K are available free of charge after they have been filed with the Securities and Exchange Commission. The information presented on our website currently and in the future is not considered to be part of this document or any document incorporated by reference in this document. +In addition, the SEC maintains an Internet site (at www.sec.gov ) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. \ No newline at end of file diff --git a/raw/filings/0000719733/2024/0000719733-24-000113/item13.txt b/raw/filings/0000719733/2024/0000719733-24-000113/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..839ce80b5b8459abb141e10835dc4548d493068e --- /dev/null +++ b/raw/filings/0000719733/2024/0000719733-24-000113/item13.txt @@ -0,0 +1,2 @@ +Item 13: CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +Information appearing under the caption “Related Person Transactions” and “Directors’ Independence” in the Company’s 2024 Proxy Statement is incorporated herein by this reference. \ No newline at end of file diff --git a/raw/filings/0000719733/2024/0000719733-24-000113/item9a.txt b/raw/filings/0000719733/2024/0000719733-24-000113/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..41b13584dcd7c6860f30eadab198a9748c835fa3 --- /dev/null +++ b/raw/filings/0000719733/2024/0000719733-24-000113/item9a.txt @@ -0,0 +1,25 @@ +Item 9A: CONTROLS AND PROCEDURES +Evaluation of Disclosure Controls and Procedures +It is the responsibility of our management to establish, maintain, and monitor disclosure controls and procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act of 1934 (the “Exchange Act”) are recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms. Additionally, these disclosure controls include controls and procedures that are designed to accumulate and communicate the information required to be disclosed to our Chief Executive Officer and Chief Financial Officer, allowing for timely decisions regarding required disclosures. +As of the end of the period covered by this report, our management carried out an evaluation, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Exchange Act Rule 13a-15(b). +Based on our assessment, we believe that as of June 29, 2024, the Company’s disclosure controls and procedures were not effective as a result of the material weaknesses in internal control over financial reporting discussed below. +Management’s Report on Internal Control over Financial Reporting +Our management has the responsibility to establish and maintain adequate internal control over our financial reporting, as defined in Rule 13a-15(f) under the Exchange Act. Our internal controls are designed to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of our external financial statements in accordance with generally accepted accounting principles (GAAP). +Due to inherent limitations of any internal control system, management acknowledges that there are limitations as to the effectiveness of internal controls over financial reporting and therefore recognize that only reasonable assurance can be gained from any internal control system. Accordingly, our internal control system may not detect or prevent material misstatements in our financial statements and projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. +Under the supervision and participation of management, including the Chief Executive Officer and Chief Financial Officer, we have performed an assessment of the effectiveness of our internal controls over financial reporting as of June 29, 2024. This assessment was based on the criteria established in Internal Control-Integrated Framework (2013), issued by the Committee of Sponsoring Organizations (“COSO”) of the Treadway Commission. Based on our assessment, management concluded that the Company's internal control over financial reporting was not effective as of June 29, 2024 due to the material weaknesses described below. +A material weakness is a deficiency, or combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis. The following material weaknesses have been identified: +The Company did not fully maintain components of the COSO framework, including elements of the control environment, risk assessment, control activities, and monitoring activities components, relating to: (i) sufficiency of processes to identify and analyze risks to the achievement of objectives across the entity, (ii) sufficiency of competent personnel with appropriate levels of knowledge, experience, and training in accounting, and internal control matters to perform assigned responsibilities and have appropriate accountability for the design and operation of internal control over financial reporting; (iii) sufficiency of procedures to select and develop control activities that contribute to the mitigation of risks, and (iv) performing ongoing evaluations to ascertain whether the components of internal control are present and functioning. +The entity level material weaknesses contributed to material weaknesses within the Company’s financial close and reporting processes as follows: +• The Company did not design and implement effective controls over the adoption of new accounting standards. +• The Company did not design and implement effective controls over the accounting for revenue recognition relating to cost recovery of material price variances. +64 +These material weaknesses resulted in the restatement of our consolidated financial statements as of and for the years ended July 1, 2023 and July 2, 2022 and our unaudited consolidated statements of operations for the quarters ended March 30, 2024, December 30, 2023, September 30, 2023, April 1, 2023, December 31, 2022, October 1, 2022, April 2, 2022, January 1, 2022 and October 2, 2021, and revision of our unaudited consolidated balance sheets as of March 30, 2024, December 30, 2023, and September 30, 2023. +As a result of this determination, management has taken, and is in the process of taking, the following actions to remediate the identified material weaknesses in its internal control over financial reporting: +• Training related to the proper accounting for material price variances +• Enhancing closing process documentation related to material price variances +• Hiring of technical accounting finance staff with US GAAP knowledge and experience; and +• Enhance closing process documentation related to adoption of new accounting standards +We will continue to assess the effectiveness of our controls and remediation efforts in connection with our future assessments of the effectiveness of internal control over financial reporting and disclosure controls and procedures. +Changes in Internal Control over Financial Reporting +There have been no significant changes in our internal control over financial reporting during our fourth fiscal quarter ended June 29, 2024 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f)). +65 \ No newline at end of file diff --git a/raw/filings/0000719733/2024/0000719733-24-000113/rp_note.txt b/raw/filings/0000719733/2024/0000719733-24-000113/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0000719733/2024/0000719733-24-000113/rpt_disclosure.txt b/raw/filings/0000719733/2024/0000719733-24-000113/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..4ba0b8e1883457bf1d87900a7fdf32a122280622 --- /dev/null +++ b/raw/filings/0000719733/2024/0000719733-24-000113/rpt_disclosure.txt @@ -0,0 +1,6 @@ +Related Person Transactions +In April 2007, the Board of Directors adopted a written policy for the approval or ratification of Interested Transactions with Related Parties, which was amended in October 2023. The policy supplements the Company’s Code of Conduct. The policy defines an “Interested Transaction” as any transaction, arrangement or relationship or series of similar transactions, arrangements or relationships (including any indebtedness or guarantee of indebtedness) in which (1) the aggregate amount involved will or may be expected to exceed $100,000 in any calendar year, (2) the Company is a participant, and (3) any Related Party has or will have a direct or indirect material interest (other than solely as a result of being a director or a less than 10 percent beneficial owner of another entity). +The policy defines a “Related Party” as any (a) person who is or was (since the beginning of the last fiscal year, even if they do not presently serve in that role) an executive officer, director or nominee for election as a director of the Company, (b) greater than 5 percent beneficial owner of the Company’s Common Stock, or (c) an immediate family member of any of the foregoing. Immediate family member includes a person’s spouse, parent, stepparent, child, stepchild, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law, sister-in-law and any person (other than a tenant or employee) sharing the household of such person. +The Audit Committee is responsible for review, approval, ratification or disapproval of Interested Transactions. In determining whether to approve or ratify an Interested Transaction, the Committee will take into account, among other factors it deems appropriate, whether the Interested Transaction is on terms no less favorable than terms generally available to an unaffiliated third party under the same or similar circumstances and the extent of the Related Party’s interest in the Transaction. +During fiscal year 2025, the Company entered into an agreement with Craig Gates pursuant to which he will provide certain consulting services to the Company following his retirement. The Consulting Agreement provides for a term beginning on June 30, 2024 and ending on June 30, 2026 and payments of $10,000 per month. There were no other Interested Transactions required to be disclosed pursuant to the SEC’s related persons disclosure. +8 \ No newline at end of file diff --git a/raw/filings/0001017303/2019/0001017303-20-000012/filing.txt b/raw/filings/0001017303/2019/0001017303-20-000012/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..8b8e350fef3d3eb96473b17eedf5b8a29f9bd58a --- /dev/null +++ b/raw/filings/0001017303/2019/0001017303-20-000012/filing.txt @@ -0,0 +1,4844 @@ +10-K +1 +form10k2019.htm +FORM 10K FOR THE YEAR ENDED DECEMBER 31, 2019 +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +(Mark One) +⌧ +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2019 +or +□ +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from to . +Commission file number: 0-21121 +(Exact name of registrant as specified in its charter) +Delaware +06-1456680 +(State or other jurisdiction of incorporation or organization) +(I.R.S. Employer Identification No.) +One Hamden Center, 2319 Whitney Avenue, Suite 3B, Hamden, CT +06518 +(Address of principal executive offices) +(Zip Code) +(203) 859-6800 +(Registrant’s Telephone Number, Including Area Code) +Title of each class +Trading Symbol(s) +Name of each exchange on which registered +Common stock, par value $0.01 per share +TACT +NASDAQ Global Market +Securities registered pursuant to Section 12(b) of the Act: None +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes □ No ⌧ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes □ No ⌧ +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities +Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ⌧ No □ +Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant +to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ⌧ No □ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller +reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one): +Large accelerated filer □ +Accelerated filer ⌧ +Non-accelerated filer □ +Smaller reporting company ⌧ +Emerging growth company □ +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for +complying with any new or revised financial standards provided pursuant to Section 13(a) of the Exchange Act. □ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes □ No ⌧ +The aggregate market value of the voting and non-voting common equity held by non-affiliates of the Registrant was approximately +$81,900,000 based on the last sale price on June 28, 2019. +As of February 28, 2020, the number of shares outstanding of the Registrant’s common stock, $0.01 par value, was 7,534,133. +DOCUMENTS INCORPORATED BY REFERENCE +Portions of the Registrant’s Definitive Proxy Statement related to its 2020 Annual Meeting of Stockholders (the “Proxy Statement”) to be +filed with the Securities and Exchange Commission within 120 days after the Registrant’s fiscal year end of December 31, 2019 are incorporated by reference into Part III of this Annual Report on Form 10-K. +TRANSACT TECHNOLOGIES INCORPORATED +INDEX +PART I. +Item 1. +Business +1 +Item 1A. +Risk Factors +5 +Item 1B. +Unresolved Staff Comments +11 +Item 2. +Properties +11 +Item 3. +Legal Proceedings +11 +Item 4. +Mine Safety Disclosures +11 +PART II. +Item 5. +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +12 +Item 6. +Selected Financial Data +14 +Item 7. +Management's Discussion and Analysis of Financial Condition and Results of Operations +14 +Item 7A. +Quantitative and Qualitative Disclosures About Market Risk +26 +Item 8. +Financial Statements and Supplementary Data +26 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +26 +Item 9A. +Controls and Procedures +26 +Item 9B. +Other Information +27 +PART III. +Item 10. +Directors, Executive Officers and Corporate Governance +28 +Item 11. +Executive Compensation +28 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +28 +Item 13. +Certain Relationships and Related Transactions, and Director Independence +28 +Item 14. +Principal Accounting Fees and Services +28 +PART IV. +Item 15. +Exhibits, Financial Statement Schedules +29 +Item 16. +Form 10-K Summary +31 +SIGNATURES +Signatures +32 +CONSOLIDATED FINANCIAL STATEMENTS +Index to Consolidated Financial Statements +F-1 +PART I +Forward Looking Statements +Certain statements included in this Annual Report on Form 10-K (this “Form 10-K”) may include +“forward-looking statements” within the meaning of the U.S. federal securities laws, including the Private Securities Litigation Reform Act of 1995. Forward-looking statements are any statements other than statements of historical fact. +Forward-looking statements represent current views about possible future events and are often identified by the use of forward-looking terminology, such as “may”, “will”, “expect”, “intend”, “estimate”, “anticipate”, “believe”, “project” or +“continue” or the negative thereof or other similar words. Forward-looking statements are subject to certain risks, uncertainties and assumptions. In the event that one or more of such risks or uncertainties materialize, or one or more underlying +assumptions prove incorrect, actual results may differ materially from those expressed or implied by the forward-looking statements. +Important factors and uncertainties that could cause actual results to differ materially from +those expressed or implied by the forward-looking statements include, but are not limited to, the following: our ability to successfully develop new products that garner customer acceptance and generate sales, both domestically and internationally, +in the face of substantial competition from competitors that have broader lines of products and greater financial resources; our ability to successfully transition our business towards the food service technology and casino and gaming markets; our +ability to remediate the material weaknesses over internal control over financial reporting; risks associated with potential future acquisitions; our dependence on a significant customer; general economic conditions in the United +States, Australia, New Zealand, Europe, Latin America and Asia; our dependence on contract manufacturers for the manufacturing and assembly of a large portion of our products in Asia; our dependence on significant suppliers; our ability to recruit +and retain quality employees as the Company grows; our dependence on third parties for sales outside the United States, including Australia, New Zealand, Latin America and Asia; marketplace acceptance of new products; risks associated with foreign +operations; the availability of third-party components at reasonable prices; price wars or other significant pricing pressures affecting the Company's products in the United States or abroad; increased product costs or reduced customer demand for our +products due to changes in U.S. policy that may result in trade wars or tariffs; our ability to protect intellectual property; the effect on global economic conditions, financial markets and our business from the United Kingdom’s withdrawal from +the European Union; and other risk factors detailed from time to time in the Company’s reports filed with the Securities and Exchange Commission. +We caution readers not to place undue reliance on forward-looking statements, which speak +only as of the date of this Form 10-K. We undertake no obligation to public publicly or otherwise revise any forward-looking statements, whether as a result of new information, future events or other factors, except where we are expressly required +to do so by law. +Item 1. Business. +The Company +TransAct Technologies Incorporated (together with its consolidated subsidiaries, “TransAct”, the “Company”, “we”, “us”, or “our”) was +incorporated in June 1996 and began operating as a stand-alone business in August 1996 as a spin-off of the printer business that was formerly conducted by certain subsidiaries of Tridex Corporation. We completed an initial public offering on August +22, 1996. +TransAct is a global leader in developing and selling software-driven technology and printing solutions for high growth markets +including food service technology, point of sale (“POS”) automation and banking, casino and gaming, lottery, and oil and gas. Our world-class products are designed from the ground up based on market and customer requirements and are sold under the +BOHA!™, AccuDate™, Epic®, EPICENTRAL™, Ithaca®, and Printrex® brand names. In March 2019, we launched a new line of products for the food service technology market, the BOHA! branded suite of cloud-based applications and companion hardware +solutions. The new BOHA! software and hardware products help restaurants and food service operators of all sizes automate the food production operations in the back-of-house operations. Known and respected worldwide for innovative designs and +real-world service reliability, our thermal and inkjet printers and terminals generate top-quality labels, coupons and transaction records such as receipts, tickets and other documents, as well as printed logging and plotting of data. We sell our +technology to original equipment manufacturers (“OEMs”), value-added resellers, select distributors, as well as directly to end-users. Our product distribution spans across the Americas, Europe, the Middle East, Africa, Asia, Australia, New Zealand, +Latin America, the Caribbean Islands and the South Pacific. We also offer world-class service, support, labels, spare parts, accessories and printing supplies to our growing worldwide base of products currently in use by our customers. Through our +TransAct Services Group (“TSG”), we provide a complete range of supplies and consumables used in the printing and scanning activities of customers in the restaurant and hospitality, banking, retail, casino and gaming, government and oil and gas +exploration markets. Through our webstore, www.transactsupplies.com , and our direct selling team, we address the demand for these products. Our primary +operating, hardware research and development, and eastern region service center is located in Ithaca, New York. In addition, we have a casino and gaming sales headquarters, software research and development and western region service center in Las +Vegas, Nevada; a European sales and service center at our subsidiary in the United Kingdom (“UK”); and a sales office located in Macau, China. Our executive offices are located at One Hamden Center, 2319 Whitney Avenue, Suite 3B, Hamden, +Connecticut, 06518, with a telephone number of (203) 859-6800. +Products, Services and Distribution Methods +Printers, +terminals and other hardware: TransAct designs, develops and markets a broad array of transaction-based and specialty printers and terminals utilizing thermal and inkjet printing technology for applications, primarily in the food service +technology, POS automation and banking, casino and gaming, lottery, and oil and gas printing markets. Our printers and terminals are configurable and offer customers the ability to choose from a variety of features and functions. Options typically +include interface configuration, mounting configuration, paper cutting devices, paper handling capacities and cabinetry color. Our food service technology terminals also offer software configurable menu options. Our food service technology market +also includes sales of hardware products including handheld devices, tablets, temperature probes and temperature sensors and gateways. +1 +Food Service +Technology: The primary offering in the food service technology market is our BOHA! ecosystem, which combines our latest generation terminal, cloud-based software applications and related hardware into a unique solution to automate +operations with food production in the back-of-house operations in restaurants and food service operations. The software component of BOHA! consists of a suite of software-as-a-service (“SaaS”)-based applications, including applications for +inventory management, temperature monitoring of food and equipment, timers, food safety labeling, food recalls, checklists and procedures, equipment service management, and delivery management. Any and all these applications can be chosen by our +customer and packaged into a single platform with the associated hardware, which includes the BOHA! terminal, handheld devices, tablets, temperature probes and temperature sensors and gateways. The BOHA! terminal combines the software and hardware +components in a device that includes an operating system, touchscreen and one or two thermal print mechanisms that print easy-to-read food rotation labels, grab and go labels for prepared foods, nutritional labels and “enjoy by” date labels. The +BOHA! terminal is equipped with the TransAct Enterprise Management System to ensure that only approved applications and functions are available on the device and allows over-the-air updates to the applications and operating system. BOHA! helps food +service establishments and restaurants (including fine dining, casual dining, fast casual and quick-serve restaurants, convenience stores, hospitality establishments and contract food service providers) effectively manage food safety and grab-and-go +initiatives, as well as automate and manage back-of-house operations. Recurring revenue from BOHA! is generated by software sales, including software subscriptions that are charged to customers upfront on a per-application basis, as well as sales of +labels, extended warranty and service contracts, and technical support services. In the food service technology market, we use an internal sales force to solicit sales directly from end users. +POS automation +and banking: In the POS market, we sell several models of printers utilizing thermal printing technology. Our POS printers are used +primarily by quick-serve restaurants located either at the checkout counter or within self-service kiosks to print receipts for consumers or print on linerless labels. In the POS market, we primarily sell our products through a network of domestic +and international distributors and resellers. We use an internal sales force to manage sales through our distributors and resellers, as well as to solicit sales directly from end-users. In the banking market, we sold inkjet printers that are used +by banks, credit unions and other financial institutions to print deposit and withdrawal receipts and to validate checks at bank teller stations. In the banking market, we primarily sold our products directly to end-user banks and financial +institutions through our internal sales force and, to a lesser extent, resellers. We exited the banking market as of December 31, 2018 and therefore do not expect any future sales. +Casino and +gaming: We sell several models of printers used in slot machines and video lottery terminals (“VLTs”) and other gaming machines that print tickets or receipts instead of issuing coins (“ticket-in, ticket-out” or “TITO”) at casinos, +racetracks and other gaming venues worldwide. These printers utilize thermal printing technology to print tickets and receipts in monochrome and offer various other features such as jam resistant bezels and a dual port interface that enables casinos +to print coupons and promotions. In addition, we sell printers using thermal roll-fed printing technology for use in non-casino establishments, including game types such as Amusements with Prizes, Skills with Prizes, Fixed Odds Betting Terminals and +other off-premise gaming type machines around the world. We sell our casino and gaming products primarily (1) to slot machine manufacturers, who incorporate our printers into slot machines and, in turn, sell completed slot machines directly to +casinos and other gaming establishments and (2) through distributors. Prior to December 31, 2017, the Suzo-Happ Group was our primary worldwide distributor. However, effective January 1, 2018, we replaced the Suzo-Happ Group with new distributors +in Asia and Australia and adopted a direct selling model in Europe utilizing our UK sales office. We also maintain a dedicated internal sales force to solicit sales from slot machine manufacturers and casinos, and to manage sales through our +distributors. +We also offer a software solution, the EPICENTRAL™ Print System (“EPICENTRAL™” and “EPICENTRAL® SE”), including annual software +maintenance, that enables casino operators to create promotional coupons and marketing messages and to print them in real-time at the slot machine. With EPICENTRAL™, casinos can utilize the system to create multiple promotions and incentives to +either increase customer time spent on the casino floor or encourage additional visits to generate more revenue to the casinos. In 2017, we introduced EPICENTRAL® SE, a system edition version of our software solution, that is specifically designed +to work with the existing bonusing modules of casino slot machine management systems. In addition, EPICENTRAL® SE provides an upgrade path to a full EPICENTRAL TM implementation in the event an operator seeks to expand its promotion and +bonusing options beyond the slot machine management systems currently offered. In 2019 we introduced Epicentral 4.0, a cloud based version that also uses the new Acres 4.0 technology that provides Epicentral with true real time slot machine play +data. +Lottery: Our +lottery printers are designed for high-volume, high-speed printing of lottery tickets for various lottery applications. We primarily supply lottery printers to International Gaming Technology and its subsidiaries (“IGT”), our largest customer and +the world’s largest provider of lottery terminals. During 2019, we decided to exit this business and we expect our last sales to occur in 2020 and no future sales beyond 2020. Sales of our lottery products are made directly to IGT and other lottery +system customers and are managed by an internal sales representative. +Printrex: Printrex +printers include wide format, desktop and rack mounted and vehicle mounted black and white thermal printers used by customers in the oil and gas exploration industry to log and plot oil field and down hole well drilling data. The Printrex® brand of +printers also includes high-speed color inkjet desktop printers used by oil and gas field service companies to print logs at their data centers. Prior to 2019, revenue in this market also included sales of vehicle mounted printers used to print +schematics and certain other critical information in emergency services vehicles and other mobile printing applications. We exited this market as of December 31, 2018 and do not expect any future sales. We primarily sell our Printrex® products +directly to oil field service and drilling companies and OEM’s, as well as through regional distributors in the United States, Europe, Canada and Asia. +TSG : Through TSG, we proactively market the sale of consumable products (including inkjet cartridges, ribbons, receipt paper, color thermal paper, and +other printing supplies), replacement parts, maintenance and repair services and testing services for all of our products and certain competitor’s products. Our maintenance services include the sale of extended warranties, multi-year maintenance +contracts, 24-hour guaranteed replacement product service called TransAct Xpress™ and other repair services for our printers and terminals. Within the United States, we provide repair services through our eastern region service center in Ithaca, New +York and our western region service center in Las Vegas, Nevada. Internationally, we provide repair services through our European service center located in Doncaster, UK, and through partners strategically located around the world. +We also provide customers with telephone sales and technical support, and a personal account representative to handle orders, +shipping and general information. Technical and sales support personnel receive training on all our manufactured products and services. +In addition to personalized telephone and technical support, we also market and sell consumable products 24 hours a day, seven days a +week, via our online webstore, www.transactsupplies.com . +2 +Sources and Availability of Raw Materials +We design our products to optimize product performance, quality, reliability and durability. These designs combine cost efficient +materials, sourcing and assembly methods with high standards of workmanship. Approximately 99% of our printer and terminal production is primarily through two third-party contract manufacturers in Asia. The remaining 1% of our products are +assembled in our Ithaca, New York facility largely on a configure-to-order basis using components and subassemblies that have been sourced from vendors and contract manufacturers around the world. +We procure component parts and subassemblies for use in the assembly of our hardware products in Ithaca, New York. Critical +component parts and subassemblies include thermal and inkjet print heads, printing/cutting mechanisms, power supplies, motors, injection molded plastic parts, LCD screens, circuit boards and electronic components, which are obtained from domestic and +foreign suppliers at competitive prices. As a result of the majority of our production being performed by our contract manufacturers, the majority of our purchases consist of fully-assembled printers and terminals produced by our contract +manufacturers and, to a much lesser extent, component parts. We typically strive to maintain more than one source for our component parts, subassemblies and fully assembled printers and terminals to reduce the risk of parts shortages or +unavailability. However, we could experience temporary disruption if certain suppliers ceased doing business with us, as described below. +We currently buy a majority of our thermal print mechanisms, an important component of our thermal printers, and fully assembled +printers for several of our printer and food service technology terminal models, from one foreign contract manufacturer in China and to a lesser extent, one other foreign contract manufacturer in Thailand. Although we believe that other contract +manufacturers could provide similar thermal print mechanisms or fully assembled printers and terminals, on comparable terms, a change in contract manufacturers could cause a delay in manufacturing and possible loss of sales, which may have a material +adverse effect on our operating results. Although we do not have supply agreements with our foreign contract manufacturers, our relationship with both remain strong and we have no reason to believe that either will discontinue their supply of +thermal print mechanisms or fully assembled printers to us during 2020 or that their terms to us will be substantially less favorable than they have been historically. Due to the impact from the Chinese tariff, we are seeking to increasingly +transfer production from our largest contract manufacturer in China to our contract manufacturer in Thailand during 2020. +HP Inc. (“HP”) is the sole supplier of inkjet cartridges that are used in all our banking inkjet printers. Though we have exited the +banking market as of December 31, 2018, we still sell a substantial number of HP inkjet cartridges as a consumable product through TSG. Although other inkjet cartridges are compatible with our banking inkjet printers, the loss of the supply of HP +inkjet cartridges could have a material adverse effect on the sale of our TSG consumable products. Our relationship with HP remains stable and we have no reason to believe that HP will discontinue its supply of inkjet cartridges to us or that their +terms to us will be materially different than they have been historically. The inkjet cartridges we purchase from HP are used not only in our inkjet printers for the POS automation and banking market, but also in other manufacturer’s printing +devices across several other markets. +Canon, Inc. (“Canon”) is the sole supplier of inkjet cartridges and other consumable items (“Canon Consumables”) that are used in our +Printrex® 980 oil and gas printer. The loss of supply of Canon Consumables would have a material adverse effect on the sale of Printrex 980® printers and the Canon Consumables. We have a supply agreement with Canon to supply us with Canon +Consumables until May 2020. Prices under this agreement were fixed through May 2013 but may be changed during the remainder of the agreement if the exchange rate fluctuates significantly between the Japanese yen and the U.S. dollar. +Patents and Proprietary Information +TransAct relies on a combination of trade secrets, patents, employee and third-party nondisclosure agreements, copyright laws and +contractual rights to establish and protect its proprietary rights in its products. We hold 36 United States and 37 foreign patents and have 8 United States and 3 foreign patent applications pending pertaining to our products. The duration of these +patents range from 1 to 15 years. The expiration of any individual patent would not have a significant negative impact on our business. We regard certain manufacturing processes and designs to be proprietary and attempt to protect them through +employee and third-party nondisclosure agreements and similar means. It may be possible for unauthorized third parties to copy certain portions of our products or to reverse engineer or otherwise obtain and use, to our detriment, information that we +regard as proprietary. Moreover, the laws of some foreign countries do not afford the same protection to our proprietary rights as do the laws of the United States. There can be no assurance that legal protections we rely upon to protect our +proprietary position will be adequate or that our competitors will not independently develop technologies that are substantially equivalent or superior to our technologies. +Trademarks, Service Marks and Copyrights +We own or have rights to trademarks, service marks, trade names and copyrights that we use in connection with the operation of our +business, including our corporate names, logos and website names. Other trademarks, service marks and trade names appearing in this Annual Report on Form 10-K are the property of their respective owners. The trademarks we own include TransAct®, +BOHA! TM , AccuDate™, Epic, EPICENTRAL™, Ithaca® and Printrex®. Solely for convenience, some of the trademarks, service marks, trade names and copyrights referred to in this annual report on Form 10-K are listed without the ©, ® and ™ +symbols, but we will assert, to the fullest extent under applicable law, our rights to our trademarks, service marks, trade names and copyrights. +Seasonality +Restaurants typically reduce purchases of equipment in the fourth quarter due to the increased volume of transactions during the +holiday period, which may negatively impact sales of our food service technology terminals or POS printers. +Working Capital +Inventory, accounts receivable, and accounts payable levels, payment terms, and where applicable, return policies are in accordance +with the general practices of the industry and standard business procedures. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. +3 +Certain Significant Customers +IGT is our most significant customer and has been since 1995. We sell both on-line lottery printers and casino and gaming printers +to IGT. On May 29, 2015, we signed an agreement with IGT to sell on-line lottery and casino printers to IGT on a non-exclusive basis through December 31, 2019. We decided not to renew the agreement upon its expiration and to exit the on-line +lottery market. Although we no longer have an agreement with IGT, we expect to continue selling casino and gaming printers to IGT in the future but will no longer sell on-line lottery printers other than expected last time purchases by IGT in 2020. +Sales to IGT represented 14%, 18% and 35% of our total net sales for the years ended December 31, 2019, 2018 and 2017, respectively. +Backlog +Our backlog of firm orders was approximately $5.7 million as of February 29, 2020, compared to $6.9 million as of February 28, +2019. Based on customers’ current delivery requirements, we expect to fill and recognize as revenue $5.4 million of our current backlog during 2020, $0.2 million during 2021 and the remaining balance of the amount during 2022. +Competition +The market for transaction-based and specialty printers and food service technology terminals is extremely competitive, and we expect +such competition to continue in the future. However, we experience less competition for EPICENTRAL TM software due to the highly customized nature of the product. We compete with a number of companies, many of which have greater +financial, technical and marketing resources than TransAct. We believe our ability to compete successfully depends on a number of factors both within and outside our control, including durability, reliability, quality, design capability, product +customization, price, customer support, success in developing new products, manufacturing expertise and capacity, supply of component parts and materials, strategic relationships with suppliers, the timing of new product introductions by us and our +competitors, general market, economic and political conditions and, in some cases, the uniqueness of our products. +In the food service technology market, we primarily compete with Avery Dennison Corporation, Ecolab Inc., ITD Food Safety, CMC +Daymark, Integrated Control Corp, Digi International, Squadle Inc., Jolt Software and Zenput. We compete in this market based largely on our ability to provide highly specialized software and purpose-built products and ongoing technical support. +In the POS automation and banking market, we primarily compete with Epson America, Inc., which holds a dominant market position. We +also compete, to a much lesser extent, with CognitiveTPG, Star Micronics America, Inc., Citizen -- CBM America Corporation, Pertech Industries, Inc., Addmaster, and Samsung/Bixolon. Certain competitors of ours have greater financial resources and +lower costs attributable to higher volume production which enables them to occasionally offer lower prices than us. However, we have exited the banking market and will continue to deemphasize efforts in the POS automation market going forward as we +have shifted our focus toward our higher-value, technology enabled food service technology and casino and gaming products. +In the casino and gaming market (consisting principally of slot machine printing, VLT transaction printing and promotional coupon +printing), we compete with several companies including JCM Global, Nanoptix, Inc., Custom Engineering SPA, Eurocoin and others. Certain of our products sold for casino and gaming applications compete based upon our ability to provide highly +specialized products, custom engineering and ongoing technical support. +In the lottery market (consisting principally of on-line lottery transaction printing), we compete with other lottery printer +providers such as Custom Engineering SPA, Star Micronics and Wincor Nixdorf. However, we have exited the lottery market going forward as we have shifted our focus toward our higher-value, technology enabled food service technology and casino and +gaming products. +In the oil and gas market, our Printrex® products compete primarily with the products of Imaging Systems Group, Inc. and Neuralog +Inc. We compete in this market based largely on our ability to provide specialized, custom-engineered products. +The market in which TSG competes is highly fragmented, and we compete with numerous competitors of various sizes, including POS and +internet resellers and paper converters depending on the geographic area. +Our strategy for competing in our markets is to continually develop new products (hardware and software), such as BOHA! TM +in 2019, and product line extensions that are technologically advanced and provide differentiated features and functions, to increase our geographic market penetration, to take advantage of strategic relationships, and to lower the cost of our +products by sourcing certain products overseas. Although we believe that our products, operations and relationships provide a competitive foundation, there can be no assurance that we will compete successfully in the future. In addition, our +products utilize certain thermal and inkjet printing technologies. If new technologies are introduced, or existing technologies evolve, we may be required to incorporate these technologies into our products. Alternatively, if such technologies were +to become available to our competitors, our products could become obsolete, which could have a significant negative impact on our business. +Environment Compliance +Our compliance with federal, state and local laws and regulations relating to environmental protection and discharge of hazardous +materials has not had a material impact on our capital expenditures, earnings or competitive position, and we do not anticipate any material impact from such compliance in the future. +Available Information +We make available free of charge through the “Investor Relations” tab on our Internet website, www.transact-tech.com, our Annual +Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and all amendments to those reports and statements as soon as reasonably practicable after such material is electronically filed with or furnished to +the Securities and Exchange Commission (“SEC”) pursuant to Sections 13(a) or 15(d) of the Exchange Act. The SEC maintains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at +http;//www.sec.gov. The content on any website referred to in this Form 10-K is not incorporated by reference in this Form 10-K unless expressly noted. +4 +Employees +As of December 31, 2019, TransAct and our subsidiaries employed 134 persons, all of whom were full-time employees. None of our +employees are unionized, and we consider our relationships with our employees to be good. +Information about our Executive Officers +The following is a list of the names and ages of all executive officers of the registrant, indicating all positions and offices with +the registrant held by each such person and each person’s principal occupations and employment during at least the past five years. +Name +Age +Position +Bart C. Shuldman +62 +Chairman of the Board and Chief Executive Officer +Steven A. DeMartino +50 +President, Chief Financial Officer, Treasurer and Secretary +Donald E. Brooks +67 +Senior Vice President-Engineering +Tracey S. Chernay +60 +Senior Vice President, Casino, Gaming and Lottery Sales +Andrew J. Hoffman +62 +Senior Vice President, Operations +David B. Peters +41 +Vice President and Chief Accounting Officer +Raymond T. Walsh, Jr. +34 +Senior Vice President, Global Sales +Bart C. Shuldman has been Chief Executive Officer, President and a Director of the Company since its formation in June 1996. In +February 2001, Mr. Shuldman was elected Chairman of the Board. Mr. Shuldman relinquished the President title, effective June 1, 2010, to focus on new products and markets, international expansion and potential acquisitions. +Steven A. DeMartino was named as TransAct’s President, Chief Financial Officer, Treasurer and Secretary on June 1, 2010. Previously, +Mr. DeMartino served as Executive Vice President, Chief Financial Officer, Treasurer and Secretary from June 2004 to May 2010, Senior Vice President, Finance and Information Technology from October 2001 to May 2004, Vice President and Corporate +Controller from January 1998 to October 2001, and Corporate Controller from August 1996 to December 1997. Mr. DeMartino is a certified public accountant. +Donald E. Brooks was appointed Senior Vice President of Engineering in April 2012. Previously, Mr. Brooks served as Vice President, +Engineering from September 2004 to April 2012, Senior Project Engineer from February 1998 to September 2004, Project Engineer from June 1997 to February 1998, Director of Electrical Engineering from March 1986 to June 1997 and Manager of Electronic +Development from December 1983 to March 1986. +Tracey S. Chernay was appointed Senior Vice President, Casino and Gaming Sales and Marketing in June 2010, with responsibility for +the sales and marketing of all casino and gaming products. Previously, Ms. Chernay served as Senior Vice President, Sales and Marketing from June 2007 to May 2010, Senior Vice President, Marketing and Sales, POS and Banking with the Company from +July 2006 to June 2007, and joined TransAct in May of 2005 as Senior Vice President, Marketing. Prior to joining TransAct, Ms. Chernay was employed with Xerox Corporation where she held the role of Manager, Worldwide Marketing since 2003, and +Manager, Sales Operations from 2000 to 2002. She joined Xerox Corporation in 1983. +Andrew J. Hoffman was appointed Senior Vice President, Operations for TransAct worldwide in November 2004. He served as Vice +President, Operations from September 1994 to November 2004. +David B. Peters was appointed Vice President and Chief Accounting Officer on March 1, 2018. Previously, Mr. Peters served as +Director, SEC and Financial Reporting since joining TransAct in March 2014. Prior to joining TransAct, Mr. Peters was employed with United Technologies Corporation from November 2006 to March 2014 where he served in various financial management +positions. Mr. Peters is a certified public accountant. +Raymond T. Walsh, Jr. was appointed Senior Vice President, Global Sales on February 27, 2019. Previously, Mr. Walsh served as Vice +President, Global Sales since 2018. Mr. Walsh joined TransAct in 2006 and has held several sales positions of increasing responsibility with the Company. Prior to joining TransAct, Mr. Walsh served as the Senior Manager of Business Development at +Nerac. +There are no family relationships between any of our executive officers and there is no arrangement or understanding between any of +such officers and any other person pursuant to which he or she was selected as an officer. Each of our executive officers was elected by the Board of Directors to hold office until his or her successor is elected and qualified or until his or her +earlier resignation or removal. +Item 1A. Risk Factors +Investors should carefully consider the risks, uncertainties and other factors described below, as well as other disclosures in +Management’s Discussion and Analysis of Financial Condition and Results of Operations, because they could have a material adverse effect on our business, financial condition, operating results, and growth prospects. The risks described below are not +the only ones facing our Company. Additional risks and uncertainties not presently known to us, or that we currently believe to be immaterial, may also impair our business operations. In the event that such risks or uncertainties materialize, our +business, financial condition, and results of operations could be materially adversely affected. +We assume no obligation (and specifically disclaim any such obligation) to update these Risk Factors or any other forward-looking +statements contained in this Form 10-K to reflect actual results, changes in assumptions or other factors affecting such forward-looking statements, except as required by law. +5 +Risks Related to our Business +Our operating results and financial condition may fluctuate. +Our operating results and financial condition may fluctuate from quarter-to-quarter and year-to-year and are likely to continue to +vary due to a number of factors, many of which are not within our control. If our operating results do not meet the expectations of securities analysts or investors, who may derive their expectations by extrapolating data from recent historical +operating results, the market price of our common stock will likely decline. Fluctuations in our operating results and financial condition may be due to a number of factors, including, but not limited to, those identified throughout this “Risk +Factors” section: +● +delays between our expenditures to develop and market new or enhanced products and consumables and the generation of sales from those products; +● +the geographic distribution of our sales and our supply chain; +● +market acceptance of our products, both domestically and internationally; +● +development of new competitive products by others; +● +our responses to price competition; +● +our level of research and development activities; +● +changes in the amount that we spend to develop, acquire or license new products, consumables, technologies or businesses; +● +changes in the amount we spend to promote our products and services; +● +changes in the cost of satisfying our warranty obligations and servicing our installed base of products; +● +availability of third-party components at reasonable prices; +● +general economic and industry conditions, including changes in interest rates affecting returns on cash balances and investments, that affect customer demand; +● +fluctuations of world-wide oil and gas prices; +● +the dependence of our supply chain on a few, foreign third-party manufacturers and suppliers; +● +severe weather events, public health crises, and other external events out of our control that can disrupt our operations or the operations of our customers’ or +suppliers’ facilities; and +● +changes in accounting rules. +Due to all of the foregoing factors, and the other risks discussed in this Form 10-K, quarter-to-quarter comparisons of our operating +results may not be an indicator of future performance. +Our revenue and profitability depend on our ability to continue to develop, on a timely basis, +new products and technologies which are free from hardware or software anomalies and cannot be fraudulently manipulated, and customer acceptance of such products. +Our success depends upon our ability to timely adapt our capabilities and processes to meet the demands of producing new and +innovative products. Because our newer products contain software and generally are more technologically sophisticated than those we have produced in the past, we must continually refine our capabilities to meet the needs of our product innovation. +If we cannot efficiently adapt our infrastructure to meet the needs of our product innovations in a timely manner, our business could be negatively impacted. +In addition, even if we successfully develop such products, there is no assurance that our innovations will be accepted by our +customers. Developing and marketing new products, such as our BOHA! ecosystem, is costly, and our business could be materially adversely affected if we are unable to generate sales of such products or if our existing or new customers do not quickly +accept such products. Customer acceptance is crucial because new products typically have very little competition and market penetration due to their novelty. Although we develop new products with the input of our customers, which has contributed to +the early success of BOHA!, customer acceptance is never assured may take time to materialize. +We compete in highly competitive markets, which are likely to become more competitive. +Competitors may be able to respond more quickly to new or emerging technology and changes in customer requirements. +We face significant competition in developing and selling our printers, terminals, software, consumables and +services. Our principal competitors have substantial marketing, financial, development and personnel resources. To remain competitive, we believe we must continue to provide: +● +technologically advanced products that satisfy the user demands; +● +superior customer service; +● +high levels of quality and reliability; and +● +dependable and efficient distribution networks. +We cannot ensure we will be able to compete successfully against current or future competitors. Increased competition may result in +price reductions, lower gross profit margins and loss of market share, and could require increased spending on research and development, sales and marketing and customer support. Some competitors may make strategic acquisitions or establish +cooperative relationships with suppliers or companies that produce complementary products. Any of these factors could reduce our earnings. +Our success will depend on our ability to sustain and manage growth. +As part of our business strategy, we intend to pursue a growth strategy. Assuming this growth occurs, it will require the expansion +of customer relationships in international markets, the successful development and marketing of new products for our existing and new markets, expanded internal sales and marketing, customer service and support, and the continued implementation and +improvement of our operational, financial and management information systems. +6 +To the extent that we seek growth through acquisitions, our ability to manage our growth will also depend on our +ability to integrate businesses that have previously operated independently. We may not be able to achieve this integration without encountering difficulties or experiencing the loss of key employees, customers or suppliers. It may be difficult to +design and implement effective financial controls for combined operations and differences in existing controls for each business may result in weaknesses that require remediation when the financial controls and reporting functions are combined. As +we pursue acquisitions, we may incur legal, accounting and other transaction related expenses for unsuccessful acquisition attempts that could adversely affect our results of operations in the period in which they are incurred. +There can be no assurance that we will be able to successfully implement our growth strategy, or that we can +successfully manage expanded operations, if they occur. As we expand, we may from time to time experience constraints that will adversely affect our ability to satisfy customer demand in a timely fashion. Failure to manage growth effectively could +adversely affect our results of operations and financial condition. +Material weaknesses in our internal control over financial reporting have been identified, and +if we are unable to implement and maintain effective internal control over financial reporting, or our independent registered public accounting firm is unable to provide an unqualified report thereon, we could be materially adversely affected. +Material weaknesses in our internal control over financial reporting existed as of December 31, 2018 and 2019 +regarding our internal controls over user access to ensure appropriate segregation of duties and to adequately restrict user access to appropriate personnel. Specifically, the provisioning and user recertification controls are not designed to ensure +users maintain proper segregation of duties and therefore could have inappropriate access rights. Additionally, we identified a material weakness in controls over key spreadsheets supporting our accounting records. Specifically, we did not design +adequate controls to address the completeness and accuracy of information included in key spreadsheets. As a result of these material weaknesses, management concluded that our internal control over financial reporting was not effective as of +December 31, 2019. +Unless and until these material weaknesses have been remediated or should new material weaknesses arise or be +discovered in the future, a material misstatement could occur and go undetected in our interim or annual consolidated financial statements. As a result, we may experience delays in fulfilling our reporting obligations or complying with federal +securities laws, which could result in investigations and sanctions by regulatory authorities, including, but not limited to, the Securities and Exchange Commission (the “SEC”), and may result in defaults or accelerations under our credit facility in +the event that we are unable to timely file reports with the SEC, to the extent that in such an event, we are unable to obtain waivers from our lender. Any of these results could adversely affect our business and the value of our common stock. +In the casino and gaming market and the lottery market, we are dependent on sales to one large +customer; the loss of this customer or reduction in orders from this customer could materially affect our sales. +Lottery and, to a lesser extent, casino and gaming sales to IGT have represented a material percentage of our net +sales since 1995. A reduction, delay or cancellation in orders from this customer, including reductions or delays due to market, economic, or competitive conditions in the industries in which we serve, could have a material adverse effect upon our +results of operations. +General economic conditions could have a material adverse effect on our business, operating +results and financial condition. +Our business is subject to general economic conditions. Uncertainty or negative trends in U.S. or international economic and +investment climates, including the impact of Brexit and recent developments in U.S.-China trade relations (discussed separately below), could adversely affect our business. For example, customers or potential customers could reduce or delay orders, +key suppliers and customers could become insolvent, which could result in production delays, and our customers may not be able to obtain credit. Any of these possible effects could impact our ability to effectively manage inventory levels and +collect receivables, create unabsorbed costs due to lower net sales, and ultimately decrease our net sales and profitability including write-downs of assets. +Fluctuations in oil and gas prices could adversely affect drilling and exploration activities +by oil and gas companies and our revenue in our Printrex market. If oil and gas prices remain volatile, or if oil or gas prices remain low or decline further, the demand for our Printrex products could be adversely affected. +The demand for our Printrex products depends on the level of spending by oil and gas companies for drilling and exploratory +activities, which are affected by short-term and long-term trends in oil and gas prices, including current and anticipated oil and gas prices. Oil and gas prices, as well as the level of drilling and exploration, historically have been extremely +volatile and are expected to continue to be highly volatile. If oil and gas prices continue to remain low or decline further, or if there is a further reduction in drilling and exploration activities, the demand for our Printrex products could be +materially and adversely affected. +If market conditions deteriorate or future results of operations are less than expected, a +valuation allowance may be required for all or a portion of our deferred tax assets. +We currently have deferred tax assets, which may be used to reduce taxable income in the future. We assess the realization of these +deferred tax assets on a quarterly basis, and if we determine that it is more likely than not that some portion of these assets will not be realized, an income tax valuation allowance is recorded. If market conditions deteriorate or future results +of operations are less than expected, or there is a change to applicable tax rules, future assessments may result in a determination that it is more likely than not that some or all of our net deferred tax assets are not realizable. As a result, we +may need to establish a valuation allowance for all or a portion of our net deferred tax assets, which may have a material adverse effect on our business, results of operations and financial condition. +We rely on distributors and resellers to sell our products and services. +We use a variety of distribution channels, including OEMs and distributors, to market and sell our products and services. We may be +adversely impacted by any conflicts that could arise between and among our various sales channels. +7 +Our dependence upon distributors and resellers exposes us to numerous risks, including: +● +loss of channel and the ability to bring new products to market; +● +concentration of credit risk, including disruption in distribution should the distributors and / or resellers’ financial condition deteriorate; +● +reduced visibility to end user demand and pricing issues which makes forecasting more difficult; +● +distributors or resellers leveraging their buying power to change the terms of pricing, payment and product delivery schedules; and +● +direct competition should a distributor or reseller decide to manufacture printers internally or source printers from a competitor. +We cannot guarantee that resellers will not reduce, delay or eliminate purchases from us, which could have a material adverse effect +upon the business, consolidated results of operations and financial condition. +We are dependent upon two manufacturers located in China and Thailand for the manufacturing +and assembly of our printers and terminals, and their operations have been disrupted by the outbreak of the Coronavirus. The impact of this disruption on the Company is uncertain at this time, but this disruption, and any further or future disruption +in their businesses or operations, such as those caused by political, social or economic instability, trade restrictions or tariffs, severe weather, additional public health crises and other events out of our control, could materially adversely +affect our business, financial condition and results of operations. +In an effort to achieve additional cost savings and operation benefits, we have outsourced substantially all of the manufacturing and +assembly of our printers and terminals to two contract manufacturers located in Asia. Approximately 80% of our printer and terminal manufacturing is conducted by one third-party manufacturer located in China, and an additional 19% is conducted by +one other third-party manufacturers located in Thailand. As a result, we are dependent on them for the manufacturing of our products, and any disruption in such manufacturing or the export of products from these manufacturers to the U.S. may +adversely affect our business, financial condition and results of operations. +Risks affecting the businesses and operations of our two manufacturers in Asia include: political and regional strife; war; labor +shortages; severe weather and natural disasters such as earthquakes, hurricanes, fires, and floods; lengthy power outages; increased pricing, financial instability and capacity constraints of shippers; and concerns with or threats of public health +crises, contagious diseases or health epidemics. The risk to our business posed by any disruption in manufacturing is exacerbated by the concentration of our manufacturing operations in two manufacturers both located in Asia. +In December 2019, a novel strain of the coronavirus was reported in China that has subsequently spread outside of China. In response +to the coronavirus outbreak, the Chinese government has placed restrictions on travel and mandated business closures. Such restrictions and closures have started to disrupt our supply chain by delaying product shipments from our contract +manufacturers during 2020. Although the impact of such disruptions and delays has not had a material impact on our results of operations, there is significant uncertainty relating to the outbreak of coronavirus as well as the potential effects of +such outbreak on our business. +The extent to which the coronavirus impacts our operations will depend on future developments, which are highly uncertain and cannot +be predicted with confidence, including the duration of the outbreak, new information which may emerge concerning the severity of the coronavirus and the actions to contain the coronavirus or treat its impact, among others. Without the contract +manufacturers continuing to manufacture our products and the continuing operation of the contract manufacturers’ facilities, we will have limited means for the final assembly of a majority of our products until we are able to secure the manufacturing +capability at another facility or develop an alternative manufacturing facility, which could be costly and time consuming and have a material adverse effect on our operating and financial results. However, any such risk is partially offset by the +current inventory of printing solutions maintained at our Ithaca, New York and, to a lesser extent, Las Vegas, Nevada facilities. +We may also incur increased business continuity and reputational risks to the extent that we continue to outsource the manufacturing +and assembly of our products to foreign third-party service providers. For example, outsourcing of manufacturing prevents us from exercising control over the assembly of certain of our products and related operations or processes, including the +internal controls associated with operations and processes conducted and the quality of our products assembled by contract manufacturers. If we are unable to effectively manage and oversee our outsourcing strategy, we may not realize cost structure +efficiencies and our operating and financial results could be materially adversely affected. Outsourcing also exposes us to increased risk of infringement or misappropriation of our intellectual property, to which our manufacturers have access. +Because our manufacturers are located in Asia, there is no guarantee that our intellectual property rights will be protected or enforced to the same extent as under U.S. federal and state laws. Consequently, we may not be able to prevent +third-parties from developing or selling products made using our technologies. +We face risks associated with manufacturing forecasts. +If we fail to predict our manufacturing requirements accurately, we could incur additional costs or experience +manufacturing delays, which could cause us to lose orders or customers and result in lower net sales. We currently use a rolling 12-month forecast based primarily on our anticipated product orders and our product order history to help determine our +requirements for components and materials. It is very important that we accurately predict both the demand for our products and the lead-time required to obtain the necessary components and raw materials. +Lead times for materials and components that we order vary significantly and depend on factors such as the +specific supplier, the size of the order, contract terms, and demand for each component at a given time. If we underestimate our requirements, we may have inadequate manufacturing capacity or inventory, which could interrupt manufacturing of our +products and result in delays in shipments and net sales. If we overestimate our requirements, we could have excess inventory of parts and finished products. In addition, delays in the manufacturing of our products could cause us to lose orders or +customers. +We purchase component parts and consumable products from third-party and sole source +suppliers, and any interference with this supply chain may impact our ability to manufacture and sell our products. +We rely on third-party or sole source suppliers to provide certain key components for our products. We do not have guaranteed supply +contracts with any of our component suppliers, and our suppliers could delay shipments, increase prices or cease manufacturing or selling such components to us at any time. A disruption in the supply of such component parts and consumable products +could delay our production and/or the release of our new products and hinder our ability to meet our commitments to customers. If we are unable to obtain a sufficient quantity of these components on commercially reasonable terms or in a timely +manner, or if we are unable to obtain alternative sources for the components, sales of our products could be delayed or halted entirely or we may be required to redesign our products. Any of these events could result in lost sales, reduced gross +margins or damage to our end-customer relationships, which would have a material adverse effect on our operations and financial results. +8 +In addition to maintaining offices in the UK and Macau, we sell and ship a significant portion +of our products internationally and rely on third parties that make up our global salesforce. The international nature of our operations may expose us to certain risks associated with doing business outside of the U.S., including risks posed by the +UK’s withdrawal from the European Union, tariffs, and changes in trade relations. +We sell a significant amount of our products to customers outside the United States. Shipments to international customers are +expected to continue to account for a material portion of net sales. In addition, our manufacturers and suppliers are largely located in Asia. As a result, our products are largely exported to one of our facilities in the United States, which makes +our operations vulnerable to disruptions in trade that could adversely affect our business results. +Our international operations, including our reliance on manufacturers and suppliers located in Asia, our worldwide sales team, and +our sales to customers located outside the United States, expose us to disruptions in trade and other associated risks such as: +● +the imposition of additional duties, tariffs, quotas, taxes, trade barriers, capital flow restrictions and other charges on imports and exports by the United States +or the governments of the countries in which we or our manufacturers and suppliers operate; +● +delays in the delivery of cargo due to port security considerations, labor disputes such as dock strikes, and our reliance on a limited number of shipping and air +carriers, which may experience capacity issues that adversely affect our ability to ship inventory in a timely manner or for an acceptable cost; +● +fluctuations in the value of the U.S. Dollar against foreign currencies, which could restrict sales, or increase costs of purchasing, in foreign countries; +● +economic or political instability in any of the countries in which we or our manufacturers or suppliers operate, which could result in a reduction in demand for our +products due to political and economic instability or impair our foreign assets; +● +a reduced ability or inability to sell in or purchase from certain markets as a result of export or import restrictions; +● +potentially limited intellectual property protection in certain countries, such as China, may limit recourse against infringing products or cause us to refrain from +selling in certain geographic territories; and +● +reliance on a limited number of shipping and air carriers who may experience capacity issues that adversely affect our ability to ship inventory in a timely manner +or for an acceptable cost; and +● +economic uncertainties and adverse economic conditions (including inflation and recession). +Although we carry business interruption insurance to cover lost revenue and profits in an amount we consider adequate, this insurance +does not cover all possible situations. In addition, the business interruption insurance would not compensate us for the loss of opportunity and potential adverse impact, both short-term and long-term, on relations with our existing customers +resulting from our inability to produce products for them. +Outside of the United States we maintain offices in the UK and Macau. Effective January 31, 2020, the UK formally withdrew from the +European Union. Following the UK’s withdrawal, often referred to as “Brexit,” the UK entered a transition period, which is currently set to end on December 31, 2020. It is expected that the UK will negotiate a new free trade agreement with the +European Union during this transition period. In the event that no such agreement is reached prior to the end of the transition period, the UK will have no international agreement governing its ongoing relationship with the EU. +We are still evaluating the impact of Brexit on our business, particularly as it relates to our UK subsidiary, during and after this +transition period. Adverse consequences such as deterioration in economic conditions and volatility in currency exchange rates could have a negative impact on the Company's operations, financial condition and results of operations. In addition, the +future trade relationship between the UK and the European Union remains uncertain, and any incremental regulatory controls and regulations governing trade between the UK and the European Union could have adverse consequences on the steel industry in +the UK and/or the European Union and could negatively impact the Company's operations and financial condition. +Our business could be adversely affected by actual or threatened terrorist attacks or the +related heightened security measures, military actions and other efforts to combat terrorism. +Our business could be adversely affected by actual or threatened terrorist attacks or the related heightened security measures, +military actions and other efforts to combat terrorism. It is possible that terrorist attacks could be directed at important locations for the gaming industry. Heightened security measures and other efforts to combat terrorism may also have an +adverse effect on the gaming industry by reducing tourism. Any of these developments could also negatively affect the general economy and consumer confidence. Any downturn in the economy in general, or in the gaming industry in particular could +result in a reduced demand for our products and could adversely affect our business and results of operations. In addition, heightened security measures may cause certain governments to restrict the import or export of goods, which may have an +adverse effect on our ability to buy and sell goods. +We depend on key personnel, the loss of which could materially impact our business. +Our future success will depend in significant part upon the continued service of certain key management and other +personnel and our continuing ability to attract and retain highly qualified managerial, technical and sales and marketing personnel. There can be no assurance that we will be able to recruit and retain such personnel. The loss of either Bart C. +Shuldman, the Company's Chairman of the Board and Chief Executive Officer, or Steven A. DeMartino, the Company’s President, Chief Financial Officer, Treasurer and Secretary, or the loss of certain groups of key employees, could have a material +adverse effect on our results of operations. +9 +The inability to protect our intellectual property rights could harm our reputation, damage +our business or interfere with our competitive position, and infringement on the intellectual property rights of others, or claims thereof, could put us at a competitive disadvantage, and any related litigation could be time consuming and costly. +Our intellectual property is valuable and provides us with certain competitive advantages. Copyrights, patents, trademarks, service +marks, trade secrets, nondisclosure agreements and contracts are used to protect these proprietary rights. Despite these precautions, it may be possible for third parties to copy aspects of our products or, without authorization, to obtain and use +information which we regard as trade secrets. +In addition, prosecuting and defending infringement lawsuits is very expensive. We are committed to aggressively asserting and +defending our technology and related intellectual property rights, which we have spent a significant amount of money to develop. Similarly, third-parties may claim, from time to time, that we have violated their intellectual property rights. To the +extent of a violation of a third-party’s patent or other intellectual property right, we may be prevented from operating our business as planned and may be required to pay damages, to obtain a license, if available, or to use a non-infringing method, +if possible, to accomplish our objectives. Any such claims could result in costly litigation and, if successful, could result in costly judgments or settlements. +The expense of prosecuting or defending any future infringement lawsuits could have a material adverse effect on our business, +financial condition and results of operations. Intellectual property litigation is generally complex, costly, protracted, and highly disruptive to business operations by diverting the attention and energies of management and key technical personnel. +Cyber-security and privacy breaches, cyber-attacks, or other disruptions could expose us to +liability, affect our business, and damage our reputation. +We are increasingly dependent on our information technology systems and infrastructure for our business. We +collect, store, and transmit sensitive information including intellectual property, proprietary business information and personal information in connection with business operations. The secure maintenance of this information is critical to our +operations and business strategy. Some of this information could be an attractive target of criminal attack by third parties with a wide range of motives and expertise, including organized criminal groups, disgruntled current or former employees, and +others. Cyber-attacks are of ever-increasing levels of sophistication, and despite our extensive security measures, our information technology and infrastructure may be vulnerable to such attacks or may be breached, including due to employee error or +malfeasance. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. If our systems become compromised, we may not promptly discover the intrusion. Like other companies in +our industry, we have experienced attacks to our data and systems, including malware and computer viruses that we have been able to detect and eliminate. If our systems fail or are breached or disrupted, we could lose product sales, and suffer +reputational damage and loss of customer confidence. Such incidents would require notification to affected individuals and may result in legal claims or proceedings and liability under federal and state laws that protect the privacy and security of +personal information. Any one of these events could cause our business to be materially harmed and our results of operations to be adversely impacted. +We cannot provide any assurance that current laws, or any laws enacted in the future, will not +have a material adverse effect on our business. +Our operations are subject to laws, rules, regulations, including environmental regulations, government policies and other +requirements in each of the jurisdictions in which we conduct business. Changes in such laws, rules, regulations, policies or requirements could result in the need to modify our products and could affect the demand for our products, which may have +an adverse impact on our future operating results. If we do not comply with applicable laws, rules and regulations we could be subject to costs and liabilities and our business may be adversely impacted. +Risks Related to our Common Stock +Our stock price may fluctuate significantly. +The market price of our common stock could fluctuate significantly in response to variations in quarterly +operating results and other factors, such as: +● +changes in our business, operations or prospects; +● +developments in our relationships with our customers; +● +announcements of new products or services by us or by our competitors; +● +announcement or completion of acquisitions by us or by our competitors; +● +changes in existing or adoption of additional government regulations; +● +unfavorable or reduced analyst coverage; and +● +prevailing domestic and international market and economic conditions. +In addition, the stock market may experience significant price fluctuations year-to-year. Broad market +fluctuations, general economic conditions and specific conditions in the industries in which we operate may adversely affect the market price of our common stock. +Limited trading volume and a reduction in analyst coverage of our common stock may contribute +to its price volatility. +Our common stock is traded on the Nasdaq Global Market. During the year ended December 31, 2019 the average +daily trading volume for our common stock as reported by the Nasdaq Global Market was approximately 19,000 shares. We are uncertain whether a more active trading market in our common stock will develop. In addition, many investment banks no longer +find it profitable to provide securities research on micro-cap and small-cap companies. As a result, relatively small trades may have a significant impact on the market price of our common stock, which could increase the volatility and depress the +price of our common stock. +Future sales of our common stock may cause our stock price to decline. +In the future, we may sell additional shares of our common stock in public or private offerings, and we may also issue additional +shares of our common stock to finance future acquisitions. Shares of our common stock are also available for future sale pursuant to stock options and other equity awards that we have granted to our employees, and in the future, we may grant +additional stock options and other forms of equity compensation to our employees. Sales of our common stock or the perception that such sales could occur may adversely affect prevailing market prices for shares of our common stock and could impair +our ability to raise capital through future offerings. +10 +Item 1B. Unresolved Staff Comments. +Not applicable. +Item 2. Properties. +Our principal facilities as of December 31, 2019 are listed below. We believe that all facilities generally are in good condition, +adequately maintained and suitable for their present and currently contemplated uses. +Location +Operations Conducted +Size +(Approx. Sq. +Ft.) +Owned or +Leased +Lease Expiration +Date +Hamden, Connecticut +Executive offices and sales office +11,100 +Leased +April 30, 2027 +Ithaca, New York* +Hardware design and development, assembly and service facility +73,900 +Leased +May 31, 2021 +Las Vegas, Nevada +Software design and development, service center and casino and gaming sales office +19,600 +Leased +October 31, 2022 +Doncaster, UK +Sales office and service center +6,000 +Leased +August 26, 2026 +Macau, China +Sales office +180 +Leased +June 30, 2020 +110,780 +* On February 28, 2020, we signed +an amendment to extend our lease in Ithaca, New York to May 31, 2025. +Item 3. Legal Proceedings. +The Company may, in the ordinary course of business, become a party to litigation involving collection matters, contract claims and +other legal proceedings relating to the conduct of its business. As of December 31, 2019, we are unaware of any legal proceedings pending or threatened against us that management believes are likely to have a material adverse effect on our business, +financial condition or results of operations. +Item 4. Mine Safety Disclosures. +Not applicable. +11 +PART II +Item 5. Market for Registrant’s Common Equity, Related Stockholder +Matters and Issuer Purchases of Equity Securities. +Our common stock is traded on the Nasdaq Global Market under the symbol TACT. As of February 28, 2020, there were 261 holders of +record of the common stock. +Issuer Purchases of Equity Securities +Prior to its expiration on December 31, 2019, we maintained a stock repurchase program (the "2018 Stock Repurchase Program") whereby +we were authorized to repurchase up to $5 million of our outstanding shares of common stock from time to time in the open market at prevailing market prices based on market conditions, share price and other factors. During 2019 we did not repurchase +any shares of our common stock. From the start of the 2018 Stock Repurchase Program on March 1, 2018 through December 31, 2018, we repurchased 156,410 shares of our common stock for approximately $2 million at an average price per share of $12.79. +Dividend Policy +In 2012, our Board of Directors initiated a quarterly cash dividend program which is subject to the Board’s approval each +quarter. Our Board of Directors declared an increase to the quarterly cash dividend from $0.06 to $0.07 per share in May 2013, from $0.07 to $0.08 per share in May 2014, and from $0.08 to $0.09 per share in May 2017. Dividends declared and paid on +our common stock totaled $2.7 million or $0.36 per in both 2019 and 2018. On January 23, 2020, our Board of Directors announced the cessation of our quarterly cash dividend on the Company’s common stock to accelerate the investment in sales and +marketing, continued product development and infrastructure of the BOHA! ecosystem. The final dividend payment was made in December 2019. +Sales of Unregistered Securities +None. +12 +CORPORATE PERFORMANCE GRAPH +The following graph compares the cumulative total return on the Company’s Common Stock from December 31, 2014 through December 31, +2019, with the CRSP Total Return Index for the Nasdaq Stock Market (U.S.) and the Nasdaq Computer Hardware Stocks Index. The graph assumes that $100 was invested on December 31, 2014 in each of TransAct’s common stock, the CRSP Total Return Index for +the Nasdaq Stock Market (U.S.) and the Nasdaq Computer Manufacturer Stocks Index, and that all dividends were reinvested. +The performance graph shall not be deemed “filed” for purposes of Section 18 of the Exchange Act or incorporated by reference into +any filings of the Company under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing. +COMPARISON OF CUMULATIVE TOTAL RETURN AMONG +TRANSACT TECHNOLOGIES INCORPORATED COMMON STOCK, +THE CRSP TOTAL RETURN INDEX FOR THE NASDAQ STOCK MARKET (U.S.), +AND THE NASDAQ COMPUTER MANUFACTURER STOCKS INDEX +12/31/14 +12/31/15 +12/31/16 +12/31/17 +12/31/18 +12/31/19 +TransAct Technologies Incorporated Common Stock +$ +100.00 +$ +157.04 +$ +120.66 +$ +242.23 +$ +164.17 +$ +200.55 +CRSP Total Return Index for the Nasdaq Stock Market (U.S.) +$ +100.00 +$ +100.48 +$ +113.55 +$ +137.83 +$ +130.33 +$ +170.96 +Nasdaq Computer Hardware Stocks Index +$ +100.00 +$ +91.05 +$ +104.94 +$ +150.94 +$ +141.35 +$ +259.32 +13 +Item 6. Selected Financial Data (in thousands, except per share +amounts) +The following is summarized from our audited financial statements of the past five years: +Year Ended December 31, +2019 +2018 +2017 +2016 +2015 +Consolidated Statement of Operations Data: +Net sales +$ +45,748 +$ +54,587 +$ +56,311 +$ +57,235 +$ +59,676 +Gross profit +21,935 +26,743 +26,662 +23,799 +24,978 +Operating expenses +21,592 +19,984 +19,848 +18,599 +20,510 +Operating income +343 +6,759 +6,814 +5,200 +4,468 +Net income +516 +5,426 +3,211 +3,617 +3,092 +Net income per share: +Basic +0.07 +0.73 +0.43 +0.48 +0.40 +Diluted +0.07 +0.70 +0.42 +0.47 +0.39 +Dividends declared and paid per share +0.36 +0.36 +0.35 +0.32 +0.32 +December 31, +2019 +2018 +2017 +2016 +2015 +Consolidated Balance Sheet Data: +Total assets +$ +36,061 +$ +34,956 +$ +33,950 +$ +32,042 +$ +32,569 +Shareholders’ equity +25,926 +27,567 +26,014 +24,109 +25,728 +Item 7. Management's Discussion and Analysis of Financial +Condition and Results of Operations. +This discussion should be read in conjunction with the Consolidated Financial Statements and notes thereto. +Overview +During the year ended December 31, 2019, we launched our BOHA! software-as-a-service (“SaaS”)-based software and hardware ecosystem. +BOHA! is a comprehensive ecosystem of cloud-based SaaS software applications and hardware designed to help restaurant and food service companies automate their back-of-house operations. BOHA! represents the first single-vendor solution to allow +customers to choose from any combination of applications for inventory management, temperature monitoring of food and equipment, food safety labeling, food recalls, checklists & procedures, equipment service management, timers and delivery +management. In order to accelerate the investment in sales and marketing and continued product development of the BOHA! ecosystem, the Board of Directors announced the Company will cease our quarterly dividend on the Company’s common stock. The +final dividend payment was made in December 2019. +During 2019, our sales decreased due to declines in all markets other than food service technology. POS automation and banking sales +declined due to lower sales of our Ithaca 9000 printer to McDonald’s in 2019 compared to higher than normal levels in 2018. Casino and gaming sales were lower in 2019 due to a large order from a domestic casino operator during 2018 that did not +reoccur in 2019 and lower casino and gaming sales to Europe in 2019 compared to 2018 due to a large order from a slot machine manufacturer to replace a competitor’s printer. Sales for our lottery market and TransAct Services Group (“TSG”) market +decreased in 2019 compared to 2018 due to lower sales to International Gaming Technology and its subsidiaries (“IGT”). TSG sales to IGT decreased due to lower sales of spare parts in the lottery market during 2019 compared to 2018. These sales +declines were as expected as we are no longer focusing on the lottery markets and therefore we expect lottery and TSG sales to continue to decrease in 2020 compared to 2019. +During the year ended December 31, 2019, our total net sales decreased 16% to approximately $45.7 million. We have reclassified +sales of labels and other recurring revenue items, which includes extended warranty and service contracts, and technical support services related to our food service technology market, previously included in TSG to Food Service Technology for all +periods presented in this Form 10-K. See the table below for a breakdown of our sales by market: +Year Ended +Year Ended +Change +(In thousands) +December 31, 2019 +December 31, 2018 +$ +% +Food service technology +$ +6,104 +13.3 +% +$ +5,086 +9.3 +% +$ +1,018 +20.0 +% +POS automation and banking +5,758 +12.6 +% +7,273 +13.3 +% +(1,515 +) +(20.8 +%) +Casino and gaming +21,529 +47.1 +% +26,593 +48.7 +% +(5,064 +) +(19.0 +%) +Lottery +1,291 +2.8 +% +3,093 +5.7 +% +(1,802 +) +(58.3 +%) +Printrex +1,166 +2.6 +% +1,297 +2.4 +% +(131 +) +(10.1 +%) +TSG +9,900 +21.6 +% +11,245 +20.6 +% +(1,345 +) +(12.0 +%) +$ +45,748 +100.0 +% +$ +54,587 +100.0 +% +$ +(8,839 +) +(16.2 +%) +Sales of our food service technology products increased 20% in the year ended December 31, 2019 compared to the year ended December +31, 2018. In the food service technology market, we focus on providing hardware products, which include terminals, handheld devices, tablets, temperature probes and temperature sensors; in addition to cloud-based software applications, labels and +other recurring revenue items. In 2019, we launched our BOHA! solution, which combines our latest generation terminal, cloud-based software applications and hardware into a unique solution to automate the back-of-house operations in restaurants and +food service operations. Food service technology sales increased in 2019 primarily due to a 264% increase in recurring revenue attributable to sales of BOHA!, which sales reflect subscriptions for the related software applications, as well as sales +of labels, extended warranty and service contracts, and technical support services. We expect food service technology to increase in 2020 as we plan to accelerate investments in selling and marketing and product development to exploit the +significant market opportunities. +Sales of our POS automation and banking products decreased 21% in the year ended December 31, 2019 compared to the year ended +December 31, 2018. In the POS market, we focus primarily on supplying printers that print receipts or linerless labels for customers in the restaurant and quick serve markets. During the year ended December 31, 2019, sales of our Ithaca 9000 +printer to McDonald’s slowed from the record pace of the prior two years, which we expect to continue in 2020. In the banking market, we had focused mainly on supplying printers for use in bank teller stations at banks and financial institutions +primarily in the U.S. As we continue to shift our focus to our new food service technology market, we do not expect any future sales of these legacy products, as we exited the banking market at the end of 2018. +14 +Sales of our casino and gaming products decreased 19% in 2019 compared to 2018. In our casino and gaming market, our focus lies +primarily in supplying printers worldwide for use in slot machines at casinos and racetracks, as well as in other electronic gaming devices that print tickets or receipts. Additionally, we supplement these printer sales with revenue from EPICENTRAL™, +our promotional printing system that enables casino operators to create promotional coupons and marketing messages and print them real time at the slot machine. The decrease of casino and gaming printer sales is primarily due to decreased domestic +and international sales of our thermal casino printers of 18% and 17%, respectively. The decrease in domestic thermal casino printers was driven primarily by lower sales to our OEMs and a large order of replacement printers from a domestic casino +operator in 2018 that did not reoccur in 2019. Total casino and gaming sales also decreased, although to a lesser extent, due to a 23% decrease in sales of our international off-premise gaming printers. +During the year ended December 31, 2019, total lottery printer sales decreased approximately 58% due to lower sales to IGT. Our +sales to IGT each year are directly dependent on the timing and number of new and upgraded lottery terminal installations IGT performs and are not indicative of IGT’s overall business or revenue. On December 31, 2019, we decided to end our +non-exclusive agreement with IGT and exit the lottery market as we have shifted our focus to our higher-value, technology-enabled market for food service technology and casino and gaming products. We do expect IGT to make a last time buy of lottery +printers in 2020, with no future sales expected beyond 2020. +Sales of our Printrex branded printers include wide format, rack mounted and vehicle mounted thermal printers used by customers to +log and plot oil field and down hole well drilling data in the oil and gas exploration industry. During the year ended December 31, 2019, we experienced a 10% decline in Printrex oil and gas printer sales. Although we will continue to fulfill +orders from existing customers during 2020, we have shifted our focus away from this market and towards our higher value, technology enabled restaurant solution terminals and casino and gaming products. +TSG, which sells service, replacement parts and consumable products, including receipt paper, ribbons and inkjet cartridges, +continues to offer a recurring revenue stream for the Company. TSG sales decreased 12% in 2019 from 2018 primarily due to lower sales of lottery printer spare parts to IGT for a legacy lottery printer. Although the installed base of our thermal +lottery printers remains large, we expect sales of spare parts to IGT to decline and overall TSG sales to decrease in 2020 compared to 2019. +Operationally, our gross margin was 47.9% in 2019, a decrease of 110 basis points from 2018 when we reached our highest reported full +year gross margin of 49%. +During 2019 our operating margin declined to 0.7% compared to 12.4% in 2018 primarily due to the 16% decline in sales and 8% increase +in operating expenses. Operating expenses increased primarily due to increased investments in the launch of BOHA!. During 2020, we expect operating expenses to increase more significantly compared to 2019, as we accelerate investment in engineering +and selling and marketing to take advantage of the opportunities we see in the food service technology market. +We reported net income of $0.5 million and net income per diluted share of $0.07 for 2019, compared to $5.4 million and net income +per diluted share of $0.70 for 2018. In terms of cash flow for 2019 we generated $4.8 million of cash from operating activities. We also returned $2.7 million to our shareholders during 2019 in the form of cash dividends. We ended the year with +cash and cash equivalents of $4.2 million and no debt on our Consolidated Balance Sheet at December 31, 2019. +Critical Accounting Policies and Estimates +The preparation of financial statements in conformity with generally accepted accounting principles requires management to make +estimates, judgments and assumptions that affect both Balance Sheet items and Statement of Income categories. Such estimates and judgments are based upon historical experience and certain assumptions that are believed to be reasonable in the +particular circumstances. We evaluate our assumptions on an ongoing basis by comparing actual results with our estimates. Actual results may differ from the original estimates. +The following accounting policies are those that we believe to be most critical in the preparation of our financial +statements. These items utilize assumptions and estimates about the effect of future events that are inherently uncertain and are therefore based on our judgment. Please refer to Note 2 – Summary of significant accounting policies in the +accompanying Consolidated Financial Statements for a complete listing of our accounting policies. +Revenue Recognition – We account for revenue in accordance with ASC Topic 606: Revenue from Contracts with Customers. We adopted ASC 606 effective January 1, 2018 and elected the modified retrospective approach. The results for +periods before 2018 were not adjusted for the new standard and there was no cumulative effect for the change in accounting at the date of adoption. In accordance with ASC 606, a performance obligation is a promise in a contract with a customer to +transfer a distinct good or service to the customer. Some of our contracts with customers contain a single performance obligation, while other contracts contain multiple performance obligations (most commonly when contracts include a hardware +product, software and extended warranties). A contract's transaction price is allocated to each distinct performance obligation and recognized as revenue when, or as, the performance obligation is satisfied. +The transaction price is determined based on the consideration to which the Company will be entitled in exchange for transferring +services to the customer. To the extent the transaction price includes variable consideration, such as price protection, reserves for returns and other allowances, the Company estimates the amount of variable consideration that should be included in +the transaction price utilizing either the “expected value” method or the “most likely amount” method depending on the nature of the variable consideration. Variable consideration is included in the transaction price if, in the Company’s judgment, +it is probable that a significant future reversal of cumulative revenue under the contract will not occur. +For a majority of our revenue, which consists of printers, terminals, consumables, and replacement parts, the Company recognizes +revenue as of a point of time. The transaction price is recognized upon shipment of the order when control of the goods is transferred to the customer and at the time the performance obligation is fulfilled. We also sell a software solution in our +casino and gaming market, EPICENTRAL™, that enables casino operators to create promotional coupons and marketing messages and to print them in real-time at the slot machine. EPICENTRAL TM is primarily comprised of both a software +component, which is licensed to the customer, and a hardware component. EPICENTRAL™ software and hardware are integrated to deliver the system's full functionality. The transaction prices from EPICENTRAL™ software license and hardware are +recognized upon installation and formal acceptance by the customer when control of the license is transferred to the customer. For out-of-warranty repairs, the transaction price is recognized after the repair work is completed and the printer or +terminal is returned to the customer, as control of the product is transferred to the customer and our performance obligation is completed. +15 +Performance obligations are satisfied over time if the customer receives the benefits as we perform work, if the customer controls +the asset as it is being produced, or if the product being produced for the customer has no alternative use and we have a contractual right to payment. For our separately priced extended warranty, BOHA! cloud-based software applications, technical +support for our food service technology terminals and maintenance agreements (including free one-year maintenance received by the customers upon completion of EPICENTRAL™ installation) revenue is recognized over time as the customer receives the +benefit. The transaction price from the maintenance services is recognized ratably over time, using output methods, as control of the services is transferred to the customer. The cloud-based software component of BOHA! allows customers to use +hosted software over the contract period without taking possession of the software and are provided on a subscription basis and is recognized ratably over the contract period. For extended warranties, the transaction price is recognized ratably over +the warranty period, using output methods, as control of the services is transferred to the customer. +When there is more than one performance obligation in a customer arrangement, the Company typically uses the “standalone selling +price” method to determine the transaction price to allocate to each performance obligation. The Company sells the performance obligations separately and has established standalone selling prices for its products and services. In the case of an +overall price discount, the discount is applied to each performance obligation proportionately based on standalone selling price. To determine the standalone selling price for initial EPICENTRAL™ installations, the Company uses the adjusted market +assessment approach. +Accounts +Receivable – We have standardized credit granting and review policies and procedures for all customer accounts, including: credit reviews of all new customer accounts; ongoing credit evaluations of current customers; credit limits and +payment terms based on available credit information; and adjustments to credit limits based upon payment history and the customer’s current creditworthiness. We also provide an estimate of doubtful accounts based on historical experience and +specific customer collection issues. Our allowance for doubtful accounts as of December 31, 2019 was $221 thousand, or 3.3% of outstanding accounts receivable, which we believe is appropriate considering the overall quality of our accounts +receivable. Although credit losses have historically been within expectations and the reserves established, there is no assurance that our credit loss experience will continue to be consistent with historical experience. +Inventories – +Our inventories are stated at the lower of cost (principally standard cost, which approximates actual cost on a first-in, first-out basis) or net realizable value. We review net realizable value based on estimated selling prices in the ordinary +course of business less estimated costs of completion, disposal and transportation, historical usage and estimates of future demand. Assumptions are reviewed at least quarterly and adjustments are made, as necessary, to reflect changing market +conditions. Based on these reviews, inventory write-downs are recorded, as necessary, to reflect estimated obsolescence, excess quantities and net realizable value. Should circumstances change and we determine that additional inventory is subject to +obsolescence, additional write-downs of inventory could result in a charge to income. +Goodwill and +Intangible Assets – We acquire businesses in purchase transactions that result in the recognition of goodwill and intangible assets. The determination of the value of intangible assets requires management to make estimates and assumptions. +In accordance with ASC 350-20 “Goodwill”, acquired goodwill is not amortized, but is subject to impairment testing at least annually and when an event occurs or circumstances change, which indicate it is more likely than not an impairment exists. +Factors considered that may trigger an impairment review are: significant underperformance relative to expected historical or projected future operating results; significant changes in the manner of use of acquired assets or the strategy for the +overall business; significant negative industry or economic trends; and significant decline in market capitalization relative to net book value. Definite-lived intangible assets are amortized and are tested for impairment when appropriate. We +reported $2.6 million of goodwill and $0.8 million of unamortized definite-lived intangible assets at December 31, 2019. We have determined that no goodwill or intangible asset impairment has occurred and the fair value of goodwill was substantially +higher than our carrying value based on our assessment as of December 31, 2019 when the impairment review was performed. +Income Taxes +– In preparing our Consolidated Financial Statements, we are required to estimate income taxes in each of the jurisdictions in which we operate. This involves estimating the actual current tax exposure together with assessing temporary differences +between the tax basis of certain assets and liabilities and their reported amounts in the financial statements, as well as net operating losses, tax credits and other carryforwards. These differences result in deferred tax assets and liabilities, +which are reflected in our Consolidated Balance Sheets. We then assess the likelihood that the deferred tax assets will be realized from future taxable income, and to the extent that we believe that realization is not likely, we establish a +valuation allowance. +Significant judgment is required in determining the provision for income taxes and, in particular, any valuation allowance or tax +reserves with respect to our deferred tax assets and uncertain tax positions. On a quarterly basis, we evaluate the recoverability of our deferred tax assets based upon historical results and forecasted taxable income over future years, and match +this forecast against the basis differences, deductions available in future years and the limitations allowed for net operating loss and tax credit carryforwards to ensure that there is adequate support for the realization of the deferred tax assets. +Although we have considered future taxable income and ongoing prudent and feasible tax planning strategies in assessing the need for a valuation allowance, in the event we were to determine that we would not be able to realize all or part of our +deferred tax assets in the future, an adjustment to the valuation allowance or tax reserves would be charged as a reduction to income in the period such determination was made. Likewise, should we determine that we would be able to realize future +deferred tax assets in excess of its net recorded amount, an adjustment to the valuation allowance would increase net income in the period such determination was made. +We account for income taxes in accordance with ASC 740, “Income Taxes.” Among other things this provision prescribes a minimum +recognition threshold that an income tax position must meet before it is recorded in the reporting entity’s financial statements. It also requires that the effects of such income tax positions be recognized only if, as of the balance sheet reporting +date, it is “more likely than not” (i.e., more than a 50% likelihood) that the income tax position will be sustained based solely on its technical merits. When making this assessment, management must assume that the responsible taxing authority will +examine the income tax position and have full knowledge of all relevant facts and other pertinent information. The accounting guidance also clarifies the method of accruing for interest and penalties when there is a difference between the amount +claimed, or expected to be claimed, on a company’s income tax returns and the benefits recognized in the financial statements. See Note 10 to the consolidated financial statements for further details of the impact of the Tax Reform Act. +16 +Warranty – +We generally warrant our products for up to 24 months and record the estimated cost of such product warranties at the time the sale is recorded. Estimated warranty costs are based upon actual past experience of product repairs and the related +estimated cost of labor and material to make the necessary repairs. If actual future product repair rates or the actual costs of material and labor differ from the estimates, adjustments to the accrued warranty liability and related warranty expense +would be made. +Share-Based +Compensation – We calculate share-based compensation expense in accordance with ASC 718, “Compensation – Stock Compensation” using the Black-Scholes option-pricing model to calculate the fair value of share-based awards. The key assumptions +for this valuation method include the expected term of an option grant, stock price volatility, risk-free interest rate, and dividend yield. We account for forfeitures as they occur. +Results of Operations: Year ended December 31, 2019 compared to Year ended December 31, 2018 +Net Sales. Net +sales, which include printer, terminal and software sales as well as sales of replacement parts, consumables and maintenance and repair services, by market for the years ended December 31, 2019 and 2018 are detailed in the below table. We have +reclassified sales of labels and other recurring revenue items, which includes extended warranty and service contracts, and technical support services related to our food service technology market, previously included in TSG to Food Service +Technology for all periods presented in this Form 10-K. +Year Ended +Year Ended +Change +(In thousands) +December 31, 2019 +December 31, 2018 +$ +% +Food service technology +$ +6,104 +13.3 +% +$ +5,086 +9.3 +% +$ +1,018 +20.0 +% +POS automation and banking +5,758 +12.6 +% +7,273 +13.3 +% +(1,515 +) +(20.8 +%) +Casino and gaming +21,529 +47.1 +% +26,593 +48.7 +% +(5,064 +) +(19.0 +%) +Lottery +1,291 +2.8 +% +3,093 +5.7 +% +(1,802 +) +(58.3 +%) +Printrex +1,166 +2.6 +% +1,297 +2.4 +% +(131 +) +(10.1 +%) +TSG +9,900 +21.6 +% +11,245 +20.6 +% +(1,345 +) +(12.0 +%) +$ +45,748 +100.0 +% +$ +54,587 +100.0 +% +$ +(8,839 +) +(16.2 +%) +International* +$ +10,416 +22.8 +% +$ +11,069 +20.3 +% +$ +(653 +) +(5.9 +%) +* +International sales do not include sales of products made to domestic distributors or other customers who in turn ship those products to international destinations. +Net sales for 2019 decreased $8.8 million, or 16%, from 2018. Printer, terminal and other hardware sales volume decreased by 22% to +approximately 111,000 units, driven primarily by a 17% decrease in unit volume from the casino and gaming market and, to a lesser extent, a 66% and 22% decrease in the lottery market and POS automation and banking market, respectively. The average +selling price of our printers, terminals and other hardware increased 2% during 2019 compared to 2018. +International sales decreased $0.7 million, or 6%, primarily driven by a 7% decrease of international casino and gaming sales. This +increase was partially offset by a 31% increase from our international food service technology market during 2019 compared to 2018. +Food service technology: The +primary offering in the food service technology market is our BOHA! ecosystem, which combines our latest generation terminal, cloud-based software applications and related hardware into a unique solution to automate back-of-house operations in +restaurants and food service operations. The software component of BOHA! consists of a suite of SaaS-based applications, including applications for inventory management, temperature monitoring of food and equipment, timers, food safety labeling, +food recalls, checklists and procedures, equipment service management, and delivery management. These applications are combined into a single platform with the associated hardware, which includes the BOHA! terminal, handheld devices, tablets, +temperature probes and temperature sensors. The BOHA! terminal combines the software and hardware components in a device that includes an operating system, touchscreen and one or two thermal print mechanisms that print easy-to-read food rotation +labels, grab and go labels for prepared foods, and “enjoy by” date labels. The BOHA! terminal is equipped with the TransAct Enterprise Management System to ensure that only approved applications and functions are available on the device, and allows +over-the-air updates to the applications and operating system. BOHA! helps food service establishments and restaurants (including fine dining, casual dining, fast casual and quick-serve restaurants, convenience stores, hospitality establishments and +contract food service providers) effectively manage food safety and grab-and-go initiatives, as well as automate and manage back-of-house operations. Recurring revenue from BOHA! is generated by software sales, including software subscriptions that +are charged to customers upfront on a per-application basis, as well as sales of labels, extended warranty and service contracts, and technical support services. In the food service technology market, we use an internal sales force and, to a lesser +extent, distributors, to solicit sales directly from end users. Sales of our worldwide food service technology products for the years ended December 31, 2019 and 2018 is as follows (in thousands, except percentages): +Year Ended +Year Ended +Change +(In thousands) +December 31, 2019 +December 31, 2018 +$ +% +Domestic +$ +5,522 +90.5 +% +$ +4,640 +91.2 +% +$ +882 +19.0 +% +International +582 +9.5 +% +446 +8.8 +% +136 +30.5 +% +$ +6,104 +100.0 +% +$ +5,086 +100.0 +% +$ +1,018 +20.0 +% +Year Ended +Year Ended +Change +(In thousands) +December 31, 2019 +December 31, 2018 +$ +% +Hardware +$ +4,169 +68.3 +% +$ +4,555 +89.6 +% +$ +(386 +) +(8.5 +%) +Software, labels and other recurring revenue +1,935 +31.7 +% +531 +10.4 +% +1,404 +264.4 +% +$ +6,104 +100.0 +% +$ +5,086 +100.0 +% +$ +1,018 +20.0 +% +17 +The increase in food service technology sales in 2019 compared to 2018 was driven by sales of our BOHA! software, labels and other +recurring revenue. Sales of BOHA! software, recognized on a SaaS subscription basis, labels and other recurring revenue increased by 264%, including a 241% increase in label sales and an eight-fold increase in software sales (though off a low base +for 2018). Hardware sales declined approximately 9% primarily due to lower sales of our AccuDate 9700 terminal to our former U.S. distributor. Sales of our new BOHA! terminal and other hardware products partially offset the decline of the AccuDate +9700 terminal, increasing 4% in 2019 compared to 2018. We expect food service technology sales to increase in 2020 compared to 2019 as we convert the investments we have made, and will continue to make in our BOHA! products, into sales, including +recurring software subscription, service and label sales. +International food service technology sales increased during 2019 compared to 2018 primarily due to increased sales of the BOHA! +ecosystem to a casino operator in Asia and a quick serve chain in Canada. +POS automation and banking: Revenue +from the POS automation and banking market includes sales of thermal printers used primarily by quick serve restaurants located either at the checkout counter or within self-service kiosks to print receipts for consumers or to print on linerless +labels. In addition, revenue includes sales of inkjet printers used by banks, credit unions and other financial institutions to print deposit or withdrawal receipts and/or validate checks at bank teller stations. As of December 31, 2018, we exited +the banking market, but will continue to fulfill orders from legacy customers until our inventory is exhausted and to sell consumable products through TSG that are compatible with the previously sold inkjet printers. A summary of sales of our +worldwide POS automation and banking products for the years ended December 31, 2019 and 2018 is as follows: +Year Ended +Year Ended +Change +(In thousands) +December 31, 2019 +December 31, 2018 +$ +% +Domestic +$ +5,714 +99.2 +% +$ +7,122 +97.9 +% +$ +(1,408 +) +(19.8 +%) +International +44 +0.8 +% +151 +2.1 +% +(107 +) +(70.9 +%) +$ +5,758 +100.0 +% +$ +7,273 +100.0 +% +$ +(1,515 +) +(20.8 +%) +The decrease in domestic POS automation and banking sales in 2019 compared to 2018 was primarily driven by a 20% +decrease in domestic sales of our Ithaca® 9000 printer, as sales to McDonald’s decreased during 2019 compared to 2018, and the decrease in international POS automation and banking sales was primarily due to lower sales of our Ithaca® 9000 printer to +our Canadian distributor for McDonald’s during 2019 compared to 2018. We expect POS automation and banking sales to decrease due to lower expected sales of our Ithaca® 9000 printer to McDonald's in 2020 compared to 2019. +Casino and Gaming: Revenue +from the casino and gaming market includes sales of thermal ticket printers used in slot machines, video lottery terminals, and other gaming machines that print tickets or receipts instead of issuing coins at casinos and racetracks and other gaming +venues worldwide. Revenue from this market also includes sales of thermal roll-fed printers used in the international off-premise gaming market in gaming machines such as Amusement with Prizes, Skills with Prizes and Fixed Odds Betting Terminals at +non-casino gaming establishments. Revenue from this market also includes royalties related to our patented casino and gaming technology. In addition, casino and gaming market revenue includes sales of the EPICENTRAL™ print system, our software +solution (including annual software maintenance), that enables casino operators to create promotional coupons and marketing messages and to print them real-time at the slot machine. A summary of sales of our worldwide casino and gaming products for the years ended December 31, 2019 and 2018 is as follows: +Year Ended +Year Ended +Change +(In thousands) +December 31, 2019 +December 31, 2018 +$ +% +Domestic +$ +13,076 +60.7 +% +$ +17,518 +65.9 +% +$ +(4,442 +) +(25.4 +%) +International +8,453 +39.3 +% +9,075 +34.1 +% +(622 +) +(6.9 +%) +$ +21,529 +100.0 +% +$ +26,593 +100.0 +% +$ +(5,064 +) +(19.0 +%) +The decrease in domestic sales of our casino and gaming products during 2019 compared to 2018 was due primarily to a 18% decrease in +domestic sales of our thermal casino printer, driven primarily by a large order from a domestic casino operator for replacement printers during 2018 that did not reoccur in 2019, as well as lower sales to our domestic OEMs. Additionally, domestic +sales of our off-premise gaming printers decreased 95% during 2019 compared to 2018 due to sales to an OEM in the 2018 period that did not reoccur in 2019. Domestic EPICENTRAL™ software sales decreased 60%, as we had no new installations during 2019 +compared to two new installations during 2018. Sales of EPICENTRAL™ are project based, and as a result, may fluctuate significantly quarter-to-quarter and year-to-year. +The decrease in international sales in 2019 compared to 2018 was primarily due to a 17% decline in international sales of our thermal +casino printer due primarily to lower sales to a large OEM in Europe to replace a competitor’s printer . The decrease was partially offset by a 26% increase in +international sales of our off-premise gaming printers to Europe for sports betting. Sales of our off-premise gaming printers are largely project-oriented and therefore may fluctuate significantly from quarter-to-quarter and year-to-year. +Lottery: Revenue from the +lottery market includes sales of thermal on-line and other lottery printers primarily to IGT and, to a lesser extent, other lottery system companies for various lottery applications. A summary of sales of our worldwide lottery printers for the years +ended December 31, 2019 and 2018 is as follows: +Year Ended +Year Ended +Change +(In thousands) +December 31, 2019 +December 31, 2018 +$ +% +Domestic +$ +1,290 +99.9 +% +$ +3,046 +98.5 +% +$ +(1,756 +) +(57.6 +%) +International +1 +0.1 +% +47 +1.5 +% +(46 +) +(97.9 +%) +$ +1,291 +100.0 +% +$ +3,093 +100.0 +% +$ +(1,802 +) +(58.3 +%) +18 +Our sales to IGT are directly dependent on the timing and number of new and upgraded lottery terminal installations that IGT +performs, and as a result, may fluctuate significantly quarter-to-quarter and year-to-year. Our sales to IGT are not indicative of IGT’s overall business or revenue. We allowed our non-exclusive agreement to provide lottery terminal printers to IGT +to expire on December 31, 2019 as we have decided to exit this market and to shift our focus towards our higher-value, technology enabled food service technology and casino and gaming products. As a result, we expect IGT to make a last time buy in +2020 and expect no future sales beyond 2020. +Printrex: Printrex branded +printers are sold into markets that include wide format, desktop and rack mounted and vehicle mounted black/white thermal printers used by customers to log and plot oil field, seismic and down hole well drilling data in the oil and gas exploration +industry. It also includes high-speed color inkjet desktop printers used to print logs at the data centers of the oil and gas field service companies. Prior to 2019, revenue in this market also included sales of vehicle mounted printers used to +print schematics and certain other critical information in emergency services vehicles and other mobile printing applications. We exited this market at the end of 2018 and do not expect any future sales. A summary of sales of our worldwide Printrex +printers for the years ended December 31, 2019 and 2018 is as follows (in thousands, except percentages): +Year Ended +Year Ended +Change +(In thousands) +December 31, 2019 +December 31, 2018 +$ +% +Domestic +$ +961 +82.4 +% +$ +1,028 +79.3 +% +$ +(67 +) +(6.5 +%) +International +205 +17.6 +% +269 +20.7 +% +(64 +) +(23.8 +%) +$ +1,166 +100.0 +% +$ +1,297 +100.0 +% +$ +(131 +) +(10.1 +%) +The decrease in sales of Printrex printers during 2019 compared to 2018 resulted from a 12% decrease in domestic and international +sales in the oil and gas market. This decrease was partially offset by higher sales from the international medical and mobile market which we exited at the end of 2018 but continued to fulfill orders from legacy customers during 2019. +TSG: Revenue generated by our +TSG includes sales of consumable products (inkjet cartridges, ribbons, receipt paper, and other printing supplies), replacement parts, maintenance and repair services, testing services, refurbished printers, and shipping and handling charges. TSG +sales for all periods presented in this Form 10-K exclude the sales of labels, extended warranty and service contracts, and technical support services related to our food service technology market, which have been reclassified to food service +technology. A summary of sales in our worldwide TSG market for the years ended December 31, 2019 and 2018 is as follows: +Year Ended +Year Ended +Change +(In thousands) +December 31, 2019 +December 31, 2018 +$ +% +Domestic +$ +8,769 +88.6 +% +$ +10,164 +90.4 +% +$ +(1,395 +) +(13.7 +%) +International +1,131 +11.4 +% +1,081 +9.6 +% +50 +4.6 +% +$ +9,900 +100.0 +% +$ +11,245 +100.0 +% +$ +(1,345 +) +(12.0 +%) +The decrease in domestic revenue from TSG for 2019 as compared to 2018 was due primarily to lower sales of replacement parts and +lower sales of consumable products. Replacement part sales decreased 29% due to lower lottery printer spare parts to IGT. Consumable sales declined 13% due largely to lower sales of HP inkjet cartridges used in our banking printers, as we exited +the banking market at the end of 2018. These decreases were partially offset by a 24% increase in service revenue during 2019 compared 2018. We expect TSG sales to decrease in 2020 compared to 2019 due to lower expected sales of lottery printer +spare printer parts to IGT and lower service sales related to a service contract with a banking customer that is expected to end in 2020. +Internationally, TSG revenue increased during 2019 compared to 2018 primarily due to a 18% increase in sales of replacement parts and +accessories to international casino and gaming customers. This increase was partially offset by a 60% decrease of international consumable sales in 2019 compared to 2018. +Gross Profit. Gross +profit information for the years ended December 31, 2019 and 2018 is summarized below (in thousands, except percentages): +December 31, +Percent +Percent of +Percent of +2019 +2018 +Change +Total Sales - 2019 +Total Sales - 2018 +Year ended +$ +21,935 +$ +26,743 +(18.0 +%) +47.9 +% +49.0 +% +Gross profit is measured as revenue less cost of sales, which includes primarily the cost of all raw materials and component parts, +direct labor, manufacturing overhead expenses, cost of finished products purchased directly from our contract manufacturers and expenses associated with installations and support of our EPICENTRAL TM print system and BOHA! ecosystem. Gross +profit decreased $4.8 million, or 18%, and gross margin decreased 110 basis points due primarily to the 16% sales decrease in 2019 compared to 2018. The decline in gross margin reflects higher manufacturing overhead expenses including approximately +$0.2 million incurred for the new Chinese tariffs and $0.4 million for the write-off of tooling related to a product design change incurred during the year ended December 31, 2019 compared to the year ended December 31, 2018. +Operating +Expenses - Engineering, Design and Product Development. Engineering, design and product development information for the years ended December 31, 2019 and 2018 is summarized below (in thousands, except percentages): +December 31, +Percent +Percent of +Percent of +2019 +2018 +Change +Total Sales - 2019 +Total Sales - 2018 +Year ended +$ +4,393 +$ +4,576 +(4.0 +%) +9.6 +% +8.4 +% +19 +Engineering, design and product development expenses primarily includes salary and payroll related expenses for our hardware and +software engineering staff, depreciation and design expenses (including prototype printer expenses, outside design, development and testing services, supplies and contract software development expenses). Engineering, design and product development +expenses decreased $183 thousand, or 4%, in 2019 compared to 2018 due primarily to lower expenses related to hardware product development for the food service technology market and casino and gaming market. We expect engineering, design and product +development expenses to increase in 2020 related to accelerated investments planned for our food service technology products. +Operating +Expenses - Selling and Marketing . Selling and marketing information for the years ended December 31, 2019 and 2018 is summarized below +(in thousands, except percentages): +December 31, +Percent +Percent of +Percent of +2019 +2018 +Change +Total Sales - 2019 +Total Sales - 2018 +Year ended +$ +8,033 +$ +7,203 +11.5 +% +17.6 +% +13.2 +% +Selling and marketing expenses primarily include salaries and payroll related expenses for our sales and marketing staff, sales +commissions, travel expenses, expenses associated with the lease of sales offices, advertising, trade show expenses, public relations, e-commerce and other promotional marketing expenses. Selling and marketing expenses increased $830 thousand, or +12%, in 2019 compared to 2018 due primarily to higher compensation expenses related to the hiring of additional outside sales, technical sales and marketing staff and higher promotional marketing expenses for our food service technology market. We +expect selling and marketing expenses to continue to increase in 2020 as we make substantial strategic investments in our food service technology sales and marketing groups. +Operating +Expenses - General and Administrative. General and administrative information for the years ended December 31, 2019 and 2018 is summarized below (in thousands, except percentages): +December 31, +Percent +Percent of +Percent of +2019 +2018 +Change +Total Sales - 2019 +Total Sales - 2018 +Year ended +$ +9,166 +$ +8,205 +11.7 +% +20.0 +% +15.0 +% +General and administrative expenses primarily include salaries, incentive compensation, and other payroll related expenses for our +executive, accounting, human resources and information technology staff, expenses for our corporate headquarters, professional and legal expenses, telecommunication expenses, and other expenses related to being a publicly-traded company. General and +administrative expenses increased $961 thousand, or 12%, in 2019 compared to 2018 due primarily to higher professional and legal expenses. We expect general and administrative expenses to increase in 2020 compared to 2019 due to the hiring of +additional administrative staff to support the anticipated growth in the food service technology market. +Operating Income. Operating +income information for the years ended December 31, 2019 and 2018 is summarized below (in thousands, except percentages): +December 31, +Percent +Percent of +Percent of +2019 +2018 +Change +Total Sales – 2019 +Total Sales – 2018 +Year ended +$ +343 +$ +6,759 +(94.9 +%) +0.7 +% +12.4 +% +Our operating income decreased by $6.4 million, or 95%, in 2019 due to a decrease in sales of 16% and an 8% increase in operating +expenses related to the investments made in our food service technology market during 2019 compared to 2018. +Interest. We +recorded net interest expense of $11 thousand in 2019 compared to $27 thousand in 2018 primarily due to interest income earned on the note receivable during 2019 partially offsetting interest expense. +Other, net . We recorded other income of $35 thousand in 2019 compared to other expense of $266 thousand in 2018 primarily due to foreign exchange gains recorded +by our UK entity during 2019 compared to foreign exchange losses recorded during 2018. Going forward, we may continue to experience more foreign exchange gains or losses depending on the level of sales to Europe through our UK subsidiary and the +change in exchange rates of the Euro and Pound Sterling against the U.S. dollar. +Income Taxes . We recorded an income tax benefit during the year ended December 31, 2019 of $149 thousand at an effective tax rate of -40.6%, compared to an income +tax provision during the year ended December 31, 2018 of $1.0 million at an effective tax rate of 16.1%. An income tax benefit was recorded in 2019 primarily due to the impact of research and development (R&D) credits on a relatively low level +of taxable income. +Net Income. We +reported net income of $0.5 million, or $0.07 per diluted share, in 2019 compared to net income of $5.4 million, or $0.70 per diluted share, in 2018. +20 +Results of Operations: Year ended December 31, 2018 compared to year ended December 31, 2017 +Net Sales. Net +sales, which include printer, terminal and software sales as well as sales of replacement parts, consumables and maintenance and repair services, by market for the years ended December 31, 2018 and 2017 are detailed in the below table. We have +reclassified sales of labels and other recurring revenue items, which includes extended warranty and service contracts, and technical support services related to our food service technology market, previously included in TSG to Food Service +Technology for all periods presented in this Form 10-K. +Year Ended +Year Ended +Change +(In thousands) +December 31, 2018 +December 31, 2017 +$ +% +Food service technology +$ +5,086 +9.3 +% +$ +4,862 +8.6 +% +$ +224 +4.6 +% +POS automation and banking +7,273 +13.3 +% +7,905 +14.0 +% +(632 +) +(8.0 +%) +Casino and gaming +26,593 +48.7 +% +18,615 +33.1 +% +7,978 +42.9 +% +Lottery +3,093 +5.7 +% +9,805 +17.4 +% +(6,712 +) +(68.5 +%) +Printrex +1,297 +2.4 +% +1,052 +1.9 +% +245 +23.3 +% +TSG +11,245 +20.6 +% +14,072 +25.0 +% +(2,827 +) +(20.1 +%) +$ +54,587 +100.0 +% +$ +56,311 +100.0 +% +$ +(1,724 +) +(3.1 +%) +International* +$ +11,069 +20.3 +% +$ +7,591 +13.5 +% +$ +3,478 +45.8 +% +* +International sales do not include sales of products made to domestic distributors or other customers who in turn ship those products to international destinations. +Net sales for 2018 decreased $1.7 million, or approximately 3%, from 2017. Printer and terminal sales volume decreased by 5% to +approximately 142,000 units, driven primarily by a 71% decrease in unit volume from the lottery market and, to a lesser extent, a 6% and 18% decrease in the POS automation and banking market and food service technology market, respectively. These +decreases were partially offset by an increase in sales volume of 44% in the casino and gaming market. Although unit volume decreased during 2018 compared to 2017, the average selling price of our printers and terminals increased 7% during 2018 +compared to 2017, due primarily to the decreased volume of lottery printers, which carry lower prices than our other products. +International sales increased $3.5 million, or 46%, primarily driven by 81% higher international sales in the casino and gaming +market. This increase was partially offset by a $1.1 million sales decrease in our international lottery market during 2018 compared to 2017. +Food service technology: A +summary of sales of our worldwide food service technology products for the years ended December 31, 2018 and 2017 is as follows: +Year Ended +Year Ended +Change +(In thousands) +December 31, 2018 +December 31, 2017 +$ +% +Domestic +$ +4,640 +91.2 +% +$ +4,488 +92.3 +% +$ +152 +3.4 +% +International +446 +8.8 +% +374 +7.7 +% +72 +19.3 +% +$ +5,086 +100.0 +% +$ +4,862 +100.0 +% +$ +224 +4.6 +% +Year Ended +Year Ended +Change +(In thousands) +December 31, 2018 +December 31, 2017 +$ +% +Hardware +$ +4,555 +89.6 +% +$ +4,758 +97.9 +% +$ +(203 +) +(4.3 +%) +Software, labels and other recurring revenue +531 +10.4 +% +104 +2.1 +% +427 +410.6 +% +$ +5,086 +100.0 +% +$ +4,862 +100.0 +% +$ +224 +4.6 +% +The increase in food service technology sales in 2018 compared to 2017 was due to increased sales of our labels and other recurring +revenue, primarily increased label sales which more than quadrupled in 2018 compared 2017. Hardware sales declined 4% in 2018 compared to 2017 due to lower sales of our AccuDate 9700 terminal for McDonald’s. This decrease was partially offset by +increased sales of our newer AccuDate XL2e terminal, which was renamed to our BOHA! terminal in 2019, to three large corporate customers. +International food service technology sales increased during 2018 compared to 2017 due to increased sales of the AccuDate 9700 for +McDonald’s through our Canadian distributor. +POS automation and banking: A +summary of sales of our worldwide POS automation and banking products for the years ended December 31, 2018 and 2017 is as follows: +Year Ended +Year Ended +Change +(In thousands) +December 31, 2018 +December 31, 2017 +$ +% +Domestic +$ +7,122 +97.9 +% +$ +7,596 +96.1 +% +$ +(474 +) +(6.2 +%) +International +151 +2.1 +% +309 +3.9 +% +(158 +) +(51.1 +%) +$ +7,273 +100.0 +% +$ +7,905 +100.0 +% +$ +(632 +) +(8.0 +%) +The decrease in domestic POS automation and banking sales in 2018 compared to 2017 was primarily driven by a 75% decrease in sales of +our legacy banking and other POS printers. These decreases were partially offset by a slight increase in domestic sales of our Ithaca® 9000 printers of 1% during 2018 compared to 2017, as sales rebounded to 2017, near-record levels during the second +and third quarters of 2018. +International POS automation and banking sales decreased due to lower sales of our Ithaca® 9000 printer to our Canadian distributor +for McDonald’s during 2018 compared to 2017. +21 +Casino and gaming: A summary +of sales of our worldwide casino and gaming products for the years ended December 31, 2018 and 2017 is as follows: +Year Ended +Year Ended +Change +(In thousands) +December 31, 2018 +December 31, 2017 +$ +% +Domestic +$ +17,518 +65.9 +% +$ +13,608 +73.1 +% +$ +3,910 +28.7 +% +International +9,075 +34.1 +% +5,007 +26.9 +% +4,068 +81.2 +% +$ +26,593 +100.0 +% +$ +18,615 +100.0 +% +$ +7,978 +42.9 +% +The increase in domestic sales of our casino and gaming products was due primarily to a 20% increase in domestic sales of our thermal +casino printer in 2018 compared to 2017, driven primarily by increased sales to our OEMs and a large order from a domestic casino operator for replacement printers. Domestic sales also increased during 2018 due to a significant sale of our +off-premise gaming printers to an OEM. Sales of EPICENTRAL™ software during 2018 were comparable with our 2017 EPICENTRAL™ sales as we completed two new installations during both 2018 and 2017. +The increase in international sales in 2018 compared to 2017 was due to a 143% increase of thermal casino printer sales. These +increases were due to the successful transition away from using our previous exclusive worldwide distributor whose contract ended at the end of 2017 and using our new direct sales team to sell to end user casino and gaming customers in Europe. These +increases were partially offset by a 5% decrease in international sales of off-premise gaming printers. +Lottery: A summary of sales +of our worldwide lottery printers for the years ended December 31, 2018 and 2017 is as follows: +Year Ended +Year Ended +Change +(In thousands) +December 31, 2018 +December 31, 2017 +$ +% +Domestic +$ +3,046 +98.5 +% +$ +8,626 +88.0 +% +$ +(5,580 +) +(64.7 +%) +International +47 +1.5 +% +1,179 +12.0 +% +(1,132 +) +(96.0 +%) +$ +3,093 +100.0 +% +$ +9,805 +100.0 +% +$ +(6,712 +) +(68.5 +%) +Our sales to IGT are directly dependent on the timing and number of new and upgraded lottery terminal installations that IGT +performs, and as a result, may fluctuate significantly quarter-to-quarter and year-to-year. However, our lottery market sales are not indicative of IGT’s overall business or revenue. +The decrease in international lottery sales in 2018 compared to 2017 was primarily due to a sale of lottery printers to IGT for the +Canadian lottery in 2017 and no comparable sale occurring in 2018. +Printrex: A summary of sales +of our worldwide Printrex printers for the years ended December 31, 2018 and 2017 is as follows (in thousands, except percentages): +Year Ended +Year Ended +Change +(In thousands) +December 31, 2018 +December 31, 2017 +$ +% +Domestic +$ +1,028 +79.3 +% +$ +849 +80.7 +% +$ +179 +21.1 +% +International +269 +20.7 +% +203 +19.3 +% +66 +32.5 +% +$ +1,297 +100.0 +% +$ +1,052 +100.0 +% +$ +245 +23.3 +% +The increase in Printrex sales in 2018 compared to 2017 resulted from a 57% increase in domestic and international sales of our oil +and gas printers due to a continued recovery in the oil and gas market. This increase was partially offset by 87% lower sales of domestic and international medical and mobile printers in 2018 compared to 2017. +TSG: A summary of sales in +our worldwide TSG market for the years ended December 31, 2018 and 2017 is as follows: +Year Ended +Year Ended +Change +(In thousands) +December 31, 2018 +December 31, 2017 +$ +% +Domestic +$ +10,164 +90.4 +% +$ +13,553 +96.3 +% +$ +(3,389 +) +(25.0 +%) +International +1,081 +9.6 +% +519 +3.7 +% +562 +108.3 +% +$ +11,245 +100.0 +% +$ +14,072 +100.0 +% +$ +(2,827 +) +(20.1 +%) +The decrease in domestic revenue from TSG in 2018 compared to 2017 was due primarily to lower sales of replacement parts, +non-Printrex consumable products and service revenue. Replacement part sales decreased 36% due to lower sales of lottery printer spare parts to IGT. Non-Printrex consumables sales declined 10% due to lower sales of our legacy HP inkjet cartridges +used in our banking printers, as we exited the banking market at the end of 2018. Service revenue declined 14% in 2018 compared to 2017 due to paper testing sales that occurred in 2017 but did not repeat in 2018. +Internationally, TSG revenue increased primarily due to a 134% increase in sales of replacement parts and accessories in 2018 +compared to 2017, as sales of replacement parts and accessories to international casino and gaming customers increased upon the transition away from using our previous exclusive worldwide distributor and using our new direct sales team to sell to end +user casino and gaming customers. +22 +Gross Profit. Gross +profit information for the years ended December 31, 2018 and 2017 is summarized below (in thousands, except percentages): +December 31, +Percent +Percent of +Percent of +2018 +2017 +Change +Total Sales - 2018 +Total Sales - 2017 +Year ended +$ +26,743 +$ +26,662 +0.3 +% +49.0 +% +47.3 +% +Gross profit increased $81 thousand, or less than 1%, and gross margin increased 170 basis points due primarily to a more favorable +sales mix in 2018 compared to 2017. The increased gross margin reflected a favorable shift in sales mix towards higher-value, technology driven solutions, as well as lower sales volume of lottery and POS printers, which carry lower margins than our +other products. +Operating +Expenses - Engineering, Design and Product Development. Engineering, design and product development information for the years ended December 31, 2018 and 2017 is summarized below (in thousands, except percentages): +December 31, +Percent +Percent of +Percent of +2018 +2017 +Change +Total Sales - 2018 +Total Sales - 2017 +Year ended +$ +4,576 +$ +4,303 +6.3 +% +8.4 +% +7.6 +% +Engineering, design and product development expenses increased $273 thousand, or 6%, in 2018 compared to 2017 due primarily to the +hiring of additional engineering staff and increased expenses related to product development for the food service technology and casino and gaming markets. +Operating Expenses - Selling and Marketing . Selling and marketing information for the years ended December 31, 2018 and 2017 is +summarized below (in thousands, except percentages): +December 31, +Percent +Percent of +Percent of +2018 +2017 +Change +Total Sales - 2018 +Total Sales - 2017 +Year ended +$ +7,203 +$ +7,561 +(4.7 +%) +13.2 +% +13.4 +% +Selling and marketing expenses decreased $358 thousand, or 5%, in 2018 compared to 2017 primarily due to the retirement of our EVP, +Sales and Marketing in December 2017, whose position was replaced by an existing employee of TransAct, as well as the elimination of sales commission expense to our former international casino and gaming distributor, Suzo-Happ. These decreases were +partially offset by the hiring of additional sales staff to replace our former exclusive worldwide distributor with a direct selling team for our casino and gaming sales in Europe. +Operating +Expenses - General and Administrative. General and administrative information for the years ended December 31, 2018 and 2017 is summarized below (in thousands, except percentages): +December 31, +Percent +Percent of +Percent of +2018 +2017 +Change +Total Sales - 2018 +Total Sales - 2017 +Year ended +$ +8,205 +$ +7,984 +2.8 +% +15.0 +% +14.2 +% +General and administrative expenses increased $221 thousand, or 3%, in 2018 compared to 2017 due primarily to increased legal +expenses and increased administrative expenses related to the expansion of our food service technology sales staff and transitioning to a direct selling model for the casino and gaming market in Europe. These increases were partially offset by lower +incentive compensation expense in 2018 compared to 2017. +Operating Income +(Loss). Operating income information for the years ended December 31, 2018 and 2017 is summarized below (in thousands, except percentages): +December 31, +Percent +Percent of +Percent of +2018 +2017 +Change +Total Sales – 2018 +Total Sales – 2017 +Year ended +$ +6,759 +$ +6,814 +(0.8 +%) +12.4 +% +12.1 +% +Our operating income decreased by $55 thousand, or 1%. Despite a sales decline of 3% our operating margin improved, increasing 30 +basis points to 12.4% in 2018 compared to 12.1% in 2017, largely due to a 170 basis point increase in gross margin somewhat offset by a 1% increase in operating expenses. +Interest. We +recorded net interest expense of $27 thousand in 2018 compared to $33 thousand in 2017. +Other, net . We recorded other expense of $266 thousand in 2018 compared to $9 thousand in 2017. The additional expense was due to higher foreign currency +exchange losses recorded by our U.K. subsidiary in 2018 compared to 2017. +Income Taxes . We recorded an income tax provision during the year ended December 31, 2018 of $1.0 million at an effective tax rate of 16.1%, compared to an income +tax provision during the year ended December 31, 2017 of $3.6 million at an effective tax rate of 52.6%. The effective tax rate in 2018 was lower than the effective tax rate in 2017 due to the enactment of the Tax Reform Act that was signed on +December 22, 2017. Additionally, the effective tax rate in 2017 was unusually high due to the initial impact of the Tax Reform Act as we recognized a provisional $1.3 million charge to income tax expense for the year ended December 31, 2017 as a +result of revaluing our net deferred tax assets using the new U.S. corporate tax rate of 21%. +Net Income. We +reported net income during 2018 of $5.4 million, or $0.70 per diluted share, compared to $3.2 million, or $0.42 per diluted share, for 2017. +23 +Liquidity and Capital Resources +We assess our liquidity in terms of our ability to generate cash to fund our operating, investing and financing +activities. Significant factors affecting the management of liquidity are cash flows from operating activities, capital expenditures, access to bank lines of credit and our ability to attract long-term capital with satisfactory terms. +Internal cash generation together with currently available cash and cash equivalents, available borrowing facilities and an ability +to access credit lines, if needed, are expected to be sufficient to fund operations, capital expenditures, and any increase in working capital that would be required to accommodate a higher level of business activity. We may actively seek to expand +by acquisition as well as through the growth of our current business. While a significant acquisition may require additional debt and/or equity financing, although no assurances can be given, we believe that we would be able to obtain additional +financing based on our available collateral and historical earnings performance. +Cash Flow +During 2019 our cash balance decreased $0.5 million, or 10%, from December 31, 2018 and we returned cash to shareholders of $2.7 +million in the form of cash dividends paid to common shareholders. Additionally, we issued a note receivable of $1 million to a third party in 2019. Even after funding these items and our capital expenditures, we had $4.2 million in cash and cash +equivalents as of December 31, 2019, of which $0.9 million was held by our UK subsidiary, and no debt outstanding. +Operating activities : The +following significant factors primarily affected our cash provided by operating activities of $4.8 million in 2019 as compared to $5.1 million in 2018. During 2019: +● +We reported a net income of $0.5 million. +● +We recorded depreciation and amortization of $1.4 million and share-based compensation expense of $0.7 million. +● +Accounts receivable decreased $1.6 million, or 20%, primarily due to strong collections on receivables during the fourth quarter of 2019. +● +Inventories decreased $0.8 million, or 6%, primarily due to the utilization of inventory on hand to fulfill sales. +● +Prepaid income taxes decreased $0.6 million, or 71%, primarily due to an income tax refund received in the fourth quarter of 2019. +● +Other current and long-term assets increased $0.3 million, or 47%, due primarily to an advanced payment of royalty fees to a technology partner for food service +technology. +● +Accounts payable decreased $0.5 million, or 15%, primarily due to the utilization of inventory on hand to fulfill sales requiring a lower level of inventory +purchases during the second half of 2019. +● +Accrued liabilities and other liabilities increased $0.4 million, or 11%, due primarily to an increase in deferred revenue related to our food service technology +service contracts and software subscriptions. +During 2018: +● +We reported a net income of $5.4 million. +● +We recorded depreciation and amortization of $1.0 million and share-based compensation expense of $0.6 million. +● +Accounts receivable decreased $2.7 million, or 25%, primarily due to the collection of past due receivables from 2017 sales made to our former international +casino and gaming distributor. +● +Inventories increased $4.0 million, or 46%, primarily due to the buildup of inventory on hand to support future anticipated sales in the casino and gaming market +and food service technology market. +● +Accounts payable decreased $0.3 million, or 9%, primarily due to the timing of inventory purchases in 2017 compared to 2018. +● +Accrued liabilities and other liabilities decreased $0.2 million, or 5%, due primarily to a decrease in our accrued incentive compensation. +Investing activities : Our +capital expenditures, including capitalized software costs, were $1.4 million and $1.5 million in 2019 and 2018, respectively. Expenditures in 2019 were primarily for new product tooling equipment, and, to a lesser extent, computer and networking +equipment. Expenditures in 2018 were primarily for computer and networking equipment and furniture and fixtures purchases related to investments made in our UK facility to support the build-out of our internal sales infrastructure to sell directly +to slot machine manufacturers and end-user casino and gaming customers. To a lesser extent, expenditures in 2018 included computer and networking equipment for our U.S. operations and leasehold improvements made at our Las Vegas facility. +Capital expenditures and additions to capitalized software for 2020 are expected to be approximately $1.1 million, primarily for +new product tooling, new computer software and equipment purchases and leasehold improvements to support our food service technology market. +Financing activities : We +used $2.9 million of cash from financing activities during 2019 to pay dividends of $2.7 million and $0.2 million related to the relinquishment of shares to pay for withholding taxes on stock issued from our stock compensation plan. During 2018, +we used $4.5 million of cash to pay dividends of $2.7 million to common shareholders, purchase $2 million of common stock for treasury and $0.3 million related to the relinquishment of shares to pay for withholding taxes on stock issued from our +stock compensation plan, partially offset by proceeds from stock option exercises of $0.4 million. +Resource Sufficiency +We believe that our cash and cash equivalents on hand, cash flows generated from operating activities and access to our credit +facility will provide sufficient resources to meet our working capital needs, finance our capital expenditures, support planned investments for our food service technology market and meet our liquidity requirements through at least the next twelve +months. +Credit Facility and Borrowings +During 2019 we maintained a credit facility (the “TD Bank Credit Facility”) with TD Bank N.A. (“TD Bank) which provided for a $20 +million revolving credit line. On November 21, 2017, we signed an amendment to the TD Bank Credit Facility through November 28, 2022. Borrowings under the revolving credit line bear a floating rate of interest at the prime rate minus one percent +and are secured by a lien on all our assets. We also pay a fee of 0.125% on unused borrowings under the revolving credit line. The amendment increased the amount of revolving credit loans we may use to fund future cash dividend payments or treasury +share buybacks to $12.5 million from $10 million. +24 +The TD Bank Credit Facility imposes certain quarterly financial covenants on us and restricts, among other things, our ability to +incur additional indebtedness and the creation of other liens. On November 6, 2019, we amended our TD Credit Facility to change the definition of interest expense to exclude fees paid on unused borrowings under the revolving credit line which is used +to calculate total debt service in the operating cash flow to total debt service. Additionally, the amendment limited our maximum loan amount to $1 million. We were in compliance with all financial covenants of the TD Bank Credit Facility at +December 31, 2019. +Financial Covenant +Requirement/Restriction +Calculation at December 31, 2019 +Operating cash flow / Total debt service +Minimum of 1.25 times +0 +Funded debt / EBITDA +Maximum of 3.0 times +0 times +As of December 31, 2019, we had no outstanding borrowings under the TD Bank Credit facility. +On March 13, 2020 we terminated our TD Bank Credit Facility and signed a $10 million credit facility (the “Siena Credit Facility”) +with Siena Lending Group LLC. The Siena Credit Facility replaced our TD Bank Credit Facility. The Siena Credit Facility provides for a $10 million revolving credit line expiring on March 13, 2023. Borrowings under the Siena Credit Facility bear +a floating rate of interest equal to the greatest of (i) the prime rate plus 1.75%, (ii) the federal funds rate plus 2.25%, and (iii) 6.50%. We incurred a closing fee of $63 thousand payable 50% on the closing date and 50% on the first anniversary of +the closing date. We will also pay a fee of 0.50% on unused borrowings under the facility. Borrowings under the facility are secured by a lien on substantially all the assets of the Company. The Siena Credit Facility imposes certain financial +covenants on the Company and borrowings are subject to a borrowing base based on (i) 85% of eligible accounts receivable plus the lesser of (a) $5,000,000 and (b) 50% of eligible raw material and 60% of finished good inventory. +Shareholder Dividend Payments +In 2012, our Board of Directors initiated a quarterly cash dividend program which is subject to the Board’s approval each +quarter. Our Board of Directors declared an increase to the quarterly cash dividend from $0.06 to $0.07 per share in May 2013, from $0.07 to $0.08 per share in May 2014, and from $0.08 to $0.09 per share in May 2017. Dividends declared and paid on +our common stock totaled $2.7 million or $0.36 per in both 2019 and 2018. On January 23, 2020, our Board of Directors announced the cessation of our quarterly cash dividend on the Company’s common stock to accelerate the investment in sales and +marketing, continued product development and infrastructure of the BOHA! ecosystem. The final dividend payment was made in December 2019. +Stock Repurchase Program +Prior to its expiration on December 31, 2019, we maintained a stock repurchase program (the "2018 Stock Repurchase Program") whereby +we were authorized to repurchase up to $5 million of our outstanding shares of common stock from time to time in the open market at prevailing market prices based on market conditions, share price and other factors. We use the cost method to account +for treasury stock purchases, under which the price paid for the stock is charged to the treasury stock account. Repurchases of our common stock are accounted for as of the settlement date. During 2019 we did not repurchase any shares of our common +stock. From the start of the 2018 Stock Repurchase Program on March 1, 2018 through December 31, 2018, we repurchased 156,410 shares of our common stock for approximately $2.0 million at an average price per share of $12.79. +In 2017, under a prior repurchase program that was in place from February 25, 2016 through December 31, 2017, we purchased 36,465 +shares of our common stock for $0.4 million at an average price of $9.84 per share. From January 1, 2005 through December 31, 2019, we repurchased a total of 4,044,842 shares of common stock for $32.1 million, at an average price of $7.94 per share. +Shareholders’ Equity +Shareholders’ equity decreased $1.6 million, or 6%, to $25.9 million at December 31, 2019 from $27.6 million at December 31, +2018. The decrease was due to the payment of $2.7 million in dividends during 2019 and $0.2 million related to the relinquishment of stock awards to pay for withholding taxes on stock awards. These decreases were partially offset by net income of +$0.5 million, as well as share-based compensation expense related to stock awards of $0.7 million. +Off-Balance Sheet Arrangements +As of December 31, 2019, we had no off-balance sheet arrangements that have had or that we expect would be reasonably likely to have +a future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources. +Contractual Obligations +Our contractual obligations as of December 31, 2019 were as follows: +Payments due by period +(In thousands) +Total +Less than +1 year +1-3 years +3-5 years +More than +5 years +Operating lease obligations +$ +3,344 +$ +1,042 +$ +1,145 +$ +541 +$ +616 +Purchase obligations +9,056 +$ +9,056 +$ +- +– +– +Total +$ +12,400 +$ +10,098 +$ +1,145 +$ +541 +$ +616 +Purchase obligations are for purchases made in the normal course of business to meet operational requirements, primarily of fully +assembled printers, terminals and component part inventory. +Impact of Inflation +We believe that our business has not been affected to a significant degree by inflationary trends during the past three +years. However, inflation is still a factor in the worldwide economy and may increase the cost of purchasing products from our contract manufacturers in Asia, as well as the cost of certain raw materials, component parts and labor used in the +production of our products. It also may increase our operating expenses, manufacturing overhead expenses and the cost to acquire or replace fixed assets. We have generally been able to maintain or improve our profit margins through productivity and +efficiency improvements, cost reduction programs and to a lesser extent, price increases, and we expect to be able to do the same during 2020. As such, we do not believe that inflation will have a significant impact on our business during 2020. +25 +Item 7A. Quantitative and Qualitative Disclosures about Market +Risk. +Interest Rate Risk +Our exposure to market risk for changes in interest rates relates primarily to the investment of our available cash and cash +equivalents. In accordance with our investment policy, we strive to achieve above market rates of return in exchange for accepting a prudent amount of incremental risk, which includes the risk of interest rate movements. Risk tolerance is +constrained by an overriding objective to preserve capital. An increase or decrease of 10% in effective interest rates would not have a material effect on our results of operations or cash flows. +Foreign Currency Exchange Risk +Transaction Exposure – We +transact business in foreign currencies and have international revenue, as well as costs denominated in foreign currencies which are the Euro and Pound Sterling. As a result, we are exposed to the risk of fluctuations in foreign currency exchange +rates. Accordingly, changes in exchange rates, and in particular a strengthening of the U.S. dollar, would negatively affect our revenue and other operating results as expressed in U.S. dollars. +Beginning in 2018, we have experienced increased fluctuations in our net loss as a result of transaction gains or losses related to +revaluation and ultimately settling certain asset and liability balances that are denominated in currencies other than the functional currency of our UK subsidiary, which is Pound Sterling. Net realized and unrealized foreign currency gains were $35 +thousand in 2019 and net realized and unrealized losses were $267 thousand and $11 thousand in 2018 and 2017, respectively. +The change in foreign currency gains and losses is primarily a result of increased sales recognized by our U.K. subsidiary upon the +adoption of a direct selling model in Europe in 2018. We do not use derivative financial instruments to manage foreign currency exchange risk exposure. As a result, both positive and negative currency fluctuations against the U.S. dollar may affect +our results of operations. Based on our foreign currency exposures from monetary assets and liabilities, we estimate that a 10% change in exchange rates against the U.S. dollar would have resulted in a gain or loss of approximately $280 thousand as +of December 31, 2019. +Translation Exposure – We +are also exposed to foreign exchange rate fluctuations as we translate the financial statements of our UK subsidiary into U.S. dollars in consolidation. If there is a change in foreign currency exchange rates, the translating adjustments resulting +from the conversion of our U.K. subsidiary into U.S. dollars would result in a gain or loss recorded as a component of accumulated other comprehensive loss which is part of stockholders’ equity. +Item 8. Financial Statements and Supplementary Data. +The financial statements of the Company are annexed to this Annual Report as pages F-3 through F-21. The “Report of Independent +Registered Public Accounting Firm” is annexed to this Annual Report as of page F-2. An index to such materials appears on page F-1. +Item 9. Changes in and Disagreements with Accountants on +Accounting and Financial Disclosure. +None. +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +Our management, with the participation of our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), evaluated the +effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Exchange Act as of December 31, 2019. In the Amendment to our Annual Report on Form 10-K for the year ended December 31, 2018, filed with the SEC on +November 21, 2019, we disclosed that management, including our CEO and CFO, concluded that our disclosure controls and procedures were not effective as of December 31, 2018, due to material weaknesses in our internal control over financial reporting +as described below. As of December 31, 2019, these material weaknesses were not fully remediated and our disclosure controls and procedures were not effective as of December 31, 2019. Management has begun remediation efforts, which are described +below. +Notwithstanding these material weaknesses, our management, including our CEO and CFO, has concluded that our consolidated financial +statements, included in this Form 10-K, fairly present, in all material respects, our financial condition, results of operations and cash flows for the periods presented in conformity with generally accepted accounting principles, and that they can +still be relied upon. +Management’s Annual Report on Internal Control Over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial +reporting, as defined in Rule 13a-15(f) under the Exchange Act, to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with generally +accepted accounting principles. Internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions +of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures +of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the +Company’s assets that could have a material effect on the financial statements. +26 +Our management assessed our internal control over financial reporting as of December 31, 2019. Our management +based its assessment on criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the +Treadway Commission (“2013 COSO”). In the opinion of management, TransAct did not maintain effective internal control over financial reporting as of December 31, 2019 solely because of the material weaknesses in internal control over financial +reporting described below that existed as of December 31, 2018 and were not remediated as of December 31, 2019. +A material weakness is defined in Rule 12b-2 under the Exchange Act as a deficiency, or a combination of +deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis. +We identified the following control deficiencies that constituted material weaknesses in our internal control +over financial reporting as of December 31, 2019 and 2018. +We did not design and maintain effective controls over user access within the Company’s ERP system, +Oracle, to ensure appropriate segregation of duties and to adequately restrict user access to appropriate personnel. Specifically, the provisioning and user recertification controls are not designed to ensure users maintain proper +segregation of duties and therefore could have inappropriate access rights. (the “Access Control Weakness”). +We did not design and maintain effective controls over the completeness and accuracy of information +included in key spreadsheets supporting our accounting records (the “Spreadsheet Control Weakness”). +The control deficiencies constituted material weaknesses but did not result in a material misstatement of our +annual or interim consolidated financial statements. However, if these material weaknesses are not remediated, a material misstatement of account balances or disclosures may not be prevented, and may go undetected, which could result in a material +misstatement of future annual or interim consolidated financial statements. +The effectiveness of the Company’s internal control over financial reporting as of December 31, 2019 has been +audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on pages F-2 through F-3 of this Form 10-K. +Remediation Plan +During 2019, we commenced developing and implementing a plan to enhance the design and operating effectiveness +of our internal control over financial reporting, which includes taking the following steps to remediate the identified control deficiencies and material weaknesses: +To address the Access Control Weakness, we are utilizing the services of an Oracle consulting firm to +assist us in analyzing and reviewing Oracle access for all users. During the first quarter of 2020, we completed the analysis and have developed an action plan to modify the designated Oracle responsibilities for each employee with respect +to whom a conflict was identified to remove any Oracle transactional responsibilities that we believe are conflicting and, in some instances, we will reassign those responsibilities to a different employee to ensure proper segregation of +duties. We have begun the design and testing of the new Oracle responsibilities created. In addition, we plan to enhance and implement provisioning and user certification controls to ensure we maintain the appropriate segregation of +duties within Oracle following the analysis. +To address the Spreadsheet Control Weakness, for each key spreadsheet using Oracle data, we plan to +evaluate and determine (1) if a standard Oracle report exists containing the same information as the spreadsheet, and if so, we would utilize the standard Oracle report (without modification) instead of the spreadsheet to support our +accounting records and (2) if a standard Oracle report cannot be used, we will implement a new key control whereby an employee performs a formal validation that the information from Oracle is completely and accurately transferred +(automatically or manually) to a spreadsheet by verifying totals and other information on a test basis. For all other key spreadsheets, we plan to design and implement a new key control to validate completeness and accuracy of information +supporting our accounting records. During the first quarter of 2020, we began the process of evaluating each key spreadsheet based on the above criteria, and for several key spreadsheets, we implemented a new key control to validate the +completeness and accuracy of the information contained within and supporting each such spreadsheet. +We believe these steps will address the material weaknesses described above. +Changes in Internal Control over Financial Reporting +There has been no change in our internal control over financial reporting that occurred during the quarter ended December 31, 2019 +that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. +Item 9B. Other Information. +Not applicable. +27 +PART III +Item 10. Directors, Executive Officers and Corporate Governance. +Set forth in Item 1 of this Form 10-K is certain information regarding our executive officers. The remaining information in response +to this item will be contained in our Proxy Statement for our 2020 Annual Meeting of Stockholders (the “Proxy Statement”) under the headings, “Delinquent Section 16(a) Reportings,” “Corporate Governance,” “Proposal 1: Election of Directors,” “Audit +Committee Report,” “Executive Compensation – Compensation Committee Report,” “Compensation Committee Interlocks and Insider Participation,” “Stockholder Proposals for 2020 Annual Meeting,” “Procedures for Submitted Director Nominations and +Recommendations” and “Stockholder Communications with the Board of Directors Policy,” which will be filed within 120 days after the end of the year covered by this Form 10-K and is incorporated herein by reference. +Code of Ethics +We maintain a Code of Business Conduct that includes our code of ethics that is applicable to all employees, including our Chief +Executive Officer, Chief Financial Officer and Controller. Our Code of Business Conduct, which requires continued observance of high ethical standards, such as honesty, integrity and compliance with the law in the conduct of our business, is +available for public access on our Internet website at https://transacttech.gcs-web.com/corporate-governance. Any person may request a copy of our Code of Business Conduct free of charge by calling (203) 859-6800. +Item 11. Executive Compensation. +The information in response to this item will be contained in the Proxy Statement under the heading “Executive Compensation,” and is +incorporated herein by reference. +Item 12. Security Ownership of Certain Beneficial Owners and +Management and Related Stockholder Matters. +Set forth below is certain information regarding our equity compensation plans. The remaining information in response to this item +will be contained in the Proxy Statement under the heading, “Security Ownership of Certain Beneficial Owners and Management,” and is incorporated herein by reference. +Equity Compensation Plan Information +Information regarding our equity compensation plans as of December 31, 2019 is as follows: +Plan category +(a) +Number of +securities to be +issued upon exercise +of outstanding options, +warrants and rights +(b) +Weighted-average +exercise price of +outstanding +options, warrants +and rights +(c) +Number of securities +remaining available for +future issuance under +equity compensation plans +(excluding securities +reflected in column (a) +Equity compensation plans approved by security holders: +2005 Equity Incentive Plan +363,500 +$ +9.18 +– +2014 Equity Incentive Plan +869,543 +8.29 +332,541 +Total +1,233,043 +$ +8.56 +332,541 +In May 2014, our stockholders approved the adoption of the 2014 Equity Incentive Plan. In May 2017, our stockholders approved an +amendment to the 2014 Equity Incentive Plan to increase the number of shares of common stock which may be subject to awards granted under the plan from 600,000 to its current level of 1,400,000. The Company also maintains the 2005 Equity Incentive +Plan; however no new awards will be available for future issuance under this plan. Both plans generally provide for award in the form of: (i) incentive stock options, (ii) non-qualified stock options, (iii) restricted stock, (iv) restricted stock +units (which may include performance-based vesting), (v) stock appreciation rights or (vi) limited stock appreciation rights. The Company does not have any equity plans that have not been approved by its stockholders. +Item 13. Certain Relationships and Related Transactions, and +Director Independence. +The information in response to this item will be contained in the Proxy Statement under the headings “Certain Relationships and +Related Transactions” and is incorporated herein by reference. +Item 14. Principal Accountant Fees and Services. +The information in response to this item will be contained in the Proxy Statement under the headings, “Policy Regarding Pre-Approval +of Services Provided by the Independent Registered Public Accounting Firm” and “Independent Registered Public Accounting Firm’s Services and Fee’s” and is incorporated herein by reference. +28 +PART IV +Item 15. Exhibits and Financial Statement Schedules. +(a) +The following documents are filed as part of this Form 10-K: +1. +Financial Statements. +Report of Independent Registered Public Accounting Firm +Consolidated Balance Sheets as of December 31, 2019 and 2018 +Consolidated Statements of Income for the years ended December 31, 2019, 2018, and 2017 +Consolidated Statements of Comprehensive Income for the years ended December 31, 2019, 2018 and 2017 +Consolidated Statements of Changes in Shareholders' Equity for the years ended December 31, 2019, 2018 and +2017 +Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017 +Notes to Consolidated Financial Statements +2. +Schedules. +All schedules are omitted because they are either inapplicable or not required, or because the information required therein is included +in the Consolidated Financial Statements and Notes thereto. +29 +3. Exhibits. +Exhibits Index +3.1(a) +Certificate of Incorporation of TransAct Technologies Incorporated (conformed copy) (incorporated by reference to Exhibit 3(i) of the Company’s +Quarterly Report on Form 10-Q (SEC File No. 000-21121) filed with the SEC on August 9, 2019). +3.1(b) +Certificate of Designation, Series A Preferred Stock, filed with the Secretary of State of Delaware on December 2, 1997 (incorporated by reference +to Exhibit C of the Company’s Current Report on Form 8-K (SEC File No. 000-21121) filed with the SEC on February 18, 1999). +3.1(c) +Certificate of Designation, Series B Preferred Stock, filed with the Secretary of State of Delaware on April 6, 2000 (incorporated by reference to +Exhibit 3.1(c) of the Company’s Quarterly Report on Form 10-Q (SEC File No. 000-21121) filed with the SEC on May 8, 2000). +3.2 +Amended and Restated By-laws of the Company (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K (SEC File No. +000-21121) filed with the SEC on August 2, 2019). +4.1 +Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 of the Company’s Registration Statement on Form S-1/A (No. 333-06895) +filed with the SEC on August 1, 1996). +4.2 * +Description of Securities. +10.1 (x) +2005 Equity Incentive Plan (incorporated by reference to Exhibit 99.1 of the Company’s Current Report on Form 8-K (SEC File No. 000-21121) filed +with the SEC on June 1, 2005). +10.2 (x) +2014 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 000-21121) filed +with the SEC on May 19, 2014). +10.3 (x) +Amendment to 2014 Equity Incentive Plan approved by Shareholders on May 22, 2017 (incorporated by reference to Exhibit 10.1 of the Company’s +Quarterly Report on Form 10-Q (SEC File No. 000-21121) filed with the SEC on August 9, 2017). +10.4 (x) +2014 Equity Incentive Plan Time-based Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.2 of the Company's Quarterly Report +on Form 10-Q (SEC File No. 000-21121) filed with the SEC on May 6, 2016). +10.5 (x) +2014 Equity Incentive Plan Performance-based Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.1 of the Company's Quarterly +Report on Form 10-Q (SEC File No. 000-211121) filed with the SEC on August 8, 2016). +10.6 (x) +Employment Agreement, dated July 31, 1996, by and between TransAct and Bart C. Shuldman (incorporated by reference to Exhibit 10.20 of the +Company’s Registration Statement on Form S-1/A (No. 333-06895) filed with the SEC on August 1, 1996). +10.7 (x) +Severance Agreement by and between TransAct and Steven A. DeMartino, dated June 1, 2004 (incorporated by reference to Exhibit 10.8 of the Company’s +Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 16, 2005). +10.8 (x) +Severance Agreement by and between TransAct and Tracey S. Chernay, dated July 29, 2005 (incorporated by reference to Exhibit 10.9 of the Company’s +Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 14, 2008). +10.9 (x) +Amendment to Employment Agreement, effective January 1, 2008, by and between TransAct and Bart C. Shuldman (incorporated by reference to Exhibit +10.10 of the Company’s Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 16, 2009). +10.10 (x) +Amendment to Severance Agreement by and between TransAct and Steven A. DeMartino, effective January 1, 2008 (incorporated by reference to Exhibit +10.12 of the Company’s Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 16, 2009). +10.11 (x) +Amendment to Severance Agreement by and between TransAct and Tracey S. Chernay, effective January 1, 2008 (incorporated by reference to Exhibit +10.14 of the Company’s Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 16, 2009). +10.12 +Lease Agreement by and between Bomax Properties and Ithaca, dated as of March 23, 1992 (incorporated by reference to Exhibit 10.14 of the Company’s +Registration Statement on Form S-1 (No. 333-06895) filed with the SEC on June 26, 1996). +10.13 +Second Amendment to Lease Agreement by and between Bomax Properties and Ithaca, dated December 2, 1996 ( incorporated by reference to Exhibit 10.27 of the Company’s Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 31, 1998). +10.14 +Agreement regarding the Continuation and Renewal of Lease by and between Bomax Properties, LLC and TransAct, dated July 18, 2001 (incorporated by reference to Exhibit 10.8 of the Company’s Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 29, 2002). +10.15 +Amendment No. 1 to Lease Agreement between Bomax Properties, LLC and TransAct (incorporated by reference to Exhibit 10.16 of the Company’s +Quarterly Report on Form 10-Q (SEC File No. 000-21121) filed with the SEC on May 10, 2012). +10.16 +Amendment No. 2 to Lease Agreement between Bomax Properties, LLC and TransAct, dated January 14, 2016 (incorporated by reference to Exhibit 10.13 +of the Company’s Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 11, 2016). +10.17 +Amendment No. 3 to Lease Agreement between Bomax Properties, LLC and TransAct, dated February 28, 2020 (incorporated by reference to Exhibit 10.1 +to the Company’s Current Report on Form 8-K (SEC File No. 000-21121) filed with the SEC on March 4, 2020). +10.18 +Lease Agreement by and between Las Vegas Airport Properties LLC and TransAct dated December 2, 2004 (incorporated by reference to Exhibit 10.13 of +the Company’s Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 16, 2005). +10.19 +First Amendment to Lease Agreement by and between Las Vegas Airport Properties LLC and TransAct dated August 31, 2009 (incorporated by reference to +Exhibit 10.19 of the Company’s Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 16, 2010). +10.20 +Second Amendment to Lease Agreement by and between The Realty Associates Fund IX LP and TransAct dated June 30, 2015 (incorporated by reference to +Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q (SEC File No. 000-21121) filed with the SEC on August 7, 2015). +10.21 +Lease Agreement by and between 2319 Hamden Center I, L.L.C. and TransAct dated November 27, 2006 (incorporated by reference to Exhibit 10.14 of the +Company’s Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 15, 2007). +10.22 +First Amendment to Lease by and between 2319 Hamden Center I, L.L.C. and TransAct dated January 3, 2017 (incorporated by reference to Exhibit 10.20 +of the Company’s Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 16, 2017). +10.23 +Amended and Restated Revolving Credit and Security Agreement between TransAct and TD Banknorth, N.A. dated November 28, 2006 (incorporated by +reference filed with the Company's Annual Report on Form 10-K (SEC File No. 000-21121)for the year ended December 31, 2006). +10.24 +First Amendment to Amended and Restated Revolving Credit and Security Agreement between TransAct and TD Banknorth, N.A. effective September 30, +2007 (incorporated by reference to Exhibit 10.20 of the Company’s Quarterly Report on Form 10-Q (SEC File No. 000-21121) filed with the SEC on November 9, 2007). +10.25 +Second Amendment to Amended and Restated Revolving Credit and Security Agreement between TransAct and TD Bank, N.A. effective November 22, 2011 (incorporated +by reference to Exhibit 10.25 of the Company’s Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 12, 2012). +10.26 +Third Amendment to Amended and Restated Revolving Credit and Security Agreement effective September 7, 2012 (incorporated by reference to Exhibit +10.26 of the Company’s Current Report on Form 8-K (SEC File No. 000-21121) filed with the SEC on September 11, 2012). +10.27 +Fourth Amendment to Amended and Restated Revolving Credit and Security Agreement effective November 26, 2014 (incorporated by reference to Exhibit +99.1 of the Company’s Current Report on Form 8-K (SEC File No. 000-21121) filed with the SEC on December 1, 2014). +10.28 +Fifth Amendment to Amended and Restated Revolving Credit and Security Agreement effective November 21, 2017 (incorporated by reference to Exhibit +99.1 to the Company’s Current Report on Form 8-K (SEC File No. 000-21121) filed with the SEC on November 22, 2017).. +21 +Subsidiaries of the Company +23 +Consent of PricewaterhouseCoopers LLP. +31.1 +Rule 13a-14(a) Certification of Chief Executive Officer in accordance with Section 302 of the Sarbanes-Oxley Act of 2002. +31.2 +Rule 13a-14(a) Certification of Chief Financial Officer in accordance with Section 302 of the Sarbanes-Oxley Act of 2002. +32 +Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the +Sarbanes-Oxley Act of 2002. +101.INS +XBRL Instance Document. +101.SCH +XBRL Taxonomy Extension Schema Document. +101.CAL +XBRL Taxonomy Extension Calculation Linkbase Document. +101.DEF +XBRL Taxonomy Extension Definition Linkbase Document. +101.LAB +XBRL Taxonomy Extension Label Linkbase Document. +101.PRE +XBRL Taxonomy Extension Presentation Linkbase Document. +30 +* These +exhibits are filed herewith. +(x) +Management contract or compensatory plan or arrangement. +(a) +Exhibits. +The Exhibits required by Item 601 of Regulation S-K under the Exchange Act are included in the Exhibit Index above under a(3) of this Item 15. +(b) +Financial Statement Schedules. +See the Notes to the Consolidated Financial Statements included in this Form 10-K. +Item 16. Form 10-K Summary. +Not applicable. +31 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report +to be signed on its behalf by the undersigned, thereunto duly authorized. +TRANSACT TECHNOLOGIES INCORPORATED +By: +/s/ Bart C. Shuldman +Name: +Bart C. Shuldman +Title: +Chairman of the Board and Chief Executive Officer +Date: March 16, 2020 +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on +behalf of the registrant and in the capacities and on the dates indicated. +Signature +Title +Date +/s/ Bart C. Shuldman +Chairman of the Board and Chief Executive Officer +March 16, 2020 +Bart C. Shuldman +(Principal Executive Officer) +/s/ Steven A. DeMartino +President, Chief Financial Officer, Treasurer and Secretary +March 16, 2020 +Steven A. DeMartino +(Principal Financial Officer) +/s/ David B. Peters +Vice President and Chief Accounting Officer +March 16, 2020 +David B. Peters +(Principal Accounting Officer) +/s/ John M. Dillon +Director +March 16, 2020 +John M. Dillon +/s/ Emanuel P. N. Hilario +Director +March 16, 2020 +Emanuel P. N. Hilario +/s/ Haydee Olinger +Director +March 16, 2020 +Haydee Olinger +/s/ Thomas R. Schwarz +Director +March 16, 2020 +Thomas R. Schwarz +32 +TRANSACT TECHNOLOGIES INCORPORATED +INDEX TO FINANCIAL STATEMENTS +Financial Statements +Report of Independent Registered Public Accounting Firm +F-3 +Consolidated Balance Sheets as of December 31, 2019 and 2018 +F-4 +Consolidated Statements of Income for the years ended December 31, 2019, +2018, and 2017 +F-5 +Consolidated Statements of Comprehensive Income for the years ended +December 31, 2019, 2018 and 2017 +F-6 +Consolidated Statements of Changes in Shareholders' Equity for the years ended +December 31, 2019, 2018 and 2017 +F-7 +Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and +2017 +F-8 +Notes to Consolidated Financial Statements +F-9 +F-1 +Report of Independent Registered Publi c Accounting Firm +To the Board of Directors and Shareholders of TransAct Technologies Incorporated +Opinions on the Financial Statements and Internal Control over Financial +Reporting +We have audited the accompanying consolidated balance sheets of TransAct Technologies Incorporated and its +subsidiaries (the “Company”) as of December 31, 2019 and 2018, and the related consolidated statements of income, comprehensive income, changes in shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2019, +including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). +In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, +the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with accounting principles generally accepted +in the United States of America. Also in our opinion, the Company did not maintain, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO because material weaknesses in internal control over financial reporting existed as of that date related to +the Company not designing and maintaining effective controls over (i) user access within the Company’s ERP system, Oracle, to ensure appropriate segregation of duties and to adequately restrict user access to appropriate personnel, and (ii) the +completeness and accuracy of information included in key spreadsheets supporting the Company’s accounting records. +A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial +reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis. The material weaknesses referred to above are described in +Management’s Annual Report on Internal Control over Financial Reporting appearing under Item 9A. We considered these material weaknesses in determining the nature, timing, and extent of audit tests applied in our audit of the 2019 consolidated +financial statements, and our opinion regarding the effectiveness of the Company’s internal control over financial reporting does not affect our opinion on those consolidated financial statements. +Change in Accounting Principle +As discussed in Note 2 to the consolidated financial statements, the Company changed the manner in which it +accounts for leases in 2019. +Basis for Opinions +The Company's management is responsible for these consolidated financial statements, for maintaining effective +internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in management's report referred to above. Our responsibility is to express opinions on the Company’s +consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are +required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and +perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in +all material respects. +Our audits of the consolidated financial statements included performing procedures to assess the risks of +material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures +in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our +audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness +of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. +F-2 +Definition and Limitations of Internal Control over Financial Reporting +A company’s internal control over financial reporting is a process designed to provide reasonable assurance +regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those +policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are +recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and +directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. +Because of its inherent limitations, internal control over financial reporting may not prevent or detect +misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may +deteriorate. +/s/ PricewaterhouseCoopers LLP +Hartford, Connecticut +March 16, 2020 +We have served as the Company's auditor since 1996. +F-3 +TRANSACT TECHNOLOGIES INCORPORATED +CONSOLIDATED BALANCE SHEETS +(In thousands, except share data) +December 31, +2019 +December 31, +2018 +Assets: +Current assets: +Cash and cash equivalents +$ +4,203 +$ +4,691 +Accounts receivable, net +6,418 +8,025 +Note receivable +1,017,000 +– +Inventories, net +12,099 +12,835 +Prepaid income taxes +180 +809 +Other current assets +998 +677 +Total current assets +24,915 +27,037 +Fixed assets, net +2,244 +2,272 +Right-of-use asset +2,855,000 +– +Goodwill +2,621 +2,621 +Deferred tax assets +2,565 +2,198 +Intangible assets, net +817 +797 +Other assets +44 +31 +11,146 +7,919 +Total assets +36,061 +34,956 +Liabilities and Shareholders’ Equity: +Current liabilities: +Accounts payable +$ +2,960 +$ +3,483 +Accrued liabilities +3,041 +2,765 +Lease liability +945,000 +– +Deferred revenue +700 +384 +Total current liabilities +7,646 +6,632 +Deferred revenue, net of current portion +219 +265 +Lease liability, net of current portion +2,104 +– +Deferred rent, net of current portion +– +250,000 +Other liabilities +166 +242 +2,489 +757 +Total liabilities +10,135 +7,389 +Commitments and contingencies (Note 15) +Shareholders’ equity: +Preferred stock, $0.01 value, 4,800,000 authorized, none issued and outstanding +– +– +Preferred stock, Series A, $0.01 par value, 200,000 authorized, none issued and +outstanding +– +– +Common stock, $0.01 par value, 20,000,000 authorized at December 31, 2019 and 2018; +11,515,090 and 11,463,141 shares issued; 7,470,248 and 7,418,299 shares outstanding, at December 31, 2019 and 2018, respectively +115 +115 +Additional paid-in capital +32,604 +32,129 +Retained earnings +25,348 +27,515 +Accumulated other comprehensive loss, net of tax +(31 +) +(82 +) +Treasury stock, 4,044,842 shares, at cost +(32,110 +) +(32,110 +) +Total shareholders’ equity +25,926 +27,567 +Total liabilities and shareholders’ equity +$ +36,061 +$ +34,956 +See accompanying notes to Consolidated Financial Statements. +F-4 +TRANSACT TECHNOLOGIES INCORPORATED +CONSOLIDATED STATEMENTS OF INCOME +(In thousands, except per share data) +Year Ended December 31, +2019 +2018 +2017 +Net sales +$ +45,748 +$ +54,587 +$ +56,311 +Cost of sales +23,813 +27,844 +29,649 +Gross profit +21,935 +26,743 +26,662 +Operating expenses: +Engineering, design and product development +4,393 +4,576 +4,303 +Selling and marketing +8,033 +7,203 +7,561 +General and administrative +9,166 +8,205 +7,984 +21,592 +19,984 +19,848 +Operating income +343 +6,759 +6,814 +Interest and other income (expense): +Interest expense +(28 +) +(27 +) +(33 +) +Interest income +17 +– +– +Other, net +35 +(266 +) +(9 +) +24 +(293 +) +(42 +) +Income before income taxes +367 +6,466 +6,772 +Income tax (benefit) provision +(149 +) +1,040 +3,561 +Net income +$ +516 +$ +5,426 +$ +3,211 +Net income per common share: +Basic +$ +0.07 +$ +0.73 +$ +0.43 +Diluted +$ +0.07 +$ +0.70 +$ +0.42 +Shares used in per-share calculation: +Basic +7,466 +7,444 +7,423 +Diluted +7,677 +7,759 +7,592 +Dividends declared and paid per common share: +$ +0.36 +$ +0.36 +$ +0.35 +See accompanying notes to Consolidated Financial Statements. +F-5 +TRANSACT TECHNOLOGIES INCORPORATED +CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME +(In thousands, except share data) +Year Ended December 31, +2019 +2018 +2017 +Net income +$ +516 +$ +5,426 +$ +3,211 +Foreign currency translation adjustment, net of tax +51 +17 +10 +Comprehensive income +$ +567 +$ +5,443 +$ +3,221 +See accompanying notes to Consolidated Financial Statements. +F-6 +TRANSACT TECHNOLOGIES INCORPORATED +CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY +(In thousands, except share data) +Common Stock +Additional +Paid-in +Retained +Treasury +Accumulated +Other +Comprehensive +Total +Shares +Amount +Capital +Earnings +Stock +Income (Loss) +Equity +Balance, December 31, 2016 +7,333,364 +$ +112 +$ +29,701 +$ +24,157 +$ +(29,752 +) +$ +(109 +) +$ +24,109 +Issuance of shares from exercise of stock options +166,600 +2 +1,041 +– +– +– +1,043 +Issuance of common stock on restricted stock units +8,300 +– +– +– +– +– +– +Issuance of common stock on deferred stock units +8,663 +– +– +– +– +– +– +Relinquishment of stock awards and deferred stock units to pay withholding taxes +(2,368 +) +– +(29 +) +– +– +– +(29 +) +Purchase of treasury stock +(36,465 +) +– +– +– +(358 +) +– +(358 +) +Dividends declared and paid on common stock +– +– +– +(2,581 +) +– +– +(2,581 +) +Share-based compensation expense +– +– +609 +– +– +– +609 +Adjustment upon adoptions of ASU 2016-09 +– +– +31 +(31 +) +– +– +– +Foreign currency translation adjustment, net of tax +– +– +– +– +– +10 +10 +Net income +– +– +– +3,211 +– +– +3,211 +Balance, December 31, 2017 +7,478,094 +$ +114 +$ +31,353 +$ +24,756 +$ +(30,110 +) +$ +(99 +) +$ +26,014 +Issuance of shares from exercise of stock options +58,146 +1 +415 +– +– +– +416 +Issuance of common stock on restricted stock units +33,935 +– +– +– +– +– +– +Issuance of common stock on deferred stock units +23,578 +– +– +– +– +– +– +Relinquishment of stock awards and deferred stock units to pay withholding taxes +(19,044 +) +– +(268 +) +– +– +– +(268 +) +Purchase of treasury stock +(156,410 +) +– +– +– +(2,000 +) +– +(2,000 +) +Dividends declared and paid on common stock +– +– +– +(2,667 +) +– +– +(2,667 +) +Share-based compensation expense +– +– +629 +– +– +– +629 +Foreign currency translation adjustment, net of tax +– +– +– +– +– +17 +17 +Net income +– +– +– +5,426 +– +– +5,426 +Balance, December 31, 2018 +7,418,299 +$ +115 +$ +32,129 +$ +27,515 +$ +(32,110 +) +$ +(82 +) +$ +27,567 +Issuance of common stock on restricted stock units +45,167 +– +– +– +– +– +– +Issuance of common stock on deferred stock units +28,231 +– +– +– +– +– +– +Relinquishment of stock awards and deferred stock units to pay withholding taxes +(21,449 +) +– +(217 +) +– +– +– +(217 +) +Dividends declared and paid on common stock +– +– +– +(2,683 +) +– +– +(2,683 +) +Share-based compensation expense +– +– +692 +– +– +– +692 +Foreign currency translation adjustment, net of tax +– +– +– +– +– +51 +51 +Net income +– +– +– +516 +– +– +516 +Balance, December 31, 2019 +7,470,248 +$ +115 +$ +32,604 +$ +25,348 +$ +(32,110 +) +$ +(31 +) +$ +25,926 +See accompanying notes to Consolidated Financial Statements. +F-7 +TRANSACT TECHNOLOGIES INCORPORATED +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Year Ended December 31, +2019 +2018 +2017 +Cash flows from operating activities: +Net income +$ +516 +$ +5,426 +$ +3,211 +Adjustments to reconcile net income to net cash provided by operating activities: +Share-based compensation expense +692 +629 +609 +Depreciation and amortization +1,371 +997 +1,081 +Deferred income tax (benefit) provision +(294 +) +(107 +) +1,117 +Provision for doubtful accounts +16 +105 +50 +Foreign currency transaction losses +18 +199 +11 +Changes in operating assets and liabilities: +Accounts receivable +1,589 +2,688 +(405 +) +Inventories +796 +(4,049 +) +834 +Prepaid income taxes +577 +(100 +) +(518 +) +Other current and long term assets +(333 +) +(161 +) +(137 +) +Accounts payable +(517 +) +(332 +) +(988 +) +Accrued liabilities and other liabilities +415 +(186 +) +1,053 +Net cash provided by operating activities +4,846 +5,109 +5,918 +Cash flows from investing activities: +Capital expenditures +(1,062 +) +(1,007 +) +(835 +) +Additions to capitalized software +(304 +) +(466 +) +(150 +) +Issuance of note receivable +(1,000,000 +) +– +– +Net cash used in investing activities +(2,366 +) +(1,473 +) +(985 +) +Cash flows from financing activities: +Proceeds from stock option exercises +– +416 +1,043 +Purchases of common stock for treasury +– +(2,000 +) +(358 +) +Payment of dividends on common stock +(2,683 +) +(2,667 +) +(2,581 +) +Withholding taxes paid on stock issuances +(214 +) +(265 +) +(23 +) +Net cash used in financing activities +(2,897 +) +(4,516 +) +(1,919 +) +Effect of exchange rate changes on cash and cash equivalents +(71 +) +64 +(10 +) +(Decrease) increase in cash and cash equivalents +(488 +) +(816 +) +3,004 +Cash and cash equivalents, beginning of period +4,691 +5,507 +2,503 +Cash and cash equivalents, end of period +$ +4,203 +$ +4,691 +$ +5,507 +Supplemental cash flow information: +Interest paid +$ +30 +$ +25 +$ +30 +Income taxes paid +65 +1,249 +2,991 +Non-cash capital expenditure items +17 +21 +44 +See accompanying notes to Consolidated Financial Statements. +F-8 +TRANSACT TECHNOLOGIES INCORPORATED +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. Description of business +TransAct Technologies Incorporated (together with its subsidiaries, “TransAct,” the “Company,” "we,", "us,", +"our"), which has its headquarters in Hamden, Connecticut and its primary operating facility in Ithaca, New York, operates in one operating segment: software-driven technology and printing solutions for high growth markets including food service +technology, casino and gaming, lottery, POS automation and banking, and oil and gas markets. Our solutions are designed from the ground up based on market and customer requirements and are sold under the BOHA! TM , AccuDate™ Ithaca®, Epic, +EPICENTRAL TM and Printrex® product brands. We sell our products to original equipment manufacturers, value-added resellers, select distributors, and directly to end-users. Our product distribution spans across the Americas, Europe, the +Middle East, Africa, Asia, Australia, the Caribbean Islands and the South Pacific. TransAct also provides world-class service, spare parts, accessories and printing supplies to its growing worldwide installed base of products. We also generate +revenue from the after-market side of the business, providing printer and terminal service, supplies and spare parts in addition to revenue from our two software solutions; (i)the EPICENTRAL TM Print System (“EPICENTRAL TM ”), that +enables casino operators to create promotional coupons and marketing messages and print them in real-time at the slot machine and (ii) our newly-launched line of BOHA! software applications used to automate the back-of-house operations of restaurants +and other food service establishments. +2. Summary of significant accounting policies +Principles of +consolidation: The accompanying Consolidated Financial Statements include the accounts of TransAct and its wholly-owned subsidiaries, which require consolidation, after the elimination of intercompany accounts, transactions and unrealized +profit. +Use of estimates : The preparations of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America +(“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses, and disclosure of contingent assets and liabilities as of the date of the Consolidated Financial Statements +and the reported amounts of sales and expenses during the reporting period. Actual results could differ from those estimates. +Segment reporting : We apply the provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 280, “Segment Reporting.” We +view our operations and manage our business as one segment: the design, development and marketing of software-driven technology and printing solutions and providing printer and terminal related software, services, supplies and spare parts. Factors +used to identify TransAct’s single operating segment include the organizational structure of the Company and the financial information available for evaluation by the chief operating decision-maker in making decisions about how to allocate resources +and assess performance. +Cash and cash +equivalents : We consider all highly liquid investments with a maturity date of three months or less at date of purchase to be cash +equivalents. +Allowance for +doubtful accounts : We establish an allowance for doubtful accounts to ensure trade receivables are valued appropriately. We maintain an +allowance for doubtful accounts based on a variety of factors, including the length of time receivables are past due, significant one-time events and historical experience. We record a specific allowance for individual accounts when we become aware +of a customer’s inability to meet its financial obligations, such as in the case of bankruptcy filings or deterioration in the customer’s operating results or financial position. If circumstances related to customers change, we would further adjust +estimates of the recoverability of receivables. +The following table summarizes the activity recorded in the valuation account for accounts receivable: +Year Ended December 31, +(In thousands) +2019 +2018 +2017 +Balance, beginning of period +$ +205 +$ +100 +$ +50 +Additions charged to costs and expenses +39 +105 +50 +Deductions +(23 +) +- +- +Balance, end of period +$ +221 +$ +205 +$ +100 +Inventories: Inventories +are stated at the lower of cost (principally standard cost, which approximates actual cost on a first-in, first-out basis) or net realizable value. We review net realizable value based on estimated selling prices in the ordinary course of business +less estimated costs of completions, disposal and transportation, historical usage and estimates of future demand. Based on these reviews, inventory write-downs are recorded, as necessary, to reflect estimated obsolescence, excess quantities and net +realizable value. +Fixed assets: Fixed +assets are stated at cost. Depreciation is recorded using the straight-line method over the estimated useful lives. The estimated useful life of tooling is five years; machinery and equipment is ten years; furniture and office equipment is five +years to ten years; and computer software and equipment is three years to seven years. Leasehold improvements are amortized over the shorter of the term of the lease or the useful life of the asset. Costs related to repairs and maintenance are +expensed as incurred. The costs of sold or retired assets are removed from the related asset and accumulated depreciation accounts and any gain or loss is recognized. Depreciation expense was $1.1 million, $0.9 million and $0.8 million in 2019, +2018, and 2017, respectively. +Leases: ASU 2016-02, “Leases” , which was codified in, and is referred to +in this Annual Report as, ASC 842, became effective for reporting periods beginning after December 15, 2018. The adoption required a modified retrospective transition approach, applying the new standard to all leases existing at the date of initial +application. An entity may choose to use either (1) its effective date or (2) the beginning of the earliest comparative period presented in the financial statements as its date of initial application. The Company has elected to adopt the standard +using the effective date, January 1, 2019, as its date of initial application. Consequently, financial information for prior periods will not be updated, and the disclosures required under the new standard will not be provided for dates and periods +before January 1, 2019. +F-9 +The new standard requires lessees to apply a dual approach, classifying leases as either finance or operating leases based on the +principle of whether or not the lease is effectively a financed purchase by the lessee. This classification will determine whether lease expense is recognized based on an effective interest method or on a straight-line basis over the term of the +lease, respectively. A lessee is also required to record a right-of-use asset and a lease liability for all leases with a term of greater than 12 months regardless of their classification. Leases with a term of 12 months or less will be accounted for +based on existing guidance for operating leases. If risks and rewards are conveyed without the transfer of control, the lease is treated as financing. If the lessor does not convey risks and rewards or control, the lease is treated as operating. +We have elected certain practical expedients available under ASC 842 upon adoption. We have applied the practical expedient which +allows prospective transition to ASC 842 on January 1, 2019. Under this transition practical expedient, we did not reassess lease classification, embedded leases or initial direct costs. We have applied the practical expedient for short-term leases. +We have lease agreements that include lease and non-lease components, and we have not elected the practical expedients to combine these components for any of our leases. The adoption of ASC 842 had no effect on our Consolidated Statement of Income +or Consolidated Statement of Cash Flows. Upon adoption of ASC 842, we recorded a $3.7 million right-of-use asset and a $3.9 million lease liability. The adoption of the new standard had no impact on retained earnings. +We enter into lease agreements for the use of real estate space and certain other equipment under operating leases and we have no financing leases. We determine if an arrangement contains a lease at inception. Our leases are included in Right of use assets and Lease +liabilities in our Condensed Consolidated Balance Sheet. +Right of use assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation +to make lease payments arising from the lease. Lease right of use assets and liabilities are recognized at the commencement date of the lease based on the present value of lease payments over the lease term. As most of our leases do not provide an +implicit rate, the Company determines its incremental borrowing rate by using the rate of interest that the Company would have to pay to borrow on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic +environment. Our lease right of use assets exclude lease incentives. Our leases have remaining lease terms of one year to eight years, some of which include options to extend. The majority of our leases with options to extend provide for extensions +of up to five years with the ability to terminate the lease within one year. The exercise of lease renewal options is at our sole discretion and our lease right of use assets and liabilities reflect only the options we are reasonably certain that we +will exercise. Lease expense is recognized on a straight-line basis over the lease term. +Goodwill and +Intangible assets : We acquire businesses in purchase transactions that result in the recognition of goodwill and intangible assets. The +determination of the value of intangible assets requires management to make estimates and assumptions. In accordance with ASC 350-20 “Goodwill”, acquired goodwill is not amortized but is subject to impairment testing at least annually and when an +event occurs or circumstances change, that indicate it is more likely than not an impairment exists. Factors considered that may trigger an impairment review of either acquired goodwill or intangible assets are: significant underperformance relative +to expected historical or projected future operating results; significant changes in the manner of use of acquired assets or the strategy for the overall business; significant negative industry or economic trends; and significant decline in market +capitalization relative to net book value. Finite lived intangible assets are amortized and are tested for impairment when appropriate. We have determined that no goodwill or intangible asset impairment has occurred and the fair value of goodwill was +substantially higher than our carrying value based on our assessment as of December 31, 2019 when the impairment review is performed. +Revenue recognition: We account for revenue in accordance with ASC Topic 606: Revenue from Contracts with Customers. We adopted ASC 606 effective January 1, 2018 and elected the modified retrospective approach. The results for +periods before 2018 were not adjusted for the new standard and there was no cumulative effect for the change in accounting at the date of adoption. In accordance with ASC 606, a performance obligation is a promise in a contract with a customer to +transfer a distinct good or service to the customer. Some of our contracts with customers contain a single performance obligation, while other contracts contain multiple performance obligations (most commonly when contracts include a hardware +product, software and extended warranties). A contract's transaction price is allocated to each distinct performance obligation and recognized as revenue when, or as, the performance obligation is satisfied. +The transaction price is determined based on the consideration to which the Company will be entitled in exchange for transferring +services to the customer. To the extent the transaction price includes variable consideration, such as price protection, reserves for returns and other allowances, the Company estimates the amount of variable consideration that should be included in +the transaction price utilizing either the “expected value” method or the “most likely amount” method depending on the nature of the variable consideration. Variable consideration is included in the transaction price if, in the Company’s judgment, +it is probable that a significant future reversal of cumulative revenue under the contract will not occur. +For a majority of our revenue, which consists of printers, terminals, consumables, and replacement parts, the Company recognizes +revenue as of a point of time. The transaction price is recognized upon shipment of the order when control of the goods is transferred to the customer and at the time the performance obligation is fulfilled. We also sell a software solution in our +casino and gaming market, EPICENTRAL™, that enables casino operators to create promotional coupons and marketing messages and to print them in real-time at the slot machine. EPICENTRAL TM is primarily comprised of both a software +component, which is licensed to the customer, and a hardware component. EPICENTRAL™ software and hardware are integrated to deliver the system's full functionality. The transaction prices from EPICENTRAL™ software license and hardware are +recognized upon installation and formal acceptance by the customer when control of the license is transferred to the customer. For out-of-warranty repairs, the transaction price is recognized after the repair work is completed and the printer or +terminal is returned to the customer, as control of the product is transferred to the customer and our performance obligation is completed. +F-10 +Performance obligations are satisfied over time if the customer receives the benefits as we perform work, if the customer controls +the asset as it is being produced, or if the product being produced for the customer has no alternative use and we have a contractual right to payment. For our separately priced extended warranty, BOHA! cloud-based software applications, technical +support for our food service technology terminals and maintenance agreements (including free one-year maintenance received by customers upon completion of EPICENTRAL™ installation) revenue is recognized over time as the customer receives the +benefit. The transaction price from the maintenance services is recognized ratably over time, using output methods, as control of the services is transferred to the customer. Our cloud-based BOHA! software allows customers to use hosted software +over the contract period without taking possession of the software and are provided on a subscription basis and is recognized ratably over the contract period. For extended warranties, the transaction price is recognized ratably over the warranty +period, using output methods, as control of the services is transferred to the customer. +When there is more than one performance obligation in a customer arrangement, the Company typically uses the “standalone selling +price” method to determine the transaction price to allocate to each performance obligation. The Company sells the performance obligations separately and has established standalone selling prices for its products and services. In the case of an +overall price discount, the discount is applied to each performance obligation proportionately based on standalone selling price. To determine the standalone selling price for initial EPICENTRAL™ installations, the Company uses the adjusted market +assessment approach. +For contracts with terms of less than 12 months, the Company expenses sales commissions as they are incurred, +since the expected amortization period of the cost to obtain a contract is less than 12 months. Prior to the adoption of ASC 606 in 2018, cost to obtain a contract were expensed as incurred regardless of the length of contract. +Disaggregation of revenue +The following table disaggregates our revenue by market-type, as we believe it best depicts how the nature, amount, timing and uncertainty of our revenue +and cash flows are affected by economic factors. Sales and usage-based taxes are excluded from revenues. +Year Ended +December 31, 2019 +United States +International +Total +(In thousands) +Food Service Technology +$ +5,522 +$ +582 +$ +6,104 +POS Automation and Banking +5,714 +44 +5,758 +Casino and Gaming +13,076 +8,453 +21,529 +Lottery +1,290 +1 +1,291 +Printrex +961 +205 +1,166 +TransAct Services Group +8,769 +1,131 +9,900 +Total net sales +$ +35,332 +$ +10,416 +$ +45,748 +Year Ended +December 31, 2018 +United States +International +Total +(In thousands) +Food Service Technology +$ +4,640 +$ +446 +$ +5,086 +POS Automation and Banking +7,122 +151 +7,273 +Casino and Gaming +17,518 +9,075 +26,593 +Lottery +3,046 +47 +3,093 +Printrex +1,028 +269 +1,297 +TransAct Services Group +10,164 +1,081 +11,245 +Total net sales +$ +43,518 +$ +11,069 +$ +54,587 +Year Ended +December 31, 2017 +United States +International +Total +(In thousands) +Food Service Technology +$ +4,488 +$ +374 +$ +4,862 +POS Automation and Banking +7,596 +309 +7,905 +Casino and Gaming +13,608 +5,007 +18,615 +Lottery +8,626 +1,179 +9,805 +Printrex +849 +203 +1,052 +TransAct Services Group +13,553 +519 +14,072 +Total net sales +$ +48,720 +$ +7,591 +$ +56,311 +F-11 +Contract balances +Our contract liabilities consist of customer pre-payments and deferred revenue. Customer prepayments are reported as “Accrued +Liabilities” in current liabilities in the Condensed Consolidated Balance Sheets and represent customer payments made in advance of performance obligations in instances where credit has not been extended and is recognized as revenue when the +performance obligation is complete. Deferred revenue is reported separately in current liabilities and non-current liabilities and consists of our extended warranty contracts, technical support for our food service technology terminals, EPICENTRAL™ +maintenance contracts and testing service contracts and prepaid software subscriptions for our BOHA! software applications, and is recognized as revenue as (or when) we perform under the contract. The increase in current and non-current deferred +revenue is primarily due to the sale of BOHA! software subscriptions, extended warranties and technical support for our food service technology terminals. We do not have any contract asset balances as of December 31, 2019 or 2018. During the year +ended December 31, 2019, we recognized revenue of $0.4 million related to our contract liabilities as of December 31, 2018. Total contract liabilities consist of the following: +December 31, 2019 +December 31, 2018 +(In thousands) +Customer pre-payments +$ +232 +$ +50 +Deferred revenue, current +700 +384 +Deferred revenue, non-current +219 +265 +Total contract liabilities +$ +1,151 +$ +699 +Remaining performance obligations +Remaining performance obligations represent the transaction price of firm orders for which a good or service has not been delivered +to our customer. As of December 31, 2019, the aggregate amount of the transaction price allocated to remaining performance obligations was $5.8 million. The Company expects to recognize revenue on $5.5 million of our remaining performance +obligations within the next 12 months, $0.2 million within the next 24 months and the balance of these remaining performance obligations recognized within the next 36 months. +Concentration of +credit risk: Financial instruments that potentially expose us to concentrations of credit risk are limited to cash and cash equivalents held by our banks in excess of insured limits and accounts receivable. +Accounts receivable from customers representing 10% or more of total accounts receivable were as follows: +December 31, +2019 +2018 +International Gaming Technology ("IGT") +15 +% +21 +% +Bally Technologies +10 +% +6 +% +Sales to customers representing 10% or more of total net sales were as follows: +Year Ended December 31, +2019 +2018 +2017 +IGT +14 +% +18 +% +35 +% +Warranty: We +generally warrant our products for up to 24 months and record the estimated cost of such product warranties at the time the sale is recorded. Estimated warranty costs are based upon actual past experience of product repairs and the related estimated +cost of labor and material to make the necessary repairs. +The following table summarizes the activity recorded in the accrued product warranty liability: +Year Ended December 31, +(In thousands) +2019 +2018 +2017 +Balance, beginning of period +$ +273 +$ +267 +$ +267 +Warranties issued +181 +269 +259 +Warranty settlements +(239 +) +(263 +) +(259 +) +Balance, end of period +$ +215 +$ +273 +$ +267 +$174 thousand and $192 thousand of the accrued product warranty liability were classified as current in Accrued liabilities at +December 31, 2019 and 2018, respectively. The remaining $41 thousand and $81 thousand of the accrued product warranty liability as of December 31, 2019 and 2018, respectively, is classified as long-term in Other liabilities. +Engineering, +design and product development: Engineering, design and product development expenses include expenses incurred in connection with specialized engineering and design to introduce new products and to customize existing products, and are +expensed as a component of operating expenses as incurred. We recorded $4.4 million, $4.6 million and $4.3 million of research and development expenses in 2019, 2018, and 2017, respectively. +Costs incurred in the engineering, design and product development of a computer software product are charged to expense until +technological feasibility has been established, at which point all material software costs are capitalized within Intangible assets in our Consolidated Balance Sheet until the product is available for general release to customers. While judgment is +required in determining when technological feasibility of a product is established, we have determined that it is reached after all high-risk development issues have been documented in a formal detailed plan design. The amortization of these costs +have been included in cost of sales over the estimated life of the product. During 2019 and 2018, we contracted several third-parties to develop software for our food service technology products. Unamortized development costs for such software were +$704 thousand as of December 31, 2019. The total amount charged to cost of sales for capitalized software development costs was $186 thousand, $30 thousand and $2 thousand in 2019, 2018, and 2017, respectively. +Advertising: Advertising +costs are expensed as incurred. Advertising expenses, which are included in selling and marketing expense on the accompanying Consolidated Statements of Income, for 2019, 2018, and 2017 totaled $1.4 million, $1.0 million and $1.0 million, +respectively. These expenses include items such as consulting and professional services, tradeshows, and print advertising. +F-12 +Income taxes: The +income tax amounts reflected in the accompanying Consolidated Financial Statements are accounted for under the liability method in accordance with ASC 740, “Income Taxes” (“ASC 740”). Deferred tax assets and liabilities are recognized for the +estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and +liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. We assess the likelihood that net deferred tax assets will be realized from future taxable income, +and to the extent that we believe that realization is not likely, we establish a valuation allowance. In accordance with ASC 740, we identified, evaluated and measured the amount of benefits to be recognized for our tax return positions. See Note +10 for information regarding our accounting for income taxes and additional provision items recorded in regard to the Tax Cuts and Job Act. +Foreign currency +translation: The financial position and results of operations of our foreign subsidiary in the UK are measured using local currency as the functional currency. Assets and liabilities of such subsidiary have been translated into U.S. +dollars at the year-end exchange rate, related sales and expenses have been translated at the exchange rate as of the date the transaction was recognized, and shareholders’ equity has been translated at historical exchange rates. The resulting +translation gains or losses, net of tax, are recorded in shareholders’ equity as a cumulative translation adjustment, which is a component of accumulated other comprehensive income. Foreign currency transaction gains and losses, including those +related to intercompany balances, are recognized in Other, net on the Consolidated Statements of Income. +Share-based +payments: At December 31, 2019, we have share-based employee compensation plans, which are described more fully in Note 9 - Stock +incentive plans. We account for those plans under the recognition and measurement principles of ASC 718, “Compensation – Stock Compensation” (“ASC 718”). Share-based compensation expense is measured at the grant date, based on the estimated fair +value of the award, and is recognized as expense over the employee’s requisite service period. +We use the Black-Scholes option-pricing model to calculate the fair value of share based awards. The key assumptions for this +valuation method include the expected term of the option, stock price volatility, risk-free interest rate, dividend yield, market price of our underlying stock and exercise price. Many of these assumptions are judgmental and highly sensitive in the +determination of compensation expense. Beginning in the first quarter of 2017, we recognize forfeitures as they occur. +In May 2017, the FASB issued ASU No. 2017-09, "Compensation-Stock Compensation: Scope of modification accounting". ASU 2017-09 +provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in ASC 718. ASU No. 2017-09 was effective for fiscal years beginning after December 15, 2017. The +amendments are applied prospectively to an award modified on or after the adoption date. We adopted this guidance in the first quarter of 2018 and the adoption did not result in a change to our financial statements. +Net income and +loss per share: We report net income or loss per share in accordance with ASC 260, “Earnings per Share (EPS).” Under this guidance, basic EPS, which excludes dilution, is computed by dividing income or loss available to common shareholders +by the weighted average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Diluted +EPS includes in-the-money stock options using the treasury stock method. During a loss period, the assumed exercise of in-the-money stock options has an anti-dilutive effect, and therefore, these instruments are excluded from the computation of +dilutive EPS. See Note 11 - Earnings per share. +3. Note receivable +The note receivable balance relates to a loan given to a third party and repayment is expected to occur in 12 months or less of +original issuance. The note receivable has an interest rate of 4.5% and is due in April 2020. Notes receivable are stated at unpaid balances and interest income is recognized on the accrual method. As of December 31, 2019, we have no allowances +for loan losses, unamortized deferred loan fees or unearned discounts. +4. Inventories, net +The components of inventories, net are: +December 31, +(In thousands) +2019 +2018 +Raw materials and purchased component parts +$ +7,724 +$ +6,593 +Work-in-process +– +29 +Finished goods +4,375 +6,213 +$ +12,099 +$ +12,835 +5. Fixed assets +The components of fixed assets, net are: +December 31, +(In thousands) +2019 +2018 +Tooling, machinery and equipment +$ +9,175 +$ +11,177 +Furniture and office equipment +1,694 +1,690 +Computer software and equipment +7,062 +6,930 +Leasehold improvements +2,696 +2,666 +20,627 +22,463 +Less: Accumulated depreciation and amortization +(19,010 +) +(20,518 +) +1,617 +1,945 +Construction in-process +627 +327 +$ +2,244 +$ +2,272 +F-13 +6. Intangible assets +Identifiable intangible assets are recorded in Intangible assets in the accompanying Consolidated Balance Sheets and are comprised of +the following: +December 31, +2019 +2018 +(In thousands) +Gross +Amount +Accumulated +Amortization +Gross +Amount +Accumulated +Amortization +Purchased technology +$ +2,526 +$ +(1,792 +) +$ +2,221 +$ +(1,558 +) +Customer relationships +1,300 +(1,300 +) +1,300 +(1,300 +) +Trademark +480 +(402 +) +480 +(354 +) +Covenant not to compete +146 +(146 +) +146 +(146 +) +Patents +56 +(51 +) +57 +(49 +) +Other +80 +(80 +) +80 +(80 +) +Total +$ +4,588 +$ +(3,771 +) +$ +4,284 +$ +(3,487 +) +Amortization expense was $284 thousand, $128 thousand and $237 thousand in 2019, 2018 and 2017, respectively. Amortization expense +for each of the next five years ending December 31 is expected to be as follows: $237 thousand in 2020; $185 thousand in 2021; $154 thousand in 2022; $154 thousand in 2023; $87 thousand in 2024; and none thereafter. +7. Accrued liabilities +The components of accrued liabilities are: +December 31, +(In thousands) +2019 +2018 +Salaries and compensation related +$ +1,541 +$ +1,817 +Warranty +174 +192 +Professional and consulting +465 +231 +Other +861 +525 +$ +3,041 +$ +2,765 +8. Retirement savings plan +We maintain a 401(k) plan under which all full-time employees are eligible to participate at the beginning of each month immediately +following their date of hire. We match employees’ contributions at a rate of 50% of employees’ contributions up to the first 6% of the employees’ compensation contributed to the 401(k) plan. Our matching contributions were $305 thousand, $237 +thousand and $264 thousand in 2019, 2018, and 2017, respectively. +9. Borrowings +During 2019, we maintained a credit facility (the “TD Bank Credit Facility”) with TD Bank N.A. (“TD Bank) which provided for a $20 +million revolving credit line. On November 21, 2017, we signed an amendment to the TD Bank Credit Facility extending the term through November 28, 2022. Borrowings under the revolving credit line bear a floating rate of interest at the prime rate +minus one percent and are secured by a lien on all our assets. We also pay a fee of 0.125% on unused borrowings under the revolving credit line. The amendment increased the amount of revolving credit loans we may use to fund future cash dividend +payments or treasury share buybacks to $12.5 million from $10 million. +The TD Bank Credit Facility imposes certain quarterly financial covenants on us and restricts, among other things, our ability to +incur additional indebtedness and the creation of other liens. On November 6, 2019, we amended our TD Credit Facility to change the definition of interest expense to exclude fees paid on unused borrowings under the revolving credit line which is used +to calculate total debt service in the operating cash flow to total debt service financial covenant. We were in compliance with all financial covenants of the TD Bank Credit Facility at December 31, 2019. +As of December 31, 2019, we had no outstanding borrowings under the TD Bank Credit facility. +On March 13, 2020, we terminated our TD Bank Credit Facility and signed a new credit facility with Siena Lending Group LLC. See Note +16 – Subsequent Event. +F-14 +10. Stock incentive plans +Stock incentive +plans . We currently have two primary stock incentive plans: the 2005 Equity Incentive Plan and 2014 Equity Incentive Plan, which provide +for awards to executives, key employees, directors and consultants. The plans generally provide for awards in the form of: (i) incentive stock options, (ii) non-qualified stock options, (iii) restricted stock, (iv) restricted stock units (which may +include performance-based vesting), (v) stock appreciation rights or (vi) limited stock appreciation rights. Awards granted under these plans have exercise prices equal to 100% of the fair market value of the common stock at the date of grant. +Awards granted have a ten years-year term and generally vest over a two year- to five year period, unless automatically accelerated for certain defined events. As of May 2014, no new awards were made under the 2005 Equity Incentive Plan. Under our +2014 Equity Incentive Plan, we are authorized to grant awards of up to 1,400,000 shares of TransAct common stock. At December 31, 2019, 332,541 shares of common stock remained available for issuance under the 2014 Equity Incentive Plan. +Under the assumptions indicated below, the weighted-average per share fair value of stock option grants for 2019, 2018, and 2017 was +$3.01, $4.38 and $1.95, respectively. We also issued restricted stock units for certain executives and directors that vest over a specified period of time, and in some instances require achieving certain performance metrics. The weighted-average +per share fair value of these restricted stock units was $10.46, $12.91 and $7.53 in 2019, 2018 and 2017 respectively. +The table below indicates the key assumptions used in the option valuation calculations for options granted in 2019, 2018, and 2017 +and a discussion of our methodology for developing each of the assumptions used in the valuation model: +Year Ended December 31, +2019 +2018 +2017 +Expected option term (in years) +6.8 +6.8 +6.8 +Expected volatility +38.8 +% +38.0 +% +36.2 +% +Risk-free interest rate +2.6 +% +2.7 +% +2.1 +% +Dividend yield +3.5 +% +2.6 +% +4.3 +% +Expected Option +Term - This is the weighted average period of time over which the options granted are expected to remain outstanding giving consideration to our historical exercise patterns. Options granted have a maximum term of ten years and an increase +in the expected term will increase compensation expense. +Expected +Volatility – The stock volatility for each grant is measured using the weighted average of historical daily price changes of our common stock over the most recent period approximately equal to the expected option term of the grant. An +increase in the expected volatility factor will increase compensation expense. +Risk-Free +Interest Rate - This is the U.S. Treasury rate in effect at the time of grant having a term approximately equal to the expected term of the option. An increase in the risk-free interest rate will increase compensation expense. +Dividend Yield +–The dividend yield is calculated by dividing the annual dividend declared per common share by the weighted average market value of our common stock on the date of grant. An increase in the dividend yield will decrease compensation expense. +For 2019, 2018, and 2017, we recorded $692 thousand, $629 thousand, and $609 thousand of share-based compensation expense, +respectively, included primarily in general and administrative expense in our Consolidated Statements of Income. We also recorded income tax benefits of $152 thousand, $138 thousand, and $134 thousand in 2019, 2018, and 2017 respectively, related to +such share-based compensation. At December 31, 2019, these benefits are recorded as a deferred tax asset in the Consolidated Balance Sheets. +Equity award activity in the 2005 Equity Incentive Plan and 2014 Equity Incentive Plan is summarized below: +Stock Options +Restricted Stock Units +Number of Shares +Average Price* +Number of Units +Average Price** +Outstanding at December 31, 2018 +1,004,293 +$ +9.00 +98,600 +$ +9.82 +Granted +180,675 +10.31 +58,050 +10.44 +Exercised +– +– +(45,167 +) +9.16 +Forfeited +(36,625 +) +8.72 +(20,908 +) +12.12 +Expired +(5,875 +) +6.05 +– +– +Outstanding at December 31, 2019 +1,142,468 +$ +9.23 +90,575 +$ +10.46 +* +weighted average exercise price per share +** +weighted-average grant stock price per share +The following summarizes information about equity awards outstanding that are vested and expect to vest and equity awards that are +exercisable at December 31, 2019: +Equity Awards Vested and Expected to Vest +Equity Awards That Are Exercisable +Awards +Average Price* +Aggregate Intrinsic Value +Remaining Term** +Awards +Average Price* +Aggregate Intrinsic Value +Remaining Term** +Stock Options +1,142,468 +$ +9.23 +$ +2,441 +5.7 +730,500 +$ +8.62 +$ +1,888 +4.1 +Restricted stock units +90,575 +– +994 +2.5 +– +– +– +– +* +weighted average exercise price per share +** +weighted-average contractual remaining term in years +Shares that are issued upon exercise of employee stock awards are newly issued shares and not issued from treasury stock. As of +December 31, 2019, unrecognized compensation cost related to non-vested equity awards granted under our stock incentive plans is approximately $1.5 million, which is expected to be recognized over a weighted average period of 2.1 years. +F-15 +The total fair value of awards vested during the years ended December 31, 2019, 2018, and 2017 was $1.6 million, $1.1 million, and +$1.1 million, respectively. The total intrinsic value (which is the amount by which the stock price exceeded the exercise price on the date of exercise) of stock options exercised during the years ended December 31, 2018, and 2017 was $280 thousand +and $958 thousand, respectively. No stock options were exercised during the year ended December 31, 2019. Cash received from option exercises was $0.4 million and $1 million for 2018 and 2017, respectively. We recorded a realized tax benefit in +2018 and 2017 from equity-based awards of $17 thousand and $150 thousand, respectively, related to options exercised. Upon adoption of ASU 2016-09 in 2017 tax benefits realized on stock options exercises are included in income tax expense and are no +longer included as a component of cash flows. +11. Income taxes +The components of the income tax provision are as follows: +Year Ended December 31, +(In thousands) +2019 +2018 +2017 +Current: +Federal +$ +58 +$ +1,049 +$ +2,379 +State +51 +85 +114 +Foreign +(58) +13 +(49 +) +51 +1,147 +2,444 +Deferred: +Federal +(205 +) +(117) +1,097 +State +5 +10 +20 +(200 +) +(107 +) +1,117 +Income tax provision (benefit) +$ +(149 +) +$ +1,040 +$ +3,561 +On December 22, 2017, the United States enacted significant changes to U.S. tax law following the passage and signing of the Tax +Reform Act. The legislation significantly changes U.S. tax law by, among other things, lowering corporate income tax rates, implementing a territorial tax system and imposing a one-time repatriation tax on undistributed foreign earnings. The Tax +Reform Act permanently reduces the U.S. corporate income tax rate from a maximum of 35% to a flat 21% rate, effective January 1, 2018. Income tax effects resulting from changes in tax laws are accounted for by the Company in accordance with +authoritative guidance, which requires that these tax effects be recognized in the period in which the law is enacted. +The Company uses the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and +liabilities are recognized for future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured +using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to reverse. As a result of the reduction of TransAct's U.S. corporate income tax rate from 34% to 21% under the Tax Reform Act, +the Company revalued its ending net deferred tax assets at December 31, 2017 and recognized a provisional $1.3 million charge to income tax expense in the Company's consolidated statement of income for the year ended December 31, 2017. +The Tax Reform Act also provided for a one-time deemed mandatory repatriation of post-1986 undistributed foreign subsidiary earnings +and profits ("E&P") through the year ended December 31, 2017. The Company had no undistributed foreign E&P subject to the one-time mandatory repatriation and, therefore, did not recognize any income tax expense related to undistributed +foreign subsidiary E&P for the year ended December 31, 2017. +While the Tax Reform Act provides for a territorial tax system, beginning in 2018, it includes two new U.S. tax base erosion +provisions, the global intangible low-taxed income ("GILTI") provisions and the base-erosion and anti-abuse tax ("BEAT") provisions. The GILTI provisions require the Company to include in its U.S. income tax return foreign subsidiary earnings in +excess of an allowable return on the foreign subsidiary's tangible assets. The BEAT provisions in the Tax Reform Act eliminate the deduction of certain base-erosion payments made to related foreign corporations, and impose a minimum tax if greater +than regular tax. The Company is not currently subject to these taxes and therefore has not included any tax impacts of GILTI or BEAT in its consolidated financial statements for the year ended December 31, 2019 or 2018. +At December 31, 2019, we have no federal or state net operating loss carryforwards, $111 thousand in R&D credit carryforwards, +and no state tax credit carryforwards. Foreign loss before taxes was $515 thousand, $286 thousand, and $563 thousand in 2019, 2018, and 2017, respectively. +F-16 +Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in +the Consolidated Financial Statements. Our deferred tax assets and liabilities were comprised of the following: +December 31, +(In thousands) +2019 +2018 +Deferred tax assets: +Foreign net operating losses +$ +538 +$ +390 +Depreciation +165 +71 +Inventory reserves +916 +879 +Deferred revenue +58 +16 +Warranty reserve +47 +60 +Stock compensation expense +701 +682 +Other accrued compensation +226 +233 +R&D credit carryforward +111 +– +Other liabilities and reserves +276 +278 +Gross deferred tax assets +3,038 +2,609 +Valuation allowance +(444 +) +(390 +) +Net deferred tax assets +2,594 +2,219 +Deferred tax liabilities: +Other +29 +21 +Net deferred tax liabilities +29 +21 +Total net deferred tax assets +$ +2,565 +$ +2,198 +As of December 31, 2019 a valuation allowance of $444 thousand has been established for foreign net operating loss carryforwards that +are not expected to be used. The following table summarizes the activity recorded in the valuation allowance on the deferred tax assets: +Year Ended December 31, +(In thousands) +2019 +2018 +2017 +Balance, beginning of period +$ +390 +$ +328 +$ +423 +Additions charged to income tax provision +54 +62 +67 +Reductions credited to income tax provision +– +– +(162 +) +Balance, end of period +$ +444 +$ +390 +$ +328 +Differences between the U.S. statutory federal income tax rate and our effective income tax rate are analyzed below: +Year Ended December 31, +2019 +2018 +2017 +Federal statutory tax rate +21.0 +% +21.0 +% +34.0 +% +Valuation allowance and tax accruals +14.8 +1.0 +1.6 +State income taxes, net of federal income taxes +12.0 +1.2 +1.3 +Business meals and entertainment +5.4 +0.4 +0.4 +Miscellaneous permanent items +1.4 +0.3 +(0.9 +) +Uncertain tax positions +1.0 +– +(0.1 +) +Stock option cancellations +0.8 +– +1.7 +U.S. corporate tax rate change +– +– +19.4 +Foreign-derived intangible income deduction +(5.4 +) +(1.5 +) +– +Stock award excess tax benefit +(8.4 +) +(1.5 +) +(1.4 +) +R&D credit +(83.2 +) +(4.9 +) +(3.3 +) +Other +– +0.1 +(0.1 +) +Effective tax rate +(40.6 +%) +16.1 +% +52.6 +% +F-17 +Our effective tax rates were -40.6%, 16.1%, and 52.6% for 2019, 2018, and 2017, respectively. We recorded a tax +benefit in 2019 due to the impact of R&D credits on a near break-even level of income before income tax. +We had $107 thousand and $104 thousand of total gross unrecognized tax benefits at December 31, 2019 and 2018, respectively that, if +recognized, would favorably affect the effective income tax rate in any future periods. We are not aware of any events that could occur within the next twelve months that could cause a significant change in the total amount of unrecognized tax +benefits. A tabular reconciliation of the gross amounts of unrecognized tax benefits at the beginning and end of the year is as follows: +December 31, +(In thousands) +2019 +2018 +Unrecognized tax benefits as of January 1 +$ +104 +$ +104 +Tax positions taken during the current period +28 +28 +Lapse of statute of limitations +(25 +) +(28 +) +Unrecognized tax benefits as of December 31 +$ +107 +$ +104 +We expect $27 thousand of the $107 thousand of unrecognized tax benefits will reverse in 2020 upon the expiration of the statute of +limitations. +We recognize interest and penalties related to uncertain tax positions in the income tax provision. We have accrued interest and +penalties related to uncertain tax positions of $18 thousand and $17 thousand as of December 31, 2019 and 2018, respectively. +We are subject to U.S. federal income tax as well as income tax of certain state and foreign jurisdictions. We have substantially +concluded all U.S. federal income tax, state and local, and foreign tax matters through 2015. However, our federal tax returns for the years 2016 through 2018 remain open to examination. Various state and foreign tax jurisdiction tax years remain +open to examination as well, though we believe that any additional assessment would be immaterial to the Consolidated Financial Statements. +12. Earnings per share +For 2019, 2018, and 2017, earnings per share was computed as follows (in thousands, except per share amounts): +Year Ended December 31, +2019 +2018 +2017 +Net income +$ +516 +$ +5,426 +$ +3,211 +Shares: +Basic: Weighted average common shares outstanding +7,466 +7,444 +7,423 +Add: Dilutive effect of outstanding equity awards as determined by the treasury stock +method +211 +315 +169 +Diluted: Weighted average common and common equivalent shares outstanding +7,677 +7,759 +7,592 +Net income per common share: +Basic +$ +0.07 +$ +0.73 +$ +0.43 +Diluted +0.07 +0.70 +0.42 +F-18 +The computation of diluted earnings per share excludes the effect of the potential exercise of stock awards, including stock options, +restricted stock units and performance stock awards, when the average market price of the common stock is lower than the exercise price of the related stock award during the period. These outstanding stock awards are not included in the computation +of diluted earnings per share because the effect would be anti-dilutive. Anti-dilutive stock awards excluded from the computation of earnings per dilutive share were 447,000, 149,000 and 341,000, at December 31, 2019, 2018 and 2017 respectively. +13. Stock repurchase program +Prior to its expiration on December 31, 2019, we maintained a stock repurchase program (the "2018 Stock Repurchase Program") whereby +we were authorized to repurchase up to $5 million of our outstanding shares of common stock from time to time in the open market at prevailing market prices based on market conditions, share price and other factors. We use the cost method to account +for treasury stock purchases, under which the price paid for the stock is charged to the treasury stock account. Repurchases of our common stock are accounted for as of the settlement date. During 2019 we did not repurchase any shares of our common +stock. From the start of the 2018 Stock Repurchase Program on March 1, 2018 through December 31, 2018, we repurchased 156,410 shares of our common stock for approximately $2.0 million at an average price per share of $12.79. +In 2017, under a prior repurchase program that was in place from February 25, 2016 through December 31, 2017, we purchased 36,465 +shares of our common stock for $0.4 million at an average price of $9.84 per share. From January 1, 2005 through December 31, 2019, we repurchased a total of 4,044,842 shares of common stock for $32.1 million, at an average price of $7.94 per share. +14. Geographic area information +Information regarding our operations by geographic area is contained in the following table. These amounts in the geographic area +table are based on the location of the customer and asset. +Year Ended December 31, +(In thousands) +2019 +2018 +2017 +Net sales: +United States +$ +35,332 +$ +43,518 +$ +48,720 +International +10,416 +11,069 +7,591 +Total +$ +45,748 +$ +54,587 +$ +56,311 +Fixed assets, net: +United States +$ +1,326 +$ +1,767 +$ +1,548 +International +918 +505 +621 +Total +$ +2,244 +$ +2,272 +$ +2,169 +Sales to international customers were 23%, 20%, and 14% of total sales in 2019, 2018, and 2017 respectively. Sales to Europe +represented 44%, 56%, and 44%, sales to the Pacific Rim (which includes Australia and Asia) represented 46%, 36%, and 32%, and sales to Canada represented 8%, 6%, and 18% of total international sales in 2019, 2018, and 2017 +respectively. International long-lived assets consist of net fixed assets located at our foreign subsidiary in the UK as well as our contract manufacturers in China, Thailand, Malaysia and Mexico. +F-19 +15. Leases +Operating lease expense for the year ended December 31, 2019, 2018 and 2017 was $1.0 million, $1.1 million and $1.1 million, +respectively, and was included within Cost of sales, Engineering, design and product development expense, Selling and marketing expense, and General and administrative expense. Operating costs include short-term lease costs which were immaterial +during the period. +The following information represents supplemental disclosure for the statement of cash flows related to operating leases (in +thousands): +Year Ended +December 31, 2019 +Operating cash outflows from leases +$ +1,031 +The following summarizes additional information related to our leases as of December 31, 2019: +December 31, 2019 +Weighted average remaining lease term (in years) +5.0 +Weighted average discount rate +3.7 +% +The maturity of the Company’s operating lease liabilities as of December 31, 2019 are as follows (in thousands): +December 31, 2019 +2020 +$ +1,042 +2021 +711 +2022 +434 +2023 +268 +2024 +273 +Thereafter +616 +Total undiscounted lease payments +3,344 +Less imputed interest +295 +Total lease liabilities +$ +3,049 +Prior to the adoption of ASC 842, rental commitments on an undiscounted basis were approximately $4.3 million at December 31, 2018 +under non-cancelable operating leases and were payable as follows: $1.0 million in 2019; $1.0 million in 2020; $0.7 million in 2021; $0.4 million in 2022, $0.3 million in 2023 and $0.9 million thereafter. +16. Quarterly results of operations (unaudited) +Our quarterly results of operations for 2019 and 2018 are as follows: +Quarter Ended +(In thousands, except per share amounts) +March 31 +June 30 +September 30 +December 31 +2019: +Net sales +$ +11,550 +$ +11,350 +$ +11,686 +$ +11,162 +Gross profit +6,086 +5,704 +5,546 +4,599 +Net income (loss) +746 +186 +384 +(800 +) +Net income (loss) per common share: +Basic +0.10 +0.02 +0.05 +(0.11 +) +Diluted +0.10 +0.02 +0.05 +(0.11 +) +2018: +Net sales +$ +12,243 +$ +14,751 +$ +15,838 +$ +11,755 +Gross profit +5,862 +6,991 +8,004 +5,886 +Net income +680 +1,210 +2,574 +962 +Net income per common share: +Basic +0.09 +0.16 +0.35 +0.13 +Diluted +0.09 +0.16 +0.33 +0.12 +F-20 +17. Subsequent events +On February 28, 2020, we entered into an amendment to extend the lease on our facility in Ithaca, New York. The lease, which was +last amended on January 14, 2016, was scheduled to expire on May 31, 2021. The lease amendment provides for an extension of the lease for four additional years from June 1, 2021 to May 31, 2025. +On March 13, 2020, we entered into a new $10 million credit facility (the “Siena Credit Facility”) with Siena +Lending Group LLC. The Siena Credit Facility replaced our TD Bank Credit Facility. The Siena Credit Facility provides for a $10 million revolving credit line expiring on March 13, 2023. Borrowings under the Siena Credit Facility bear a floating +rate of interest equal to the greatest of (i) the prime rate plus 1.75%, (ii) the federal funds rate plus 2.25%, and (iii) 6.50%. We incurred a closing fee of $63 thousand payable 50% on the closing date and 50% on the first anniversary of the +closing date. We also pay a fee of 0.50% on unused borrowings under the facility. Borrowings under the facility are secured by a lien on substantially all the assets of the Company. The Siena Credit Facility imposes certain financial covenants on +the Company and borrowings are subject to a borrowing base based on (i) 85% of eligible accounts receivable plus the lesser of (a) $5,000,000 and (b) 50% of eligible raw material and 60% of finished good inventory. +On March 13, 2020 we loaned an additional $0.6 million to a third party increasing the total note receivable principal balance to +$1.6 million. Repayment is expected to occur in 12 months or less of original issuance and the terms of the loan are the same as the original loan disclosed in Note 3-Note receivable above. +F-21 \ No newline at end of file diff --git a/raw/filings/0001017303/2019/0001017303-20-000012/filing_metadata.csv b/raw/filings/0001017303/2019/0001017303-20-000012/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..96a97c3b4d4a30dd22600f682694cd1f98e075c1 --- /dev/null +++ b/raw/filings/0001017303/2019/0001017303-20-000012/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001017303,TACT,TRANSACT TECHNOLOGIES INC,10-K,2020-03-16,2019-12-31,2020-03-16T21:16:11.000Z,0001017303-20-000012,form10k2019.htm,"FORM 10K FOR THE YEAR ENDED DECEMBER 31, 2019",9276589,1,0,https://www.sec.gov/Archives/edgar/data/1017303/000101730320000012/form10k2019.htm,https://www.sec.gov/Archives/edgar/data/1017303/000101730320000012/,2019,2019,1 diff --git a/raw/filings/0001017303/2019/0001017303-20-000012/item1.txt b/raw/filings/0001017303/2019/0001017303-20-000012/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..140267e2293a22509ac89443b9e1a5b275391072 --- /dev/null +++ b/raw/filings/0001017303/2019/0001017303-20-000012/item1.txt @@ -0,0 +1,211 @@ +Item 1. Business. +The Company +TransAct Technologies Incorporated (together with its consolidated subsidiaries, “TransAct”, the “Company”, “we”, “us”, or “our”) was +incorporated in June 1996 and began operating as a stand-alone business in August 1996 as a spin-off of the printer business that was formerly conducted by certain subsidiaries of Tridex Corporation. We completed an initial public offering on August +22, 1996. +TransAct is a global leader in developing and selling software-driven technology and printing solutions for high growth markets +including food service technology, point of sale (“POS”) automation and banking, casino and gaming, lottery, and oil and gas. Our world-class products are designed from the ground up based on market and customer requirements and are sold under the +BOHA!™, AccuDate™, Epic®, EPICENTRAL™, Ithaca®, and Printrex® brand names. In March 2019, we launched a new line of products for the food service technology market, the BOHA! branded suite of cloud-based applications and companion hardware +solutions. The new BOHA! software and hardware products help restaurants and food service operators of all sizes automate the food production operations in the back-of-house operations. Known and respected worldwide for innovative designs and +real-world service reliability, our thermal and inkjet printers and terminals generate top-quality labels, coupons and transaction records such as receipts, tickets and other documents, as well as printed logging and plotting of data. We sell our +technology to original equipment manufacturers (“OEMs”), value-added resellers, select distributors, as well as directly to end-users. Our product distribution spans across the Americas, Europe, the Middle East, Africa, Asia, Australia, New Zealand, +Latin America, the Caribbean Islands and the South Pacific. We also offer world-class service, support, labels, spare parts, accessories and printing supplies to our growing worldwide base of products currently in use by our customers. Through our +TransAct Services Group (“TSG”), we provide a complete range of supplies and consumables used in the printing and scanning activities of customers in the restaurant and hospitality, banking, retail, casino and gaming, government and oil and gas +exploration markets. Through our webstore, www.transactsupplies.com , and our direct selling team, we address the demand for these products. Our primary +operating, hardware research and development, and eastern region service center is located in Ithaca, New York. In addition, we have a casino and gaming sales headquarters, software research and development and western region service center in Las +Vegas, Nevada; a European sales and service center at our subsidiary in the United Kingdom (“UK”); and a sales office located in Macau, China. Our executive offices are located at One Hamden Center, 2319 Whitney Avenue, Suite 3B, Hamden, +Connecticut, 06518, with a telephone number of (203) 859-6800. +Products, Services and Distribution Methods +Printers, +terminals and other hardware: TransAct designs, develops and markets a broad array of transaction-based and specialty printers and terminals utilizing thermal and inkjet printing technology for applications, primarily in the food service +technology, POS automation and banking, casino and gaming, lottery, and oil and gas printing markets. Our printers and terminals are configurable and offer customers the ability to choose from a variety of features and functions. Options typically +include interface configuration, mounting configuration, paper cutting devices, paper handling capacities and cabinetry color. Our food service technology terminals also offer software configurable menu options. Our food service technology market +also includes sales of hardware products including handheld devices, tablets, temperature probes and temperature sensors and gateways. +1 +Food Service +Technology: The primary offering in the food service technology market is our BOHA! ecosystem, which combines our latest generation terminal, cloud-based software applications and related hardware into a unique solution to automate +operations with food production in the back-of-house operations in restaurants and food service operations. The software component of BOHA! consists of a suite of software-as-a-service (“SaaS”)-based applications, including applications for +inventory management, temperature monitoring of food and equipment, timers, food safety labeling, food recalls, checklists and procedures, equipment service management, and delivery management. Any and all these applications can be chosen by our +customer and packaged into a single platform with the associated hardware, which includes the BOHA! terminal, handheld devices, tablets, temperature probes and temperature sensors and gateways. The BOHA! terminal combines the software and hardware +components in a device that includes an operating system, touchscreen and one or two thermal print mechanisms that print easy-to-read food rotation labels, grab and go labels for prepared foods, nutritional labels and “enjoy by” date labels. The +BOHA! terminal is equipped with the TransAct Enterprise Management System to ensure that only approved applications and functions are available on the device and allows over-the-air updates to the applications and operating system. BOHA! helps food +service establishments and restaurants (including fine dining, casual dining, fast casual and quick-serve restaurants, convenience stores, hospitality establishments and contract food service providers) effectively manage food safety and grab-and-go +initiatives, as well as automate and manage back-of-house operations. Recurring revenue from BOHA! is generated by software sales, including software subscriptions that are charged to customers upfront on a per-application basis, as well as sales of +labels, extended warranty and service contracts, and technical support services. In the food service technology market, we use an internal sales force to solicit sales directly from end users. +POS automation +and banking: In the POS market, we sell several models of printers utilizing thermal printing technology. Our POS printers are used +primarily by quick-serve restaurants located either at the checkout counter or within self-service kiosks to print receipts for consumers or print on linerless labels. In the POS market, we primarily sell our products through a network of domestic +and international distributors and resellers. We use an internal sales force to manage sales through our distributors and resellers, as well as to solicit sales directly from end-users. In the banking market, we sold inkjet printers that are used +by banks, credit unions and other financial institutions to print deposit and withdrawal receipts and to validate checks at bank teller stations. In the banking market, we primarily sold our products directly to end-user banks and financial +institutions through our internal sales force and, to a lesser extent, resellers. We exited the banking market as of December 31, 2018 and therefore do not expect any future sales. +Casino and +gaming: We sell several models of printers used in slot machines and video lottery terminals (“VLTs”) and other gaming machines that print tickets or receipts instead of issuing coins (“ticket-in, ticket-out” or “TITO”) at casinos, +racetracks and other gaming venues worldwide. These printers utilize thermal printing technology to print tickets and receipts in monochrome and offer various other features such as jam resistant bezels and a dual port interface that enables casinos +to print coupons and promotions. In addition, we sell printers using thermal roll-fed printing technology for use in non-casino establishments, including game types such as Amusements with Prizes, Skills with Prizes, Fixed Odds Betting Terminals and +other off-premise gaming type machines around the world. We sell our casino and gaming products primarily (1) to slot machine manufacturers, who incorporate our printers into slot machines and, in turn, sell completed slot machines directly to +casinos and other gaming establishments and (2) through distributors. Prior to December 31, 2017, the Suzo-Happ Group was our primary worldwide distributor. However, effective January 1, 2018, we replaced the Suzo-Happ Group with new distributors +in Asia and Australia and adopted a direct selling model in Europe utilizing our UK sales office. We also maintain a dedicated internal sales force to solicit sales from slot machine manufacturers and casinos, and to manage sales through our +distributors. +We also offer a software solution, the EPICENTRAL™ Print System (“EPICENTRAL™” and “EPICENTRAL® SE”), including annual software +maintenance, that enables casino operators to create promotional coupons and marketing messages and to print them in real-time at the slot machine. With EPICENTRAL™, casinos can utilize the system to create multiple promotions and incentives to +either increase customer time spent on the casino floor or encourage additional visits to generate more revenue to the casinos. In 2017, we introduced EPICENTRAL® SE, a system edition version of our software solution, that is specifically designed +to work with the existing bonusing modules of casino slot machine management systems. In addition, EPICENTRAL® SE provides an upgrade path to a full EPICENTRAL TM implementation in the event an operator seeks to expand its promotion and +bonusing options beyond the slot machine management systems currently offered. In 2019 we introduced Epicentral 4.0, a cloud based version that also uses the new Acres 4.0 technology that provides Epicentral with true real time slot machine play +data. +Lottery: Our +lottery printers are designed for high-volume, high-speed printing of lottery tickets for various lottery applications. We primarily supply lottery printers to International Gaming Technology and its subsidiaries (“IGT”), our largest customer and +the world’s largest provider of lottery terminals. During 2019, we decided to exit this business and we expect our last sales to occur in 2020 and no future sales beyond 2020. Sales of our lottery products are made directly to IGT and other lottery +system customers and are managed by an internal sales representative. +Printrex: Printrex +printers include wide format, desktop and rack mounted and vehicle mounted black and white thermal printers used by customers in the oil and gas exploration industry to log and plot oil field and down hole well drilling data. The Printrex® brand of +printers also includes high-speed color inkjet desktop printers used by oil and gas field service companies to print logs at their data centers. Prior to 2019, revenue in this market also included sales of vehicle mounted printers used to print +schematics and certain other critical information in emergency services vehicles and other mobile printing applications. We exited this market as of December 31, 2018 and do not expect any future sales. We primarily sell our Printrex® products +directly to oil field service and drilling companies and OEM’s, as well as through regional distributors in the United States, Europe, Canada and Asia. +TSG : Through TSG, we proactively market the sale of consumable products (including inkjet cartridges, ribbons, receipt paper, color thermal paper, and +other printing supplies), replacement parts, maintenance and repair services and testing services for all of our products and certain competitor’s products. Our maintenance services include the sale of extended warranties, multi-year maintenance +contracts, 24-hour guaranteed replacement product service called TransAct Xpress™ and other repair services for our printers and terminals. Within the United States, we provide repair services through our eastern region service center in Ithaca, New +York and our western region service center in Las Vegas, Nevada. Internationally, we provide repair services through our European service center located in Doncaster, UK, and through partners strategically located around the world. +We also provide customers with telephone sales and technical support, and a personal account representative to handle orders, +shipping and general information. Technical and sales support personnel receive training on all our manufactured products and services. +In addition to personalized telephone and technical support, we also market and sell consumable products 24 hours a day, seven days a +week, via our online webstore, www.transactsupplies.com . +2 +Sources and Availability of Raw Materials +We design our products to optimize product performance, quality, reliability and durability. These designs combine cost efficient +materials, sourcing and assembly methods with high standards of workmanship. Approximately 99% of our printer and terminal production is primarily through two third-party contract manufacturers in Asia. The remaining 1% of our products are +assembled in our Ithaca, New York facility largely on a configure-to-order basis using components and subassemblies that have been sourced from vendors and contract manufacturers around the world. +We procure component parts and subassemblies for use in the assembly of our hardware products in Ithaca, New York. Critical +component parts and subassemblies include thermal and inkjet print heads, printing/cutting mechanisms, power supplies, motors, injection molded plastic parts, LCD screens, circuit boards and electronic components, which are obtained from domestic and +foreign suppliers at competitive prices. As a result of the majority of our production being performed by our contract manufacturers, the majority of our purchases consist of fully-assembled printers and terminals produced by our contract +manufacturers and, to a much lesser extent, component parts. We typically strive to maintain more than one source for our component parts, subassemblies and fully assembled printers and terminals to reduce the risk of parts shortages or +unavailability. However, we could experience temporary disruption if certain suppliers ceased doing business with us, as described below. +We currently buy a majority of our thermal print mechanisms, an important component of our thermal printers, and fully assembled +printers for several of our printer and food service technology terminal models, from one foreign contract manufacturer in China and to a lesser extent, one other foreign contract manufacturer in Thailand. Although we believe that other contract +manufacturers could provide similar thermal print mechanisms or fully assembled printers and terminals, on comparable terms, a change in contract manufacturers could cause a delay in manufacturing and possible loss of sales, which may have a material +adverse effect on our operating results. Although we do not have supply agreements with our foreign contract manufacturers, our relationship with both remain strong and we have no reason to believe that either will discontinue their supply of +thermal print mechanisms or fully assembled printers to us during 2020 or that their terms to us will be substantially less favorable than they have been historically. Due to the impact from the Chinese tariff, we are seeking to increasingly +transfer production from our largest contract manufacturer in China to our contract manufacturer in Thailand during 2020. +HP Inc. (“HP”) is the sole supplier of inkjet cartridges that are used in all our banking inkjet printers. Though we have exited the +banking market as of December 31, 2018, we still sell a substantial number of HP inkjet cartridges as a consumable product through TSG. Although other inkjet cartridges are compatible with our banking inkjet printers, the loss of the supply of HP +inkjet cartridges could have a material adverse effect on the sale of our TSG consumable products. Our relationship with HP remains stable and we have no reason to believe that HP will discontinue its supply of inkjet cartridges to us or that their +terms to us will be materially different than they have been historically. The inkjet cartridges we purchase from HP are used not only in our inkjet printers for the POS automation and banking market, but also in other manufacturer’s printing +devices across several other markets. +Canon, Inc. (“Canon”) is the sole supplier of inkjet cartridges and other consumable items (“Canon Consumables”) that are used in our +Printrex® 980 oil and gas printer. The loss of supply of Canon Consumables would have a material adverse effect on the sale of Printrex 980® printers and the Canon Consumables. We have a supply agreement with Canon to supply us with Canon +Consumables until May 2020. Prices under this agreement were fixed through May 2013 but may be changed during the remainder of the agreement if the exchange rate fluctuates significantly between the Japanese yen and the U.S. dollar. +Patents and Proprietary Information +TransAct relies on a combination of trade secrets, patents, employee and third-party nondisclosure agreements, copyright laws and +contractual rights to establish and protect its proprietary rights in its products. We hold 36 United States and 37 foreign patents and have 8 United States and 3 foreign patent applications pending pertaining to our products. The duration of these +patents range from 1 to 15 years. The expiration of any individual patent would not have a significant negative impact on our business. We regard certain manufacturing processes and designs to be proprietary and attempt to protect them through +employee and third-party nondisclosure agreements and similar means. It may be possible for unauthorized third parties to copy certain portions of our products or to reverse engineer or otherwise obtain and use, to our detriment, information that we +regard as proprietary. Moreover, the laws of some foreign countries do not afford the same protection to our proprietary rights as do the laws of the United States. There can be no assurance that legal protections we rely upon to protect our +proprietary position will be adequate or that our competitors will not independently develop technologies that are substantially equivalent or superior to our technologies. +Trademarks, Service Marks and Copyrights +We own or have rights to trademarks, service marks, trade names and copyrights that we use in connection with the operation of our +business, including our corporate names, logos and website names. Other trademarks, service marks and trade names appearing in this Annual Report on Form 10-K are the property of their respective owners. The trademarks we own include TransAct®, +BOHA! TM , AccuDate™, Epic, EPICENTRAL™, Ithaca® and Printrex®. Solely for convenience, some of the trademarks, service marks, trade names and copyrights referred to in this annual report on Form 10-K are listed without the ©, ® and ™ +symbols, but we will assert, to the fullest extent under applicable law, our rights to our trademarks, service marks, trade names and copyrights. +Seasonality +Restaurants typically reduce purchases of equipment in the fourth quarter due to the increased volume of transactions during the +holiday period, which may negatively impact sales of our food service technology terminals or POS printers. +Working Capital +Inventory, accounts receivable, and accounts payable levels, payment terms, and where applicable, return policies are in accordance +with the general practices of the industry and standard business procedures. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. +3 +Certain Significant Customers +IGT is our most significant customer and has been since 1995. We sell both on-line lottery printers and casino and gaming printers +to IGT. On May 29, 2015, we signed an agreement with IGT to sell on-line lottery and casino printers to IGT on a non-exclusive basis through December 31, 2019. We decided not to renew the agreement upon its expiration and to exit the on-line +lottery market. Although we no longer have an agreement with IGT, we expect to continue selling casino and gaming printers to IGT in the future but will no longer sell on-line lottery printers other than expected last time purchases by IGT in 2020. +Sales to IGT represented 14%, 18% and 35% of our total net sales for the years ended December 31, 2019, 2018 and 2017, respectively. +Backlog +Our backlog of firm orders was approximately $5.7 million as of February 29, 2020, compared to $6.9 million as of February 28, +2019. Based on customers’ current delivery requirements, we expect to fill and recognize as revenue $5.4 million of our current backlog during 2020, $0.2 million during 2021 and the remaining balance of the amount during 2022. +Competition +The market for transaction-based and specialty printers and food service technology terminals is extremely competitive, and we expect +such competition to continue in the future. However, we experience less competition for EPICENTRAL TM software due to the highly customized nature of the product. We compete with a number of companies, many of which have greater +financial, technical and marketing resources than TransAct. We believe our ability to compete successfully depends on a number of factors both within and outside our control, including durability, reliability, quality, design capability, product +customization, price, customer support, success in developing new products, manufacturing expertise and capacity, supply of component parts and materials, strategic relationships with suppliers, the timing of new product introductions by us and our +competitors, general market, economic and political conditions and, in some cases, the uniqueness of our products. +In the food service technology market, we primarily compete with Avery Dennison Corporation, Ecolab Inc., ITD Food Safety, CMC +Daymark, Integrated Control Corp, Digi International, Squadle Inc., Jolt Software and Zenput. We compete in this market based largely on our ability to provide highly specialized software and purpose-built products and ongoing technical support. +In the POS automation and banking market, we primarily compete with Epson America, Inc., which holds a dominant market position. We +also compete, to a much lesser extent, with CognitiveTPG, Star Micronics America, Inc., Citizen -- CBM America Corporation, Pertech Industries, Inc., Addmaster, and Samsung/Bixolon. Certain competitors of ours have greater financial resources and +lower costs attributable to higher volume production which enables them to occasionally offer lower prices than us. However, we have exited the banking market and will continue to deemphasize efforts in the POS automation market going forward as we +have shifted our focus toward our higher-value, technology enabled food service technology and casino and gaming products. +In the casino and gaming market (consisting principally of slot machine printing, VLT transaction printing and promotional coupon +printing), we compete with several companies including JCM Global, Nanoptix, Inc., Custom Engineering SPA, Eurocoin and others. Certain of our products sold for casino and gaming applications compete based upon our ability to provide highly +specialized products, custom engineering and ongoing technical support. +In the lottery market (consisting principally of on-line lottery transaction printing), we compete with other lottery printer +providers such as Custom Engineering SPA, Star Micronics and Wincor Nixdorf. However, we have exited the lottery market going forward as we have shifted our focus toward our higher-value, technology enabled food service technology and casino and +gaming products. +In the oil and gas market, our Printrex® products compete primarily with the products of Imaging Systems Group, Inc. and Neuralog +Inc. We compete in this market based largely on our ability to provide specialized, custom-engineered products. +The market in which TSG competes is highly fragmented, and we compete with numerous competitors of various sizes, including POS and +internet resellers and paper converters depending on the geographic area. +Our strategy for competing in our markets is to continually develop new products (hardware and software), such as BOHA! TM +in 2019, and product line extensions that are technologically advanced and provide differentiated features and functions, to increase our geographic market penetration, to take advantage of strategic relationships, and to lower the cost of our +products by sourcing certain products overseas. Although we believe that our products, operations and relationships provide a competitive foundation, there can be no assurance that we will compete successfully in the future. In addition, our +products utilize certain thermal and inkjet printing technologies. If new technologies are introduced, or existing technologies evolve, we may be required to incorporate these technologies into our products. Alternatively, if such technologies were +to become available to our competitors, our products could become obsolete, which could have a significant negative impact on our business. +Environment Compliance +Our compliance with federal, state and local laws and regulations relating to environmental protection and discharge of hazardous +materials has not had a material impact on our capital expenditures, earnings or competitive position, and we do not anticipate any material impact from such compliance in the future. +Available Information +We make available free of charge through the “Investor Relations” tab on our Internet website, www.transact-tech.com, our Annual +Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and all amendments to those reports and statements as soon as reasonably practicable after such material is electronically filed with or furnished to +the Securities and Exchange Commission (“SEC”) pursuant to Sections 13(a) or 15(d) of the Exchange Act. The SEC maintains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at +http;//www.sec.gov. The content on any website referred to in this Form 10-K is not incorporated by reference in this Form 10-K unless expressly noted. +4 +Employees +As of December 31, 2019, TransAct and our subsidiaries employed 134 persons, all of whom were full-time employees. None of our +employees are unionized, and we consider our relationships with our employees to be good. +Information about our Executive Officers +The following is a list of the names and ages of all executive officers of the registrant, indicating all positions and offices with +the registrant held by each such person and each person’s principal occupations and employment during at least the past five years. +Name +Age +Position +Bart C. Shuldman +62 +Chairman of the Board and Chief Executive Officer +Steven A. DeMartino +50 +President, Chief Financial Officer, Treasurer and Secretary +Donald E. Brooks +67 +Senior Vice President-Engineering +Tracey S. Chernay +60 +Senior Vice President, Casino, Gaming and Lottery Sales +Andrew J. Hoffman +62 +Senior Vice President, Operations +David B. Peters +41 +Vice President and Chief Accounting Officer +Raymond T. Walsh, Jr. +34 +Senior Vice President, Global Sales +Bart C. Shuldman has been Chief Executive Officer, President and a Director of the Company since its formation in June 1996. In +February 2001, Mr. Shuldman was elected Chairman of the Board. Mr. Shuldman relinquished the President title, effective June 1, 2010, to focus on new products and markets, international expansion and potential acquisitions. +Steven A. DeMartino was named as TransAct’s President, Chief Financial Officer, Treasurer and Secretary on June 1, 2010. Previously, +Mr. DeMartino served as Executive Vice President, Chief Financial Officer, Treasurer and Secretary from June 2004 to May 2010, Senior Vice President, Finance and Information Technology from October 2001 to May 2004, Vice President and Corporate +Controller from January 1998 to October 2001, and Corporate Controller from August 1996 to December 1997. Mr. DeMartino is a certified public accountant. +Donald E. Brooks was appointed Senior Vice President of Engineering in April 2012. Previously, Mr. Brooks served as Vice President, +Engineering from September 2004 to April 2012, Senior Project Engineer from February 1998 to September 2004, Project Engineer from June 1997 to February 1998, Director of Electrical Engineering from March 1986 to June 1997 and Manager of Electronic +Development from December 1983 to March 1986. +Tracey S. Chernay was appointed Senior Vice President, Casino and Gaming Sales and Marketing in June 2010, with responsibility for +the sales and marketing of all casino and gaming products. Previously, Ms. Chernay served as Senior Vice President, Sales and Marketing from June 2007 to May 2010, Senior Vice President, Marketing and Sales, POS and Banking with the Company from +July 2006 to June 2007, and joined TransAct in May of 2005 as Senior Vice President, Marketing. Prior to joining TransAct, Ms. Chernay was employed with Xerox Corporation where she held the role of Manager, Worldwide Marketing since 2003, and +Manager, Sales Operations from 2000 to 2002. She joined Xerox Corporation in 1983. +Andrew J. Hoffman was appointed Senior Vice President, Operations for TransAct worldwide in November 2004. He served as Vice +President, Operations from September 1994 to November 2004. +David B. Peters was appointed Vice President and Chief Accounting Officer on March 1, 2018. Previously, Mr. Peters served as +Director, SEC and Financial Reporting since joining TransAct in March 2014. Prior to joining TransAct, Mr. Peters was employed with United Technologies Corporation from November 2006 to March 2014 where he served in various financial management +positions. Mr. Peters is a certified public accountant. +Raymond T. Walsh, Jr. was appointed Senior Vice President, Global Sales on February 27, 2019. Previously, Mr. Walsh served as Vice +President, Global Sales since 2018. Mr. Walsh joined TransAct in 2006 and has held several sales positions of increasing responsibility with the Company. Prior to joining TransAct, Mr. Walsh served as the Senior Manager of Business Development at +Nerac. +There are no family relationships between any of our executive officers and there is no arrangement or understanding between any of +such officers and any other person pursuant to which he or she was selected as an officer. Each of our executive officers was elected by the Board of Directors to hold office until his or her successor is elected and qualified or until his or her +earlier resignation or removal. \ No newline at end of file diff --git a/raw/filings/0001017303/2019/0001017303-20-000012/item13.txt b/raw/filings/0001017303/2019/0001017303-20-000012/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..185fdb4abf24395ac90d3046b86fc6d10d800d31 --- /dev/null +++ b/raw/filings/0001017303/2019/0001017303-20-000012/item13.txt @@ -0,0 +1,4 @@ +Item 13. Certain Relationships and Related Transactions, and +Director Independence. +The information in response to this item will be contained in the Proxy Statement under the headings “Certain Relationships and +Related Transactions” and is incorporated herein by reference. \ No newline at end of file diff --git a/raw/filings/0001017303/2019/0001017303-20-000012/item9a.txt b/raw/filings/0001017303/2019/0001017303-20-000012/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..8a781fb6e14ff7fd292784bd81ce7f92587f9afe --- /dev/null +++ b/raw/filings/0001017303/2019/0001017303-20-000012/item9a.txt @@ -0,0 +1,54 @@ +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +Our management, with the participation of our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), evaluated the +effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Exchange Act as of December 31, 2019. In the Amendment to our Annual Report on Form 10-K for the year ended December 31, 2018, filed with the SEC on +November 21, 2019, we disclosed that management, including our CEO and CFO, concluded that our disclosure controls and procedures were not effective as of December 31, 2018, due to material weaknesses in our internal control over financial reporting +as described below. As of December 31, 2019, these material weaknesses were not fully remediated and our disclosure controls and procedures were not effective as of December 31, 2019. Management has begun remediation efforts, which are described +below. +Notwithstanding these material weaknesses, our management, including our CEO and CFO, has concluded that our consolidated financial +statements, included in this Form 10-K, fairly present, in all material respects, our financial condition, results of operations and cash flows for the periods presented in conformity with generally accepted accounting principles, and that they can +still be relied upon. +Management’s Annual Report on Internal Control Over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial +reporting, as defined in Rule 13a-15(f) under the Exchange Act, to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with generally +accepted accounting principles. Internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions +of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures +of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the +Company’s assets that could have a material effect on the financial statements. +26 +Our management assessed our internal control over financial reporting as of December 31, 2019. Our management +based its assessment on criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the +Treadway Commission (“2013 COSO”). In the opinion of management, TransAct did not maintain effective internal control over financial reporting as of December 31, 2019 solely because of the material weaknesses in internal control over financial +reporting described below that existed as of December 31, 2018 and were not remediated as of December 31, 2019. +A material weakness is defined in Rule 12b-2 under the Exchange Act as a deficiency, or a combination of +deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis. +We identified the following control deficiencies that constituted material weaknesses in our internal control +over financial reporting as of December 31, 2019 and 2018. +We did not design and maintain effective controls over user access within the Company’s ERP system, +Oracle, to ensure appropriate segregation of duties and to adequately restrict user access to appropriate personnel. Specifically, the provisioning and user recertification controls are not designed to ensure users maintain proper +segregation of duties and therefore could have inappropriate access rights. (the “Access Control Weakness”). +We did not design and maintain effective controls over the completeness and accuracy of information +included in key spreadsheets supporting our accounting records (the “Spreadsheet Control Weakness”). +The control deficiencies constituted material weaknesses but did not result in a material misstatement of our +annual or interim consolidated financial statements. However, if these material weaknesses are not remediated, a material misstatement of account balances or disclosures may not be prevented, and may go undetected, which could result in a material +misstatement of future annual or interim consolidated financial statements. +The effectiveness of the Company’s internal control over financial reporting as of December 31, 2019 has been +audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on pages F-2 through F-3 of this Form 10-K. +Remediation Plan +During 2019, we commenced developing and implementing a plan to enhance the design and operating effectiveness +of our internal control over financial reporting, which includes taking the following steps to remediate the identified control deficiencies and material weaknesses: +To address the Access Control Weakness, we are utilizing the services of an Oracle consulting firm to +assist us in analyzing and reviewing Oracle access for all users. During the first quarter of 2020, we completed the analysis and have developed an action plan to modify the designated Oracle responsibilities for each employee with respect +to whom a conflict was identified to remove any Oracle transactional responsibilities that we believe are conflicting and, in some instances, we will reassign those responsibilities to a different employee to ensure proper segregation of +duties. We have begun the design and testing of the new Oracle responsibilities created. In addition, we plan to enhance and implement provisioning and user certification controls to ensure we maintain the appropriate segregation of +duties within Oracle following the analysis. +To address the Spreadsheet Control Weakness, for each key spreadsheet using Oracle data, we plan to +evaluate and determine (1) if a standard Oracle report exists containing the same information as the spreadsheet, and if so, we would utilize the standard Oracle report (without modification) instead of the spreadsheet to support our +accounting records and (2) if a standard Oracle report cannot be used, we will implement a new key control whereby an employee performs a formal validation that the information from Oracle is completely and accurately transferred +(automatically or manually) to a spreadsheet by verifying totals and other information on a test basis. For all other key spreadsheets, we plan to design and implement a new key control to validate completeness and accuracy of information +supporting our accounting records. During the first quarter of 2020, we began the process of evaluating each key spreadsheet based on the above criteria, and for several key spreadsheets, we implemented a new key control to validate the +completeness and accuracy of the information contained within and supporting each such spreadsheet. +We believe these steps will address the material weaknesses described above. +Changes in Internal Control over Financial Reporting +There has been no change in our internal control over financial reporting that occurred during the quarter ended December 31, 2019 +that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. \ No newline at end of file diff --git a/raw/filings/0001017303/2019/0001017303-20-000012/rp_note.txt b/raw/filings/0001017303/2019/0001017303-20-000012/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001017303/2019/0001017303-20-000012/rpt_disclosure.txt b/raw/filings/0001017303/2019/0001017303-20-000012/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..a18480773b8bfff0ab10000bfff69055446e2430 --- /dev/null +++ b/raw/filings/0001017303/2019/0001017303-20-000012/rpt_disclosure.txt @@ -0,0 +1,16 @@ +CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS +The Company maintains a Related Party Transactions Policy relating to the identification, review and approval of related party transactions, in addition to the +requirements of The Nasdaq Global Market (“Nasdaq”) and the SEC The Related Party Transactions Policy, which is administered by our Audit Committee, is set forth in our Standards of Business Conduct and Code of Ethics available under the “Corporate +Governance” tab on the “Investor Relations” page of our website at www.transact-tech.com. +In particular, our Standards of Business Conduct and Code of Ethics requires all directors, officers and employees to avoid any situation that involves an actual +or apparent conflict of interest in personal and professional relationships or with their duty to, or with any interest of, the Company, including engaging in “Related Party Transactions.” The term “Related Party Transaction” means any transaction, +arrangement or relationship, or any series of similar transactions, arrangements or relationships, in which (i) the Company or any of its subsidiaries or Controlled Affiliates (as such term is defined in the policy) is or will be a participant, (ii) +the aggregate amount involved will or may be expected to exceed $120,000 in any fiscal year, and (iii) any Related Party has or will have a direct or indirect interest. A “Related Party” is defined as any person who is or was (since the beginning of +the last fiscal year for which the Company has filed an Annual Report on Form 10-K and proxy statement, even if such person does not presently serve in that role) an executive officer, director or nominee for director of the Company, any stockholder +owning more than 5% of any class of the Company’s voting securities, or an immediate family member of any such person. +The Chair of the Audit Committee must be notified prior to a Related Party engaging in a Related Party Transaction. The Audit Committee is then responsible for +reviewing the transaction. No transaction determined to be a Related Party Transaction will be approved or ratified if the transaction is contrary to the best interests of the Company. In determining whether to approve or ratify a Related Party +Transaction, the Audit Committee takes into account such factors as it deems appropriate, which may include whether the interested transaction is on terms no less favorable than terms generally available to an unaffiliated third party under the same +or similar circumstances and the extent of the Related Party’s interest in the transaction. +From January 1, 2018 to the date of this Proxy Statement, there have not been any transactions subject to the Company’s Related Party Transactions Policy or of +the type described in Item 404 of Regulation S-K, and currently no such transactions are proposed. \ No newline at end of file diff --git a/raw/filings/0001017303/2020/0001017303-21-000020/filing.txt b/raw/filings/0001017303/2020/0001017303-21-000020/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..13121806a6c45a6352ebd4df32e6f775851715c2 --- /dev/null +++ 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tact:Solution xbrli:pure tact:Plan +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549 +FORM 10-K +(Mark One) +☒ +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2020 +or +☐ +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from __________ to __________ +Commission file number: 0-21121 +TRANSACT TECHNOLOGIES INC +(Exact name of registrant as specified in its charter) +Delaware +06-1456680 +(State or other jurisdiction of incorporation or organization) +(I.R.S. Employer Identification No.) +One Hamden Center , 2319 Whitney Avenue, Suite 3B , Hamden , Connecticut +06518 +(Address of principal executive offices) +(Zip Code) +( 203 ) 859-6800 +(Registrant’s Telephone Number, Including Area Code) +Securities registered pursuant to Section 12(b) of the Act: None +Securities registered pursuant to Section 12(g) of the Act: +Title of each class +Trading Symbol(s) +Name of each exchange on which registered +Common stock, par value $0.01 per share +TACT +NASDAQ Global Market +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes □ No ⌧ +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes □ No ⌧ +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ⌧ No □ +Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ⌧ No □ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one): +Large accelerated filer □ +Accelerated filer □ +Non-accelerated filer ⌧ +Smaller reporting company ☒ +Emerging growth company ☐ +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial standards provided pursuant to Section 13(a) of the Exchange Act. □ +Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. □ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ⌧ +The aggregate market value of the voting and non-voting common equity held by non-affiliates of the Registrant was approximately $ 33,500,000 based on the last sale price on June 30, 2020. +As of February 28, 2021, the number of shares outstanding of the Registrant’s common stock, $0.01 par value, was 8,960,535 . +DOCUMENTS INCORPORATED BY REFERENCE +Portions of the Registrant’s Definitive Proxy Statement related to its 2021 Annual Meeting of Stockholders (the “Proxy Statement”) to be filed with the Securities and Exchange Commission within 120 days after the Registrant’s fiscal year end of December 31, 2020 are incorporated by reference into Part III of this Annual Report on Form 10-K. +TRANSACT TECHNOLOGIES INCORPORATED +INDEX +PART I. +Item 1. +Business +1 +Item 1A. +Risk Factors +8 +Item 1B. +Unresolved Staff Comments +17 +Item 2. +Properties +17 +Item 3. +Legal Proceedings +17 +Item 4. +Mine Safety Disclosures +17 +PART II. +Item 5. +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities +18 +Item 6. +Selected Financial Data +18 +Item 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations +18 +Item 7A. +Quantitative and Qualitative Disclosures About Market Risk +28 +Item 8. +Financial Statements and Supplementary Data +28 +Item 9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure +28 +Item 9A. +Controls and Procedures +28 +Item 9B. +Other Information +29 +PART III. +Item 10. +Directors, Executive Officers and Corporate Governance +30 +Item 11. +Executive Compensation +30 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters +30 +Item 13. +Certain Relationships and Related Transactions, and Director Independence +30 +Item 14. +Principal Accounting Fees and Services +30 +PART IV. +Item 15. +Exhibits, Financial Statement Schedules +31 +Item 16. +Form 10-K Summary +32 +SIGNATURES +Signatures +33 +CONSOLIDATED FINANCIAL STATEMENTS +Index to Consolidated Financial Statements +F-1 +Smaller Reporting Company—Scaled Disclosure +Pursuant to Item 10(f) of Regulation S K promulgated under the Securities Act of 1933, as amended, as indicated herein, we have elected to comply with certain scaled disclosure requirements applicable to “smaller reporting companies” in this Annual Report on Form 10-K (this “Form 10-K”). +PART I +Forward-Looking Statements +Certain statements included in this Form 10-K may include “forward-looking statements” within the meaning of the U.S. federal securities laws, including the Private Securities Litigation Reform Act of 1995. Forward-looking statements are any statements other than statements of historical fact. Forward-looking statements represent current views about possible future events and are often identified by the use of forward-looking terminology, such as “may,” “will,”,, “expect,” “intend,” “estimate,” “anticipate,” “believe,” “project” or “continue” or the negative thereof or other similar words. Forward-looking statements are subject to certain risks, uncertainties and assumptions. In the event that one or more of such risks or uncertainties materialize, or one or more underlying assumptions prove incorrect, actual results may differ materially from those expressed or implied by the forward-looking statements. +Important factors and uncertainties that could cause actual results to differ materially from those expressed or implied by the forward-looking statements include, but are not limited to, the following: the adverse effects of the COVID-19 pandemic on our business, operations, financial condition, results of operations and capital resources, including as a result of supply chain disruptions, shutdowns and/or operational restrictions imposed on our customers, an inability of our customers to make payments on time or at all, diversion of management attention, necessary modifications to our business practices and operations, cost cutting measures we have made and may continue to make, a possible future reduction in the value of goodwill or other intangible assets, inadequate manufacturing capacity or a shortfall or excess of inventory as a result of difficulty in predicting manufacturing requirements due to volatile economic conditions, price increases or decreased availability of component parts or raw materials, exchange rate fluctuations, volatility of, and decreases in, trading prices of our common stock and the availability of needed financing on acceptable terms or at all; our ability to successfully develop new products that garner customer acceptance and generate sales, both domestically and internationally, in the face of substantial competition; our reliance on an unrelated third party to develop, maintain and host certain web-based food service application software and develop and maintain selected components of our downloadable software applications pursuant to a non-exclusive license agreement, and the risk that interruptions in our relationship with that third party could materially impair our ability to provide services to our food service technology customers on a timely basis or at all and could require substantial expenditures to find or develop alternative software products; our ability to successfully transition our business into the food service technology market; our ability to remediate the material weakness over internal control over financial reporting; risks associated with potential future acquisitions; general economic conditions; our dependence on contract manufacturers for the assembly of a large portion of our products in Asia; our dependence on significant suppliers; our ability to recruit and retain quality employees as the Company grows; our dependence on third parties for sales outside the United States; marketplace acceptance of new products; risks associated with foreign operations; the availability of third-party components at reasonable prices; price wars or other significant pricing pressures affecting the Company’s products in the United States or abroad; increased product costs or reduced customer demand for our products due to changes in U.S. policy that may result in trade wars or tariffs; our ability to protect intellectual property; the effect of the United Kingdom’s withdrawal from the European Union; and other risk factors identified and discussed in Part I, Item 1A, Risk Factors , and Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations , of this Form 10-K and that may be detailed from time to time in the Company’s other reports filed with the Securities and Exchange Commission (the “SEC”). +We caution readers not to place undue reliance on forward-looking statements, which speak only as of the date of this Form 10-K. We undertake no obligation to public publicly or otherwise revise any forward-looking statements, whether as a result of new information, future events or other factors, except where we are expressly required to do so by law. +Item 1. Business. +The Company +TransAct Technologies Incorporated (together with its consolidated subsidiaries, “TransAct,” the “Company,” “we,” “us,” or “our”) was incorporated in June 1996 and began operating as a stand-alone business in August 1996 as a spin-off of the printer business that was formerly conducted by certain subsidiaries of Tridex Corporation. We completed an initial public offering on August 22, 1996. +TransAct is a global leader in developing and selling software-driven technology and printing solutions for high growth markets including food service technology, point of sale (“POS”) automation, casino and gaming, and oil and gas. Our world-class products are designed from the ground up based on market and customer requirements and are sold under the BOHA!™, AccuDate™, Epic®, EPICENTRAL™, Ithaca®, and Printrex® brand names. During 2019, we launched a new line of products for the food service technology market, the BOHA! branded suite of cloud-based applications and companion hardware solutions. The new BOHA! software and hardware products help restaurants, convenience stores and food service operators of all sizes automate the food production in the back-of-house operations. Known and respected worldwide for innovative designs and real-world service reliability, our thermal printers and terminals generate top-quality labels, coupons and transaction records such as receipts, tickets and other documents, as well as printed logging and plotting of data. We sell our technology to original equipment manufacturers (“OEMs”), value-added resellers, select distributors, as well as directly to end-users. Our product distribution spans across the Americas, Europe, the Middle East, Africa, Asia, Australia, New Zealand, Latin America, the Caribbean Islands and the South Pacific. We also offer world-class service, support, labels, spare parts, accessories and printing supplies to our growing worldwide base of products currently in use by our customers. Through our TransAct Services Group (“TSG”), we provide a complete range of supplies and consumables used in the printing activities of customers in the restaurant and hospitality, retail, casino and gaming, government and oil and gas exploration markets. Through our webstore, www.transactsupplies.com , and our direct selling team, we address the demand for these products. Our primary operating, hardware research and development, and U.S. service center is located in Ithaca, New York. In addition, we have a casino and gaming sales headquarters and software research and development in Las Vegas, Nevada; a European sales and service center at our subsidiary in the United Kingdom (“UK”); and a sales office located in Macau, China. Our executive offices are located at One Hamden Center, 2319 Whitney Avenue, Suite 3B, Hamden, Connecticut, 06518, with a telephone number of (203) 859-6800. +1 +Impact of the COVID-19 Pandemic +In December 2019, a novel strain of coronavirus and the disease it causes, commonly known as COVID-19, was first reported in China and has since widely impacted the global public health and economic environment. In March 2020, the World Health Organization declared COVID-19, including all additional variations and strains thereof, a global pandemic. Our business trends through the first two months of 2020 were in line with internal expectations; however, the challenges posed by the COVID-19 pandemic on the United States and global economy increased significantly as the first quarter of 2020 progressed and continued throughout the remainder of 2020. Unfortunately, the massive economic and social disruptions across the world persist due to COVID-19 and the measures implemented to mitigate its spread. The food service, casino and gaming, and oil and gas industries have been particularly affected by the pandemic, and we expect such disruptions to continue to negatively impact our overall business for the foreseeable future. +As a result of the COVID-19 pandemic and measures implemented to mitigate its spread, we experienced decreased demand for our products and lower than anticipated sales beginning in the second half of March 2020 and continuing through the end of 2020, particularly in our food service technology and casino and gaming markets. We experienced some improvement in demand during the second half of 2020 compared to the second quarter of 2020, as some state and local governments lifted certain measures implemented earlier in 2020 to mitigate the spread of the virus, however demand remained lower than 2019, and we expect this trend to continue through at least the first half of 2021. Below is a discussion of the impact of COVID-19 that we have experienced, and that we believe we will continue to experience for the foreseeable future in each of our markets. +Food service technology and POS automation . In both our food service technology and POS automation markets, many restaurants and food service establishments that were closed during much of the second quarter of 2020 started to reopen as state and local governments began to ease restrictions put in place in response to the pandemic. Many of our customers have opened under restrictions that limit them to providing drive through, take-out or delivery service without dine-in options, as well as limiting the volume of customers and employees on site at any one time. During the third and fourth quarters of 2020, we experienced sales improvement compared to the second quarter of 2020, as these food service customers reopened for business. However, during the fourth quarter of 2020, restaurants were again impacted by a resurgence of the pandemic. Notwithstanding the gradual resumption of limited operations that began in the third quarter of 2020, our food service technology and POS automation customers continue to recover from the financial impact of being closed for several months and we expect new capital expenditures to be a lower priority for them in the near term, which we believe will continue to negatively impact sales of BOHA! hardware, software and label products, as well as sales of POS printers. However, food service providers have been and are likely to continue to be required to develop and implement new or enhanced policies and operating procedures regarding cleaning, sanitizing and social distancing to ensure the safety of their employees and customers. We believe that our BOHA! hardware, software and label products could prove to be helpful to our food service customers in efficiently and effectively managing and complying with these new procedures, especially as many establishments are and will likely continue to be operating with reduced staff levels. +Casino and gaming . In the casino and gaming market, most casinos and other gaming establishments were closed worldwide during most of the second quarter of 2020. Many casinos began to reopen in late May and early June 2020, but similar to restaurants, casino openings were slow and measured, starting with reduced capacity and limited game play based on social distancing guidelines. During the fourth quarter of 2020, some casinos re-closed due to a resurgence of the pandemic. We anticipate that casinos will continue to limit capacity in the near term and will progressively increase capacity over time. As casinos gradually recover from the financial impact of being closed for several months, we expect that casinos’ appetite for purchases of new slot machines will be diminished, which we believe is likely to negatively impact sales of casino and gaming printers purchased by slot manufacturers for use in slot machines at casinos during 2021. +Lottery . We exited the lottery market at the end of 2019 and IGT made a final purchase of our lottery printer during the second quarter of 2020. Therefore, COVID-19 has not had an impact our lottery printer sales, and we do not anticipate that it will have an impact on our future lottery printer sales. +Printrex . The oil and gas market has been negatively impacted by the decline in worldwide oil prices attributable to the COVID-19 pandemic. Due to the uncertainty of current and future market conditions, we believe sales of our Printrex oil and gas printers will continue to be negatively impacted until oil and gas prices recover. +TSG . Due to closures and reduced operating capacity of restaurants, food service establishments, casinos and other gaming establishments resulting from the COVID-19 pandemic, sales of spare parts, service and consumable products have declined, and we expect such sales to remain at reduced levels, due to lower usage while the pandemic persists. +Our gross margin has been negatively impacted and we expect our gross margin to continue to be negatively impacted by the COVID-19 pandemic. As a result of an expected significantly lower sales level, we believe our gross margin will decline due to fixed manufacturing overhead expenses (such as facility costs, depreciation, etc.) that cannot be reduced or eliminated even with the lower sales level. +We have also experienced supply chain disruptions, including delayed product shipments from our two contract manufacturers located in China and Thailand that conduct almost all of our printer and terminal manufacturing, due to reduced operations and parts shortages at these facilities. To date, these disruptions have only minimally impacted deliveries to customers due to our high inventory levels and reduced demand for our products. However, if the delays are sustained or additional disruptions from the pandemic occur, we may have insufficient inventory levels and our ability to deliver products to our customers on time or at all may be impaired. +2 +While it is difficult to predict the magnitude of the ultimate impact that the pandemic and the responsive measures will have on our customers and our business, we took several actions during 2020 to manage our expenses during these turbulent and uncertain times. Such steps included: +● +a reduction of our workforce starting in July 2020 by approximately 20% through a combination of employee terminations and temporary furloughs. During the fourth quarter, we brought back all furloughed employees. As of December 31, 2020 our overall headcount was reduced by approximately 16% when compared to December 31, 2019; +● +a 10% reduction in the salaries of all salaried, non-commissioned employees, including executive officers, starting in March 2020. From May 1, 2020 until early July 2020, employees below the vice president level were paid their full salary as a result of the receipt of the PPP Loan proceeds (defined below). All employee full salaries were reinstated on January 1, 2021; +● +a reduction in sales commissions for all commissioned employees starting in March 2020 through the end of 2020; +● +a 10% reduction of cash retainer fees for all non-employee directors starting in March 2020 through the end of 2020; and +● +the elimination of discretionary spending wherever possible starting in March 2020, which has continued into the first quarter of 2021. +In addition, we took measures to increase liquidity, including the following: +● +Public Offering – On October 16, 2020, the Company raised net proceeds of $8.7 million, after deducting underwriting discounts, commissions and offering expenses, through an underwritten public offering (the “Offering”) and sold an aggregate of 1,380,000 shares of common stock. +● +PPP Loan – On May 1, 2020 (the “Loan Date”), the Company was granted a $2.2 million loan (the “PPP Loan”) under the Paycheck Protection Program (the “PPP”) administered by the Small Business Administration (“SBA”) established under Division A, Title I of the Coronavirus Aid, Relief, and Economic Security (“CARES”) Act, which enabled us to return our furloughed employees to full time employment and to restore certain pay cuts until the PPP Loan proceeds were exhausted. +● +New Credit Facility – On March 13, 2020, we entered into a new credit facility with Siena Lending Group LLC that provides a revolving credit line of up to $10.0 million, subject to a borrowing base. +● +Reduced Capital Expenditures – We limited capital expenditures during 2020. +Since the onset of the pandemic, our top priority has been to ensure the health and safety of our employees while continuing to provide our customers with high-quality, personalized service. On March 20, 2020, we instituted work-from-home practices for the majority of our employees to reduce the spread of COVID-19 and to comply with government mandates. Because most of our employees already had laptop computers with remote access into our IT systems, we have experienced only minor reductions in productivity and minimal costs related to the implementation of our work-from-home practices. In addition, even with the move to a work-from-home environment, our existing internal control structure remained operational and unchanged. +Our distribution centers, deemed an essential service, have remained operational throughout the pandemic. We implemented a new COVID-19 policy to specifically address health and safety guidelines for employees to adhere to and follow when at work or returning to work. This policy was based on the COVID-19 safety guidelines recommended by the Centers for Disease Control and Prevention and implements the following operations procedures: +● +staggered shifts and a rotational or flexible work schedule to minimize the number of employees at any particular facility at a single time; +● +mandated use of protective equipment, such as masks and gloves, when in common areas, which is provided to employees; +● +spaced seating in workspaces such as manufacturing cells, lunch/break rooms, conference rooms and other common areas to comply with social distancing guidelines ; +● +employees who (i) show symptoms of COVID-19 or (ii) have been exposed to someone who shows symptoms or has tested positive for COVID-19 are prohibited from reporting to work for 10 days ; +● +visitors are prohibited from entering all facilities ; +● +cleaning and disinfecting protocols at all facilities; and +● +daily temperature checks of all employees before entering all facilities . +We have evaluated the recoverability of the assets on our Consolidated Balance Sheet as of December 31, 2020 in accordance with relevant authoritative accounting literature. We considered the disruptions caused by the COVID-19 pandemic, including lower than previously forecasted sales and customer demand, a decline in the price of our common stock and macroeconomic factors potentially impacting accounts receivable, inventory, investments, intangible assets, goodwill and other assets and liabilities. Where forward-looking estimates are required, we made a good-faith estimate based on information available as of the balance sheet date. We have continued to monitor for indicators of impairment through the date of this Report and reflected accordingly in the accompanying condensed consolidated financial statements. +Notwithstanding the foregoing, there is no assurance that the actions we have taken in response to the pandemic are sufficient or adequate, and we may be required to take additional preventive or responsive measures, as the ultimate extent of the effects of the COVID-19 pandemic on the Company, our financial condition, results of operations, liquidity, and cash flows are uncertain and are dependent on evolving developments which cannot be predicted at this time. See Part I, Item 1A, Risk Factors, of this Form 10-K for further discussion of risks related to COVID-19. +3 +Products, Services and Distribution Methods +Printers, terminals and other hardware: TransAct designs, develops and markets a broad array of transaction-based and specialty printers and terminals utilizing thermal printing technology for applications, primarily in the food service technology, POS automation, casino and gaming, and oil and gas printing markets. Our printers and terminals are configurable and offer customers the ability to choose from a variety of features and functions. Options typically include interface configuration, mounting configuration, paper cutting devices, paper handling capacities and cabinetry color. Our food service technology terminals also offer software configurable menu options. Our food service technology market also includes sales of hardware products including handheld devices, tablets, temperature probes and temperature sensors and gateways. +Food Service Technology: The primary offering in the food service technology market is our BOHA! ecosystem, which combines our latest generation terminal, cloud-based software applications and related hardware into a unique solution to automate back-of-house operations in restaurants, convenience stores and food service operations . The software component of BOHA! consists of a suite of software-as-a-service (“SaaS”)-based applications, including applications for inventory management, temperature monitoring of food and equipment, timers, food safety labeling, food recalls, checklists and procedures, equipment service management, and delivery management. Any and all these applications can be chosen by our customer and packaged into a single platform with the associated hardware, which includes the BOHA! terminal, handheld devices, tablets, temperature probes and temperature sensors and gateways. The BOHA! terminal combines the software and hardware components in a device that includes an operating system, touchscreen and one or two thermal print mechanisms that print easy-to-read food rotation labels, grab-and-go labels for prepared foods, nutritional labels and “enjoy by” date labels. The BOHA! terminal is equipped with the TransAct Enterprise Management System to ensure that only approved applications and functions are available on the device and allows over-the-air updates to the applications and operating system. BOHA! helps food service establishments and restaurants (including fine dining, casual dining, fast casual and quick-serve restaurants, convenience stores, hospitality establishments and contract food service providers) effectively manage food safety and grab-and-go initiatives, as well as automate and manage back-of-house operations. Recurring revenue from BOHA! is generated by software sales, including software subscriptions that are charged to customers upfront on a per-application basis, as well as sales of labels, extended warranty and service contracts, and technical support services. In the food service technology market, we use an internal sales force to solicit sales directly from end users. +POS automation: In the POS market, we sell several models of printers utilizing thermal printing technology. Our POS printers are used primarily by quick-serve restaurants located either at the checkout counter or within self-service kiosks to print receipts for consumers or print on linerless labels. In the POS market, we primarily sell our products through a network of domestic and international distributors and resellers. We use an internal sales force to manage sales through our distributors and resellers, as well as to solicit sales directly from end-users. Prior to 2020, revenue in this market included sales of inkjet printers used by banks, credit unions and other financial institutions to print deposit or withdrawal receipts and/or validate checks at bank teller stations. We exited the banking market during 2018 and therefore do not expect any future sales. In the banking market, we primarily sold our products directly to end-user banks and financial institutions through our internal sales force and, to a lesser extent, resellers. +Casino and gaming: We sell several models of printers used in slot machines and video lottery terminals (“VLTs”) and other gaming machines that print tickets or receipts instead of issuing coins (“ticket-in, ticket-out” or “TITO”) at casinos, racetracks and other gaming venues worldwide. These printers utilize thermal printing technology to print tickets and receipts in monochrome and offer various other features such as jam resistant bezels and a dual port interface that enables casinos to print coupons and promotions. In addition, we sell printers using thermal roll-fed printing technology for use in international non-casino establishments, including game types such as Amusements with Prizes, Skills with Prizes, Fixed Odds Betting Terminals, sports betting establishments and other off-premise gaming type machines around the world. We sell our casino and gaming products primarily (1) to slot machine manufacturers, who incorporate our printers into slot machines and, in turn, sell completed slot machines directly to casinos and other gaming establishments and (2) through distributors. We also maintain a dedicated internal sales force to solicit sales from slot machine manufacturers and casinos, and to manage sales through our distributors. +We also offer a software solution, the EPICENTRAL™ Print System, including annual software maintenance, that enables casino operators to create promotional coupons and marketing messages and to print them in real time at the slot machine. With EPICENTRAL™, casinos can utilize the system to create multiple promotions and incentives to either increase customer time spent on the casino floor or encourage additional visits to generate more revenue to the casinos. In 2019, we introduced EPICENTRAL 4.0, which uses the new Acres 4.0 technology that provides EPICENTRAL with true real time slot machine play data. +Lottery: Our lottery printers are designed for high-volume, high-speed printing of lottery tickets for various lottery applications. We primarily supply lottery printers to International Gaming Technology and its subsidiaries (“IGT”), our largest customer and the world’s largest provider of lottery terminals. During 2019, we decided to exit this business and we expect no future sales beyond 2020. Sales of our lottery products were made directly to IGT and were managed by an internal sales representative before we exited the business in 2019. +Printrex: Printrex printers include wide format, desktop and rack-mounted and vehicle-mounted black and white thermal printers used by customers to log and plot oil field, seismic and down hole well drilling data in the oil and gas exploration industry . The Printrex® brand of printers also includes high-speed color inkjet desktop printers used by oil and gas field service companies to print logs at data centers of the oil and gas field service companies. We primarily sell our Printrex® products directly to oil field service and drilling companies and OEM’s, as well as through regional distributors in the United States, Europe, Canada and Asia. +TSG : Through TSG, we proactively market the sale of consumable products (including POS receipt paper, inkjet cartridges, ribbons and other printing supplies), replacement parts, maintenance and repair services, refurbished printers, and shipping and handling charges. Our maintenance services include the sale of extended warranties, multi-year maintenance contracts, a 24-hour guaranteed replacement product service called TransAct Xpress™ and other repair services for our printers and terminals. Within the United States, we provide repair services through our service center in Ithaca, New York. Internationally, we provide repair services through our European service center located in Doncaster, UK, and through partners strategically located around the world. +4 +We also provide customers with telephone sales and technical support, and a personal account representative to handle orders, shipping and general information. Technical and sales support personnel receive training on all our manufactured products and services. In addition to personalized telephone and technical support, we also market and sell consumable products 24 hours a day, seven days a week, via our webstore, www.transactsupplies.com . +Sources and Availability of Raw Materials +We design our products to optimize product performance, quality, reliability and durability. These designs combine cost efficient materials, sourcing and assembly methods with high standards of workmanship. Almost all of our printers and terminals are produced by two third-party manufacturers located in China and Thailand. A small portion of our products are assembled in our Ithaca, New York facility largely on a configure-to-order basis using components and subassemblies that have been sourced from vendors and contract manufacturers around the world. +We procure component parts and subassemblies for use in the assembly of our hardware products in Ithaca, New York. Critical component parts and subassemblies include thermal print heads, printing/cutting mechanisms, power supplies, motors, injection molded plastic parts, LCD screens, circuit boards and electronic components, which are obtained from domestic and foreign suppliers at competitive prices. As a result of the majority of our production being performed by our contract manufacturers, the majority of our purchases consist of fully-assembled printers and terminals produced by our contract manufacturers and, to a much lesser extent, component parts. We typically strive to maintain more than one source for our component parts, subassemblies and fully assembled printers and terminals to reduce the risk of parts shortages or unavailability. However, we could experience temporary disruption if certain suppliers ceased doing business with us, as described below. +We currently buy a majority of our thermal print mechanisms, an important component of our thermal printers, and fully assembled printers for several of our printer and food service technology terminal models, from one foreign contract manufacturer in China and to a lesser extent, one other foreign contract manufacturer in Thailand. Although we believe that other contract manufacturers could provide similar thermal print mechanisms or fully assembled printers and terminals, on comparable terms, a change in contract manufacturers could cause a delay in manufacturing and possible loss of sales, which may have a material adverse effect on our operating results. Although we do not have supply agreements with our foreign contract manufacturers, our relationship with both remain strong and we have no reason to believe that either will discontinue their supply of thermal print mechanisms or fully assembled printers to us during 2021 or that their terms to us will be substantially less favorable than they have been historically. Due to the impact from the Chinese tariff starting in 2019, during 2020 we increasingly transferred production from our largest contract manufacturer in China to our contract manufacturer in Thailand. We plan to continue transferring production to our contract manufacturer during 2021. +We currently buy a majority of our thermal print mechanisms, an important component of our thermal printers, and fully assembled printers for several of our printer and food service technology terminal models, from a foreign contract manufacturer in China and a foreign contract manufacturer in Thailand. Although we believe that other contract manufacturers could provide similar thermal print mechanisms or fully assembled printers and terminals, on comparable terms, a change in contract manufacturers could cause a delay in manufacturing and possible loss of sales, which may have a material adverse effect on our operating results. Although we do not have supply agreements with our foreign contract manufacturers, our relationship with both remain strong and we have no reason to believe that either will discontinue their supply of thermal print mechanisms or fully assembled printers to us during 2021 or that their terms to us will be substantially less favorable than they have been historically. Due to the impact from the Chinese tariff starting in 2019, during 2020 we increasingly transferred production from our contract manufacturer in China to our contract manufacturer in Thailand. We plan to continue transferring production to our contract manufacturer in Thailand during 2021. +Patents and Proprietary Information +TransAct relies on a combination of trade secrets, patents, employee and third-party nondisclosure agreements, copyright laws and contractual rights to establish and protect its proprietary rights in its products. As of February 28, 2021, we hold 35 United States and 36 foreign patents and have 5 United States and 3 foreign patent applications pending pertaining to our products. The duration of these patents ranges from 1 to 19 years. The expiration of any individual patent would not have a significant negative impact on our business. We regard certain manufacturing processes and designs to be proprietary and attempt to protect them through employee and third-party nondisclosure agreements and similar means. It may be possible for unauthorized third parties to copy certain portions of our products or to reverse engineer or otherwise obtain and use, to our detriment, information that we regard as proprietary. Moreover, the laws of some foreign countries do not afford the same protection to our proprietary rights as do the laws of the United States. There can be no assurance that legal protections we rely upon to protect our proprietary position will be adequate or that our competitors will not independently develop technologies that are substantially equivalent or superior to our technologies. +Trademarks, Service Marks and Copyrights +We own or have rights to trademarks, service marks, trade names and copyrights that we use in connection with the operation of our business, including our corporate names, logos and website names. Other trademarks, service marks and trade names appearing in this Annual Report on Form 10-K are the property of their respective owners. The trademarks we own include TransAct®, BOHA! TM , AccuDate™, Epic, EPICENTRAL™, Ithaca® and Printrex®. Solely for convenience, some of the trademarks, service marks, trade names and copyrights referred to in this annual report on Form 10-K are listed without the ©, ® and ™ symbols, but we will assert, to the fullest extent under applicable law, our rights to our trademarks, service marks, trade names and copyrights. +Seasonality +Restaurants typically reduce purchases of equipment in the fourth quarter due to the increased volume of transactions during the holiday period, which may negatively impact sales of our food service technology products or POS printers. +Working Capital +Inventory, accounts receivable, and accounts payable levels, payment terms, and where applicable, return policies are in accordance with the general practices of the industry and standard business procedures. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. +5 +Certain Significant Customers +IGT is our most significant customer and has been since 1995. We sell both on-line lottery printers and casino and gaming printers to IGT. On May 29, 2015, we signed an agreement with IGT to sell on-line lottery and casino printers to IGT on a non-exclusive basis through December 31, 2019. We decided not to renew the agreement upon its expiration and to exit the on-line lottery market. Although we no longer have an agreement with IGT, we expect to continue selling casino and gaming printers to IGT, as well as spare parts for our remaining, but declining, installed base of lottery printers, in the future but no longer expect to sell on-line lottery printers beyond 2020. +Sales to IGT represented 15% and 14% of our total net sales for the years ended December 31, 2020 and 2019, respectively. +Backlog +Our backlog of firm orders was approximately $3.4 million as of February 28, 2021, compared to $5.7 million as of February 29, 2020. Based on customers’ current delivery requirements, we expect to fill and recognize as revenue $2.7 million of our current backlog during 2021, $0.4 million during 2022 and the remaining balance of the amount during 2023. +Competition +The market for transaction-based and specialty printers and food service technology terminals is extremely competitive, and we expect such competition to continue in the future. However, we experience less competition for EPICENTRAL TM software due to the highly customized nature of the product. We compete with a number of companies, many of which have greater financial, technical and marketing resources than TransAct. We believe our ability to compete successfully depends on a number of factors both within and outside our control, including durability, reliability, quality, design capability, product customization, price, customer support, success in developing new products, manufacturing expertise and capacity, supply of component parts and materials, strategic relationships with suppliers, the timing of new product introductions by us and our competitors, general market, economic and political conditions and, in some cases, the uniqueness of our products. +In the food service technology market, we primarily compete with Avery Dennison Corporation, Ecolab Inc., ITD Food Safety, CMC Daymark, Integrated Control Corp, Digi International, Squadle Inc., Jolt Software and Zenput. We compete in this market based largely on our ability to provide highly specialized software and purpose-built products and ongoing technical support. We rely upon third-party developed software and hosting services combined with our own proprietary hardware and software to offer a unique BOHA! branded solution to support back-of-house operations in the food service industry. Our competitors or others may develop, or may establish relationships with developers with the capability to develop, software and services that are similar to or competitive with ours, which may be disadvantageous to our competitive position. Certain portions of our food service technology software are licensed from a third-party developer on a non-exclusive basis through 2031 and are subject to a revenue sharing arrangement with the developer. We are reliant upon the third-party developer to further develop and maintain their developed software, and the developer controls the software source code. The license agreement does not preclude the developer from working with others on similar products. Also, the third party developer hosts the web-based applications. Therefore, presently, we are highly dependent upon this third-party developer for continued service to our customers and the further development of our food service technology software products. +In the POS automation market, we primarily compete with Epson America, Inc., which holds a dominant market position. We also compete, to a much lesser extent, with Star Micronics America, Inc. and Citizen -- CBM America Corporation. Certain competitors of ours have greater financial resources and lower costs attributable to higher volume production which enables them to occasionally offer lower prices than us. However, we will continue to deemphasize efforts in the POS automation market going forward as we have shifted our focus toward our higher-value, technology enabled food service technology and casino and gaming products. +In the casino and gaming market (consisting principally of slot machine printing, VLT transaction printing and promotional coupon printing), we compete with several companies including JCM Global, Nanoptix, Inc., Custom Engineering SPA, Eurocoin and others. Certain of our products sold for casino and gaming applications compete based upon our ability to provide highly specialized products, custom engineering and ongoing technical support. +In the lottery market (consisting principally of on-line lottery transaction printing), we competed with other lottery printer providers such as Custom Engineering SPA, Star Micronics and Wincor Nixdorf. However, we exited the lottery market in 2019 and shifted our focus toward our higher-value, technology enabled food service technology and casino and gaming products. +In the oil and gas market, our Printrex® products compete primarily with the products of Imaging Systems Group, Inc. and Neuralog Inc. We compete in this market based largely on our ability to provide specialized, custom-engineered products. +The market in which TSG competes is highly fragmented, and we compete with numerous competitors of various sizes, including POS and internet resellers and paper converters depending on the geographic area. +Our strategy for competing in our markets is to continually develop and/or license new products (hardware and software), such as our launch of BOHA! TM in 2019, and product line extensions that are technologically advanced and provide differentiated features and functions, to increase our market penetration, to take advantage of strategic relationships, and to lower the cost of our products by sourcing certain products overseas. Although we believe that our products, operations and relationships provide a competitive foundation, there can be no assurance that we will compete successfully in the future. In addition, our products utilize certain thermal printing technologies and licensed software. If new technologies are introduced, or existing technologies evolve, we may be required to incorporate these technologies into our products. Alternatively, if such technologies were to become available to our competitors, our products could become obsolete, which could have a significant negative impact on our business. +Environmental Compliance +Our compliance with federal, state and local laws and regulations relating to environmental protection and discharge of hazardous materials has not had a material impact on our capital expenditures, earnings or competitive position, and we do not anticipate any material impact from such compliance in the future. +6 +Available Information +We make available free of charge through the “Investor Relations” tab on our Internet website, www.transact-tech.com, our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and all amendments to those reports and statements as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC pursuant to Sections 13(a) or 15(d) of the Exchange Act. The SEC maintains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http;//www.sec.gov. The content on any website referred to in this Form 10-K is not incorporated by reference in this Form 10-K unless expressly noted. +Employees +As of December 31, 2020, TransAct and our subsidiaries employed 112 persons, all of whom were full-time employees. None of our employees are unionized, and we consider our relationships with our employees to be good. +Information about our Executive Officers +The following is a list of the names and ages of all executive officers of the registrant, indicating all positions and offices with the registrant held by each such person and each person’s principal occupations and employment during at least the past five years. +Name +Age +Position +Bart C. Shuldman +63 +Chairman of the Board and Chief Executive Officer +Steven A. DeMartino +51 +President, Chief Financial Officer, Treasurer and Secretary +Donald E. Brooks +68 +Senior Vice President, Engineering +Tracey S. Chernay +61 +Senior Vice President, Casino, Gaming and Lottery Sales +Andrew J. Hoffman +63 +Senior Vice President, Operations +David B. Peters +42 +Vice President and Chief Accounting Officer +Brent Richtsmeier +56 +Senior Vice President, Software Engineering +Raymond T. Walsh, Jr. +35 +Senior Vice President, Global Sales +Bart C. Shuldman has been Chief Executive Officer and a Director of the Company since its formation in June 1996. In February 2001, Mr. Shuldman was elected Chairman of the Board. Mr. Shuldman served as President of the Company from its formation until June 2010, when he relinquished the President title, to focus on new products and markets, international expansion and potential acquisitions. +Steven A. DeMartino was named as TransAct’s President, Chief Financial Officer, Treasurer and Secretary on June 1, 2010. Previously, Mr. DeMartino served as Executive Vice President, Chief Financial Officer, Treasurer and Secretary from June 2004 to May 2010, Senior Vice President, Finance and Information Technology from October 2001 to May 2004, Vice President and Corporate Controller from January 1998 to October 2001, and Corporate Controller from August 1996 to December 1997. Mr. DeMartino is a certified public accountant. +Donald E. Brooks was appointed Senior Vice President of Engineering in April 2012. Previously, Mr. Brooks served as Vice President, Engineering from September 2004 to April 2012, Senior Project Engineer from February 1998 to September 2004, Project Engineer from June 1997 to February 1998, Director of Electrical Engineering from March 1986 to June 1997 and Manager of Electronic Development from December 1983 to March 1986. +Tracey S. Chernay was appointed Senior Vice President, Casino and Gaming Sales and Marketing in June 2010, with responsibility for the sales and marketing of all casino and gaming products. Previously, Ms. Chernay served as Senior Vice President, Sales and Marketing from June 2007 to May 2010, Senior Vice President, Marketing and Sales, POS and Banking with the Company from July 2006 to June 2007, and joined TransAct in May of 2005 as Senior Vice President, Marketing. Prior to joining TransAct, Ms. Chernay was employed with Xerox Corporation where she held the role of Manager, Worldwide Marketing since 2003, and Manager, Sales Operations from 2000 to 2002. She joined Xerox Corporation in 1983. +Andrew J. Hoffman was appointed Senior Vice President, Operations for TransAct worldwide in November 2004. He served as Vice President, Operations from September 1994 to November 2004. +David B. Peters was appointed Vice President and Chief Accounting Officer on March 1, 2018. Previously, Mr. Peters served as Director, SEC and Financial Reporting since joining TransAct in March 2014. Prior to joining TransAct, Mr. Peters was employed with United Technologies Corporation from November 2006 to March 2014 where he served in various financial management positions. Mr. Peters is a certified public accountant. +Brent Richtsmeier was hired as Senior Vice President, Software Engineering on December 9, 2019 and appointed as an officer of the Company on January 11, 2021. Prior to joining TransAct, Mr. Richtsmeier was employed with Samsung as the VP of Development where he was responsible for software strategy, software development at scale and business development. +Raymond T. Walsh, Jr. was appointed Senior Vice President, Global Sales on February 27, 2019. Previously, Mr. Walsh served as Vice President, Global Sales since 2018. Mr. Walsh joined TransAct in 2006 and has held several sales positions of increasing responsibility with the Company. Prior to joining TransAct, Mr. Walsh served as the Senior Manager of Business Development at Nerac. +There are no family relationships between any of our executive officers and there is no arrangement or understanding between any of such officers and any other person pursuant to which he or she was selected as an officer. Each of our executive officers was elected by the Board of Directors to hold office until his or her successor is elected and qualified or until his or her earlier resignation or removal. +7 +Item 1A. Risk Factors +Investors should carefully consider the risks, uncertainties and other factors described below, as well as other disclosures in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, because they could have a material adverse effect on our business, financial condition, operating results, and growth prospects. The risks described below are not the only ones facing our Company. Additional risks and uncertainties not presently known to us, or that we currently believe to be immaterial, may also impair our business operations. In the event that such risks or uncertainties materialize, our business, financial condition, and results of operations could be materially adversely affected. +We assume no obligation (and specifically disclaim any such obligation) to update these Risk Factors or any other forward-looking statements contained in this Form 10-K to reflect actual results, changes in assumptions or other factors affecting such forward-looking statements, except as required by law. +Risks Related to our Business +We experienced a net loss in 2020, anticipate increasing expenses in the future, and we may not be able to achieve, maintain or increase profitability in the future. +We incurred a net loss of $5.6 million in 2020, we anticipate increasing expenses in the future, and we may not be able to achieve, maintain or increase profitability in the future. We expect our costs will increase over time and our losses to continue as we expect to invest significant additional funds towards growing our food service technology business and transitioning away from other lines of business. We have expended and expect to continue to expend substantial financial and other resources on developing our food service technology business, including expanding our offerings, developing or acquiring new products and services and increasing our sales and marketing efforts. These efforts may be more costly than we expect and may not result in increased revenue or growth in our food service technology business. Any failure to increase our revenue sufficiently to keep pace with our investments and other expenses could prevent us from achieving, maintaining or increasing profitability or positive cash flow on a consistent basis. If we are unable to successfully address these risks and challenges as we encounter them, our business, financial condition, and results of operations could be adversely affected. If we are unable to generate adequate revenue growth and manage our expenses, we may continue to incur significant losses in the future and may not be able to achieve, maintain or increase profitability +Our operating results and financial condition may fluctuate. +Our operating results and financial condition may fluctuate from quarter-to-quarter and year-to-year and are likely to continue to vary due to a number of factors, many of which are not within our control. If our operating results do not meet the expectations of securities analysts or investors, who may derive their expectations by extrapolating data from recent historical operating results, the market price of our common stock will likely decline. Fluctuations in our operating results and financial condition may be due to a number of factors, including, but not limited to, those identified throughout this “Risk Factors” section: +● +delays between our expenditures to develop and market new or enhanced products and consumables and the generation of sales from those products; +● +the geographic distribution of our sales and our supply chain; +● +market acceptance of our products, both domestically and internationally; +● +development of new competitive products by others; +● +our responses to price competition; +● +our level of research and development activities; +● +changes in the amount that we spend to develop, acquire or license new products, consumables, technologies or businesses; +● +changes in the amount we spend to promote our products and services; +● +changes in the cost of satisfying our warranty obligations and servicing our installed base of products; +● +availability of third-party components at reasonable prices; +● +general economic and industry conditions, including changes in interest rates affecting returns on cash balances and investments, that affect customer demand; +● +fluctuations of world-wide oil and gas prices; +● +the dependence of our supply chain on a few, foreign third-party manufacturers and suppliers; +● +severe weather events, public health crises, and other external events out of our control that can disrupt our operations or the operations of our customers’ or suppliers’ facilities; and +● +changes in accounting rules. +Due to all of the foregoing factors, and the other risks discussed in this Form 10-K, quarter-to-quarter comparisons of our operating results may not be an indicator of future performance. +8 +The COVID-19 pandemic has had, and is likely to continue to have, an adverse impact on our business, operations, financial condition, results of operations and capital resources, as well as on the operations and financial performance of many of our suppliers and customers. We are unable to predict the ultimate extent to which the pandemic and related effects will adversely impact our business, operations, financial condition, results of operations, capital resources and the achievement of our strategic objectives. +As a result of the COVID-19 pandemic and the numerous disease control measures being taken to limit the spread of COVID-19, we have experienced, and can be expected to continue to experience, disruptions to our business, our operations, the delivery of our products and customer demand for our products, including the following: +● +operating losses in excess of those we anticipated in transitioning our business focus toward the food service technology market, which, in addition to the factors discussed below, may require us to seek to obtain additional capital through debt or equity financings or other arrangements to fund operations, or if such arrangements are not available, to take additional significant cost-cutting measures ; +● +supply chain disruptions, including delayed product shipments from two contract manufacturers located in China and Thailand that conduct substantially all of our printer and terminal manufacturing, which, if sustained, could lead to insufficient inventory levels and harm our ability to deliver products to our customers on time or at all ; +● +continuing or new restrictions on the operations of our customers in the casino industry and food service industry, including, in some cases, partial or complete business shutdowns, which have resulted in, and are likely to continue to result in, reduced demand for our products in the two primary markets that we serve ; +● +an inability of our customers to make payments in a timely fashion or at all, which may continue even after operating restrictions are lifted in the event that the downturn in economic conditions persist ; +● +devotion of significant time, management attention and resources to monitoring the COVID-19 pandemic and its impacts, and anticipated impacts, on our business, and seeking to mitigate the effects of the pandemic on our business and workforce, which diverts management’s attention and resources away from strategic initiatives, new business opportunities, the transition of our business toward the food service and casino and gaming markets, and the overall profitability of our business ; +● +necessary modifications to our business practices and operations, including suspension of employee travel, cancellation of physical participation in meetings, events and conferences and social distancing measures, including work-from-home policies, and such further actions as may be required by government authorities or that we determine are in the best interests of our employees, customers and suppliers, which may adversely impact efficiency and productivity and may increase operational risks, including cybersecurity risks, and have affected the way that we conduct our product development, marketing, customer support and other activities ; +● +a permanent reduction in workforce, furlough of workers and an across-the-board 10% salary reduction, as well as other cost-cutting measures we have taken to help mitigate the impact of the COVID-19 crisis on our business, which may, along with any additional such measures that may be taken in the future, impair our ability to operate and have a negative effect on employee loyalty and our reputation and, if furloughed employees do not return following the crisis, or if employees seek higher-paying jobs, may limit our ability to restart operations following the crisis and to grow our food service technology business as planned ; +● +a possible future reduction in the value of goodwill or other intangible assets causing the carrying value of such assets to exceed their fair value, which could require us to recognize asset impairment ; +● +difficulty predicting our manufacturing requirements accurately due to volatile economic conditions and uncertainty as to when our customers may resume operations, which could result, in the case of an underestimate, in inadequate manufacturing capacity or inventory, interruptions in production and delayed deliveries to customers (with resulting losses in orders or customers lowering our net sales), or in the case of an overestimate, in an excess inventory of component parts or manufactured products ; +● +increases in prices and/or decreases in availability of component parts and raw materials needed to produce our products ; +● +foreign exchange rate fluctuations due to volatile global economic conditions, which could negatively affect earnings and the value of our assets held outside the United States, and if we increase prices to absorb a portion of the currency impact, could cause demand to decrease ; +● +volatility of, and decreases in, trading prices of our common stock ; and +● +t he possibility that we may need to raise additional capital through an equity or debt financing to support operations but are unable to do so due to, among other things, global economic conditions, conditions in the global financing markets, trading prices of our common stock and the outlook for the industries that we serve, all of which could be negatively impacted by the COVID-19 pandemic, such that there can be no assurance that such financing would be available to us. +If we issue equity or debt securities to raise additional funding, our existing shareholders may experience dilution and we may incur significant financing costs. If we issue debt securities or otherwise incur additional debt, we would have additional debt service obligations, could become subject to additional restrictions limiting our ability to operate our business, and may be required to further encumber our assets. +The COVID-19 pandemic continues to evolve rapidly, and additional material impacts and disruptions may occur. The factors described above, which may worsen, have had and, along with other factors that we cannot predict, can be expected to continue to have, a material adverse impact on our business, operations, financial condition, results of operations and capital resources. The ultimate impact of the COVID-19 pandemic on the Company is highly uncertain and subject to change and will depend on future developments, which cannot be accurately predicted, including the duration of the pandemic, additional or modified government actions, new information that may emerge concerning the severity and impact of the COVID-19 pandemic, newly identified strains of COVID-19, the rollout and effectiveness of vaccines and treatments and the actions taken to contain COVID-19 or address its impact in the short and long term, among others. We do not yet know and cannot predict the full extent of potential impacts on our business, operations, financial condition, results of operations and capital resources. +In addition, any of the risks and uncertainties set forth in this Form 10-K can be expected to be further heightened by the COVID-19 pandemic and have a material adverse effect on the Company’s business, prospects, financial condition, results of operations and capital resources and the achievement of our strategic objectives +9 +Our revenue and profitability depend on our ability to continue to develop or license, on a timely basis, new products and technologies which are free from hardware or software anomalies and cannot be fraudulently manipulated, and customer acceptance of such products. +Our success depends upon our and our development partners’ ability to timely adapt our capabilities and processes to meet the demands of producing new and innovative products. Because our newer products contain software and generally are more technologically sophisticated than those we have produced in the past, we must continually refine our capabilities to meet the needs of our product innovation. If we cannot efficiently adapt our infrastructure to meet the needs of our product innovations in a timely manner, our business could be negatively impacted. +In addition, even if we, or developers on our behalf, successfully develop such products, there is no assurance that our innovations will be accepted by our customers. Developing and marketing new products, such as our BOHA! ecosystem, is costly, and our business could be materially adversely affected if we are unable to generate sales of such products or if our existing or new customers do not quickly accept such products. Customer acceptance is crucial because new products typically have very little competition and market penetration due to their novelty. Although we develop new products with the input of our customers, which has contributed to the early success of BOHA!, customer acceptance is never assured and may take time to materialize. Further, technological innovation often results in unintended consequences such as bugs, vulnerabilities, and other system failures. Any such bug, vulnerability, or failure, especially in connection with a significant technical implementation or change, could result in lost business, harm to our brand or reputation, consumer complaints, and other adverse consequences, any of which could materially adversely affect our business, results of operations, and financial condition. +We rely on an unrelated third party to develop, maintain and host certain portions of our food service technology software, and any disruption in the relationship with that third party, or any defects in the software provided by that third party, could have a material adverse effect on our reputation, business, financial condition and results of operations. +We rely upon third-party developed software and hosting services combined with our own proprietary hardware and software to offer our unique BOHA! branded solution to support back-of-house operations in the food service industry. Certain web-based food service application software and selected components of our downloadable software applications are licensed from a third-party developer on a non-exclusive basis through 2031 and are subject to a revenue sharing arrangement with the developer. We are reliant upon the third-party developer to further develop and maintain their developed software, and the developer controls the software source code. Therefore, presently, we are highly dependent on this third-party developer for continued service to our customers and the further development of our food service technology software products. If the software provider were to terminate operations or otherwise be unavailable to provide maintenance, hosting and development services to us and our customers, the availability or usage of our software products could be disrupted and our customers could be adversely affected. In any such case, we may need to seek comparable software and services from other third parties or develop it internally, which could require significant time and expense. There can be no assurance that such software or services would be available from other sources, or that if available, it would be of comparable quality and cost. Moreover, any efforts to develop new software, whether internal or by third parties, would require significant lead time, and there could be an interruption in service during any period in which the software provider ceases to provide products and services and new products remain under development. Any such occurrence could materially and adversely impact our business, financial condition and results of operations. +Any errors or defects in, or failures of, third-party software or applications could result in errors or defects in or failures of our food service technology products and services, which could be costly to correct and have a material adverse effect on our reputation, business, financial condition and results of operations +We compete in highly competitive markets, which are likely to become more competitive. Competitors may be able to respond more quickly to new or emerging technology and changes in customer requirements. +We face significant competition in developing and selling our printers, terminals, software, consumables and services. Our principal competitors have substantial marketing, financial, development and personnel resources. To remain competitive, we believe we must continue to provide: +● +technologically advanced products that satisfy the user demands; +● +superior customer service; +● +high levels of quality and reliability; and +● +dependable and efficient distribution networks. +We cannot ensure we will be able to compete successfully against current or future competitors. Increased competition may result in price reductions, lower gross profit margins and loss of market share, and could require increased spending on research and development, sales and marketing and customer support. Some competitors may make strategic acquisitions or establish cooperative relationships with suppliers or companies that produce complementary products, which may include relationships with our software developer. Any of these factors could reduce our earnings. +Our success will depend on our ability to sustain and manage growth. +As part of our business strategy, we intend to pursue a growth strategy. Assuming this growth occurs, it will require the expansion of customer relationships in international markets, the successful development and marketing of new products for our existing and new markets, expanded internal sales and marketing, customer service and support, and the continued implementation and improvement of our operational, financial and management information systems. +To the extent that we seek growth through acquisitions, our ability to manage our growth will also depend on our ability to integrate businesses that have previously operated independently. We may not be able to achieve this integration without encountering difficulties or experiencing the loss of key employees, customers or suppliers. It may be difficult to design and implement effective financial controls for combined operations and differences in existing controls for each business may result in weaknesses that require remediation when the financial controls and reporting functions are combined. As we pursue acquisitions, we may incur legal, accounting and other transaction related expenses for unsuccessful acquisition attempts that could adversely affect our results of operations in the period in which they are incurred. +There can be no assurance that we will be able to successfully implement our growth strategy, or that we can successfully manage expanded operations, if they occur. As we expand, we may from time to time experience constraints that will adversely affect our ability to satisfy customer demand in a timely fashion. Failure to manage growth effectively could adversely affect our results of operations and financial condition. +10 +Material weaknesses in our internal control over financial reporting have been identified, and if we are unable to implement and maintain effective internal control over financial reporting, or our independent registered public accounting firm is unable to provide an unqualified report thereon, we could be materially adversely affected. +Material weaknesses in our internal control over financial reporting existed as of December 31, 2018 and 2019 regarding our internal controls over user access to ensure appropriate segregation of duties and to adequately restrict user access to appropriate personnel. Specifically, the provisioning and user recertification controls are not designed to ensure users maintain proper segregation of duties and therefore could have inappropriate access rights. Additionally, we identified a material weakness in controls over key spreadsheets supporting our accounting records as of December 2018 and 2019. Specifically, we did not design adequate controls to address the completeness and accuracy of information included in key spreadsheets. During 2020, we remediated the material weakness related to the provisioning and user recertification controls, but the material weakness related to key spreadsheets still exists as of December 31, 2020. As a result of the remaining key spreadsheet material weaknesses, management concluded that our internal control over financial reporting was not effective as of December 31, 2020. +Unless and until the material weakness has been remediated or should new material weaknesses arise or be discovered in the future, a material misstatement could occur and go undetected in our interim or annual consolidated financial statements. As a result, we may experience delays in fulfilling our reporting obligations or complying with federal securities laws, which could result in investigations and sanctions by regulatory authorities, including, but not limited to, the SEC, and may result in defaults or accelerations under our credit facility in the event that we are unable to timely file reports with the SEC, to the extent that in such an event, we are unable to obtain waivers from our lender. Any of these results could adversely affect our business and the value of our common stock. +We are dependent on sales to one large customer; the loss of this customer or reduction in orders from this customer could materially affect our sales. +Casino and gaming sales and lottery spare part sales to IGT represent a material percentage of our net sales. A reduction, delay or cancellation in orders from this customer, including reductions or delays due to market, economic, or competitive conditions in the industries in which we serve, could have a material adverse effect upon our results of operations. +General economic conditions could have a material adverse effect on our business, operating results and financial condition. +Our business is subject to general economic conditions. Uncertainty or negative trends in U.S. or international economic and investment climates, including the impact of Brexit and recent developments in U.S.-China trade relations (discussed separately below), could adversely affect our business. For example, customers or potential customers could reduce or delay orders, key suppliers could become insolvent, which could result in production delays, and our customers may become insolvent or be unable to obtain credit. Any of these possible effects could impact our ability to effectively manage inventory levels and collect receivables, create unabsorbed costs due to lower net sales, and ultimately decrease our net sales and profitability including write-downs of assets. +Fluctuations in oil and gas prices could adversely affect drilling and exploration activities by oil and gas companies and our revenue in our Printrex market. If oil and gas prices remain volatile, or if oil or gas prices decline, the demand for our Printrex products could be adversely affected. +The demand for our Printrex products depends on the level of spending by oil and gas companies for drilling and exploratory activities, which are affected by short-term and long-term trends in oil and gas prices, including current and anticipated oil and gas prices. Oil and gas prices, as well as the level of drilling and exploration, historically have been extremely volatile and are expected to continue to be highly volatile. Further, oil prices may be impacted by continuing political and social attention to the issue of climate change, state regulation of greenhouse gas emissions, and executive orders, regulatory actions and/or legislation that the current presidential administration may pursue in furtherance of its stated priority to address climate change. If oil and gas prices decline, or if there is a reduction in drilling and exploration activities, the demand for our Printrex products could be materially and adversely affected. +If market conditions deteriorate or future results of operations are less than expected, a valuation allowance may be required for all or a portion of our deferred tax assets. +We currently have deferred tax assets, which may be used to reduce taxable income in the future. We assess the realization of these deferred tax assets on a quarterly basis, and if we determine that it is more likely than not that some portion of these assets will not be realized, an income tax valuation allowance is recorded. If market conditions deteriorate or future results of operations are less than expected, or there is a change to applicable tax rules, future assessments may result in a determination that it is more likely than not that some or all of our net deferred tax assets are not realizable. As a result, we may need to establish a valuation allowance for all or a portion of our net deferred tax assets, which may have a material adverse effect on our business, results of operations and financial condition. +We rely on distributors and resellers to sell our products and services. +We use a variety of distribution channels, including OEMs and distributors, to market and sell our products and services. We may be adversely impacted by any conflicts that could arise between and among our various sales channels. +Our dependence upon distributors and resellers exposes us to numerous risks, including: +● +loss of channel and the ability to bring new products to market; +● +concentration of credit risk, including disruption in distribution should the distributors and / or resellers’ financial condition deteriorate; +● +reduced visibility to end user demand and pricing issues which makes forecasting more difficult; +● +distributors or resellers leveraging their buying power to change the terms of pricing, payment and product delivery schedules; and +● +direct competition should a distributor or reseller decide to manufacture printers internally or source printers from a competitor. +We cannot guarantee that resellers will not reduce, delay or eliminate purchases from us, which could have a material adverse effect upon the business, consolidated results of operations and financial condition. +11 +We are dependent upon two manufacturers located in China and Thailand for the manufacturing and assembly of our printers and terminals, and their operations were disrupted by the outbreak of COVID-19. The disruption adversely affected the Company’s business, financial conditions and results of operations, and any further or future disruption in their businesses or operations, such as those caused by political, social or economic instability, trade restrictions or tariffs, severe weather, additional public health crises and other events out of our control, could materially adversely affect our business, financial condition and results of operations. +In an effort to achieve additional cost savings and operation benefits, we have outsourced substantially all of the manufacturing and assembly of our printers and terminals to two contract manufacturers located in China and Thailand. As a result, we are dependent on them for the manufacturing of our products, and any disruption in such manufacturing or the export of products from these manufacturers to the U.S. may adversely affect our business, financial condition and results of operations. +Risks affecting the businesses and operations of our two manufacturers in Asia include: political and regional strife; war; labor shortages; severe weather and natural disasters such as earthquakes, hurricanes, fires, and floods; lengthy power outages; increased pricing, financial instability and capacity constraints of shippers; and concerns with or threats of public health crises, contagious diseases or health epidemics. The risk to our business posed by any disruption in manufacturing is exacerbated by the concentration of our manufacturing operations in two manufacturers both located in Asia. +In response to COVID-19, the Chinese government placed restrictions on travel and mandated business closures. Such restrictions and closures disrupted our supply chain by delaying product shipments from our contract manufacturers during 2020. +The ultimate impact of COVID-19 on our operations will depend on future developments, which are highly uncertain and cannot be predicted with confidence, including the duration of the outbreak and any resurgences, new information which may emerge concerning the severity of COVID-19 and newly identified strains, the rollout and effectiveness of vaccines and treatments and the actions to contain the virus or treat its impact, among others. Without the contract manufacturers continuing to manufacture our products and the continuing operation of the contract manufacturers’ facilities, we will have limited means for the final assembly of a majority of our products until we are able to secure the manufacturing capability at another facility or develop an alternative manufacturing facility, which could be costly and time consuming and have a material adverse effect on our operating and financial results. +We may also incur increased business continuity and reputational risks to the extent that we continue to outsource the manufacturing and assembly of our products to foreign third-party service providers. For example, outsourcing of manufacturing prevents us from exercising control over the assembly of certain of our products and related operations or processes, including the internal controls associated with operations and processes conducted and the quality of our products assembled by contract manufacturers. If we are unable to effectively manage and oversee our outsourcing strategy, we may not realize cost structure efficiencies and our operating and financial results could be materially adversely affected. Outsourcing also exposes us to increased risk of infringement or misappropriation of our intellectual property, to which our manufacturers have access. Because our manufacturers are located in Asia, there is no guarantee that our intellectual property rights will be protected or enforced to the same extent as under U.S. federal and state laws. Consequently, we may not be able to prevent third-parties from developing or selling products made using our technologies. +Overestimates or underestimates in our manufacturing forecasts could cause us to hold excess inventory or result in delays in the manufacturing and delivery of our products, which could cause us to lose orders or customers. +If we fail to predict our manufacturing requirements accurately, we could incur additional costs or experience manufacturing delays, which could cause us to lose orders or customers and result in lower net sales. We currently use a rolling 12-month forecast based primarily on our anticipated product orders and our product order history to help determine our requirements for components and materials. It is very important that we accurately predict both the demand for our products and the lead-time required to obtain the necessary components and raw materials. +Lead times for materials and components that we order vary significantly and depend on factors such as the specific supplier, the size of the order, contract terms, and demand for each component at a given time. If we underestimate our requirements, we may have inadequate manufacturing capacity or inventory, which could interrupt manufacturing of our products and result in delays in shipments and net sales. If we overestimate our requirements, we could have excess inventory of parts and finished products. In addition, delays in the manufacturing of our products could cause us to lose orders or customers. +We purchase component parts and consumable products from third-party and sole source suppliers, and any interference with this supply chain may impact our ability to manufacture and sell our products. +We rely on third-party or sole source suppliers to provide certain key components for our products including BOHA! labels. We do not have guaranteed supply contracts with any of our component suppliers, and our suppliers could delay shipments, increase prices or cease manufacturing or selling such components to us at any time. A disruption in the supply of such component parts and consumable products could delay our production and/or the release of our new products and hinder our ability to meet our commitments to customers. If we are unable to obtain a sufficient quantity of these components on commercially reasonable terms or in a timely manner, or if we are unable to obtain alternative sources for the components, sales of our products could be delayed or halted entirely or we may be required to redesign our products. Any of these events could result in lost sales, reduced gross margins or damage to our end-customer relationships, which would have a material adverse effect on our operations and financial results. +In addition to maintaining offices in the UK and Macau, we sell and ship a significant portion of our products internationally and rely on third parties that make up our global salesforce. The international nature of our operations may expose us to certain risks associated with doing business outside of the U.S., including risks posed by the UK’s withdrawal from the European Union, tariffs, and changes in trade relations. +We sell a significant amount of our products to customers outside the United States. Shipments to international customers are expected to continue to account for a material portion of net sales. In addition, our manufacturers and suppliers are largely located in Asia. As a result, our products are largely exported to one of our facilities in the United States, which makes our operations vulnerable to disruptions in trade that could adversely affect our business results. +12 +Our international operations, including our reliance on manufacturers and suppliers located in Asia, our worldwide sales team, and our sales to customers located outside the United States, expose us to disruptions in trade and other associated risks such as: +● +the imposition of additional duties, tariffs, quotas, taxes, trade barriers, capital flow restrictions and other charges on imports and exports by the United States or the governments of the countries in which we or our manufacturers and suppliers operate; +● +delays in the delivery of cargo due to port security considerations, labor disputes such as dock strikes, and our reliance on a limited number of shipping and air carriers, which may experience capacity issues that adversely affect our ability to ship inventory in a timely manner or for an acceptable cost; +● +fluctuations in the value of the U.S. Dollar against foreign currencies, which could restrict sales, or increase costs of purchasing, in foreign countries; +● +economic or political instability in any of the countries in which we or our manufacturers or suppliers operate, which could result in a reduction in demand for our products due to political and economic instability or impair our foreign assets; +● +a reduced ability or inability to sell in or purchase from certain markets as a result of export or import restrictions; +● +potentially limited intellectual property protection in certain countries, such as China, may limit recourse against infringing products or cause us to refrain from selling in certain geographic territories; +● +reliance on a limited number of shipping and air carriers who may experience capacity issues that adversely affect our ability to ship inventory in a timely manner or for an acceptable cost; and +● +economic uncertainties and adverse economic conditions (including inflation and recession). +Although we carry business interruption insurance to cover lost revenue and profits in an amount we consider adequate, this insurance does not cover all possible situations. In addition, the business interruption insurance would not compensate us for the loss of opportunity and potential adverse impact, both short-term and long-term, on relations with our existing customers resulting from our inability to produce products for them. +Our business could be adversely affected by actual or threatened terrorist attacks or the related heightened security measures, military actions and other efforts to combat terrorism. +Our business could be adversely affected by actual or threatened terrorist attacks or the related heightened security measures, military actions and other efforts to combat terrorism. It is possible that terrorist attacks could be directed at important locations for the gaming industry. Heightened security measures and other efforts to combat terrorism may also have an adverse effect on the gaming industry by reducing tourism. Any of these developments could also negatively affect the general economy and consumer confidence. Any downturn in the economy in general, or in the gaming industry in particular could result in a reduced demand for our products and could adversely affect our business and results of operations. In addition, heightened security measures may cause certain governments to restrict the import or export of goods, which may have an adverse effect on our ability to buy and sell goods. +We depend on key personnel, the loss of which could materially impact our business. +Our future success will depend in significant part upon the continued service of certain key management and other personnel and our continuing ability to attract and retain highly qualified managerial, technical and sales and marketing personnel. There can be no assurance that we will be able to recruit and retain such personnel. The loss of either Bart C. Shuldman, the Company’s Chairman of the Board and Chief Executive Officer, or Steven A. DeMartino, the Company’s President, Chief Financial Officer, Treasurer and Secretary, or the loss of certain groups of key employees, could have a material adverse effect on our results of operations. +The inability to protect our intellectual property rights could harm our reputation, damage our business or interfere with our competitive position, and infringement on the intellectual property rights of others, or claims thereof, could put us at a competitive disadvantage, and any related litigation could be time consuming and costly. +Our intellectual property is valuable and provides us with certain competitive advantages. Copyrights, patents, trademarks, service marks, trade secrets, technology licensing agreements, nondisclosure agreements and contracts are used to protect these proprietary rights. Despite these precautions, it may be possible for third parties to copy aspects of our products or, without authorization, to obtain and use information which we regard as trade secrets. +In addition, prosecuting and defending infringement lawsuits is very expensive. We are committed to aggressively asserting and defending our technology and related intellectual property rights, which we have spent a significant amount of money to develop. Similarly, third-parties may claim, from time to time, that we have violated their intellectual property rights. To the extent of a violation of a third-party’s patent or other intellectual property right, we may be prevented from operating our business as planned and may be required to pay damages, to obtain a license, if available, or to use a non-infringing method, if possible, to accomplish our objectives. Any such claims could result in costly litigation and, if successful, could result in costly judgments or settlements. +The expense of prosecuting or defending any future infringement lawsuits could have a material adverse effect on our business, financial condition and results of operations. Intellectual property litigation is generally complex, costly, protracted, and highly disruptive to business operations by diverting the attention and energies of management and key technical personnel. +13 +We currently rely on third-party service providers to host our food service technology software and deliver certain services, and any interruptions or delays in services from these third parties could impair the delivery of our products and services, and our business, results of operations, and financial condition could be materially adversely affected. +We rely on a third-party service provider to host our food service technology software. Third parties also provide services to key aspects of our operations, including Internet connections and networking, data storage and processing, trust and safety and security infrastructure. We do not control the operation, physical security, or data security of any of these third-party providers. Our efforts to use commercially reasonable diligence in the selection and retention of such third-party providers may be insufficient or inadequate to prevent or remediate such operational and security risks. Our third-party providers may be subject to intrusions, computer viruses, denial-of-service attacks, sabotage, acts of vandalism, acts of terrorism or other misconduct. They are vulnerable to damage or interruption from power loss, telecommunications failures, fires, floods, earthquakes, hurricanes, tornadoes, and similar events, and they may be subject to financial, legal, regulatory, and labor issues, each of which may impose additional costs or requirements on us or prevent these third parties from providing services to us or our customers on our behalf. In addition, these third parties may breach their agreements with us, disagree with our interpretation of contract terms or applicable laws and regulations, refuse to continue or renew these agreements on commercially reasonable terms or at all, fail to or refuse to process transactions or provide other services adequately, take actions that degrade the functionality of our platform and services, increase prices, impose additional costs or requirements on us or our customers, or give preferential treatment to our competitors. If we are unable to procure alternatives in a timely and efficient manner and on acceptable terms, or at all, we may be subject to business disruptions, losses, or costs to remediate any of these deficiencies. The occurrence of any of the above events could result in reputational damage, legal or regulatory proceedings, loss of customers or other adverse consequences, any of which could materially adversely affect our business, results of operations, and financial condition. +Our food service technology business depends substantially on our customers renewing their subscriptions with the Company. Any decline in our customer renewals would harm our food service technology business, results of operations and financial condition. +Our subscription offerings are term-based, and in order for us to maintain or improve our results of operations, it is important that our customers renew their subscriptions with us when the existing subscription term expires and renew on the same or more favorable quantity and terms. Our customers have no obligation to renew their subscriptions and we may not be able to accurately predict customer renewal rates. Customers may elect not to renew their subscriptions with us for a variety of reasons, including as a result of changes in their strategic priorities, budgets and costs and, in some instances, due to competing solutions. Our retention rate may also decline or fluctuate as a result of a number of other factors, including our customers’ satisfaction or dissatisfaction with our solutions, the increase in the contract value of subscription and support contracts from new customers, the effectiveness of our customer support services, our pricing, the prices of competing products or services, global economic conditions and the other risk factors described herein. As a result, there can be no assurance that our food service technology customers will renew subscriptions. If our customers do not renew their subscriptions or renew on less favorable terms, our business, results of operations and financial condition may be adversely affected. +If we fail to offer high quality support, our business and reputation could suffer. +Our customers rely on us and our third-party service providers for support of our software and services included in our food service technology subscription packages. High-quality support is important for the renewal and expansion of our agreements with existing customers. The importance of high-quality support will increase as we expand our business and pursue new customers. If we or our third-party service providers do not help our customers quickly resolve issues and provide effective ongoing support, our ability to sell new food service technology products to existing and new customers could suffer and our reputation and relationships with existing or potential customers could be harmed. +Cyber-security and privacy breaches, cyber-attacks, or other disruptions could expose us to liability, affect our business, and damage our reputation. +We are increasingly dependent on our information technology systems and infrastructure for our business. We collect, store, and transmit sensitive information including intellectual property, proprietary business information and personal information in connection with business operations. The secure maintenance of this information is critical to our operations and business strategy. Some of this information could be an attractive target of criminal attack by third parties with a wide range of motives and expertise, including organized criminal groups, disgruntled current or former employees, and others. Cyber-attacks are of ever-increasing levels of sophistication, and despite our extensive security measures, our information technology and infrastructure may be vulnerable to such attacks or may be breached, including due to employee error or malfeasance. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. If our systems become compromised, we may not promptly discover the intrusion. Like other companies in our industry, we have experienced attacks to our data and systems, including malware and computer viruses that we have been able to detect and eliminate. If our systems fail or are breached or disrupted, we could lose product sales, and suffer reputational damage and loss of customer confidence. Such incidents would require notification to affected individuals and may result in legal claims or proceedings and liability under federal and state laws that protect the privacy and security of personal information. Any one of these events could cause our business to be materially harmed and our results of operations to be adversely impacted. +We cannot provide any assurance that current laws, or any laws enacted in the future, will not have a material adverse effect on our business. +Our operations are subject to laws, rules, regulations, including environmental regulations, government policies and other requirements in each of the jurisdictions in which we conduct business. Changes in such laws, rules, regulations, policies or requirements could result in the need to modify our products and could affect the demand for our products, which may have an adverse impact on our future operating results. If we do not comply with applicable laws, rules and regulations we could be subject to costs and liabilities and our business may be adversely impacted. +14 +Risks Related to our Indebtedness +The agreement governing our credit facility contains restrictions and limitations that could significantly affect our ability to operate our business, as well as significantly affect our liquidity. +The loan and security agreement (the “Loan Agreement”) governing the Siena Credit Facility contains a number of significant covenants that could adversely affect our ability to operate our business, our liquidity, and our results of operations. These covenants restrict, among other things, our ability, and the ability of any future domestic subsidiary, to: +● +merge, consolidate, form subsidiaries or dispose of assets; +● +acquire assets outside the ordinary course of business ; +● +e nter into other transactions outside the ordinary course of busines s; +● +sell, transfer, return or dispose of collateral; +● +make loans to or investments in, or enter into transactions with, affiliates ; +● +incur or guarantee indebtedness, incur liens ; +● +redeem equity interests while borrowings are outstanding under the credit facility ; +● +change our capital structure; or ; +● +dissolve, divide, change our line of business or cease or suffer a disruption to all or a material portion of our business . +Additionally, the Loan Agreement requires us to comply with a minimum EBITDA covenant, the amount of which is based on financial forecasts provided to the lender. The breach of any covenants or obligations in the Loan Agreement, if not otherwise waived or amended, could result in a default under the Loan Agreement and could trigger acceleration of our obligations thereunder and permit the lender to foreclose on the collateral securing our obligations under the Loan Agreement and exercise other rights of secured creditors. +Availability under the Siena Credit Facility is subject to a borrowing base, which is based on eligible accounts receivable and inventory. To the extent that our eligible accounts receivable and inventory decline in value, our borrowing base will decrease, and the availability under the Siena Credit Facility currently is and may continue to be less than its stated amount and may decrease. In addition, if at any time the amount of outstanding borrowings and letters of credit under that facility exceeds the borrowing base, we are required to prepay borrowings and/or cash collateralize letters of credit sufficient to eliminate the excess. +Our ability to comply with the covenants under the Loan Agreement or to maintain our borrowing base may be affected by events beyond our control, including deteriorating economic conditions and consequences of the COVID-19 crisis. For example, the minimum EBITDA covenant, as applicable to periods through March 31, 2021, is based on financial projections prepared before most COVID-19-related operating restrictions were put in place in the United States, and our actual EBITDA for any of those periods may be substantially less than projected in such forecasts. In such event, we may not be able to comply with the covenant. In addition, reductions in the value of accounts receivable and inventory have occurred and are likely to continue to occur due to decreases in sales and production that have occurred as a result of the COVID-19 pandemic. Further, certain slow-moving inventory and accounts receivable that remain unpaid for a specified period of time are excluded from the borrowing base calculation. Thus, a decline in economic conditions and/or a decline in the financial condition of customers in the industries we serve, such as the decline that has occurred in the casino and food service industries in connection with the COVID-19 pandemic, has impacted and may continue to negatively impact the borrowing base both by decreasing the value of existing accounts and reducing the number and amount of new accounts. If we overestimate our inventory needs due to the uncertainty surrounding the COVID-19 pandemic and the duration of its impact on customer closures and economic conditions, we may have inventory that is considered slow-moving and thus excluded from the borrowing base calculation, and any reduction in production in response to decreased demand would also result in a lower inventory value and thus a lower borrowing base. +Any of these events could require us to seek waivers or amendments of covenants or alternative sources of financing or to reduce expenditures. We cannot assure you that such waivers, amendments or alternative financing could be obtained, or if obtained, would be on terms acceptable to us, or that we would be able to reduce expenditures enough to offset any decrease in the borrowing base, or that we could make such reductions without a material negative impact on our business. +We may not be entitled to forgiveness of our PPP Loan. +On May 1, 2020, the Company was granted the $2.2 million PPP Loan. The PPP Loan is unsecured and is evidenced by a note a dated the Loan Date (the “Note”) issued by the Company in favor of Berkshire Bank, as the lender (the “PPP Lender”). The Note has a two-year term. The PPP provides for forgiveness of up to the full amount borrowed as long as the Company uses the loan proceeds during the covered period following disbursement for eligible purposes as described in the CARES Act and related guidance. Under the CARES Act, loan forgiveness is generally available to the extent the PPP Loan was used, during the covered period, for payroll costs and costs to continue group health care benefits, as well as for interest on mortgage obligations incurred before February 15, 2020, rent under lease agreements in effect before February 15, 2020, utilities for which service began before February 15, 2020, and interest on debt obligations incurred before February 15, 2020 (“qualifying expenses”), subject to conditions and limitations provided in the CARES Act . We maximized usage of the proceeds from the PPP Loan for qualifying expenses during the applicable period. As of the date of this filing, we have not yet submitted an application for forgiveness. +Under the revised rules for the PPP, if we submit a forgiveness application within 10 months after the end of the covered period, we will not have to begin principal and interest payments before the date on which the SBA remits the loan forgiveness amount to the PPP Lender (or notifies the PPP Lender that no loan forgiveness is allowed). If no loan forgiveness is allowed, the Company will be required to pay the PPP Lender equal monthly payments of principal and interest based on the principal amount outstanding on the PPP Loan, plus interest outstanding at the end of the deferment period, and taking into account any reductions in the principal amount due to forgiveness, if any. We cannot provide any assurance that we will be eligible for loan forgiveness or that any amount of the PPP Loan will ultimately be forgiven by the SBA. +15 +General Risk Factors +Our stock price may fluctuate significantly. +The market price of our common stock could fluctuate significantly in response to variations in quarterly operating results and other factors, such as: +● +prevailing domestic and international market and economic conditions, and conditions in the industries we serve, including current market volatility and the economic impact of COVID-19 and resulting shutdowns on the casino and food service industries and on the U.S. and global economies ; +● +adverse business conditions faced by customers, or bankruptcies or store closures of our customers resulting from adverse economic conditions due to COVID-19 or otherwise; +● +changes in our business, operations or prospects; +● +developments in our relationships with our customers or strategic partners; +● +announcements of new products or services by us or by our competitors; +● +announcement or completion of acquisitions by us or by our competitors; +● +changes in existing or adoption of additional government regulations; and +● +unfavorable or reduced analyst coverage. +In addition, the stock market may experience significant price fluctuations year-to-year. Broad market fluctuations, general economic conditions and specific conditions in the industries in which we operate may adversely affect the market price of our common stock. +Limited trading volume and a reduction in analyst coverage of our common stock may contribute to its price volatility. +The limited trading volume of our common stock may contribute to its price volatility. The trading market for our common stock also relies in part on the research and reports that industry or financial analysts may publish about us, our business, our markets and our competitors. We currently have limited analyst coverage. If securities analysts do not cover our common stock in the future, the lack of research coverage may adversely affect the market price of our common stock. Furthermore, if one or more of the analysts who cover us downgrade our stock, or if those analysts issue other unfavorable commentary about us or our business, our stock price may decline. +Our common stock is traded on the Nasdaq Global Market. During the year ended December 31, 2020 the average daily trading volume for our common stock as reported by the Nasdaq Global Market was approximately 29,000 shares. We are uncertain whether a more active trading market in our common stock will develop. In addition, many investment banks no longer find it profitable to provide securities research on micro-cap and small-cap companies. As a result, relatively small trades may have a significant impact on the market price of our common stock, which could increase the volatility and depress the price of our common stock. +Our common stock is thinly traded, and investors may be unable to sell their shares at their desired prices, or at all, and sales of large blocks of shares may adversely affect the price of our common stock. +Our common stock has historically been sporadically or “thinly traded,” meaning that the number of persons interested in purchasing shares of our common stock at prevailing prices at any given time may be relatively small. This could lead to wide fluctuations in our share price. Investors may be unable to sell their common stock at or above their purchase price, which may result in substantial losses. As a consequence of this lack of liquidity, the trading of relatively small quantities of shares by our stockholders may disproportionately influence the price of shares of our common stock in either direction. The price of shares of our common stock could, for example, decline precipitously in the event a large number of shares of our common stock are sold on the market without commensurate demand, while an issuer with a more robust daily trading volume for its common stock might better absorb those sales without an adverse impact on its share price. +If we raise additional capital in the future, existing shareholder ownership interest in the Company could be diluted or otherwise adversely impacted, and future sales of our common stock or other financing arrangements may cause our stock price to decline. +In the future, we may sell additional shares of our common stock in public or private offerings, or we may obtain funds through a credit facility or by issuing debt or preferred securities. We may also issue additional shares of our common stock to finance future acquisitions. Shares of our common stock are also available for future issuance and sale pursuant to stock options and other equity awards that we have granted to our employees, and in the future, we may grant additional stock options, restricted stock units and other forms of equity compensation to our employees. Any issuance of equity we may undertake in the future to raise additional capital could cause the price of our common stock to decline, or require us to issue shares at a price that is lower than that paid by holders of our common stock in the past, which would result in those newly issued shares being dilutive. Sales of our common stock or the perception that such sales could occur may adversely affect prevailing market prices for shares of our common stock and could impair our ability to raise capital through future offerings. The lenders under our existing debt agreements have rights that are senior to your rights as a common stockholder, and if we obtain funds in the future through a credit facility or through the issuance of debt or preferred securities, the lenders of such facility or the holders of such securities would likely also have rights senior to the rights of our common stockholders, which could impair the value of our common stock. +We take advantage of specified scaled disclosure requirements applicable to a “smaller reporting company” under Regulation S-K, and the information that we provide to stockholders may therefore be different than they might receive from other public companies. If some investors find our shares of common stock less attractive as a result of this scaled disclosure, there may be a less active trading market for our shares of common stock, which may increase the volatility of the market price of our common stock. +We are a “smaller reporting company,” as defined in Item 10(f)(1) of Regulation S-K. As a smaller reporting company, we take advantage of specified scaled disclosure and other requirements that are otherwise applicable generally to public companies. +We intend to continue to take advantage of certain of the scaled disclosure requirements of smaller reporting companies and may continue to do so until we are no longer a smaller reporting company. We will cease to be a smaller reporting company if we have (i) more than $250 million in market value of our shares held by non-affiliates as of the last business day of our second fiscal quarter or (ii) more than $100 million of annual revenues in our most recent fiscal year completed before the last business day of our second fiscal quarter and a market value of our shares held by non-affiliates more than $700 million as of the last business day of our second fiscal quarter. We choose to take advantage of some but not all of these scaled disclosure requirements; therefore, the information that we provide stockholders may be different than one might get from other public companies. Further, if some investors find our shares of common stock less attractive as a result, there may be a less active trading market for our shares of common stock and the market price of such shares of common stock may be more volatile. +16 +Item 1B. Unresolved Staff Comments. +Not applicable. +Item 2. Properties. +Our principal facilities as of December 31, 2020 are listed below. We believe that all facilities generally are in good condition, adequately maintained and suitable for their present and currently contemplated uses. +Location +Operations Conducted +Size +(Approx. Sq. Ft.) +Owned +or Leased +Lease Expiration +Date +Hamden, Connecticut +Executive offices and sales office +11,100 +Leased +April 30, 2027 +Ithaca, New York +Hardware design and development, assembly and service facility +73,900 +Leased +May 31, 2025 +Las Vegas, Nevada +Software design and development and casino and gaming sales office +19,600 +Leased +October 31, 2022 +Doncaster, UK +Sales office and service center +6,000 +Leased +August 26, 2026 +Macau, China +Sales office +180 +Leased +June 30, 2021 +110,780 +Item 3. Legal Proceedings. +The Company may, in the ordinary course of business, become a party to litigation involving collection matters, contract claims and other legal proceedings relating to the conduct of its business. As of December 31, 2020, we are unaware of any material legal proceedings pending or threatened against us, or any material legal proceedings contemplated by governmental authorities. +Item 4. Mine Safety Disclosures. +Not applicable. +17 +PART II +Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. +Our common stock is traded on the Nasdaq Global Market under the symbol TACT. As of February 28, 2021, there were 251 holders of record of the common stock. +Issuer Purchases of Equity Securities +During the fourth quarter of 2020, we did not repurchase any shares of our common stock. +Dividend Policy +In 2012, our Board of Directors initiated a quarterly cash dividend program subject to the Board’s approval each quarter. Dividends declared and paid on our common stock totaled $2.7 million or $0.36 per share in 2019. On January 23, 2020, our Board of Directors announced the cessation of our quarterly cash dividend on the Company’s common stock to accelerate the investment in sales and marketing, continued product development and infrastructure of the BOHA! ecosystem. The final dividend payment was made in December 2019. +Sales of Unregistered Securities +None. +Item 6. Selected Financial Data +Not required. +Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. +This discussion should be read in conjunction with the Consolidated Financial Statements and notes thereto. +Overview +The year ended December 31, 2020 was a very challenging year, as the COVID-19 pandemic unexpectedly occurred and significantly impacted our and our customers’ businesses. The pandemic caused us to quickly react and take actions and measures to reduce costs, increase liquidity and protect our employees. The good news is that TransAct persevered and made it through these difficult times. Even with the pandemic raging, we continued to focus our efforts on the sales execution and growing revenue of BOHA! software-as-a-service (“SaaS”)-based software and hardware ecosystem launched in 2019. BOHA! is a comprehensive ecosystem of cloud-based SaaS software applications and hardware designed to help restaurant and food service companies automate their back-of-house operations. BOHA! represents the first single-vendor solution to allow customers to choose from any combination of applications for inventory management, temperature monitoring of food and equipment, food safety labeling, food recalls, checklists & procedures, equipment service management, timers and delivery management. Despite the negative impact from the COVID-19 pandemic explained above, food service technology sales increased in 2020 compared to 2019 due primarily to sales of our BOHA! software, labels and other recurring revenue to both new customers and our existing installed base of BOHA! terminals. +During 2020, sales in all markets other than food service technology decreased primarily due to the negative impact from the COVID-19 pandemic. POS automation and banking sales declined primarily due to lower sales of our Ithaca 9000 printer to McDonald’s in 2020 compared to 2019. Casino and gaming sales were lower in 2020 due to casino closures and gradual reopenings in the second half of 2020 in response to the COVID-19 pandemic. Sales for our lottery market decreased as we exited the lottery market in 2019 and completed our final sale of lottery printers in 2020. Printrex sales declined primarily due to the negative impact from lower worldwide oil prices largely attributable to the COVID-19 pandemic. TSG sales decreased in 2020 compared to 2019 primarily due to lower sales of our legacy consumable products and service sales due to the exit of the banking market in 2018. +During the year ended December 31, 2020, our total net sales decreased 33% to approximately $30.6 million compared to the year ended December 31, 2019. See the table below for a breakdown of our sales by market: +Year Ended +Year Ended +(In thousands, except percentages) +December 31, 2020 +December 31, 2019 +$ Change +% Change +Food service technology +$ +7,734 +25.3 +% +$ +6,104 +13.3 +% +$ +1,630 +26.7 +% +POS automation and banking +3,770 +12.3 +% +5,758 +12.6 +% +(1,988 +) +(34.5 +%) +Casino and gaming +10,979 +35.9 +% +21,529 +47.1 +% +(10,550 +) +(49.0 +%) +Lottery +817 +2.7 +% +1,291 +2.8 +% +(474 +) +(36.7 +%) +Printrex +300 +1.0 +% +1,166 +2.6 +% +(866 +) +(74.3 +%) +TSG +6,995 +22.8 +% +9,900 +21.6 +% +(2,905 +) +(29.3 +%) +$ +30,595 +100.0 +% +$ +45,748 +100.0 +% +$ +(15,153 +) +(33.1 +%) +Sales of our food service technology products increased 27% in the year ended December 31, 2020 compared to the year ended December 31, 2019. In the food service technology market, we focus on providing hardware products, which include terminals, handheld devices, tablets, temperature probes and temperature sensors; in addition to cloud-based software applications, labels and other recurring revenue items. In 2019, we launched our BOHA! solution, which combines our latest generation terminal, cloud-based software applications and hardware into a unique solution to automate the back-of-house operations in restaurants and food service operations. Food service technology sales increased in 2020 primarily due to a 96% increase in recurring revenue attributable to sales of BOHA!, which sales reflect subscriptions for the related software applications, as well as sales of labels, extended warranty and service contracts, and technical support services. +18 +Sales of our POS automation and banking products decreased 35% in the year ended December 31, 2020 compared to the year ended December 31, 2019. In the POS market, we focus primarily on supplying printers that print receipts or linerless labels for customers in the restaurant and quick serve markets. During the year ended December 31, 2020, sales of our Ithaca 9000 printer to McDonald’s decreased. We believe the decrease is a result of the COVID-19 pandemic. In the banking market, which we exited at the end of 2018, we focused mainly on supplying printers for use in bank teller stations at banks and financial institutions primarily in the U.S. We exited the banking market in order to shift focus to our food service technology market and we do not expect any future sales of these legacy products. +Sales of our casino and gaming products decreased 49% in 2020 compared to 2019. In our casino and gaming market, our focus lies primarily in supplying printers worldwide for use in slot machines at casinos and racetracks, as well as in other electronic gaming devices that print tickets or receipts. Additionally, we supplement these printer sales with revenue from EPICENTRAL™, our promotional printing system that enables casino operators to create promotional coupons and marketing messages and print them in real time at the slot machine. The decrease of casino and gaming printers was d riven by industry-wide weakness resulting in lower sales to our OEMs that were impacted by casino closures in response to the COVID-19 pandemic, which were in place for most of the second quarter of 2020 before gradually reopening at reduced capacities during the second half of 2020. +During the year ended December 31, 2020, total lottery printer sales decreased approximately 37% due to lower sales to IGT. On December 31, 2019, we ended our non-exclusive agreement with IGT and exited the lottery market as we shifted our focus to our higher-value, technology-enabled market for food service technology and casino and gaming products. During 2020 IGT made a final purchase of lottery printers and we expect no future sales of our lottery printer. +Sales of our Printrex branded printers include wide format, rack-mounted and vehicle-mounted thermal printers used by customers to log and plot oil field and down hole well drilling data in the oil and gas exploration industry. During the year ended December 31, 2020, we experienced a 74% decline in Printrex oil and gas printer sales as a result of lower worldwide oil prices as a result of the COVID-19 pandemic. Although we will continue to fulfill orders from existing customers during 2021, we have shifted our focus away from this market and towards our higher value, technology enabled food service technology terminals and casino and gaming products. +TSG, which sells service, replacement parts and consumable products, including receipt paper, ribbons and inkjet cartridges, continues to offer a recurring revenue stream from mostly our legacy products. TSG sales decreased 29% in 2020 from 2019 primarily due to lower sales of consumable products for our legacy banking printers and lower service sales primarily related to a service contract with a banking customer that is expected to end in 2021. We expect TSG sales to continue to decline in 2021 due to the ending of the service contract and lower expected sales of our lottery printer spare parts to IGT for our legacy lottery printer. +Operationally, our gross margin was 42.3% in 2020, a decrease of 560 basis points from 2019 due to the 33% sales decline during 2020 and the impact of fixed manufacturing overhead on lower sales volume as a result of the impact of the COVID-19 pandemic. +During 2020, our operating margin declined from 0.7% in 2019 to negative 26.7% in 2020 due to the 33% decline in sales and 560 basis point decrease in gross margin. Operating expenses decreased by 2% due to cost saving initiatives implemented in March 2020 and maintained through 2020 in response to the negative impact from the COVID-19 pandemic. During 2021, we expect operating expenses to increase significantly compared to 2020, as we resume our investment in selling and marketing to take advantage of the opportunities we see in the food service technology market. +We reported a net loss of $5.6 million and net loss per diluted share of $0.72 for 2020, compared to net income of $0.5 million and net income per diluted share of $0.07 for 2019. In terms of cash flow, for 2020 we used $3.5 million of cash in operating activities. During 2020, we completed an underwritten public offering (the “Offering”) which raised net proceeds of $8.7 million and the Company was granted the $2.2 million PPP Loan . We ended the year with cash and cash equivalents of $10.4 million on our Consolidated Balance Sheet at December 31, 2020. +Critical Accounting Policies and Estimates +The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates, judgments and assumptions that affect both Balance Sheet items and Statement of Operations categories. Such estimates and judgments are based upon historical experience and certain assumptions that are believed to be reasonable in the particular circumstances. We evaluate our assumptions on an ongoing basis by comparing actual results with our estimates. Actual results may differ from the original estimates. +The following accounting policies are those that we believe to be most critical in the preparation of our financial statements. These items utilize assumptions and estimates about the effect of future events that are inherently uncertain and are therefore based on our judgment. Please refer to Note 2 – Summary of significant accounting policies in the accompanying Consolidated Financial Statements for a complete listing of our significant accounting policies. +Revenue Recognition – We account for revenue in accordance with the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 606, “Revenue from Contracts with Customers (“ASC 606”). We adopted ASC 606 effective January 1, 2018 and elected the modified retrospective approach. In accordance with ASC 606, a performance obligation is a promise in a contract with a customer to transfer a distinct good or service to the customer. Some of our contracts with customers contain a single performance obligation, while other contracts contain multiple performance obligations (most commonly when contracts include a hardware product, software and extended warranties). A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue when, or as, the performance obligation is satisfied. +The transaction price is determined based on the consideration to which the Company will be entitled in exchange for transferring services to the customer. To the extent the transaction price includes variable consideration, such as price protection, reserves for returns and other allowances, the Company estimates the amount of variable consideration that should be included in the transaction price utilizing either the “expected value” method or the “most likely amount” method depending on the nature of the variable consideration. Variable consideration is included in the transaction price if, in the Company’s judgment, it is probable that a significant future reversal of cumulative revenue under the contract will not occur. +19 +For a majority of our revenue, which consists of printers, terminals, consumables, and replacement parts, the Company recognizes revenue as of a point of time. The transaction price is recognized upon shipment of the order when control of the goods is transferred to the customer and at the time the performance obligation is fulfilled. We also sell a software solution in our casino and gaming market, EPICENTRAL™, that enables casino operators to create promotional coupons and marketing messages and to print them in real time at the slot machine. EPICENTRAL TM is primarily comprised of both a software component, which is licensed to the customer, and a hardware component. EPICENTRAL™ software and hardware are integrated to deliver the system’s full functionality. The transaction prices from EPICENTRAL™ software license and hardware are recognized upon installation and formal acceptance by the customer when control of the license is transferred to the customer. For out-of-warranty repairs, the transaction price is recognized after the repair work is completed and the printer or terminal is returned to the customer, as control of the product is transferred to the customer and our performance obligation is completed. +Performance obligations are satisfied over time if the customer receives the benefits as we perform work, if the customer controls the asset as it is being produced, or if the product being produced for the customer has no alternative use and we have a contractual right to payment. For our separately priced extended warranty, BOHA! cloud-based software applications, technical support for our food service technology terminals and maintenance agreements (including free one-year maintenance received by customers upon completion of EPICENTRAL™ installation) revenue is recognized over time as the customer receives the benefit. The transaction price from the maintenance services is recognized ratably over time, using output methods, as control of the services is transferred to the customer. Our cloud-based BOHA! software allows customers to use hosted software over the contract period without taking possession of the software and are provided on a subscription basis and is recognized ratably over the contract period. For extended warranties, the transaction price is recognized ratably over the warranty period, using output methods, as control of the services is transferred to the customer. +When there is more than one performance obligation in a customer arrangement, the Company typically uses the “standalone selling price” method to determine the transaction price to allocate to each performance obligation. The Company sells the performance obligations separately and has established standalone selling prices for its products and services. In the case of an overall price discount, the discount is applied to each performance obligation proportionately based on standalone selling price. To determine the standalone selling price for initial EPICENTRAL™ installations, the Company uses the adjusted market assessment approach. +Accounts Receivable – We have standardized credit granting and review policies and procedures for all customer accounts, including: credit reviews of all new customer accounts; ongoing credit evaluations of current customers; credit limits and payment terms based on available credit information; and adjustments to credit limits based upon payment history and the customer’s current creditworthiness. We also provide an estimate of doubtful accounts based on historical experience and specific customer collection issues. Our allowance for doubtful accounts as of December 31, 2020 was $220 thousand, or 6.1% of outstanding accounts receivable, which we believe is appropriate considering the overall quality of our accounts receivable. Although credit losses have historically been within expectations and the reserves established, there is no assurance that our credit loss experience will continue to be consistent with historical experience. +Inventories – Our inventories are stated at the lower of cost (principally standard cost, which approximates actual cost on a first-in, first-out basis) or net realizable value. We review net realizable value based on estimated selling prices in the ordinary course of business less estimated costs of completion, disposal and transportation, historical usage and estimates of future demand. Assumptions are reviewed at least quarterly and adjustments are made, as necessary, to reflect changing market conditions. Based on these reviews, inventory write-downs are recorded, as necessary, to reflect estimated obsolescence, excess quantities and net realizable value. Should circumstances change and we determine that additional inventory is subject to obsolescence, additional write-downs of inventory could result in a charge to income. +Goodwill and Intangible Assets – We acquire businesses in purchase transactions that result in the recognition of goodwill and intangible assets. The determination of the value of intangible assets requires management to make estimates and assumptions. In accordance with ASC 350-20 “Goodwill,” acquired goodwill is not amortized but is subject to impairment testing at least annually and when an event occurs or circumstances change that indicate it is more likely than not an impairment exists. We perform a fair value-based impairment test to the carrying value of goodwill and indefinite-lived intangible assets on an annual basis (as of December 31) and, if certain events or circumstances indicate that an impairment loss may have been incurred, on an interim basis. The Company utilizes the option to first assess qualitative factors to determine whether it is necessary to perform the Step 1 quantitative goodwill impairment test in accordance with the applicable accounting standards. Under the qualitative assessment, management considers relevant events and circumstances including, but not limited to, macroeconomic conditions, industry and market considerations, Company performance, and events directly affecting the Company. If the Company determines that the Step 1 quantitative impairment test is required, management estimates the fair value of the reporting unit primarily using the income approach, which reflects management’s cash flow projections, and also evaluates the fair value using the market approach. Factors considered that may trigger an interim period impairment review of either acquired goodwill or intangible assets are: significant underperformance relative to expected historical or projected future operating results; significant changes in the manner of use of acquired assets or the strategy for the overall business; significant negative industry or economic trends; and significant decline in market capitalization relative to net book value. Finite lived intangible assets are amortized and are tested for impairment when appropriate. +During the three months ended March 31, 2020, our stock price declined to the lowest price since 2009. We determined that the significant decline in our market capitalization and broader economic downturn arising from the COVID-19 pandemic was a triggering event and an indicator that it was more likely than not that the carrying value of goodwill exceeded fair value. Therefore, we concluded that quantitative analyses were required to be performed due to the triggering event occurring during the first quarter of 2020. We utilized an implied market value method under the market approach to calculate the fair value of the Company as of March 31, 2020, which we determined was the best approximation of fair value in the current social and economic environment. Based on our interim impairment assessment as of March 31, 2020, we determined that no goodwill or intangible asset impairment occurred and the fair value of goodwill was substantially higher than our carrying value. +As of December 31, 2020, upon the completion of our annual assessment for impairment, we have determined that no goodwill or intangible asset impairment has occurred and the fair value of goodwill was substantially higher than our carrying value. +20 +Income Taxes – In preparing our Consolidated Financial Statements, we are required to estimate income taxes in each of the jurisdictions in which we operate. This involves estimating the actual current tax exposure together with assessing temporary differences between the tax basis of certain assets and liabilities and their reported amounts in the financial statements, as well as net operating losses, tax credits and other carryforwards. These differences result in deferred tax assets and liabilities, which are reflected in our Consolidated Balance Sheets. We then assess the likelihood that the deferred tax assets will be realized from future taxable income, and to the extent that we believe that realization is not likely, we establish a valuation allowance. +Significant judgment is required in determining the provision for income taxes and, in particular, any valuation allowance or tax reserves with respect to our deferred tax assets and uncertain tax positions. On a quarterly basis, we evaluate the recoverability of our deferred tax assets based upon historical results and forecasted taxable income over future years, and match this forecast against the basis differences, deductions available in future years and the limitations allowed for net operating loss and tax credit carryforwards to ensure that there is adequate support for the realization of the deferred tax assets. Although we have considered future taxable income and ongoing prudent and feasible tax planning strategies in assessing the need for a valuation allowance, in the event we were to determine that we would not be able to realize all or part of our deferred tax assets in the future, an adjustment to the valuation allowance or tax reserves would be charged as a reduction to income in the period such determination was made. Likewise, should we determine that we would be able to realize future deferred tax assets in excess of its net recorded amount, an adjustment to the valuation allowance would increase net income in the period such determination was made. +We account for income taxes in accordance with ASC 740, “Income Taxes” (“ASC 740”) Among other things this provision prescribes a minimum recognition threshold that an income tax position must meet before it is recorded in the reporting entity’s financial statements. It also requires that the effects of such income tax positions be recognized only if, as of the balance sheet reporting date, it is “more likely than not” (i.e., more than a 50% likelihood) that the income tax position will be sustained based solely on its technical merits. When making this assessment, management must assume that the responsible taxing authority will examine the income tax position and have full knowledge of all relevant facts and other pertinent information. The accounting guidance also clarifies the method of accruing for interest and penalties when there is a difference between the amount claimed, or expected to be claimed, on a company’s income tax returns and the benefits recognized in the financial statements. +Warranty – We generally warrant our products for up to 24 months and record the estimated cost of such product warranties at the time the sale is recorded. Estimated warranty costs are based upon actual past experience of product repairs and the related estimated cost of labor and material to make the necessary repairs. If actual future product repair rates or the actual costs of material and labor differ from the estimates, adjustments to the accrued warranty liability and related warranty expense would be made. +Share-Based Compensation – We calculate share-based compensation expense in accordance with ASC 718, “Compensation – Stock Compensation” using the Black-Scholes option-pricing model to calculate the fair value of share-based awards. The key assumptions for this valuation method include the expected term of an option grant, stock price volatility, risk-free interest rate, and dividend yield. We account for forfeitures as they occur. +Results of Operations: Year Ended December 31, 2020 Compared to Year Ended December 31, 2019 +Net Sales. Net sales, which include printer, terminal and software sales as well as sales of replacement parts, consumables and maintenance and repair services, by market for the years ended December 31, 2020 and 2019 are detailed in the below table. +Year Ended +Year Ended +(In thousands, except percentages) +December 31, 2020 +December 31, 2019 +$ Change +% Change +Food service technology +$ +7,734 +25.3 +% +$ +6,104 +13.3 +% +$ +1,630 +26.7 +% +POS automation and banking +3,770 +12.3 +% +5,758 +12.6 +% +(1,988 +) +(34.5 +%) +Casino and gaming +10,979 +35.9 +% +21,529 +47.1 +% +(10,550 +) +(49.0 +%) +Lottery +817 +2.7 +% +1,291 +2.8 +% +(474 +) +(36.7 +%) +Printrex +300 +1.0 +% +1,166 +2.6 +% +(866 +) +(74.3 +%) +TSG +6,995 +22.8 +% +9,900 +21.6 +% +(2,905 +) +(29.3 +%) +$ +30,595 +100.0 +% +$ +45,748 +100.0 +% +$ +(15,153 +) +(33.1 +%) +International* +$ +5,862 +19.2 +% +$ +10,416 +22.8 +% +$ +(4,554 +) +(43.7 +%) +* +International sales do not include sales of products made to domestic distributors or other customers who in turn ship those products to international destinations. +Net sales for 2020 decreased $15.2 million, or 33%, from 2019. Printer, terminal and other hardware sales volume decreased by 44% to approximately 62,000 units, due to volume decreases in almost all our markets except for a slight increase in food service technology terminal sales. The volume decrease in 2020 was driven primarily by a 52% decrease in unit volume from the casino and gaming market and, to a lesser extent, a 28% decrease in the POS automation and banking market and 50% decrease in the lottery market. The average selling price of our printers, terminals and other hardware increased 2% during 2020 compared to 2019 primarily due to a lower level of POS automation and banking printer sales, which sell at a lower price than our other products. The sales volume decreases were partially offset by a $1.9 million, or 96%, increase in software, labels and other recurring revenue from our food service technology market. +International sales for 2020 decreased $4.6 million, or 44%, compared to 2019, primarily due to a 51% decrease of international casino and gaming sales. +21 +Food service technology: Our primary offering in the food service technology market is our BOHA! ecosystem, which combines our latest generation terminal, cloud-based software applications and related hardware into a unique solution to automate back-of-house operations in restaurants, convenience stores and food service operations. The software component of BOHA! consists of a suite of software-as-a-service (“SaaS”)-based applications, including applications for inventory management, temperature monitoring of food and equipment, timers, food safety labeling, food recalls, checklists and procedures, equipment service management, and delivery management. These applications are combined into a single platform with the associated hardware, which includes the BOHA! terminal, handheld devices, tablets, temperature probes and temperature sensors. The BOHA! terminal combines the software and hardware components in a device that includes an operating system, touchscreen and one or two thermal print mechanisms that print easy-to-read food rotation labels, grab and go labels for prepared foods, and “enjoy by” date labels. The BOHA! terminal is equipped with the TransAct Enterprise Management System to ensure that only approved applications and functions are available on the device and allows over-the-air updates to the applications and operating system. BOHA! helps food service establishments and restaurants (including fine dining, casual dining, fast casual and quick-serve restaurants, convenience stores, hospitality establishments and contract food service providers) effectively manage food safety and grab-and-go initiatives, as well as automate and manage back-of-house operations. Recurring revenue from BOHA! is generated by software sales, including software subscriptions that are charged to customers upfront on a per-application basis, as well as sales of labels, extended warranty and service contracts, and technical support services. Sales of our worldwide food service technology products for the years ended December 31, 2020 and 2019 is as follows: +Year Ended +Year Ended +(In thousands, except percentages) +December 31, 2020 +December 31, 2019 +$ Change +% Change +Domestic +$ +6,956 +89.9 +% +$ +5,522 +90.5 +% +$ +1,434 +26.0 +% +International +778 +10.1 +% +582 +9.5 +% +196 +33.7 +% +$ +7,734 +100.0 +% +$ +6,104 +100.0 +% +$ +1,630 +26.7 +% +Year Ended +Year Ended +(In thousands, except percentages) +December 31, 2020 +December 31, 2019 +$ Change +% Change +Hardware +$ +3,938 +50.9 +% +$ +4,169 +68.3 +% +$ +(231 +) +(5.5 +%) +Software, labels and other recurring revenue +3,796 +49.1 +% +1,935 +31.7 +% +1,861 +96.2 +% +$ +7,734 +100.0 +% +$ +6,104 +100.0 +% +$ +1,630 +26.7 +% +The increase in food service technology sales in 2020 compared to 2019 was driven primarily by sales of our BOHA! software, labels and other recurring revenue. Sales of BOHA! software recognized on a SaaS subscription basis, labels and other recurring revenue increased by 96%, primarily due to increased label sales and, to a lesser extent, increased software sales, compared to the prior year period. Sales for the prior year period were significantly lower due to the launch of BOHA! not occurring until March 2019. The large increase of label sales in 2020 was primarily due to an initial stocking order to a distributor of a large convenience store chain as well as increased usage by existing customers as the installed terminal base continued to increase. Hardware sales in 2020 decreased 6% compared to 2019 primarily due to the impact from the COVID-19 pandemic that resulted in widespread store closings and substantially reduced customer operations. +POS automation and banking: Revenue from the POS automation and banking market includes sales of thermal printers used primarily by quick serve restaurants located either at the checkout counter or within self-service kiosks to print receipts for consumers or print on linerless labels. Prior to 2020, revenue included sales of inkjet printers used by banks, credit unions and other financial institutions to print deposit or withdrawal receipts and/or validate checks at bank teller stations. We exited the banking market during 2018. A summary of sales of our worldwide POS automation and banking products for the years ended December 31, 2020 and 2019 is as follows: +Year Ended +Year Ended +(In thousands, except percentages) +December 31, 2020 +December 31, 2019 +$ Change +% Change +Domestic +$ +3,763 +99.8 +% +$ +5,714 +99.2 +% +$ +(1,951 +) +(34.1 +%) +International +7 +0.2 +% +44 +0.8 +% +(37 +) +(84.1 +%) +$ +3,770 +100.0 +% +$ +5,758 +100.0 +% +$ +(1,988 +) +(34.5 +%) +The decrease in both domestic and international POS automation and banking sales in 2020 compared to 2019 was primarily driven by a 33% decrease in domestic and international sales of our Ithaca® 9000 printer largely attributable to fewer sales to McDonald’s which we believe resulted from the COVID-19 pandemic. +22 +Casino and Gaming: Revenue from the casino and gaming market includes sales of thermal ticket printers used in slot machines, video lottery terminals, and other gaming machines that print tickets or receipts instead of issuing coins at casinos and racetracks and other gaming venues worldwide. Revenue from this market also includes sales of thermal roll-fed printers used in the international off-premise gaming market in gaming machines such as Amusement with Prizes, Skills with Prizes and Fixed Odds Betting Terminals at non-casino gaming and sports betting establishments. Revenue from this market also includes royalties related to our patented casino and gaming technology. In addition, casino and gaming market revenue includes sales of the EPICENTRAL™ print system, our software solution (including annual software maintenance), that enables casino operators to create promotional coupons and marketing messages and to print them in real time at the slot machine. A summary of sales of our worldwide casino and gaming products for the years ended December 31, 2020 and 2019 is as follows: +Year Ended +Year Ended +(In thousands, except percentages) +December 31, 2020 +December 31, 2019 +$ Change +% Change +Domestic +$ +6,852 +62.4 +% +$ +13,076 +60.7 +% +$ +(6,224 +) +(47.6 +%) +International +4,127 +37.6 +% +8,453 +39.3 +% +(4,326 +) +(51.2 +%) +$ +10,979 +100.0 +% +$ +21,529 +100.0 +% +$ +(10,550 +) +(49.0 +%) +The decrease in domestic sales of our casino and gaming products during 2020 compared to 2019 was primarily due to a 50% decrease in domestic sales of our thermal casino printer, driven by industry-wide weakness resulting in lower sales to our OEMs that were impacted by casino closures in response to the COVID-19 pandemic, which were in place for most of the second quarter of 2020 before gradually reopening at reduced capacities during the second half of 2020. This decrease was partially offset by a 73% increase in EPICENTRAL™ sales to an existing EPICENTRAL™ customer that expanded their slot machine floor. There were no new EPICENTRAL™ software installations during 2020 or 2019. Sales of domestic EPICENTRAL TM are project based, and as a result, may fluctuate significantly quarter-to-quarter and year-to-year. +The decrease in international casino and gaming sales during 2020 compared to 2019 was primarily due to a 46% decline in sales of our thermal casino printers and a 64% decline in international sales of our off-premise gaming printers attributable to the negative impacts of the COVID-19 pandemic on the international casino and gaming industry. +Lottery: Revenue from the lottery market includes sales of thermal on-line and other lottery printers primarily to IGT and, to a lesser extent, other lottery system companies for various lottery applications. A summary of sales of our worldwide lottery printers for the years ended December 31, 2020 and 2019 is as follows: +Year Ended +Year Ended +(In thousands, except percentages) +December 31, 2020 +December 31, 2019 +$ Change +% Change +Domestic +$ +817 +100.0 +% +$ +1,290 +99.9 +% +$ +(473 +) +(36.7 +%) +International +– +0.0 +% +1 +0.1 +% +(1 +) +(100.0 +%) +$ +817 +100.0 +% +$ +1,291 +100.0 +% +$ +(474 +) +(36.7 +%) +On December 31, 2019, we allowed our non-exclusive agreement to provide lottery terminal printers to IGT to expire, as we decided to exit the lottery market and shift our focus towards our higher-value, technology enabled food service technology and casino and gaming products. As a result, IGT made a final purchase of our lottery printers during the second quarter of 2020 and we do not expect any further lottery printer sales in the future. +Printrex: Printrex branded printers are sold into markets that include wide format, desktop and rack mounted and vehicle mounted black/white thermal printers used by customers to log and plot oil field, seismic and down hole well drilling data in the oil and gas exploration industry. It also includes high-speed color inkjet desktop printers used to print logs at the data centers of the oil and gas field service companies. A summary of sales of our worldwide Printrex printers for the years ended December 31, 2020 and 2019 is as follows: +Year Ended +Year Ended +(In thousands, except percentages) +December 31, 2020 +December 31, 2019 +$ Change +% Change +Domestic +$ +83 +27.7 +% +$ +961 +82.4 +% +$ +(878 +) +(91.4 +%) +International +217 +72.3 +% +205 +17.6 +% +12 +5.9 +% +$ +300 +100.0 +% +$ +1,166 +100.0 +% +$ +(866 +) +(74.3 +%) +The decrease in sales of Printrex printers in 2020 compared to 2019 resulted primarily from lower domestic sales in the oil and gas market which was negatively impacted by the decline in worldwide oil prices largely attributable to the COVID-19 pandemic. +23 +TSG: Revenue generated by TSG includes sales of consumable products (POS receipt paper, inkjet cartridges, ribbons and other printing supplies), replacement parts, maintenance and repair services, testing services, refurbished printers, and shipping and handling charges. A summary of sales in our worldwide TSG market for the years ended December 31, 2020 and 2019 is as follows: +Year Ended +Year Ended +(In thousands, except percentages) +December 31, 2020 +December 31, 2019 +$ Change +% Change +Domestic +$ +6,262 +89.5 +% +$ +8,769 +88.6 +% +$ +(2,507 +) +(28.6 +%) +International +733 +10.5 +% +1,131 +11.4 +% +(398 +) +(35.2 +%) +$ +6,995 +100.0 +% +$ +9,900 +100.0 +% +$ +(2,905 +) +(29.3 +%) +The decrease in domestic TSG sales for 2020 as compared to 2019 was primarily due to a 72% decline in consumable sales resulting largely from lower sales of legacy HP inkjet cartridges used in our banking printers, as we exited the banking market at the end of 2018, and to a lesser extent, lower sales of legacy POS receipt paper. In addition, we experienced 32% lower service sales primarily related to a service contract with a banking customer that is expected to end in 2021. We expect TSG sales to decrease in 2021 compared to 2020 due to lower expected sales of lottery printer spare printer parts to IGT and lower service sales related to the service contract with a banking customer that is expected to end in 2021. +Internationally, TSG sales decreased during 2020 compared to 2019 primarily due to a 49% decrease in sales of replacement parts and accessories to international casino and gaming customers. +Gross Profit. Gross profit information for the years ended December 31, 2020 and 2019 is summarized below (in thousands, except percentages): +Year Ended December 31, +Percent +Percent of +Percent of +2020 +2019 +Change +Total Sales - 2020 +Total Sales - 2019 +$ +12,929 +$ +21,935 +(41.1 +%) +42.3 +% +47.9 +% +Gross profit is measured as revenue less cost of sales, which includes primarily the cost of all raw materials and component parts, direct labor, manufacturing overhead expenses, cost of finished products purchased directly from our contract manufacturers, expenses associated with installations and support of our EPICENTRAL TM print system and BOHA! ecosystem and royalty payments to third parties, including to the third party licensor of our food service technology software products. Gross profit decreased $9.0 million, or 41% in 2020 compared to 2019 primarily due to a 33% sales decrease in 2020 compared to 2019. Gross margin decreased 560 basis points to 42.3% during 2020 compared to 47.9% in 2019 primarily due to the impact of fixed manufacturing overhead expenses on lower sales volume as a result of the effects of the COVID-19 pandemic, partially offset by cost savings measures implemented in late March 2020 and maintained through the end of 2020 in response to the COVID-19 pandemic. +Operating Expenses - Engineering, Design and Product Development. Engineering, design and product development information for the years ended December 31, 2020 and 2019 is summarized below (in thousands, except percentages): +Year Ended December 31, +Percent +Percent of +Percent of +2020 +2019 +Change +Total Sales - 2020 +Total Sales - 2019 +$ +5,703 +$ +4,393 +29.8 +% +18.6 +% +9.6 +% +Engineering, design and product development expense primarily includes salary and payroll related expenses for our hardware and software engineering staff, depreciation and design expenses (including prototype printer expenses, outside design, development and testing services, supplies and contract software development expenses). Engineering, design and product development expenses increased $1.3 million, or 30%, in 2020 compared to 2019 primarily due to continued expanded development for our food service technology products. We expect engineering, design and product development expense to increase in 2021 compared to 2020 related to accelerated investments planned for our food service technology products. +Operating Expenses - Selling and Marketing . Selling and marketing information for the years ended December 31, 2020 and 2019 is summarized below (in thousands, except percentages): +Year Ended December 31, +Percent +Percent of +Percent of +2020 +2019 +Change +Total Sales - 2020 +Total Sales - 2019 +$ +6,144 +$ +8,033 +(23.5 +%) +20.1 +% +17.6 +% +Selling and marketing expense primarily includes salaries and payroll related expenses for our sales and marketing staff, sales commissions, travel expenses, expenses associated with the lease of sales offices, advertising, trade show expenses, public relations, e-commerce and other promotional marketing expenses. Selling and marketing expenses decreased $1.9 million, or 24%, in 2020 compared to 2019 primarily due to cost saving measures implemented in late March 2020 and maintained through 2020 in response to the COVID-19 pandemic, which more than offset the increase in sales and marketing expenses resulting from the new and expanded marketing programs and promotions to support our food service technology products that were implemented during the first quarter of 2020 prior to the COVID-19 outbreak. We expect selling and marketing expenses to increase in 2021 as we gradually return to more normalized pre-COVID-19 spending levels as well as make substantial strategic investments in our food service technology sales and marketing groups that were deferred from 2020 due to the pandemic. +24 +Operating Expenses - General and Administrative. General and administrative information for the years ended December 31, 2020 and 2019 is summarized below (in thousands, except percentages): +Year Ended December 31, +Percent +Percent of +Percent of +2020 +2019 +Change +Total Sales - 2020 +Total Sales - 2019 +$ +9,255 +$ +9,166 +1.0 +% +30.3 +% +20.0 +% +General and administrative expenses primarily include salaries, incentive compensation, and other payroll related expenses for our executive, accounting, human resources, business development and information technology staff, expenses for our corporate headquarters, professional and legal expenses, telecommunication expenses, and other expenses related to being a publicly-traded company. General and administrative expenses increased $0.1 million, or 1%, in 2020 compared to 2019 primarily due to higher compensation expense almost entirely offset by a decrease in professional fees and discretionary spending resulting from cost saving initiatives implemented in the first quarter of 2020 in response to the COVID-19 pandemic. We expect general and administrative expenses to increase in 2021 as we gradually return to more normalized pre-COVID-19 spending levels. +Operating (Loss) Income. Operating (loss) income information for the years ended December 31, 2020 and 2019 is summarized below (in thousands, except percentages): +Year Ended December 31, +Percent +Percent of +Percent of +2020 +2019 +Change +Total Sales – 2020 +Total Sales – 2019 +$ +(8,173 +) +$ +343 +(2,482.8 +%) +(26.7 +%) +0.7 +% +Our operating income decreased $8.5 million during 2020 compared to 2019 primarily due to the 33% decrease in sales and the 560 basis point decrease in gross margin in 2020 compared to 2019. +Interest. We recorded net interest expense of $52 thousand in 2020 compared to $11 thousand in 2019. The increase in interest expense was primarily due to interest on borrowings under the Siena Credit Facility in the second quarter of 2020 and higher fees for unused borrowings under the Siena Credit Facility as compared to no borrowings and lower fees for unused borrowings under the TD Bank revolving line of credit during 2019. +Other, net . We recorded other income of $56 thousand in 2020 compared to $35 thousand in 2019 primarily due to foreign exchange gains recorded by our UK subsidiary. Going forward, we may continue to experience more foreign exchange gains or losses depending on the level of sales to European customers through our UK subsidiary and the fluctuation in exchange rates of the Euro and Pound Sterling against the U.S. Dollar, which may be impacted by volatility in global economic conditions due to the COVID-19 pandemic. +Income Taxes . We recorded an income tax benefit during the year ended 2020 of $2.5 million at an effective tax rate of 31.1%, compared to an income tax benefit during the year ended 2019 of $149 thousand at an effective tax rate of (40.6%). The effective tax rate for 2020 included the impact of the net operating loss (“NOL”) that we expect to carry back to prior years. The CARES Act permits NOLs incurred in 2018, 2019 and 2020 to be carried back to each of the five preceding taxable years to generate a refund of previously paid income taxes. We generated an NOL for 2020 which we will carry back to tax years that had a federal statutory tax rate of 34% compared to 21% in 2020. The income tax benefit for 2019 was unusually high primarily due to the impact of research and development (R&D) credits on a relatively low level of taxable income. +Net Income. We reported a net loss for the year ended 2020 of $5.6 million, or $(0.72) per diluted share, compared to net income of $0.5 million, or $0.07 per diluted share, in 2019. +Liquidity and Capital Resources +We assess our liquidity in terms of our ability to generate cash to fund our operating, investing and financing activities. Significant factors affecting the management of liquidity are cash flows from operating activities, capital expenditures, access to bank lines of credit and our ability to attract long-term capital with satisfactory terms. +Internal cash generation together with currently available cash and cash equivalents, available borrowing facilities and an ability to access credit lines, if needed, are expected to be sufficient to fund operations, capital expenditures, and any increase in working capital that would be required to accommodate a higher level of business activity. We may actively seek to expand by acquisition as well as through the growth of our current business. A significant acquisition may require additional debt and/or equity financing. +25 +Cash Flow +During 2020 our cash balance increased $6.2 million, or 146%, from December 31, 2019 due to financing activities providing $11 million of cash primarily from the completion of the Offering and the funds received from the PPP Loan. We had $10.4 million in cash and cash equivalents as of December 31, 2020, of which $0.5 million was held by our UK subsidiary. +Operating activities : The following significant factors primarily affected our cash used in operating activities of $3.5 million in 2020 as compared to cash provided by operating activities of $4.8 million in 2019. During 2020: +● +We reported a net loss of $5.6 million. +● +We recorded depreciation and amortization of $1.3 million and share-based compensation expense of $0.9 million. +● +Accounts receivable decreased $3 million, or 47%, primarily due to lower sales volume during the fourth quarter of 2020 compared to the fourth quarter of 2019 due to the pandemic. +● +Inventories decreased $0.9 million, or 7%, primarily due to the utilization of inventory on hand to fulfill sales in response to the pandemic. +● +Prepaid income taxes increased $2.2 million due to an expected income tax refund related to the net operating loss reported for 2020 that will be carried back to prior years as permitted by the CARES Act. +● +Other current and long-term assets increased $0.2 million, or 19%, due primarily to recording a contract asset related to a long term BOHA! sales contract which was partially offset by the recognition of royalty expense that was prepaid in 2019 to a technology partner for food service technology. +● +Accounts payable decreased $1.3 million, or 43%, d ue to inventory purchases made towards the end of the fourth quarter of 2019 that were subsequently paid in the first quarter of 2020 and a lower level of inventory purchases during 2020 due to the pandemic . +● +Accrued liabilities and other liabilities increased $0.2 million, or 3%, due primarily to an increase in accrued inventive compensation. +During 2019: +● +We reported a net income of $0.5 million. +● +We recorded depreciation and amortization of $1.4 million and share-based compensation expense of $0.7 million. +● +Accounts receivable decreased $1.6 million, or 20%, primarily due to strong collections on receivables during the fourth quarter of 2019. +● +Inventories decreased $0.8 million, or 6%, primarily due to the utilization of inventory on hand to fulfill sales. +● +Prepaid income taxes decreased $0.6 million, or 71%, primarily due to an income tax refund received in the fourth quarter of 2019. +● +Other current and long-term assets increased $0.3 million, or 47%, due primarily to an advanced payment of royalty fees to a technology partner for food service technology. +● +Accounts payable decreased $0.5 million, or 15%, primarily due to the utilization of inventory on hand to fulfill sales requiring a lower level of inventory purchases during the second half of 2019. +● +Accrued liabilities and other liabilities increased $0.4 million, or 11%, due primarily to an increase in deferred revenue related to our food service technology service contracts and software subscriptions. +Investing activities : Our capital expenditures, including capitalized software costs, were $0.7 million and $1.4 million in 2020 and 2019, respectively. Expenditures for 2020 were primarily for new product tooling equipment, leasehold improvements at our Las Vegas facility and computer and networking equipment. Expenditures in 2019 were primarily for new product tooling equipment, and, to a lesser extent, computer and networking equipment. Additionally, during the first quarter of 2020, prior to widespread shutdowns in the United States in response to the COVID-19 pandemic, we loaned an additional $0.6 million to a third party software developer from whom we license our food service technology software. +Capital expenditures and additions to capitalized software for 2021 are expected to be approximately $1.4 million, primarily for new product tooling, new computer software and computer and networking equipment to support our food service technology market. +Financing activities: Financing activities provided $11.0 million of cash during 2020 primarily from the completion of the Offering which raised net proceeds of $8.7 million, after deducting u nderwriting discounts, commissions and offering expenses, and the $2.2 million in funds received from the PPP Loan and, to a lesser extent, proceeds of $0.4 million from stock option exercises. These increases were partially offset by the payment of financing costs associated with signing our Siena Credit Facility. During 2019, we used $2.9 million of cash from financing activities to pay dividends of $2.7 million and $0.2 million related to the relinquishment of shares to pay for withholding taxes on stock issued from our stock compensation plan. +Resource Sufficiency +Given the unprecedented uncertainty related to the impact of the COVID-19 pandemic on the food service and casino industries, the Company is closely monitoring its cash generation, usage and preservation including the management of working capital to generate cash. The Company does not currently anticipate requiring any additional credit facilities within the next twelve months beyond our Siena Credit Facility and the PPP Loan, which are discussed above, nor does it anticipate a material change in the terms or covenants pertaining to its current facilities. +We believe that our cash and cash equivalents on hand, our expected cash flows generated from operating activities, proceeds raised through the Offering on October 16, 2020, borrowings available under our Siena Credit Facility, and savings from the cost reduction actions discussed above will provide sufficient resources to meet our working capital needs, finance our capital expenditures and meet our liquidity requirements through at least the next twelve months. Notwithstanding this belief, the duration and extent of the pandemic remain uncertain and its ultimate impact unknown. As a result, continue to evaluate several different strategies to enhance our liquidity position as a result of the significant financial and operational impacts due to the COVID-19 pandemic. These strategies may include, but are not limited to, seeking to raise additional capital through an equity or debt financing and applying for additional relief through other programs established under the CARES Act. +26 +Credit Facility and Borrowings +On March 13, 2020, we entered into the Siena Credit Facility with Siena Lending Group LLC and terminated our credit facility with TD Bank N.A.. The Siena Credit Facility provides for a revolving credit line of up to $10 million expiring on March 13, 2023. Borrowings under the Siena Credit Facility bear a floating rate of interest equal to the greatest of (i) the prime rate plus 1.75%, (ii) the federal funds rate plus 2.25%, and (iii) 6.50%. The total deferred financing costs related to expenses incurred to complete the Siena Credit Facility were $245 thousand. We also pay a fee of 0.50% on unused borrowings under the Siena Credit Facility. Borrowings under the Siena Credit Facility are secured by a lien on substantially all the assets of the Company. Borrowings under the Siena Credit Facility are subject to a borrowing base based on (i) 85% of eligible accounts receivable plus the lesser of (a) $5 million and (b) 50% of eligible raw material and 60% of finished goods inventory. +The Siena Credit Facility imposes a quarterly financial covenant on the Company and restricts, among other things, our ability to incur additional indebtedness and the creation of other liens. The three month period from April 1, 2020 to June 30, 2020 was the first period we were subject to the financial covenant, which required the Company to maintain a minimum EBITDA. As of December 31, 2020, we had no outstanding borrowings under the Siena Credit Facility and were in compliance with our financial covenant. The following table demonstrates our compliance with the financial covenant at December 31, 2020. +Financial Covenant +Requirement +Calculation for the period from April 1, 2020 to December 31, 2020 +EBITDA +Minimum of $(6,631) +$(4,899) +On May 1, 2020, the Company entered into the PPP Loan with Berkshire Bank in the aggregate amount of $2.2 million, pursuant to the PPP which is administered by the SBA and was established under Division A, Title I of the CARES Act, enacted March 27, 2020. +The PPP Loan, which is evidenced by a Note dated the Loan Date issued by the Company (the “Note”), matures on May 1, 2022 and bears interest at a fixed rate of 1.0% per annum, accruing from the Loan Date and payable monthly. No payments are due on the PPP Loan for six months from the date of first disbursement, and if a loan forgiveness application is submitted to the SBA within 10 months after the end of the covered period, no payments are due until the date on which the SBA remits the loan forgiveness amount to the PPP Lender (or notifies the PPP Lender that no loan forgiveness is allowed), but interest will continue to accrue during the deferment period. If no loan forgiveness is allowed, the Company will be required to pay the PPP Lender equal monthly payments of principal and interest based on the principal amount outstanding on the PPP Loan, plus interest outstanding at the end of the deferment period, and taking into account any reductions in the principal amount due to forgiveness, if any. The Note is unsecured and guaranteed by the SBA. The Note may be prepaid by the Company at any time prior to maturity with no prepayment penalties. The Note provides for customary defaults, including failure to make payment when due or to fulfill the Company’s obligations under the Note or related documents, reorganizations, mergers, consolidations or other changes to the Company’s business structure, and certain defaults on other indebtedness, bankruptcy events, adverse changes in financial condition or civil or criminal actions. The PPP Loan may be accelerated upon the occurrence of a default. +Under the terms of the PPP, the PPP Loan may be forgiven to the extent that funds from the PPP Loan are used for qualifying expenses, subject to conditions and limitations provided in the CARES Act. At least 60% (as amended) of the proceeds of the PPP Loan must be used for eligible payroll costs for the PPP Loan to be forgivable. The Company has maximized the use of the PPP Loan proceeds for qualifying expenses and intends to apply for forgiveness of the PPP Loan in accordance with the terms of the CARES Act, as amended by the Paycheck Protection Program Flexibility Act of 2020. Whether forgiveness will be granted and in what amount is subject to an application to, and approval by, the SBA and may also be subject to further requirements in any regulations and guidelines the SBA may adopt. The PPP Loan is classified as “Long-term debt” in the Condensed Consolidated Balance Sheet until the forgiveness determination has been made by the SBA. +Shareholder Dividend Payments +In 2012, our Board of Directors initiated a quarterly cash dividend program which is subject to the Board’s approval each quarter. Dividends declared and paid on our common stock totaled $2.7 million or $0.36 per share in 2019. On January 23, 2020, our Board of Directors announced the cessation of our quarterly cash dividend on the Company’s common stock to accelerate the investment in sales and marketing, continued product development and infrastructure of the BOHA! ecosystem. The final dividend payment was made in December 2019. +Stock Repurchase Program +During 2020 and 2019 we did not repurchase any shares of our common stock. +Shareholders’ Equity +Shareholders’ equity increased 4.3 million, or 17%, to $30.2 million at December 31, 2020 from $25.9 million at December 31, 2019. The increase was primarily due to the completion of the Offering which raised net proceeds of $8.7 million, after deducting u nderwriting discounts, commissions and offering expenses, and sold an aggregate of 1,380,000 shares of common stock. Shareholders’ equity also increased, although to a lesser extent, from share-based compensation expense related to stock awards of $0.9 million and $0.4 million from the issuance of 62,500 shares of common stock related to employee stock awards, net of relinquishments. These increases were partially offset by a net loss of $5.6 million. +Off-Balance Sheet Arrangements +As of December 31, 2020, we had no off-balance sheet arrangements that have had or that we expect would be reasonably likely to have a future material effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources. +27 +Item 7A. Quantitative and Qualitative Disclosures about Market Risk. +TransAct is a smaller reporting company, as defined in Item 10(f)(1) of Regulation S-K, and is not required to provide information under this item. +Item 8. Financial Statements and Supplementary Data. +The financial statements of the Company are annexed to this Annual Report as pages F-5 through F-23. The “Report of Independent Registered Public Accounting Firm” is annexed to this Annual Report as of page F-2. An index to such materials appears on page F-1. +Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +Not applicable. +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +Our management, with the participation of our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), evaluated the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Exchange Act as of December 31, 2020. In the Amendment to our Annual Report on Form 10-K for the year ended December 31, 2018, filed with the SEC on November 21, 2019, we disclosed that management, including our CEO and CFO, concluded that our disclosure controls and procedures were not effective as of December 31, 2018, due to material weaknesses in our internal control over financial reporting as described below. As of December 31, 2020, one material weakness was not fully remediated and our disclosure controls and procedures were not effective as of December 31, 2020. Management has begun remediation efforts, which are described below. +Notwithstanding these material weaknesses, our management, including our CEO and CFO, has concluded that our consolidated financial statements, included in this Form 10-K, fairly present, in all material respects, our financial condition, results of operations and cash flows for the periods presented in conformity with generally accepted accounting principles, and that they can still be relied upon. +Management’s Annual Report on Internal Control Over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act, to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements. +Our management assessed our internal control over financial reporting as of December 31, 2020. Our management based its assessment on criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“2013 COSO”). In the opinion of management, TransAct did not maintain effective internal control over financial reporting as of December 31, 2020 solely because of the material weakness in internal control over financial reporting described below that existed as of December 31, 2018 and has not been remediated as of December 31, 2020. +A material weakness is defined in Rule 12b-2 under the Exchange Act as a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis. +Material Weaknesses in Internal Control Over Financial Reporting +We identified the following control deficiency that constituted a material weakness in our internal control over financial reporting as of December 31, 2019 and 2018 which has been fully remediated as of December 31, 2020. +● +We did not design and maintain effective controls over user access within the Company’s ERP system, Oracle, to ensure appropriate segregation of duties and to adequately restrict user access to appropriate personnel. Specifically, the provisioning and user recertification controls were not designed to ensure that users maintain proper segregation of duties and, as a result, users could have had inappropriate access rights (the “Access Control Weakness”). +28 +We identified the following control deficiency that constituted a material weakness in our internal control over financial reporting as of December 31, 2020 and 2019. +● +We did not design and maintain effective controls over the completeness and accuracy of information included in key spreadsheets supporting our accounting records (the “Spreadsheet Control Weakness”). +These control deficiencies constituted material weaknesses, but did not result in a material misstatement to our annual or interim consolidated financial statements. However, if the remaining material weakness is not remediated, a material misstatement of account balances or disclosures may not be prevented, and may go undetected, which could result in a material misstatement of future annual or interim consolidated financial statements. +Remediation Efforts to Address Material Weaknesses +Beginning December 31, 2019, we commenced developing and implementing a plan to enhance the design and operating effectiveness of our internal control over financial reporting, which includes taking the following steps to remediate the identified control deficiencies and material weaknesses: +● +To address the Access Control Weakness, we utilized the services of an Oracle consulting firm and an accounting firm unrelated to our Independent Registered Accounting Firm, to assist us in analyzing and reviewing Oracle access for all users. During the first quarter of 2020, we completed the analysis and deployed an action plan. Based on this analysis and action plan, during the second quarter of 2020, we created new Oracle responsibilities for each employee for which a conflict was identified to remove Oracle transactional responsibilities that we believed to be conflicting and reassigned those responsibilities to a different employee to ensure proper segregation of duties. We completed the implementation of the new Oracle responsibilities for all users in July 2020. During the third quarter of 2020, we completed the enhancement and implementation provisioning and user certification controls to ensure we maintain the appropriate segregation of duties within Oracle. The Access Control Weakness was deemed to be remediated as of September 30, 2020. +● +To address the Spreadsheet Control Weakness, for each key spreadsheet we plan to evaluate and determine (1) if a standard Oracle report exists containing the same information as the spreadsheet, and if so, we would utilize the standard Oracle report (without modification) instead of the spreadsheet to support our accounting records and (2) if a standard Oracle report cannot be used, we will implement a new key control whereby an employee performs a formal validation that the information from Oracle is completely and accurately transferred (automatically or manually) to a spreadsheet by verifying totals and other information on a test basis. For all key spreadsheets, we plan to design and implement a new key control to validate the completeness and accuracy of information supporting our accounting records. During 2020, we began the process of evaluating each key spreadsheet based on the above criteria, and for several key spreadsheets, we implemented a new key control to validate the completeness and accuracy of the information contained within and supporting each such spreadsheet. +We believe these steps will address the remaining material weakness described above. +Changes in Internal Control over Financial Reporting +Other than the changes intended to remediate the material weakness noted above, no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the three months ended December 31, 2020 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. +Item 9B. Other Information. +Not applicable. +29 +PART III +Item 10. Directors, Executive Officers and Corporate Governance. +Set forth in Item 1 of this Form 10-K is certain information regarding our executive officers. The remaining information in response to this item will be contained in our Proxy Statement for our 2021 Annual Meeting of Stockholders (the “Proxy Statement”) under the headings, “Delinquent Section 16(a) Reports,” “Corporate Governance,” “Proposal 1: Election of Directors,” “Audit Committee Report,” “Executive Compensation – Compensation Committee Report,” “Stockholder Proposals for 2022 Annual Meeting,” “Procedures for Submitted Director Nominations and Recommendations” and “Policy Regarding Stockholder Communications with the Board of Directors,” which will be filed within 120 days after the end of the year covered by this Form 10-K and is incorporated herein by reference. +Code of Ethics +We maintain a Standards of Business Conduct and Code of Ethics that includes our code of ethics that is applicable to all employees, including our Chief Executive Officer, Chief Financial Officer and Controller. Our Standards of Business Conduct, which requires continued observance of high ethical standards, such as honesty, integrity and compliance with the law in the conduct of our business, is available for public access on our Internet website at https://transacttech.gcs-web.com/corporate-governance. Any person may request a copy of our Standards of Business Conduct free of charge by calling (203) 859-6800. +Item 11. Executive Compensation. +The information in response to this item will be contained in the Proxy Statement under the heading “Executive Compensation,” and is incorporated herein by reference. +Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. +Set forth below is certain information regarding our equity compensation plans. The remaining information in response to this item will be contained in the Proxy Statement under the heading, “Security Ownership of Certain Beneficial Owners and Management,” and is incorporated herein by reference. +Equity Compensation Plan Information +Information regarding our equity compensation plans as of December 31, 2020 is as follows: +Plan category +(a) +Number of +securities to be +issued upon exercise +of outstanding +options, warrants +and rights +(b) +Weighted- +average +exercise price +of outstanding +options, warrants +and rights +(c) +Number of securities +remaining available for +future issuance under +equity compensation plans +(excluding securities +reflected in column (a) +Equity compensation plans approved by security holders: +2005 Equity Incentive Plan +291,000 +$ +9.47 +– +2014 Equity Incentive Plan +1,107,155 +7.95 +837,204 +Total +1,398,155 +$ +8.27 +837,204 +In May 2014, our stockholders approved the adoption of the 2014 Equity Incentive Plan. In May 2020, our stockholders approved an amendment to the 2014 Equity Incentive Plan to increase the number of common stock which may be subject to awards granted under the plan from 1,400,000 to its current level of 2,200,000. The Company also maintains the 2005 Equity Incentive Plan; however no new awards will be available for future issuance under this plan. Both plans generally provide for award in the form of: (i) incentive stock options, (ii) non-qualified stock options, (iii) restricted stock, (iv) restricted stock units (which may include performance-based vesting), (v) stock appreciation rights or (vi) limited stock appreciation rights. The Company does not have any equity plans that have not been approved by its stockholders. +Item 13. Certain Relationships and Related Transactions, and Director Independence. +The information in response to this item will be contained in the Proxy Statement under the headings “Certain Relationships and Related Transactions” and is incorporated herein by reference. +Item 14. Principal Accountant Fees and Services. +The information in response to this item will be contained in the Proxy Statement under the headings, “Policy Regarding Pre-Approval of Services Provided by the Independent Registered Public Accounting Firm” and “Independent Registered Public Accounting Firm’s Services and Fees” and is incorporated herein by reference. +30 +PART IV +Item 15. Exhibits and Financial Statement Schedules. +(a) +The following documents are filed as part of this Form 10-K: +1. +Financial Statements. +Report of Independent Registered Public Accounting Firm +Consolidated Balance Sheets as of December 31, 2020 and 2019 +Consolidated Statements of Operations for the years ended December 31, 2020 and 2019 +Consolidated Statements of Comprehensive (Loss) Income for the years ended December 31, 2020 and 2019 +Consolidated Statements of Changes in Shareholders’ Equity for the years ended December 31, 2020 and 2019 +Consolidated Statements of Cash Flows for the years ended December 31, 2020 and 2019 +Notes to Consolidated Financial Statements +2. +Schedules. +All schedules are omitted because they are either inapplicable or not required, or because the information required therein is included in the Consolidated Financial Statements and Notes thereto. +3. Exhibits. +Exhibits Index +3.1(a) +Certificate of Incorporation of TransAct Technologies Incorporated (conformed copy) (incorporated by reference to Exhibit 3(i) of the Company’s Quarterly Report on Form 10-Q (SEC File No. 000-21121) filed with the SEC on August 9, 2019). +3.1(b) +Certificate of Designation, Series A Preferred Stock, filed with the Secretary of State of Delaware on December 2, 1997 (incorporated by reference to Exhibit C of the Company’s Current Report on Form 8-K (SEC File No. 000-21121) filed with the SEC on February 18, 1999). +3.1(c) +Certificate of Designation, Series B Preferred Stock, filed with the Secretary of State of Delaware on April 6, 2000 (incorporated by reference to Exhibit 3.1(c) of the Company’s Quarterly Report on Form 10-Q (SEC File No. 000-21121) filed with the SEC on May 8, 2000). +3.2 +Amended and Restated By-laws of the Company (incorporated by reference to Exhibit 3.1 of the Company’s Current Report on Form 8-K (SEC File No. 000-21121) filed with the SEC on August 2, 2019). +4.1 +Specimen Common Stock Certificate (incorporated by reference to Exhibit 4.1 of the Company’s Registration Statement on Form S-1/A (No. 333-06895) filed with the SEC on August 1, 1996). +4.2 +Description of Securities (incorporated by reference to Exhibit 4.2 of the Company’s Annual Report on Form 10-K (SEC File No. +000-21121) filed with the SEC on March 16, 2020). +10.1 (x) +2005 Equity Incentive Plan (incorporated by reference to Exhibit 99.1 of the Company’s Current Report on Form 8-K (SEC File No. 000-21121) filed with the SEC on June 1, 2005). +10.2 (x) +TransAct Technologies Incorporated 2014 Equity Incentive Plan, as Amended and Restated (incorporated by reference to Exhibit A to the Definitive Proxy Statement on Schedule 14A filed with the Commission on April 23, 2020, File No. 000-21121). +10.3 (x) +2014 Equity Incentive Plan Time-based Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q (SEC File No. 000-21121) filed with the SEC on May 6, 2016). +10.4 (x) +2014 Equity Incentive Plan Performance-based Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q (SEC File No. 000-211121) filed with the SEC on August 8, 2016). +10.5 (x) +Employment Agreement, dated July 31, 1996, by and between TransAct and Bart C. Shuldman (incorporated by reference to Exhibit 10.20 of the Company’s Registration Statement on Form S-1/A (No. 333-06895) filed with the SEC on August 1, 1996). +10.6 (x) +Severance Agreement by and between TransAct and Steven A. DeMartino, dated June 1, 2004 (incorporated by reference to Exhibit 10.8 of the Company’s Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 16, 2005). +10.7 (x) +Severance Agreement by and between TransAct and Tracey S. Chernay, dated July 29, 2005 (incorporated by reference to Exhibit 10.9 of the Company’s Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 14, 2008). +10.8 (x) +Amendment to Employment Agreement, effective January 1, 2008, by and between TransAct and Bart C. Shuldman (incorporated by reference to Exhibit 10.10 of the Company’s Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 16, 2009). +10.9 (x) +Amendment to Severance Agreement by and between TransAct and Steven A. DeMartino, effective January 1, 2008 (incorporated by reference to Exhibit 10.12 of the Company’s Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 16, 2009). +10.10 (x) +Amendment to Severance Agreement by and between TransAct and Tracey S. Chernay, effective January 1, 2008 (incorporated by reference to Exhibit 10.14 of the Company’s Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 16, 2009). +10.11 +Lease Agreement by and between Bomax Properties and Ithaca, dated as of March 23, 1992 (incorporated by reference to Exhibit 10.14 of the Company’s Registration Statement on Form S-1 (No. 333-06895) filed with the SEC on June 26, 1996). +10.12 +Second Amendment to Lease Agreement by and between Bomax Properties and Ithaca, dated December 2, 1996 ( incorporated by reference to Exhibit 10.27 of the Company’s Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 31, 1998). +31 +10.13 +Agreement regarding the Continuation and Renewal of Lease by and between Bomax Properties, LLC and TransAct, dated July 18, 2001 (incorporated by reference to Exhibit 10.8 of the Company’s Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 29, 2002). +10.14 +Amendment No. 1 to Lease Agreement between Bomax Properties, LLC and TransAct (incorporated by reference to Exhibit 10.16 of the Company’s Quarterly Report on Form 10-Q (SEC File No. 000-21121) filed with the SEC on May 10, 2012). +10.15 +Amendment No. 2 to Lease Agreement between Bomax Properties, LLC and TransAct, dated January 14, 2016 (incorporated by reference to Exhibit 10.13 of the Company’s Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 11, 2016). +10.16 +Amendment No. 3 to Lease Agreement between Bomax Properties, LLC and TransAct, dated February 28, 2020 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (SEC File No. 000-21121) filed with the SEC on March 4, 2020). +10.17 +Lease Agreement by and between Las Vegas Airport Properties LLC and TransAct dated December 2, 2004 (incorporated by reference to Exhibit 10.13 of the Company’s Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 16, 2005). +10.18 +First Amendment to Lease Agreement by and between Las Vegas Airport Properties LLC and TransAct dated August 31, 2009 (incorporated by reference to Exhibit 10.19 of the Company’s Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 16, 2010). +10.19 +Second Amendment to Lease Agreement by and between The Realty Associates Fund IX LP and TransAct dated June 30, 2015 (incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q (SEC File No. 000-21121) filed with the SEC on August 7, 2015). +10.20 +Lease Agreement by and between 2319 Hamden Center I, L.L.C. and TransAct dated November 27, 2006 (incorporated by reference to Exhibit 10.14 of the Company’s Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 15, 2007). +10.21 +First Amendment to Lease by and between 2319 Hamden Center I, L.L.C. and TransAct dated January 3, 2017 (incorporated by reference to Exhibit 10.20 of the Company’s Annual Report on Form 10-K (SEC File No. 000-21121) filed with the SEC on March 16, 2017). +10.22 +Loan and Security Agreement, dated as of March 13, 2020, among Siena Lending Group LLC, TransAct Technologies Incorporated and the other Loan Parties from time to time party thereto (incorporated by reference to Exhibit 10.2 of the Company’s Quarterly Report on Form 10-Q (SEC File No. 000-21121) filed with the SEC on May 22, 2020). +10.23 +Note, dated May 1, 2020, by TransAct Technologies Incorporated in favor of Berkshire Bank (incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K (SEC File No. 000-21121) filed with the SEC on May 5, 2020). +10.24 † +Master License Agreement dated February 22, 2019 and amendments thereto. +1 0.25 † +Master Development and License Agreement dated July 20, 2018. +21 * +Subsidiaries of the Company +23.1 * +Consent of Marcum LLP +23.2 * +Consent of PricewaterhouseCoopers LLP (predecessor auditor). +31.1 * +Rule 13a-14(a) Certification of Chief Executive Officer in accordance with Section 302 of the Sarbanes-Oxley Act of 2002. +31.2 * +Rule 13a-14(a) Certification of Chief Financial Officer in accordance with Section 302 of the Sarbanes-Oxley Act of 2002. +32 ‡ +Certification of Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. +101.INS +Inline XBRL Instance Document (the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document). +101.SCH +Inline XBRL Taxonomy Extension Schema Document. +101.CAL +Inline XBRL Taxonomy Extension Calculation Linkbase Document. +101.DEF +Inline XBRL Taxonomy Extension Definition Linkbase Document. +101.LAB +Inline XBRL Taxonomy Extension Label Linkbase Document. +101.PRE +Inline XBRL Taxonomy Extension Presentation Linkbase Document. +104 +Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). +(x) +Management contract or compensatory plan or arrangement. +* +These exhibits are filed herewith. +† +Certain portions of this exhibit (indicated by “[***]”) have been omitted pursuant to Item (601)(b)(10) of Regulation S-K. +‡ +Furnished herewith. +(b) +Exhibits. +The Exhibits required by Item 601 of Regulation S-K under the Exchange Act are included in the Exhibit Index above under a(3) of this Item 15. +(c) +Financial Statement Schedules. +See the Notes to the Consolidated Financial Statements included in this Form 10-K. +Item 16. Form 10-K Summary. +Not applicable. +32 +SIGNATURES +Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. +TRANSACT TECHNOLOGIES INCORPORATED +By: +/s/ Bart C. Shuldman +Name: +Bart C. Shuldman +Title: +Chairman of the Board and Chief Executive Officer +Date: March 12, 2021 +Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. +Signature +Title +Date +/s/ Bart C. Shuldman +Chairman of the Board and Chief Executive Officer +March 12, 2021 +Bart C. Shuldman +(Principal Executive Officer) +/s/ Steven A. DeMartino +President, Chief Financial Officer, Treasurer and Secretary +March 12, 2021 +Steven A. DeMartino +(Principal Financial Officer) +/s/ David B. Peters +Vice President and Chief Accounting Officer +March 12, 2021 +David B. Peters +(Principal Accounting Officer) +/s/ John M. Dillon +Director +March 12, 2021 +John M. Dillon +/s/ Randall S. Friedman +Director +March 12, 2021 +Randall S. Friedman +/s/ Emanuel P. N. Hilario +Director +March 12, 2021 +Emanuel P. N. Hilario +/s/ Haydee Olinger +Director +March 12, 2021 +Haydee Olinger +/s/ Thomas R. Schwarz +Director +March 12, 2021 +Thomas R. Schwarz +33 +TRANSACT TECHNOLOGIES INCORPORATED +INDEX TO FINANCIAL STATEMENTS +Financial Statements +Report of Independent Registered Public Accounting Firm +F-2 +Consolidated Balance Sheets as of December 31, 2020 and 2019 +F-5 +Consolidated Statements of Operations for the years ended December 31, 2020 and 2019 +F-6 +Consolidated Statements of Comprehensive (Loss) Income for the years ended December 31, 2020 and 2019 +F-7 +Consolidated Statements of Changes in Shareholders’ Equity for the years ended December 31, 2020 and 2019 +F-8 +Consolidated Statements of Cash Flows for the years ended December 31, 2020 and 2019 +F-9 +Notes to Consolidated Financial Statements +F-10 +F- 1 +Report of Independent Registered Publi c Accounting Firm +To the Shareholders and Board of Directors of Transact Technologies Incorporated +Opinion on the Financial Statements +We have audited the accompanying consolidated balance sheet of TransAct Technologies Incorporated and its subsidiaries (the “Company”) as of December 31, 2020, the related consolidated statements of operations, comprehensive loss , changes in shareholders’ equity and cash flows for the year in the period ended December 31, 2020, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020, and the results of its operations and its cash flows for the year in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America. +Basis for Opinion +These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's consolidated financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit , we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. +Our audit included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audit provides a reasonable basis for our opinion. +Critical Audit Matters +The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. +Revenue recognition – Identification of Distinct Performance Obligations and Estimate of Standalone Selling Price +As described in Note 2 to the consolidated financial statements, some of the Company’s contracts with customers contain multiple performance obligations (most commonly when contracts include a hardware product, software and extended warranties). A contract's transaction price is allocated to each distinct performance obligation and recognized as revenue when, or as, the performance obligation is satisfied. The transaction price is determined based on the consideration to which the Company will be entitled in exchange for transferring services to the customer. For a majority of the Company’s revenue, which consists of printers, terminals, consumables, and replacement parts, the Company recognizes revenue as of a point of time; the revenue is recognized upon shipment of the order when control of the goods is transferred to the customer and at the time the performance obligation is fulfilled. Performance obligations are satisfied over time if the customer receives the benefits as the Company performs work. The Company’s cloud-based BOHA! software, provided on a subscription basis, allows customers to use hosted software over the contract period without taking possession of the software and is recognized ratably over the contract period. For extended warranties, the transaction price is recognized ratably over the warranty period, using output methods, as control of the services is transferred to the customer. When there is more than one performance obligation in a customer arrangement, the Company typically uses the “standalone selling price” method to determine the transaction price to allocate to each performance obligation. +F- 2 +In 2020, the Company launched a new service offering related to BOHA! that bundled the BOHA! products (cloud-based SaaS software applications, hardware and after-market service) in one price payable monthly over a three year period. During the year ended December 31, 2020, the Company recognized revenue from contracts with customers related to this new service offering in the amount of approximately $928 thousand. Judgement was required by management to identify the performance obligations in the contract and allocate the transaction price to each performance obligation. +The principal considerations for our determination that revenue recognition, specifically related to management’s identification of distinct performance obligations and the estimation of standalone selling prices related to this new service offering, is a critical audit matter are that there was significant judgment by management in (1) the identification of distinct performance obligations related to this new service offering, specifically the determination that one distinct performance obligation existed for point in time revenue recognition and three distinct performance obligations existed for over-time revenue recognition, (2) the estimation of the standalone selling price using market pricing conditions and other observable inputs, such as historical pricing practices, for each distinct performance obligation; (3) the determination that a significant financing component existed in the arrangement with the customer, therefore, requiring deferral of a portion of the point in time revenue to be recognized as interest income over the contract period; (4) management’s election of the accounting policy expedient to exclude sales taxes collected from customers from the transaction price in accordance with ASU 2016-12; and (5) the identification of costs incurred to obtain the contract and management’s decision to defer such costs and recognize the expense on a straight-line basis over the life of the contract. This in turn led to a high degree of auditor judgment and subjectivity in performing our audit procedures, which were designed to evaluate audit evidence related to management’s identification of distinct performance obligations within the contract with the customer related to this new service offering and the judgments made by management to estimate the standalone selling prices used to allocate the transaction price to those distinct performance obligations identified. Due to this complexity, there was significant effort in performing our audit procedures to evaluate the reasonableness of management’s estimates used in the Company’s adoption of the accounting standard related to revenue recognition for this new service offering. +Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included, among others, (i) evaluating the Company’s revenue recognition accounting policy resulting from its adoption of the accounting standard related to revenue recognition; (ii) evaluating management’s identification of distinct performance obligations in its contract with the customer; (iii) evaluating management’s process for estimating the standalone selling price which included testing the completeness and accuracy of input data used and evaluating the reasonableness of significant assumptions used by management, principally observable inputs such as historical pricing practices; and (iv) evaluation of the accuracy of management’s allocation of the transaction price to the performance obligations contained within the related contract with the customer. +/s/ Marcum llp +Marcum llp +We have served as the Company’s auditor since 2020. +Hartford, Connecticut +March 12, 2021 +F- 3 +Report of Independent Registered Public Accounting Firm +To the Board of Directors and Shareholders of Transact Technologies Incorporated +Opinion on the Financial Statements +We have audited the consolidated balance sheet of TransAct Technologies Incorporated and its subsidiaries (the “Company”) as of December 31, 2019, and the related consolidated statements of operations, comprehensive (loss) income, changes in shareholders’ equity and cash flows for the year then ended, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019, and the results of its operations and its cash flows for the year then ended in conformity with accounting principles generally accepted in the United States of America. +Basis for Opinion +These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audit of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. +Our audit included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audit provides a reasonable basis for our opinion. +/s/ PricewaterhouseCoopers LLP +Hartford, Connecticut +March 16, 2020 +We served as the Company’s auditor from 1996 to 2020. +F- 4 +TRANSACT TECHNOLOGIES INCORPORATED +CONSOLIDATED BALANCE SHEETS +(In thousands, except share data) +December 31, +2020 +December 31, +2019 +Assets: +Current assets: +Cash and cash equivalents +$ +10,359 +$ +4,203 +Accounts receivable, net +3,377 +6,418 +Note receivable +100 +1,017 +Inventories +11,286 +12,099 +Prepaid income taxes +2,409 +180 +Other current assets +644 +998 +Total current assets +28,175 +24,915 +Fixed assets, net +1,950 +2,244 +Notes receivable, net of current portion +1,584 +– +Right-of-use asset +3,618 +2,855 +Goodwill +2,621 +2,621 +Deferred tax assets +2,939 +2,565 +Intangible assets, net +583 +817 +Other assets +777 +44 +14,072 +11,146 +Total assets +$ +42,247 +$ +36,061 +Liabilities and Shareholders’ Equity: +Current liabilities: +Accounts payable +$ +1,691 +$ +2,960 +Accrued liabilities +3,665 +3,041 +Lease liability +837 +945 +Deferred revenue +504 +700 +Total current liabilities +6,697 +7,646 +Long-term debt +2,173 +– +Deferred revenue, net of current portion +111 +219 +Lease liability, net of current portion +2,864 +2,104 +Other liabilities +166 +166 +5,314 +2,489 +Total liabilities +12,011 +10,135 +Commitments and contingencies (Note 15) +Shareholders’ equity: +Preferred stock, $ 0.01 value, 4,800,000 authorized, none issued and outstanding +– +– +Preferred stock, Series A, $ 0.01 par value, 200,000 authorized, none issued and outstanding +– +– +Common stock, $ 0.01 par value, 20,000,000 authorized at December 31, 2020 and 2019; 12,976,227 and 11,515,090 shares issued; 8,931,385 and 7,470,248 shares outstanding, at December 31, 2020 and 2019, respectively +130 +115 +Additional paid-in capital +42,536 +32,604 +Retained earnings +19,718 +25,348 +Accumulated other comprehensive loss, net of tax +( 38 +) +( 31 +) +Treasury stock, 4,044,842 shares, at cost +( 32,110 +) +( 32,110 +) +Total shareholders’ equity +30,236 +25,926 +Total liabilities and shareholders’ equity +$ +42,247 +$ +36,061 +See accompanying notes to Consolidated Financial Statements. +F- 5 +TRANSACT TECHNOLOGIES INCORPORATED +CONSOLIDATED STATEMENTS OF OPERATIONS +(In thousands, except per share data) +Year Ended December 31, +2020 +2019 +Net sales +$ +30,595 +$ +45,748 +Cost of sales +17,666 +23,813 +Gross profit +12,929 +21,935 +Operating expenses: +Engineering, design and product development +5,703 +4,393 +Selling and marketing +6,144 +8,033 +General and administrative +9,255 +9,166 +21,102 +21,592 +Operating (loss) income +( 8,173 +) +343 +Interest and other income (expense): +Interest expense +( 130 +) +( 28 +) +Interest income +78 +17 +Other, net +56 +35 +4 +24 +(Loss) income before income taxes +( 8,169 +) +367 +Income tax benefit +2,539 +149 +Net (loss) income +$ +( 5,630 +) +$ +516 +Net (loss) income per common share: +Basic +$ +( 0.72 +) +$ +0.07 +Diluted +$ +( 0.72 +) +$ +0.07 +Shares used in per-share calculation: +Basic +7,827 +7,466 +Diluted +7,827 +7,677 +Dividends declared and paid per common share: +$ +- +$ +0.36 +See accompanying notes to Consolidated Financial Statements. +F- 6 +TRANSACT TECHNOLOGIES INCORPORATED +CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME +(In thousands) +Year Ended December 31, +2020 +2019 +Net (loss) income +$ +( 5,630 +) +$ +516 +Foreign currency translation adjustment, net of tax +( 7 +) +51 +Comprehensive (loss) income +$ +( 5,637 +) +$ +567 +See accompanying notes to Consolidated Financial Statements. +F- 7 +TRANSACT TECHNOLOGIES INCORPORATED +CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY +(In thousands, except share data) +Common Stock +Additional +Paid-in +Retained +Treasury +Accumulated +Other +Comprehensive +Total +Shares +Amount +Capital +Earnings +Stock +Income (Loss) +Equity +Balance, January 1, 2019 +7,418,299 +$ +115 +$ +32,129 +$ +27,515 +$ +( 32,110 +) +$ +( 82 +) +$ +27,567 +Issuance of common stock on restricted stock units +45,167 +– +– +– +– +– +– +Issuance of common stock on deferred stock units +28,231 +– +– +– +– +– +– +Relinquishment of stock awards and deferred stock units to pay withholding taxes +( 21,449 +) +– +( 217 +) +– +– +– +( 217 +) +Dividends declared and paid on common stock +– +– +– +( 2,683 +) +– +– +( 2,683 +) +Share-based compensation expense +– +– +692 +– +– +– +692 +Foreign currency translation adjustment, net of tax +– +– +– +– +– +51 +51 +Net income +– +– +– +516 +– +– +516 +Balance, December 31, 2019 +7,470,248 +$ +115 +$ +32,604 +$ +25,348 +$ +( 32,110 +) +$ +( 31 +) +$ +25,926 +Issuance of shares from exercise of stock options +62,500 +1 +374 +– +– +– +375 +Issuance of common stock on restricted stock units +32,725 +– +– +– +– +– +– +Issuance of common stock, net of issuance cost +1,380,000 +14 +8,723 +– +– +– +8,737 +Relinquishment of stock awards and deferred stock units to pay withholding taxes +( 14,088 +) +– +( 41 +) +– +– +– +( 41 +) +Share-based compensation expense +– +– +876 +– +– +– +876 +Foreign currency translation adjustment, net of tax +– +– +– +– +– +( 7 +) +( 7 +) +Net loss +– +– +– +( 5,630 +) +– +– +( 5,630 +) +Balance, December 31, 2020 +8,931,385 +$ +130 +$ +42,536 +$ +19,718 +$ +( 32,110 +) +$ +( 38 +) +$ +30,236 +See accompanying notes to Consolidated Financial Statements. +F- 8 +TRANSACT TECHNOLOGIES INCORPORATED +CONSOLIDATED STATEMENTS OF CASH FLOWS +(In thousands) +Year Ended December 31, +2020 +2019 +Cash flows from operating activities: +Net (loss) income +$ +( 5,630 +) +$ +516 +Adjustments to reconcile net (loss) income to net cash (used in) provided by operating activities: +Share-based compensation expense +876 +692 +Depreciation and amortization +1,342 +1,371 +Deferred income tax benefit +( 367 +) +( 294 +) +(Recovery of) provision for doubtful accounts +( 1 +) +16 +Foreign currency transaction (gains) losses +( 58 +) +18 +Changes in operating assets and liabilities: +Accounts receivable +2,976 +1,589 +Inventories +876 +796 +Prepaid income taxes +( 2,226 +) +577 +Other current and long term assets +( 198 +) +( 333 +) +Accounts payable +( 1,276 +) +( 517 +) +Accrued liabilities and other liabilities +176 +415 +Net cash (used in) provided by operating activities +( 3,510 +) +4,846 +Cash flows from investing activities: +Capital expenditures +( 744 +) +( 1,062 +) +Additions to capitalized software +– +( 304 +) +Issuance of note receivable +( 600 +) +( 1,000 +) +Net cash used in investing activities +( 1,344 +) +( 2,366 +) +Cash flows from financing activities: +Revolving credit line borrowings +2,756 +– +Revolving credit line payments +( 2,756 +) +– +Long-term debt borrowings +2,173 +– +Proceeds from stock option exercises +375 +– +Payment of dividends on common stock +– +( 2,683 +) +Proceeds from the issuance of common stock +9,798 +– +Payment of common stock issuance costs +( 1,061 +) +– +Withholding taxes paid on stock issuance +( 41 +) +( 214 +) +Payment of bank financing costs +( 213 +) +– +Net cash provided by (used in) financing activities +11,031 +( 2,897 +) +Effect of exchange rate changes on cash and cash equivalents +( 21 +) +( 71 +) +Increase (decrease) in cash and cash equivalents +6,156 +( 488 +) +Cash and cash equivalents, beginning of period +4,203 +4,691 +Cash and cash equivalents, end of period +$ +10,359 +$ +4,203 +Supplemental cash flow information: +Interest paid +$ +64 +$ +30 +Income taxes paid +46 +65 +Non-cash capital expenditure items +25 +17 +See accompanying notes to Consolidated Financial Statements. +F- 9 +TRANSACT TECHNOLOGIES INCORPORATED +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +1. Description of business +TransAct Technologies Incorporated (together with its subsidiaries, “TransAct,” the “Company,” “we,” “us,” or “our”), which has its headquarters in Hamden, Connecticut and its primary operating facility in Ithaca, New York, operates in one operating segment: software-driven technology and printing solutions for high growth markets including food service technology, casino and gaming, POS automation, and oil and gas markets. Our solutions are designed from the ground up based on market and customer requirements and are sold under the BOHA! TM , AccuDate™, Epic®, Ithaca®, EPICENTRAL TM and Printrex® product brands. We sell our products to original equipment manufacturers, value-added resellers, select distributors, and directly to end-users. Our product distribution spans across the Americas, Europe, the Middle East, Africa, Asia, Australia, New Zealand, the Caribbean Islands and the South Pacific. TransAct also provides world-class service, spare parts, accessories and printing supplies to its growing worldwide installed base of products. We also generate revenue from the after-market side of the business, providing printer and terminal service, consumables and spare parts in addition to revenue from our two software solutions; (i) our line of BOHA! software applications used to automate the back-of-house operations of restaurants, convenience stores and food service operators and (ii) the EPICENTRAL TM Print System (“EPICENTRAL TM ”), that enables casino operators to create promotional coupons and marketing messages and print them in real time at the slot machine. +Impact of the COVID-19 Pandemic +The unprecedented and rapid spread of COVID-19 and the resulting social distancing measures, including closures and restricted openings of restaurants and casinos implemented by federal, state and local authorities, have significantly reduced recent customer demand and disrupted portions of our supply chain, including delayed product shipments from our two manufacturers located in China and Thailand. We are monitoring indicators of demand recovery, including our sales pipeline, customer orders and product shipments to ascertain an estimate of the ultimate impact of the COVID-19 pandemic on our business; however, the length and ultimate severity of the reduction in demand due to the pandemic remains uncertain. +While we began to experience a modest recovery during the second half of 2020 and expect this recovery to continue in 2021, the exact timing and pace of recovery is unknown given uncertainty surrounding responsive measures to potential future resurgences of the virus and the significant disruption that our customers have already experienced and may continue to experience. In light of this uncertainty, we implemented measures to help mitigate the impact on our financial position and operations. These measures include, but are not limited to, the following: +Expense Management. With the reduction in net sales, we implemented the following cost saving initiatives during 2020: +● +a reduction of our workforce starting in July 2020 by approximately 20 % through a combination of employee terminations and temporary furloughs. During the fourth quarter, we brought back all furloughed employees. As of December 31, 2020 our overall headcount was reduced by approximately 16 % when compared to December 31, 2019; +● +a 10 % reduction in the salaries of all salaried, non-commissioned employees, including executive officers, starting in March 2020. From May 1, 2020 until early July 2020, employees below the vice president level were paid their full salary as a result of the receipt of the PPP Loan proceeds (defined below). All employees’ full salaries were reinstated on January 1, 2021; +● +a reduction in sales commissions for all commissioned employees starting in March 2020 through the end of 2020; +● +a 10 % reduction of cash retainer fees for all non-employee directors starting in March 2020 through the end of 2020; and +● +the elimination of discretionary spending wherever possible starting in March 2020 and continuing into the first quarter of 2021. +Balance Sheet, Cash Flow and Liquidity. In addition to the expense management actions noted above, we took the following actions to increase liquidity and strengthen our financial position. +● +Public Offering – On October 16, 2020, the Company raised net proceeds of $ 8.7 million, after deducting underwriting discounts, commissions and offering expenses, through an underwritten public offering (the “Offering”) and sold an aggregate of 1,380,000 shares of common stock. +● +PPP Loan – On May 1, 2020, the Company was granted a $ 2.2 million loan (the “PPP Loan”) under the Paycheck Protection Program (the “PPP”) administered by the Small Business Administration (“SBA”) established under Division A, Title I of the Coronavirus Aid, Relief, and Economic Security (“CARES”) Act, which enabled us to return our furloughed employees to full time employment and to restore certain pay cuts until the PPP Loan proceeds were exhausted. +● +New Credit Facility – On March 13, 2020, we entered into a new credit facility with Siena Lending Group LLC that provides a revolving credit line of up to $ 10.0 million, subject to a borrowing base. +● +Reduced Capital Expenditures – We limited capital expenditures during 2020. +F- 10 +We may further modify or supplement the expense management measures we have implemented and the actions we have taken to increase liquidity as the timing and extent of customer demand recovery develops. +After reviewing whether conditions and/or events raise substantial doubt about our ability to meet future financial obligations over the 12 months following the date on which the Consolidated Financial Statements included in this Form 10-K (this “Report”) were issued, including consideration of the actions taken to manage expenses and liquidity, we believe that our net cash to be provided by operations combined with our cash and cash equivalents, borrowing availability under our revolving credit facility and the net proceeds from the Offering will provide sufficient liquidity to fund our current obligations, capital spending, and working capital requirements and to comply with the financial covenants of our credit facility over at least 12 months following the date that the Consolidated Financial Statements were issued. +Use of Assumptions and Estimates +Management’s belief that the Company will be able to fund its planned operations over the 12 months following the date on which the Consolidated Financial Statements were issued is based on assumptions which involve significant judgment and estimates of future revenues, capital expenditures and other operating costs. Our current assumptions are that casinos and restaurants remain open and continue to gradually increase capacity limitations during 2021, but that many casinos and restaurants may delay purchases of new slot machines and our BOHA! products, respectively, due to the extended business closures and continuing capacity limitations. Based on these assumptions, we anticipate that sales in casino and gaming and food service technology will continue to be negatively impacted for the foreseeable future. We have performed a sensitivity analysis on these assumptions to forecast the potential impact of a slower-than-anticipated recovery and believe that we are positioned to withstand the impact of lower-than-anticipated sales and that we will be able to take additional financial and operational actions to cut costs and/or increase liquidity if necessary. These actions may include additional expense reductions and capital raising activities. +In addition, the presentation of the accompanying audited Consolidated Financial Statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenue and expenses, and the disclosure of contingent assets and liabilities. Our estimates include those related to revenue recognition, inventory obsolescence, the valuation of deferred tax assets and liabilities, depreciable lives of equipment, warranty obligations, and contingent liabilities. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances. Actual results could differ from those estimates used. +Smaller Reporting Company +As a smaller reporting company, as defined in Item 10(f)(1) of Regulation S-K, we may choose to prepare our disclosures relying on certain scaled disclosure requirements for smaller reporting companies in Regulation S-K and in Article 8 of Regulation S-X. +The scaled disclosure requirements for smaller reporting companies permit us (i) to include less extensive narrative disclosure than required of other reporting companies, particularly in the description of executive compensation and (ii) to provide audited financial statements for two fiscal years, in contrast to other reporting companies, which must provide audited financial statements for three years. +We may lose our status as a smaller reporting company on the last day of the fiscal year in which (i) our public float exceeds $250 million or (ii) if we have more than $100 million in annual revenues and (a) have no public float or (b) have a public float more than $700 million. +2. Summary of significant accounting policies +Principles of consolidation: The accompanying Consolidated Financial Statements include the accounts of TransAct and its wholly-owned subsidiaries, which require consolidation, after the elimination of intercompany accounts, transactions and unrealized profit. +Use of estimates : The preparation of Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America (“GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses, and disclosure of contingent assets and liabilities as of the date of the Consolidated Financial Statements and the reported amounts of sales and expenses during the reporting period. Actual results could differ from those estimates. +Segment reporting : We apply the provisions of the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) 280, “Segment Reporting.” We view our operations and manage our business as one segment: the design, development and marketing of software-driven technology and printing solutions and providing printer and terminal related software, services, supplies and spare parts. Factors used to identify TransAct’s single operating segment include the organizational structure of the Company and the financial information available for evaluation by the chief operating decision-maker in making decisions about how to allocate resources and assess performance. +Cash and cash equivalents : We consider all highly liquid investments with a maturity date of three months or less at date of purchase to be cash equivalents. +Allowance for doubtful accounts : We establish an allowance for doubtful accounts to ensure trade receivables are valued appropriately. We maintain an allowance for doubtful accounts based on a variety of factors, including the length of time receivables are past due, significant one-time events and historical experience. We record a specific allowance for individual accounts when we become aware of a customer’s inability to meet its financial obligations, such as in the case of bankruptcy filings or deterioration in the customer’s operating results or financial position. If circumstances related to customers change, we further adjust estimates of the recoverability of receivables. +F- 11 +The following table summarizes the activity recorded in the valuation account for accounts receivable: +Year Ended December 31, +(In thousands) +2020 +2019 +Balance, beginning of period +$ +221 +$ +205 +Additions charged to costs and expenses +1 +39 +Deductions +( 2 +) +( 23 +) +Balance, end of period +$ +220 +$ +221 +Inventories: Inventories are stated at the lower of cost (principally standard cost, which approximates actual cost on a first-in, first-out basis) or net realizable value. We review net realizable value based on estimated selling prices in the ordinary course of business less estimated costs of completions, disposal and transportation, historical usage and estimates of future demand. Based on these reviews, inventory write-downs are recorded, as necessary, to reflect estimated obsolescence, excess quantities and net realizable value. +Fixed assets: Fixed assets are stated at cost. Depreciation is recorded using the straight-line method over the estimated useful lives. The estimated useful life of tooling is five years ; machinery and equipment is ten years ; furniture and office equipment is five years to ten years ; and computer software and equipment is three years to seven years . Leasehold improvements are amortized over the shorter of the term of the lease or the useful life of the asset. Costs related to repairs and maintenance are expensed as incurred. The costs of sold or retired assets are removed from the related asset and accumulated depreciation accounts and any gain or loss is recognized. Depreciation expense was $ 1.0 million and $ 1.1 million in 2020 and 2019, respectively. +Leases: We account for leases in accordance with ASC 842, “Leases” (“ASC 842”) which we adopted effective January 1, 2019. The adoption required a modified retrospective transition approach, applying the new standard to all leases existing at the date of initial application. An entity was allowed to choose to use either (1) its effective date or (2) the beginning of the earliest comparative period presented in the financial statements as its date of initial application. The Company elected to adopt the standard using the effective date, January 1, 2019, as its date of initial application. +The standard requires lessees to apply a dual approach, classifying leases as either finance or operating leases based on the principle of whether or not the lease is effectively a financed purchase by the lessee. This classification determines whether lease expense is recognized based on an effective interest method for finance leases or on a straight-line basis over the term of the lease for operating leases. A lessee is also required to record a right-of-use asset and a lease liability for all leases with a term of greater than 12 months regardless of their classification. Leases with a term of 12 months or less are accounted for based on existing guidance for operating leases. If risks and rewards are conveyed without the transfer of control, the lease is treated as financing. If the lessor does not convey risks and rewards or control, the lease is treated as operating. +We have elected certain practical expedients available under ASC 842 upon adoption. We have applied the practical expedient which allows prospective transition to ASC 842 on January 1, 2019. Under this transition practical expedient, we did not reassess lease classification, embedded leases or initial direct costs. We have applied the practical expedient for short-term leases. We have lease agreements that include lease and non-lease components, and we have not elected the practical expedients to combine these components for any of our leases. The adoption of ASC 842 had no effect on our Consolidated Statements of Operations. Upon adoption of ASC 842 on January 1, 2019, we recorded a $ 3.7 million right-of-use asset and a $ 3.9 million lease liability. The adoption of the new standard had no impact on retained earnings. +We enter into lease agreements for the use of real estate space and certain other equipment under operating leases and we have no financing leases. We determine if an arrangement contains a lease at inception. Our leases are included in Right of use assets and Lease liabilities in our Condensed Consolidated Balance Sheet. +Right of use assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. Lease right of use assets and liabilities are recognized at the commencement date of the lease based on the present value of lease payments over the lease term. Our right-of-use-asset and lease liability was higher at December 31, 2020 compared to December 31, 2019 due to the extension of one of our leases. On February 28, 2020, we entered into an amendment to extend the lease on our facility in Ithaca, New York, which resulted in recording an additional right-of-use-asset and lease liability of $ 1.5 million. The lease, which was last amended on January 14, 2016, was scheduled to expire on May 31, 2021. The lease amendment provides for an extension of the lease for four additional years from June 1, 2021 to May 31, 2025. Lease expense is recognized on a straight-line basis over the lease term. As most of our leases do not provide an implicit rate, the Company determines its incremental borrowing rate by using the rate of interest that the Company would have to pay to borrow on a collateralized basis over a similar term, an amount equal to the lease payments in a similar economic environment. Our lease right of use assets exclude lease incentives. Our leases have remaining lease terms of one year to seven years , some of which include options to extend. The majority of our leases with options to extend provide for extensions of up to five years . The exercise of lease renewal options is at our sole discretion and our lease right of use assets and liabilities reflect only the options we are reasonably certain that we will exercise. Lease expense is recognized on a straight-line basis over the lease term. +F- 12 +Goodwill and Intangible assets : We acquire businesses in purchase transactions that result in the recognition of goodwill and intangible assets. The determination of the value of intangible assets requires management to make estimates and assumptions. In accordance with ASC 350-20 “Goodwill,” acquired goodwill is not amortized but is subject to impairment testing at least annually and when an event occurs or circumstances change that indicate it is more likely than not an impairment exists. We perform a fair value-based impairment test to the carrying value of goodwill and indefinite-lived intangible assets on an annual basis (as of December 31) and, if certain events or circumstances indicate that an impairment loss may have been incurred, on an interim basis. The Company utilizes the option to first assess qualitative factors to determine whether it is necessary to perform the Step 1 quantitative goodwill impairment test in accordance with the applicable accounting standards. Under the qualitative assessment, management considers relevant events and circumstances including but not limited to macroeconomic conditions, industry and market considerations, Company performance and events directly affecting the Company. If the Company determines that the Step 1 quantitative impairment test is required, management estimates the fair value of the reporting unit primarily using the income approach, which reflects management’s cash flow projections, and also evaluates the fair value using the market approach. Factors considered that may trigger an interim period impairment review of either acquired goodwill or intangible assets are: significant underperformance relative to expected historical or projected future operating results; significant changes in the manner of use of acquired assets or the strategy for the overall business; significant negative industry or economic trends; and significant decline in market capitalization relative to net book value. Finite lived intangible assets are amortized and are tested for impairment when appropriate. +During the three months ended March 31, 2020, our stock price declined to the lowest price since 2009. We determined that the significant decline in our market capitalization and broader economic downturn arising from the COVID-19 pandemic was a triggering event and an indicator that it was more likely than not that the carrying value of goodwill exceeded fair value. Therefore, we concluded that quantitative analyses were required to be performed due to the triggering event occurring during the first quarter of 2020. We utilized an implied market value method under the market approach to calculate the fair value of the Company as of March 31, 2020, which we determined was the best approximation of fair value in the current social and economic environment. Based on our interim impairment assessment as of March 31, 2020, we determined that no goodwill or intangible asset impairment occurred and the fair value of goodwill was substantially higher than our carrying value. +As of December 31, 2020, we have determined that no goodwill or intangible asset impairment has occurred and the fair value of goodwill was substantially higher than our carrying value based on our assessment as of December 31, 2020 when our annual review for impairment was performed. +Revenue recognition: We account for revenue in accordance with ASC Topic 606: Revenue from Contracts with Customers. In accordance with ASC 606, a performance obligation is a promise in a contract with a customer to transfer a distinct good or service to the customer. Some of our contracts with customers contain a single performance obligation, while other contracts contain multiple performance obligations (most commonly when contracts include a hardware product, software and extended warranties). A contract’s transaction price is allocated to each distinct performance obligation and recognized as revenue when, or as, the performance obligation is satisfied. +The transaction price is determined based on the consideration to which the Company will be entitled in exchange for transferring services to the customer. To the extent the transaction price includes variable consideration, such as price protection, reserves for returns and other allowances, the Company estimates the amount of variable consideration that should be included in the transaction price utilizing either the “expected value” method or the “most likely amount” method depending on the nature of the variable consideration. Variable consideration is included in the transaction price if, in the Company’s judgment, it is probable that a significant future reversal of cumulative revenue under the contract will not occur. +For a majority of our revenue, which consists of printers, terminals, consumables, and replacement parts, the Company recognizes revenue as of a point of time. The transaction price is recognized upon shipment of the order when control of the goods is transferred to the customer and at the time the performance obligation is fulfilled. We also sell a software solution in our casino and gaming market, EPICENTRAL™, that enables casino operators to create promotional coupons and marketing messages and to print them in real time at the slot machine. EPICENTRAL TM is primarily comprised of both a software component, which is licensed to the customer, and a hardware component. EPICENTRAL™ software and hardware are integrated to deliver the system’s full functionality. The transaction prices from EPICENTRAL™ software license and hardware are recognized upon installation and formal acceptance by the customer when control of the license is transferred to the customer. For out-of-warranty repairs, the transaction price is recognized after the repair work is completed and the printer or terminal is returned to the customer, as control of the product is transferred to the customer and our performance obligation is completed. +Performance obligations are satisfied over time if the customer receives the benefits as we perform work, if the customer controls the asset as it is being produced, or if the product being produced for the customer has no alternative use and we have a contractual right to payment. For our separately priced extended warranty, BOHA! cloud-based software applications, technical support for our food service technology terminals and maintenance agreements (including free one-year maintenance received by customers upon completion of EPICENTRAL™ installation) revenue is recognized over time as the customer receives the benefit. The transaction price from the maintenance services is recognized ratably over time, using output methods, as control of the services is transferred to the customer. Our cloud-based BOHA! software allows customers to use hosted software over the contract period on a subscription basis without taking possession of the software and the subscription price is recognized ratably over the contract period. For extended warranties, the transaction price is recognized ratably over the warranty period, using output methods, as control of the services is transferred to the customer. +When there is more than one performance obligation in a customer arrangement, the Company typically uses the “standalone selling price” method to determine the transaction price to allocate to each performance obligation. The Company sells the performance obligations separately and has established standalone selling prices for its products and services. In the case of an overall price discount, the discount is applied to each performance obligation proportionately based on standalone selling price. To determine the standalone selling price for initial EPICENTRAL™ installations, the Company uses the adjusted market assessment approach. +For contracts with terms of less than 12 months, the Company expenses sales commissions as they are incurred, since the expected amortization period of the cost to obtain a contract is less than 12 months. +F- 13 +Disaggregation of revenue +The following table disaggregates our revenue by market type, as we believe it best depicts how the nature, amount, timing and uncertainty of our revenue and cash flows are affected by economic factors. Sales and usage-based taxes are excluded from revenues. +Year Ended December 31, 2020 +(In thousands) +United States +International +Total +Food service technology +$ +6,956 +$ +778 +$ +7,734 +POS automation and banking +3,763 +7 +3,770 +Casino and gaming +6,852 +4,127 +10,979 +Lottery +817 +– +817 +Printrex +83 +217 +300 +TransAct Services Group +6,262 +733 +6,995 +Total net sales +$ +24,733 +$ +5,862 +$ +30,595 +Year Ended December 31, 2019 +(In thousands) +United States +International +Total +Food service technology +$ +5,522 +$ +582 +$ +6,104 +POS automation and banking +5,714 +44 +5,758 +Casino and gaming +13,076 +8,453 +21,529 +Lottery +1,290 +1 +1,291 +Printrex +961 +205 +1,166 +TransAct Services Group +8,769 +1,131 +9,900 +Total net sales +$ +35,332 +$ +10,416 +$ +45,748 +Contract balances +Contract assets consist of unbilled receivables. Pursuant to the over-time revenue recognition model, revenue may be recognized prior to the customer being invoiced. An unbilled receivable is recorded to reflect revenue that is recognized when such revenue exceeds the amount invoiced to the customer. Unbilled receivables are separated into current and non-current assets and included within “Accounts Receivable” and “Other Non-Current Assets” on the Consolidated Balance Sheets as of December 31, 2020. We first recorded contract assets during 2020 upon the start of a long-term BOHA! contract. +Contract liabilities consist of customer prepayments and deferred revenue. Customer prepayments are reported as “Accrued Liabilities” in current liabilities in the Condensed Consolidated Balance Sheets and represent customer payments made in advance of performance obligations in instances where credit has not been extended and is recognized as revenue when the performance obligation is complete. Deferred revenue is reported separately in current liabilities and non-current liabilities and consists of our extended warranty contracts, technical support for our food service technology terminals, EPICENTRAL™ maintenance contracts and prepaid software subscriptions for our BOHA! software applications, and is recognized as revenue as (or when) we perform under the contract. The decrease in current deferred revenue in 2020 compared to 2019 is primarily due to delayed renewals of our EPICENTRAL™ maintenance contracts from COVID-19 related closures of casinos during 2020. Non-current deferred revenue decreased primarily due to decreased sales of long-term extended warranties for a legacy POS printer. During the year ended December 31, 2020, we recognized revenue of $ 1.3 million related to our contract liabilities as of December 31, 2019. +Net contract assets (liabilities) consist of the following: +December 31, +(In thousands) +2020 +2019 +Unbilled receivables, current +$ +290 +$ +– +Unbilled receivables, non-current +591 +– +Customer pre-payments +( 216 +) +( 232 +) +Deferred revenue, current +( 504 +) +( 700 +) +Deferred revenue, non-current +( 111 +) +( 219 +) +Net contract assets (liabilities) +$ +50 +$ +( 1,151 +) +Remaining performance obligations +Remaining performance obligations represent the transaction price of firm orders for which a good or service has not been delivered to our customer. As of December 31, 2020, the aggregate amount of the transaction price allocated to remaining performance obligations was $ 4.4 million. The Company expects to recognize revenue on $ 3.8 million of our remaining performance obligations within the next 12 months, $ 0.4 million within the next 24 months and the balance of these remaining performance obligations recognized within the next 36 months. +F- 14 +Concentration of credit risk: Financial instruments that potentially expose us to concentrations of credit risk are limited to cash and cash equivalents held by our banks in excess of insured limits and accounts receivable. +Accounts receivable from customers representing 10% or more of total accounts receivable were as follows: +December 31, +2020 +2019 +International Gaming Technology (“IGT”) +11 +% +15 +% +Scientific Games +– +10 +% +Sales to customers representing 10% or more of total net sales were as follows: +December 31, +2020 +2019 +IGT +15 +% +14 +% +Warranty: We generally warrant our products for up to 24 months and record the estimated cost of such product warranties at the time the sale is recorded. Estimated warranty costs are based upon actual past experience of product repairs and the related estimated cost of labor and material to make the necessary repairs. +The following table summarizes the activity recorded in the accrued product warranty liability: +December 31, +(In thousands) +2020 +2019 +Balance, beginning of period +$ +215 +$ +273 +Warranties issued +56 +181 +Warranty settlements +( 131 +) +( 239 +) +Balance, end of period +$ +140 +$ +215 +$ 112 thousand and $ 174 thousand of the accrued product warranty liability were classified as current in Accrued liabilities at December 31, 2020 and 2019, respectively. The remaining $ 28 thousand and $ 41 thousand of the accrued product warranty liability as of December 31, 2020 and 2019, respectively, is classified as long-term in Other liabilities. +Engineering, design and product development: Engineering, design and product development expenses include expenses incurred in connection with specialized engineering and design to introduce new products and to customize existing products, and are expensed as a component of operating expenses as incurred. We recorded $ 5.7 million and $ 4.4 million of research and development expenses in 2020 and 2019, respectively. +Costs incurred in the engineering, design and product development of a computer software product are charged to expense until technological feasibility has been established, at which point all material software costs are capitalized within Intangible assets in our Consolidated Balance Sheet until the product is available for general release to customers. While judgment is required in determining when technological feasibility of a product is established, we have determined that it is reached after all high-risk development issues have been documented in a formal detailed plan design. The amortization of these costs have been included in cost of sales over the estimated life of the product. During 2019, we contracted several third-parties to develop software for our food service technology products, the cost for which we capitalized. Unamortized development costs for such software were $ 551 thousand as of December 31, 2020. The total amount charged to cost of sales for capitalized software development costs was $ 153 thousand and $ 186 thousand in 2020 and 2019, respectively. +Advertising: Advertising costs are expensed as incurred. Advertising expenses, which are included in selling and marketing expense on the accompanying Consolidated Statements of Operations, for 2020 and 2019 totaled $ 0.7 million and $ 1.4 million, respectively. These expenses include items such as consulting and professional services, tradeshows, and print advertising. +Income taxes: The income tax amounts reflected in the accompanying Consolidated Financial Statements are accounted for under the liability method in accordance with ASC 740, “Income Taxes” (“ASC 740”). Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. We assess the likelihood that net deferred tax assets will be realized from future taxable income, and to the extent that we believe that realization is not likely, we establish a valuation allowance. In accordance with ASC 740, we identified, evaluated and measured the amount of benefits to be recognized for our tax return positions. +Foreign currency translation: The financial position and results of operations of our foreign subsidiary in the UK are measured using local currency as the functional currency. Assets and liabilities of such subsidiary have been translated into U.S. dollars at the year-end exchange rate, related sales and expenses have been translated at the exchange rate as of the date the transaction was recognized, and shareholders’ equity has been translated at historical exchange rates. The resulting translation gains or losses, net of tax, are recorded in shareholders’ equity as a cumulative translation adjustment, which is a component of accumulated other comprehensive income. Foreign currency transaction gains and losses, including those related to intercompany balances, are recognized in Other, net on the Consolidated Statements of Operations. +F- 15 +Share-based payments: At December 31, 2020, we have share-based employee compensation plans, which are described more fully in Note 10 - Stock incentive plans. We account for those plans under the recognition and measurement principles of ASC 718, “Compensation – Stock Compensation”. Share-based compensation expense is measured at the grant date, based on the estimated fair value of the award, and is recognized as expense over the employee’s requisite service period. +We use the Black-Scholes option-pricing model to calculate the fair value of share-based awards. The key assumptions for this valuation method include the expected term of the option, stock price volatility, risk-free interest rate, dividend yield, market price of our underlying stock and exercise price. Many of these assumptions are require judgment and are highly sensitive in the determination of compensation expense. Forfeitures are recognized as they occur. +Net income and loss per share: We report net income or loss per share in accordance with ASC 260, “Earnings per Share (EPS).” Under this guidance, basic EPS, which excludes dilution, is computed by dividing income or loss available to common shareholders by the weighted average number of common shares outstanding for the period. Diluted EPS reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. Diluted EPS includes in-the-money stock options using the treasury stock method. During a loss period, the assumed exercise of in-the-money stock options has an anti-dilutive effect, and therefore, these instruments are excluded from the computation of diluted EPS. See Note 12 - Earnings per share. +3. Note receivable +The note receivable balance relates to loans given to a third party software developer for whom we license our food service technology software with an interest rate of 4.5 % , which were due in April 2020. We intend to collect the remaining principal and interest due under the note pursuant to a lender recourse provision that enables us to apply payments that would have been due to the third party under revenue sharing provisions of a previously signed license agreement towards the loan balance. A $ 100 thousand royalty fee was scheduled to be paid to the third party in January 2021 that was instead applied towards the note receivable balance as it became due. As a result $ 100 thousand of the balance was classified as current and the remaining $ 1.6 million is expected to be reduced thereafter using the lender recourse provision. Notes receivable are stated at unpaid balances and interest income is recognized on the accrual method. As of December 31, 2020 , we have no allowances for loan losses, unamortized deferred loan fees or unearned discounts. +4. Inventories +The components of inventories are: +December 31, +(In thousands) +2020 +2019 +Raw materials and purchased component parts +$ +5,467 +$ +7,724 +Finished goods +5,819 +4,375 +$ +11,286 +$ +12,099 +5. Fixed assets, net +The components of fixed assets, net are: +December 31, +(In thousands) +2020 +2019 +Tooling, machinery and equipment +$ +9,508 +$ +9,175 +Furniture and office equipment +1,706 +1,694 +Computer software and equipment +7,364 +7,062 +Leasehold improvements +2,873 +2,696 +21,451 +20,627 +Less: Accumulated depreciation and amortization +( 19,979 +) +( 19,010 +) +1,472 +1,617 +Construction in-process +478 +627 +$ +1,950 +$ +2,244 +F- 16 +6. Intangible assets, net +Identifiable intangible assets are recorded in Intangible assets in the accompanying Consolidated Balance Sheets and are comprised of the following: +December 31, +2020 +2019 +(In thousands) +Gross Amount +Accumulated Amortization +Gross Amount +Accumulated Amortization +Purchased technology +$ +2,526 +$ +( 1,975 +) +$ +2,526 +$ +( 1,792 +) +Customer relationships +1,300 +( 1,300 +) +1,300 +( 1,300 +) +Trademark +480 +( 450 +) +480 +( 402 +) +Covenant not to compete +146 +( 146 +) +146 +( 146 +) +Patents +56 +( 54 +) +56 +( 51 +) +Other +80 +( 80 +) +80 +( 80 +) +Total +$ +4,588 +$ +( 4,005 +) +$ +4,588 +$ +( 3,771 +) +Amortization expense was $ 234 thousand and $ 284 thousand in 2020 and 2019 , respectively. Amortization expense for each of the next five years ending December 31 is expected to be as follows: $ 188 thousand in 2021; $ 154 thousand in 2022; $ 154 thousand in 2023; $ 87 thousand in 2024; and none thereafter. +7. Accrued liabilities +The components of accrued liabilities are: +December 31, +(In thousands) +2020 +2019 +Salaries and compensation related +$ +2,328 +$ +1,541 +Warranty +112 +174 +Professional and consulting +257 +465 +Other +968 +861 +$ +3,665 +$ +3,041 +8. Retirement savings plan +We maintain a 401(k) plan under which all full-time employees are eligible to participate at the beginning of the month immediately following their date of hire. We match employees’ contributions at a rate of 50 % of employees’ contributions up to the first 6 % of the employees’ compensation contributed to the 401(k) plan. Our matching contributions were $ 270 thousand and $ 305 thousand in 2020 and 2019, respectively. +9. Borrowings +On March 13, 2020, we entered into a new credit facility (the “Siena Credit Facility”) with Siena Lending Group LLC. The Siena Credit Facility provides for a revolving credit line of up to $ 10.0 million expiring on March 13, 2023 . Borrowings under the Siena Credit Facility bear a floating rate of interest equal to the greatest of (i) the prime rate plus 1.75 %, (ii) the federal funds rate plus 2.25 %, and (iii) 6.50 %. The total deferred financing costs related to expenses incurred to complete the Siena Credit Facility was $ 245 thousand, which were reported as “other current assets” in current assets and “other assets” in non-current assets in the Condensed Consolidated Balance Sheets. We also pay a fee of 0.50 % on unused borrowings under the facility. Borrowings under the facility are secured by a lien on substantially all the assets of the Company. The Siena Credit Facility imposes a minimum EBITDA financial covenant on the Company and borrowings are subject to a borrowing base based on (i) 85 % of eligible accounts receivable plus the lesser of (a) $ 5.0 million and (b) 50 % of eligible raw material and 60 % of finished goods inventory. As of December 31, 2020, we had $ 4.5 million of borrowing capacity available under the Siena Credit Facility and had no outstanding borrowings. We were in compliance with all financial covenants of the Siena Credit Facility at December 31, 2020. +Prior to entering the Siena Credit Facility, we maintained a credit facility with TD Bank N.A. (“TD Bank) which provided for a $ 20 million revolving credit line. Borrowings under the revolving credit line bore a floating rate of interest at the prime rate minus one percent and were secured by a lien on all our assets. We also paid a fee of 0.125 % on unused borrowings under the revolving credit line. +On May 1, 2020 (the “Loan Date”), the Company was granted the PPP Loan from Berkshire Bank in the aggregate amount of $ 2.2 million, pursuant to the PPP. +F- 17 +The PPP Loan, which is evidenced by a Note dated the Loan Date issued by the Company (the “Note”) in favor of Berkshire Bank, as lender (the “PPP Lender”), matures on May 1, 2022 and bears interest at a fixed rate of 1.0 % per annum, accruing from the Loan Date and payable monthly. No payments were due on the PPP Loan for six months from the date of first disbursement, and if a loan forgiveness application is submitted to the SBA within 10 months after the end of the covered period, no payments are due until the date on which the SBA remits the loan forgiveness amount to the PPP Lender (or notifies the PPP Lender that no loan forgiveness is allowed), but interest continues to accrue during the deferment period. If no loan forgiveness is allowed, the Company will be required to pay the PPP Lender equal monthly payments of principal and interest based on the principal amount outstanding on the PPP Loan, plus interest outstanding at the end of the deferment period, and taking into account any reductions in the principal amount due to forgiveness, if any. The Note is unsecured and guaranteed by the SBA. The Note may be prepaid by the Company at any time prior to maturity with no prepayment penalties. The Note provides for customary defaults, including failure to make payment when due or to fulfill the Company’s obligations under the Note or related documents, reorganizations, mergers, consolidations or other changes to the Company’s business structure, and certain defaults on other indebtedness, bankruptcy events, adverse changes in financial condition or civil or criminal actions. The PPP Loan may be accelerated upon the occurrence of a default. +Under the terms of the PPP, the PPP Loan may be forgiven to the extent that funds from the PPP Loan are used for payroll costs and costs to continue group health care benefits, as well as for interest on mortgage obligations incurred before February 15, 2020, rent under lease agreements in effect before February 15, 2020, utilities for which service began before February 15, 2020, and interest on debt obligations incurred before February 15, 2020 (collectively, “qualifying expenses”), subject to conditions and limitations provided in the CARES Act. At least 60% (as amended) of the proceeds from the PPP Loan must be used for eligible payroll costs for the PPP Loan to be forgiven. The Company has maximized the use of PPP Loan proceeds for qualifying expenses and intends to apply for forgiveness of the PPP Loan in accordance with the terms of the CARES Act, as amended by the Paycheck Protection Flexibility Act of 2020. Whether forgiveness will be granted and in what amount is subject to an application to, and approval by, the SBA and may also be subject to further requirements in any regulations and guidelines the SBA may adopt. The PPP Loan is classified as “Long-term debt” in the Condensed Consolidated Balance Sheet until the forgiveness determination has been made by the SBA. In the event that no portion of the PPP Loan is forgiven by the SBA, $1.5 million in principal and interest of the $2.2 million PPP Loan would be due in 2021 with the remaining balance due in 2022. +10. Stock incentive plans +Stock incentive plans . We currently have two primary stock incentive plans: the 2005 Equity Incentive Plan and the 2014 Equity Incentive Plan, which provide for awards to executives, key employees, directors and consultants. The plans generally provide for awards in the form of: (i) incentive stock options, (ii) non-qualified stock options, (iii) restricted stock, (iv) restricted stock units (which may include performance-based vesting), (v) stock appreciation rights or (vi) limited stock appreciation rights. Awards granted under these plans have exercise prices equal to 100 % of the fair market value of the common stock at the date of grant. Awards granted have a ten-year term and generally vest over a two-year to five-year period, unless automatically accelerated for certain defined events. As of May 2014, no new awards may be made under the 2005 Equity Incentive Plan. Under our 2014 Equity Incentive Plan, as amended in May 2020, we are authorized to grant awards of up to 2,200,000 shares of TransAct common stock. At December 31, 2020, 837,204 shares of common stock remained available for issuance under the 2014 Equity Incentive Plan. +Under the assumptions indicated below, the weighted-average per share fair value of stock option grants for 2020 and 2019 was $ 3.19 and $ 3.01 , respectively. We also issued restricted stock units for certain executives and directors that vest over a specified period of time, and in some instances require achieving certain performance metrics. The weighted-average per share fair value of these restricted stock units was $ 9.77 and $ 10.46 in 2020 and 2019, respectively. +The table below indicates the key assumptions used in the option valuation calculations for options granted in 2020 and 2019 and a discussion of our methodology for developing each of the assumptions used in the valuation model: +December 31, +2020 +2019 +Expected option term (in years) +7.0 +6.8 +Expected volatility +41.7 +% +38.8 +% +Risk-free interest rate +0.9 +% +2.6 +% +Dividend yield +0.0 +% +3.5 +% +Expected Option Term - This is the weighted average period of time over which the options granted are expected to remain outstanding giving consideration to our historical exercise patterns. Options granted have a maximum term of ten years and an increase in the expected term will increase compensation expense. +Expected Volatility – The stock volatility for each grant is measured using the weighted average of historical daily price changes of our common stock over the most recent period approximately equal to the expected option term of the grant. An increase in the expected volatility factor will increase compensation expense. +Risk-Free Interest Rate - This is the U.S. Treasury rate in effect at the time of grant having a term approximately equal to the expected term of the option. An increase in the risk-free interest rate will increase compensation expense. +Dividend Yield –The dividend yield is calculated by dividing the annual dividend declared per common share by the weighted average market value of our common stock on the date of grant. An increase in the dividend yield will decrease compensation expense. +F- 18 +For 2020 and 2019, we recorded $ 876 thousand and $ 692 thousand of share-based compensation expense, respectively, included primarily in general and administrative expense in our Consolidated Statements of Operations. We also recorded income tax benefits of $ 193 thousand and $ 152 thousand in 2020 and 2019, respectively, related to such share-based compensation. At December 31, 2020, these benefits are recorded as a deferred tax asset in the Consolidated Balance Sheets. +Equity award activity in the 2005 Equity Incentive Plan and the 2014 Equity Incentive Plan is summarized below: +Stock Options +Restricted Stock Units +Number of Shares +Average Price* +Number of Units +Average Price** +Outstanding at December 31, 2019 +1,142,468 +$ +9.23 +90,575 +$ +10.46 +Granted +245,950 +7.43 +52,700 +9.76 +Exercised +( 62,500 +) +7.79 +( 32,725 +) +9.88 +Forfeited +( 1,563 +) +10.32 +– +– +Expired +( 36,750 +) +8.61 +– +– +Outstanding at December 31, 2020 +1,287,605 +$ +8.98 +110,550 +$ +10.30 +* +weighted average exercise price per share +** +weighted average grant stock price per share +The following summarizes information about equity awards outstanding that are vested and expect to vest and equity awards that are exercisable at December 31, 2020: +Equity Awards Vested and Expected to Vest +Equity Awards That Are Exercisable +Awards +Average Price* +Aggregate Intrinsic Value +Remaining Term** +Awards +Average Price* +Aggregate Intrinsic Value +Remaining Term** +Stock Options +1,287,605 +$ +8.98 +$ +366 +5.8 +809,512 +$ +8.85 +$ +67 +4.2 +Restricted stock units +110,550 +– +785 +2.4 +– +– +– +– +* +weighted average exercise price per share +** +weighted-average contractual remaining term in years +Shares that are issued upon exercise of employee stock awards are newly issued shares and not issued from treasury stock. As of December 31, 2020, unrecognized compensation cost related to non-vested equity awards granted under our stock incentive plans is approximately $ 1.9 million, which is expected to be recognized over a weighted average period of 2.2 years. +The total fair value of awards vested during the years ended December 31, 2020 and 2019 was $ 1.7 million and $ 1.6 million, respectively. The total intrinsic value (which is the amount by which the stock price exceeded the exercise price on the date of exercise) of stock options exercised during the years ended December 31, 2020 was $ 174 thousand and cash received from option exercises was $ 375 thousand in 2020. No stock options were exercised during the year ended December 31, 2019. We recorded a realized tax provision in 2020 from equity-based awards of $ 14 thousand related to options exercised. +11. Income taxes +The components of the income tax benefit are as follows: +December 31, +(In thousands) +2020 +2019 +Current: +Federal +$ +( 2,141 +) +$ +58 +State +17 +51 +Foreign +( 48 +) +(58 +) +( 2,172 +) +51 +Deferred: +Federal +( 483 +) +( 205 +) +State +( 36 +) +5 +Foreign +152 +- +( 367 +) +( 294 +) +Income tax benefit +$ +( 2,539 +) +$ +( 149 +) +Our effective tax rates were 31.1 % and ( 40.6 )% for 2020 and 2019 , respectively. The effective tax rate for 2020 included the impact of the net operating loss (“NOL”) that we expect to carry back to prior years. The CARES Act permits NOLs incurred in 2018, 2019 and 2020 to be carried back to each of the five preceding taxable years to generate a refund of previously paid income taxes. We generated a NOL for 2020 which we will carry back to tax years that had a federal statutory tax rate of 34% compared to 21 % in 2020. We recorded an unusually high tax benefit in 2019 due to the impact of R&D credits on a near break-even level of income before income tax. +F- 19 +At December 31, 2020, we have no federal net operating loss carryforwards and $ 33 thousand of state net operating loss carryforwards, $ 460 thousand in R&D credit carryforwards, and no state tax credit carryforwards. Foreign loss before taxes was $ 468 thousand and $ 515 thousand in 2020 and 2019, respectively. +Deferred income taxes arise from temporary differences between the tax basis of assets and liabilities and their reported amounts in the Consolidated Financial Statements. Our deferred tax assets and liabilities were comprised of the following: +December 31, +(In thousands) +2020 +2019 +Deferred tax assets: +Foreign net operating losses +$ +563 +$ +538 +Depreciation +302 +165 +Inventory reserves +719 +916 +Deferred revenue +47 +58 +Warranty reserve +31 +47 +Stock compensation expense +731 +701 +Other accrued compensation +388 +226 +R&D credit carryforward +460 +111 +Other liabilities and reserves +394 +276 +Gross deferred tax assets +3,635 +3,038 +Valuation allowance +( 659 +) +( 444 +) +Net deferred tax assets +2,976 +2,594 +Deferred tax liabilities: +Other +37 +29 +Net deferred tax liabilities +37 +29 +Total net deferred tax assets +$ +2,939 +$ +2,565 +As of December 31, 2020 a valuation allowance of $ 659 thousand has been established for foreign net operating loss carryforwards that are not expected to be used. The following table summarizes the activity recorded in the valuation allowance on the deferred tax assets: +Year Ended December 31, +(In thousands) +2020 +2019 +Balance, beginning of period +$ +444 +$ +390 +Additions charged to income tax provision +215 +54 +Balance, end of period +$ +659 +$ +444 +Differences between the U.S. statutory federal income tax rate and our effective income tax rate are analyzed below: +Year Ended December 31, +2020 +2019 +Federal statutory tax rate +21.0 +% +21.0 +% +U.S. corporate tax rate change +9.5 +– +R&D credit +4.2 +( 83.2 +) +State income taxes, net of federal income taxes +0.2 +12.0 +Business meals and entertainment +0.1 +5.4 +Miscellaneous permanent items +– +1.4 +Uncertain tax positions +( 0.2 +) +1.0 +Foreign-derived intangible income deduction +– +( 5.4 +) +Stock award excess tax benefit +( 0.3 +) +( 8.4 +) +Stock option cancellations +( 0.5 +) +0.8 +Valuation allowance and tax accruals +( 2.6 +) +14.8 +Other +( 0.3 +) +– +Effective tax rate +31.1 +% +( 40.6 +)% +F- 20 +We had $ 121 thousand and $ 107 thousand of total gross unrecognized tax benefits at December 31, 2020 and 2019, respectively that, if recognized, would favorably affect the effective income tax rate in any future periods. We are not aware of any events that could occur within the next twelve months that could cause a significant change in the total amount of unrecognized tax benefits. A tabular reconciliation of the gross amounts of unrecognized tax benefits at the beginning and end of the year is as follows: +December 31, +(In thousands) +2020 +2019 +Unrecognized tax benefits as of January 1 +$ +107 +$ +104 +Tax positions taken during the current period +41 +28 +Lapse of statute of limitations +( 27 +) +( 25 +) +Unrecognized tax benefits as of December 31 +$ +121 +$ +107 +We expect $ 24 thousand of the $ 121 thousand of unrecognized tax benefits will reverse in 2021 upon the expiration of the statute of limitations. +We recognize interest and penalties related to uncertain tax positions in the income tax provision. We have accrued interest and penalties related to uncertain tax positions of $ 19 thousand and $ 18 thousand as of December 31, 2020 and 2019, respectively. +We are subject to U.S. federal income tax as well as income tax of certain state and foreign jurisdictions. We have substantially concluded all U.S. federal income tax, state and local, and foreign tax matters through 2016. However, our federal tax returns for the years 2017 through 2019 remain open to examination. Various state and foreign tax jurisdiction tax years remain open to examination as well, though we believe that any additional assessment would be immaterial to the Consolidated Financial Statements. +12. Earnings per share +Earnings per share was computed as follows (in thousands, except per share amounts): +Year Ended December 31, +2020 +2019 +Net (loss) income +$ +( 5,630 +) +$ +516 +Shares: +Basic: Weighted average common shares outstanding +7,827 +7,466 +Add: Dilutive effect of outstanding equity awards as determined by the treasury stock method +- +211 +Diluted: Weighted average common and common equivalent shares outstanding +7,827 +7,677 +Net (loss) income per common share: +Basic +$ +( 0.72 +) +$ +0.07 +Diluted +( 0.72 +) +0.07 +The computation of diluted earnings per share excludes the effect of the potential exercise of stock awards, including stock options, restricted stock units and performance stock awards, when the average market price of the common stock is lower than the exercise price of the related stock award during the period. These outstanding stock awards are not included in the computation of diluted earnings per share because the effect would be anti-dilutive. Anti-dilutive stock awards excluded from the computation of earnings per dilutive share were 1,284,000 and 447,000 , at December 31, 2020 and 2019, respectively. +13. Stock repurchase program +We use the cost method to account for treasury stock purchases, under which the price paid for the stock is charged to the treasury stock account. Repurchases of our common stock are accounted for as of the settlement date. During 2020 and 2019 we did no t repurchase any shares of our common stock. From January 1, 2005 through December 31, 2020, we repurchased a total of 4,044,842 shares of common stock for $ 32.1 million, at an average price of $ 7.94 per share. +F- 21 +14. Geographic area information +Information regarding our operations by geographic area is contained in the following table. These amounts in the geographic area table are based on the location of the customer and asset. +Year Ended December 31, +(In thousands) +2020 +2019 +Net sales: +United States +$ +24,733 +$ +35,332 +International +5,862 +10,416 +Total +$ +30,595 +$ +45,748 +Fixed assets, net: +United States +$ +1,079 +$ +1,326 +International +871 +918 +Total +$ +1,950 +$ +2,244 +Sales to international customers were 19 % and 23 % of total sales in 2020 and 2019, respectively. Sales to Europe represented 45 % and 44 %, sales to the Pacific Rim (which includes Australia and Asia) represented 45 % and 46 %, and sales to Canada represented 8 % of total international sales in both 2020 and 2019. International long-lived assets consist of net fixed assets located at our foreign subsidiary in the UK as well as our contract manufacturers in China, Thailand, Malaysia and Mexico. +15. Leases +Operating lease expense for the years ended December 31, 2020 and 2019 was $ 1.0 million and $ 1.0 million, respectively, and are reported as “Cost of sales,” “Engineering, design and product development expense,” “Selling and marketing expense,” and “General and administrative expense” in the Consolidated Statements of Operations. Operating costs include short-term lease costs which were immaterial during the period. +The following information represents supplemental disclosure for the statement of cash flows related to operating leases (in thousands): +Year Ended December 31, +2020 +2019 +Operating cash outflows from leases +$ +1,040 +$ +1,031 +The following summarizes additional information related to our leases as of December 31, 2020: +Year Ended December 31, +2020 +2019 +Weighted average remaining lease term (in years) +4.9 +5.0 +Weighted average discount rate +4.1 +% +3.7 +% +The maturity of the Company’s operating lease liabilities as of December 31, 2020 are as follows (in thousands): +December 31, 2020 +2021 +$ +971 +2022 +879 +2023 +713 +2024 +718 +2025 +464 +Thereafter +180 +Total undiscounted lease payments +3,925 +Less imputed interest +224 +Total lease liabilities +$ +3,701 +F- 22 +16. Quarterly results of operations (unaudited) +Our quarterly results of operations for 2020 and 2019 are as follows: +Quarter Ended +(In thousands, except per share amounts) +March 31 +June 30 +September 30 +December 31 +2020: +Net sales +$ +10,247 +$ +5,285 +$ +7,300 +$ +7,763 +Gross profit +4,918 +2,290 +3,349 +2,372 +Net loss +( 992 +) +( 1,853 +) +( 867 +) +( 1,918 +) +Net loss per common share: +Basic +( 0.13 +) +( 0.25 +) +( 0.11 +) +( 0.22 +) +Diluted +( 0.13 +) +( 0.25 +) +( 0.11 +) +( 0.22 +) +2019: +Net sales +$ +11,550 +$ +11,350 +$ +11,686 +$ +11,162 +Gross profit +6,086 +5,704 +5,546 +4,599 +Net income (loss) +746 +186 +384 +( 800 +) +Net income (loss) per common share: +Basic +0.10 +0.02 +0.05 +( 0.11 +) +Diluted +0.10 +0.02 +0.05 +( 0.11 +) +17. Subsequent events +The Company has evaluated all events or transactions that occurred up to the date the consolidated financial statements were available to issue. Based upon this review, the Company did not identify any subsequent events that would have required adjustment or disclosure in the consolidated financial statements. +F- 23 \ No newline at end of file diff --git a/raw/filings/0001017303/2020/0001017303-21-000020/filing_metadata.csv b/raw/filings/0001017303/2020/0001017303-21-000020/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..e4204dc5b107afef22b11ec92620a492538c569a --- /dev/null +++ b/raw/filings/0001017303/2020/0001017303-21-000020/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001017303,TACT,TRANSACT TECHNOLOGIES INC,10-K,2021-03-12,2020-12-31,2021-03-12T21:50:37.000Z,0001017303-21-000020,form10k2020.htm,"FORM 10K FOR THE YEAR ENDED DECEMBER 31, 2020",9915855,1,1,https://www.sec.gov/Archives/edgar/data/1017303/000101730321000020/form10k2020.htm,https://www.sec.gov/Archives/edgar/data/1017303/000101730321000020/,2020,2020,1 diff --git a/raw/filings/0001017303/2020/0001017303-21-000020/item1.txt b/raw/filings/0001017303/2020/0001017303-21-000020/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..c3a04bf32956b65f3b44b4e7dace6db08b9c28e0 --- /dev/null +++ b/raw/filings/0001017303/2020/0001017303-21-000020/item1.txt @@ -0,0 +1,140 @@ +Item 1. Business. +The Company +TransAct Technologies Incorporated (together with its consolidated subsidiaries, “TransAct,” the “Company,” “we,” “us,” or “our”) was incorporated in June 1996 and began operating as a stand-alone business in August 1996 as a spin-off of the printer business that was formerly conducted by certain subsidiaries of Tridex Corporation. We completed an initial public offering on August 22, 1996. +TransAct is a global leader in developing and selling software-driven technology and printing solutions for high growth markets including food service technology, point of sale (“POS”) automation, casino and gaming, and oil and gas. Our world-class products are designed from the ground up based on market and customer requirements and are sold under the BOHA!™, AccuDate™, Epic®, EPICENTRAL™, Ithaca®, and Printrex® brand names. During 2019, we launched a new line of products for the food service technology market, the BOHA! branded suite of cloud-based applications and companion hardware solutions. The new BOHA! software and hardware products help restaurants, convenience stores and food service operators of all sizes automate the food production in the back-of-house operations. Known and respected worldwide for innovative designs and real-world service reliability, our thermal printers and terminals generate top-quality labels, coupons and transaction records such as receipts, tickets and other documents, as well as printed logging and plotting of data. We sell our technology to original equipment manufacturers (“OEMs”), value-added resellers, select distributors, as well as directly to end-users. Our product distribution spans across the Americas, Europe, the Middle East, Africa, Asia, Australia, New Zealand, Latin America, the Caribbean Islands and the South Pacific. We also offer world-class service, support, labels, spare parts, accessories and printing supplies to our growing worldwide base of products currently in use by our customers. Through our TransAct Services Group (“TSG”), we provide a complete range of supplies and consumables used in the printing activities of customers in the restaurant and hospitality, retail, casino and gaming, government and oil and gas exploration markets. Through our webstore, www.transactsupplies.com , and our direct selling team, we address the demand for these products. Our primary operating, hardware research and development, and U.S. service center is located in Ithaca, New York. In addition, we have a casino and gaming sales headquarters and software research and development in Las Vegas, Nevada; a European sales and service center at our subsidiary in the United Kingdom (“UK”); and a sales office located in Macau, China. Our executive offices are located at One Hamden Center, 2319 Whitney Avenue, Suite 3B, Hamden, Connecticut, 06518, with a telephone number of (203) 859-6800. +1 +Impact of the COVID-19 Pandemic +In December 2019, a novel strain of coronavirus and the disease it causes, commonly known as COVID-19, was first reported in China and has since widely impacted the global public health and economic environment. In March 2020, the World Health Organization declared COVID-19, including all additional variations and strains thereof, a global pandemic. Our business trends through the first two months of 2020 were in line with internal expectations; however, the challenges posed by the COVID-19 pandemic on the United States and global economy increased significantly as the first quarter of 2020 progressed and continued throughout the remainder of 2020. Unfortunately, the massive economic and social disruptions across the world persist due to COVID-19 and the measures implemented to mitigate its spread. The food service, casino and gaming, and oil and gas industries have been particularly affected by the pandemic, and we expect such disruptions to continue to negatively impact our overall business for the foreseeable future. +As a result of the COVID-19 pandemic and measures implemented to mitigate its spread, we experienced decreased demand for our products and lower than anticipated sales beginning in the second half of March 2020 and continuing through the end of 2020, particularly in our food service technology and casino and gaming markets. We experienced some improvement in demand during the second half of 2020 compared to the second quarter of 2020, as some state and local governments lifted certain measures implemented earlier in 2020 to mitigate the spread of the virus, however demand remained lower than 2019, and we expect this trend to continue through at least the first half of 2021. Below is a discussion of the impact of COVID-19 that we have experienced, and that we believe we will continue to experience for the foreseeable future in each of our markets. +Food service technology and POS automation . In both our food service technology and POS automation markets, many restaurants and food service establishments that were closed during much of the second quarter of 2020 started to reopen as state and local governments began to ease restrictions put in place in response to the pandemic. Many of our customers have opened under restrictions that limit them to providing drive through, take-out or delivery service without dine-in options, as well as limiting the volume of customers and employees on site at any one time. During the third and fourth quarters of 2020, we experienced sales improvement compared to the second quarter of 2020, as these food service customers reopened for business. However, during the fourth quarter of 2020, restaurants were again impacted by a resurgence of the pandemic. Notwithstanding the gradual resumption of limited operations that began in the third quarter of 2020, our food service technology and POS automation customers continue to recover from the financial impact of being closed for several months and we expect new capital expenditures to be a lower priority for them in the near term, which we believe will continue to negatively impact sales of BOHA! hardware, software and label products, as well as sales of POS printers. However, food service providers have been and are likely to continue to be required to develop and implement new or enhanced policies and operating procedures regarding cleaning, sanitizing and social distancing to ensure the safety of their employees and customers. We believe that our BOHA! hardware, software and label products could prove to be helpful to our food service customers in efficiently and effectively managing and complying with these new procedures, especially as many establishments are and will likely continue to be operating with reduced staff levels. +Casino and gaming . In the casino and gaming market, most casinos and other gaming establishments were closed worldwide during most of the second quarter of 2020. Many casinos began to reopen in late May and early June 2020, but similar to restaurants, casino openings were slow and measured, starting with reduced capacity and limited game play based on social distancing guidelines. During the fourth quarter of 2020, some casinos re-closed due to a resurgence of the pandemic. We anticipate that casinos will continue to limit capacity in the near term and will progressively increase capacity over time. As casinos gradually recover from the financial impact of being closed for several months, we expect that casinos’ appetite for purchases of new slot machines will be diminished, which we believe is likely to negatively impact sales of casino and gaming printers purchased by slot manufacturers for use in slot machines at casinos during 2021. +Lottery . We exited the lottery market at the end of 2019 and IGT made a final purchase of our lottery printer during the second quarter of 2020. Therefore, COVID-19 has not had an impact our lottery printer sales, and we do not anticipate that it will have an impact on our future lottery printer sales. +Printrex . The oil and gas market has been negatively impacted by the decline in worldwide oil prices attributable to the COVID-19 pandemic. Due to the uncertainty of current and future market conditions, we believe sales of our Printrex oil and gas printers will continue to be negatively impacted until oil and gas prices recover. +TSG . Due to closures and reduced operating capacity of restaurants, food service establishments, casinos and other gaming establishments resulting from the COVID-19 pandemic, sales of spare parts, service and consumable products have declined, and we expect such sales to remain at reduced levels, due to lower usage while the pandemic persists. +Our gross margin has been negatively impacted and we expect our gross margin to continue to be negatively impacted by the COVID-19 pandemic. As a result of an expected significantly lower sales level, we believe our gross margin will decline due to fixed manufacturing overhead expenses (such as facility costs, depreciation, etc.) that cannot be reduced or eliminated even with the lower sales level. +We have also experienced supply chain disruptions, including delayed product shipments from our two contract manufacturers located in China and Thailand that conduct almost all of our printer and terminal manufacturing, due to reduced operations and parts shortages at these facilities. To date, these disruptions have only minimally impacted deliveries to customers due to our high inventory levels and reduced demand for our products. However, if the delays are sustained or additional disruptions from the pandemic occur, we may have insufficient inventory levels and our ability to deliver products to our customers on time or at all may be impaired. +2 +While it is difficult to predict the magnitude of the ultimate impact that the pandemic and the responsive measures will have on our customers and our business, we took several actions during 2020 to manage our expenses during these turbulent and uncertain times. Such steps included: +● +a reduction of our workforce starting in July 2020 by approximately 20% through a combination of employee terminations and temporary furloughs. During the fourth quarter, we brought back all furloughed employees. As of December 31, 2020 our overall headcount was reduced by approximately 16% when compared to December 31, 2019; +● +a 10% reduction in the salaries of all salaried, non-commissioned employees, including executive officers, starting in March 2020. From May 1, 2020 until early July 2020, employees below the vice president level were paid their full salary as a result of the receipt of the PPP Loan proceeds (defined below). All employee full salaries were reinstated on January 1, 2021; +● +a reduction in sales commissions for all commissioned employees starting in March 2020 through the end of 2020; +● +a 10% reduction of cash retainer fees for all non-employee directors starting in March 2020 through the end of 2020; and +● +the elimination of discretionary spending wherever possible starting in March 2020, which has continued into the first quarter of 2021. +In addition, we took measures to increase liquidity, including the following: +● +Public Offering – On October 16, 2020, the Company raised net proceeds of $8.7 million, after deducting underwriting discounts, commissions and offering expenses, through an underwritten public offering (the “Offering”) and sold an aggregate of 1,380,000 shares of common stock. +● +PPP Loan – On May 1, 2020 (the “Loan Date”), the Company was granted a $2.2 million loan (the “PPP Loan”) under the Paycheck Protection Program (the “PPP”) administered by the Small Business Administration (“SBA”) established under Division A, Title I of the Coronavirus Aid, Relief, and Economic Security (“CARES”) Act, which enabled us to return our furloughed employees to full time employment and to restore certain pay cuts until the PPP Loan proceeds were exhausted. +● +New Credit Facility – On March 13, 2020, we entered into a new credit facility with Siena Lending Group LLC that provides a revolving credit line of up to $10.0 million, subject to a borrowing base. +● +Reduced Capital Expenditures – We limited capital expenditures during 2020. +Since the onset of the pandemic, our top priority has been to ensure the health and safety of our employees while continuing to provide our customers with high-quality, personalized service. On March 20, 2020, we instituted work-from-home practices for the majority of our employees to reduce the spread of COVID-19 and to comply with government mandates. Because most of our employees already had laptop computers with remote access into our IT systems, we have experienced only minor reductions in productivity and minimal costs related to the implementation of our work-from-home practices. In addition, even with the move to a work-from-home environment, our existing internal control structure remained operational and unchanged. +Our distribution centers, deemed an essential service, have remained operational throughout the pandemic. We implemented a new COVID-19 policy to specifically address health and safety guidelines for employees to adhere to and follow when at work or returning to work. This policy was based on the COVID-19 safety guidelines recommended by the Centers for Disease Control and Prevention and implements the following operations procedures: +● +staggered shifts and a rotational or flexible work schedule to minimize the number of employees at any particular facility at a single time; +● +mandated use of protective equipment, such as masks and gloves, when in common areas, which is provided to employees; +● +spaced seating in workspaces such as manufacturing cells, lunch/break rooms, conference rooms and other common areas to comply with social distancing guidelines ; +● +employees who (i) show symptoms of COVID-19 or (ii) have been exposed to someone who shows symptoms or has tested positive for COVID-19 are prohibited from reporting to work for 10 days ; +● +visitors are prohibited from entering all facilities ; +● +cleaning and disinfecting protocols at all facilities; and +● +daily temperature checks of all employees before entering all facilities . +We have evaluated the recoverability of the assets on our Consolidated Balance Sheet as of December 31, 2020 in accordance with relevant authoritative accounting literature. We considered the disruptions caused by the COVID-19 pandemic, including lower than previously forecasted sales and customer demand, a decline in the price of our common stock and macroeconomic factors potentially impacting accounts receivable, inventory, investments, intangible assets, goodwill and other assets and liabilities. Where forward-looking estimates are required, we made a good-faith estimate based on information available as of the balance sheet date. We have continued to monitor for indicators of impairment through the date of this Report and reflected accordingly in the accompanying condensed consolidated financial statements. +Notwithstanding the foregoing, there is no assurance that the actions we have taken in response to the pandemic are sufficient or adequate, and we may be required to take additional preventive or responsive measures, as the ultimate extent of the effects of the COVID-19 pandemic on the Company, our financial condition, results of operations, liquidity, and cash flows are uncertain and are dependent on evolving developments which cannot be predicted at this time. See Part I, Item 1A, Risk Factors, of this Form 10-K for further discussion of risks related to COVID-19. +3 +Products, Services and Distribution Methods +Printers, terminals and other hardware: TransAct designs, develops and markets a broad array of transaction-based and specialty printers and terminals utilizing thermal printing technology for applications, primarily in the food service technology, POS automation, casino and gaming, and oil and gas printing markets. Our printers and terminals are configurable and offer customers the ability to choose from a variety of features and functions. Options typically include interface configuration, mounting configuration, paper cutting devices, paper handling capacities and cabinetry color. Our food service technology terminals also offer software configurable menu options. Our food service technology market also includes sales of hardware products including handheld devices, tablets, temperature probes and temperature sensors and gateways. +Food Service Technology: The primary offering in the food service technology market is our BOHA! ecosystem, which combines our latest generation terminal, cloud-based software applications and related hardware into a unique solution to automate back-of-house operations in restaurants, convenience stores and food service operations . The software component of BOHA! consists of a suite of software-as-a-service (“SaaS”)-based applications, including applications for inventory management, temperature monitoring of food and equipment, timers, food safety labeling, food recalls, checklists and procedures, equipment service management, and delivery management. Any and all these applications can be chosen by our customer and packaged into a single platform with the associated hardware, which includes the BOHA! terminal, handheld devices, tablets, temperature probes and temperature sensors and gateways. The BOHA! terminal combines the software and hardware components in a device that includes an operating system, touchscreen and one or two thermal print mechanisms that print easy-to-read food rotation labels, grab-and-go labels for prepared foods, nutritional labels and “enjoy by” date labels. The BOHA! terminal is equipped with the TransAct Enterprise Management System to ensure that only approved applications and functions are available on the device and allows over-the-air updates to the applications and operating system. BOHA! helps food service establishments and restaurants (including fine dining, casual dining, fast casual and quick-serve restaurants, convenience stores, hospitality establishments and contract food service providers) effectively manage food safety and grab-and-go initiatives, as well as automate and manage back-of-house operations. Recurring revenue from BOHA! is generated by software sales, including software subscriptions that are charged to customers upfront on a per-application basis, as well as sales of labels, extended warranty and service contracts, and technical support services. In the food service technology market, we use an internal sales force to solicit sales directly from end users. +POS automation: In the POS market, we sell several models of printers utilizing thermal printing technology. Our POS printers are used primarily by quick-serve restaurants located either at the checkout counter or within self-service kiosks to print receipts for consumers or print on linerless labels. In the POS market, we primarily sell our products through a network of domestic and international distributors and resellers. We use an internal sales force to manage sales through our distributors and resellers, as well as to solicit sales directly from end-users. Prior to 2020, revenue in this market included sales of inkjet printers used by banks, credit unions and other financial institutions to print deposit or withdrawal receipts and/or validate checks at bank teller stations. We exited the banking market during 2018 and therefore do not expect any future sales. In the banking market, we primarily sold our products directly to end-user banks and financial institutions through our internal sales force and, to a lesser extent, resellers. +Casino and gaming: We sell several models of printers used in slot machines and video lottery terminals (“VLTs”) and other gaming machines that print tickets or receipts instead of issuing coins (“ticket-in, ticket-out” or “TITO”) at casinos, racetracks and other gaming venues worldwide. These printers utilize thermal printing technology to print tickets and receipts in monochrome and offer various other features such as jam resistant bezels and a dual port interface that enables casinos to print coupons and promotions. In addition, we sell printers using thermal roll-fed printing technology for use in international non-casino establishments, including game types such as Amusements with Prizes, Skills with Prizes, Fixed Odds Betting Terminals, sports betting establishments and other off-premise gaming type machines around the world. We sell our casino and gaming products primarily (1) to slot machine manufacturers, who incorporate our printers into slot machines and, in turn, sell completed slot machines directly to casinos and other gaming establishments and (2) through distributors. We also maintain a dedicated internal sales force to solicit sales from slot machine manufacturers and casinos, and to manage sales through our distributors. +We also offer a software solution, the EPICENTRAL™ Print System, including annual software maintenance, that enables casino operators to create promotional coupons and marketing messages and to print them in real time at the slot machine. With EPICENTRAL™, casinos can utilize the system to create multiple promotions and incentives to either increase customer time spent on the casino floor or encourage additional visits to generate more revenue to the casinos. In 2019, we introduced EPICENTRAL 4.0, which uses the new Acres 4.0 technology that provides EPICENTRAL with true real time slot machine play data. +Lottery: Our lottery printers are designed for high-volume, high-speed printing of lottery tickets for various lottery applications. We primarily supply lottery printers to International Gaming Technology and its subsidiaries (“IGT”), our largest customer and the world’s largest provider of lottery terminals. During 2019, we decided to exit this business and we expect no future sales beyond 2020. Sales of our lottery products were made directly to IGT and were managed by an internal sales representative before we exited the business in 2019. +Printrex: Printrex printers include wide format, desktop and rack-mounted and vehicle-mounted black and white thermal printers used by customers to log and plot oil field, seismic and down hole well drilling data in the oil and gas exploration industry . The Printrex® brand of printers also includes high-speed color inkjet desktop printers used by oil and gas field service companies to print logs at data centers of the oil and gas field service companies. We primarily sell our Printrex® products directly to oil field service and drilling companies and OEM’s, as well as through regional distributors in the United States, Europe, Canada and Asia. +TSG : Through TSG, we proactively market the sale of consumable products (including POS receipt paper, inkjet cartridges, ribbons and other printing supplies), replacement parts, maintenance and repair services, refurbished printers, and shipping and handling charges. Our maintenance services include the sale of extended warranties, multi-year maintenance contracts, a 24-hour guaranteed replacement product service called TransAct Xpress™ and other repair services for our printers and terminals. Within the United States, we provide repair services through our service center in Ithaca, New York. Internationally, we provide repair services through our European service center located in Doncaster, UK, and through partners strategically located around the world. +4 +We also provide customers with telephone sales and technical support, and a personal account representative to handle orders, shipping and general information. Technical and sales support personnel receive training on all our manufactured products and services. In addition to personalized telephone and technical support, we also market and sell consumable products 24 hours a day, seven days a week, via our webstore, www.transactsupplies.com . +Sources and Availability of Raw Materials +We design our products to optimize product performance, quality, reliability and durability. These designs combine cost efficient materials, sourcing and assembly methods with high standards of workmanship. Almost all of our printers and terminals are produced by two third-party manufacturers located in China and Thailand. A small portion of our products are assembled in our Ithaca, New York facility largely on a configure-to-order basis using components and subassemblies that have been sourced from vendors and contract manufacturers around the world. +We procure component parts and subassemblies for use in the assembly of our hardware products in Ithaca, New York. Critical component parts and subassemblies include thermal print heads, printing/cutting mechanisms, power supplies, motors, injection molded plastic parts, LCD screens, circuit boards and electronic components, which are obtained from domestic and foreign suppliers at competitive prices. As a result of the majority of our production being performed by our contract manufacturers, the majority of our purchases consist of fully-assembled printers and terminals produced by our contract manufacturers and, to a much lesser extent, component parts. We typically strive to maintain more than one source for our component parts, subassemblies and fully assembled printers and terminals to reduce the risk of parts shortages or unavailability. However, we could experience temporary disruption if certain suppliers ceased doing business with us, as described below. +We currently buy a majority of our thermal print mechanisms, an important component of our thermal printers, and fully assembled printers for several of our printer and food service technology terminal models, from one foreign contract manufacturer in China and to a lesser extent, one other foreign contract manufacturer in Thailand. Although we believe that other contract manufacturers could provide similar thermal print mechanisms or fully assembled printers and terminals, on comparable terms, a change in contract manufacturers could cause a delay in manufacturing and possible loss of sales, which may have a material adverse effect on our operating results. Although we do not have supply agreements with our foreign contract manufacturers, our relationship with both remain strong and we have no reason to believe that either will discontinue their supply of thermal print mechanisms or fully assembled printers to us during 2021 or that their terms to us will be substantially less favorable than they have been historically. Due to the impact from the Chinese tariff starting in 2019, during 2020 we increasingly transferred production from our largest contract manufacturer in China to our contract manufacturer in Thailand. We plan to continue transferring production to our contract manufacturer during 2021. +We currently buy a majority of our thermal print mechanisms, an important component of our thermal printers, and fully assembled printers for several of our printer and food service technology terminal models, from a foreign contract manufacturer in China and a foreign contract manufacturer in Thailand. Although we believe that other contract manufacturers could provide similar thermal print mechanisms or fully assembled printers and terminals, on comparable terms, a change in contract manufacturers could cause a delay in manufacturing and possible loss of sales, which may have a material adverse effect on our operating results. Although we do not have supply agreements with our foreign contract manufacturers, our relationship with both remain strong and we have no reason to believe that either will discontinue their supply of thermal print mechanisms or fully assembled printers to us during 2021 or that their terms to us will be substantially less favorable than they have been historically. Due to the impact from the Chinese tariff starting in 2019, during 2020 we increasingly transferred production from our contract manufacturer in China to our contract manufacturer in Thailand. We plan to continue transferring production to our contract manufacturer in Thailand during 2021. +Patents and Proprietary Information +TransAct relies on a combination of trade secrets, patents, employee and third-party nondisclosure agreements, copyright laws and contractual rights to establish and protect its proprietary rights in its products. As of February 28, 2021, we hold 35 United States and 36 foreign patents and have 5 United States and 3 foreign patent applications pending pertaining to our products. The duration of these patents ranges from 1 to 19 years. The expiration of any individual patent would not have a significant negative impact on our business. We regard certain manufacturing processes and designs to be proprietary and attempt to protect them through employee and third-party nondisclosure agreements and similar means. It may be possible for unauthorized third parties to copy certain portions of our products or to reverse engineer or otherwise obtain and use, to our detriment, information that we regard as proprietary. Moreover, the laws of some foreign countries do not afford the same protection to our proprietary rights as do the laws of the United States. There can be no assurance that legal protections we rely upon to protect our proprietary position will be adequate or that our competitors will not independently develop technologies that are substantially equivalent or superior to our technologies. +Trademarks, Service Marks and Copyrights +We own or have rights to trademarks, service marks, trade names and copyrights that we use in connection with the operation of our business, including our corporate names, logos and website names. Other trademarks, service marks and trade names appearing in this Annual Report on Form 10-K are the property of their respective owners. The trademarks we own include TransAct®, BOHA! TM , AccuDate™, Epic, EPICENTRAL™, Ithaca® and Printrex®. Solely for convenience, some of the trademarks, service marks, trade names and copyrights referred to in this annual report on Form 10-K are listed without the ©, ® and ™ symbols, but we will assert, to the fullest extent under applicable law, our rights to our trademarks, service marks, trade names and copyrights. +Seasonality +Restaurants typically reduce purchases of equipment in the fourth quarter due to the increased volume of transactions during the holiday period, which may negatively impact sales of our food service technology products or POS printers. +Working Capital +Inventory, accounts receivable, and accounts payable levels, payment terms, and where applicable, return policies are in accordance with the general practices of the industry and standard business procedures. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. +5 +Certain Significant Customers +IGT is our most significant customer and has been since 1995. We sell both on-line lottery printers and casino and gaming printers to IGT. On May 29, 2015, we signed an agreement with IGT to sell on-line lottery and casino printers to IGT on a non-exclusive basis through December 31, 2019. We decided not to renew the agreement upon its expiration and to exit the on-line lottery market. Although we no longer have an agreement with IGT, we expect to continue selling casino and gaming printers to IGT, as well as spare parts for our remaining, but declining, installed base of lottery printers, in the future but no longer expect to sell on-line lottery printers beyond 2020. +Sales to IGT represented 15% and 14% of our total net sales for the years ended December 31, 2020 and 2019, respectively. +Backlog +Our backlog of firm orders was approximately $3.4 million as of February 28, 2021, compared to $5.7 million as of February 29, 2020. Based on customers’ current delivery requirements, we expect to fill and recognize as revenue $2.7 million of our current backlog during 2021, $0.4 million during 2022 and the remaining balance of the amount during 2023. +Competition +The market for transaction-based and specialty printers and food service technology terminals is extremely competitive, and we expect such competition to continue in the future. However, we experience less competition for EPICENTRAL TM software due to the highly customized nature of the product. We compete with a number of companies, many of which have greater financial, technical and marketing resources than TransAct. We believe our ability to compete successfully depends on a number of factors both within and outside our control, including durability, reliability, quality, design capability, product customization, price, customer support, success in developing new products, manufacturing expertise and capacity, supply of component parts and materials, strategic relationships with suppliers, the timing of new product introductions by us and our competitors, general market, economic and political conditions and, in some cases, the uniqueness of our products. +In the food service technology market, we primarily compete with Avery Dennison Corporation, Ecolab Inc., ITD Food Safety, CMC Daymark, Integrated Control Corp, Digi International, Squadle Inc., Jolt Software and Zenput. We compete in this market based largely on our ability to provide highly specialized software and purpose-built products and ongoing technical support. We rely upon third-party developed software and hosting services combined with our own proprietary hardware and software to offer a unique BOHA! branded solution to support back-of-house operations in the food service industry. Our competitors or others may develop, or may establish relationships with developers with the capability to develop, software and services that are similar to or competitive with ours, which may be disadvantageous to our competitive position. Certain portions of our food service technology software are licensed from a third-party developer on a non-exclusive basis through 2031 and are subject to a revenue sharing arrangement with the developer. We are reliant upon the third-party developer to further develop and maintain their developed software, and the developer controls the software source code. The license agreement does not preclude the developer from working with others on similar products. Also, the third party developer hosts the web-based applications. Therefore, presently, we are highly dependent upon this third-party developer for continued service to our customers and the further development of our food service technology software products. +In the POS automation market, we primarily compete with Epson America, Inc., which holds a dominant market position. We also compete, to a much lesser extent, with Star Micronics America, Inc. and Citizen -- CBM America Corporation. Certain competitors of ours have greater financial resources and lower costs attributable to higher volume production which enables them to occasionally offer lower prices than us. However, we will continue to deemphasize efforts in the POS automation market going forward as we have shifted our focus toward our higher-value, technology enabled food service technology and casino and gaming products. +In the casino and gaming market (consisting principally of slot machine printing, VLT transaction printing and promotional coupon printing), we compete with several companies including JCM Global, Nanoptix, Inc., Custom Engineering SPA, Eurocoin and others. Certain of our products sold for casino and gaming applications compete based upon our ability to provide highly specialized products, custom engineering and ongoing technical support. +In the lottery market (consisting principally of on-line lottery transaction printing), we competed with other lottery printer providers such as Custom Engineering SPA, Star Micronics and Wincor Nixdorf. However, we exited the lottery market in 2019 and shifted our focus toward our higher-value, technology enabled food service technology and casino and gaming products. +In the oil and gas market, our Printrex® products compete primarily with the products of Imaging Systems Group, Inc. and Neuralog Inc. We compete in this market based largely on our ability to provide specialized, custom-engineered products. +The market in which TSG competes is highly fragmented, and we compete with numerous competitors of various sizes, including POS and internet resellers and paper converters depending on the geographic area. +Our strategy for competing in our markets is to continually develop and/or license new products (hardware and software), such as our launch of BOHA! TM in 2019, and product line extensions that are technologically advanced and provide differentiated features and functions, to increase our market penetration, to take advantage of strategic relationships, and to lower the cost of our products by sourcing certain products overseas. Although we believe that our products, operations and relationships provide a competitive foundation, there can be no assurance that we will compete successfully in the future. In addition, our products utilize certain thermal printing technologies and licensed software. If new technologies are introduced, or existing technologies evolve, we may be required to incorporate these technologies into our products. Alternatively, if such technologies were to become available to our competitors, our products could become obsolete, which could have a significant negative impact on our business. +Environmental Compliance +Our compliance with federal, state and local laws and regulations relating to environmental protection and discharge of hazardous materials has not had a material impact on our capital expenditures, earnings or competitive position, and we do not anticipate any material impact from such compliance in the future. +6 +Available Information +We make available free of charge through the “Investor Relations” tab on our Internet website, www.transact-tech.com, our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements and all amendments to those reports and statements as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC pursuant to Sections 13(a) or 15(d) of the Exchange Act. The SEC maintains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http;//www.sec.gov. The content on any website referred to in this Form 10-K is not incorporated by reference in this Form 10-K unless expressly noted. +Employees +As of December 31, 2020, TransAct and our subsidiaries employed 112 persons, all of whom were full-time employees. None of our employees are unionized, and we consider our relationships with our employees to be good. +Information about our Executive Officers +The following is a list of the names and ages of all executive officers of the registrant, indicating all positions and offices with the registrant held by each such person and each person’s principal occupations and employment during at least the past five years. +Name +Age +Position +Bart C. Shuldman +63 +Chairman of the Board and Chief Executive Officer +Steven A. DeMartino +51 +President, Chief Financial Officer, Treasurer and Secretary +Donald E. Brooks +68 +Senior Vice President, Engineering +Tracey S. Chernay +61 +Senior Vice President, Casino, Gaming and Lottery Sales +Andrew J. Hoffman +63 +Senior Vice President, Operations +David B. Peters +42 +Vice President and Chief Accounting Officer +Brent Richtsmeier +56 +Senior Vice President, Software Engineering +Raymond T. Walsh, Jr. +35 +Senior Vice President, Global Sales +Bart C. Shuldman has been Chief Executive Officer and a Director of the Company since its formation in June 1996. In February 2001, Mr. Shuldman was elected Chairman of the Board. Mr. Shuldman served as President of the Company from its formation until June 2010, when he relinquished the President title, to focus on new products and markets, international expansion and potential acquisitions. +Steven A. DeMartino was named as TransAct’s President, Chief Financial Officer, Treasurer and Secretary on June 1, 2010. Previously, Mr. DeMartino served as Executive Vice President, Chief Financial Officer, Treasurer and Secretary from June 2004 to May 2010, Senior Vice President, Finance and Information Technology from October 2001 to May 2004, Vice President and Corporate Controller from January 1998 to October 2001, and Corporate Controller from August 1996 to December 1997. Mr. DeMartino is a certified public accountant. +Donald E. Brooks was appointed Senior Vice President of Engineering in April 2012. Previously, Mr. Brooks served as Vice President, Engineering from September 2004 to April 2012, Senior Project Engineer from February 1998 to September 2004, Project Engineer from June 1997 to February 1998, Director of Electrical Engineering from March 1986 to June 1997 and Manager of Electronic Development from December 1983 to March 1986. +Tracey S. Chernay was appointed Senior Vice President, Casino and Gaming Sales and Marketing in June 2010, with responsibility for the sales and marketing of all casino and gaming products. Previously, Ms. Chernay served as Senior Vice President, Sales and Marketing from June 2007 to May 2010, Senior Vice President, Marketing and Sales, POS and Banking with the Company from July 2006 to June 2007, and joined TransAct in May of 2005 as Senior Vice President, Marketing. Prior to joining TransAct, Ms. Chernay was employed with Xerox Corporation where she held the role of Manager, Worldwide Marketing since 2003, and Manager, Sales Operations from 2000 to 2002. She joined Xerox Corporation in 1983. +Andrew J. Hoffman was appointed Senior Vice President, Operations for TransAct worldwide in November 2004. He served as Vice President, Operations from September 1994 to November 2004. +David B. Peters was appointed Vice President and Chief Accounting Officer on March 1, 2018. Previously, Mr. Peters served as Director, SEC and Financial Reporting since joining TransAct in March 2014. Prior to joining TransAct, Mr. Peters was employed with United Technologies Corporation from November 2006 to March 2014 where he served in various financial management positions. Mr. Peters is a certified public accountant. +Brent Richtsmeier was hired as Senior Vice President, Software Engineering on December 9, 2019 and appointed as an officer of the Company on January 11, 2021. Prior to joining TransAct, Mr. Richtsmeier was employed with Samsung as the VP of Development where he was responsible for software strategy, software development at scale and business development. +Raymond T. Walsh, Jr. was appointed Senior Vice President, Global Sales on February 27, 2019. Previously, Mr. Walsh served as Vice President, Global Sales since 2018. Mr. Walsh joined TransAct in 2006 and has held several sales positions of increasing responsibility with the Company. Prior to joining TransAct, Mr. Walsh served as the Senior Manager of Business Development at Nerac. +There are no family relationships between any of our executive officers and there is no arrangement or understanding between any of such officers and any other person pursuant to which he or she was selected as an officer. Each of our executive officers was elected by the Board of Directors to hold office until his or her successor is elected and qualified or until his or her earlier resignation or removal. +7 \ No newline at end of file diff --git a/raw/filings/0001017303/2020/0001017303-21-000020/item13.txt b/raw/filings/0001017303/2020/0001017303-21-000020/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..0e9efee92c857cfcf6ce5e2547e7c151ee597904 --- /dev/null +++ b/raw/filings/0001017303/2020/0001017303-21-000020/item13.txt @@ -0,0 +1,2 @@ +Item 13. Certain Relationships and Related Transactions, and Director Independence. +The information in response to this item will be contained in the Proxy Statement under the headings “Certain Relationships and Related Transactions” and is incorporated herein by reference. \ No newline at end of file diff --git a/raw/filings/0001017303/2020/0001017303-21-000020/item9a.txt b/raw/filings/0001017303/2020/0001017303-21-000020/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..f56b6337a4ad6f8d94e9a17374f69a53d5d637e7 --- /dev/null +++ b/raw/filings/0001017303/2020/0001017303-21-000020/item9a.txt @@ -0,0 +1,26 @@ +Item 9A. Controls and Procedures. +Evaluation of Disclosure Controls and Procedures +Our management, with the participation of our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), evaluated the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Exchange Act as of December 31, 2020. In the Amendment to our Annual Report on Form 10-K for the year ended December 31, 2018, filed with the SEC on November 21, 2019, we disclosed that management, including our CEO and CFO, concluded that our disclosure controls and procedures were not effective as of December 31, 2018, due to material weaknesses in our internal control over financial reporting as described below. As of December 31, 2020, one material weakness was not fully remediated and our disclosure controls and procedures were not effective as of December 31, 2020. Management has begun remediation efforts, which are described below. +Notwithstanding these material weaknesses, our management, including our CEO and CFO, has concluded that our consolidated financial statements, included in this Form 10-K, fairly present, in all material respects, our financial condition, results of operations and cash flows for the periods presented in conformity with generally accepted accounting principles, and that they can still be relied upon. +Management’s Annual Report on Internal Control Over Financial Reporting +Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) under the Exchange Act, to provide reasonable assurance regarding the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements. +Our management assessed our internal control over financial reporting as of December 31, 2020. Our management based its assessment on criteria established in Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“2013 COSO”). In the opinion of management, TransAct did not maintain effective internal control over financial reporting as of December 31, 2020 solely because of the material weakness in internal control over financial reporting described below that existed as of December 31, 2018 and has not been remediated as of December 31, 2020. +A material weakness is defined in Rule 12b-2 under the Exchange Act as a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis. +Material Weaknesses in Internal Control Over Financial Reporting +We identified the following control deficiency that constituted a material weakness in our internal control over financial reporting as of December 31, 2019 and 2018 which has been fully remediated as of December 31, 2020. +● +We did not design and maintain effective controls over user access within the Company’s ERP system, Oracle, to ensure appropriate segregation of duties and to adequately restrict user access to appropriate personnel. Specifically, the provisioning and user recertification controls were not designed to ensure that users maintain proper segregation of duties and, as a result, users could have had inappropriate access rights (the “Access Control Weakness”). +28 +We identified the following control deficiency that constituted a material weakness in our internal control over financial reporting as of December 31, 2020 and 2019. +● +We did not design and maintain effective controls over the completeness and accuracy of information included in key spreadsheets supporting our accounting records (the “Spreadsheet Control Weakness”). +These control deficiencies constituted material weaknesses, but did not result in a material misstatement to our annual or interim consolidated financial statements. However, if the remaining material weakness is not remediated, a material misstatement of account balances or disclosures may not be prevented, and may go undetected, which could result in a material misstatement of future annual or interim consolidated financial statements. +Remediation Efforts to Address Material Weaknesses +Beginning December 31, 2019, we commenced developing and implementing a plan to enhance the design and operating effectiveness of our internal control over financial reporting, which includes taking the following steps to remediate the identified control deficiencies and material weaknesses: +● +To address the Access Control Weakness, we utilized the services of an Oracle consulting firm and an accounting firm unrelated to our Independent Registered Accounting Firm, to assist us in analyzing and reviewing Oracle access for all users. During the first quarter of 2020, we completed the analysis and deployed an action plan. Based on this analysis and action plan, during the second quarter of 2020, we created new Oracle responsibilities for each employee for which a conflict was identified to remove Oracle transactional responsibilities that we believed to be conflicting and reassigned those responsibilities to a different employee to ensure proper segregation of duties. We completed the implementation of the new Oracle responsibilities for all users in July 2020. During the third quarter of 2020, we completed the enhancement and implementation provisioning and user certification controls to ensure we maintain the appropriate segregation of duties within Oracle. The Access Control Weakness was deemed to be remediated as of September 30, 2020. +● +To address the Spreadsheet Control Weakness, for each key spreadsheet we plan to evaluate and determine (1) if a standard Oracle report exists containing the same information as the spreadsheet, and if so, we would utilize the standard Oracle report (without modification) instead of the spreadsheet to support our accounting records and (2) if a standard Oracle report cannot be used, we will implement a new key control whereby an employee performs a formal validation that the information from Oracle is completely and accurately transferred (automatically or manually) to a spreadsheet by verifying totals and other information on a test basis. For all key spreadsheets, we plan to design and implement a new key control to validate the completeness and accuracy of information supporting our accounting records. During 2020, we began the process of evaluating each key spreadsheet based on the above criteria, and for several key spreadsheets, we implemented a new key control to validate the completeness and accuracy of the information contained within and supporting each such spreadsheet. +We believe these steps will address the remaining material weakness described above. +Changes in Internal Control over Financial Reporting +Other than the changes intended to remediate the material weakness noted above, no change in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) occurred during the three months ended December 31, 2020 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. \ No newline at end of file diff --git a/raw/filings/0001017303/2020/0001017303-21-000020/rp_note.txt b/raw/filings/0001017303/2020/0001017303-21-000020/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001692415/2017/0001477932-18-001468/filing.txt b/raw/filings/0001692415/2017/0001477932-18-001468/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..aa1a5149a6a511ffa6eb861ec9ffec5dd2f18a1e --- /dev/null +++ b/raw/filings/0001692415/2017/0001477932-18-001468/filing.txt @@ -0,0 +1,2025 @@ +10-K +1 +codx_10k.htm +FORM 10-K +codx_10k.htm +UNITED STATES +SECURITIES AND EXCHANGE COMMISSION +Washington, D.C. 20549. +Form 10-K +(Mark One) +x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the fiscal year ended December 31, 2017 +OR +¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For the transition period from_______to_______ +Commission File Number 1-38148 +CO-DIAGNOSTICS, INC. +(Exact Name of Registrant as Specified in Its Charter) +Utah +3841 +46-2609396 +(State or other jurisdiction of +incorporation or organization) +(Primary Standard Industrial +Classification Code Number) +(I.R.S. Employer +Identification Number) +2401 S. Foothill Drive, Salt Lake City, Utah 84109 +(Address of principal executive offices and zip code) +(801) 438-1036 +(Registrant’s telephone number including area code) +Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x +Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ¨ No x +Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨ +Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or such shorter period that the registrant was required to submit and post such files). Yes x No ¨ +Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨ +Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. +Large accelerated filer +¨ +Accelerated filer +¨ +Non-accelerated filer +¨ +Smaller reporting company +x +Emerging Growth Company +x +If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨ +Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No x +The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common stock was last sold as of the last business day of the registrant’s most recently completed second fiscal quarter was approximately $ N/A . +As of March 27, 2018, there were 12,317,184 shares of common stock, par value $0.001 per share, outstanding. +Table of Contents +Page +PART I +Item 1. +Business. +4 +Item 1A. +Risk Factors. +8 +Item 1B. +Unresolved Staff Comments. +9 +Item 2. +Properties. +9 +Item 3. +Legal Proceedings. +9 +Item 4. +Mine Safety Disclosures. +9 +PART II +Item 5. +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. +10 +Item 6. +Selected Financial Data. +11 +Item 7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations. +11 +Item 7A. +Quantitative and Qualitative Disclosures About Market Risk. +16 +Item 8. +Financial Statements and Supplementary Data. +17 +Item 9. +Changes in and Disagreements With Accountants on Accounting and Financial Disclosure. +18 +Item 9A. +Controls and Procedures. +18 +Item 9B. +Other Information. +18 +PART III +Item 10. +Directors, Executive Officers and Corporate Governance. +19 +Item 11. +Executive Compensation. +23 +Item 12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. +26 +Item 13. +Certain Relationships and Related Transactions, and Director Independence. +28 +Item 14. +Principal Accountant Fees and Services. +28 +PART IV +Item 15. +Exhibits and Financial Statement Schedules. +29 +2 +PART I +Forward-Looking Statements +This Annual Report on Form 10-K contains “forward-looking statements.” Forward-looking statements reflect the current view about future events. When used in this Form 10-K, the words “anticipate,” “believe,” “estimate,” “expect,” “future,” “intend,” “plan,” or the negative of these terms and similar expressions, as they relate to us or our management, identify forward-looking statements. Such statements, include, but are not limited to, statements contained in this Annual Report relating to our business strategy, our future operating results and liquidity and capital resources outlook. Forward-looking statements are based on our current expectations and assumptions regarding our business, the economy and other future conditions. Because forward-looking statements relate to the future, they are subject to inherent uncertainties, risks and changes in circumstances that are difficult to predict. Our actual results may differ materially from those contemplated by the forward-looking statements. They are neither statements of historical fact nor guarantees of assurance of future performance. We caution you therefore against relying on any of these forward-looking statements. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, without limitation: +· +the results of clinical trials and the regulatory approval process; +· +our ability to raise capital to fund continuing operations; +· +market acceptance of any products that may be approved for commercialization; +· +our ability to protect our intellectual property rights; +· +the impact of any infringement actions or other litigation brought against us; +· +competition from other providers and products; +· +our ability to develop and commercialize new and improved products and services; +· +changes in government regulation; +· +our ability to complete capital raising transactions; +· +and other factors (including the risks contained in the section of this Annual Report entitled “Risk Factors”) relating to our industry, our operations and results of operations. +Should one or more of these risks or uncertainties materialize, or should the underlying assumptions prove incorrect, actual results may differ significantly from those anticipated, believed, estimated, expected, intended or planned. +Factors or events that could cause our actual results to differ may emerge from time to time, and it is not possible for us to predict all of them. We cannot guarantee future results, levels of activity, performance or achievements. Except as required by applicable law, including the securities laws of the United States, we do not intend to update any of the forward-looking statements to conform these statements to actual results. +As used in this Annual Report, the terms “we”, “us”, “our”, and “Co-Diagnostics” means Co-Diagnostics, Inc., a Utah corporation and its consolidated subsidiaries (the “Company”), unless otherwise indicated. +3 +Table of Contents +ITEM 1: BUSINESS +Overview +Co-Diagnostics, Inc. (“Company,” or “CDI,”), a Utah corporation, is a molecular diagnostics company that has developed and intends to manufacture and sell reagents used for diagnostic tests that function via the detection and/or analysis of nucleic acid molecules (DNA or RNA), and to sell diagnostic equipment from other manufacturers as self-contained lab systems (which we refer to as the “MDx device”). +In addition, the unique properties of our Co-Primer technology make them ideally suited to a variety of applications where sensitivity is key to optimal results, including multiplexing several targets, enhanced SNP detection and enrichment for next gen sequencing. +Dr. Brent Satterfield, our Chief Technology Officer, created the Company’s suite of intellectual properties. Our scientists were the first to understand the complex mathematics of DNA test design, to “engineer” a DNA test and to automate algorithms that rapidly screen millions of possible options to pinpoint the optimum design. Dr. Satterfield developed the Company’s intellectual property consisting of the predictive mathematical algorithms and proprietary reagents used in the testing process, which together represent a major advance in Polymerase Chain Reaction (“PCR”) testing systems. CDI technologies are now protected by five granted or pending US patents, as well as certain trade secrets. Ownership of our proprietary platform permits us the advantage of avoiding payment of patent royalties required by other PCR test systems, which grants us the opportunity of selling diagnostic tests at a lower price than competitors, while generating a profit margin. +We will either sell or lease our portable labs to existing diagnostic centers, through sale or lease agreements, and sell the reagents that comprise our proprietary tests to those laboratories and testing facilities. +CDI’s low-cost system (pictured at right) uses CDI’s tests to diagnose tuberculosis, Zika, hepatitis B and C, Malaria, dengue and HIV, all of which tests have been designed and verified in CDI’s laboratory as explained below. +We designed our tests by identifying the optimal locations on the target gene for amplification and paired the location with the optimized primer and probe structure to achieve outputs that meet the design input requirements identified from market research. This is done by following planned and documented processes, procedures and testing. In other words, the data resulting from our tests verify that we succeeded in designing what we intended to at the outset. Verification is a series of testing that concludes that the product is ready to proceed to validation in a clinical evaluation setting using initial production tests to confirm that the product as designed meets the user needs. +CDI’s diagnostics systems enable very rapid, low-cost, sophisticated molecular testing for organisms and genetic diseases by greatly automating historically complex procedures in both the development and administration of tests. CDI’s newest technical advance involves a novel approach to PCR test design ("Co-Primers") that eliminates one of the key vexing issues of PCR amplification, the exponential growth of primer-dimer pairs (false positives and false negatives) which adversely interferes with identification of the target DNA. +Using its proprietary test design system and proprietary reagents, CDI will design and sell PCR diagnostic tests for diseases and pathogens starting with tests for tuberculosis, a drug resistant tuberculosis test, hepatitis B and C, Malaria, dengue, HIV and Zika virus, all of which tests have been designed and verified in CDI’s laboratory. +4 +Table of Contents +Infectious Disease Product Offering +We plan to manufacture molecular diagnostic tests for the following diseases in the following regions, to be sold along with the MDx device: +Timetable +Region +Tests +Current (revenues in the 2nd quarter in 2018) +Caribbean and Central and South America +Zika, Tuberculosis, Hepatitis B and C, Dengue +India +Tuberculosis, Hepatitis B and C, Malaria, Dengue and HIV +2018-2019 +European Union; Asia +Tuberculosis, Hepatitis B and C +2020-2025 +United States +To be determined based on need and regulatory barriers +Caribbean and Central and South America +Our initial sales will be to entities within the Caribbean Public Health Agency Members States (Anguilla, Antigua and Barbuda, Aruba, Bahamas, Barbados, Belize, Bermuda, BES Islands, British Virgin Islands, Cayman Islands, Curacao, Dominica, Grenada, Haiti, Guyana, Jamaica, Montserrat, Saint Kitts and Nevis, Saint Lucia, St Maarten, Saint Vincent and the Grenadines, Suriname, Trinidad and Tobago, Turks and Caicos Islands). +In some of these countries, there are no regulatory hurdles and we can start offering our tests immediately. The U.S. Food and Drug Administration (FDA) has granted permission for us to export many of our products. The FDA's permission to export was granted under Section 801 (e) of the Federal Food, Drug, and Cosmetic Act, as amended (the “FDC Act”). Section 801(e) of the FDA Act covers certain medical devices that have not yet received an approved Premarket Approval in the United States by the FDA, such as our products. We have not commenced any Premarket Approval steps with the FDA. Section 801(e) applies to medical devices that are acceptable to the importing country and that are manufactured under the FDA's Good Manufacturing Practices. +We will first offer our Zika test in this region because of the demand for such test, followed quickly by tests for tuberculosis, hepatitis B and C, and dengue, then our full range of tests. Products will be manufactured for sale upon receipt of purchase orders from labs and hospitals. +India +The Company has entered into an agreement to manufacture diagnostics tests for seven infectious diseases with a pharmaceutical manufacturing company in India. The agreement provides for the manufacture of the tests named above and the joint sales and marketing of those tests in India. We have commenced with our joint venture partner to construct a plant that will be used for testing and manufacturing to service the Indian market. We believe that the plant will be completed and manufacturing activities will begin in the third quarter of 2018. +Since the tests will be conducted in India on Indian citizens, no FDA approval or inspection will be required. Certain Indian regulatory approval from the Central Drugs Standard Control Organization (CDSCO) must be acquired. We are engaging the services of an experienced consultant in India to help get us through this process. Research Use Only (RUO) reagents are able to be sold without requiring regulatory approval as long as they are labeled and designated as such. Tests for some of the targeted diseases are available for sale currently in India. +India is the country with the highest burden of tuberculosis. World Health Organization (WHO) tuberculosis statistics for India for 2015 give an estimated incidence figure of 2.2 million cases of tuberculosis for India out of a global incidence of 9.6 million. The tuberculosis incidence for India is the number of new cases of active tuberculosis disease in India during a certain time period (usually a year). We currently have a tuberculosis test and tuberculosis test that measures drug resistance to aid in more effective treatment. +5 +Table of Contents +Europe +Molecular diagnostics, such as our tests, are governed in Europe by the framework for in vitro diagnostics (IVDs), which encompasses diagnostic products such as reagents, instruments and systems intended for use in diagnosis of disease. The regulatory system for IVDs is built largely on a self-certification procedure, placing heavy responsibility on manufacturers. Non self-certified products are subject to the same standards as self-certified products but are subject to audit and review by a notified body prior to receiving approval to be CE-marked. A CE-marking is a manufacturer’s declaration that a product meets the requirements of the applicable European Commission directive. Examples of current obligations include having in place a qualitative manufacturing process, user instructions that are clear and fit for purpose, ensuring that the ‘physical’ features of devices and diagnostics do not pose any danger. If a product fulfils these and other related control requirements, it may be CE-marked as an indication that the product is compliant with EU legislation and sold in the European Union. +We have received ISO 13485 and ISO 9001 certifications relating to the design and manufacture of our medical device products. The ISO certification indicates that we meet the standards required to self-certify certain of our products and affix a CE-marking for sales of our products in countries accepting the CE marking (not in the United States) with only minimal further governmental approvals in each country. We expect to have our Zika and tuberculosis tests CE-marked in 2018. We estimate the remaining costs for CE-marks on the initial tests we will offer to be approximately $100,000. +United States +We do not anticipate offering our tests in the United States in the near future. We believe, however, our tests may be able to qualify as Laboratory Developed Tests (LDT's), diagnostic tests that are developed and manufactured by CLIA certified laboratories. These tests are developed by the lab for use only in that laboratory. CLIA laboratories develop the performance characteristics, perform the analytical validation for their LDT's and obtain licenses to offer them as diagnostic services. The FDA has publicly announced its intention to regulate certain LDTs in a phased-in approach, but draft guidance that was published a couple of years ago was withdrawn at the end of the Obama administration and replaced by an informal non-enforceable discussion paper reflecting some of the feedback that it received on LDT regulation. +Market Opportunity +The molecular diagnostics market is a fast growing portion of the in vitro (test tube based, controlled environment) diagnostics market. Using estimates of the incidence of disease by the Centers for Disease Control, the World Health Organization and other international health agencies and sources, the Company estimates that the global annual demand for diagnostic tests are: +Tuberculosis +10,400,000 +HIV +36,700,000 +Multi-drug resistant Tuberculosis +580,000 +Malaria +214,000,000 +Zika +324,000,000 +Sexually Transmitted Illnesses +357,000,000 +Hepatitis B +240,000,000 +Human papilloma virus +291,000,000 +Hepatitis C +130,000,000 +Dengue +390,000,000 +Total Annual Tests +1,993,680,000 +There are several advantages of molecular tests, such as the ones we market and sell, over other forms of diagnostic testing, which include higher sensitivities, the ability to perform multiplex tests and the ability to test for drug resistance or individual genes. +6 +Table of Contents +Competitive Advantages of Co-Diagnostics +We believe that we have the following competitive advantages: +· +Affordability: Lower-cost test kits and low-cost MDx-device. +· +Flexibility: CDI’s tests have been designed to run on many vendors’ DNA diagnostic testing machines. These tests are particularly well suited to the new generation of “lab-on-a-chip” and “point-of-care” (“LOC and POC”), highly portable analysis machinery for field, clinic and office applications. +· +Speed : We believe our rapid assay development provides shorter time to results. +· +Accuracy : We believe our tests are more accurate than competitors’ and can detect more strains of viruses. +· +Exclusivity : CDI owns all patents used in preparation of its tests, all intellectual property including a 100-year license on Co-Primers and all additional product and process development of Dr. Satterfield through March 2019. +· +Personalized Medicine : We project that rising health care costs in developed and developing nations will increasingly require that health care systems be patient specific to eliminate waste, misdiagnoses, and ineffectiveness. A critical component will be accurate, more affordable DNA-based diagnostics, which CDI plans to offer. +· +Low-cost Provider : We plan to keep the Company’s overhead low. Its platform technology obviates the need to pay patent royalties typically required of its competitors, which use patented test platforms to design their tests. +· +Worldwide Footprint : With a dynamic technology that encompasses markets worldwide, the Company anticipates that it can identify the best target markets, not only in high burden developing countries (HBDC’s) but also in developed nations. +· +Growth Industry Category : We believe that DNA testing is the fastest-growing segment of in-vitro diagnostic testing. +· +Combination Product Offering : CDI’s ultra-sensitive tests can be a well-designed match for a new generation of handheld and other small point-of-care devices now entering the market. Used together, these affordable tests and devices may revolutionize the molecular diagnostics industry in cost, speed of test results and simplification. +· +Multi-plexing: We believe our Co-Primer designed tests will be able to test for multiple targets in the same sample without the distortion caused by false negatives and false positives that generally occur in multiplexed tests. +Primer Design Product Offering +In addition, the unique properties of our Co-Primer technology make them ideally suited to a variety of applications where sensitivity is key to optimal results, including multiplexing several targets, enhanced SNP detection and enrichment for next gen sequencing. Because of these unique characteristics of Co-Primers, research companies and institutions have requested that we design diagnostics to locate and identify uncommon gene sequences and SNPs and create tests for the target sequences in a multiplexed reaction. This application of our technology is in its beginning stages, but we believe that the results from our initial research indicate a significant step forward in defining the capabilities of our technology, which we believe can be translated to revenue producing licensing arrangements. +7 +Table of Contents +Organizational History and Corporate Information +We were incorporated as Co-Diagnostics, Inc., in Utah on April 18, 2013. Our principal executive office is located 2401 S. Foothill Drive, Salt Lake City, Utah 84109. Our telephone number is (801) 438-1036. Our web address is http://codiagnostics.com. +Implications of Being an Emerging Growth Company +We are an "emerging growth company," as defined in the Jumpstart Our Business Startups Act of 2012. We will remain an emerging growth company until the earlier of (i) the last day of the fiscal year following the fifth anniversary of July 12, 2017, the date of the first sale of our common stock pursuant to an effective registration statement under the Securities Act of 1933, as amended (the “Securities Act”); (ii) the last day of the fiscal year in which we have total annual gross revenues of $1 billion or more; (iii) the date on which we have issued more than $1 billion in nonconvertible debt during the previous three years; or (iv) the date on which we are deemed to be a large accelerated filer under applicable SEC rules. We expect that we will remain an emerging growth company for the foreseeable future, but cannot retain our emerging growth company status indefinitely. We refer to the Jumpstart Our Business Startups Act of 2012 herein as the "JOBS Act". For so long as we remain an emerging growth company, we are permitted and intend to rely on exemptions from specified disclosure requirements that are applicable to other public companies that are not emerging growth companies. These exemptions include: +· +being permitted to provide only two years of audited financial statements, in addition to any required unaudited interim financial statements, with correspondingly reduced "Management's Discussion and Analysis of Financial Condition and Results of Operations" disclosure; +· +not being required to comply with the requirement of auditor attestation of our internal controls over financial reporting; +· +not being required to comply with any requirement that may be adopted by the Public Company Accounting Oversight Board regarding mandatory audit firm rotation or a supplement to the auditor's report providing additional information about the audit and the financial statements; +· +reduced disclosure obligations regarding executive compensation; and +· +not being required to hold a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. +For as long as we continue to be an emerging growth company, we expect that we will take advantage of the reduced disclosure obligations available to us as a result of that classification. Accordingly, the information contained herein may be different than the information you receive from other public companies in which you hold stock. +An emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. This allows an emerging growth company to delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We have irrevocably elected to avail ourselves of this extended transition period and, as a result, we will not be required to adopt new or revised accounting standards on the dates on which adoption of such standards is required for other public reporting companies. +We are also a "smaller reporting company" as defined in Rule 12b-2 of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and have elected to take advantage of certain of the scaled disclosure available for smaller reporting companies. +ITEM 1A. RISK FACTORS +Not applicable to smaller reporting companies. +8 +Table of Contents +ITEM 1B. UNRESOLVED STAFF COMMENTS +None. +ITEM 2. PROPERTIES +Our executive offices are located at 2401 S. Foothill Drive, Salt Lake City, Utah 84109. We occupy the space at the executive offices under a lease, which expires January 31, 2020. The lease covers approximately 7,015 square feet of lab and office space leased at a rate of $11,109 per month. We have no other properties. +ITEM 3. LEGAL PROCEEDINGS +From time to time, we may become involved in litigation relating to claims arising out of our operations in the normal course of business. To the best of our knowledge, no governmental authority is contemplating any proceeding to which we are a party or to which any of our properties or businesses are subject, which would reasonably be likely to have a material adverse effect on the Company. +ITEM 4. MINE SAFETY DISCLOSURES +Not applicable. +9 +Table of Contents +PART II +ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER EQUITY SECURITIES +Market Information +Our common stock, from July 12, 2017, was quoted on the NASDAQ market under the symbol “CODX”. The following table sets forth the high and low prices for our common stock for the periods indicated, as reported by NASDAQ. +2018 +HIGH +LOW +First Quarter (through March 19, 2018) +$ +3.27 +$ +1.45 +2017 +HIGH +LOW +First Quarter +$ +---- +$ +----- +Second Quarter +$ +---- +$ +----- +Third Quarter +$ +6.75 +$ +3.50 +Fourth Quarter +$ +6.85 +$ +2.35 +Holders +As of March 19, 2018, the last reported sales price reported on NASDAQ for our common stock was $2.25 per share. As of the date of this filing, we had approximately 391 holders of our common stock. The number of record holders was determined from the records of our transfer agent and does not include beneficial owners of common stock whose shares are held in the names of various security brokers, dealers, and registered clearing agencies. The transfer agent for our common stock is VStock Transfer LLC located at 18 Lafayette Pl, Woodmere, New York 11598. +Dividends +We have never declared or paid any cash dividends on our capital stock. The payment of dividends on our common stock in the future will depend on our earnings, capital requirements, operating and financial condition and such other factors as our Board of Directors may consider appropriate. We currently expect to use all available funds to finance the future development and expansion of our business and do not anticipate paying dividends on our common stock in the foreseeable future. +10 +Table of Contents +Recent Sales of Unregistered Securities +On December 6, 2017, we issued 20,000 shares of our common stock and on January 25, 2018 we issued 10,000 shares of our common stock to the same corporation in consideration of consulting services performed. We relied on the exemption from registration under the Securities Act set forth in Section 4(2) thereof. +On January 25, 2018, we issued 4,209 shares of our common stock in consideration of consulting services performed by a limited liability company. The limited liability company is an accredited investor. We relied on the exemption from registration under the Securities Act set forth in Section 4(2) thereof. +Purchases of Equity Securities by the Issuer and Affiliated Purchasers +None. +ITEM 6. SELECTED FINANCIAL DATA +Not required. +ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULT OF OPERATIONS +The following management’s discussion and analysis of financial condition and results of operations describes the principal factors affecting the results of our operations, financial condition, and changes in financial condition. This discussion should be read in conjunction with the accompanying audited financial statements, and notes thereto, included elsewhere in this report. The information contained in this discussion is subject to a number of risks and uncertainties. We urge you to review carefully the sections of this report entitled “ Risk Factors ” and “ Forward-Looking Statements ” for a more complete discussion of the risks and uncertainties associated with an investment in our securities. +Overview +Co-Diagnostics, Inc. (“Company,” or “CDI,”), a Utah corporation, is a molecular diagnostics company that has developed, and intends to sell molecular diagnostic technology such as lab systems (which we refer to as the “MDx device”) and manufacture and sell reagents used for tests that are designed using the detection and/or analysis of nucleic acid molecules (DNA or RNA). +In addition, the unique properties of our Co-Primer technology make them ideally suited to a variety of applications where sensitivity is key to optimal results, including multiplexing several targets, enhanced SNP detection and enrichment for next gen sequencing. +Dr. Brent Satterfield, our Chief Technology Officer, created the Company’s suite of intellectual properties. Our scientists were the first to understand the complex mathematics of DNA test design, to “engineer” a DNA test and to automate algorithms that rapidly screen millions of possible options to pinpoint the optimum design. Dr. Satterfield developed the Company’s intellectual property consisting of the predictive mathematical algorithms and proprietary reagents used in the testing process, which together represent a major advance in Polymerase Chain Reaction (“PCR”) testing systems. CDI’s technologies are now protected by five granted or pending US patents, as well as certain trade secrets. Ownership of our proprietary platform permits us to avoid paying existing patent royalties required by other PCR test systems, which grants us the opportunity of selling diagnostic labs and tests at a lower cost than competitors, while generating a profit margin. +11 +Table of Contents +Agreement with Synbiotics +The Company has entered into a joint venture agreement to manufacture diagnostics tests for seven infectious diseases with Synbiotics Limited, a pharmaceutical manufacturing company in India. The Company and Synbiotics shall be equal partners in the joint venture. The agreement provides for the manufacture of the tests named above and the joint sales and marketing of those tests in India. The Company will license its technology to the joint venture on a royalty-free basis. The profits from the partnership shall be divided as follows: +Profit Level +CDI Share +Synbiotics Share +Up to $1,000,000 +50 +% +50 +% +$1,000,000-$2,000,000 +60 +% +40 +% +$2,000,000-$3,000,000 +70 +% +30 +% +Above $3,000,000 +80 +% +20 +% +Synbiotics will be reimbursed by the joint venture for some expenses, such as approximately $84,000 in rent for the manufacturing plant and office space. If the joint venture needs additional funding, it will be achieved through loans obtained by the joint venture, or if loans are not available on commercially reasonable terms, from capital contributions. There is no term to the joint venture agreement but it can be dissolved by mutual agreement or by one party upon a material breach by the other party. +Intellectual Property Protection +Because much of our future success and value depends on our proprietary technology, our patent and intellectual property strategy is of critical importance. Three of our initial U.S. patents related to our technology have been granted by the U.S. Patent and Trademark Office, or PTO. As of March 19, 2018, we had two additional patents pending in the U.S. and foreign counterpart applications. Two of our issued patents expire in 2034 and the other patent expires in 2036. +We have identified additional applications of the technology, which represent potential patents that further define specific applications of the processes that are covered by the original patents. We intend to continue building our intellectual property portfolio as development continues and resources are available. +We have copyrighted our development software that can be used by any lab or developer to develop diagnostic tests based on our technology. We have allowed one potential customer access to our development software and intend to sell customized reagents through that customer to labs serviced by that customer throughout the world. To date we have not sold any products through that customer. +Major Customers +We currently have no major customers. +Competition +The molecular diagnostics industry is extremely competitive. There are many firms that provide some or all of the products we provide and provide many diagnostic tests that we have yet to develop. Many of these competitors are larger than us and have significantly greater financial resources. Because we are not established, many of our competitors have a competitive advantage in the diagnostic testing industry because they also have other lines of business in the pharmaceutical industry from which they derive revenues and for which they are well known and respected in the medical profession. We will need to overcome the disadvantage of being a start up with no history of success and no respect of the medical and testing professionals. In the diagnostic testing industry, we compete with such companies as BioMerieux, Siemans, Qiagen, and Cephied and with such pharmaceutical companies as Abbott Laboratories, Becton, Dickinson and Johnson and Johnson. +12 +Table of Contents +Many of these competitors already have an established customer base with industry standard technology, which we must overcome to be successful. +Employees +We currently employ 15 full-time personnel at our executive offices and lab facilities in Salt Lake City, Utah, and two employees outside of Utah. We have engaged independent contractors in India to promote the use of our products and develop outlets for products and employ the services of independent sales representatives on an “as needed” basis. +Government Regulation +We will be regulated by the U.S. Federal Drug Administration and our products must be approved by the FDA before we will be allowed to sell our tests in the United States. Because our lab is ISO certified we are allowed to apply for CE-Marking, which will allow us to sell in most countries in Europe, South America and Asia. +Properties +Our executive offices are located at 2401 S. Foothill Drive, Salt Lake City, Utah 84109. We occupy the space at the executive offices under a lease, which expires January 31, 2020. The lease covers approximately 7,015 square feet of lab and office space leased at a rate of $11,109 per month. We have no other properties. +Legal Proceedings +The Company has no legal proceedings and to the knowledge of management, no litigation has been threatened. +RESULTS OF OPERATIONS +Results of Operations for the Years Ended December 31, 2017 and 2016 +Table derived from audited financial statements +For the years ended +December 31, +December 31, +2017 +2016 +Net sales +$ +7,662 +$ +-- +Cost of sales +302 +-- +Gross profit +7,360 +-- +Operating expenses: +Selling and marketing +426,711 +122,105 +Administrative and general +3,095,791 +796,896 +Research and development +1,003,167 +731,474 +Depreciation and amortization +45,758 +37,491 +Total operating expenses +4,571,427 +1,687,966 +Total operating loss +(4,564,067 +) +(1,687,966 +) +Other expense: +Interest expense +(310,233 +) +(240,720 +) +Loss on Extinguishment of Debt +(2,072,365 +) +-- +Net loss from investment in joint venture +(16,396 +) +-- +Interest income +3,829 +-- +Total other expense +(2,395,165 +) +(240,720 +) +Loss before income taxes +(6,959,232 +) +(1,928,686 +) +Provision for income taxes +-- +-- +Net loss +$ +(6,959,232 +) +$ +(1,928,686 +) +13 +Table of Contents +Revenues +We had no sales of products in the twelve months ended December 31, 2017 and 2016. However, we had licensing revenue of $6,062 in 2017, other service revenue of $1,000 and leased equipment revenue of $600, but no revenue from sales of diagnostic tests. +Cost of Revenues and Gross Profit +We had no sales of products in the twelve months ended December 31, 2017 and 2016. We had licensing revenue in 2017, but there were no costs associated with the license revenue. We recorded $302 in depreciation on the leased equipment as a cost of sale. +Operating Expenses +We incurred total operating expenses of $4,571,427 for the year ended December 31, 2017 compared to total operating expenses of $1,687,966 for the year ended December 31, 2016. The increase of $2,883,461 was due to an increase in general and administrative of $2,298,895, an increase in sales and marketing costs of $304,606, an increase of $271,693 in our research and development expenses and an increase in depreciation and amortization expense of $8,267. +Our general and administrative expenses increased $2,298,895 from $796,896 for the year ended December 31, 2016 to $3,095,791 for the year ended December 31, 2017. The increase was primarily the result of an increase of $972,403 in other professional services and an increase of $900,662 in consulting services both of which primarily represented expenses incurred related to our stock being publicly traded. Salaries and related benefits increased $225,368 resulting from an increase in staff and salaries following the closing of our public financing. Legal and professional fees increased $69,410 primarily incident to the completion of our public financing and our stock being publicly traded. Our option and warrant expense increased $52,694 representing options issued to our board of directors. +Our sales and marketing expenses for the year ended December 31, 2017 were $426,711 compared to sales and marketing expenses of $122,105 for the year ended December 31, 2016. The increase of $304,606 is due primarily to an increase of $170,932 in salaries and related benefits, and an increase of $93,513 in travel expenses, which were incurred as we increased our sales efforts. In addition, advertising and promotion expense increased $12,931. +Our research and development expenses increased by $271,693 from $731,474 for the year ended December 31, 2016 to $1,003,167 for the year ended December 31, 2017. The increase was primarily due to an increase of $324,389 in salaries and related benefits as we increased staff following completion of our public financing. In addition, lab supplies consumed by the increased research activities increased $194,463. The increase in expenses was partially offset by a reduction of $252,500 reduction in technology license royalties and a reduction of $50,626 in consulting fees. +Interest and Other Expense +We recorded interest expense of $240,720 in the year ended December 31, 2016 compared with interest expense of $310,233 in the year ended December 31, 2017. The increase of $69,513 was primarily the result of our bridge financing of approximately $1,100,000 being outstanding for approximately six months in 2017 compared with one month in 2016. +14 +Table of Contents +We incurred a loss on the extinguishment of debt of $2,072,365 when all of our outstanding debt was retired through conversion of the debt to common stock incident to our public financing. In addition, we incurred expenses incident to our India joint venture of approximately $16,396, all of which was partially offset by realizing $3,829 in interest income. +Net Loss +We had net loss of $6,959,232 for the year ended December 31, 2017 compared to a net loss of $1,928,686 for the year ended December 31, 2016. The increase in net loss for the year ended December 31, 2017 compared to the year ended December 31, 2016 was $5,030,546 resulted primarily from increased operating expenses explained in more detail above and the realization of the loss on extinguishment of debt referenced above. +LIQUIDITY AND CAPITAL RESOURCES +Liquidity is the ability of a company to generate funds to support its current and future operations, satisfy its obligations, and otherwise operate on an ongoing basis. Significant factors in the management of liquidity are funds generated by operations, levels of accounts receivable and accounts payable and capital expenditures. +To date we have financed our operations through sales of common stock and the issuance of debt. +At December 31, 2017, we had cash and cash equivalents of $3,534,454, total current assets of $4,451,874, total current liabilities of $628,256 and total stockholders' equity of $3,850,524. At December 31, 2016, we had cash and cash equivalents of $998,737, total current assets of $1,208,398, total current liabilities of $3,845,413 and total stockholders' deficit of $2,994,586. +On July 12, 2017, we entered into an underwriting agreement (the “Underwriting Agreement”) with WallachBeth Capital, LLC and Network 1 Financial Securities, Inc. (the “Underwriters”), related to the Company’s initial public offering of 1,178,532 shares of the Company’s common stock, at a price of $6.00 per share, less $0.60 constituting the underwriting commissions and non-accountable expense allowance. Under the terms of the Underwriting Agreement, the Company granted the Underwriters an option, exercisable for 45 days, to purchase up to an additional 176,780 shares of common stock to cover over-allotments, if any. Total gross proceeds from the offering were $7,071,192 and the Company received net proceeds after costs of $5,977,924. +Coincident with the closing of the IPO, the Company retired all of its principal debt of $3,440,000 and approximately $283,000 of accrued interest through the issuance of approximately 857,048 shares. +We experienced negative cash flow used in operations during the twelve months ended December 31, 2017 of $3,211,401 compared to negative cash flow used in operations for the twelve months ended December 31, 2016 of $1,312,267. The negative cash flow was met by cash reserves, issuances of short term debt, sale of an exclusive license to sell our Zika test and related mosquito borne illnesses and most recently from the issuances of common stock incident to the completion of our initial public offering. The amount of our operating deficit could decrease or increase significantly depending on strategic and other operating decisions, thereby affecting our need for additional capital. We expect our operating losses will continue until we are able to generate revenue. Until our operations become profitable, we will continue to rely on proceeds received from our initial public offering. We expect additional investment capital to come from (i) additional private placements of our common stock with existing and new investors and (ii) the private placement of other securities with investors similar to those that have provided funding in the past. +Our monthly cash operating expenses, including our technology research and development expenses and interest expense, were approximately $267,616 per month during the year ended December 31, 2017. Our operating expenses increased significantly upon completion of our initial public offering as we increased development and sales activities in furtherance of our business plan. We did not have sufficient capital resources at December 31, 2016 to fund our negative cash flow for the next year without raising additional capital and therefore in July completed our initial public offering to fund operations until we commence sales of products. The foregoing estimates, expectations and forward-looking statements are subject to change as we make strategic operating decisions from time to time and as our expenses fluctuate from period to period. +15 +Table of Contents +The amount of our operating deficit could decrease or increase significantly depending on strategic and other operating decisions, thereby affecting our need for additional capital. We expect our operating expenses will continue until we are able to generate revenue. Our business model contemplates that revenue will commence in 2018 and our need for additional investment will depend on the amount of revenue generated. +Our long-term liquidity is dependent upon execution of our business model and the commencement of revenue generating activities and working capital as described above, and upon capital needed for continued commercialization and development of our diagnostic testing technology. Commercialization and future development of diagnostic tests utilizing our PCR technology are expected to require additional capital estimated to be approximately $850,000 annually for the foreseeable future. This estimate will increase or decrease depending on specific opportunities and available funding. +To date, we have met our working capital needs primarily through funds received from sales of our common stock and from convertible debt financings. Until our operations become profitable, we will continue to rely on proceeds received from external funding. We expect additional investment capital may come from additional private placements of our common stock with existing and new investors and the private placement of other securities with investors similar to those that have provided funding in the past. +Off-Balance Sheet Arrangements +As of December 31, 2017, we had no off-balance sheet arrangements. +ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Not required. +16 +Table of Contents +ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATE. +CONSOLIDATED FINANCIAL STATEMENTS +DECEMBER 31, 2017 AND 2016 +Table of Contents +Report of Independent Registered Public Accounting Firm +F-1 +Balance Sheets +F-2 +Statements of Operations +F-3 +Statement of Changes in Stockholders’ Equity (Deficit) +F-4 +Statements of Cash Flows +F-5 +Notes to Financial Statements +F-6 +17 +REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +To the Board of Directors and +Stockholders of Co-Diagnostics, Inc. and Subsidiaries +Opinion on the Financial Statements +We have audited the accompanying consolidated balance sheets of Co-Diagnostics, Inc. (the Company) as of December 31, 2017 and 2016, and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for each of the years in the two-year period ended December 31, 2017, and the related notes and schedules (collectively referred to as the financial statements). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, 2017, in conformity with accounting principles generally accepted in the United States of America. +Basis for Opinion +These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. +Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion. +/s/ Haynie & Company +Haynie & Company +We have served as the Company’s auditor since 2016 +Salt Lake City, Utah +March 27, 2018 +F-1 +Table of Contents +CO-DIAGNOSTICS, INC. AND SUBSIDIARIES +CONSOLIDATED BALANCE SHEETS +December 31, +2017 +December 31, +2016 +ASSETS: +Current Assets +Cash and cash equivalents +$ +3,534,454 +$ +998,737 +Other receivables +-- +3,183 +Inventory +9,068 +-- +Prepaid expenses +908,352 +206,478 +Total current assets +4,451,874 +1,208,398 +Property and equipment, net +165,567 +87,429 +Investment in joint venture +44,885 +-- +Total other long-term assets +210,452 +87,429 +Total assets +$ +4,662,326 +$ +1,295,827 +LIABILITIES AND STOCKHOLDERS’ EQUITY: +Current Liabilities +Accounts payable +$ +40,819 +$ +29,934 +Accounts payable (related party) +-- +75,000 +Accrued expenses +96,645 +101,239 +Accrued expenses (related party) +480,000 +690,168 +Current notes payable net of $0 and $87,605 discount, respectively +-- +2,111,895 +Current notes payable (related party) net of $0 and $263 discount, respectively +-- +837,177 +Deferred income current +10,792 +-- +Total current liabilities +628,256 +3,845,413 +Long-term Liabilities +Notes payable long-term +-- +445,000 +Deferred income long-term +183,546 +-- +Total long-term liabilities +183,546 +445,000 +Total liabilities +811,802 +4,290,413 +Commitments and contingencies +STOCKHOLDERS’ EQUITY (DEFICIT): +Common stock, $.001 par value, 180,000,000 shares authorized; 12,317,184 and 9,882,395 shares issued and outstanding as of December 31, 2017 and 2016, respectively. +12,317 +9,882 +Additional paid-in capital +16,260,651 +2,458,744 +Accumulated deficit +(12,422,444 +) +(5,463,212 +) +Total stockholders’ equity (deficit) +3,850,524 +(2,994,586 +) +Total liabilities and stockholders’ equity (deficit) +$ +4,662,326 +$ +1,295,827 +See accompanying notes to consolidated financial statements. +F-2 +Table of Contents +CO-DIAGNOSTICS, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF OPERATIONS +FOR THE YEARS ENDED DECEMBER 31, 2017 AND 2016 +For the years ended +December 31, +2017 +2016 +Net sales +$ +7,662 +$ +-- +Cost of sales +302 +-- +Gross profit +7,360 +-- +Operating expenses: +Selling and marketing +426,711 +122,105 +Administrative and general +3,095,791 +796,896 +Research and development +1,003,167 +731,474 +Depreciation and amortization +45,758 +37,491 +Total operating expenses +4,571,427 +1,687,966 +Total operating loss +(4,564,067 +) +(1,687,966 +) +Other expense: +Interest expense +(310,233 +) +(240,720 +) +Interest income +3,829 +-- +Loss on extinguishment of debt +(2,072,365 +) +-- +Net loss from investment in joint venture +(16,396 +) +-- +Total other expense +(2,395,165 +) +(240,720 +) +Loss before income taxes +(6,959,232 +) +(1,928,686 +) +Provision for income taxes +-- +-- +Net loss +$ +(6,959,232 +) +$ +(1,928,686 +) +Net loss per share – basic and diluted +$ +(0.63 +) +$ +(0.20 +) +Weighted average shares – basic and diluted +10,960,326 +9,882,395 +See accompanying notes to consolidated financial statements. +F-3 +Table of Contents +CO-DIAGNOSTICS, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT) +FOR THE YEARS ENDED DECEMBER 31, 2017 AND 2016 +Common Stock +Additional +Paid-in +Retained +Earnings +Equity +Shares +Amount +Capital +(Deficit) +(Deficit) +Balance, December 31, 2015 +9,882,395 +$ +9,882 +$ +2,377,265 +$ +(3,534,526 +) +$ +(1,147,379 +) +Issuance of convertible debt warrants +-- +-- +11,914 +-- +11,914 +Stock-based compensation +-- +-- +69,565 +-- +69,565 +Net loss +-- +-- +-- +(1,928,686 +) +(1,928,686 +) +Balance, December 31, 2016 +9,882,395 +9,882 +2,458,744 +(5,463,212 +) +(2,994,586 +) +Stock issued for cash, net of offering costs of $1,093,268 +1,178,533 +1,179 +5,976,745 +-- +5,977,924 +Stock issued for debt retirement +857,047 +857 +5,791,603 +-- +5,792,460 +Stock based compensation +399,209 +399 +2,033,559 +2,033,958 +Net loss +-- +-- +-- +(6,959,232 +) +(6,959,232 +) +Balance, December 31, 2017 +12,317,184 +$ +12,317 +$ +16,260,651 +$ +(12,422,444 +) +$ +(3,850,524 +) +See accompanying notes to consolidated financial statements. +F-4 +Table of Contents +CO-DIAGNOSTICS, INC. AND SUBSIDIARIES +CONSOLIDATED STATEMENTS OF CASH FLOWS +FOR THE YEARS ENDED DECEMBER 31, 2017 AND 2016 +Years Ended +December 31, +2017 +2016 +Cash flows from operating activities : +Net loss +$ +(6,959,232 +) +$ +(1,928,686 +) +Adjustments to reconcile net loss to net cash used in operating activities: +Depreciation and amortization +45,758 +37,491 +Stock based compensation +2,033,958 +69,565 +Accretion of notes payable discount +84,101 +21,516 +Loss on extinguishment of debt +2,072,365 +-- +Other losses +16,396 +-- +Changes in assets and liabilities: +Increase deferred income +194,338 +473,062 +Decrease (increase) in prepaid and other assets +(698,389 +) +14,785 +Increase in inventory +(9,068 +) +-- +Increase in accounts payable and accrued expenses +8,372 +-- +Net cash used in operating activities +(3,211,401 +) +(1,312,267 +) +Cash flows from investing activities: +Purchase of fixed assets +(129,306 +) +(12,241 +) +Investment in joint venture +(60,000 +) +-- +Net cash used by investing activities +(189,306 +) +(12,241 +) +Cash flows from financing activities: +Proceeds from equity financing +7,071,192 +-- +Offering costs from equity financing +(1,093,268 +) +-- +Proceeds from debt financing +-- +1,871,950 +Proceeds from debt financing (related party) +-- +502,440 +Principal payments on debt +-- +(14,950 +) +Principal payments on debt (related party) +(41,500 +) +(70,000 +) +Net cash provided by financing activities +5,936,424 +2,289,440 +Net increase (decrease) in cash +2,535,717 +964,932 +Cash and cash equivalents beginning of period +998,737 +33,805 +Cash and cash equivalents end of period +$ +3,534,454 +$ +998,737 +Supplemental disclosure of cash flow information: +Interest paid +$ +73,523 +$ +10,050 +Income taxes paid +$ +-- +$ +-- +Schedule of non-cash (investing) and financing activities: +Warrants issued with convertible debt +$ +-- +$ +11,914 +Common stock issued for convertible debt +$ +5,792,460 +$ +-- +See accompanying notes to consolidated financial statements. +F-5 +Table of Contents +CO-DIAGNOSTICS, INC. AND SUBSIDIARIES +NOTES TO CONSOLIDATED FINANCIAL STATEMENTS +YEARS ENDED DECEMBER 31, 2017 AND 2016 +NOTE 1: ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Co-Diagnostics, Inc. (“Company,” “CDI,” “we”), a Utah corporation headquartered in Salt Lake City, Utah, is a molecular diagnostics company formed in April, 2013 that develops, manufactures and markets a new diagnostics technology. +The accompanying consolidated financial statements include our accounts and the accounts of our wholly-owned subsidiary. All intercompany account balances and transactions have been eliminated in consolidation. +We entered into a joint venture agreement with a company in India for the purpose of setting up a manufacturing location in India of our products and for distribution of our products in India. We invested $60,000 in 2017 for our 50% interest in the joint venture. We determined that we had a variable interest in the joint venture company, which is considered a variable interest entity, but that we were not the primary beneficiary as the power to direct the significant activities of the joint venture company are shared. Therefore, we used the equity method of accounting to record our investment in the joint venture. Our equity method investees are recorded in other long-term assets in the accompanying consolidated balance sheet. Our share of earnings or losses from equity method investees is included in other losses in the accompanying consolidated statements of operations. +The Company evaluates its equity method investments for impairment whenever events or changes in circumstances indicate that the carrying amounts of such investments may not be recoverable. The difference between the carrying value of the equity method investment and its estimated fair value is recognized as an impairment charge when the loss in value is deemed other than temporary. +Profits from the partnership shall be divided as follows: +Profit Level +CDI +Share +Partner +Share +Up to $1,000,000 +50 +% +50 +% +$1,000,000-$2,000,000 +60 +% +40 +% +$2,000,000-$3,000,000 +70 +% +30 +% +Above $3,000,000 +80 +% +20 +% +The joint venture partner will be reimbursed for some expenses, such as approximately $30,000 for office space. If the joint venture needs additional funding, it will be achieved through loans obtained by the joint venture, or if loans are not available on commercially reasonable terms, from capital contributions. There is no term to the joint venture agreement but it can be dissolved by mutual agreement or by one party upon a material breach by the other party. +Basis of Presentation +The accompanying audited consolidated financial statements of Co-Diagnostics, Inc. have been prepared to reflect the financial position, results of operations and cash flows of the Company and have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). +Reverse Stock Split +On May 24, 2017 the Company affected an 11 to 1 reverse stock split. The statements in this report have been prepared showing the effect as of the beginning of the periods included. +F-6 +Table of Contents +Initial Public Offering +On July 12, 2017, we entered into an underwriting agreement (the “Underwriting Agreement”) with WallachBeth Capital, LLC and Network 1 Financial Securities, Inc. (the “Underwriters”), related to the Company’s initial public offering of 1,178,533 shares of the Company’s common stock, at a price of $6.00 per share, less $0.60 constituting the underwriting commissions and expense allowance. Under the terms of the Underwriting Agreement, the Company granted the Underwriters an option, exercisable for 45 days, to purchase up to an additional 176,780 shares of common stock to cover over-allotments, if any. Total gross proceeds from the offering were $7,071,192 and the Company received net proceeds after costs of $5,977,924. +Coincident with the closing of the IPO, the Company retired all of its principal debt of $3,440,440 and $283,423 of accrued interest through the issuance of 857,047 shares of common stock. +Significant Account Policies +Cash and Cash Equivalents +The Company considers all cash on hand and in banks, and highly liquid investments to be cash equivalents. At December 31, 2017, the Company had $3,284,454 in bank balances in excess of amounts insured by the Federal Deposit Insurance Corporation. Included in cash and cash equivalents are $2,200,288 in short-term federally insured certificates of deposits. At December 31, 2016, the Company had $748,737 in bank balances in excess of amounts insured by the Federal Deposit Insurance Corporation. The Company has not experienced any losses in such accounts, and management believes the Company is not exposed to any significant credit risk on cash and cash equivalents. +Inventory +Inventory is stated at the lower of cost or market. Inventory cost is determined on a first-in first-out basis that approximates average cost in accordance with ASC 330-10-30-12. Provisions are made to reduce slow-moving, obsolete, or unusable inventories to their estimated useful or scrap values. The Company establishes reserves for this purpose. +Accounts Receivable +Trade accounts receivable are carried at original invoice amount less an estimate made for doubtful receivables based on a review of all outstanding amounts on a monthly basis. Management determines the allowance for doubtful accounts by identifying troubled accounts and by using historical experience applied to an aging of accounts. Trade receivables are written off when deemed uncollectible. Recoveries of trade receivables previously written off are recorded when collected. +Property and Equipment +Property and equipment are stated at cost. Depreciation is provided using the straight-line method over the estimated useful lives of the property, generally from three to five years. Repairs and maintenance costs are expensed as incurred except when such repairs significantly add to the useful life or productive capacity of the asset, in which case the repairs are capitalized. +Equity-Method Investments +Our equity method investments are initially recorded at costs and are included in other long-term assets in the accompanying consolidated balance sheet. We adjust the carrying value of our investment based on our share of the earnings or losses in the periods which they are reported by the investee until the carrying amount is zero. The earnings or losses are included in other losses in the accompanying consolidated statements of operations. +In 2017, we entered into a joint venture agreement with Synbiotocs Limited, a pharmaceutical manufacturing company in India, for the purpose of setting up a manufacturing location of our products in India and for distribution of our products in India. We invested $60,000 in 2017 for our 50% interest in the joint venture, CoSara. We determined that we had a variable interest in the joint venture company, which is considered a variable interest entity, but that we were not the primary beneficiary as the power to direct the significant activities of the joint venture company are shared. Therefore, we used the equity method of accounting to record our investment in the joint venture. +F-7 +Table of Contents +Earnings (Loss) per Share +Basic earnings or loss per common share is computed by dividing net income or loss applicable to common shareholders by the weighted average number of shares outstanding during each period. As the Company experienced net losses during the years ending December 31, 2017 and 2016, no common stock equivalents have been included in the diluted earnings per common share calculations as the effect of such common stock equivalents would be anti-dilutive. As of December 31, 2017 and 2016, there were 1,028,969 and 634,727 potentially dilutive shares, respectively. +Stock-based Compensation +The Company accounts for stock-based compensation under the provisions of FASB ASC Topic 718, Compensation-Stock Compensation (“ASC 718”), which requires the measurement and recognition of compensation expense for all stock-based awards made to employees and directors based on estimated fair values on the grant date. The Company estimates the fair value of stock-based awards on the date of grant using the Black-Scholes-Merton option-pricing model (the “Black-Scholes Model”). The value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service periods using the straight-line method. +The Company estimates forfeitures at the time of grant and revises its estimate in subsequent periods if actual forfeitures differ from those estimates. +The Company accounts for stock-based compensation awards to non-employees in accordance with FASB ASC Topic 505-50, Equity-Based Payments to Non-Employees (“ASC 505-50”). Under ASC 505-50, the Company determines the fair value of the warrants or stock-based compensation awards granted as either the fair value of the consideration received or the fair value of the equity instruments issued, whichever is more reliably measurable. +All issuances of stock options or other equity instruments to employees and non-employees as the consideration for goods or services received by the Company are accounted for based on the fair value of the equity instruments issued or the fair market value of the services provided. Any stock options issued to non-employees are recorded in expense and additional paid-in capital in shareholders’ equity over the applicable service periods using variable accounting through the vesting dates based on the fair value of the options at the end of each reporting period. +Income Taxes +We account for income taxes in accordance with the asset and liability method of accounting for income taxes prescribed by ASC Topic 740. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to the taxable income in the years in which those temporary differences are expected to be recovered or settled. +Deferred taxes are provided on an asset and liability method whereby deferred tax assets are recognized for deductible temporary differences and operating loss and tax credit carry-forwards and deferred tax liabilities are recognized for taxable temporary differences. Temporary differences are the differences between the reported amounts of assets and liabilities and their tax bases. Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates on the date of enactment. +Research and Development +Research and development costs are expensed when incurred. The Company expensed $1,003,167 and $731,474 of research and development costs for the years ended December 31, 2017 and 2016, respectively. +F-8 +Table of Contents +Use of Estimates +The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the amounts reported in the financial statements and the accompanying notes. Such estimates include receivables and other long lived assets, legal and regulatory contingencies, income taxes, share based arrangements, and others. These estimates and assumptions are based on management’s best estimates and judgments. Actual amounts and results could differ from those estimates. +Fair Value Measurements +The carrying amounts of our accounts receivable, accounts payable and accrued liabilities approximate their fair values due to their immediate or short-term maturities. The aggregate carrying amount of the notes payable approximates fair value as the individual notes bear interest at market interest rates and there has not been a significant change in our operations and risk profile. +Patents and Intangibles +Patents represent initial legal costs incurred to apply for United States and international patents on the diagnostic testing technology, and are amortized on a straight-line basis over their useful life of approximately 20 years. We have filed patent applications in the United States and foreign countries. As of March 19, 2018, the U.S. Patent and Trademark Office or PTO had approved three patents. Additionally, we had two pending patent applications, including U.S. and foreign counterpart applications. While we are unsure whether we can develop the technology in order to obtain the full benefits of the issued patents, the patents themselves hold value and could be sold to companies with more resources to complete the development. On-going legal expenses incurred for patent follow-up have been expensed from April 2013 forward. +Long-Lived Assets +We review our long-lived assets, including patents, whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets held and used is measured by a comparison of the carrying amount of an asset to future un-discounted net cash flows expected to be generated by the asset. If such assets are considered to be impaired, then the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. Fair value is determined by using cash flow analyses and other market valuations. After our review at December 31, 2017, it was determined that no adjustment was required. +Customer Leased Equipment +Customer leased equipment is capitalized and depreciated using the straight-line method over the estimated useful life of the equipment, generally from three to five years. The expense for the depreciation on this equipment is included in cost of sales. The company typically retains ownership of this equipment. +Revenue Recognition +We recognize revenue when evidence exists that there is an arrangement between us and our customers, delivery of products sold or service has occurred, the selling price to our customers is fixed and determinable with required documentation, and collectability is reasonably assured. We recognize as deferred revenue, payments made in advance by customers for products not yet provided. +In instances where we have entered into license agreements with a third parties to use our technology within their product offering, we recognize any base or prepaid revenues over the term of the agreement and any per occurrence or periodic usage revenues in the period they are earned. +F-9 +Table of Contents +Related-Party Transactions +Parties are considered to be related to the Company if the parties directly or indirectly, through one or more intermediaries, control, are controlled by, or are under common control with the Company. Related parties also include principal stockholders of the Company, its management, members of the immediate families of principal stockholders of the Company and its management and other parties with which the Company may deal where one party controls or can significantly influence the management or operating policies of the other to an extent that one of the transacting parties might be prevented from fully pursuing its own separate interests. The Company discloses all material related-party transactions. All transactions shall be recorded at fair value of the goods or services exchanged. Property purchased from a related party is recorded at the cost to the related party and any payment to or on behalf of the related party in excess of the cost is reflected as compensation or distribution to related parties depending on the transaction. +Recently Issued Accounting Standards +In March 2017, the FASB issued ASU 2017-08, Receivables – Nonrefundable Fees and Other Costs (Subtopic 310-20) . The amendments in this update shorten the amortization period for certain callable debt securities held at a premium. Specifically, the amendments require the premium to be amortized to the earliest call date. The amendments do not require an accounting change for securities held at a discount; the discount continues to be amortized to maturity. For public business entities, the amendments in this update are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018. This update is not expected to have a significant impact on the Company’s financial statements. +In January 2017, the FASB has issued (“ASU”) No. 2017-03. Investments — Equity Method and Joint Ventures (Topic 323) This standard addresses specific guidance on applying the equity method of accounting to investments in partnerships, unincorporated joint ventures and limited liability companies. The new authoritative guidance is effective for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Earlier application is permitted. Management is currently evaluating the impact that the updated standard will have on its consolidated financial statements and related disclosures. +In February 2016, the FASB issued Accounting Standards Update (“ASU”) No. 2016-02 Leases , which requires recognition of leased assets and liabilities on the balance sheet and disclosing key information about leasing arrangements. This update is effective for annual periods and interim periods with those periods beginning after December 15, 2018. Management is currently evaluating the impact that the updated standard will have on its consolidated financial statements and related disclosures. +In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, to clarify guidance on the presentation and classification of certain cash receipts and payments in the statement of cash flows. This update was issued with the intent of reducing diversity in practice with respect to eight types of cash flows. This guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. The update is not expected to have a significant impact on the Company’s financial statements. +In May 2014, the FASB issued ASU No. 2014-09: "Revenue from Contracts with Customers (Topic 606)" which supersedes the revenue recognition requirements in ASC Topic 605, "Revenue Recognition", and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The new authoritative guidance is effective for interim and annual periods beginning after December 15, 2017. The Company will apply the guidance when recognizing revenue, but the update is not expected to have a significant impact on the Company’s financial statements since the Company’s revenue is currently immaterial. +F-10 +Table of Contents +NOTE 2: NOTES PAYABLE +The recorded value of our notes payable (net of debt discount) for the years ending December 31, 2017 and 2016, were as follows: +December 31, +2017 +December 31, +2016 +Notes payable, net of debt discount +R. Phillip Zobrist Convertible Note +$ +-- +$ +99,664 +Pine Valley Investments, LLC. Revolving Line of Credit Promissory Note +-- +86,000 +Legends Capital Opportunity Fund, LLC Convertible Notes +-- +25,000 +Robert Salna Convertible Promissory Note +-- +192,427 +December 2016 Notes Payable +-- +105,000 +Zika Diagnostics, Inc. +-- +445,000 +Bridge Notes Payable +-- +1,603,804 +Total +-- +2,556,895 +Less Current Portion +-- +(2,111,895 +) +Total Long-term +$ +-- +$ +445,000 +Notes payable (related party), net of debt discount +Co Diagnostics, Ltd. Revolving Line of Credit Promissory Note +$ +-- +$ +609,940 +Legends Capital Group, LLC Convertible Note +-- +99,737 +Clavo Rico Promissory Note +-- +10,000 +Legends Capital Group, LLC. Revolving Line of Credit Promissory Note +-- +10,000 +Hamilton Mining Resources, Inc. Revolving Line of Credit Promissory Note +-- +66,000 +Machan 1988 Property Trust Revolving Line of Credit Promissory Note +-- +41,500 +Total Related Party +-- +837,177 +Less Current Portion Related Party +-- +(837,177 +) +Total Long-term Related Party +$ +-- +$ +-- +Beaufort Capital Partners, LLC Convertible Note +On May 15, 2015, the Company entered into a $500,000 Convertible Promissory Note with Beaufort Capital Partners, LLC. The note bore a 12% annual interest rate and is due monthly. The principal was due on April 30, 2016, and because it was not paid, the note was in default. The holder filed a lawsuit in Third District Court in Salt Lake City, Utah and was awarded a judgment on June 6, 2016. The holder agreed to forbear any collection proceedings pursuant to a Forbearance Agreement dated August 8, 2016, through October 31, 2016, in consideration of interest payments which have been made since the Forbearance Agreement was executed. The note contained a conversion feature allowing the principal and any unpaid accrued interest to be converted into common shares of the company at a rate of $8.25 or 20% less than the price of the anticipated Initial Public Offering, whichever is less, per share at the discretion of the note holder. The conversion feature was not accounted for as a derivative because it was not deemed to be beneficial. In addition, the equity and liability components of the convertible note were not separately accounted for since the conversion price did not bear any relationship to the value of the privately held stock rendering the exercise of the conversion feature improbable. In addition, the Note contained an adjustment provision effective in the event of stock dividends, splits and combinations that adjusts the conversion price such that the holder would receive the same number of shares of stock upon conversion that holder would have had after the stock adjustment event if the conversion had taken place prior to the stock adjustment event. The Company had received $490,000 on the origination date with $10,000 being withheld as points paid by the Company, additionally the Company paid a $25,000 finders fee. The $35,000 represented by the points and finders fee had been recorded as a discount to the principal of the note and was accreted over the term of the note. In December, 2016, the holder agreed to convert the $500,000 principal of the note along with $83,500 of unpaid accrued interest into the Company’s Bridge Notes Payable detailed below. +For the year ended December 31, 2016, $12,066 was accreted for the note discount and included in interest expense. Interest of $91,000 related to the note principal was included in interest expense for the year ended December 31, 2016. For the year ended December 31, 2016 we made cash payments totaling $10,000 in accrued interest. +F-11 +Table of Contents +R. Phillip Zobrist Convertible Note +On December 1, 2015, the Company entered into a $100,000 Convertible Promissory Note with R. Phillip Zobrist. The note bore an 8.5% annual interest rate and was due semi annually. The principal was due on September 30, 2017. The note contains a conversion feature allowing the principal and any unpaid accrued interest to be converted into common shares of the company at a rate of $11.00 or 20% less than the price of the anticipated Initial Public Offering, whichever is less, per share at the discretion of the note holder. The conversion feature was not accounted for as a derivative because it was not deemed to be beneficial. In addition, the equity and liability components of the convertible note were not separately accounted for since the conversion price did not bear any relationship to the value of the privately held stock rendering the exercise of the conversion feature improbable. In addition, the Note contains an adjustment provision effective in the event of stock dividends, splits and combinations that adjusts the conversion price such that the holder would receive the same number of shares of stock upon conversion that holder would have had after the stock adjustment event if the conversion had taken place prior to the stock adjustment event. +On July 12, 2017, the Company concluded an initial public offering. Coincident with the closing of the IPO, the Company retired all of its principal debt and outstanding accrued interest through the issuance of common stock. The note holder converted the $100,000 principal and $13,718 of accrued and unpaid interest into 23,691 shares of our common stock at a conversion price of $4.80 per share. The fair value of the shares issued in this exchange less the carrying value of the note resulted in a loss on extinguishment of debt of $28,528. +The note holder also received a warrant to purchase up to 4,545 shares of our common stock at a price of the lesser of $11.00 or the offering price of an initial public offering of the Company common stock during the term of the warrant. The warrant expires on November 12, 2020, the Company calculated a note discount for the value of the warrant received by the note holder of $824 using a Black-Scholes pricing model with the following assumptions: (i) risk free interest rate 1.59%, (ii) expected life (in years) of 5; (iii) expected volatility of 97.60%; (iv) expected dividend yield of 0.00%; and (v) stock trading price of $0.638. The $824 valuation of warrant was accreted over the term of the note and for the years ended December 31, 2017 and 2016, $236 and $451, respectively was included in interest expense. Interest of $4,510 and $8,500 related to the note principal was included in interest expense for the years ended December 31, 2017 and 2106, respectively. +Pine Valley Investments, LLC. Revolving Line of Credit Promissory Note +On December 30, 2015, the Company entered into a Revolving Line of Credit Promissory Note with Pine Valley Investments, LLC, a Utah limited Liability Company, with a maximum limit on advances of $100,000. The note bore a 12% annual interest rate on advances received. All accrued and unpaid interest along with the total sum of any outstanding advances were due on September 30, 2017. The note holder agreed that in the event the Company was able to file a Registration Statement for an Initial Public Offering to include the Note principal and accrued interest outstanding on the filing date with the Registration Statement to convert all of the Note principal and accrued interest to common stock of the Company. At December 31, 2016, the Company had net outstanding balances due on advances received of $86,000. +On July 12, 2017, the Company concluded an initial public offering. Coincident with the closing of the IPO, the Company retired all of its principal debt and outstanding accrued interest through the issuance of common stock. The note holder converted the $86,000 principal and $9,626 of accrued and unpaid interest in to 22,768 shares of our common stock at a conversion price of $4.20 per share. The fair value of the shares issued in this exchange less the carrying value of the note resulted in a loss on extinguishment of debt of $40,982. Interest of 3,845 and $5,826 related to the note principal was included in interest expense for the years ended December 31, 2017 and 2016, respectively. +F-12 +Table of Contents +Legends Capital Opportunity Fund, LLC Convertible Notes +In August 2016, the Company entered into two convertible promissory notes with Legends Capital Opportunity Fund, LLC. At June 30, 2017 the aggregate principal due on these notes was $25,000. The notes bore interest at the rate of 10% per annum and were due on December 31, 2017. The notes provided that the principal and interest on the notes would be convertible to shares of common stock at a conversion rate of $8.25 per share or seventy percent (70%) of the anticipated initial public offering (“IPO”) price per share. In addition, the Notes contained an adjustment provision effective in the event of stock dividends, splits and combinations that adjusts the conversion price such that the holder would receive the same number of shares of stock upon conversion that holder would have had after the stock adjustment event if the conversion had taken place prior to the stock adjustment event. +On July 12, 2017, the Company concluded an initial public offering. Coincident with the closing of the IPO, the Company retired all of its principal debt and outstanding accrued interest through the issuance of common stock. The note holder converted the $25,000 principal and $2,186 of accrued and unpaid interest in to 7,615 shares of our common stock at a conversion price of $3.57 per share. The fair value of the shares issued in this exchange less the carrying value of the note resulted in a loss on extinguishment of debt of $18,504. Interest of $1,313 and $874 related to the notes principal was included in interest expense for the years ended December 31, 2017and 2016, respectively. +Robert Salna Convertible Promissory Note +In September 2016, the Company entered into a convertible promissory note in the principal amount of $200,000, with Robert Salna. The note bore interest at the rate of 10% per annum and was due on December 31, 2017. The note provided that the principal and interest on the note would be convertible to shares of common stock at a conversion rate of the lesser of $8.25 per share or a discount of 15% to the conversion price of a bridge financing, which bridge financing, was completed on December 12, 2016. In addition, the Note contained an adjustment provision effective in the event of stock dividends, splits and combinations that adjusted the conversion price such that the holder would receive the same number of shares of stock upon conversion that holder would have had after the stock adjustment event if the conversion had taken place prior to the stock adjustment event. The Company paid a $10,000 finder’s fee which had been recorded as a discount to the principal of the note and was accreted over the term of the note. +On July 12, 2017, the Company concluded an initial public offering. Coincident with the closing of the IPO, the Company retired all of its principal debt and outstanding accrued interest through the issuance of common stock. The note holder converted the $200,000 principal and $16,833 of accrued and unpaid interest in to 60,738 shares of our common stock at a conversion price of $3.57 per share. The fair value of the shares issued in this exchange less the carrying value of the note resulted in a loss on extinguishment of debt of $151,184. For the years ended December 31, 2017 and 2016, $3,983, and $2,427 respectively, was accreted for the note discount and included in interest expense. Interest of $10,500 and $6,333 related to the note principal was included in interest expense for the years December 31, 2017and 2016, respectively. +December 2016 Notes Payable +In December 2016, the Company entered into convertible promissory notes with two individuals and one company in the aggregate of $105,000. The notes bore interest at the rate of 10% per annum and were due on December 31, 2017. The notes provided that the principal and interest on the notes would be convertible to shares of common stock at a conversion rate of the lesser of $8.25 per share or seventy percent (70%) of the anticipated initial public offering (“IPO”) price per share. In addition, the Note contained an adjustment provision effective in the event of stock dividends, splits and combinations that adjusted the conversion price such that the holder would receive the same number of shares of stock upon conversion that holder would have had after the stock adjustment event if the conversion had taken place prior to the stock adjustment event. +On July 12, 2017, the Company concluded an initial public offering. Coincident with the closing of the IPO, the Company retired all of its principal debt and outstanding accrued interest through the issuance of common stock. The note holders converted the $105,000 principal and $6,333 of accrued and unpaid interest into 26,508 shares of our common stock at a conversion price of $4.20 per share. The fair value of the shares issued in this exchange less the carrying value of the note resulted in a loss on extinguishment of debt of $47,715. Interest of $5,571 and $762 related to the notes principal was included in interest expense for the years ended December 31, 2017 and 2016, respectively. +F-13 +Table of Contents +Zika Diagnostics, Inc. Note Payable +On October 11, 2016, the Company entered into an exclusive license agreement with Watermark Group, Inc., a Nevada corporation, (“Watermark”) which granted the exclusive license to sell the Company’s proprietary molecular diagnostic tests for the Zika virus and other mosquito borne illnesses in exchange for an initial royalty of $500,000 and a royalty of 10% of net sales. The license was cancelled as described hereafter. Also as part of the transaction the Company entered into a stock purchase agreement with the major shareholder of Watermark for the purchase of 3,600,000 shares of common stock in Watermark for $55,000, which constituted a controlling interest in Watermark. Watermark subsequently changed its name to Zika Diagnostics, Inc. contemporaneously, with the execution of those two agreements, Watermark secured an investment of $1.05 million from an individual for the purchase of shares of Watermark, $0.5 million of which was paid to the Company pursuant to the exclusive license agreement as an initial royalty payment. As an integral part of the license agreement and the stock purchase agreement, the Company required that Watermark be debt free for the transaction to close. It was represented that a related party loan (“Related Note”) on the books of Watermark as of July 31, 2016 in the approximate amount of $172,000 plus accrued interest was satisfied. The Company was furnished written documentation from what was purported to be the then holder of the Related Note (“Tide Pool Ventures”) and a written confirmation from the original holder of the Related Note (“P&G Holdings”) that the debt was satisfied. The seller of the Watermark stock purchased by the Company also represented that the Related Note was satisfied as a condition to the stock purchase agreement. On or about January 10, 2017, the Company and Watermark were notified by P&G Holdings that the Related Note was not only still outstanding, but that it was in default and payment was demanded. On January 31, 2017, P&G Holdings filed a lawsuit in Federal District Court in New York demanding payment of the Related Note, all accrued interest thereon and attorney’s fees and that stock be issued such that P&G Holdings would own 80% of the issued and outstanding shares of stock of Watermark. +During the investigation undertaken by the Company to determine why the Note was still outstanding it was discovered that the written confirmation originally furnished to the Company by P&G Holdings appeared to have been forged, that the Related Note had never been transferred to Tide Pool Ventures, and that there were documents requesting issuances of stock from the Watermark transfer agent that appeared to have forged signatures of the then president of Watermark. +In light of these irregularities, the Company determined that it would unwind the transaction by terminating the license agreement effective as of October 11, 2016 and rescinding the stock purchase, which it did on March 22, 2017. Under the terms of the rescission and cancellation of the license agreement, the Company returned the shares of stock of Watermark that it held to the seller of the stock and agreed to repay a portion of the initial license fee it received. In that connection the Company reversed the amortization of the deferred revenue originally recognized and removed the deferred revenue accounts related to the license agreement to reflect the license termination and in addition removed the investment in Watermark which reflected the cost of the stock purchased ($55,000) and set up a note payable to Watermark of $445,000. The note principal was due December 31, 2020 and was non-interest bearing. On March 20, 2017, a new note was entered into, replacing the previous note for the $445,000 principal balance due, for which the maturity date was September 30, 2017 and established an annual interest rate of 12%. +On July 12, 2017, the Company concluded an initial public offering. Coincident with the closing of the IPO, the Company retired all of its principal debt and outstanding accrued interest through the issuance of common stock. The note holder converted the $445,000 principal and $17,800 of accrued and unpaid interest into 77,133 shares of our common stock at a conversion price of $6.00 per share. The fair value of the shares issued in this exchange less the carrying value of the note resulted in a gain on extinguishment of debt of $2. For the year ended December 31, 2017, $17,800 was included in interest expense. +F-14 +Table of Contents +Bridge Notes Payable +In December 2016, the Company entered into convertible promissory notes with six individuals and five companies, in the aggregate principal amount of $1,683,500 which consisted of (a) $1,100,000 of new investor funding and (b) $583,500 representing the satisfaction of the $500,000 note principal plus $83,500 of accrued interest on the Beaufort Capital Partners, LLC Convertible Note. The notes bore interest at the rate of 15% per annum and were due in June 2017. The notes provided that the principal and interest on the notes would be convertible to shares of common stock at a conversion rate of the lesser of $8.25 per share or seventy percent (70%) of the initial public offering (“IPO”) price per share. The notes were secured by all of the assets of the Company. The Company (i) received $1,041,000 in cash (net of $59,000 in commissions withheld) and, (ii) converted $583,500 of principal and interest from the Beaufort Capital Partners, LLC Convertible Note mentioned above. The Company agreed to register the shares underlying the bridge notes and the warrants underlying the bridge notes. The transaction documents contained negative covenants that included restrictions on the repayment of debt and issuance of dividends, restrictions on new debt (including restrictions on variable rate loans) and new security interests on the Company’s assets and other customary restrictions. In addition, the Notes contained an adjustment provision effective in the event of stock dividends, splits and combinations that adjusted the conversion price such that the holder would receive the same number of shares of stock upon conversion that holder would have had after the stock adjustment event if the conversion had taken place prior to the stock adjustment event. On July 12, 2017 the note holders converted the $1,683,500 principal and $73,651 of accrued and unpaid interest into 418,370 shares of our common stock at a conversion price of $4.20 per share. Additionally, we paid two note holders an aggregate of $23,055 for accrued and unpaid interest. +The note holders also received warrants to purchase up to an aggregate of 102,039 shares of our common stock which would be exercisable at a price of eighty-five percent (85%) of the Company’s IPO price per share. The warrants expire in December 2021. The Company calculated a note discount for the value of the warrants received by the note holders of $11,914 using a Black-Scholes pricing model with the following assumptions: (i) risk free interest rate 1.96%, (ii) expected life (in years) of 5; (iii) expected volatility of 80.49%; (iv) expected dividend yield of 0.00%; and (v) stock trading price of $0.638. In addition, the warrants contain an adjustment provision effective in the event of stock dividends, splits and combinations that adjusts the exercise price and number of shares such that the holder would receive the same number of shares of stock upon exercise at an equivalent purchase price that holder would have had after the stock adjustment event if the exercise had taken place prior to the stock adjustment event. +Upon any default of the notes for non-payment, any bankruptcy event or breach of the note or other transaction documents, the Company may be liable to pay a default redemption amount equal to 130% of the amount due under the note and deliver an additional warrant to purchase 50% of the common stock issuable upon conversion of the notes. The Company may have to issue additional warrants due to stock dividends, stock splits, reclassification or other actions such as a merger or reorganization of the Company. If, at any time when the notes or warrants issued to the bridge note holders, the Company issues any common stock or common stock equivalents at a lower conversion or exercise price, the conversion or exercise price of the notes and/or warrants shall be reduced to such lower conversion or exercise price. +Additionally, the Company paid $15,000 in loan preparation fees. The $59,000 withheld as finder’s fees, the $11,914 warrant valuation and the $15,000 for loan preparation have all been recorded as a discount to the principal of the note had been accreted over the term of the note. For the years ended December 31, 2017 and 2016, $79,696 and $6,218 respectively, was accreted for the note discount and included in interest expense. Interest of $132,691 and $10,700 related to the note principal was included in interest expense for the years ended December 31, 2017and 2016, respectively. +On July 12, 2017, the Company concluded an initial public offering. Coincident with the closing of the IPO, the Company retired all of its principal debt and outstanding accrued interest through the issuance of common stock. The note holders converted the outstanding aggregate principal of $1,683,500 plus $73,651 of accrued interest into 418,369 shares of our common stock at a conversion price of $4.20 per share. The fair value of the shares issued in this exchange less the carrying value of the notes resulted in a loss on extinguishment of debt of $1,403,241. Additionally, because the Company had not retired the notes on the original due date of June 12, 2017, the Company agreed to increase the number of warrants from 50% of the shares issuable to the note holders upon conversion to 75% of the shares issuable to the note holders upon conversion. Based on the price per share of the IPO and the note extension agreements, the Company issued an additional aggregate of 211,740 warrants valued at $578,706 to the note holders pursuant to the terms of the Bridge Notes and note extension agreements. The warrants expire on December 29, 2021. The Company calculated the value of the warrants received by the note holders using a Black-Scholes pricing model with the following assumptions: (i) risk free interest rate 1.90%, (ii) expected life (in years) of 4.5; (iii) expected volatility of 46.41%; (iv) expected dividend yield of 0.00%; and (v) stock trading price of $6.00. +F-15 +Table of Contents +Co Diagnostics, Ltd. Revolving Line of Credit Promissory Note +On August 1, 2015, the Company entered into a Revolving Line of Credit Promissory Note with Co Diagnostics, Ltd a Turks and Caicos limited company, with a maximum limit on advances of $750,000. Co Diagnostics, Ltd. is a greater than 20% shareholder of the Company. The note bore a 12% annual interest rate on advances received. All accrued and unpaid interest along with the total sum of any outstanding advances were due on September 30, 2017. The note holder agreed that in the event the Company was able to file a Registration Statement for an Initial Public Offering on or before December 31, 2016, the note holder agreed to include the Note principal and accrued interest outstanding on the filing date with the Registration Statement to convert all of the Note principal and accrued interest to common stock of the Company. +On July 12, 2017, the Company concluded an initial public offering. Coincident with the closing of the IPO, the Company retired all of its principal debt and outstanding accrued interest through the issuance of common stock. The note holder converted the $609,940 principal and $112,633 of accrued and unpaid interest into 172,041 shares of our common stock at a conversion price of $4.20 per share. The fair value of the shares issued in this exchange less the carrying value of the note resulted in a loss on extinguishment of debt of $309,673. Interest of $38,502 and $63,371 related to the note principal was included in interest expense for the years ended December 31, 2017 and 2016, respectively. +Legends Capital Group, LLC Convertible Note +On November 12, 2015, the Company entered into a $100,000 Convertible Promissory Note with Legends Capital Group, LLC, a Utah limited liability company . Legends Capital Group is a 12% shareholder of the Company and one of its members is a member of our Board of Directors. The note bore an 8.5% annual interest rate and was due semi annually. The principal was due on September 30, 2017. The note contained a conversion feature allowing the principal and any unpaid accrued interest to be converted into common shares of the company at a rate of $11.00 or 20% less than the price of the anticipated Initial Public Offering, whichever is less, per share at the discretion of the note holder. The conversion feature was not accounted for as a derivative because it was not deemed to be beneficial. In addition, the equity and liability components of the convertible note were not separately accounted for since the conversion price did not bear any relationship to the value of the privately held stock rendering the exercise of the conversion feature improbable. In addition, the Note contains an adjustment provision effective in the event of stock dividends, splits and combinations that adjusts the conversion price such that the holder would receive the same number of shares of stock upon conversion that holder would have had after the stock adjustment event if the conversion had taken place prior to the stock adjustment event. +On July 12, 2017, the Company concluded an initial public offering. Coincident with the closing of the IPO, the Company retired all of its principal debt and outstanding accrued interest through the issuance of common stock. The note holder converted the $100,000 principal and $14,143 of accrued and unpaid interest in to 23,780 shares of our common stock at a conversion price of $4.80 per share. The fair value of the shares issued in this exchange less the carrying value of the note resulted in a loss on extinguishment of debt of $28,614. +The note holder also received a warrant to purchase up to 4,545 shares of our common stock at a price of the lesser of $16.50 or the offering price of an initial public offering of the Company common stock during the term of the warrant. In addition, the warrants contain an adjustment provision effective in the event of stock dividends, splits and combinations that adjusts the exercise price and number of shares such that the holder would receive the same number of shares of stock upon exercise at an equivalent purchase price that holder would have had after the stock adjustment event if the exercise had taken place prior to the stock adjustment event. The warrant expires on November 12, 2020, the Company calculated a note discount for the value of the warrant received by the note holder of $665 using a Black-Scholes pricing model with the following assumptions: (i) risk free interest rate 1.67%, (ii) expected life (in years) of 5; (iii) expected volatility of 97.71%; (iv) expected dividend yield of 0.00%; and (v) stock trading price of $0.638. The $665 valuation of warrant had been accreted over the term of the note and for the years December 31, 2017 and 2016, $186 and $354, respectively was included in interest expense for the note discount. Interest of $4,510 and $8,500 related to the note principal was included in interest expense for the years ended December 31, 2017and 2016, respectively. +F-16 +Table of Contents +Clavo Rico Promissory Note +In February 2016, the Company entered into a promissory note in the principal amount of $10,000 with Clavo Rico Inc. a Utah corporation. The president of Clavo Rico is an officer of the Company. The note bore interest at the rate of 12% per annum with an amended maturity date of September 30, 2017. On September 14, 2016 we amended the note to provide that the principal and interest on the note would be convertible to shares of common stock at a conversion rate of $8.25 per share or a discount of 30% to the price of an IPO if the Company were to file a Registration Statement. +On July 12, 2017, the Company concluded an initial public offering. Coincident with the closing of the IPO, the Company retired all of its principal debt and outstanding accrued interest through the issuance of common stock. The note holder converted the $10,000 principal and $1,660 of accrued and unpaid interest in to 2,776 shares of our common stock at a conversion price of $4.20 per share. The fair value of the shares issued in this exchange less the carrying value of the note resulted in a loss on extinguishment of debt of $4,996. Interest of $631 and $1,029 related to the note principal was included in interest expense for the years ended December 31, 2017 and 2016, respectively. +Legends Capital Group, LLC. Revolving Line of Credit Promissory Note +In March 2016, the Company entered into a revolving line of credit promissory note Legends Capital Group, LLC in the principal amount of $100,000. The investor is a principal shareholder of ours and owns approximately 12% of the issued and outstanding shares of the Company. The note bore interest at the rate of 12% per annum with an amended maturity date of September 30, 2017. At December 31, 2016, the company had net outstanding advances due of $10,000 under the line of credit. On September 14, 2016, the Company amended the note to provide that the principal and interest on the note would be convertible to shares of common stock at a conversion rate of $8.25 per share or a discount of 30% to the price of an IPO if we were to file a Registration Statement. +On July 12, 2017, the Company concluded an initial public offering. Coincident with the closing of the IPO, the Company retired all of its principal debt and outstanding accrued interest through the issuance of common stock. The note holder converted the $10,000 principal and $6,112 of accrued and unpaid interest in to 3,836 shares of our common stock at a conversion price of $4.20 per share. The fair value of the shares issued in this exchange less the carrying value of the note resulted in a loss on extinguishment of debt of $6,904. Interest of $631 and $5,481 related to the note principal was included in interest expense for the years ended December 31, 2017 and 2016, respectively. +Hamilton Mining Resources, Inc. Revolving Line of Credit Promissory Note +In May 2016, the Company entered into a revolving line of credit promissory note with Hamilton Mining Resources Inc. in the principal amount of $75,000. The president of Hamilton is an officer of the Company. The note bore interest at the rate of 12% per annum and an amended maturity date of September 30, 2017. At both June 30, 2017 and 2016, the Company had net outstanding advances due of $66,000 under the line of credit. On September 14, 2016, the Company amended the note to provide that the principal and interest on the note would be convertible to shares of common stock at a conversion rate of $8.25 per share or a discount of 30% to the price of an IPO if we were to file a Registration Statement. +On July 12, 2017, the Company concluded an initial public offering. Coincident with the closing of the IPO, the Company retired all of its principal debt and outstanding accrued interest through the issuance of common stock. The note holder converted the $66,000 principal and $8,726 of accrued and unpaid interest in to 17,792 shares of our common stock at a conversion price of $4.20 per share. The fair value of the shares issued in this exchange less the carrying value of the note resulted in a loss on extinguishment of debt of $32,026. Interest of $4,202 and $4,524 related to the note principal was included in interest expense for the years ended December 31, 2017 and 2016, respectively. +F-17 +Table of Contents +Machan 1988 Property Trust Revolving Line of Credit Promissory Note +In May 2016, the Company entered into a revolving line of credit promissory note with Machan 1988 Property Trust in the principal amount of $50,000. The Trustee of the Trust is a member of the Company’s Board of Directors. The note bore interest at the rate of 12% per annum. At December 31, 2016, the Company had net outstanding advances due of $41,500 under the line of credit. On September 14, 2016, the Company amended the note to provide that the principal and interest on the note would be convertible to shares of common stock at a conversion rate of $8.25 per share or a discount of 30% to the price of an IPO if the Company were to file a Registration Statement before December 31, 2016. The Company did not file the aforementioned Registration Statement until after December 31, 2016. The Company subsequently retired the $41,500 principal and $3,783 of accrued interest in 2017. Interest of $913 and $2,780 related to the note principal was included in interest expense for the years ended December 31, 2017 and 2016, respectively. +NOTE 3: STOCK-BASED COMPENSATION +Stock Incentive Plans +Under the Co-Diagnostics, Inc. 2015 Long-term Incentive Plan (the “2015 Plan”), the board of directors may issue incentive stock options, share equivalents such as restricted stock awards, stock bonus awards, performance shares and restricted stock units to employees and directors and non-qualified stock options to consultants of the company. Options generally expire ten years after being granted. Options granted vest in accordance with the vesting schedule determined by the board of directors, usually ratably over a three-year vesting schedule upon anniversary date of the grant with the first 1/3 vesting on the grant date. Should an employee terminate before the vesting period is completed, the unvested portion of each grant is forfeited. The Company has used the Black-Scholes valuation model to estimate fair value of our stock-based awards, which requires various judgmental assumptions including estimated stock price volatility, forfeiture rates, and expected life. Our computation of expected volatility is based on market-based implied volatility. The 2015 Plan reserves an aggregate of 6,000,000 shares. The number of unissued stock options authorized under the 2015 Plan at December 31, 2017 was 5,677,293. +Stock Options +There were 61,335 and 163,641 options granted in the years ended December 31, 2017 and 2016, respectively. The Black-Scholes valuation model requires various judgmental assumptions including the estimated volatility, risk-free interest rate and expected option term. In determining the expected volatility our computation is based the stock prices of 3 comparable companies and is based on a combination of historical and market-based implied volatility. The risk-free interest rate was based on the yield curve of a zero-coupon U.S. Treasury bond on the date the warrant was issued with a maturity equal to the expected term of the option. The fair values for the options granted were estimated at the date of grant using the Black Scholes option-pricing model with the following weighted average assumptions: +Year Ended +December 31, +2017 +Year Ended +December 31, +2016 +Risk free interest rate +1.53 +% +1.52 +% +Expected life (in years) +5.0 +5.5 +Expected volatility +45.54 +% +95.24 +% +Expected dividend yield +0.00 +% +0.00 +% +Stock price +$ +3.85 +$ +0.638 +Included in stock based compensation for the year ended December 31, 2017, the Company recognized expense of $122,259 recorded in our general and administrative department (i) $97,474 for 61,335 options granted to three members of our board of directors and (ii) $24,785 for options vesting which had been granted prior to January 1, 2017. +F-18 +Table of Contents +Included in stock based compensation for the year ended December 31, 2016, the Company recognized $69,565 of stock based compensation expense recorded in our general and administrative department of which (i) $51,432 for options granted to 10 employees and one consultant of the company to purchase an aggregate of 163,641 shares of our common stock and (ii) $18,133 for the vesting of options which had been granted prior to January 1, 2016. +The following table summarizes option activity during the years ended December 31, 2017 and December 31, 2016, respectively. +Options +Outstanding +Weighted +Average +Exercise Price +Weighted +Average Fair +Value +Weighted +Average +Remaining Contractual +Life (years) +Outstanding at January 1, 2016 +136,369 +$ +0.55 +$ +0.49 +9.05 +Options granted +163,641 +0.55 +0.49 +9.04 +Expired +-- +-- +-- +-- +Forfeited options +(38,638 +) +0.55 +0.49 +8.04 +Exercised +-- +-- +-- +-- +Outstanding at December 31, 2016 +261,372 +$ +0.55 +$ +0.49 +8.63 +Options granted +61,335 +3.85 +1.59 +4.60 +Expired +-- +-- +-- +-- +Forfeited options +-- +-- +-- +-- +Exercised +-- +-- +-- +-- +Outstanding at December 31, 2017 +322,707 +$ +1.29 +$ +0.70 +7.05 +Warrants +The Company estimates the fair value of issued warrants on the date of issuance as determined using a Black-Scholes pricing model. The Company amortizes the fair value of issued warrants using a vesting schedule based on the terms and conditions of each associated underlying contract, as earned. The Black-Scholes valuation model requires various judgmental assumptions including the estimated volatility, risk-free interest rate and expected warrant term. In determining the expected volatility our computation is based the stock prices of 3 comparable companies and is based on a combination of historical and market-based implied volatility. The risk-free interest rate was based on the yield curve of a zero-coupon U.S. Treasury bond on the date the warrant was issued with a maturity equal to the expected term of the warrant. +There were 595,133 and 102,039 warrants issued in the years December 31, 2017 and 2016, respectively. The fair values for the warrants issued were estimated at the date of grant using the Black Scholes option-pricing model with the following weighted average assumptions: +Year Ended +December 31, +2017 +Year Ended +December 31, +2016 +Risk free interest rate +1.89 +% +1.96 +% +Expected life (in years) +4.7 +5.0 +Expected volatility +46.80 +% +80.49 +% +Expected dividend yield +0.00 +% +0.00 +% +Stock price +$ +2.98 +$ +0.638 +F-19 +Table of Contents +The weighted average fair value of warrants issued during the years ended December 31, 2017 and 2016 was $1.74 and $0.11 per share, respectively. +Included in stock based compensation for the year ended December 31, 2017, the Company recognized expense of $256,199 recorded in our general and administrative department for 297,727 warrants issued to 2 companies for services rendered. +The following table summarizes warrant activity during the years ended December 31, 2017 and 2016, respectively. +Warrants Outstanding +Weighted +Average +Exercise Price +Weighted +Average Fair +Value +Weighted +Average +Remaining Contractual +Life (years) +Outstanding at January 1, 2016 +9,090 +13.75 +0.11 +4.90 +Warrants issued +102,039 +8.25 +0.11 +5.00 +Expired +-- +-- +-- +-- +Forfeited warrants +-- +-- +-- +-- +Exercised +-- +-- +-- +-- +Outstanding at December 31, 2016 +111,129 +$ +8.25 +$ +0.11 +4.91 +Warrants issued +595,133 +2.91 +1.74 +4.28 +Expired +-- +-- +-- +-- +Forfeited warrants +-- +-- +-- +-- +Exercised +-- +-- +-- +-- +Outstanding at December 31, 2017 +706,262 +$ +3.27 +$ +1.48 +4.22 +The following table summarizes information about stock options and warrants outstanding at December 31, 2017. +Outstanding +Exercisable +Weighted +Average +Remaining +Weighted +Average +Weighted +Average +Range of +Exercise Prices +Number +Outstanding +Contractual +Life (years) +Exercise +Price +Number +Exercisable +Exercise +Price +$ +0.11-0.55 +534,099 +5.97 +$ +0.33 +483,340 +$ +0.30 +2.00-3.85 +86,355 +4.63 +3.31 +86,335 +3.31 +5.10-7.20 +408,535 +4.08 +5.46 +408,535 +5.46 +$ +0.11-7.20 +1,028,969 +5.11 +$ +2.61 +978,210 +$ +2.72 +F-20 +Table of Contents +Common Stock +In the year ended December 31, 2017, the Company issued 399,209 share of our common stock valued at $1,655,500 to 4 companies for consulting services, as stock based compensation. For the year ended December 31, 2017, the Company recognized expense of $813,229 in our general and administrative department for to-date services rendered. +Total unrecognized stock-based compensation was $842,271 at December 31, 2017 which the Company expects to recognize in 2018. +NOTE 4: LEASE OBLIGATIONS +Our offices are located at 2401 S Foothill Dr. Suite D Salt Lake City Utah 84109-1479. The space consists of approximately 7,015 square feet and is leased under a multi-year contract a rate of $11,109 per month expiring on January 31, 2020. For the years December 31, 2017 and 2016, the Company expensed $53,132 and $66,807, respectively for rent. The Company’s lease rent obligation is as follows: +Year +Amount +2018 +$ +133,308 +2019 +133,308 +2020 +11,109 +Total +$ +277,725 +NOTE 5: RELATED PARTY TRANSACTIONS +The Company acquired the exclusive rights to the Co-Primer technology pursuant to a license agreement dated April 2014, between us and DNA Logix, Inc., which was assigned to Dr. Satterfield prior to our acquisition of DNA Logix, Inc. Pursuant to the license the Company was to pay Dr. Satterfield minimum royalty payments of $30,000 per month until the Company receives an equity funding of at least $4,000,000, at which time the payments increase to $60,000 per month for the remainder of the year. The payment terms were orally modified to maintain the monthly royalties at $30,000 per month through December 2016. On March 1, 2017, the Company entered into an amendment effective January 1, 2017, to its Exclusive License Agreement for its Cooperative Primers (“License”) technology with Dr. Satterfield, a member of our Board of Directors. The amendment provides in part that all accrued royalties under the License cease as of January 1, 2017, and we began in January to pay $700,000 of accrued royalties at the rate of $10,000 per month. For the year ended December 31, 2017, the Company included $107,500 as an expense for this license agreement in research and development. For the year ended December 31, 2016, the Company included $360,000 as an expense for this license agreement in research and development. +The Company financed operations partly through short term loans with related parties and through the deferral of payment to related parties for expenses incurred. At December 31, 2017, the Company accrued $480,000 in expenses for technology royalties payable to Dr. Satterfield. At December 31, 2016, the Company accrued $690,168 in expenses and had accounts payable of $75,000 for technology royalties, consulting fees, and interest on related party debts. In addition the Company had notes outstanding from six related party entities totaling $837,177. +NOTE 6: EQUITY +2017 +For the year ended December 31, 2017, the Company issued warrants to purchase 595,133 shares of our common stock with a weighted average exercise price of $2.91 with an aggregate value of $1,035,624 as follows: (i) 297,727 for consulting services to two companies, (ii) 211,740 for debt conversion to six individuals and four companies, and (iii) 85,666 for agency fees related to equity funding to four companies. +In the year ended December 31, 2017, the Company issued 2,434,789 shares of common stock as follows: (i) 1,178,533 shares related to the sale of equity, (ii) 857,047 shares associated with the conversion of debt, and (iii) 399,209 shares for services rendered. +2016 +For the year ended December 31, 2016, the Company issued warrants to purchase 102,039 shares of our common stock with an exercise price of $8.25 to eleven entities related to the funding received on our Bridge Notes Payable with an aggregate value of $11,914. +F-21 +Table of Contents +NOTE 7: INCOME TAXES +Net deferred tax assets consist of the following components as of December 31, 2017 and 2016: +2017 +2016 +Deferred tax assets +NOL carry-forward +$ +2,537,300 +$ +1,550,900 +Sec 179 carry-forwards +1,600 +2,400 +Depreciation +2,500 +43,200 +Valuation allowance +(2,541,400 +) +(1,596,500 +) +Net deferred tax asset +$ +-- +$ +-- +The income tax provision differs from the amount of income tax determined by applying the U.S. federal income tax rate to pretax income from continuing operations for the years ended December 31, 2017 and 2016 due to the following: +2017 +2016 +Book loss +$ +(1,809,400 +) +$ +(752,200 +) +Depreciation +4,900 +(9,700 +) +Meals and entertainment +1,100 +400 +Other non-deductible expenses +359,300 +63,800 +Change in valuation allowance +1,444,100 +697,700 +$ +- +$ +- +At December 31, 2017, the Company had net operating loss carry-forwards of approximately $9,759,000 that may be offset against future taxable income from the year 2018 through 2034. No tax benefit has been reported in the December 31, 2017 and 2016, consolidated financial statements since the potential tax benefit is offset by a valuation allowance of the same amount. Additionally, DNA Logix, Inc. is a pass through entity and therefore no provision or liability for federal income tax has been included in the consolidated financial statements for that entity. +Due to change in ownership provisions of the Tax Reform Act of 1986, net operating loss carry-forwards for Federal income tax reporting purposes are subject to annual limitations. Should a change in ownership occur, net operating loss carry-forwards may be limited as to use in future years. +The Company’s policy on the classification of interest and penalties related to income taxes is to recognize the interest and penalties in the period incurred. There were no penalties or interest incurred for the years ending December 31, 2017 and 2016, related to income taxes. +NOTE 8: SUBSEQUENT EVENTS +The Company evaluated subsequent events pursuant to ACS Topic 855 and determined that there are no additional events that need to be reported. +F-22 +Table of Contents +ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. +None. +ITEM 9A. CONTROLS AND PROCEDURES +(a) Disclosure Controls and Procedures +We maintain a set of disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in rules and forms adopted by the SEC. +In accordance with Rule 13a-15(b) of the Exchange Act, as of the end of the period covered by this annual report on Form 10-K, an evaluation was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, to assess the effectiveness of our disclosure controls and procedures. As of the end of the period covered by this annual report on Form 10-K our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and is accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +(b) Management’s Report on Internal Control over Financial Reporting and Attestation Report of Registered Public Accounting Firm +This annual report on Form 10-K does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of our registered public accounting firm due to a transition period established by rules of the SEC applicable to newly public companies. +(c) Changes in Internal Control Over Financial Reporting +There have been no changes in the Company's internal control over financial reporting that occurred during the Company's last three-month period that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting. +ITEM 9B. OTHER INFORMATION +None. +18 +Table of Contents +PART III +ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE. +The following table sets forth the names, ages and positions of our executive officers and directors: +Name +Age +Position +Dwight H. Egan +63 +Chief Executive Officer, President and Chairman of the Board +Brent Satterfield +41 +Chief Science Officer and Director +Reed L Benson +71 +Chief Financial Officer and Secretary +Edward J. Borkowski +59 +Director +Frank J. Kiesner +73 +Director +Richard S. Serbin +73 +Director +Dwight H. Egan has been an officer and director since April 2013. Mr. Egan has been engaged in private investment business from February 1999 to the present. He was a senior executive at Data Broadcasting Corporation, a leading provider of wireless, real-time financial market data, news and sophisticated fixed- income portfolio analytics to 27,000 individual and professional investors from 1995 to 1999. He co-founded and served as CEO and Chairman of the Board of Broadcast International, Inc. from 1984 to 1995, when Data Broadcasting Corporation acquired Broadcast International and created CBS MarketWatch , a leading financial news site and participated in its initial public offering. Mr. Egan’s prior experience in directing a public company and working with capital markets gives him valuable experience in advising the board on matters of finance and operations. +Brent Satterfield has been our chief science officer and director since April 2013. Dr. Satterfield has been employed by the Company from January 31, 2015 to the present. Prior to that he was the sole shareholder and owner of DNA Logix, Inc. from January 2013 to January 31, 2015, and in DNA Logix he developed and patented the technology now owned by the Company. He founded Co-Diagnostics in April 2013 and is the first in his field to use engineering mathematics to design new DNA testing technology. From 2006 to 2008, he was employed by Arcxis Biotechnologies where he developed new diagnostic platforms for groups such as the Department of Homeland Security, the National Biodefense Analysis and Countermeasures Center, the United States Army Medical Research Institute of Infectious Disease, Sandia National Laboratories, the California Department of Public Health and numerous others. Under fellowship from the Department of Homeland Security, he received his Ph.D. in 2007 in Bioengineering with an emphasis in entrepreneurship and intellectual property law from Arizona State University in a dual-enrollment program with UC Berkeley. Dr. Satterfield’s experience with the science underlying all of the Company’s products and technology gives him valuable experience in advising the board on the status of the products and our positioning in the diagnostic testing industry. +Reed L Benson has been Chief Financial Officer and Secretary from November 2014 to the present and a director from November 2014 to May 2017. Since September, 2008 to the present, in addition to the private practice of law, he is a founder and partner of Legends Capital Group, LLC, a privately held venture capital group that identifies investment opportunities in natural resources, bio tech and technology fields. From October 2004 to September 2008 he was employed as Chief Financial Officer, Secretary, and General Counsel and member of Board of Directors of Broadcast International, Inc., a publicly traded communications services company. From 2001 to October 2004, he was in the private practice of law where his practice focused on tax and business related matters. From July 1995 to January 2001 he was secretary and general counsel for Data Broadcasting Corporation, a provider of market information to individual investors. Mr. Benson received his J.D. degree from the University of Utah School of Law in 1976 and a Bachelor of Science Degree in Accounting from the University of Utah in 1971. Mr. Benson became a Certified Public Accountant in 1974. Mr. Benson’s experience in finance, accounting and business consulting, together with his role as our CFO and prior public company directorship, provide Mr. Benson with expertise enabling critical input to our company. +Edward Borkowski joined our Board of Directors in May 2017. Since August 2016, Mr. Borkowski has served as the Executive Vice President and CFO of Concordia International. Mr. Borkowski is a healthcare executive who previously was the acting CFO of Amerigen Pharmaceuticals, a generic pharmaceutical company with a focus on oral controlled release products, from 2013 to 2016. In addition, Mr. Borkowski previously held the position of CFO with Convatec, a global medical device company focused on wound care and ostomy, from 2012 to 2013, and Carefusion, a global medical device company for which he helped lead its spin-out from Cardinal Health into an independent public company. Mr. Borkowski was also previously CFO and Executive Vice President of Mylan N.V. Mr. Borkowski also held senior financial positions at Pharmacia and American Home Products (Wyeth). He started his career with Arthur Andersen & Co. after graduating from Rutgers University with an MBA in accounting. Mr. Borkowski also graduated from Allegheny College with a degree in Economics and Political Science. He is a Trustee and an Executive Committee member of Allegheny College. Mr. Borkowski is also the Chairman of the Board of Directors of AzurRx Biopharma, Inc., a company listed on the Nasdaq Capital Market. We believe that Mr. Borkowski’s industry specific extensive management experience provides him with a broad and deep understanding of our business and our competitors’ efforts, which makes him a qualified member of our board. Additionally, his expertise in the accounting and financial matters will be critical to our Board of Directors and audit committee. +19 +Table of Contents +Frank J. Kiesner joined our Board of Directors in May 2017 and is the founder of several companies in the medical diagnostic field. Mr. Kiesner is the Chairman and Chief Executive Officer of OvaGene Oncology, Inc., a molecular diagnostics company which he founded in 2008. OvaGene Oncology, Inc. provides gene-based assays to assist physicians/gynecologic oncologists in the diagnosis, radiation and chemotherapy, prognosis, and therapy selection of gynecologic cancers in women. Mr. Kiesner served as Chairman, President and CEO of Oncotech Inc. for 17 years until its acquisition by Exiqon in 2008. Oncotech became the leading company in the USA and Europe in the field of individualizing cancer treatment and drug selection. Mr. Kiesner was previously a partner at Northstar Ventures, General Counsel and Treasurer of public-company ADC Telecommunications, and President of ADC Corporation's Magnetic Division. He served on multiple committees and boards for the American Laboratory Association and has extensive experience in the regional, federal and congressional workings of health care reimbursement. Working with Congressman Bill Thomas, Chairman of the Congress's Ways and Means Sub-Committee on Health, Mr. Kiesner was the leading force behind the passage of the "Patients Benefit Improvement Act Of 1999" which rewrote the new technology approval and patient- provider appellate process for the Medicare and other federal Statutory Programs. Mr. Kiesner obtained his J.D. from the University of Minnesota School of Law. Mr. Kiesner’s experience running diagnostic companies, especially companies in the molecular diagnostic field, will be invaluable to the Board of Directors and our company. +Richard S. Serbin, who joined our Board of Directors in May 2017, currently serves as a consultant to many companies in the healthcare industry. He was the President of Corporate Development and In-House Legal Counsel at Life Science Institute, LLC, from June 1, 2013 to July 15, 2014. Mr. Serbin is a global strategy advisor, pharmacist and entrepreneur with credentials both in pharmacy and law, complemented by more than 40 years of service as an FDA regulatory attorney and patent attorney in the healthcare industry. He was appointed to the Advisory Board of Cure Pharmaceutical in January 2017 and has been a Member of Advisory Board at Prime Access, Inc. since September 2015. Mr. Serbin has been a Director at Rapid Nutrition Plc since November 18, 2014. He served as Director at Viropro Inc. from May 2013 to June 2014. He was Head of Business Advisory Board at Mazal Plant Pharmaceuticals Inc. from October 2006 to September 2007 and also served as its Member of Business Advisory Board. He served as Chief Executive Officer of Optigenex Inc. from July 2002 to September 15, 2005 and a director from July 2004 to September 2005. From January 1999 until July 2002 Mr. Serbin served as a consultant to various pharmaceutical companies. He served as the President of Bradley Pharmaceuticals. He served as Vice President of Corporate Development at Ortho Pharmaceuticals, a Johnson & Johnson subsidiary, and practiced Patent and FDA law at Revlon Johnson & Johnson and Schering-Plough. He served as Patent Attorney for Schering Plough Corporation and Chief FDA Counsel for Revlon Corporation and Johnson and Johnson Corporation. Subsequently, he worked at Revlon Corporation, as its Chief Food, Drug and Cosmetic Counsel. He founded Radius Scientific Corporation. He was J&J's Vice President of Corporate Development, and later led a successful public offering venture based on technology developed at Stanford Medical School. Mr. Serbin spent a large portion of his career focusing on international markets and clients. While at J&J, Mr. Serbin served on the Board of Directors of 16 US and international subsidiary companies, including Ethicon, Ortho, J&J Consumer Products, Pittman-Moore, Mc Neil, and J&J Development Corporation. He worked on multiple international acquisitions and strategic relationships, and sat on the Board of Directors of several of its international subsidiaries, including those in India, Hong Kong, Japan, Taiwan, Germany, and England. Mr. Serbin has a B.S. and a B. Pharmacy from Rutgers University and Rutgers University College of Pharmacy, a J.D. degree from Seton Hall Law School and a Masters Degree in Trade Regulations and Law from NYU Law School. Mr. Serbin’s experience in business, law and medicine and knowledge gained as an advisor to the healthcare industry will be critical to our Board of Directors as it commercializes its products. +Our directors generally serve until the next annual or special meeting of shareholders held for the purpose of electing directors. Our officers generally serve at the discretion of the Board of Directors. Messrs. Egan and Satterfield are employees. Mr. Egan serves as our president and chief executive officer and Mr. Satterfield serves as our Chief Science Officer. +20 +Table of Contents +Involvement in Certain Legal Proceedings +To the best of our knowledge, none of our directors or executive officers have, during the past ten years, been involved in any legal proceedings described in subparagraph (f) of Item 401 of Regulation S-K. +Board and Committee Matters +We maintain an audit committee of the board, a compensation committee of the board and a corporate governance and nominating committee of the board, each of which is discussed below. We have not established a nominating committee of the board. Our board has determined that Messrs. Borkowski, Kiesner and Serbin are “independent” under the definition of independence in the Marketplace Rules of the NASDAQ listing requirements. +We do not have a formal policy concerning shareholder recommendations of candidates for board of director membership. Our board views that such a formal policy is not necessary at the present time given the board’s willingness to consider candidates recommended by shareholders. Shareholders may recommend candidates by writing to our Secretary at our principal offices: 2401 S. Foothill Drive, Suite D, Salt Lake City, Utah 84109, giving the candidate’s name, contact information, biographical data and qualifications. A written statement from the candidate consenting to be named as a candidate and, if nominated and elected, to serve as a director should accompany any such recommendation. Shareholders who wish to nominate a director for election are generally advised to submit a shareholder proposal no later than December 31 for the next year’s annual meeting of shareholders. +Audit Committee and Financial Expert +Our audit committee currently is comprised of Messrs. Borkowski, Kiesner and Serbin with Mr. Borkowski serving as chairman of the audit committee. The functions of the audit committee include engaging an independent registered public accounting firm to audit our annual financial statements, reviewing the independence of our auditors, the financial statements and the auditors’ report, and reviewing management’s administration of our system of internal control over financial reporting and disclosure controls and procedures. The Board of Directors has adopted a written audit committee charter. A current copy of the audit committee charter is available to security holders on our website at www.codiagnostics.com. Our board has determined that both of our directors that are serving on the audit committee are “independent” under the definition of independence in the Marketplace Rules of the NASDAQ listing standards. +Our Board of Directors has determined that Mr. Borkowski meets the requirements of an “audit committee financial expert” as defined in applicable SEC regulations. +Compensation Committee +Our compensation committee currently includes Messrs. Serbin and Borkowski with Mr. Serbin serving as chairman of the compensation committee. The functions of the compensation committee include reviewing and approving corporate goals relevant to compensation for executive officers, evaluating the effectiveness of our compensation practices, evaluating and approving the compensation of our chief executive officer and other executives, recommending compensation for board members, and reviewing and making recommendations regarding incentive compensation and other employee benefit plans. The Board of Directors has adopted a written compensation committee charter. A current copy of the compensation committee charter is available to shareholders on our website at www.codiagnostics.com . Our board has determined that both of our directors serving on the compensation committee are “independent” under the definition of independence in the Marketplace Rules of the NASDAQ listing standards. +21 +Table of Contents +Corporate Governance and Nominating Committee +Our corporate governance and nominating committee currently includes Messrs. Kiesner, Borkowski and Serbin with Mr. Kiesner serving as chairman of the corporate governance and nominating committee. The functions of the corporate governance and nominating committee is identifying and recommending candidates to fill vacancies on the Board of Directors. Among its duties and responsibilities, the corporate governance and nominating committee periodically evaluates and assesses the performance of the officers and directors; reviews the qualifications of candidates for director positions; assists in identifying, interviewing and recruiting candidates for the Board of Directors and reviews the composition of each committee of the Board of Directors. A current copy of the corporate governance and nominating committee charter is available to shareholders on our website at www.codiagnostics.com . Our board has determined all directors serving on the corporate governance and nominating committee are “independent” under the definition of independence in the Marketplace Rules of the NASDAQ listing standards. +Communication with the Board +We have not, to date, developed a formal process for shareholder communications with the board of directors. We believe our current informal process, in which any communication sent to the board of directors, either generally or in care of the chief executive officer, secretary or other corporate officer or director, is forwarded to all members of the board of directors, has served the board’s and the shareholders’ needs. +Conflicts of Interests +On an annual basis, each director and executive officer is obligated to complete a director and officer questionnaire that requires disclosure of any transactions with our company, including related person transactions reportable under SEC rules, in which the director or executive officer, or any member of his or her immediate family, have a direct or indirect material interest. Under our company’s standards of conduct for employees, all employees, including the executive officers, are expected to avoid conflicts of interest. Pursuant to our code of ethics for the chief executive officer and senior finance officers (as discussed below), such officers are prohibited from engaging in any conflict of interest unless a specific exception has been granted by the board. All of our directors are subject to general fiduciary standards to act in the best interests of our company and our shareholders. Conflicts of interest involving an executive officer or a director are generally resolved by the board. +Compliance with Section 16(a) of the Exchange Act +Section 16(a) of the Exchange Act requires our directors and executive officers, and persons who own more than 10% of our common stock, to file with the SEC initial reports of ownership and reports of changes in ownership of our common stock and other equity securities. Executive officers, directors and greater than 10% shareholders are required by SEC regulations to furnish us with copies of all Section 16(a) forms they file. +To our knowledge, during the year ended December 31, 2017, our directors, executive officers and greater than 10% shareholders complied with all Section 16(a) filing requirements. +Code of Ethics +We have adopted a code of ethics for our principal executive officer, principal financial officer, controller, or persons performing similar functions. A copy of the code of ethics is included on our website at www.codiagnostics.com. +Family Relationships +There are no family relationships among our directors and executive officers. +22 +Table of Contents +ITEM 11. EXECUTIVE COMPENSATION +Throughout this section, the individuals who served as our chief executive officer and chief financial officer during 2016 and 2017 are collectively referred to as the “named executive officers.” +The compensation committee has overall responsibility to review and approve our compensation structure, policy and programs and to assess whether the compensation structure establishes appropriate incentives for management and employees. The compensation committee annually reviews and determines the salary and any bonus and equity compensation that may be awarded to our chief executive officer, or CEO, and our chief financial officer, or CFO. The compensation committee oversees the administration of our long-term incentive plan and employee benefit plans. +The compensation committee’s chairman regularly reports to the board on compensation committee actions and recommendations. The compensation committee has authority to retain, at our expense, outside counsel, experts, compensation consultants and other advisors as needed. +Company Performance . Because of the stage of our company’s development, the compensation committee looks at various factors in evaluating the progress the company has made and the services provided by the named executive officers. In considering executive compensation, the compensation committee noted certain aspects of our financial performance and accomplishments in 2017 and 2016 including the following: (a) Development Milestones, (b) Financial Milestones and (c) Sales and Marketing Milestones. +Compensation Philosophy . Our general compensation philosophy is designed to link an employee’s total cash compensation with our performance, the employee’s department goals and individual performance. Given our stage of operations and limited capital resources, we are subject to various financial restraints in our compensation practices. As an employee’s level of responsibility increases, there is a more significant level of variability and compensation at risk. The compensation committee believes linking incentive compensation to our performance creates an environment in which our employees are stakeholders in our success and, thus, benefits all shareholders. +Executive Compensation Policy . Our executive compensation policy is designed to establish an appropriate relationship between executive pay and our annual performance, our long-term growth objectives, individual performance of the executive officer and our ability to attract and retain qualified executive officers. The compensation committee attempts to achieve these goals by integrating competitive annual base salaries with bonuses based on corporate performance and on the achievement of specified performance objectives, and to a lesser extent, awards through our long-term incentive plan. The compensation committee believes that cash compensation in the form of salary and bonus provides our executives with short-term rewards for success in operations. The compensation committee also believes our executive compensation policy and programs do not promote inappropriate risk-taking behavior by executive officers that could threaten the value of our company. +In making compensation decisions, the compensation committee compares each element of total compensation against companies referred to as the “compensation peer group.” The compensation peer group is a group of companies that the compensation committee selected from readily available information about small companies engaged in similar businesses and with similar resources. The compensation committee selected these companies from research on its own and with limited consultation with outside consultants given the size of the company and its resources to retain such experts. The types of companies selected for the peer group included publicly-traded technology development companies in the diagnostic testing industry. Since there are relatively few companies in the rather narrow field of diagnostic testing the comparisons were limited to those that are publicly traded whose financial information could be readily accessed. The compensation committee determined these companies were appropriate for inclusion in the peer group because of the similar nature of their businesses and their general stage of development and financial resources. +Role of Executive Officers in Compensation Decisions +The compensation committee makes all compensation decisions for the named executive officers and approves recommendations regarding equity awards to all of our other senior management personnel. The CEO annually reviews the performance of the CFO and other senior management. The conclusions reached and recommendations based on these reviews, including with respect to salary adjustments and annual award amounts, are presented to the compensation committee. The compensation committee is charged with the responsibility of ensuring a consistent compensation plan throughout the company and providing an independent evaluation of the proposed adjustments or awards at all levels of management. As such, the compensation committee has determined that it have the discretion to modify or adjust any proposed awards and changes to management compensation to be able to satisfy these responsibilities. +23 +Table of Contents +Stock Option Plans +Under our 2015 Long-term Incentive Plan (the “2015 Plan”), the board of directors may issue incentive stock options to employees and directors and non-qualified stock options to consultants of the company. Options expire ten years after being granted. Options granted vest in accordance with the vesting schedule determined by the board of directors, usually ratably over a two-year vesting schedule upon the anniversary date of the grant. Should an employee’s director’s or consultant’s relationship with the company terminate before the vesting period is completed, the unvested portion of each grant is forfeited. We continue to maintain and grant awards under the 2015 Plan which will remain in effect its expiration by its terms. The number of unissued stock options authorized under the 2015 Plan at December 31, 2017 was 3,779,508. +The purpose of our incentive plan is to advance the interests of our stockholders by enhancing our ability to attract, retain and motivate persons who are expected to make important contributions to the company by providing them with both equity ownership opportunities and performance-based incentives intended to align their interests with those of our stockholders. These plans are designed to provide us with flexibility to select from among various equity-based compensation methods, and to be able to address changing accounting and tax rules and corporate governance practices by optimally utilizing stock options and shares of common stock. +Summary Compensation Table +The table below summarizes the total compensation paid or earned by each of the named executive officers in their respective capacities for the fiscal years ended December 31, 2017, 2016 and 2015. When setting total compensation for each of the named executive officers, the compensation committee reviewed tally sheets which show the executive’s current compensation, including equity and non-equity based compensation. We have omitted in this report certain columns otherwise required to be included because there was no compensation made with respect to such columns, as permitted by applicable SEC regulations. +Option +All +Name and +Salary +Bonus +Awards +Other +Total +Principal Position +Year +($) +($) +($) +Compensation +($) +Dwight H. Egan +2017 +$ +195,000 +$ +15,000 +$ +-- +$ +-- +$ +210,000 +President & Chief Executive Officer (1) +2016 +23,750 +-- +-- +-- +23,750 +2015 +48,000 +-- +-- +-- +48,000 +Reed L Benson +2017 +$ +195,000 +$ +10,000 +$ +-- +$ +-- +$ +205,000 +Chief Financial Officer and Secretary (2) +2016 +-- +-- +-- +-- +-- +2015 +-- +-- +-- +-- +-- +Brent Satterfield +2017 +$ +159,300 +$ +-- +$ +-- +$ +-- +$ +159,300 +Chief Technology Officer (3) +2016 +81,096 +-- +-- +-- +81,096 +2015 +76,548 +-- +-- +-- +76,548 +______________ +(1) +The amounts shown in the salary column for 2016 and 2015 reflect amounts paid by the Company to Reagents, LLC that were specifically designated as compensation for Mr. Egan. +(2) +Mr. Benson is a member of Legends Capital Group, LLC, which received consulting income from the Company in 2015 and 2016. However, Mr. Benson did not receive any of the funds received by Legends Capital Group from the Company. +(3) +Dr. Satterfield also received royalties from the Company in the amount of $2,500 in 2016 and $170,000 in 2017 pursuant to a technology license agreement that was amended in January 2017 to terminate the ongoing royalties and the payments in 2017 reduced the past accrued royalties. +24 +Table of Contents +Other Compensation +We do not have any non-qualified deferred compensation plan. +Outstanding Equity Awards at Fiscal Year-End +We do not have any outstanding equity awards a fiscal year end +Potential Payments Upon Termination or Change of Control +There is no compensation payable to the named executive officers upon voluntary termination, retirement, involuntary not-for-cause termination, termination following a change of control or in the event of disability or death of the executive. +Compensation Committee Interlocks and Insider Participation in Compensation Decisions +None of our executive officers served as a member of the compensation committee or as a director of any other company. +Director Compensation +We use a combination of cash and stock-based incentive compensation to attract and retain qualified candidates to serve on its board of directors. In setting director compensation, we consider the significant amount of time that directors expend in fulfilling their duties as well as the skill-level required by our members of the board. +Our non-employee directors generally receive fees of $35,000 per year, paid quarterly, $10,000 per year for serving as chairman of any Board committee and $5,000 for serving as a member of other Board committees. In addition, each director receives an initial grant of stock options to purchase 20,455 shares (thereafter annual grants of 4,545 options or restricted stock units) of our common stock with an exercise price equal to the fair market value of the stock on the date of grant. The board approved and the non-employee directors accepted the 2017 compensation set forth in the director summary compensation table below. In addition, non-employee directors may be entitled to receive special awards of stock options from time to time as determined by the board. The chairman of the board and the chairman of each of the audit and compensation committees receive no additional fees for serving in such capacities. There is no additional compensation for meeting attendance. Directors who are employees of the Company receive no additional compensation for serving as directors. All stock options granted to outside directors are immediately exercisable and expire ten years from the date of grant. Directors are reimbursed for ordinary expenses incurred in connection with attending board and committee meetings. +25 +Table of Contents +Director Summary Compensation Table +The table below summarizes the compensation paid by us to our directors for the fiscal year ended December 31, 2017. +(a) +(b) +(c) +(d) +(e) +Name +Fees Earned or +Paid in Cash +($) (2) +Options/Awards +($) +Restricted Stock Units +($) +Total +($) +Dwight H. Egan (1) +$ +-- +-- +$ +-- +$ +-- +Dr. Brent Satterfield (1) +-- +-- +-- +-- +Frank Kiesner +$ +37,500 +$ +32,491 +-- +$ +69,991 +Richard Serbin +37,500 +32,491 +-- +69,991 +Edward J. Borkowski +37,500 +32,491 +-- +69,991 +____________ +(1) +Messers Egan and Satterfield receive no compensation for serving as a director, but are compensated in their capacity as Company President and Chief Science Officer, respectively. +(2) +Each of Messrs. Kiesner, Serbin, and Borkowski were granted a total of 20,455 incentive stock options with an estimated value of $32,491. +ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The following table sets forth certain information, as of March 19, 2018, with respect to the holdings of (1) each person who is the beneficial owner of more than 5% of our Common Stock, (2) each of our directors, (3) each executive officer, and (4) all of our current directors and executive officers as a group. +Beneficial ownership of the common stock is determined in accordance with the rules of the Securities and Exchange Commission and includes any shares of common stock over which a person exercises sole or shared voting or investment power, or of which a person has a right to acquire ownership at any time within 60 days of the date of this Annual Report. Except as otherwise indicated, we believe that the persons named in this table have sole voting and investment power with respect to all shares of common stock held by them. Applicable percentage ownership in the following table is based on 12,317,184 shares of common stock plus, for each individual, any securities that individual has the right to acquire within 60 days of March 19, 2018. +26 +Table of Contents +To the best of our knowledge, except as otherwise indicated, each of the persons named in the table has sole voting and investment power with respect to the shares of our common stock beneficially owned by such person, except to the extent such power may be shared with a spouse. To our knowledge, none of the shares listed below are held under a voting trust or similar agreement, except as noted. To our knowledge, there is no arrangement, including any pledge by any person of securities of the Company, the operation of which may at a subsequent date result in a change in control of the Company. +Name and Address of Beneficial Owner Officers and Directors +Title +Beneficially +Percent of +Class +Dwight H. Egan (1) +Chief Executive Officer, President and Chairman +-- +Reed L. Benson (1) +Chief Financial Officer and Secretary +-- +Dr. Brent Satterfield (1) +Chief Science Officer and Director +2,269,795 +18 +% +Edward J. Borkowski +Director +20,455 +* +Frank J. Kiesner +Director +20,455 +* +Richard S. Serbin +Director +20,455 +* +Officers and Directors as a Group (total of 6 persons) +2,331,160 +19 +% +5% Stockholders +Legends Capital Group, LLC (2) +1,300,344 +11 +% +Reagents, LLC (3) +1,771,796 +14 +% +______ +* less than 1% +(1) +The address is 2401 S. Foothill Drive, Salt Lake City, Utah 84109. +(2) +Legends Capital Group, LLC, with an address of 4049 S Highland Drive, Salt Lake City, UT 84124, is beneficially owned by Jason Briggs. Reed Benson, an officer of the Company, owns an 11% equity interest in Legends Capital Group, LLC. +(3) +Reagents, LLC, with an address of 8160 S. Highland Drive, Salt Lake City, UT 84093, is beneficially owned by Seth Egan. +27 +Table of Contents +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +The Company acquired the exclusive rights to the Co-Primer technology pursuant to a license agreement dated April 2014, between us and DNA Logix, Inc., which was assigned to Dr. Satterfield prior to our acquisition of DNA Logix, Inc. Pursuant to the license the Company was to pay Dr. Satterfield minimum royalty payments of $30,000 per month until the Company receives an equity funding of at least $4,000,000, at which time the payments increase to $60,000 per month for the remainder of the year. The payment terms were orally modified to maintain the monthly royalties at $30,000 per month through December 2016. On March 1, 2017, the Company entered into an amendment effective January 1, 2017, to its Exclusive License Agreement for its Cooperative Primers (“License”) technology with Dr. Satterfield, a member of our Board of Directors. The amendment provides in part that all accrued royalties under the License cease as of January 1, 2017, and we began in January to pay $700,000 of accrued royalties at the rate of $10,000 per month. For the year ending December 31, 2017, the Company included $107,500 as an expense for this license agreement in research and development. +The Company financed operations partly through short term loans with related parties and through the deferral of payment to related parties for expenses incurred. At December 31, 2017, the Company accrued $480,000 in expenses for technology royalties payable to Dr. Satterfield. At December 31, 2016, the Company accrued $690,168 in expenses and had accounts payable of $75,000 for technology royalties, consulting fees, and interest on related party debts. In addition the Company had notes outstanding from six related party entities totaling $837,177. +We paid consulting fees to two companies who are also significant shareholders. Legends Capital Group, LLC, one of the consultants, was paid a total of $75,000 in 2017 for expenses accrued in 2016. The other consultant, Reagents, LLC, was paid $46,385 in 2016. +ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +Fees for professional services provided by our current independent auditors for each of the last two fiscal years, in each of the following categories, are as follows: +2017 +2016 +Audit fees +$ +97,000 +$ +62,000 +Audit-related fees +-- +-- +Tax fees +-- +-- +All other fees +-- +-- +Total +$ +97,000 +$ +62,000 +Audit fees included fees associated with the annual audit and reviews of our annual and quarterly reports for 2017 and our annual report for 2106. In addition, these fees for 2017 included fees associated with our registration statement under the Securities Act of 1933, as amended, filed with the SEC. All audit fees incurred during 2017 were pre-approved by the audit committee. All audit fees incurred during 2016 were pre-approved by our Board of Directors. +Tax fees included fees associated with tax compliance and tax consultations. All tax fees incurred during 2017 were pre-approved by the audit committee. All tax fees incurred during 2016 were pre-approved by our Board of Directors. +The audit committee has adopted a policy that requires advance approval of all services performed by the independent auditor when fees are expected to exceed $15,000. The audit committee has delegated to the audit committee chairman, Mr. Borkowski, authority to approve services, subject to ratification by the audit committee at its next committee meeting. +28 +Table of Contents +PART IV +Item 15. Exhibits, Financial Statement Schedules. +Exhibit +Number Description +1.1 +Underwriting Agreement (5) +3.1 +Articles of Incorporation (1) +3.1.1 +Amendment to the Articles of Incorporation (1) +3.2 +Bylaws (1) +10.1 +Subscription Agreement between Co-Diagnostics, Inc. and Codiagnostics, Ltd., dated April 30, 2013 (1) +10.1.1 +Amendment to Subscription Agreement between Co-Diagnostics, Inc. and Codiagnostics, Ltd., dated May 1, 2015 (1) +10.2 +Exclusive Agreement between Co-Diagnostics, Inc. and DNA Logix, Inc., dated April 18, 2014 (1) +10.3 +Stock Exchange Agreement among Co-Diagnostics, Inc., DNA Logix, Inc., and the Shareholders of DNA Logix, Inc., dated January 22, 2015 (1) +10.4 +Revolving Line of Credit Promissory Note between Co-Diagnostics, Inc. and Codiagnostics, LTD, dated August 1, 2015 (1) +10.5 +10% Convertible Note between Co-Diagnostics, Inc. and Robert Salna for $200,000, dated September 1, 2016 (1) +10.6 +Exclusive License Agreement between Co-Diagnostics, Inc. and Watermark Group Inc., dated October 13, 2016 (1) +10.7 +Securities Purchase Agreement with Exhibits between Co-Diagnostics and Senior Holders, dated December 12, 2016 (1) +10.7.1 +Form of Amendment Agreement (6) +10.7.2 +Form of Second Amendment Agreement (7) +10.8 +Securities Purchase Agreement with Exhibits between Co-Diagnostics and Beaufort Capital Partners, LLC, dated December 12, 2016 (1) +10.9 +2015 Long-Term Incentive Plan (2) +10.10 +Subscription Agreement between Co-Diagnostics and Codiagnostics, Ltd. for 454,545 shares of Co-Diagnostic’s common stock, dated April 20, 2013 (3) +10.11 +Subscription Agreement between Co-Diagnostics and Prosperity Investments for $100,000, dated June 2014. (3) +10.12 +12% Convertible Note between Co-Diagnostics, Inc. and Beaufort Capital Partners, LLC for $500,000, dated May 15, 2015 (3) +10.13 +Form Revolving Line of Credit Promissory Note between Co-Diagnostics and Turks and Caicos Limited Company, Pine Valley Investments, LLC, Clavo Rico Incorporated, Legends Capital Group, LLC, Hamilton Mining Resources, Inc., and Machan 1988 Property Trust. (3) +29 +Table of Contents +10.13.1 +Amendment to 12% Revolving Line of Credit Promissory Note, dated August 1, 2015, between Co-Diagnostics and Codiagnostics, Ltd., for $750,000, dated September 14, 2016. (3) +10.13.2 +Amendment to 12% Revolving Line of Credit Promissory Note, December 30, 2015, between Co-Diagnostics and Pine Valley Investments, LLC for $100,000, dated September 14, 2016. (3) +10.13.3 +Amendment to 12% Revolving Line of Credit Promissory Note, February 22, 2016, between Co-Diagnostics and Clavo Rico Incorporated for $10,000, dated September 14, 2016. (3) +10.13.4 +Amendment to 12% Revolving Line of Credit Promissory Note, March 1, 2016, between Co-Diagnostics and Legends Capital Group, LLC for $100,000, dated September 14, 2016. (3) +10.13.5 +Amendment to 12% Revolving Line of Credit Promissory Note, May 15, 2016, between Co-Diagnostics and Hamilton Mining Resources, Inc. for $75,000, dated September 14, 2016. (3) +10.13.6 +Amendment to 12% Revolving Line of Credit Promissory Note, May 30, 2016, between Co-Diagnostics and Machan 1988 Property Trust for $50,000, dated September 14, 2016. (3) +10.13.7 +Form Second Amendment to 12% Revolving Line of Credit Promissory Note Due 2017 between Co-Diagnostics, Inc. and Codiagnostics, Ltd., Pine Valle Investments, LLC, Clavo Rico Incorporated, Legends Capital Group, LLC, and Hamilton Mining Resources, Inc. (4) +10.13.8 +Form of Indemnification Agreement. (4) +10.14 +Form 8.5% Convertible Note between Co-Diagnostics and Legends Capital Group, LLC for $100,000, dated November 12, 2015 and R. Phillip Zobrist for $100,000, dated December 1, 2015. (3) +10.15 +Form 10% Convertible Note between Co-Diagnostics and Legends Capital Opportunity Fund, LLC for $15,000, DAV Capital Management Corp. for $15,000, April Kameka for $40,000, and Mark Kovacic for $50,000. (3) +10.16 +Shareholders’ Agreement between Co-Diagnostics and Synbiotics Limited, dated January 27, 2017. (3) +10.17 +Amended Exclusive License Agreement between Co-Diagnostics, Brent Satterfield, and DNA Logix, Inc., dated January 1, 2017. (3) +10.18 +Stock Purchase Agreement between Co-Diagnostics and Ted Murphy for 1,800,000 shares of Watermark Group, Inc.’s common stock, dated September 22, 2016. (3) +10.19 +Non-Interest Bearing Note between Co-Diagnostics and Zika Diagnostics, Inc. f/k/a/ Watermark Group, Inc. for $445,000, dated March 20, 2017. (3) +10.20 +Mutual Rescission Agreement of the Stock Purchase Agreement, dated September 22, 2016, and the License Agreement, dated October 13, 2016, between Co-Diagnostics, Robert Salna, and Ted Murphy, dated March 30, 2017. (3) +21.1 +Subsidiaries of Registrant (1) +31.1 +Certification of Chief Executive Officer pursuant to section 302 of the Sarbanes-Oxley Act of 2002 +31.2 +Certification of Principal Financial Officer pursuant to section 302 of the Sarbanes-Oxley Act of 2002 +32.1 +Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 +32.2 +Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 +101 +Interactive data files pursuant to Rule 405 of Regulation S-T +____________ +* +Management contract or compensatory plan or arrangement. +(1) +Incorporated by reference to the Draft Registration Statement filed with the SEC on January 11, 2017. +(2) +Incorporated by reference to the Draft Registration Statement filed with the SEC on March 27, 2017. +(3) +Incorporated by reference to the Form S-1 filed with the SEC on April 28, 2017. +(4) +Incorporated by reference to the Form S-1/A filed with the SEC on May 24, 2017. +(5) +Incorporated by reference to the Form S-1/A filed with the SEC on June 9, 2017. +(6) +Incorporated by reference to the Form S-1/A filed with the SEC on June 23, 2017. +(7) +Incorporated by reference to the Form S-1/A filed with the SEC on July 10, 2017. +30 +Table of Contents +SIGNATURES +Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. +CO-DIAGNOSTICS, INC. +Date: March 28, 2018 +By: +/s/ Dwight Egan +Dwight Egan +Chief Executive Officer, President and Director +(Principal Executive Officer and Interim Principal Financial and Accounting Officer) +By: +/s/ Reed L. Benson +Reed L. Benson +Chief Financial Officer and Secretary +(Principal Financial and Accounting Officer +In accordance with the Exchange Act, this report has been signed below by the following persons on March 28, 2018, on behalf of the registrant and in the capacities Indicated. +Signature +Title +/s/ Dwight Egan +Chief Executive Officer, President and Director +Dwight Egan +/s/ Reed L. Benson +Chief Financial Officer and Secretary +Reed L. Benson +/s/ Brent Satterfield +Director +Brent Satterfield +/s/ Edward J. Borkowski +Director +Edward J. Borkowski +/s/ Frank Kiesner +Director +Frank Kiesner +/s/ Richard Serbin +Director +Richard Serbin +31 \ No newline at end of file diff --git a/raw/filings/0001692415/2017/0001477932-18-001468/filing_metadata.csv b/raw/filings/0001692415/2017/0001477932-18-001468/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..8121dc7b2ecfc123696fc3348f1112a4b6b77367 --- /dev/null +++ b/raw/filings/0001692415/2017/0001477932-18-001468/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001692415,CODX,"Co-Diagnostics, Inc.",10-K,2018-03-28,2017-12-31,2018-03-28T19:52:28.000Z,0001477932-18-001468,codx_10k.htm,FORM 10-K,4210815,1,0,https://www.sec.gov/Archives/edgar/data/1692415/000147793218001468/codx_10k.htm,https://www.sec.gov/Archives/edgar/data/1692415/000147793218001468/,2017,2017,1 diff --git a/raw/filings/0001692415/2017/0001477932-18-001468/item1.txt b/raw/filings/0001692415/2017/0001477932-18-001468/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..787475379ddf7868775ec10a8d2e9f93b7da9f33 --- /dev/null +++ b/raw/filings/0001692415/2017/0001477932-18-001468/item1.txt @@ -0,0 +1,115 @@ +ITEM 1: BUSINESS +Overview +Co-Diagnostics, Inc. (“Company,” or “CDI,”), a Utah corporation, is a molecular diagnostics company that has developed and intends to manufacture and sell reagents used for diagnostic tests that function via the detection and/or analysis of nucleic acid molecules (DNA or RNA), and to sell diagnostic equipment from other manufacturers as self-contained lab systems (which we refer to as the “MDx device”). +In addition, the unique properties of our Co-Primer technology make them ideally suited to a variety of applications where sensitivity is key to optimal results, including multiplexing several targets, enhanced SNP detection and enrichment for next gen sequencing. +Dr. Brent Satterfield, our Chief Technology Officer, created the Company’s suite of intellectual properties. Our scientists were the first to understand the complex mathematics of DNA test design, to “engineer” a DNA test and to automate algorithms that rapidly screen millions of possible options to pinpoint the optimum design. Dr. Satterfield developed the Company’s intellectual property consisting of the predictive mathematical algorithms and proprietary reagents used in the testing process, which together represent a major advance in Polymerase Chain Reaction (“PCR”) testing systems. CDI technologies are now protected by five granted or pending US patents, as well as certain trade secrets. Ownership of our proprietary platform permits us the advantage of avoiding payment of patent royalties required by other PCR test systems, which grants us the opportunity of selling diagnostic tests at a lower price than competitors, while generating a profit margin. +We will either sell or lease our portable labs to existing diagnostic centers, through sale or lease agreements, and sell the reagents that comprise our proprietary tests to those laboratories and testing facilities. +CDI’s low-cost system (pictured at right) uses CDI’s tests to diagnose tuberculosis, Zika, hepatitis B and C, Malaria, dengue and HIV, all of which tests have been designed and verified in CDI’s laboratory as explained below. +We designed our tests by identifying the optimal locations on the target gene for amplification and paired the location with the optimized primer and probe structure to achieve outputs that meet the design input requirements identified from market research. This is done by following planned and documented processes, procedures and testing. In other words, the data resulting from our tests verify that we succeeded in designing what we intended to at the outset. Verification is a series of testing that concludes that the product is ready to proceed to validation in a clinical evaluation setting using initial production tests to confirm that the product as designed meets the user needs. +CDI’s diagnostics systems enable very rapid, low-cost, sophisticated molecular testing for organisms and genetic diseases by greatly automating historically complex procedures in both the development and administration of tests. CDI’s newest technical advance involves a novel approach to PCR test design ("Co-Primers") that eliminates one of the key vexing issues of PCR amplification, the exponential growth of primer-dimer pairs (false positives and false negatives) which adversely interferes with identification of the target DNA. +Using its proprietary test design system and proprietary reagents, CDI will design and sell PCR diagnostic tests for diseases and pathogens starting with tests for tuberculosis, a drug resistant tuberculosis test, hepatitis B and C, Malaria, dengue, HIV and Zika virus, all of which tests have been designed and verified in CDI’s laboratory. +4 +Table of Contents +Infectious Disease Product Offering +We plan to manufacture molecular diagnostic tests for the following diseases in the following regions, to be sold along with the MDx device: +Timetable +Region +Tests +Current (revenues in the 2nd quarter in 2018) +Caribbean and Central and South America +Zika, Tuberculosis, Hepatitis B and C, Dengue +India +Tuberculosis, Hepatitis B and C, Malaria, Dengue and HIV +2018-2019 +European Union; Asia +Tuberculosis, Hepatitis B and C +2020-2025 +United States +To be determined based on need and regulatory barriers +Caribbean and Central and South America +Our initial sales will be to entities within the Caribbean Public Health Agency Members States (Anguilla, Antigua and Barbuda, Aruba, Bahamas, Barbados, Belize, Bermuda, BES Islands, British Virgin Islands, Cayman Islands, Curacao, Dominica, Grenada, Haiti, Guyana, Jamaica, Montserrat, Saint Kitts and Nevis, Saint Lucia, St Maarten, Saint Vincent and the Grenadines, Suriname, Trinidad and Tobago, Turks and Caicos Islands). +In some of these countries, there are no regulatory hurdles and we can start offering our tests immediately. The U.S. Food and Drug Administration (FDA) has granted permission for us to export many of our products. The FDA's permission to export was granted under Section 801 (e) of the Federal Food, Drug, and Cosmetic Act, as amended (the “FDC Act”). Section 801(e) of the FDA Act covers certain medical devices that have not yet received an approved Premarket Approval in the United States by the FDA, such as our products. We have not commenced any Premarket Approval steps with the FDA. Section 801(e) applies to medical devices that are acceptable to the importing country and that are manufactured under the FDA's Good Manufacturing Practices. +We will first offer our Zika test in this region because of the demand for such test, followed quickly by tests for tuberculosis, hepatitis B and C, and dengue, then our full range of tests. Products will be manufactured for sale upon receipt of purchase orders from labs and hospitals. +India +The Company has entered into an agreement to manufacture diagnostics tests for seven infectious diseases with a pharmaceutical manufacturing company in India. The agreement provides for the manufacture of the tests named above and the joint sales and marketing of those tests in India. We have commenced with our joint venture partner to construct a plant that will be used for testing and manufacturing to service the Indian market. We believe that the plant will be completed and manufacturing activities will begin in the third quarter of 2018. +Since the tests will be conducted in India on Indian citizens, no FDA approval or inspection will be required. Certain Indian regulatory approval from the Central Drugs Standard Control Organization (CDSCO) must be acquired. We are engaging the services of an experienced consultant in India to help get us through this process. Research Use Only (RUO) reagents are able to be sold without requiring regulatory approval as long as they are labeled and designated as such. Tests for some of the targeted diseases are available for sale currently in India. +India is the country with the highest burden of tuberculosis. World Health Organization (WHO) tuberculosis statistics for India for 2015 give an estimated incidence figure of 2.2 million cases of tuberculosis for India out of a global incidence of 9.6 million. The tuberculosis incidence for India is the number of new cases of active tuberculosis disease in India during a certain time period (usually a year). We currently have a tuberculosis test and tuberculosis test that measures drug resistance to aid in more effective treatment. +5 +Table of Contents +Europe +Molecular diagnostics, such as our tests, are governed in Europe by the framework for in vitro diagnostics (IVDs), which encompasses diagnostic products such as reagents, instruments and systems intended for use in diagnosis of disease. The regulatory system for IVDs is built largely on a self-certification procedure, placing heavy responsibility on manufacturers. Non self-certified products are subject to the same standards as self-certified products but are subject to audit and review by a notified body prior to receiving approval to be CE-marked. A CE-marking is a manufacturer’s declaration that a product meets the requirements of the applicable European Commission directive. Examples of current obligations include having in place a qualitative manufacturing process, user instructions that are clear and fit for purpose, ensuring that the ‘physical’ features of devices and diagnostics do not pose any danger. If a product fulfils these and other related control requirements, it may be CE-marked as an indication that the product is compliant with EU legislation and sold in the European Union. +We have received ISO 13485 and ISO 9001 certifications relating to the design and manufacture of our medical device products. The ISO certification indicates that we meet the standards required to self-certify certain of our products and affix a CE-marking for sales of our products in countries accepting the CE marking (not in the United States) with only minimal further governmental approvals in each country. We expect to have our Zika and tuberculosis tests CE-marked in 2018. We estimate the remaining costs for CE-marks on the initial tests we will offer to be approximately $100,000. +United States +We do not anticipate offering our tests in the United States in the near future. We believe, however, our tests may be able to qualify as Laboratory Developed Tests (LDT's), diagnostic tests that are developed and manufactured by CLIA certified laboratories. These tests are developed by the lab for use only in that laboratory. CLIA laboratories develop the performance characteristics, perform the analytical validation for their LDT's and obtain licenses to offer them as diagnostic services. The FDA has publicly announced its intention to regulate certain LDTs in a phased-in approach, but draft guidance that was published a couple of years ago was withdrawn at the end of the Obama administration and replaced by an informal non-enforceable discussion paper reflecting some of the feedback that it received on LDT regulation. +Market Opportunity +The molecular diagnostics market is a fast growing portion of the in vitro (test tube based, controlled environment) diagnostics market. Using estimates of the incidence of disease by the Centers for Disease Control, the World Health Organization and other international health agencies and sources, the Company estimates that the global annual demand for diagnostic tests are: +Tuberculosis +10,400,000 +HIV +36,700,000 +Multi-drug resistant Tuberculosis +580,000 +Malaria +214,000,000 +Zika +324,000,000 +Sexually Transmitted Illnesses +357,000,000 +Hepatitis B +240,000,000 +Human papilloma virus +291,000,000 +Hepatitis C +130,000,000 +Dengue +390,000,000 +Total Annual Tests +1,993,680,000 +There are several advantages of molecular tests, such as the ones we market and sell, over other forms of diagnostic testing, which include higher sensitivities, the ability to perform multiplex tests and the ability to test for drug resistance or individual genes. +6 +Table of Contents +Competitive Advantages of Co-Diagnostics +We believe that we have the following competitive advantages: +· +Affordability: Lower-cost test kits and low-cost MDx-device. +· +Flexibility: CDI’s tests have been designed to run on many vendors’ DNA diagnostic testing machines. These tests are particularly well suited to the new generation of “lab-on-a-chip” and “point-of-care” (“LOC and POC”), highly portable analysis machinery for field, clinic and office applications. +· +Speed : We believe our rapid assay development provides shorter time to results. +· +Accuracy : We believe our tests are more accurate than competitors’ and can detect more strains of viruses. +· +Exclusivity : CDI owns all patents used in preparation of its tests, all intellectual property including a 100-year license on Co-Primers and all additional product and process development of Dr. Satterfield through March 2019. +· +Personalized Medicine : We project that rising health care costs in developed and developing nations will increasingly require that health care systems be patient specific to eliminate waste, misdiagnoses, and ineffectiveness. A critical component will be accurate, more affordable DNA-based diagnostics, which CDI plans to offer. +· +Low-cost Provider : We plan to keep the Company’s overhead low. Its platform technology obviates the need to pay patent royalties typically required of its competitors, which use patented test platforms to design their tests. +· +Worldwide Footprint : With a dynamic technology that encompasses markets worldwide, the Company anticipates that it can identify the best target markets, not only in high burden developing countries (HBDC’s) but also in developed nations. +· +Growth Industry Category : We believe that DNA testing is the fastest-growing segment of in-vitro diagnostic testing. +· +Combination Product Offering : CDI’s ultra-sensitive tests can be a well-designed match for a new generation of handheld and other small point-of-care devices now entering the market. Used together, these affordable tests and devices may revolutionize the molecular diagnostics industry in cost, speed of test results and simplification. +· +Multi-plexing: We believe our Co-Primer designed tests will be able to test for multiple targets in the same sample without the distortion caused by false negatives and false positives that generally occur in multiplexed tests. +Primer Design Product Offering +In addition, the unique properties of our Co-Primer technology make them ideally suited to a variety of applications where sensitivity is key to optimal results, including multiplexing several targets, enhanced SNP detection and enrichment for next gen sequencing. Because of these unique characteristics of Co-Primers, research companies and institutions have requested that we design diagnostics to locate and identify uncommon gene sequences and SNPs and create tests for the target sequences in a multiplexed reaction. This application of our technology is in its beginning stages, but we believe that the results from our initial research indicate a significant step forward in defining the capabilities of our technology, which we believe can be translated to revenue producing licensing arrangements. +7 +Table of Contents +Organizational History and Corporate Information +We were incorporated as Co-Diagnostics, Inc., in Utah on April 18, 2013. Our principal executive office is located 2401 S. Foothill Drive, Salt Lake City, Utah 84109. Our telephone number is (801) 438-1036. Our web address is http://codiagnostics.com. +Implications of Being an Emerging Growth Company +We are an "emerging growth company," as defined in the Jumpstart Our Business Startups Act of 2012. We will remain an emerging growth company until the earlier of (i) the last day of the fiscal year following the fifth anniversary of July 12, 2017, the date of the first sale of our common stock pursuant to an effective registration statement under the Securities Act of 1933, as amended (the “Securities Act”); (ii) the last day of the fiscal year in which we have total annual gross revenues of $1 billion or more; (iii) the date on which we have issued more than $1 billion in nonconvertible debt during the previous three years; or (iv) the date on which we are deemed to be a large accelerated filer under applicable SEC rules. We expect that we will remain an emerging growth company for the foreseeable future, but cannot retain our emerging growth company status indefinitely. We refer to the Jumpstart Our Business Startups Act of 2012 herein as the "JOBS Act". For so long as we remain an emerging growth company, we are permitted and intend to rely on exemptions from specified disclosure requirements that are applicable to other public companies that are not emerging growth companies. These exemptions include: +· +being permitted to provide only two years of audited financial statements, in addition to any required unaudited interim financial statements, with correspondingly reduced "Management's Discussion and Analysis of Financial Condition and Results of Operations" disclosure; +· +not being required to comply with the requirement of auditor attestation of our internal controls over financial reporting; +· +not being required to comply with any requirement that may be adopted by the Public Company Accounting Oversight Board regarding mandatory audit firm rotation or a supplement to the auditor's report providing additional information about the audit and the financial statements; +· +reduced disclosure obligations regarding executive compensation; and +· +not being required to hold a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments not previously approved. +For as long as we continue to be an emerging growth company, we expect that we will take advantage of the reduced disclosure obligations available to us as a result of that classification. Accordingly, the information contained herein may be different than the information you receive from other public companies in which you hold stock. +An emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. This allows an emerging growth company to delay the adoption of certain accounting standards until those standards would otherwise apply to private companies. We have irrevocably elected to avail ourselves of this extended transition period and, as a result, we will not be required to adopt new or revised accounting standards on the dates on which adoption of such standards is required for other public reporting companies. +We are also a "smaller reporting company" as defined in Rule 12b-2 of the Securities Exchange Act of 1934, as amended, or the Exchange Act, and have elected to take advantage of certain of the scaled disclosure available for smaller reporting companies. \ No newline at end of file diff --git a/raw/filings/0001692415/2017/0001477932-18-001468/item13.txt b/raw/filings/0001692415/2017/0001477932-18-001468/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..6587a619df73645705b1963692cab93d41ca2d68 --- /dev/null +++ b/raw/filings/0001692415/2017/0001477932-18-001468/item13.txt @@ -0,0 +1,4 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +The Company acquired the exclusive rights to the Co-Primer technology pursuant to a license agreement dated April 2014, between us and DNA Logix, Inc., which was assigned to Dr. Satterfield prior to our acquisition of DNA Logix, Inc. Pursuant to the license the Company was to pay Dr. Satterfield minimum royalty payments of $30,000 per month until the Company receives an equity funding of at least $4,000,000, at which time the payments increase to $60,000 per month for the remainder of the year. The payment terms were orally modified to maintain the monthly royalties at $30,000 per month through December 2016. On March 1, 2017, the Company entered into an amendment effective January 1, 2017, to its Exclusive License Agreement for its Cooperative Primers (“License”) technology with Dr. Satterfield, a member of our Board of Directors. The amendment provides in part that all accrued royalties under the License cease as of January 1, 2017, and we began in January to pay $700,000 of accrued royalties at the rate of $10,000 per month. For the year ending December 31, 2017, the Company included $107,500 as an expense for this license agreement in research and development. +The Company financed operations partly through short term loans with related parties and through the deferral of payment to related parties for expenses incurred. At December 31, 2017, the Company accrued $480,000 in expenses for technology royalties payable to Dr. Satterfield. At December 31, 2016, the Company accrued $690,168 in expenses and had accounts payable of $75,000 for technology royalties, consulting fees, and interest on related party debts. In addition the Company had notes outstanding from six related party entities totaling $837,177. +We paid consulting fees to two companies who are also significant shareholders. Legends Capital Group, LLC, one of the consultants, was paid a total of $75,000 in 2017 for expenses accrued in 2016. The other consultant, Reagents, LLC, was paid $46,385 in 2016. \ No newline at end of file diff --git a/raw/filings/0001692415/2017/0001477932-18-001468/item9a.txt b/raw/filings/0001692415/2017/0001477932-18-001468/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..750af577de9c1d49fe5d83863521844048d7b71e --- /dev/null +++ b/raw/filings/0001692415/2017/0001477932-18-001468/item9a.txt @@ -0,0 +1,8 @@ +ITEM 9A. CONTROLS AND PROCEDURES +(a) Disclosure Controls and Procedures +We maintain a set of disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in rules and forms adopted by the SEC. +In accordance with Rule 13a-15(b) of the Exchange Act, as of the end of the period covered by this annual report on Form 10-K, an evaluation was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, to assess the effectiveness of our disclosure controls and procedures. As of the end of the period covered by this annual report on Form 10-K our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and is accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. +(b) Management’s Report on Internal Control over Financial Reporting and Attestation Report of Registered Public Accounting Firm +This annual report on Form 10-K does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of our registered public accounting firm due to a transition period established by rules of the SEC applicable to newly public companies. +(c) Changes in Internal Control Over Financial Reporting +There have been no changes in the Company's internal control over financial reporting that occurred during the Company's last three-month period that has materially affected, or is reasonably likely to materially affect, the Company's internal control over financial reporting. \ No newline at end of file diff --git a/raw/filings/0001692415/2017/0001477932-18-001468/rp_note.txt b/raw/filings/0001692415/2017/0001477932-18-001468/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..d0f6729779f130518f1ed142906081ee088c8d11 --- /dev/null +++ b/raw/filings/0001692415/2017/0001477932-18-001468/rp_note.txt @@ -0,0 +1,3 @@ +NOTE 5: RELATED PARTY TRANSACTIONS +The Company acquired the exclusive rights to the Co-Primer technology pursuant to a license agreement dated April 2014, between us and DNA Logix, Inc., which was assigned to Dr. Satterfield prior to our acquisition of DNA Logix, Inc. Pursuant to the license the Company was to pay Dr. Satterfield minimum royalty payments of $30,000 per month until the Company receives an equity funding of at least $4,000,000, at which time the payments increase to $60,000 per month for the remainder of the year. The payment terms were orally modified to maintain the monthly royalties at $30,000 per month through December 2016. On March 1, 2017, the Company entered into an amendment effective January 1, 2017, to its Exclusive License Agreement for its Cooperative Primers (“License”) technology with Dr. Satterfield, a member of our Board of Directors. The amendment provides in part that all accrued royalties under the License cease as of January 1, 2017, and we began in January to pay $700,000 of accrued royalties at the rate of $10,000 per month. For the year ended December 31, 2017, the Company included $107,500 as an expense for this license agreement in research and development. For the year ended December 31, 2016, the Company included $360,000 as an expense for this license agreement in research and development. +The Company financed operations partly through short term loans with related parties and through the deferral of payment to related parties for expenses incurred. At December 31, 2017, the Company accrued $480,000 in expenses for technology royalties payable to Dr. Satterfield. At December 31, 2016, the Company accrued $690,168 in expenses and had accounts payable of $75,000 for technology royalties, consulting fees, and interest on related party debts. In addition the Company had notes outstanding from six related party entities totaling $837,177. \ No newline at end of file diff --git a/raw/filings/0001692415/2017/0001477932-18-001468/rpt_disclosure.txt b/raw/filings/0001692415/2017/0001477932-18-001468/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..6587a619df73645705b1963692cab93d41ca2d68 --- /dev/null +++ b/raw/filings/0001692415/2017/0001477932-18-001468/rpt_disclosure.txt @@ -0,0 +1,4 @@ +ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +The Company acquired the exclusive rights to the Co-Primer technology pursuant to a license agreement dated April 2014, between us and DNA Logix, Inc., which was assigned to Dr. Satterfield prior to our acquisition of DNA Logix, Inc. Pursuant to the license the Company was to pay Dr. Satterfield minimum royalty payments of $30,000 per month until the Company receives an equity funding of at least $4,000,000, at which time the payments increase to $60,000 per month for the remainder of the year. The payment terms were orally modified to maintain the monthly royalties at $30,000 per month through December 2016. On March 1, 2017, the Company entered into an amendment effective January 1, 2017, to its Exclusive License Agreement for its Cooperative Primers (“License”) technology with Dr. Satterfield, a member of our Board of Directors. The amendment provides in part that all accrued royalties under the License cease as of January 1, 2017, and we began in January to pay $700,000 of accrued royalties at the rate of $10,000 per month. For the year ending December 31, 2017, the Company included $107,500 as an expense for this license agreement in research and development. +The Company financed operations partly through short term loans with related parties and through the deferral of payment to related parties for expenses incurred. At December 31, 2017, the Company accrued $480,000 in expenses for technology royalties payable to Dr. Satterfield. At December 31, 2016, the Company accrued $690,168 in expenses and had accounts payable of $75,000 for technology royalties, consulting fees, and interest on related party debts. In addition the Company had notes outstanding from six related party entities totaling $837,177. +We paid consulting fees to two companies who are also significant shareholders. Legends Capital Group, LLC, one of the consultants, was paid a total of $75,000 in 2017 for expenses accrued in 2016. The other consultant, Reagents, LLC, was paid $46,385 in 2016. \ No newline at end of file diff --git a/raw/filings/0001692415/2018/0001493152-19-004300/filing.txt b/raw/filings/0001692415/2018/0001493152-19-004300/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..c95447a37634c0c0c25675ed945ff2fc56f2c320 --- /dev/null +++ b/raw/filings/0001692415/2018/0001493152-19-004300/filing.txt @@ -0,0 +1,3118 @@ +10-K +1 +form10-k.htm +UNITED +STATES +SECURITIES +AND EXCHANGE COMMISSION +Washington, +D.C. 20549. +Form +10-K +(Mark +One) +[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For +the fiscal year ended December 31, 2018 +OR +[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For +the transition period from_______to_______ +Commission +File Number 0-13316 +CO-DIAGNOSTICS, +INC. +(Exact +Name of Registrant as Specified in Its Charter) +Utah +3841 +46-2609396 +(State +or other jurisdiction of +incorporation +or organization) +(Primary +Standard Industrial +Classification +Code Number) +(I.R.S. +Employer +Identification +Number) +2401 +S. Foothill Drive, Salt Lake City, Utah 84109 +(Address +of principal executive offices and zip code) +(801) +438-1036 +(Registrant’s +telephone number including area code) +Indicate +by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [ ] +No [X] +Indicate +by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes [ ] +No [X] +Indicate +by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act +of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and +(2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] +Indicate +by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive +Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the +preceding 12 months (or such shorter period that the registrant was required to submit and post such files). Yes [X] No [ ] +Indicate +by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not +contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements +incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] +Indicate +by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller +reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller +reporting company” in Rule 12b-2 of the Exchange Act. +Large +accelerated filer +[ ] +Accelerated +filer +[ ] +Non-accelerated +filer +[ ] +Smaller +reporting company +[X] +Emerging +Growth Company +[X] +Indicate +by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes [ ] No [X] +The +aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at +which the common stock was last sold as of the last business day of the registrant’s most recently completed second fiscal +quarter was approximately $27,183,637. +As +of March 22, 2019, there were 17,015,766 shares of common stock, par value $0.001 per share, outstanding. +Table +of Contents +Page +PART I +Item +1. +Business. +4 +Item +1A. +Risk Factors. +8 +Item +1B. +Unresolved Staff Comments. +8 +Item +2. +Properties. +8 +Item +3. +Legal Proceedings. +8 +Item +4. +Mine Safety Disclosures. +9 +PART II +Item +5. +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. +9 +Item +6. +Selected Financial Data. +10 +Item +7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations. +10 +Item +7A. +Quantitative and Qualitative Disclosures About Market Risk. +14 +Item +8. +Financial Statements and Supplementary Data. +15 +Item +9. +Changes in and Disagreements With Accountants on Accounting and Financial Disclosure. +16 +Item +9A. +Controls and Procedures. +16 +Item +9B. +Other Information. +16 +PART III +Item +10. +Directors, Executive Officers and Corporate Governance. +17 +Item +11. +Executive Compensation. +20 +Item +12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. +23 +Item +13. +Certain Relationships and Related Transactions, and Director Independence. +24 +Item +14. +Principal Accountant Fees and Services. +24 +PART IV +Item +15. +Exhibits and Financial Statement Schedules. +25 +2 +PART +I +Forward-Looking +Statements +This +Annual Report on Form 10-K contains “forward-looking statements” that involve risks and uncertainties. All statements +other than statements of historical fact contained in this Annual Report and the documents incorporated by reference herein, including +statements regarding future events, our future financial performance, business strategy, and plans and objectives of management +for future operations, are forward-looking statements. We have attempted to identify forward-looking statements by terminology +including “anticipates,” “believes,” “can,” “continue,” “could,” “estimates,” +“expects,” “intends,” “may,” “plans,” “potential,” “predicts,” +“should,” or “will” or the negative of these terms or other comparable terminology. Although we do not +make forward looking statements unless we believe we have a reasonable basis for doing so, we cannot guarantee their accuracy. +These statements are only predictions and involve known and unknown risks, uncertainties and other factors and the documents incorporated +by reference herein, which may affect our or our industry’s actual results, levels of activity, performance or achievements +expressed or implied by these forward-looking statements. Moreover, we operate in a highly regulated, very competitive, and rapidly +changing environment. New risks emerge from time to time and it is not possible for us to predict all risk factors, nor can we +address the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause our +actual results to differ materially from those contained in any forward-looking statements. +We +have based these forward-looking statements largely on our current expectations and projections about future events and financial +trends that we believe may affect our financial condition, results of operations, business strategy, short term and long-term +business operations, and financial needs. These forward-looking statements are subject to certain risks and uncertainties that +could cause our actual results to differ materially from those reflected in the forward-looking statements. Factors that could +cause or contribute to such differences include, but are not limited to, those discussed in this Annual Report, and in particular, +the risks discussed below and under the heading “Risk Factors” in other documents we file with the SEC. The following +discussion should be read in conjunction with the consolidated financial statements for the fiscal years ended December 31, 2018 +and 2017 and notes incorporated by reference therein. We undertake no obligation to revise or publicly release the results of +any revision to these forward-looking statements, except as required by law. In light of these risks, uncertainties and assumptions, +the forward-looking events and circumstances discussed in this prospectus may not occur and actual results could differ materially +and adversely from those anticipated or implied in the forward-looking statement. +You +should not place undue reliance on any forward-looking statement, each of which applies only as of the date of this Annual Report. +Except as required by law, we undertake no obligation to update or revise publicly any of the forward-looking statements after +the date of this prospectus to conform our statements to actual results or changed expectations. +You +are advised, however, to consult any further disclosures we make on related subjects in our reports on Forms 10-Q, 8-K and 10-K +filed with the SEC. You should understand that it is not possible to predict or identify all risk factors. Consequently, you should +not consider this list to be a complete set of all potential risks or uncertainties. +Important +factors that could cause actual results to differ materially from those in the forward-looking statements include, without limitation: +● +the +results of clinical trials and the regulatory approval process; +● +our +ability to raise capital to fund continuing operations; +● +market +acceptance of any products that may be approved for commercialization; +● +our +ability to protect our intellectual property rights; +● +the +impact of any infringement actions or other litigation brought against us; +● +competition +from other providers and products; +● +our +ability to develop and commercialize new and improved products and services; +● +changes +in government regulation; +● +our +ability to complete capital raising transactions; +● +and +other factors relating +to our industry, our operations and results of operations. +3 +Should +one or more of these risks or uncertainties materialize, or should the underlying assumptions prove incorrect, actual results +may differ significantly from those anticipated, believed, estimated, expected, intended or planned. +Factors +or events that could cause our actual results to differ may emerge from time to time, and it is not possible for us to predict +all of them. We cannot guarantee future results, levels of activity, performance or achievements. Except as required by applicable +law, including the securities laws of the United States, we do not intend to update any of the forward-looking statements to conform +these statements to actual results. +As +used in this Annual Report, the terms “we”, “us”, “our”, and “Co-Diagnostics” +means Co-Diagnostics, Inc., a Utah corporation and its consolidated subsidiaries (the “Company”), unless otherwise +indicated. +ITEM +1: BUSINESS +Overview +Co-Diagnostics, +Inc. (“Company,” or “CDI,”) is developing robust and innovative molecular tools for detection of infectious +diseases, liquid biopsy for cancer screening, and agricultural applications. +Our +diagnostics systems enable very rapid, low-cost, molecular testing for organisms and genetic diseases by automating historically +complex procedures in both the development and administration of tests. CDI’s newest technical advance involves a novel +approach to PCR test design (“Co-Primers”) that eliminates one of the key vexing issues of PCR amplification, the +exponential growth of primer-dimer pairs (false positives and false negatives) which adversely interferes with identification +of the target DNA. +Our +proprietary molecular diagnostics technology is paving the way for innovation in disease detection and life sciences research +through our enhanced detection of genetic material. Because we own our platform, we are able to accomplish this faster and more +economically, allowing for wider margins while still positioning Co-Diagnostics to be a low-cost provider of molecular diagnostics +and screening services. +The +Company, a Utah corporation, is a molecular diagnostics company that has developed and intends to manufacture and sell reagents +used for diagnostic tests that function via the detection and/or analysis of nucleic acid molecules (DNA or RNA). In connection +with the sale of our tests we may sell diagnostic equipment from other manufacturers as self-contained lab systems (which we refer +to as the “MDx device”). +In +addition, continued development has demonstrated the unique properties of our Co-Primer technology that make them ideally suited +to a variety of applications where specificity is key to optimal results, including multiplexing several targets, enhanced Single +Nucleotide Polymorphism (“SNP”) detection and enrichment for next gen sequencing. +Our +scientists were the first to understand the complex mathematics of DNA test design, to “engineer” a DNA test and to +automate algorithms that rapidly screen millions of possible options to pinpoint the optimum design. Dr. Satterfield, our Chief +Technology Officer, developed the Company’s intellectual property consisting of the predictive mathematical algorithms and +proprietary reagents used in the testing process, which together represent a major advance in Polymerase Chain Reaction (“PCR”) +testing systems. CDI technologies are now protected by five granted or pending US patents, as well as certain trade secrets and +copyrights. Ownership of our proprietary platform permits us the advantage of avoiding payment of patent royalties required by +other PCR test systems, which grants us the opportunity of selling diagnostic tests at a lower price than competitors, while generating +a profit margin. +We +may either sell or lease portable and in some cases OEM laboratory equipment to existing diagnostic centers and sell the +reagents that comprise our proprietary tests to those laboratories and other testing facilities. +We +designed our tests by identifying the optimal locations on the target gene for amplification and paired the location with the +optimized primer and probe structure to achieve outputs that meet the design input requirements identified from market research. +This is done by following planned and documented processes, procedures and testing. In other words, the data resulting from our +tests verify that we succeeded in designing what we intended to at the outset. Verification is a series of testing that concludes +that the product is ready to proceed to validation in a clinical evaluation setting using initial production tests to confirm +that the product as designed meets the user needs. +Using +its proprietary test design system and proprietary reagents, CDI will design and sell PCR diagnostic tests for diseases and pathogens +starting with tests for tuberculosis, a drug resistant tuberculosis test, hepatitis B and C, Malaria, dengue, HIV and Zika virus, +all of which tests have been designed and verified in CDI’s laboratory. Our tuberculosis test, Zika test, and a triplex +test for Zika, Dengue and Chikungunya received a CE Marks in 2018 and qualifying our test to be sold throughout the European community +and in most countries in central and South America. +4 +Infectious +Disease Product Offering +We +plan to manufacture molecular diagnostic tests for the following diseases in the following regions, to be sold along with the +MDx device: +Timetable +Region +Tests +Current +(revenues in the 1st quarter in 2019) +Caribbean +and Central and South America +Zika, +Tuberculosis, Hepatitis B and C, Dengue, Zika/Dengue/Chikungunya triplex +India +Tuberculosis, +Hepatitis B and C, Malaria, Dengue and HIV +2019-2020 +European +Union; Asia +Tuberculosis, +Hepatitis B and C +2020-2025 +United +States +To +be determined based on need and regulatory barriers +Caribbean +and Central and South America +Our +initial sales will be to entities within the Caribbean Public Health Agency Members States (Anguilla, Antigua and Barbuda, Aruba, +Bahamas, Barbados, Belize, Bermuda, BES Islands, British Virgin Islands, Cayman Islands, Curacao, Dominica, Grenada, Haiti, Guyana, +Jamaica, Montserrat, Saint Kitts and Nevis, Saint Lucia, St Maarten, Saint Vincent and the Grenadines, Suriname, Trinidad and +Tobago, Turks and Caicos Islands). +In +some of these countries, there are no regulatory hurdles and we can start offering our tests immediately. The U.S. Food and Drug +Administration (FDA) has granted permission for us to export many of our products. The FDA’s permission to export was granted +under Section 801(e) of the Federal Food, Drug, and Cosmetic Act, as amended (the “FDC Act”). Section 801(e) of the +FDA Act covers certain medical devices that have not yet received an approved Premarket Approval in the United States by the FDA, +such as our products. We have not commenced any Premarket Approval steps with the FDA. Section 801(e) applies to medical devices +that are acceptable to the importing country and that are manufactured under the FDA’s Good Manufacturing Practices. +We +first offered our Zika test in this region because of the demand for such test, followed quickly by tests for tuberculosis, hepatitis +B and C, and dengue, then our full range of tests. Products will be manufactured for sale upon receipt of purchase orders from +labs and hospitals. +India +The +Company has entered into an agreement to manufacture diagnostics tests for seven infectious diseases with a pharmaceutical manufacturing +company in India. The agreement provides for the manufacture of the tests named above and the joint sales and marketing of those +tests in India. We have commenced with our joint venture partner to construct a plant that will be used for testing and manufacturing +to service the Indian market. We believe that the plant will be completed and manufacturing activities will begin in the second +quarter of 2019. +Since +the tests will be conducted in India on Indian citizens, no FDA approval or inspection will be required. Certain Indian regulatory +approval from the Central Drugs Standard Control Organization (CDSCO) must be acquired. We are engaging the services of an experienced +consultant in India to help get us through this process. Research Use Only (RUO) reagents are able to be sold without requiring +regulatory approval as long as they are labeled and designated as such. Tests for some of the targeted diseases are available +for sale currently in India. We have received test licenses from the CDSCO for the following tests: tuberculosis, Hepatitis B, +Hepatitis C, HIV, malaria, and a drug resistance test for tuberculosis. We will complete additional testing and then apply for +manufacturing and sales licenses for these tests. +India +is the country with the highest burden of tuberculosis. World Health Organization (WHO) tuberculosis statistics for India for +2015 give an estimated incidence figure of 2.2 million cases of tuberculosis for India out of a global incidence of 9.6 million. +The tuberculosis incidence for India is the number of new cases of active tuberculosis disease in India during a certain time +period (usually a year). +5 +Europe +Molecular +diagnostics, such as our tests, are governed in Europe by the framework for in vitro diagnostics (IVDs), which encompasses diagnostic +products such as reagents, instruments and systems intended for use in diagnosis of disease. The regulatory system for IVDs is +built largely on a self-certification procedure, placing heavy responsibility on manufacturers. Non self-certified products are +subject to the same standards as self-certified products but are subject to audit and review by a notified body prior to receiving +approval to be CE-marked. A CE-marking is a manufacturer’s declaration that a product meets the requirements of the applicable +European Commission directive. Examples of current obligations include having in place a qualitative manufacturing process, user +instructions that are clear and fit for purpose, ensuring that the ‘physical’ features of devices and diagnostics +do not pose any danger. If a product fulfils these and other related control requirements, it may be CE-marked as an indication +that the product is compliant with EU legislation and sold in the European Union. We received CE Marks for our tuberculosis test, +our Zika test, and our zika, dengue, chikungunya triplex test in 2018. +We +have received ISO 13485 and ISO 9001 certifications relating to the design and manufacture of our medical device products. The +ISO certification indicates that we meet the standards required to self-certify certain of our products and affix a CE-marking +for sales of our products in countries accepting the CE marking (not in the United States) with only minimal further governmental +approvals in each country. We estimate the remaining costs for CE-marks on the initial tests we will offer to be approximately +$100,000. +United +States +We +do not anticipate offering our tests in the United States in the near future. We believe, however, our tests may be able to qualify +as Laboratory Developed Tests (LDT’s), diagnostic tests that are developed and manufactured by CLIA certified laboratories. +These tests are developed by the lab for use only in that laboratory. CLIA laboratories develop the performance characteristics, +perform the analytical validation for their LDT’s and obtain licenses to offer them as diagnostic services. The FDA has +publicly announced its intention to regulate certain LDTs in a phased-in approach, but draft guidance that was published a couple +of years ago was withdrawn at the end of the Obama administration and replaced by an informal non-enforceable discussion paper +reflecting some of the feedback that it received on LDT regulation. +Market +Opportunity +The +molecular diagnostics market is a fast-growing portion of the in vitro (test tube based, controlled environment) diagnostics market. +Using estimates of the incidence of disease by the Centers for Disease Control, the World Health Organization and other international +health agencies and sources, the Company estimates that the global annual demand for our initial diagnostic tests could +be as much as follows: +Tuberculosis +10,400,000 +HIV +36,700,000 +Multi-drug resistant Tuberculosis +580,000 +Malaria +214,000,000 +Zika +324,000,000 +Sexually Transmitted Illnesses +357,000,000 +Hepatitis B +240,000,000 +Human papilloma virus +291,000,000 +Hepatitis C +130,000,000 +Dengue +390,000,000 +Total Annual Tests +1,993,680,000 +There +are several advantages of molecular tests, such as the ones we market and sell, over other forms of diagnostic testing, which +include higher sensitivities, the ability to perform multiplex tests and the ability to test for drug resistance or individual +genes. +Competitive +Advantages of Co-Diagnostics +We +believe that we have the following competitive advantages: +● +Affordability: +Lower-cost test kits and low-cost MDx-device. +● +Flexibility: +CDI’s tests have been designed to run on many vendors’ DNA diagnostic testing machines. These tests are +particularly well suited to the new generation of “lab-on-a-chip” and “point-of-care” (“LOC +and POC”), highly portable analysis machinery for field, clinic and office applications. +● +Speed : +We believe our rapid assay design system software provides shorter time to product release. +● +Accuracy : +We believe our tests are more accurate than competitors’ and can detect more strains of viruses. +● +Exclusivity : +CDI owns all patents and all intellectual property used in preparation of its tests. +6 +● +Personalized +Medicine : We project that rising health care costs in developed and developing nations will increasingly require that +health care systems be patient specific to eliminate waste, misdiagnoses, and ineffectiveness. A critical component will be +accurate, more affordable DNA-based diagnostics, which CDI plans to offer. +● +Low-cost +Provider : We plan to keep the Company’s overhead low. Its platform technology obviates the need to pay patent +royalties typically required of its competitors, which use patented test platforms to design their tests. +● +Worldwide +Footprint : With a dynamic technology that encompasses markets worldwide, the Company anticipates that it can identify +the best target markets, not only in high burden developing countries (HBDC’s) but also in developed nations. +● +Growth +Industry Category : We believe that DNA testing is the fastest-growing segment of in-vitro diagnostic testing. +● +Combination +Product Offering : CDI’s ultra-sensitive tests can be a well-designed match for a new generation of handheld +and other small point-of-care devices now entering the market. Used together, these affordable tests and devices may revolutionize +the molecular diagnostics industry in cost, speed of test results and simplification. +● +Multi-plexing: +Our initial development efforts have demonstrated that our Co-Primer designed tests will be able to test for multiple +targets in the same sample without the distortion caused by false negatives and false positives that generally occur in multiplexed +tests. +Liquid +Biopsy for Cancer Screening +The +development of the liquid biopsy test will spur low cost testing in many developing countries. We believe that our liquid biopsy +cancer screening shall be ready for testing in 2019 if we have sufficient development resources to dedicate to the project. Medical +applications of our SNP detection technology can determine the presence of cancer cells or cell-free genetic material in a liquid +or tissue biopsy, and to determine the distinct type of cancer involved. A real-life example of this includes being able to identify +specific mutation(s) in genes linked to breast cancer in order to determine a patient’s prognosis, initiate the most effective +and affordable treatment and to determine whether chemotherapy is necessary. +Our +technology has for all practical purposes essentially eliminated, primer-dimers, which opens up some very unique applications +for liquid biopsy for cancer detection. Our ability to multiplex the reaction in testing for several DNA targets allows technicians +to detect multiple cancers as free-circulating DNA fragments or whole cells in a blood sample at the same time +Agricultural +Applications +SNP +detection is also used in the agricultural industry to identify variations in crop genomes to achieve improved seed viability +and other desired characteristics, including drought resistance, disease resistance, pest resistance and higher yield. +In +mid-2017, the Company was first approached by a large agribusiness to evaluate our ability to multiplex certain target genomes. +The results of the development project have been to successfully demonstrate our ability to not only multiplex the target genomes, +but targeted SNP’s as well. The project was undertaken in conjunction with the manufacturer of our CoPrimer tests. The results +of the project encouraged the parent of our manufacturer to seek a world-wide licensing arrangement for our CoPrimers in the agricultural +industry, which was completed in October 2018. Pursuant to the exclusive license for the agrigenomics industry, the licensee will +pay us a royalty for all CoPrimers sold to the licensee’s customers. In January 2019, the licensee formally introduced the +product at a large agricultural conference and has branded the product it will sell as BHQCoPrimers. +Additional +Licensing and Assay Development In addition, the unique properties of our CoPrimer technology make them ideally suited to +a variety of applications where sensitivity is key to optimal results, including multiplexing several targets, enhanced SNP detection +and enrichment for next gen sequencing. Because of these unique characteristics of CoPrimers, research companies and institutions +have requested that we design diagnostics to locate and identify uncommon gene sequences and SNPs and create tests for the target +sequences in a multiplexed reaction. This application of our technology is in its beginning stages, but we believe that the results +from our initial research indicate a significant step forward in defining the capabilities of our technology, which we believe +can be translated to revenue producing licensing arrangements. +Organizational +History and Corporate Information +We +were incorporated as Co-Diagnostics, Inc., in Utah on April 18, 2013. Our principal executive office is located 2401 S. Foothill +Drive, Salt Lake City, Utah 84109. Our telephone number is (801) 438-1036. Our web address is http://codiagnostics.com. +7 +Implications +of Being an Emerging Growth Company +We +are an “emerging growth company,” as defined in the Jumpstart Our Business Startups Act of 2012. We will remain an +emerging growth company until the earlier of (i) the last day of the fiscal year following the fifth anniversary of July 12, 2017, +the date of the first sale of our common stock pursuant to an effective registration statement under the Securities Act of 1933, +as amended (the “Securities Act”); (ii) the last day of the fiscal year in which we have total annual gross revenues +of $1 billion or more; (iii) the date on which we have issued more than $1 billion in nonconvertible debt during the previous +three years; or (iv) the date on which we are deemed to be a large accelerated filer under applicable SEC rules. We expect that +we will remain an emerging growth company for the foreseeable future, but cannot retain our emerging growth company status indefinitely. +We refer to the Jumpstart Our Business Startups Act of 2012 herein as the “JOBS Act”. For so long as we remain an +emerging growth company, we are permitted and intend to rely on exemptions from specified disclosure requirements that are applicable +to other public companies that are not emerging growth companies. These exemptions include: +● +being +permitted to provide only two years of audited financial statements, in addition to any required unaudited interim financial +statements, with correspondingly reduced “Management’s Discussion and Analysis of Financial Condition and Results +of Operations” disclosure; +● +not +being required to comply with the requirement of auditor attestation of our internal controls over financial reporting; +● +not +being required to comply with any requirement that may be adopted by the Public Company Accounting Oversight Board regarding +mandatory audit firm rotation or a supplement to the auditor’s report providing additional information about the audit +and the financial statements; +● +reduced +disclosure obligations regarding executive compensation; and +● +not +being required to hold a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute +payments not previously approved. +For +as long as we continue to be an emerging growth company, we expect that we will take advantage of the reduced disclosure obligations +available to us as a result of that classification. Accordingly, the information contained herein may be different than the information +you receive from other public companies in which you hold stock. +An +emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities +Act for complying with new or revised accounting standards. This allows an emerging growth company to delay the adoption of certain +accounting standards until those standards would otherwise apply to private companies. We have irrevocably elected to avail ourselves +of this extended transition period and, as a result, we will not be required to adopt new or revised accounting standards on the +dates on which adoption of such standards is required for other public reporting companies. +We +are also a “smaller reporting company” as defined in Rule 12b-2 of the Securities Exchange Act of 1934, as amended, +or the Exchange Act, and have elected to take advantage of certain of the scaled disclosure available for smaller reporting companies. +ITEM +1A. RISK FACTORS +Not +applicable to smaller reporting companies. +ITEM +1B. UNRESOLVED STAFF COMMENTS +None. +ITEM +2. PROPERTIES +Our +executive offices are located at 2401 S. Foothill Drive, Salt Lake City, Utah 84109. We occupy the space at the executive offices +under a lease, which expires January 31, 2020. The lease covers approximately 10,273 square feet of lab and office space leased +at a rate of $14,086 per month. We have no other properties. +ITEM +3. LEGAL PROCEEDINGS +From +time to time, we may become involved in litigation relating to claims arising out of our operations in the normal course of business. +To the best of our knowledge, the Company has no legal proceedings against it. +8 +ITEM +4. MINE SAFETY DISCLOSURES +Not +applicable. +PART +II +ITEM +5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER EQUITY SECURITIES +Market +Information +Our +common stock, from July 12, 2017, was quoted on the NASDAQ market under the symbol “CODX”. The following table sets +forth the high and low prices for our common stock for the periods indicated, as reported by NASDAQ. +2019 +HIGH +LOW +First Quarter (through March 15, 2019) +$ 3.77 +$ 0.93 +2018 +First Quarter +$ 3.27 +$ 1.45 +Second Quarter +$ 6.66 +$ 1.57 +Third Quarter +$ 4.30 +$ 2.60 +Fourth Quarter +$ 3.10 +$ 1.15 +2017 +HIGH +LOW +First Quarter +$ — +$ — +Second Quarter +$ — +$ — +Third Quarter +$ 6.75 +$ 3.50 +Fourth Quarter +$ 6.85 +$ 2.35 +Holders +As +of March 15, 2019, the last reported sales price reported on NASDAQ for our common stock was $1.15 per share. As of the date of +this filing, we had approximately 429 holders of our common stock. The number of record holders was determined from the records +of our transfer agent and does not include beneficial owners of common stock whose shares are held in the names of various security +brokers, dealers, and registered clearing agencies. The transfer agent for our common stock is VStock Transfer LLC located at +18 Lafayette Pl, Woodmere, New York 11598. +Dividends +We +have never declared or paid any cash dividends on our capital stock. The payment of dividends on our common stock in the future +will depend on our earnings, capital requirements, operating and financial condition and such other factors as our Board of Directors +may consider appropriate. We currently expect to use all available funds to finance the future development and expansion of our +business and do not anticipate paying dividends on our common stock in the foreseeable future. +Recent +Sales of Unregistered Securities +On +October 2, 2018, we issued 249,360 shares of our common stock to a Canadian corporation which had been a licensee of ours in consideration +of changing our license agreement to a distributor agreement restricted to a single country and transferring to us all of the +Canadian corporation’s sales and marketing contacts. In addition, we issued a warrant to the licensee to acquire up to 50,000 +shares of our common stock at an exercise price of $2.00 per share. The warrant may be exercised at any time within five years +of the grant date. +On +December 27, 2018, we issued 6,000 shares of our common stock to a limited liability company in consideration of consulting services +performed. The limited liability company is an accredited investor. +On +December 27, 2018, we issued 3,000 shares of our common stock in consideration of consulting services performed by a limited liability +company. +9 +We +relied on the exemption from registration under the Securities Act set forth in Section 4(2) thereof for each of these issuances. +Purchases +of Equity Securities by the Issuer and Affiliated Purchasers +None. +ITEM +6. SELECTED FINANCIAL DATA +Not +required. +ITEM +7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULT OF OPERATIONS +The +following management’s discussion and analysis of financial condition and results of operations describes the principal +factors affecting the results of our operations, financial condition, and changes in financial condition. This discussion should +be read in conjunction with the accompanying audited financial statements, and notes thereto, included elsewhere in this report. +The information contained in this discussion is subject to a number of risks and uncertainties. We urge you to review carefully +the sections of this report entitled “ Risk Factors ” and “ Forward-Looking Statements ” for +a more complete discussion of the risks and uncertainties associated with an investment in our securities. +Overview +Co-Diagnostics, +Inc. (“Company,” or “CDI,”) is developing robust and innovative molecular tools for detection of infectious +diseases, liquid biopsy for cancer screening, and agricultural applications. +Our +diagnostics systems enable very rapid, low-cost, molecular testing for organisms and genetic diseases by automating historically +complex procedures in both the development and administration of tests. CDI’s newest technical advance involves a novel +approach to PCR test design (“Co-Primers”) that eliminates one of the key vexing issues of PCR amplification, the +exponential growth of primer-dimer pairs (false positives and false negatives) which adversely interferes with identification +of the target DNA. +Our +proprietary molecular diagnostics technology is paving the way for innovation in disease detection and life sciences research +through our enhanced detection of genetic material. Because we own our platform, we are able to accomplish this faster and more +economically, allowing for wider margins while still positioning Co-Diagnostics to be a low-cost provider of molecular diagnostics +and screening services. +The +Company, a Utah corporation, is a molecular diagnostics company that has developed and intends to manufacture and sell reagents +used for diagnostic tests that function via the detection and/or analysis of nucleic acid molecules (DNA or RNA). In connection +with the sale of our tests we may sell diagnostic equipment from other manufacturers as self-contained lab systems (which we refer +to as the “MDx device”). +In +addition, continued development has demonstrated the unique properties of our Co-Primer technology that make them ideally suited +to a variety of applications where specificity is key to optimal results, including multiplexing several targets, enhanced Single +Nucleotide Polymorphism (“SNP”) detection and enrichment for next gen sequencing. +Our +scientists were the first to understand the complex mathematics of DNA test design, to “engineer” a DNA test and to +automate algorithms that rapidly screen millions of possible options to pinpoint the optimum design. Dr. Satterfield, our Chief +Technology Officer, developed the Company’s intellectual property consisting of the predictive mathematical algorithms and +proprietary reagents used in the testing process, which together represent a major advance in Polymerase Chain Reaction (“PCR”) +testing systems. CDI technologies are now protected by five granted or pending US patents, as well as certain trade secrets and +copyrights. Ownership of our proprietary platform permits us the advantage of avoiding payment of patent royalties required by +other PCR test systems, which grants us the opportunity of selling diagnostic tests at a lower price than competitors, while generating +a profit margin. +We +may either sell or lease our portable labs to existing diagnostic centers, through sale or lease agreements, and sell the reagents +that comprise our proprietary tests to those laboratories and testing facilities. +10 +Agreement +with Synbiotics +The +Company has entered into a joint venture agreement to manufacture diagnostics tests for seven infectious diseases with Synbiotics +Limited, a pharmaceutical manufacturing company in India. The Company and Synbiotics shall be equal partners in the joint venture. +The agreement provides for the manufacture of the tests named above and the joint sales and marketing of those tests in India. +The Company will license its technology to the joint venture on a royalty-free basis. The profits from the partnership shall be +divided as follows: +Profit Level +CDI Share +Synbiotics Share +Up to $1,000,000 +50 % +50 % +$1,000,000-$2,000,000 +60 % +40 % +$2,000,000-$3,000,000 +70 % +30 % +Above $3,000,000 +80 % +20 % +Synbiotics +will be reimbursed by the joint venture for some expenses, such as approximately $96,000 in rent for the manufacturing plant and +office space. If the joint venture needs additional funding, it will be achieved through loans obtained by the joint venture, +or if loans are not available on commercially reasonable terms, from capital contributions. There is no term to the joint venture +agreement but it can be dissolved by mutual agreement or by one party upon a material breach by the other party. The manufacturing +plant is completed and is scheduled to be ready for production in the second quarter of 2019. We have submitted technical files +describing seven difference diagnostic tests to the Indian regulatory bodies requesting approval for those tests to be manufactured +in our plant and sold in the Indian market. The joint venture is currently marketing our products in the Indian market and has sold approximately $200,000 of our probes and primers to various laboratories and other users to be used as Research Use Only +tests in their facilities, which we anticipate will be the beginning of sales of our products in India. +Intellectual +Property Protection +Because +much of our future success and value depends on our proprietary technology, our patent and intellectual property strategy is of +critical importance. Four of our initial U.S. patents related to our technology have been granted by the U.S. Patent and Trademark +Office, or PTO, including the patent for our CoPrimer technology, which we consider our most important patent. One of our patents +has been issued in Great Britain, but is still pending in the United States. As of March 15, 2019, we had two additional patents +pending in the U.S. and foreign counterpart applications. Two of our issued patents expire in 2034, one in 2036 and one in 2038. +We +have identified additional applications of the technology, which represent potential patents that further define specific applications +of the processes that are covered by the original patents. We intend to continue building our intellectual property portfolio +as development continues and resources are available. +We +have copyrighted our development software that can be used by any lab or developer to develop diagnostic tests based on our technology. +We have allowed one potential customer access to our development software and intend to sell customized reagents through that +customer to labs serviced by that customer throughout the world. To date we have not sold any products to that customer. +Major +Customers +We +currently have no major customers. +Competition +The +molecular diagnostics industry is extremely competitive. There are many firms that provide some or all of the products we provide +and provide many diagnostic tests that we have yet to develop. Many of these competitors are larger than us and have significantly +greater financial resources. Because we are not established, many of our competitors have a competitive advantage in the diagnostic +testing industry because they also have other lines of business in the pharmaceutical industry from which they derive revenues +and for which they are well known and respected in the medical profession. We will need to overcome the disadvantage of being +a start up with no history of success and no respect of the medical and testing professionals. In the diagnostic testing industry, +we compete with such companies as BioMerieux, Siemans, Qiagen, and Cephied and with such pharmaceutical companies as Abbott Laboratories, +Becton, Dickinson and Johnson and Johnson. +Many +of these competitors already have an established customer base with industry standard technology, which we must overcome to be +successful. +11 +Employees +We +currently employ 20 full-time personnel at our executive offices and lab facilities in Salt Lake City, Utah, and two employees +outside of Utah. We have engaged independent contractors in India to promote the use of our products and develop outlets for products +and employ the services of independent sales representatives on an “as needed” basis. +Government +Regulation +We +will be regulated by the U.S. Federal Drug Administration and our products must be approved by the FDA before we will be allowed +to sell our tests in the United States. Because our lab is ISO certified we are allowed to apply for CE-Marking, which will allow +us to sell in most countries in Europe, South America and Asia. We currently have CE Marks issued for our tuberculosis test, our +zika virus test, and a triplex test that tests for zika, dengue, and chikungunya simultaneously. +Properties +Our +executive offices are located at 2401 S. Foothill Drive, Salt Lake City, Utah 84109. We occupy the space at the executive offices +under a lease, which expires January 31, 2020. The lease covers approximately 10,273 square feet of lab and office space leased +at a rate of $14,086 per month. We have no other properties. +Legal +Proceedings +The +Company has no legal proceedings and to the knowledge of management, no litigation has been threatened. +RESULTS +OF OPERATIONS +Results +of Operations for the Years Ended December 31, 2018 and 2017 +Table derived from audited financial statements +For the years ended +December 31, +December 31, +2018 +2017 +Net sales +$ 39,911 +$ 7,662 +Cost of sales +9,391 +302 +Gross profit +30,520 +7,360 +Operating expenses: +Selling and marketing +1,165,361 +426,711 +Administrative and general +3,570,786 +3,095,791 +Research and development +1,361,154 +1,003,167 +Depreciation and amortization +50,765 +45,758 +Total operating expenses +6,148,336 +4,571,427 +Total operating loss +(6,117,816 ) +(4,564,067 ) +Other expense: +Interest expense +(134,947 ) +(310,233 ) +Loss on extinguishment of debt +— +(2,072,365 ) +Net gain (loss) from investment in joint venture +(38,764 ) +(16,396 ) +Interest income +19,804 +3,829 +Total other expense +(153,907 ) +(2,395,165 ) +Loss before income taxes +(6,271,723 ) +(6,959,232 ) +Provision for income taxes +— +— +Net loss +$ (6,271,723 ) +$ (6,959,232 ) +Revenues +Sales +of products in the twelve months ended December 31, 2018 was $700, which represented the initial sales of our diagnostic tests. +In addition, we realized revenue from the sale of diagnostic equipment of $10,123 and had licensing revenue of $29,088 compared +to no test revenue in the twelve months ended December 31, 2017, but had licensing revenue of $6,062, other service revenue of +$1,000 and leased equipment revenue of $600. +12 +Cost +of Revenues and Gross Profit +Although +we had licensing revenue in the twelve months ended December 31, 2018 and for the twelve months ended December 31, 2017, there +were no costs associated with the license revenue. In addition, we recorded $9,200 of equipment costs of sales in 2018. +Operating +Expenses +We +incurred total operating expenses of $6,148,336 for the year ended December 31, 2018 compared to total operating expenses of $4,571,427 +for the year ended December 31, 2017. The increase of $1,576,909 was due to an increase in general and administrative expense +of $474,995, an increase in sales and marketing costs of $738,920, an increase of $357,987 in our research and development expenses +and an increase in depreciation and amortization expense of $5,007. +Our +general and administrative expenses increased $474,995 from $3,095,791 for the year ended December 31, 2017 to $3,570,786 for +the year ended December 31, 2018. The increase was primarily the result of an increase of $417,549 in salaries and related benefits +and an increase of $345,981in option and warrant expense reflecting the issuance of options to our employees and others. In addition, +legal and professional fees increased $83,158 and directors’ fees increased $82,500, and regulatory expenses increased $52,636 +all primarily incident to becoming a publically traded company. These increases were partially offset by a decrease in other professional +services of $600,572 +Our +sales and marketing expenses for the year ended December 31, 2018 were $1,165,631 compared to sales and marketing expenses of +$426,711 for the year ended December 31, 2017. The increase of $738,920 is due primarily to incurring a marketing expense of $497,208 +related to acquisition of a distributor network and changing the licensee to a distributor with its territory restricted to one +country. We also experience an increase of $118,950 in salaries and related benefits, and an increase of $44,091 in travel expenses, +which were incurred as we increased our sales efforts. +Our +research and development expenses increased by $357,987 from $1,003,167 for the year ended December 31, 2017 to $1,361,154 for +the year ended December 31, 2018. The increase was primarily due to an increase of $119,789 in salaries and related benefits as +we increased research and development activities. In addition, lab supplies consumed by the increased research activities increased +$93,733 and consulting fees for research services increased by $70,754 and other professional services increased by $76,092 and +building and lab rent increased by $58,093. The increase in expenses was partially offset by a reduction of $107,500 in technology +license royalties. +Interest +and Other Expense +Interest +and other expense items decreased for the year ended December 31, 2018 by $2,241,258. In the year ended December 31, 2017 we recorded +a loss on the extinguishment of debt incident to debt being retired following our initial public offering of $2,072,365, which +expense was not repeated in the year ended December 31, 2018. In addition, we recorded interest expense of $310,233 in the year +ended December 31, 2017 compared with interest expense of $134,947 in the year ended December 31, 2018. The decrease of $175,286 +was primarily the result of having no debt outstanding for the first eight months of 2018 compared with our bridge financing being +outstanding for approximately six months in 2017. We incurred expenses incident to our India joint venture of approximately $38,764 +in 2018 compared to expenses for the joint venture of $15,115 for the year ended December 31, 2017. +Net +Loss +We +had net loss of $6,271,723 for the year ended December 31, 2018 compared to a net loss of $6,959,232 for the year ended December +31, 2017. The decrease in net loss for the year ended December 31, 2018 compared to the year ended December 31, 2017 was $687,509 +resulted primarily from the loss on extinguishment of debt in 2017 of $2,072,365 being partially offset by increased operating +expenses of $1,576,909 in 2018 explained in more detail above. +LIQUIDITY +AND CAPITAL RESOURCES +Liquidity +is the ability of a company to generate funds to support its current and future operations, satisfy its obligations, and otherwise +operate on an ongoing basis. Significant factors in the management of liquidity are funds generated by operations, levels of accounts +receivable and accounts payable and capital expenditures. +To +date we have financed our operations through sales of common stock and the issuance of debt. +At +December 31, 2018, we had cash and cash equivalents of $950,237, total current assets of $1,051,913, total current liabilities +of $2,351,983 and total stockholders’ deficit of $1,058,811. At December 31, 2017, we had cash and cash equivalents of $3,534,454, +total current assets of $4,451,874, total current liabilities of $628,256 and total stockholders’ equity of $3,850,524. +13 +On +July 12, 2017, we entered into an underwriting agreement (the “Underwriting Agreement”) with WallachBeth Capital, +LLC and Network 1 Financial Securities, Inc. (the “Underwriters”), related to the Company’s initial public offering +of 1,178,532 shares of the Company’s common stock, at a price of $6.00 per share, less $0.60 constituting the underwriting +commissions and non-accountable expense allowance. Under the terms of the Underwriting Agreement, the Company granted the Underwriters +an option, exercisable for 45 days, to purchase up to an additional 176,780 shares of common stock to cover over-allotments, if +any. Total gross proceeds from the offering were $7,071,192 and the Company received net proceeds after costs of $5,977,924. +Coincident +with the closing of the IPO, the Company retired all of its principal debt of $3,440,000 and approximately $283,000 of accrued +interest through the issuance of approximately 857,048 shares. +We +experienced negative cash flow used in operations during the twelve months ended December 31, 2018 of $4,080,036 compared to negative +cash flow used in operations for the twelve months ended December 31, 2017 of $3,211,401. In addition, we used $153,000 of our +cash in financing transactions and used $339,000 in contributions to our joint venture in India. The negative cash flow in 2018 +was met by cash reserves from the issuances of common stock incident to the completion of our initial public offering and in August +2018, we issued short term debt to an individual in the principal amount of $2.0 million that bore interest of 9% per annum and +matured on July 31, 2019, which was converted to Series A Preferred Stock in January 2019. The amount of our operating deficit +could decrease or increase significantly depending on strategic and other operating decisions, thereby affecting our need for +additional capital. We expect our operating losses will continue until we are able to generate revenue. Until our operations become +profitable, we will continue to rely on proceeds received from our public offerings of stock. In August 2018 we filed a shelf +registration of our securities with the SEC and in September 2018 it was declared effective. In February 2019 we completed the +registered direct offering described above pursuant to that registration. We expect additional investment capital to come from +(i) additional issuances of our common stock pursuant to our S-3 shelf registration with existing and new investors and (ii) the +private placement of other securities with investors similar to those that have provided funding in the past. +Our +monthly cash operating expenses, including our technology research and development expenses and interest expense, were approximately +$385,000 per month during the year ended December 31, 2018. Our operating expenses increased significantly upon completion of +our initial public offering as we increased development and sales activities in furtherance of our business plan. We did not have +sufficient capital resources at December 31, 2018 to fund our negative cash flow for the next year without raising additional +capital and therefore in January 2019 we completed a registered direct offering to fund operations until we commence sales of +products. The foregoing estimates, expectations and forward-looking statements are subject to change as we make strategic operating +decisions from time to time and as our expenses fluctuate from period to period. +On +January 30, 2019, we entered into a securities purchase agreement with investors, whereby the investors purchased from the Company +30,000 shares of Series A Convertible Preferred Stock of the Company for a purchase price of $3,000,000. The purchase price was +paid by the investors with $1.0 million in cash and the conversion of a $2.0 million note owed by the Company to one of the investors. +The investors may not convert the Series A Preferred Stock to the extent that such conversion would result in beneficial ownership +by the investors and their affiliates of more than 4.99% of the issued and outstanding Common Stock of the Company. +On +February 4, 2019, we completed the sale of 3,925,716 shares of the Company’s common stock, par value $0.001 per share, at +a purchase price of $1.40 per share in a registered direct offering. The aggregate gross proceeds for the sale of the Common Shares +was $5,496,002 and we received net proceeds after offering costs of $4,996,322. +The +amount of our operating deficit could decrease or increase significantly depending on strategic and other operating decisions, +thereby affecting our need for additional capital. We expect our operating losses will continue until we are able to generate +revenue. Revenue has commenced in 2019 and our need for additional investment will depend on the amount of revenue generated. +At our current level of operating expenditures, we have sufficient cash to fund operations for the next twelve months. +Our +long-term liquidity is dependent upon execution of our business model and the commencement of revenue generating activities and +working capital as described above, and upon capital needed for continued commercialization and development of our diagnostic +testing technology. Commercialization and future development of diagnostic tests utilizing our PCR technology are expected to +require additional capital estimated to be approximately $850,000 annually for the foreseeable future. This estimate will increase +or decrease depending on specific opportunities and available funding. +Off-Balance +Sheet Arrangements +As +of December 31, 2018, we had no off-balance sheet arrangements. +ITEM +7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Not +required. +14 +ITEM +8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATE. +CONSOLIDATED +FINANCIAL STATEMENTS +DECEMBER +31, 2018 AND 2017 +Table +of Contents +Report of Independent Registered Public Accounting Firm +F-1 +Balance Sheets +F-2 +Statements of Operations +F-3 +Statement of Changes in Stockholders’ Equity (Deficit) +F-4 +Statements of Cash Flows +F-5 +Notes to Financial Statements +F-6 +15 +REPORT +OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +To +the Board of Directors and +Stockholders +of Co-Diagnostics, Inc. +Opinion +on the Financial Statements +We +have audited the accompanying consolidated balance sheets of Co-Diagnostics, Inc. (the Company) as of December 31, 2018 and 2017, +and the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for each of the years +in the two-year period ended December 31, 2018, and the related notes (collectively referred to as the financial statements). +In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of +December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the years in the two-year period +ended December 31, 2018, in conformity with accounting principles generally accepted in the United States of America. +Basis +for Opinion +These +financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on +the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company +Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance +with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the +PCAOB. +We +conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit +to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error +or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial +reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting, but +not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. +Accordingly, we express no such opinion. +Our +audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to +error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence +regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles +used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. +We believe that our audits provide a reasonable basis for our opinion. +/s/ +Haynie & Company +Haynie +& Company +Salt +Lake City, Utah +March +29, 2019 +We +have served as the Company’s auditor since 2016 +F- 1 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +CONSOLIDATED +BALANCE SHEETS +December +31, 2018 +December +31, 2017 +ASSETS: +Current Assets +Cash and cash equivalents +$ 950,237 +$ 3,534,454 +Accounts receivable ,net +13,420 +— +Inventory +18,153 +9,068 +Prepaid expenses +70,103 +908,352 +Total current assets +1,051,913 +4,451,874 +Property and equipment, net +156,138 +165,567 +Investment in joint venture +345,121 +44,885 +Total other long-term assets +501,259 +210,452 +Total assets +$ 1,553,172 +$ 4,662,326 +LIABILITIES AND STOCKHOLER’S EQUITY (DEFICIT) : +Current Liabilities +Accounts payable +$ 148,967 +$ 40,819 +Accrued expenses +174,444 +96,645 +Accrued expenses (related party) +120,000 +480,000 +Current notes payable net of $91,428 and $0 discount, respectively +1,908,572 +— +Deferred income current +— +10,792 +Total current liabilities +2,351,983 +628,256 +Long-term Liabilities +Accrued liabilities (related-party) +260,000 +— +Deferred income long-term +— +183,546 +Total long-term liabilities +260,000 +183,546 +Total liabilities +2,611,983 +811,802 +Commitments and contingencies +STOCKHOLDERS’ EQUITY (DEFICIT): +Common stock, $.001 par value, 100,000,000 shares authorized; 12,923,383 and 12,317,184 shares issued and outstanding, respectively. +12,923 +12,317 +Preferred stock, $.001 par value, 5,000,000 shares authorized +— +— +Additional paid-in capital +17,622,433 +16,260,651 +Accumulated deficit +(18,694,167 ) +(12,422,444 ) +Total stockholders’ equity (deficit) +(1,058,811 ) +3,850,524 +Total liabilities and stockholders’ equity (deficit) +$ 1,553,172 +$ 4,662,326 +See +accompanying notes to consolidated financial statements +F- 2 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF OPERATIONS +FOR +THE YEARS ENDED DECEMBER 31, 2018 AND 2017 +For the years ended +December 31, +2018 +2017 +Net sales +$ 39,911 +$ 7,662 +Cost of sales +9,391 +302 +Gross profit +30,520 +7,360 +Operating expenses: +Selling and marketing +1,165,631 +426,711 +Administrative and general +3,570,786 +3,095,791 +Research and development +1,361,154 +1,003,167 +Depreciation and amortization +50,765 +45,758 +Total operating expenses +6,148,336 +4,571,427 +Total operating loss +(6,117,816 ) +(4,564,067 ) +Other expense: +Interest expense +(134,947 ) +(310,233 ) +Interest income +19,804 +3,829 +Loss on extinguishment of debt +— +(2,072,365 ) +Net loss from investment in joint venture +(38,764 ) +(16,396 ) +Total other expense +(153,907 ) +(2,395,165 ) +Loss before income taxes +(6,271,723 ) +(6,959,232 ) +Provision for income taxes +— +— +Net loss +$ (6,271,723 ) +$ (6,959,232 ) +Net loss per share – basic and diluted +$ (0.50 ) +$ (0.63 ) +Weighted average shares – basic and diluted +12,484,617 +10,960,326 +See +accompanying notes to consolidated financial statements. +F- 3 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT) +FOR +THE YEARS ENDED DECEMBER 31, 2018 AND 2017 +Common Stock +Additional +Paid-in +Retained +Earnings +Equity +Shares +Amount +Capital +(Deficit) +(Deficit) +Balance, December 31, 2016 +9,882,395 +$ 9,882 +$ 2,458,744 +$ (5,463,212 ) +$ (2,994,586 ) +Stock issued for cash, net of offering costs of $1,093,268 +1,178,533 +1,179 +5,976,745 +— +5,977,924 +Stock issued for debt retirement +857,047 +857 +5,791,603 +— +5,792,460 +Stock-based compensation +399,209 +399 +2,033,559 +— +2,033,958 +Net loss +— +— +— +(6,959,232 ) +(6,959,232 ) +Balance, December 31, 2017 +12,317,184 +12,317 +16,260,651 +(12,422,444 ) +3,850,524 +Stock issued for exercise of warrants +272,727 +273 +29,727 +— +30,000 +Stock-based compensation +333,472 +333 +1,332,055 +— +1,332,388 +Net loss +— +— +— +(6,271,723 ) +(6,271,723 ) +Balance, December 31, 2018 +12,923,383 +$ 12,923 +$ 17,622,433 +$ (18,694,167 ) +$ (1,058,811 ) +See +accompanying notes to consolidated financial statements. +F- 4 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF CASH FLOWS +FOR +THE YEARS ENDED DECEMBER 31, 2018 AND 2017 +Years Ended +December 31, +2018 +2017 +Cash flows from operating activities: +Net loss +$ (6,271,723 ) +$ (6,959,232 ) +Adjustments to reconcile net loss to net cash used in operating activities: +Depreciation and amortization +50,765 +45,758 +Stock based compensation +1,332,388 +2,033,958 +Accretion of notes payable discount +— +84,101 +Loss on extinguishment of debt +— +2,072,365 +Other losses +38,764 +16,396 +Changes in assets and liabilities: +Increase (decrease) deferred income +(194,338 ) +194,338 +Decrease (increase) in prepaid and other assets +900,666 +(698,389 ) +Increase in accounts receivable +(13,420 ) +— +Increase in inventory +(9,085 ) +(9,068 ) +Increase in accounts payable and accrued expenses +85,947 +8,372 +Net cash used in operating activities +(4,080,036 ) +(3,211,401 ) +Cash flows from investing activities: +Purchase of property and equipment +(41,336 ) +(129,306 ) +Investment in joint venture +(339,000 ) +(60,000 +Net cash used by investing activities +(380,336 ) +(189,306 ) +Cash flows from financing activities: +Proceeds from equity financing +— +7,071,192 +Offering costs from equity financing +— +(1,093,268 ) +Proceeds from warrant exercise +30,000 +— +Proceeds from debt financing +2,000,000 +— +Debt financing acquisition costs +(153,845 ) +— +Principal payments on debt (related party) +— +(41,500 ) +Net cash provided by financing activities +1,876,155 +5,936,424 +Net increase (decrease) in cash +(2,584,217 ) +2,535,717 +Cash and cash equivalents beginning of period +3,534,454 +998,737 +Cash and cash equivalents end of period +$ 950,237 +$ 3,534,454 +Supplemental disclosure of cash flow information: +Interest paid +$ 71,000 +$ 73,523 +Income taxes paid +$ — +$ — +Schedule of non-cash (investing) and financing activities: +Common stock issued for convertible debt +$ — +$ 5,792,460 +See +accompanying notes to consolidated financial statements. +F- 5 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS +YEARS +ENDED DECEMBER 31, 2018 AND 2017 +NOTE +1: ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES +Co-Diagnostics, +Inc. (“Company,” “CDI,” “we”), a Utah corporation headquartered in Salt Lake City, Utah, is +a molecular diagnostics company formed in April, 2013 that develops, manufactures and markets a new diagnostics technology. +The +accompanying consolidated financial statements include our accounts and the accounts of our wholly-owned subsidiary. All intercompany +account balances and transactions have been eliminated in consolidation. +We +entered into a joint venture agreement with a company in India for the purpose of setting up a manufacturing location in India +of our products and for distribution of our products in India. We invested $339,000 and $60,000 in 2018 and 2017, respectively +for our 50% interest in the joint venture. We determined that we had a variable interest in the joint venture company, which is +considered a variable interest entity, but that we were not the primary beneficiary as the power to direct the significant activities +of the joint venture company are shared. Therefore, we used the equity method of accounting to record our investment in the joint +venture. Our equity method investees are recorded in other long-term assets in the accompanying consolidated balance sheet. Our +share of earnings or losses from equity method investees is included in other losses in the accompanying consolidated statements +of operations. +The +Company evaluates its equity method investments for impairment whenever events or changes in circumstances indicate that the carrying +amounts of such investments may not be recoverable. The difference between the carrying value of the equity method investment +and its estimated fair value is recognized as an impairment charge when the loss in value is deemed other than temporary. +Profits +from the joint venture shall be divided as follows: +Profit +Level +CDI +Share +Partner +Share +Up to +$1,000,000 +50 % +50 % +$1,000,000-$2,000,000 +60 % +40 % +$2,000,000-$3,000,000 +70 % +30 % +Above $3,000,000 +80 % +20 % +The +joint venture partner will be reimbursed for some expenses, such as approximately $96,000 per year for office space. If the joint +venture needs additional funding, it will be achieved through loans obtained by the joint venture, or if loans are not available +on commercially reasonable terms, from capital contributions. There is no term to the joint venture agreement but it can be dissolved +by mutual agreement or by one party upon a material breach by the other party. +Basis +of Presentation +The +accompanying audited consolidated financial statements of Co-Diagnostics, Inc. have been prepared to reflect the financial position, +results of operations and cash flows of the Company and have been prepared in accordance with accounting principles generally +accepted in the United States of America (“GAAP”). +Reverse +Stock Split +On +May 24, 2017 the Company affected an 11 to 1 reverse stock split. The statements in this report have been prepared showing the +effect as of the beginning of the periods included. +Initial +Public Offering +On +July 12, 2017, we entered into an underwriting agreement (the “Underwriting Agreement”) with WallachBeth Capital, +LLC and Network 1 Financial Securities, Inc. (the “Underwriters”), related to the Company’s initial public offering +of 1,178,533 shares of the Company’s common stock, at a price of $6.00 per share, less $0.60 constituting the underwriting +commissions and expense allowance. Under the terms of the Underwriting Agreement, the Company granted the Underwriters an option, +exercisable for 45 days, to purchase up to an additional 176,780 shares of common stock to cover over-allotments, if any. Total +gross proceeds from the offering were $7,071,192 and the Company received net proceeds after costs of $5,977,924. +Coincident +with the closing of the IPO, the Company retired all of its principal debt of $3,440,440 and $283,423 of accrued interest through +the issuance of 857,047 shares of common stock. +F- 6 +Significant +Account Policies +Cash +and Cash Equivalents +The +Company considers all cash on hand and in banks, and highly liquid investments to be cash equivalents. At December 31, 2018, the +Company had $700,237 in bank balances in excess of amounts insured by the Federal Deposit Insurance Corporation. At December 31, +2017, the Company had $3,284,454 in bank balances in excess of amounts insured by the Federal Deposit Insurance Corporation. Included +in cash and cash equivalents at December 31, 2017, was $2,200,288 in short-term federally insured certificates of deposits. The +Company has not experienced any losses in such accounts, and management believes the Company is not exposed to any significant +credit risk on cash and cash equivalents. +I nventory +Inventory +is stated at the lower of cost or market. Inventory cost is determined on a first-in first-out basis that approximates average +cost in accordance with ASC 330-10-30-12. Provisions are made to reduce slow-moving, obsolete, or unusable inventories to their +estimated useful or scrap values. The Company establishes reserves for this purpose. +Accounts +Receivable +Trade +accounts receivable are carried at original invoice amount less an estimate made for doubtful receivables based on a review of +all outstanding amounts on a monthly basis. Management determines the allowance for doubtful accounts by identifying troubled +accounts and by using historical experience applied to an aging of accounts. Trade receivables are written off when deemed uncollectible. +Recoveries of trade receivables previously written off are recorded when collected. +Property +and Equipment +Property +and equipment are stated at cost. Depreciation is provided using the straight-line method over the estimated useful lives of the +property, generally from three to five years. Repairs and maintenance costs are expensed as incurred except when such repairs +significantly add to the useful life or productive capacity of the asset, in which case the repairs are capitalized. +Equity-Method +Investments +Our +equity method investments are initially recorded at costs and are included in other long-term assets in the accompanying consolidated +balance sheet. We adjust the carrying value of our investment based on our share of the earnings or losses in the periods which +they are reported by the investee until the carrying amount is zero. The earnings or losses are included in other losses in the +accompanying consolidated statements of operations. +Earnings +(Loss) per Share +Basic +earnings or loss per common share is computed by dividing net income or loss applicable to common shareholders by the weighted +average number of shares outstanding during each period. As the Company experienced net losses during the years ending December +31, 2018 and 2017, no common stock equivalents have been included in the diluted earnings per common share calculations as the +effect of such common stock equivalents would be anti-dilutive. As of December 31, 2018, and 2017, there were 1,656,242 and 1,028,969 +potentially dilutive shares, respectively. +Stock-based +Compensation +The +Company accounts for stock-based compensation under the provisions of FASB ASC Topic 718, Compensation-Stock Compensation (“ASC +718”), which requires the measurement and recognition of compensation expense for all stock-based awards made to employees +and directors based on estimated fair values on the grant date. The Company estimates the fair value of stock-based awards on +the date of grant using the Black-Scholes-Merton option-pricing model (the “Black-Scholes Model”). The value of the +portion of the award that is ultimately expected to vest is recognized as expense over the requisite service periods using the +straight-line method. +The +Company estimates forfeitures at the time of grant and revises its estimate in subsequent periods if actual forfeitures differ +from those estimates. +The +Company accounts for stock-based compensation awards to non-employees in accordance with FASB ASC Topic 505-50, Equity-Based Payments +to Non-Employees (“ASC 505-50”). Under ASC 505-50, the Company determines the fair value of the warrants or stock-based +compensation awards granted as either the fair value of the consideration received or the fair value of the equity instruments +issued, whichever is more reliably measurable. +F- 7 +All +issuances of stock options or other equity instruments to employees and non-employees as the consideration for goods or services +received by the Company are accounted for based on the fair value of the equity instruments issued or the fair market value of +the services provided. Any stock options issued to non-employees are recorded in expense and additional paid-in capital in shareholders’ +equity over the applicable service periods using variable accounting through the vesting dates based on the fair value of the +options at the end of each reporting period. +Income +Taxes +We +account for income taxes in accordance with the asset and liability method of accounting for income taxes prescribed by ASC Topic +740. Under the asset and liability method, deferred tax assets and liabilities are recognized for the future tax consequences +attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective +tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to the taxable income in +the years in which those temporary differences are expected to be recovered or settled. +Deferred +taxes are provided on an asset and liability method whereby deferred tax assets are recognized for deductible temporary differences +and operating loss and tax credit carry-forwards and deferred tax liabilities are recognized for taxable temporary differences. +Temporary differences are the differences between the reported amounts of assets and liabilities and their tax bases. Deferred +tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion +or all of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes +in tax laws and rates on the date of enactment. +Research +and Development +Research +and development costs are expensed when incurred. The Company expensed $1,361,154 and $1,003,167 of research and development costs +for the years ended December 31, 2018 and 2017, respectively. +Use +of Estimates +The +preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates +and assumptions that affect the amounts reported in the financial statements and the accompanying notes. Such estimates include +receivables and other long-lived assets, legal and regulatory contingencies, income taxes, share based arrangements, and others. +These estimates and assumptions are based on management’s best estimates and judgments. Actual amounts and results could +differ from those estimates. +Fair +Value Measurements +The +carrying amounts of our accounts receivable, accounts payable and accrued liabilities approximate their fair values due to their +immediate or short-term maturities. The aggregate carrying amount of the notes payable approximates fair value as the individual +notes bear interest at market interest rates and there has not been a significant change in our operations and risk profile. +Patents +and Intangibles +Patents +represent initial legal costs incurred to apply for United States and international patents on the diagnostic testing technology, +and are amortized on a straight-line basis over their useful life of approximately 20 years. Because much of our future success +and value depends on our proprietary technology, our patent and intellectual property strategy is of critical importance. Four +of our initial U.S. patents related to our technology have been granted by the U.S. Patent and Trademark Office, or PTO, including +the patent for our CoPrimer technology, which we consider our most important patent. One of our patents has been issued in Great +Britain, but is still pending in the United States. As of March 15, 2019, we had two additional patents pending in the U.S. and +foreign counterpart applications. While we are unsure whether we can develop the technology in order to obtain the full benefits +of the issued patents, the patents themselves hold value and could be sold to companies with more resources to complete the development. +On-going legal expenses incurred for patent follow-up have been expensed from April 2013 forward. +F- 8 +Long-Lived +Assets +We +review our long-lived assets, including patents, whenever events or changes in circumstances indicate that the carrying amount +of an asset may not be recoverable. Recoverability of assets held and used is measured by a comparison of the carrying amount +of an asset to future un-discounted net cash flows expected to be generated by the asset. If such assets are considered to be +impaired, then the impairment to be recognized is measured by the amount by which the carrying amount of the assets exceeds the +estimated fair value of the assets. Fair value is determined by using cash flow analyses and other market valuations. After our +review at December 31, 2018, it was determined that no adjustment was required. +Customer +Leased Equipment +Customer +leased equipment is capitalized and depreciated using the straight-line method over the estimated useful life of the equipment, +generally from three to five years. The expense for the depreciation on this equipment is included in cost of sales. The company +typically retains ownership of this equipment. +Revenue +Recognition +We +recognize revenue when evidence exists that there is an arrangement between us and our customers, delivery of products sold or +service has occurred, the selling price to our customers is fixed and determinable with required documentation, and collectability +is reasonably assured. We recognize as deferred revenue, payments made in advance by customers for products not yet provided. +In +instances where we have entered into license agreements with a third parties to use our technology within their product offering, +we recognize any base or prepaid revenues over the term of the agreement and any per occurrence or periodic usage revenues in +the period they are earned. +Related-Party +Transactions +Parties +are considered to be related to the Company if the parties directly or indirectly, through one or more intermediaries, control, +are controlled by, or are under common control with the Company. Related parties also include principal stockholders of the Company, +its management, members of the immediate families of principal stockholders of the Company and its management and other parties +with which the Company may deal where one party controls or can significantly influence the management or operating policies of +the other to an extent that one of the transacting parties might be prevented from fully pursuing its own separate interests. +The Company discloses all material related-party transactions. All transactions shall be recorded at fair value of the goods or +services exchanged. Property purchased from a related party is recorded at the cost to the related party and any payment to or +on behalf of the related party in excess of the cost is reflected as compensation or distribution to related parties depending +on the transaction. +Recently +Issued Accounting Standards +From +time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”) that are +adopted by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued +standards, which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption. +The +Company, an emerging growth company (“EGC”), has elected to take advantage of the benefits of the extended transition +period provided for in Section 7(a)(2)(B) of the Securities Act of 1933, as amended, for complying with new or revised accounting +standards which allows the Company to defer adoption of certain accounting standards until those standards would otherwise apply +to private companies. +In +March 2017, the FASB issued Accounting Standards Update (“ASU”) No. 2017-08, Receivables – Nonrefundable Fees +and Other Costs (Subtopic 310-20). The amendments in this update shorten the amortization period for certain callable debt securities +held at a premium. Specifically, the amendments require the premium to be amortized to the earliest call date. The amendments +do not require an accounting change for securities held at a discount; the discount continues to be amortized to maturity. For +public business entities, the amendments in this update are effective for fiscal years, and interim periods within those fiscal +years, beginning after December 15, 2019, for public EGC companies like us. This update is not expected to have a significant +impact on the Company’s financial statements. +In +August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and +Cash Payments, to clarify guidance on the presentation and classification of certain cash receipts and payments in the statement +of cash flows. This update was issued with the intent of reducing diversity in practice with respect to eight types of cash flows. +This guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, +for public EGC companies like us. The update did not have a significant impact on the Company’s financial statements. +In +February 2016, the FASB issued ASU No. 2016-02 Leases (Topic 842), which requires recognition of leased assets and liabilities +on the balance sheet and disclosing key information about leasing arrangements. This update is effective for annual periods and +interim periods with those periods beginning after December 15, 2019, for public EGC companies like us. Management is currently +evaluating the impact that the updated standard will have on its consolidated financial statements and related disclosures. +F- 9 +In +May 2014, the FASB issued ASU No. 2014-09: “Revenue from Contracts with Customers (Topic 606)” which supersedes the +revenue recognition requirements in ASC Topic 605, “Revenue Recognition”, and requires entities to recognize revenue +in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to +which the entity expects to be entitled in exchange for those goods or services. Additional revenue recognition updates were also +issued in 2016 and 2017, which further clarified certain aspects of the new revenue recognition guidance. The new authoritative +guidance is effective for interim and annual periods beginning after December 15, 2018, for public EGC companies like us. The +guidance permits two methods of adoption: retrospectively to each prior reporting period presented (the full retrospective method), +or retrospectively with the cumulative effect of initially applying the guidance recognized at the date of initial application +(the modified retrospective method). The Company adopted the modified retrospective method. The update did not to have a significant +impact on the Company’s financial statements. +NOTE +2: NOTES PAYABLE +The +recorded value of our notes payable (net of $91,428 debt discount) for the years ending December 31, 2018 and 2017, were as follows: +December +31, 2018 +December +31, 2017 +Notes +payable, net of debt discount +Robert +Salna Promissory Note Payable +1,908,572 +— +Total +1,908,572 +— +Less +Current Portion +(1,908,572 ) +— +Total +Long-term +$ — +$ — +Robert +Salna Promissory Note +On +August 3, 2018, we entered into a Note Purchase Agreement with Robert Salna, an existing shareholder of the Company and prior +investor in the Company’s convertible debt securities. Pursuant to the agreement, the Company issued to Mr. Salna a Promissory +Note, dated August 3, 2018, in the principal amount of $2,000,000 (the “Note”) in exchange for a loan to the Company +of equal principal amount. +The +Note bears interest at the rate of nine percent (9.0%) per annum, payable quarterly in arrears. The maturity date of the Note +is July 31, 2019. All unpaid principal and accrued interest on the Note will become due and payable on the maturity date. The +Note is unsecured and provides for a default interest rate of eighteen percent (18.0%) per annum. The note is repayable in Canadian +dollars with a minimum of 2.6 million in Canadian dollars due at maturity, at December 31, 2018 if the note had been retired the +company would have paid the $2,000,000 principal amount. For the 12 months ended December 31, 2018, we included $71,000 in interest +expense. We incurred $153,845 in note origination costs which are being accreted of the life of the note. For the 12 months ended +December 31, 2018 we included $62,417 in interest expense for the accretion these note origination costs. +At +December 31, 2017 we had no outstanding notes payable. However, for the 12 months ended December 31 2017, we included $310,233 +of interest expense for notes outstanding prior to December 31, 2017. +NOTE +3: STOCK-BASED COMPENSATION +Stock +Incentive Plans +Under +the Co-Diagnostics, Inc. 2015 Long-term Incentive Plan (the “2015 Plan”), the board of directors may issue incentive +stock options, share equivalents such as restricted stock awards, stock bonus awards, performance shares and restricted stock +units to employees and directors and non-qualified stock options to consultants of the company. Options generally expire ten years +after being granted. Options granted vest in accordance with the vesting schedule determined by the board of directors, usually +ratably over a three-year vesting schedule upon anniversary date of the grant with the first 1/3 vesting on the grant date. Should +an employee terminate before the vesting period is completed, the unvested portion of each grant is forfeited. The Company has +used the Black-Scholes valuation model to estimate fair value of our stock-based awards, which requires various judgmental assumptions +including estimated stock price volatility, forfeiture rates, and expected life. Our computation of expected volatility is based +on market-based implied volatility. The 2015 Plan reserves an aggregate of 6,000,000 shares. The number of unissued stock options +authorized under the 2015 Plan at December 31, 2018 was 4,827,293. +F- 10 +Stock +Options +There +were 850,000 and 61,335 options granted in the years ended December 31, 2018 and 2017, respectively. The Black-Scholes valuation +model requires various judgmental assumptions including the estimated volatility, risk-free interest rate and expected option +term. In determining the expected volatility our computation is based the stock prices of 3 comparable companies and is based +on a combination of historical and market-based implied volatility. The risk-free interest rate was based on the yield curve of +a zero-coupon U.S. Treasury bond on the date the warrant was issued with a maturity equal to the expected term of the option. +The fair values for the options granted were estimated at the date of grant using the Black Scholes option-pricing model with +the following weighted average assumptions: +Year +Ended +December 31, 2018 +Year +Ended +December 31, 2017 +Risk free +interest rate +2.95 % +1.53 % +Expected life (in years) +5.5 +5.0 +Expected volatility +47.75 % +95.24 % +Expected dividend yield +0.00 % +0.00 % +Stock price +$ 2.63 +$ 3.85 +The +weighted average fair value of options granted during the years ended December 31, 2018 and 2017 was $1.24 and $1.59, respectively. +Included +in stock-based compensation for the 12 months ended December 31, 2018, the Company recognized expense of $468,240 recorded in +our general and administrative department for 850,000 options granted to nine employees. +Included +in stock-based compensation for the year ended December 31, 2017, the Company recognized expense of $122,259 recorded in our general +and administrative department (i) $97,474 for 61,335 options granted to three members of our board of directors and (ii) $24,785 +for options vesting which had been granted prior to January 1, 2017. +The +following table summarizes option activity during the years ended December 31, 2018 and December 31, 2017, respectively. +Options +Outstanding +Weighted +Average Exercise Price +Weighted +Average Fair Value +Weighted +Average +Remaining Contractual +Life (years) +Outstanding at January 1, +2017 +261,372 +$ 0.55 +$ 0.49 +8.63 +Options granted +61,335 +3.85 +1.59 +4.60 +Expired +— +— +— +— +Forfeited options +— +— +— +— +Exercised +— +— +— +— +Outstanding at December 31, 2017 +322,707 +$ 1.29 +$ 0.70 +7.05 +Options granted +850,000 +2.63 +1.24 +9.73 +Expired +— +— +— +— +Forfeited options +— +— +— +— +Exercised +— +— +— +— +Outstanding at +December 31, 2018 +1,172,707 +$ 2.23 +$ 1.09 +8.72 +Warrants +The +Company estimates the fair value of issued warrants on the date of issuance as determined using a Black-Scholes pricing model. +The Company amortizes the fair value of issued warrants using a vesting schedule based on the terms and conditions of each associated +underlying contract, as earned. The Black-Scholes valuation model requires various judgmental assumptions including the estimated +volatility, risk-free interest rate and expected warrant term. In determining the expected volatility our computation is based +the stock prices of 3 comparable companies and is based on a combination of historical and market-based implied volatility. The +risk-free interest rate was based on the yield curve of a zero-coupon U.S. Treasury bond on the date the warrant was issued with +a maturity equal to the expected term of the warrant. +F- 11 +There +were 50,000 and 595,133 warrants issued in the years December 31, 2018 and 2017, respectively. The fair values for the warrants +issued were estimated at the date of grant using the Black Scholes option-pricing model with the following weighted average assumptions: +Year +Ended +December 31, 2018 +Year +Ended +December 31, 2017 +Risk free +interest rate +2.94 % +1.89 % +Expected life (in years) +5.0 +4.7 +Expected volatility +47.95 % +46.80 % +Expected dividend yield +0.00 % +0.00 % +Stock price +$ 2.41 +$ 2.98 +The +weighted average fair value of warrants issued during the years ended December 31, 2018 and 2017 was $1.22 and $1.74 per share, +respectively. +In +the year ended December 31, 2018, the Company included $61,100 in our sales and marketing department for 50,000 warrants issued +to 1 company as part of the repurchasing of a market licensing agreement, as stock-based compensation. +Included +in stock-based compensation for the year ended December 31, 2017, the Company recognized expense of $256,199 recorded in our general +and administrative department for 297,727 warrants issued to 2 companies for services rendered. +The +following table summarizes warrant activity during the years ended December 31, 2018 and 2017, respectively. +Warrants +Outstanding +Weighted +Average Exercise Price +Weighted +Average Fair Value +Weighted +Average +Remaining Contractual +Life (years) +Outstanding at January 1, +2017 +111,129 +$ 8.25 +$ 0.11 +4.91 +Warrants issued +595,133 +2.91 +1.74 +4.28 +Expired +— +— +— +— +Forfeited warrants +— +— +— +— +Exercised +— +— +— +— +Outstanding at December 31, 2017 +706,262 +$ 3.27 +$ 1.48 +4.22 +Warrants issued +50,000 +2.00 +1.22 +5.00 +Expired +— +— +— +— +Forfeited warrants +— +— +— +— +Exercised +272,727 +0.11 +0.54 +3.39 +Outstanding at +December 31, 2018 +483,535 +$ 4.92 +$ 1.99 +3.29 +The +following table summarizes information about stock options and warrants outstanding at December 31, 2018. +Outstanding +Exercisable +Range +of +Weighted +Average +Remaining +Weighted +Average +Weighted +Average +Exercise +Prices +Number +Outstanding +Contractual +Life (years) +Exercise +Price +Number +Exercisable +Exercise +Price +$ 0.55 +261,372 +6.63 +$ 0.55 +261,372 +$ 0.55 +2.00-3.85 +986,335 +8.94 +2.66 +419,668 +2.70 +5.10-7.20 +408,535 +3.08 +5.46 +408,535 +5.46 +$ 0.55-7.20 +1,656,242 +7.13 +$ 3.02 +1,089,575 +$ 3.22 +F- 12 +Common +Stock +In +the year ended December 31, 2018, the Company issued 606,199 shares of our common stock as follows: 1) 272,727 shares for the +exercise of outstanding warrants for $30,000 in cash, 2) 84,112 shares valued at $202,090 to 4 companies for consulting services, +in our general and administrative department and, 3) 249,360 shares valued at $600,958 issued to 1 company as part of the repurchasing +of a market licensing agreement in our sales and marketing department. +In +the year ended December 31, 2017, the Company issued 399,209 shares of our common stock valued at $1,655,500 to 4 companies for +consulting services, as stock-based compensation. For the year ended December 31, 2017, the Company recognized expense of $813,229 +in our general and administrative department for to-date services rendered. +Total +unrecognized stock-based compensation was $585,311 at December 31, 2018 which the Company expects to recognize as follows: +Year +Amount +2019 +$ 351,180 +2020 +234,131 +Total +$ 585,311 +NOTE +4: LEASE OBLIGATIONS +Our +offices are located at 2401 S Foothill Dr. Suite D Salt Lake City Utah 84109-1479. The space consists of approximately 10,273 +square feet and is leased under a multi-year contract a rate of $14,086 per month expiring on January 31, 2020. For the years +December 31, 2018 and 2017, the Company expensed $166,146 and $53,132, respectively for rent. The Company’s future lease +rent obligation is as follows: +Year +Amount +2019 +$ 169,033 +2020 +14,086 +Total +$ 218,119 +NOTE +5: RELATED PARTY TRANSACTIONS +The +Company acquired the exclusive rights to the Co-Primer technology pursuant to a license agreement dated April 2014, between us +and DNA Logix, Inc., which was assigned to Dr. Satterfield prior to our acquisition of DNA Logix, Inc. Pursuant to the license +the Company was to pay Dr. Satterfield minimum royalty payments of $30,000 per month until the Company receives an equity funding +of at least $4,000,000, at which time the payments increase to $60,000 per month for the remainder of the year. The payment terms +were orally modified to maintain the monthly royalties at $30,000 per month through December 2016. On March 1, 2017, the Company +entered into an amendment effective January 1, 2017, to its Exclusive License Agreement for its Cooperative Primers (“License”) +technology with Dr. Satterfield, a member of our Board of Directors. The amendment provides in part that all accrued royalties +under the License cease as of January 1, 2017, and we began in January to pay $700,000 of accrued royalties at the rate of $10,000 +per month. For the years ended December 31, 2018 and 2017, the Company paid $100,000 and $170,000, respectively for this license +agreement. For the year ended December 31, 2017, the Company included $107,500 as an expense for this license agreement in research +and development. +The +Company financed operations partly through short term loans with related parties and through the deferral of payment to related +parties for expenses incurred. At December 31, 2018, and 2017 the Company had $480,000 and $380,000 respectively, in unpaid accrued +expenses for technology royalties payable to Dr. Satterfield +F- 13 +NOTE +6: EQUITY +2018 +For +the year ended December 31, 2018, the Company issued warrants to purchase 50,000 shares of our common stock with a weighted average +exercise price of $2.00 with an aggregate value of $61,100 to 1 company as part of the repurchasing of a market licensing agreement, +as stock-based compensation. +In +the year ended December 31, 2018, the Company issued 606,199 shares of common stock as follows: (i) 272,727 shares for the exercise +of warrants, (ii) 249,360 shares for the repurchasing of a market licensing agreement, and (iii) 84,122 shares for services rendered. +On +December 28, 2018 the Company amended it’s Articles of Incorporation to authorized two classes of stock, Common Stock and +Preferred Stock. The total number of shares which the company is authorized to issue is 105,000,000 shares, 100,000,000 shares +shall be Commons Stock, par value $.001 and 5,000,000 shares shall be Preferred Stock, par value $.001. +2017 +For +the year ended December 31, 2017, the Company issued warrants to purchase 595,133 shares of our common stock with a weighted average +exercise price of $2.91 with an aggregate value of $1,035,624 as follows: (i) 297,727 for consulting services to two companies, +(ii) 211,740 for debt conversion to six individuals and four companies, and (iii) 85,666 for agency fees related to equity funding +to four companies. +In +the year ended December 31, 2017, the Company issued 2,434,789 shares of common stock as follows: (i) 1,178,533 shares related +to the sale of equity, (ii) 857,047 shares associated with the conversion of debt, and (iii) 399,209 shares for services rendered. +NOTE +7: INCOME TAXES +Net +deferred tax assets consist of the following components as of December 31, 2018 and 2017: +2018 +2017 +Deferred +tax assets +NOL +carry-forward +$ 3,841,400 +$ 2,537,300 +Sec +179 carry-forwards +1,600 +1,600 +Depreciation +9,500 +2,500 +Valuation +allowance +(3,852,500 ) +(2,541,400 ) +Net +deferred tax asset +$ — +$ — +The +income tax provision differs from the amount of income tax determined by applying the U.S. federal income tax rate to pretax income +from continuing operations for the years ended December 31, 2018 and 2017 due to the following: +2018 +2017 +Book +loss +$ (1,630,600 ) +$ (1,809,400 ) +Depreciation +(3,000 ) +4,900 +Meals +and entertainment +400 +1,100 +Other +non-deductible expenses +356,500 +359,300 +Change +in valuation allowance +1,276,700 +1,444,100 +$ — +$ — +At +December 31, 2018, the Company had net operating loss carry-forwards of approximately $14,775,000 that may be offset against future +taxable income from the year 2019 through 2035. No tax benefit has been reported in the December 31, 2018 and 2017, consolidated +financial statements since the potential tax benefit is offset by a valuation allowance of the same amount. Additionally, DNA +Logix, Inc. is a pass-through entity and therefore no provision or liability for federal income tax has been included in the consolidated +financial statements for that entity. +F- 14 +Due +to change in ownership provisions of the Tax Reform Act of 1986, net operating loss carry-forwards for Federal income tax reporting +purposes are subject to annual limitations. Should a change in ownership occur, net operating loss carry-forwards may be limited +as to use in future years. +The +Company’s policy on the classification of interest and penalties related to income taxes is to recognize the interest and +penalties in the period incurred. There were no penalties or interest incurred for the years ending December 31, 2018 and 2017, +related to income taxes. +NOTE +8: SUBSEQUENT EVENTS +On +January 30, 2019, we entered into a securities purchase agreement with investors, whereby the investors purchased from the Company +30,000 shares of Series A Convertible Preferred Stock of the Company for a purchase price of $3,000,000. The purchase price was +paid by the investors with $1.0 million in cash and the conversion of a $2.0 million note owed by the Company to one of the investors. +The investors may not convert the Series A Preferred Stock to the extent that such conversion would result in beneficial ownership +by the investors and their affiliates of more than 4.99% of the issued and outstanding Common Stock of the Company. +On +February 4, 2019, we completed the sale of 3,925,716 shares of the Company’s common stock, par value $0.001 per share, at +a purchase price of $1.40 per share in a registered direct offering. The aggregate gross proceeds for the sale of the Common Shares +was $5,496,002 and we received net proceeds after offering costs of $4,996,322. +On +March 7, 2019, we issued 166,667 shares of our common stock to an individual who converted 2,000 shares of our Series A Preferred +Stock to common stock at a conversion price calculated by multiplying the number of preferred shares being converted by $100 and +dividing the result by $1.20. +The +Company evaluated subsequent events pursuant to ACS Topic 855 and determined that there are no additional events that need to +be reported. +F- 15 +ITEM +9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. +None. +ITEM +9A. CONTROLS AND PROCEDURES +(a) +Disclosure Controls and Procedures +We +maintain a set of disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) designed to ensure that +information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, +and reported within the time periods specified in rules and forms adopted by the SEC. +In +accordance with Rule 13a-15(b) of the Exchange Act, as of the end of the period covered by this annual report on Form 10-K, an +evaluation was carried out under the supervision and with the participation of our management, including our Chief Executive Officer +and Chief Financial Officer, to assess the effectiveness of our disclosure controls and procedures. As of the end of the period +covered by this annual report on Form 10-K our disclosure controls and procedures were not effective to provide reasonable assurance +that information required to be disclosed by us in reports that we file or submit under the Exchange Act is recorded, processed, +summarized and reported within the time periods specified in the SEC’s rules and forms and is accumulated and communicated +to our management, including the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions +regarding required disclosure. +In +performing its assessment of the effectiveness of the Company’s internal control over financial reporting, management applied +the criteria described in the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the +Treadway Commission (“COSO - 2013”). +A +material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there +is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not +be prevented or detected on a timely basis. +The material weakness +identified during management’s assessment was the lack of sufficient technical expertise on certain accounting and +tax requirements for new and unusual transactions. These control deficiencies could result in a material misstatement of +accounts or disclosures that would result in a material misstatement to the Company’s interim or annual financial statements +that would not be prevented or detected. Accordingly, management has determined that these control deficiencies constitute a material +weakness. The Company plans to hire, in the second quarter of 2019, consultants with the necessary technical accounting expertise +to improve the Company’s accounting processes and internal control program. +Because +of the material weakness, management concluded that the Company did not maintain effective internal control over financial reporting +as of December 31, 2018, based on the criteria in Internal Control-Integrated Framework issued by COSO -2013. +(b) +Management’s Report on Internal Control over Financial Reporting and Attestation Report of Registered Public Accounting +Firm +This +annual report on Form 10-K does not include a report of management’s assessment regarding internal control over financial +reporting or an attestation report of our registered public accounting firm due to a transition period established by rules of +the SEC applicable to newly public companies. +(c) +Changes in Internal Control Over Financial Reporting +There +have been no changes in the Company’s internal control over financial reporting that occurred during the Company’s +last three-month period that has materially affected, or is reasonably likely to materially affect, the Company’s internal +control over financial reporting. +ITEM +9B. OTHER INFORMATION +None. +16 +PART +III +ITEM +10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE. +The +following table sets forth the names, ages and positions of our executive officers and directors: +Name +Age +Position +Dwight +H. Egan +64 +Chief +Executive Officer, President and Chairman of the Board +Brent +Satterfield +42 +Chief +Science Officer and Director +Reed +L Benson +72 +Chief +Financial Officer and Secretary +Edward +J. Borkowski +59 +Director +Frank +J. Kiesner +74 +Director +Richard +S. Serbin +74 +Director +Dwight +H. Egan has been an officer and director since April 2013. Mr. Egan has been engaged in private investment business from February +1999 to the present. He was a senior executive at Data Broadcasting Corporation, a leading provider of wireless, real-time financial +market data, news and sophisticated fixed- income portfolio analytics to 27,000 individual and professional investors from 1995 +to 1999. He co-founded and served as CEO and Chairman of the Board of Broadcast International, Inc. from 1984 to 1995, when Data +Broadcasting Corporation acquired Broadcast International and created CBS MarketWatch , a leading financial news site and +participated in its initial public offering. Mr. Egan’s prior experience in directing a public company and working with +capital markets gives him valuable experience in advising the board on matters of finance and operations. +Brent +Satterfield has been our chief science officer and director since April 2013. Dr. Satterfield has been employed by the Company +from January 31, 2015 to the present. Prior to that he was the sole shareholder and owner of DNA Logix, Inc. from January 2013 +to January 31, 2015, and in DNA Logix he developed and patented the technology now owned by the Company. He founded Co-Diagnostics +in April 2013 and is the first in his field to use engineering mathematics to design new DNA testing technology. From 2006 to +2008, he was employed by Arcxis Biotechnologies where he developed new diagnostic platforms for groups such as the Department +of Homeland Security, the National Biodefense Analysis and Countermeasures Center, the United States Army Medical Research Institute +of Infectious Disease, Sandia National Laboratories, the California Department of Public Health and numerous others. Under fellowship +from the Department of Homeland Security, he received his Ph.D. in 2007 in Bioengineering with an emphasis in entrepreneurship +and intellectual property law from Arizona State University in a dual-enrollment program with UC Berkeley. Dr. Satterfield’s +experience with the science underlying all of the Company’s products and technology gives him valuable experience in advising +the board on the status of the products and our positioning in the diagnostic testing industry. +Reed +L Benson has been Chief Financial Officer and Secretary from November 2014 to the present and a director from November 2014 +to May 2017. Since September, 2008 to the present, in addition to the private practice of law, he is a founder and partner of +Legends Capital Group, LLC, a privately held venture capital group that identifies investment opportunities in natural resources, +bio tech and technology fields. From October 2004 to September 2008 he was employed as Chief Financial Officer, Secretary, and +General Counsel and member of Board of Directors of Broadcast International, Inc., a publicly traded communications services company. +From 2001 to October 2004, he was in the private practice of law where his practice focused on tax and business related matters. +From July 1995 to January 2001 he was secretary and general counsel for Data Broadcasting Corporation, a provider of market information +to individual investors. Mr. Benson received his J.D. degree from the University of Utah School of Law in 1976 and a Bachelor +of Science Degree in Accounting from the University of Utah in 1971. Mr. Benson became a Certified Public Accountant in 1974. +Mr. Benson’s experience in finance, accounting and business consulting, together with his role as our CFO and prior public +company directorship, provide Mr. Benson with expertise enabling critical input to our company. +Edward +Borkowski joined our Board of Directors in May 2017. He was appointed Executive Vice President April 18, 2018 and Interim +Chief Financial Officer effective June 6, 2018 of Mimedx, an advanced wound care and late stage biologics company. He served as +the Chief Financial Officer of ACETO Corporation, an international company engage in the development, marketing, sales and distribution +of pharmaceutical products from February 2018 to April 2018 and from May 2015 to April 2018 he held several executive level positions +with Concordia International Corp., an international specialty pharmaceutical company including Chief Financial Officer and Executive +Vice President. From 2013 to 2016 he served as Chief Financial Officer at Amerigen Pharmaceuticals, a pharmaceutical company focused +on generic products, and from 2012 to 2013 as Chief Financial Officer at ConvaTec, an international medical products and technologies +company. He is a member of the American Institute of Certified Public Accountants and the New York State Society of CPAs. He currently +also serves on the boards of AzurRx BioPharma (Nasdaq: AZRX) and Acacia Pharma Group, Plc (EPA: ACPH), and during the previous +five years also served on the board of WhereverTV (OTCMKTS: TVTV). Mr. Borkowski holds a Bachelor of Science in Economics and +Political Science from Allegheny College and a Master in Business Administration in Finance and Accounting from Rutgers University. +17 +Frank +J. Kiesner joined our Board of Directors in May 2017 and is the founder of several companies in the medical diagnostic field. +Mr. Kiesner is the Chairman and Chief Executive Officer of OvaGene Oncology, Inc., a molecular diagnostics company which he founded +in 2008. OvaGene Oncology, Inc. provides gene-based assays to assist physicians/gynecologic oncologists in the diagnosis, radiation +and chemotherapy, prognosis, and therapy selection of gynecologic cancers in women. Mr. Kiesner served as Chairman, President +and CEO of Oncotech Inc. for 17 years until its acquisition by Exiqon in 2008. Oncotech became the leading company in the USA +and Europe in the field of individualizing cancer treatment and drug selection. Mr. Kiesner was previously a partner at Northstar +Ventures, General Counsel and Treasurer of public-company ADC Telecommunications, and President of ADC Corporation’s Magnetic +Division. He served on multiple committees and boards for the American Laboratory Association and has extensive experience in +the regional, federal and congressional workings of health care reimbursement. Working with Congressman Bill Thomas, Chairman +of the Congress’s Ways and Means Sub-Committee on Health, Mr. Kiesner was the leading force behind the passage of the “Patients +Benefit Improvement Act Of 1999” which rewrote the new technology approval and patient- provider appellate process for the +Medicare and other federal Statutory Programs. Mr. Kiesner obtained his J.D. from the University of Minnesota School of Law. Mr. +Kiesner’s experience running diagnostic companies, especially companies in the molecular diagnostic field, will be invaluable +to the Board of Directors and our company. +Richard +S. Serbin, who joined our Board of Directors in May 2017, currently serves as a consultant to many companies in the healthcare +industry. He was the President of Corporate Development and In-House Legal Counsel at Life Science Institute, LLC, from June 1, +2013 to July 15, 2014. Mr. Serbin is a global strategy advisor, pharmacist and entrepreneur with credentials both in pharmacy +and law, complemented by more than 40 years of service as an FDA regulatory attorney and patent attorney in the healthcare industry. +He was appointed to the Advisory Board of Cure Pharmaceutical in January 2017 and has been a Member of Advisory Board at Prime +Access, Inc. since September 2015. Mr. Serbin has been a Director at Rapid Nutrition Plc since November 18, 2014. He served as +Director at Viropro Inc. from May 2013 to June 2014. He was Head of Business Advisory Board at Mazal Plant Pharmaceuticals Inc. +from October 2006 to September 2007 and also served as its Member of Business Advisory Board. He served as Chief Executive Officer +of Optigenex Inc. from July 2002 to September 15, 2005 and a director from July 2004 to September 2005. From January 1999 until +July 2002 Mr. Serbin served as a consultant to various pharmaceutical companies. He served as the President of Bradley Pharmaceuticals. +He served as Vice President of Corporate Development at Ortho Pharmaceuticals, a Johnson & Johnson subsidiary, and practiced +Patent and FDA law at Revlon Johnson & Johnson and Schering-Plough. He served as Patent Attorney for Schering Plough Corporation +and Chief FDA Counsel for Revlon Corporation and Johnson and Johnson Corporation. Subsequently, he worked at Revlon Corporation, +as its Chief Food, Drug and Cosmetic Counsel. He founded Radius Scientific Corporation. He was J&J’s Vice President +of Corporate Development, and later led a successful public offering venture based on technology developed at Stanford Medical +School. Mr. Serbin spent a large portion of his career focusing on international markets and clients. While at J&J, Mr. Serbin +served on the Board of Directors of 16 US and international subsidiary companies, including Ethicon, Ortho, J&J Consumer Products, +Pittman-Moore, Mc Neil, and J&J Development Corporation. He worked on multiple international acquisitions and strategic relationships, +and sat on the Board of Directors of several of its international subsidiaries, including those in India, Hong Kong, Japan, Taiwan, +Germany, and England. Mr. Serbin has a B.S. and a B. Pharmacy from Rutgers University and Rutgers University College of Pharmacy, +a J.D. degree from Seton Hall Law School and a Masters Degree in Trade Regulations and Law from NYU Law School. Mr. Serbin’s +experience in business, law and medicine and knowledge gained as an advisor to the healthcare industry will be critical to our +Board of Directors as it commercializes its products. +Our +directors generally serve until the next annual or special meeting of shareholders held for the purpose of electing directors. +Our officers generally serve at the discretion of the Board of Directors. Messrs. Egan and Satterfield are employees. Mr. Egan +serves as our president and chief executive officer and Mr. Satterfield serves as our Chief Science Officer. +Involvement +in Certain Legal Proceedings +To +the best of our knowledge, none of our directors or executive officers have, during the past ten years, been involved in any legal +proceedings described in subparagraph (f) of Item 401 of Regulation S-K. +Board +and Committee Matters +We +maintain an audit committee of the board, a compensation committee of the board and a corporate governance and nominating committee +of the board, each of which is discussed below. We have not established a nominating committee of the board. Our board has determined +that Messrs. Borkowski, Kiesner and Serbin are “independent” under the definition of independence in the Marketplace +Rules of the NASDAQ listing requirements. +We +do not have a formal policy concerning shareholder recommendations of candidates for board of director membership. Our board views +that such a formal policy is not necessary at the present time given the board’s willingness to consider candidates recommended +by shareholders. Shareholders may recommend candidates by writing to our Secretary at our principal offices: 2401 S. Foothill +Drive, Suite D, Salt Lake City, Utah 84109, giving the candidate’s name, contact information, biographical data and qualifications. +A written statement from the candidate consenting to be named as a candidate and, if nominated and elected, to serve as a director +should accompany any such recommendation. Shareholders who wish to nominate a director for election are generally advised to submit +a shareholder proposal no later than December 31 for the next year’s annual meeting of shareholders. +18 +Audit +Committee and Financial Expert +Our +audit committee currently is comprised of Messrs. Borkowski, Kiesner and Serbin with Mr. Borkowski serving as chairman of the +audit committee. The functions of the audit committee include engaging an independent registered public accounting firm to audit +our annual financial statements, reviewing the independence of our auditors, the financial statements and the auditors’ +report, and reviewing management’s administration of our system of internal control over financial reporting and disclosure +controls and procedures. The Board of Directors has adopted a written audit committee charter. A current copy of the audit committee +charter is available to security holders on our website at www.codiagnostics.com. Our board has determined that both of our directors +that are serving on the audit committee are “independent” under the definition of independence in the Marketplace +Rules of the NASDAQ listing standards. +Our +Board of Directors has determined that Mr. Borkowski meets the requirements of an “audit committee financial expert” +as defined in applicable SEC regulations. +Compensation +Committee +Our +compensation committee currently includes Messrs. Serbin and Borkowski with Mr. Serbin serving as chairman of the compensation +committee. The functions of the compensation committee include reviewing and approving corporate goals relevant to compensation +for executive officers, evaluating the effectiveness of our compensation practices, evaluating and approving the compensation +of our chief executive officer and other executives, recommending compensation for board members, and reviewing and making recommendations +regarding incentive compensation and other employee benefit plans. The Board of Directors has adopted a written compensation committee +charter. A current copy of the compensation committee charter is available to shareholders on our website at www.codiagnostics.com . +Our board has determined that both of our directors serving on the compensation committee are “independent” under +the definition of independence in the Marketplace Rules of the NASDAQ listing standards. +Corporate +Governance and Nominating Committee +Our +corporate governance and nominating committee currently includes Messrs. Kiesner, Borkowski and Serbin with Mr. Kiesner serving +as chairman of the corporate governance and nominating committee. The functions of the corporate governance and nominating committee +is identifying and recommending candidates to fill vacancies on the Board of Directors. Among its duties and responsibilities, +the corporate governance and nominating committee periodically evaluates and assesses the performance of the officers and directors; +reviews the qualifications of candidates for director positions; assists in identifying, interviewing and recruiting candidates +for the Board of Directors and reviews the composition of each committee of the Board of Directors. A current copy of the corporate +governance and nominating committee charter is available to shareholders on our website at www.codiagnostics.com . Our board +has determined all directors serving on the corporate governance and nominating committee are “independent” under +the definition of independence in the Marketplace Rules of the NASDAQ listing standards. +Communication +with the Board +We +have not, to date, developed a formal process for shareholder communications with the board of directors. We believe our current +informal process, in which any communication sent to the board of directors, either generally or in care of the chief executive +officer, secretary or other corporate officer or director, is forwarded to all members of the board of directors, has served the +board’s and the shareholders’ needs. +Conflicts +of Interests +On +an annual basis, each director and executive officer is obligated to complete a director and officer questionnaire that requires +disclosure of any transactions with our company, including related person transactions reportable under SEC rules, in which the +director or executive officer, or any member of his or her immediate family, have a direct or indirect material interest. Under +our company’s standards of conduct for employees, all employees, including the executive officers, are expected to avoid +conflicts of interest. Pursuant to our code of ethics for the chief executive officer and senior finance officers (as discussed +below), such officers are prohibited from engaging in any conflict of interest unless a specific exception has been granted by +the board. All of our directors are subject to general fiduciary standards to act in the best interests of our company and our +shareholders. Conflicts of interest involving an executive officer or a director are generally resolved by the board. +Compliance +with Section 16(a) of the Exchange Act +Section +16(a) of the Exchange Act requires our directors and executive officers, and persons who own more than 10% of our common stock, +to file with the SEC initial reports of ownership and reports of changes in ownership of our common stock and other equity securities. +Executive officers, directors and greater than 10% shareholders are required by SEC regulations to furnish us with copies of all +Section 16(a) forms they file. +To +our knowledge, and based on representations from our directors and executive officers, during the year ended December 31, +2018, our directors, executive officers and greater than 10% shareholders complied with all Section 16(a) filing requirements. +19 +Code +of Ethics +We +have adopted a code of ethics for our principal executive officer, principal financial officer, controller, or persons performing +similar functions. A copy of the code of ethics is included on our website at www.codiagnostics.com. +Family +Relationships +There +are no family relationships among our directors and executive officers. +ITEM +11. EXECUTIVE COMPENSATION +Throughout +this section, the individuals who served as our chief executive officer and chief financial officer during 2017 and 2018 are collectively +referred to as the “named executive officers.” +The +compensation committee has overall responsibility to review and approve our compensation structure, policy and programs and to +assess whether the compensation structure establishes appropriate incentives for management and employees. The compensation committee +annually reviews and determines the salary and any bonus and equity compensation that may be awarded to our chief executive officer, +or CEO, and our chief financial officer, or CFO. The compensation committee oversees the administration of our long-term incentive +plan and employee benefit plans. +The +compensation committee’s chairman regularly reports to the board on compensation committee actions and recommendations. +The compensation committee has authority to retain, at our expense, outside counsel, experts, compensation consultants and other +advisors as needed. +Company +Performance . Because of the stage of our company’s development, the compensation committee looks at various factors +in evaluating the progress the company has made and the services provided by the named executive officers. In considering executive +compensation, the compensation committee noted certain aspects of our financial performance and accomplishments in 2018 and 2017 +including the following: (a) Development Milestones, (b) Financial Milestones and (c) Sales and Marketing Milestones. +Compensation +Philosophy . Our general compensation philosophy is designed to link an employee’s total cash compensation with our performance, +the employee’s department goals and individual performance. Given our stage of operations and limited capital resources, +we are subject to various financial restraints in our compensation practices. As an employee’s level of responsibility increases, +there is a more significant level of variability and compensation at risk. The compensation committee believes linking incentive +compensation to our performance creates an environment in which our employees are stakeholders in our success and, thus, benefits +all shareholders. +Executive +Compensation Policy . Our executive compensation policy is designed to establish an appropriate relationship between executive +pay and our annual performance, our long-term growth objectives, individual performance of the executive officer and our ability +to attract and retain qualified executive officers. The compensation committee attempts to achieve these goals by integrating +competitive annual base salaries with bonuses based on corporate performance and on the achievement of specified performance objectives, +and to a lesser extent, awards through our long-term incentive plan. The compensation committee believes that cash compensation +in the form of salary and bonus provides our executives with short-term rewards for success in operations. The compensation committee +also believes our executive compensation policy and programs do not promote inappropriate risk-taking behavior by executive officers +that could threaten the value of our company. +In +making compensation decisions, the compensation committee compares each element of total compensation against companies referred +to as the “compensation peer group.” The compensation peer group is a group of companies that the compensation committee +selected from readily available information about small companies engaged in similar businesses and with similar resources. The +compensation committee selected these companies from research on its own and with limited consultation with outside consultants +given the size of the company and its resources to retain such experts. The types of companies selected for the peer group included +publically-traded technology development companies in the diagnostic testing industry. Since there are relatively few companies +in the rather narrow field of diagnostic testing the comparisons were limited to those that are publically traded whose financial +information could be readily accessed. The compensation committee determined these companies were appropriate for inclusion in +the peer group because of the similar nature of their businesses and their general stage of development and financial resources. +20 +Role +of Executive Officers in Compensation Decisions +The +compensation committee makes all compensation decisions for the named executive officers and approves recommendations regarding +equity awards to all of our other senior management personnel. The CEO annually reviews the performance of the CFO and other senior +management. The conclusions reached and recommendations based on these reviews, including with respect to salary adjustments and +annual award amounts, are presented to the compensation committee. The compensation committee is charged with the responsibility +of ensuring a consistent compensation plan throughout the company and providing an independent evaluation of the proposed adjustments +or awards at all levels of management. As such, the compensation committee has determined that it have the discretion to modify +or adjust any proposed awards and changes to management compensation to be able to satisfy these responsibilities. +Stock +Option Plans +Under +our 2015 Long-term Incentive Plan (the “2015 Plan”), the board of directors may issue incentive stock options to employees +and directors and non-qualified stock options to consultants of the company. Options expire ten years after being granted. Options +granted vest in accordance with the vesting schedule determined by the board of directors, usually ratably over a two-year vesting +schedule upon the anniversary date of the grant. Should an employee’s director’s or consultant’s relationship +with the company terminate before the vesting period is completed, the unvested portion of each grant is forfeited. We continue +to maintain and grant awards under the 2015 Plan which will remain in effect its expiration by its terms. The number of unissued +stock options authorized under the 2015 Plan at December 31, 2018 was 4,827,293. +The +purpose of our incentive plan is to advance the interests of our stockholders by enhancing our ability to attract, retain and +motivate persons who are expected to make important contributions to the company by providing them with both equity ownership +opportunities and performance-based incentives intended to align their interests with those of our stockholders. These plans are +designed to provide us with flexibility to select from among various equity-based compensation methods, and to be able to address +changing accounting and tax rules and corporate governance practices by optimally utilizing stock options and shares of common +stock. +Summary +Compensation Table +The +table below summarizes the total compensation paid or earned by each of the named executive officers in their respective capacities +for the fiscal years ended December 31, 2018, 2017 and 2016. When setting total compensation for each of the named executive officers, +the compensation committee reviewed tally sheets which show the executive’s current compensation, including equity and non-equity +based compensation. We have omitted in this report certain columns otherwise required to be included because there was no compensation +made with respect to such columns, as permitted by applicable SEC regulations. +Option +All +Name +and +Salary +Bonus +Awards +Other +Total +Principal +Position +Year +($) +($) +($) +Compensation +($) +Dwight +H. Egan +2018 +$ 275,000 +$ 12,500 +$ 186,000 +$ — +$ 463,500 +President & +Chief Executive Officer (1) +2017 +195,000 +15,000 +— +— +210,000 +2016 +23,750 +— +— +— +23,750 +Reed +L Benson +2018 +$ 200,000 +$ 10,000 +$ 155,000 +$ — +$ 365,000 +Chief Financial +Officer and Secretary (2) +2017 +195,000 +10,000 +— +— +205,000 +2016 +— +— +— +— +— +Brent +Satterfield +2018 +$ 237,500 +$ — +$ — +$ — +$ 237,500 +Chief Technology +Officer (3) +2017 +159,300 +— +— +— +159,300 +2016 +81,096 +— +— +— +81,096 +(1) +The +amounts shown in the salary column for 2016 reflects amounts paid by the Company to Reagents, LLC that were specifically designated +as compensation for Mr. Egan. +(2) +Mr. +Benson is a member of Legends Capital Group, LLC, which received consulting income from the Company in 2016. However, Mr. +Benson did not receive any of the funds received by Legends Capital Group from the Company. +(3) +Dr. +Satterfield also received royalties from the Company in the amount of $2,500 in 2016, $170,000 in 2017 and $100,000 in 2018 +pursuant to a technology license agreement that was amended in January 2017 to terminate the ongoing royalties and the payments +in 2017 and 2018 reduced accrued royalties. +21 +Other +Compensation +We +do not have any non-qualified deferred compensation plan. +Outstanding +Equity Awards at Fiscal Year-End +Option +Awards +Stock +Awards +Name +Number +of Securities Underlying Unexercised Options (#) Exercisable +Number +of Securities Underlying Unexercised Options (#) Unexercisable +Option +Exercise Price ($) +Option +Expiration Date +Number +of Shares or Units of Stock that have not Vested (#) +Market +Value of shares or Units of Stock that have not Vested ($) +Number +of Unearned shares, units or other rights that have not vested (#) +Market +or payout value of unearned shares, units or other rights that have not vested ($) +(a) +(b) +(c) +(d) +(e) +(f) +(g) +(h) +(i) +Dwight +H. Egan +50,000 +100,000 +2.63 +01/15/2025 +— +— +— +— +Reed +L Benson +41,667 +83,333 +2.63 +01/15/2025 +— +— +— +— +Potential +Payments Upon Termination or Change of Control +There +is no compensation payable to the named executive officers upon voluntary termination, retirement, involuntary not-for-cause termination, +termination following a change of control or in the event of disability or death of the executive. +Compensation +Committee Interlocks and Insider Participation in Compensation Decisions +None +of our executive officers served as a member of the compensation committee or as a director of any other company. +Director +Compensation +We +use a combination of cash and stock-based incentive compensation to attract and retain qualified candidates to serve on its board +of directors. In setting director compensation, we consider the significant amount of time that directors expend in fulfilling +their duties as well as the skill-level required by our members of the board. +Our +non-employee directors generally receive fees of $35,000 per year, paid quarterly, $10,000 per year for serving as chairman of +any Board committee and $5,000 for serving as a member of other Board committees. In addition, each director receives an initial +grant of stock options to purchase 20,455 shares (thereafter annual grants of 4,545 options or restricted stock units) of our +common stock with an exercise price equal to the fair market value of the stock on the date of grant. The board approved and the +non-employee directors accepted the 2018 compensation set forth in the director summary compensation table below. In addition, +non-employee directors may be entitled to receive special awards of stock options from time to time as determined by the board. +The chairman of the board and the chairman of each of the audit and compensation committees receive no additional fees for serving +in such capacities. There is no additional compensation for meeting attendance. Directors who are employees of the Company receive +no additional compensation for serving as directors. All stock options granted to outside directors are immediately exercisable +and expire ten years from the date of grant. Directors are reimbursed for ordinary expenses incurred in connection with attending +board and committee meetings. +22 +Director +Summary Compensation Table +The +table below summarizes the compensation paid or accrued by us to our directors for the fiscal year ended December 31, 2018. +(a) +(b) +(c) +(d) +(e) +Name +Fees +Earned or Paid in Cash +($) +Options/Awards +($) +Restricted +Stock Units +($) +Total +($) +Dwight H. Egan (1) +$ — +— +$ — +$ — +Dr. Brent Satterfield +(1) +— +— +— +— +Frank +Kiesner +$ 55,000 +$ — +— +$ 55,000 +Richard Serbin +55,000 +— +— +55,000 +Edward J. Borkowski +55,000 +— +— +55,000 +(1) +Messers +Egan and Satterfield receive no compensation for serving as a director, but are compensated in their capacity as Company President +and Chief Science Officer, respectively. +ITEM +12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The +following table sets forth certain information, as of March 19, 2019, with respect to the holdings of (1) each person who is the +beneficial owner of more than 5% of our Common Stock, (2) each of our directors, (3) each executive officer, and (4) all of our +current directors and executive officers as a group. +Beneficial +ownership of the common stock is determined in accordance with the rules of the Securities and Exchange Commission and includes +any shares of common stock over which a person exercises sole or shared voting or investment power, or of which a person has a +right to acquire ownership at any time within 60 days of the date of this Annual Report. Except as otherwise indicated, we believe +that the persons named in this table have sole voting and investment power with respect to all shares of common stock held by +them. Applicable percentage ownership in the following table is based on 17,015,766 shares of common stock plus, for each individual, +any securities that individual has the right to acquire within 60 days of March 19, 2019. +To +the best of our knowledge, except as otherwise indicated, each of the persons named in the table has sole voting and investment +power with respect to the shares of our common stock beneficially owned by such person, except to the extent such power may be +shared with a spouse. To our knowledge, none of the shares listed below are held under a voting trust or similar agreement, except +as noted. To our knowledge, there is no arrangement, including any pledge by any person of securities of the Company, the operation +of which may at a subsequent date result in a change in control of the Company. +Name +and Address of Beneficial Owner Officers and Directors +Title +Beneficially +Percent +of Class +Dwight +H. Egan (1)(2) +Chief +Executive Officer, President and Chairman +50,000 +* +Reed +L. Benson (1)(3) +Chief +Financial Officer and Secretary +41,667 +* +Dr. +Brent Satterfield (1)(7) +Chief +Science Officer and Director +1,359,794 +8 % +Edward +J. Borkowski +Director +20,455 +* +Frank +J. Kiesner +Director +20,455 +* +Richard +S. Serbin +Director +20,455 +* +Officers +and Directors as a Group (total of 6 persons)(4) +1,512,826 +9 % +5% +Stockholders +Legends +Capital Group, LLC (5) +1,266,784 +7 % +Reagents, +LLC (6) +1,746,796 +10 % +* +less than 1% +(1) +The +address is 2401 S. Foothill Drive, Suite D, Salt Lake City, Utah 84109. +(2) +Includes +presently exercisable options to acquire 50,000 shares of common stock. +(3) +Includes +presently exercisable options to acquire 41,667 shares of common stock. +(4) +Includes +presently exercisable options to acquire a total of 153,032 shares of common stock held by all directors and executive officers. +(5) +Legends +Capital Group, LLC, with an address of 782 E Foothill Drive, Draper, Utah 84020, is beneficially owned by Jason Briggs, who +has voting power of the stock. Reed Benson, an officer of the Company, owns an 11% equity interest in Legends Capital Group, +LLC. +(6) +Reagents, +LLC, with an address of 8160 S. Highland Drive, Salt Lake City, UT 84093, is beneficially owned by Seth Egan. +(7) +The +shares owned by Dr. Satterfield are subject to pending litigation regarding a loan and pledge agreement with lenders. +23 +ITEM +13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +The +Company acquired the exclusive rights to the CoPrimer technology pursuant to a license agreement dated April 2014, between us +and DNA Logix, Inc., which was assigned to Dr. Satterfield prior to our acquisition of DNA Logix, Inc. Pursuant to the license +the Company was to pay Dr. Satterfield minimum royalty payments of $30,000 per month until the Company receives an equity funding +of at least $4,000,000, at which time the payments increase to $60,000 per month for the remainder of the year. The payment terms +were orally modified to maintain the monthly royalties at $30,000 per month through December 2016. On March 1, 2017, the Company +entered into an amendment effective January 1, 2017, to its Exclusive License Agreement for its CoPrimer (“License”) +technology with Dr. Satterfield, a member of our Board of Directors. The amendment provides in part that all royalties under the +License cease as of January 1, 2017, and we began in January 2017 to pay $700,000 of accrued royalties at the rate of $10,000 +per month. For the year ending December 31, 2017, the Company included $107,500 as an expense for this license agreement in research +and development. In 2017 and 2018, we paid Dr. Satterfield $170,000 and $100,000, respectively, in payment of the accrued royalties. +We +paid consulting fees to a company who is also a significant shareholder. The shareholder was paid a total of $75,000 in 2017 for +expenses accrued in 2016. +ITEM +14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +Fees +for professional services provided by our current independent auditors for each of the last two fiscal years, in each of the following +categories, are as follows: +2018 +2017 +Audit +fees +$ 67,650 +$ 96,531 +Audit-related fees +— +— +Tax fees +2,913 +— +All +other fees +— +— +Total +$ 70,563 +$ 96,531 +Audit +fees included fees associated with the annual audit and reviews of our annual and quarterly reports for 2018 and our annual report +for 2107. In addition, the fees for 2017 included fees associated with our registration statement under the Securities Act of +1933, as amended, filed with the SEC. All audit fees incurred during 2018 were pre-approved by the audit committee. All audit +fees incurred during 2017 were pre-approved by our Board of Directors. +Tax +fees included fees associated with tax compliance and tax consultations. All tax fees incurred during 2018 were pre-approved by +the audit committee. All tax fees incurred during 2017 were pre-approved by our Board of Directors. +The +audit committee has adopted a policy that requires advance approval of all services performed by the independent auditor when +fees are expected to exceed $15,000. The audit committee has delegated to the audit committee chairman, Mr. Borkowski, authority +to approve services, subject to ratification by the audit committee at its next committee meeting. +24 +PART +IV +Item +15. Exhibits, Financial Statement Schedules. +Exhibit +Number +Description +1.1 +Underwriting Agreement (5) +3.1 +Articles of Incorporation (1) +3.1.1 +Amendment to the Articles of Incorporation (1) +3.2 +Bylaws (1) +5.1 +Legal Opinion of Carmel, Milazzo & DiChiara LLP (6) +10.1 +Subscription Agreement between Co-Diagnostics, Inc. and CoDiagnostics, Ltd., dated April 30, 2013 (1) +10.1.1 +Amendment to Subscription Agreement between Co-Diagnostics, Inc. and CoDiagnostics, Ltd., dated May 1, 2015 (1) +10.2 +Exclusive Agreement between Co-Diagnostics, Inc. and DNA Logix, Inc., dated April 18, 2014 (1) +10.3 +Stock Exchange Agreement among Co-Diagnostics, Inc., DNA Logix, Inc., and the Shareholders of DNA Logix, Inc., dated January 22, 2015 (1) +10.4 +Revolving Line of Credit Promissory Note between Co-Diagnostics, Inc. and Co-Diagnostics, LTD, dated August 1, 2015 (1) +10.5 +10% Convertible Note between Co-Diagnostics, Inc. and Robert Salna for $200,000, dated September 1, 2016 (1) +10.6 +Exclusive License Agreement between Co-Diagnostics, Inc. and Watermark Group Inc., dated October 13, 2016 (1) +10.7 +Securities Purchase Agreement with Exhibits between Co-Diagnostics and Senior Holders, dated December 12, 2016 (1) +10.7.1 +Form of Amendment Agreement (6) +10.7.2 +Form of Second Amendment Agreement +10.8 +Securities Purchase Agreement with Exhibits between Co-Diagnostics and Beaufort Capital Partners, LLC, dated December 12, 2016 (1) +10.9 +2015 Long-Term Incentive Plan (2) +10.10 +Subscription Agreement between Co-Diagnostics and Co-Diagnostics, Ltd. for 454,545 shares of Co-Diagnostic’s common stock, dated April 20, 2013 (3) +10.11 +Subscription Agreement between Co-Diagnostics and Prosperity Investments for $100,000, dated June 2014. (3) +10.12 +12% Convertible Note between Co-Diagnostics, Inc. and Beaufort Capital Partners, LLC for $500,000, dated May 15, 2015 (3) +10.13 +Form Revolving Line of Credit Promissory Note between Co-Diagnostics and Turks and Caicos Limited Company, Pine Valley Investments, LLC, Clavo Rico Incorporated, Legends Capital Group, LLC, Hamilton Mining Resources, Inc., and Machan 1988 Property Trust. (3) +10.13.1 +Amendment to 12% Revolving Line of Credit Promissory Note, dated August 1, 2015, between Co-Diagnostics and Co-Diagnostics, Ltd., for $750,000, dated September 14, 2016. (3) +25 +10.13.2 +Amendment to 12% Revolving Line of Credit Promissory Note, December 30, 2015, between Co-Diagnostics and Pine Valley Investments, LLC for $100,000, dated September 14, 2016. (3) +10.13.3 +Amendment to 12% Revolving Line of Credit Promissory Note, February 22, 2016, between Co-Diagnostics and Clavo Rico Incorporated for $10,000, dated September 14, 2016. (3) +10.13.4 +Amendment to 12% Revolving Line of Credit Promissory Note, March 1, 2016, between Co-Diagnostics and Legends Capital Group, LLC for $100,000, dated September 14, 2016. (3) +10.13.5 +Amendment to 12% Revolving Line of Credit Promissory Note, May 15, 2016, between Co-Diagnostics and Hamilton Mining Resources, Inc. for $75,000, dated September 14, 2016. (3) +10.13.6 +Amendment to 12% Revolving Line of Credit Promissory Note, May 30, 2016, between Co-Diagnostics and Machan 1988 Property Trust for $50,000, dated September 14, 2016. (3) +10.13.7 +Form Second Amendment to 12% Revolving Line of Credit Promissory Note Due 2017 between Co-Diagnostics, Inc. and CoDiagnostics, Ltd., Pine Valley Investments, LLC, Clavo Rico Incorporated, Legends Capital Group, LLC, and Hamilton Mining Resources, Inc. (4) +10.13.8 +Form of Indemnification Agreement. (4) +10.14 +Form 8.5% Convertible Note between Co-Diagnostics and Legends Capital Group, LLC for $100,000, dated November 12, 2015 and R. Phillip Zobrist for $100,000, dated December 1, 2015. (3) +10.15 +Form 10% Convertible Note between Co-Diagnostics and Legends Capital Opportunity Fund, LLC for $15,000, DAV Capital Management Corp. for $15,000, April Kameka for $40,000, and Mark Kovacic for $50,000. (3) +10.16 +Shareholders’ Agreement between Co-Diagnostics and Synbiotics Limited, dated January 27, 2017. (3) +10.17 +Amended Exclusive License Agreement between Co-Diagnostics, Brent Satterfield, and DNA Logix, Inc., dated January 1, 2017. (3) +10.18 +Stock Purchase Agreement between Co-Diagnostics and Ted Murphy for 1,800,000 shares of Watermark Group, Inc.’s common stock, dated September 22, 2016. (3) +10.19 +Non-Interest Bearing Note between Co-Diagnostics and Zika Diagnostics, Inc. f/k/a/ Watermark Group, Inc. for $445,000, dated March 20, 2017. (3) +10.20 +Mutual Rescission Agreement of the Stock Purchase Agreement, dated September 22, 2016, and the License Agreement, dated October 13, 2016, between Co-Diagnostics, Robert Salna, and Ted Murphy, dated March 30, 2017. (3) +14.1 +Code of Ethics of the Company +21.1 +Subsidiaries of Registrant (1) +23.1 +Consent of Haynie & Company +23.2 +Consent of Carmel, Milazzo & DiChiara LLP (see Exhibit 5.1) +31.1 +Certification of Chief Executive Officer pursuant to section 302 of the Sarbanes-Oxley Act of 2002 +31.2 +Certification of Principal Financial Officer pursuant to section 302 of the Sarbanes-Oxley Act of 2002 +32.1 +Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 +32.2 +Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 +* +Management +contract or compensatory plan or arrangement. +(1) +Incorporated +by reference to the Draft Registration Statement filed with the SEC on January 11, 2017. +(2) +Incorporated +by reference to the Draft Registration Statement filed with the SEC on March 27, 2017. +(3) +Incorporated +by reference to the Form S-1 filed with the SEC on April 28, 2017. +(4) +Incorporated +by reference to the Form S-1/A filed with the SEC on May 24, 2017. +(5) +Incorporated +by reference to the Form S-1/A filed with the SEC on June 9, 2017. +(6) +Incorporated +by reference to the Form S-1/A filed with the SEC on June 23, 2017. +26 +SIGNATURES +Pursuant +to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf +by the undersigned thereunto duly authorized. +CO-DIAGNOSTICS, +INC. +Date: +March 29, 2019 +By: +/s/ +Dwight Egan +Dwight +Egan +Chief +Executive Officer, President and Director +(Principal +Executive Officer and Interim Principal Financial and Accounting Officer) +By: +/s/ +Reed L. Benson +Reed +L. Benson +Chief +Financial Officer and Secretary +(Principal +Financial and Accounting Officer +In +accordance with the Exchange Act, this report has been signed below by the following persons on March 29, 2019, on behalf +of the registrant and in the capacities Indicated. +Signature +Title +/s/ +Dwight Egan +Chief +Executive Officer, President and Director +Dwight +Egan +/s/ +Reed L. Benson +Chief +Financial Officer and Secretary +Reed +L. Benson +/s/ +Brent Satterfield +Director +Brent +Satterfield +/s/ +Edward J. Borkowski +Director +Edward +J. Borkowski +/s/ +Frank J.Kiesner +Director +Frank +J. Kiesner +/s/ +Richard S. Serbin +Director +Richard +S. Serbin +27 \ No newline at end of file diff --git a/raw/filings/0001692415/2018/0001493152-19-004300/filing_metadata.csv b/raw/filings/0001692415/2018/0001493152-19-004300/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..27364274a4203cfcf301065b72393244963fe047 --- /dev/null +++ b/raw/filings/0001692415/2018/0001493152-19-004300/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001692415,CODX,"Co-Diagnostics, Inc.",10-K,2019-04-01,2018-12-31,2019-03-30T02:22:05.000Z,0001493152-19-004300,form10-k.htm,,5351262,1,0,https://www.sec.gov/Archives/edgar/data/1692415/000149315219004300/form10-k.htm,https://www.sec.gov/Archives/edgar/data/1692415/000149315219004300/,2018,2018,1 diff --git a/raw/filings/0001692415/2018/0001493152-19-004300/item1.txt b/raw/filings/0001692415/2018/0001493152-19-004300/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001692415/2018/0001493152-19-004300/item13.txt b/raw/filings/0001692415/2018/0001493152-19-004300/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001692415/2018/0001493152-19-004300/item9a.txt b/raw/filings/0001692415/2018/0001493152-19-004300/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001692415/2018/0001493152-19-004300/rp_note.txt b/raw/filings/0001692415/2018/0001493152-19-004300/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..13ebcebc0d60fe3c4c64c971c3b6e5efe60b49c7 --- /dev/null +++ b/raw/filings/0001692415/2018/0001493152-19-004300/rp_note.txt @@ -0,0 +1,19 @@ +5: RELATED PARTY TRANSACTIONS +The +Company acquired the exclusive rights to the Co-Primer technology pursuant to a license agreement dated April 2014, between us +and DNA Logix, Inc., which was assigned to Dr. Satterfield prior to our acquisition of DNA Logix, Inc. Pursuant to the license +the Company was to pay Dr. Satterfield minimum royalty payments of $30,000 per month until the Company receives an equity funding +of at least $4,000,000, at which time the payments increase to $60,000 per month for the remainder of the year. The payment terms +were orally modified to maintain the monthly royalties at $30,000 per month through December 2016. On March 1, 2017, the Company +entered into an amendment effective January 1, 2017, to its Exclusive License Agreement for its Cooperative Primers (“License”) +technology with Dr. Satterfield, a member of our Board of Directors. The amendment provides in part that all accrued royalties +under the License cease as of January 1, 2017, and we began in January to pay $700,000 of accrued royalties at the rate of $10,000 +per month. For the years ended December 31, 2018 and 2017, the Company paid $100,000 and $170,000, respectively for this license +agreement. For the year ended December 31, 2017, the Company included $107,500 as an expense for this license agreement in research +and development. +The +Company financed operations partly through short term loans with related parties and through the deferral of payment to related +parties for expenses incurred. At December 31, 2018, and 2017 the Company had $480,000 and $380,000 respectively, in unpaid accrued +expenses for technology royalties payable to Dr. Satterfield +F- 13 +NOTE \ No newline at end of file diff --git a/raw/filings/0001692415/2018/0001493152-19-004300/rpt_disclosure.txt b/raw/filings/0001692415/2018/0001493152-19-004300/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001692415/2020/0001493152-21-006810/filing.txt b/raw/filings/0001692415/2020/0001493152-21-006810/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..9a6c0180818f6a3dd899884f9f92a6a7216d1ead --- /dev/null +++ b/raw/filings/0001692415/2020/0001493152-21-006810/filing.txt @@ -0,0 +1,3696 @@ +10-K +1 +form10k.htm +UNITED +STATES +SECURITIES +AND EXCHANGE COMMISSION +Washington, +D.C. 20549. +Form +10-K +(Mark +One) +[X] +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For +the fiscal year ended December 31, 2020 +OR +[ ] +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For +the transition period from_______to_______ +Commission +File Number 001-38148 +CO-DIAGNOSTICS, INC. +(Exact Name of Registrant as Specified in Its Charter) +Utah +3841 +46-2609396 +(State +or other jurisdiction of +incorporation or organization) +(Primary +Standard Industrial +Classification Code Number) +(I.R.S. +Employer +Identification Number) +2401 +S. Foothill Drive, Salt Lake City, Utah 84109 +(Address +of principal executive offices and zip code) +(801) +438-1036 +(Registrant’s +telephone number including area code) +Securities +registered pursuant to Section 12(b) of the Act: +Title +of each class +Trading +Symbol(s) +Name +of each exchange on which registered +Common +Stock +CODX +Nasdaq-CM +Securities registered pursuant to Section +12(g) of the Act: None +Indicate +by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [ ] +No [X] +Indicate +by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes [ ] +No [X] +Indicate +by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act +of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and +(2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ] +Indicate +by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive +Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the +preceding 12 months (or such shorter period that the registrant was required to submit and post such files). Yes [X] No [ ] +Indicate +by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not +contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements +incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] +Indicate +by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller +reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller +reporting company” in Rule 12b-2 of the Exchange Act. +Large +accelerated filer +[ ] +Accelerated +filer +[ ] +Non-accelerated +filer +[ ] +Smaller +reporting company +[X] +Emerging +growth company +[X] +If +an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for +complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. [ ] +Indicate +by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness +of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered +public accounting firm that prepared or issued its audit report. [ ] +Indicate +by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes [ ] No [X] +The +aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at +which the common stock was last sold as of the last business day of the registrant’s most recently completed second fiscal +quarter was approximately $485,000,000. +As +of March 24, 2021, there were 28,665,714 shares of common stock, par value $0.001 per share, outstanding. +Table +of Contents +Page +PART I +Item +1. +Business. +4 +Item +1A. +Risk Factors. +12 +Item +1B. +Unresolved Staff Comments. +16 +Item +2. +Properties. +16 +Item +3. +Legal Proceedings. +16 +Item +4. +Mine Safety Disclosures. +17 +PART II +Item +5. +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. +17 +Item +6. +Selected Financial Data. +18 +Item +7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations. +18 +Item +7A. +Quantitative and Qualitative Disclosures About Market Risk. +22 +Item +8. +Financial Statements and Supplementary Data. +23 +Item +9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +41 +Item +9A. +Controls and Procedures. +41 +Item +9B. +Other Information. +42 +PART III +Item +10. +Directors, Executive Officers and Corporate Governance. +42 +Item +11. +Executive Compensation. +47 +Item +12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. +51 +Item +13. +Certain Relationships and Related Transactions, and Director Independence. +52 +Item +14. +Principal Accountant Fees and Services. +52 +PART IV +Item +15. +Exhibits and Financial Statement Schedules. +53 +2 +PART +I +Forward-Looking +Statements +This +Annual Report on Form 10-K contains “forward-looking statements” that involve risks and uncertainties. All statements +other than statements of historical fact contained in this Annual Report and the documents incorporated by reference herein, including +statements regarding future events, our future financial performance, business strategy, and plans and objectives of management +for future operations, are forward-looking statements. We have attempted to identify forward-looking statements by terminology +including “anticipates,” “believes,” “can,” “continue,” “could,” “estimates,” +“expects,” “intends,” “may,” “plans,” “potential,” “predicts,” +“should,” or “will” or the negative of these terms or other comparable terminology. Although we do not +make forward looking statements unless we believe we have a reasonable basis for doing so, we cannot guarantee their accuracy. +These statements are only predictions and involve known and unknown risks, uncertainties and other factors and the documents incorporated +by reference herein, which may affect our or our industry’s actual results, levels of activity, performance or achievements +expressed or implied by these forward-looking statements. Moreover, we operate in a highly regulated, very competitive, and rapidly +changing environment. New risks emerge from time to time and it is not possible for us to predict all risk factors, nor can we +address the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause our +actual results to differ materially from those contained in any forward-looking statements. +We +have based these forward-looking statements largely on our current expectations and projections about future events and financial +trends that we believe may affect our financial condition, results of operations, business strategy, short term and long-term +business operations, and financial needs. These forward-looking statements are subject to certain risks and uncertainties that +could cause our actual results to differ materially from those reflected in the forward-looking statements. Factors that could +cause or contribute to such differences include, but are not limited to, those discussed in this Annual Report, and in particular, +the risks discussed below and under the heading “Risk Factors” in other documents we file with the SEC. The following +discussion should be read in conjunction with the consolidated financial statements for the fiscal years ended December 31, 2020 +and 2019 and notes incorporated by reference therein. We undertake no obligation to revise or publicly release the results of +any revision to these forward-looking statements, except as required by law. In light of these risks, uncertainties and assumptions, +the forward-looking events and circumstances discussed in this Annual Report may not occur and actual results could differ materially +and adversely from those anticipated or implied in the forward-looking statement. +You +should not place undue reliance on any forward-looking statement, each of which applies only as of the date of this Annual Report. +Except as required by law, we undertake no obligation to update or revise publicly any of the forward-looking statements after +the date of this Annual Report to conform our statements to actual results or changed expectations. +You +are advised, however, to consult any further disclosures we make on related subjects in our reports on Forms 10-Q, 8-K and 10-K +filed with the SEC. You should understand that it is not possible to predict or identify all risk factors. Consequently, you should +not consider this list to be a complete set of all potential risks or uncertainties. +Important +factors that could cause actual results to differ materially from those in the forward-looking statements include, without limitation: +● +the +results of clinical trials and the regulatory approval process; +● +market +acceptance of any products that may be approved for commercialization; +● +our +ability to protect our intellectual property rights; +● +the +impact of any infringement actions or other litigation brought against us; +● +competition +from other providers and products; +● +our +ability to develop and commercialize new and improved products and services; +● +changes +in government regulation; +● +and +other factors (including the risks contained in the section entitled “Risk Factors” in other documents we file +with the SEC) relating to our industry, our operations and results of operations. +Should +one or more of these risks or uncertainties materialize, or should the underlying assumptions prove incorrect, actual results +may differ significantly from those anticipated, believed, estimated, expected, intended or planned. +Factors +or events that could cause our actual results to differ may emerge from time to time, and it is not possible for us to predict +all of them. We cannot guarantee future results, levels of activity, performance or achievements. Except as required by applicable +law, including the securities laws of the United States, we do not intend to update any of the forward-looking statements to conform +these statements to actual results. +As +used in this Annual Report, the terms “we”, “us”, “our”, and “Co-Diagnostics” +means Co-Diagnostics, Inc., a Utah corporation and its consolidated subsidiaries (the “Company”), unless otherwise +indicated. +3 +ITEM +1: BUSINESS +Overview +Co-Diagnostics, +Inc., a Utah corporation (the “Company” or “CDI”), is developing robust and innovative molecular tools +for detection of infectious diseases, liquid biopsy for cancer screening, and agricultural applications. We develop, manufacture +and sell reagents used for diagnostic tests that function via the detection and/or analysis of nucleic acid molecules (DNA or +RNA). In connection with the sale of our tests we may sell diagnostic equipment from other manufacturers as self-contained lab +systems (which we refer to as the “MDx Device”). +Our +diagnostics systems enable very rapid, low-cost, molecular testing for organisms and genetic diseases by automating historically +complex procedures in both the development and administration of tests. CDI’s technical advance involves a novel approach +to Polymerase Chain Reaction (“PCR”) test design of primer and probe structure (“CoPrimers”) that eliminates +one of the key vexing issues of PCR amplification, the exponential growth of primer-dimer pairs (false positives and false negatives) +which adversely interferes with identification of the target DNA/RNA. +We +believe our proprietary molecular diagnostics technology is paving the way for innovation in disease detection and life sciences +research through our enhanced detection of genetic material. Because we own our platform, we believe we will be able to accomplish +this faster and more economically, allowing for significant margins while still positioning the Company to be a low-cost provider +of molecular diagnostics and screening services. +In +addition, continued development has demonstrated the unique properties of our CoPrimer technology that make it ideally suited +for a variety of applications where specificity is key to optimal results, including multiplexing several targets, enhanced Single +Nucleotide Polymorphism (“SNP”) detection and enrichment for next gen sequencing. +Our +scientists use the complex mathematics of DNA/RNA test design, to engineer and optimize a DNA/RNA test and to automate algorithms +that rapidly screen millions of possible options to pinpoint the optimum design. Dr. Satterfield, our founder, developed the Company’s +intellectual property consisting of the predictive mathematical algorithms and proprietary reagents used in the testing process, +which together represent a major advance in PCR testing systems. CDI technologies are now protected by eight granted or pending +US and foreign patents, as well as certain trade secrets and copyrights. Ownership of our proprietary platform permits us the +advantage of avoiding payment of patent royalties required by other PCR test systems, which enables the sale of diagnostic tests +at a lower price than competitors, while enabling us to maintain profit margins. +We +may either sell or lease the MDx Device to labs and diagnostic centers, through sale or lease agreements, and sell the reagents +that comprise our proprietary tests to those laboratories and testing facilities. +We +design our tests by identifying the optimal locations on the target gene for amplification and pair the location with the optimized +primer and probe structure to achieve outputs that meet the design input requirements identified from market research. This is +done by following planned and documented processes, procedures and testing. In other words, the data resulting from our tests +verify that we succeeded in designing what we intended at the outset. Verification is a series of testing that concludes that +the product is ready to proceed to validation in an evaluation either in our lab or in an independent laboratory setting using +initial production tests to confirm that the product as designed meets the user needs. +Using +our proprietary test design system and proprietary reagents, we have designed and obtained regulatory approval in the European +Community and in India to sell PCR diagnostic tests for COVID-19, tuberculosis, hepatitis B and C, human papilloma virus, malaria, +chikungunya, dengue, and the zika virus. In the United States, CDI has obtained Emergency Use Authorization (“EUA”) +for its COVID-19 test from the FDA and sells that test to qualified labs. In addition, our LogixSmart COVID-19 test has been approved +for sale in Australia and Mexico by the regulatory bodies in those countries and has been registered for sale in many more countries. +4 +In +addition to testing for infectious disease, the technology lends itself to identifying any section of a DNA or RNA strand that +describe any type of genetic trait, which creates a number of significant applications. We, in conjunction with our customers, +are active in designing and licensing tests that identify genetic traits in plant and animal genomes. We also have three multiplexed +tests developed to test mosquitos for the identification of diseases carried by the mosquitos to enable municipalities to concentrate +their efforts in spraying mosquito populations on the specific areas known to be breeding the mosquitos that carry deadly viruses. +On +January 23, 2020, we announced the completion of the principal design work for a PCR screening test for the new coronavirus, COVID-19, +intended to address the potential need for detection of the virus. An outbreak of respiratory illness caused by the pneumonia-like +COVID-19 has spread rapidly throughout the world since first being discovered in the Chinese city of Wuhan on December 31, 2019. +China confirmed human-to-human transmission of the virus and the United States announced the first infection in this country, +detected in a traveler returning from Wuhan. Our COVID-19 test features the Company’s patented CoPrimer™ technology, +and was designed using our proprietary software system, following the guidelines published by the World Health Organization (WHO) +and Centers for Disease Control (CDC). +On +February 20, 2020, we announced that our Logix Smart™ COVID-19 Test technical file had been submitted for registration with +the European Union, and that it was expected to be available late February as an in vitro diagnostic (“IVD”) for markets +that accept a CE marking as valid regulatory approval. Subsequently, on February 24, 2020, we announced that our test obtained +regulatory clearance to be sold as an IVD for the diagnosis of COVID-19 in markets that accept CE-marking as valid regulatory +approval, and became available for purchase from the Company’s Utah-based ISO-13485:2016 certified facility. The Declaration +of Conformity for the Logix Smart COVID-19 test confirms that it meets the Essential Requirements of the European Community’s +In-Vitro Diagnostic Medical Device Directive (IVDD 98/79/EC), permitting export and sales of the product as an IVD in the European +Community. We shipped samples of the Research Use Only version of our test to distributors in various countries, which allowed +future customers to confirm the quality and sensitivity of the product, and for us to accelerate the sales efforts of the COVID-19 +test. +We +commenced sales of the COVID-19 tests in February and March of 2020 to international customers and have since sold approximately +10,000,000 tests in numerous countries around the world through an expanding distributor network. +On +April 6, 2020, we announced that we had received an Emergency Use Authorization from the FDA allowing us to commence sales of +our Logix Smart COVID-19 test to laboratories certified by the Center for Medicare and Medicaid Services under the Clinical Laboratories +Improvements Act (“CLIA”) to accept human samples for diagnostics testing throughout the United States and have sold +our Logix Smart COVID-19 test to such CLIA labs since that time. +Recent +Developments +Because +we believe that testing for the COVID-19 virus is going to be a consideration for public health worldwide even after the current +pandemic has subsided, we have initiated a project to facilitate frequent testing in schools, businesses, and the hospitality +industry. We believe this may be accomplished through the development of a low cost, easy to use by non-professionals, testing +device that can provide PCR quality test results in less than an hour. This project is possible due to the facts that in 2020 +we were able to successfully lyophilize our Logix Smart Covid-19 test reagents and additionally developed a saliva-based collection +system that does not require the RNA/DNA extraction. While the final result is the same as if done through a lab-based IVD process, +it has the advantages of increased speed and ease of handling thanks to lyophilization. We have engaged the services of a group +of professionals who have the expertise to develop the hardware for such a device using our CoPrimers as the reagent chemistry. +The device will be available to homes, offices, event facilities, and the travel industry at a cost that will allow screening +frequently to prevent spread of the COVID-19 virus in the future. The device would also be available to test for other pathogens +detectable through saliva samples as we develop those tests and offer them to the marketplace. +5 +Infectious +Disease Product Offering +Using +our proprietary test design system and proprietary reagents, we design and sell PCR diagnostic tests for diseases and pathogens +such as COVID-19, tuberculosis, hepatitis B and C, malaria, dengue, human papilloma virus, chikungunya, and Zika virus, all of +which tests have been designed and verified in our laboratory. Our tuberculosis test and Zika test received a CE Mark in 2018, +and a triplex test for Zika, dengue and chikungunya received a CE Mark in 2019, qualifying the tests to be sold throughout the +European community and in most countries in central and South America. In December, 2019, our Indian joint venture received a +license to manufacture and sell tuberculosis, hepatitis B, hepatitis C, human papilloma virus 16/18 and malaria tests in India +from the Central Drugs Standard Control Organization (“CDSCO”). In February 2020, we received a CE Mark for our Logix +Smart COVID-19 test and in April 2020, our COVID-19 test was approved for manufacture and sale in India by the CDSCO and in Mexico +by the INDRE, Mexico’s equivalent to the United States Center for Disease Control. In August 2020, we received approval +from the Australian Department of Health Therapeutic Goods Division to sell our COVID-19 test in Australia. +As +explained above, the development of our Logix Smart COVID-19 test was designed, developed, submitted for regulatory approval and +ready to be used both as a Research Use Only (“RUO”) and as an IVD in countries that accept a CE Mark as approval +for use of the test in a period of just over thirty days. This is a real-world example of how in an evolving epidemic that the +CDI technology can be used to get diagnostics tools in the hands of medical professionals without delay. It can be similarly used +to design a test for mutations of the virus should they occur and not be detectable using currently available tests. +Caribbean +and Central and South America +Our +initial sales were to entities located in South and Central America. In some of those countries, there are limited regulatory +hurdles so we started offering our tests immediately. We have applied for registration of our tests in those countries that require +registration and our distributors in those countries have provided us with in country assistance in completing such registrations. +We +first offered our Zika test in this region because of the demand for such test, followed quickly by tests for tuberculosis, our +triplex test for Zika, chikungunya, and dengue, hepatitis B and C, and dengue. Sales of those tests have not been material, but +with the granting of a CE mark for our Logix Smart COVID-19, we began significant sales in this region. Products are manufactured +for sale upon receipt of purchase orders from distributors, labs and hospitals. +India +In +January 2017, the Company entered into an agreement to manufacture diagnostics tests for seven infectious diseases with a pharmaceutical +manufacturing company in India and formed an Indian joint venture organized as CoSara Diagnostics, Pvt (“CoSara”). +The agreement provided for the construction of a manufacturing plant and the manufacture of the tests named above and the joint +sales and marketing of those tests in India. We have received a license for the plant in Ranoli, India to manufacture approved +tests and has been used for testing and manufacturing for the Indian market. +As +mentioned above, the CDSCO has given us the approval for manufacture and sale of the nine tests referred above and the Company +has begun manufacture and sale of those tests. The Company has commenced a reagent rental program in India with thermocyclers +purchased from third-party vendors and which we refer to as our MDx Device. Each of the reagent rental placements requires the +purchase of a minimum number of tests per month. The placement of thermocyclers in India has facilitated the sale of the SaraGene +COVID-19 tests in India, which has made CoSara profitable in 2020. The World Health Organization (“WHO”) 2019 Global +Tuberculosis Report indicates that India is the country with the highest number of cases of tuberculosis in the world. +WHO tuberculosis statistics for India for 2018 give an estimated incidence figure of 2.69 million cases of tuberculosis for India +out of a global incidence of approximately 10.0 million. The tuberculosis incidence for India is the number of new cases of active +tuberculosis disease in India during a certain time period (usually a year). We believe that we will be able to sell our tuberculosis +test in India through our sales distribution network that we are building currently. +On +March 19, 2020, we announced that CoSara received authorization to begin manufacture and sale of COVID-19 tests in India. Those +tests in India are branded as SaraGene COVID-19 tests and are sold exclusively by CoSara. Because any commercial activity in India +was severely restricted until May 2020, CoSara was not able to commence the manufacturing and sale of the SaraGene COVID-19 tests +until late in the second quarter, but sales efforts have resulted in CoSara being profitable since the commencement of sales of +the COVID-19 tests. The Indian government places restrictions on the price that could be charged for COVID-19 tests which has +limited the sales in India more than we have experienced in other parts of the world. +6 +Europe +Molecular +diagnostics, such as our tests, are governed in Europe by the framework for in vitro diagnostics (IVDs), which encompasses diagnostic +products such as reagents, instruments and systems intended for use in diagnosis of disease. The regulatory system for IVDs is +built largely on a self-certification procedure, placing heavy responsibility on manufacturers. Non self-certified products are +subject to the same standards as self-certified products but are subject to audit and review by a notified body prior to receiving +approval to be CE-marked. A CE-marking is a manufacturer’s declaration that a product meets the requirements of the applicable +European Commission directive. Examples of current obligations include having in place a qualitative manufacturing process, user +instructions that are clear and fit for purpose, ensuring that the ‘physical’ features of devices and diagnostics +do not pose any danger. If a product fulfils these and other related control requirements, it may be CE-marked as an indication +that the product is compliant with EU legislation and sold in the European Union. We have received CE Marks for six of our tests +including COVID-19, COVID-19 (2 gene test), ABC (a triplex test for Flu A, Flu B and COVID-19), tuberculosis, Zika, and our Zika, +dengue, chikungunya triplex tests. +We +have received ISO 13485 and ISO 9001 certifications relating to the design and manufacture of our medical device products. The +ISO certification indicates that we meet the standards required to self-certify certain of our products and affix a CE-marking +for sales of our products in countries accepting the CE marking (not in the United States) with only minimal further governmental +approvals and registrations in most countries. +United +States +The +U.S. Food and Drug Administration (FDA) has granted permission for us to export all of our IVD products. The FDA’s permission +to export was granted under Section 801(e) of the Federal Food, Drug, and Cosmetic Act, as amended (the “FDC Act”). +Section 801(e) of the FDA Act covers certain medical devices that have not yet received an approved Premarket Approval in the +United States by the FDA, such as our products. We have not commenced any Premarket Approval steps with the FDA. Section 801(e) +of the FDA Act applies to medical devices that are acceptable to the importing country and that are manufactured under the FDA’s +Good Manufacturing Practices. We have received EUA for our COVID-19 test, which allows sales to qualified labs in the United States. +Under +our EUA, we are actively selling our LogixSmart COVID-19 test to CLIA certified laboratories in the United States and the CLIA +labs are able to use our test as it is or further qualify our LogixSmart test as a Laboratory Developed Test (LDT), a diagnostic +test that has been validated for use in the CLIA lab. These tests may be used by the lab only in that laboratory. CLIA laboratories +develop the performance characteristics, perform the analytical validation for their LDT’s and obtain licenses to offer +them as diagnostic services. The FDA has publicly announced its intention to regulate certain LDTs in a phased-in approach, but +draft guidance that was published a couple of years ago was withdrawn at the end of the Obama administration and replaced by an +informal non-enforceable discussion paper reflecting some of the feedback that it received on LDT regulation. We are currently +marketing our Logix Smart COVID-19 test to CLIA laboratories throughout the US. +Market +Opportunity +The +market opportunity for our tests changed radically with the emergence of the COVID-19 pandemic. Because we were able to respond +rapidly and produce a quality product, we have been able to build a distribution network +that extends to more than 80 countries with over 50 active distributors, most of which have been the sales network that has allowed +us to export products throughout the world. Approximately 40% of our sales in 2020 came through sales by our distribution +network. We believe that after the pandemic is brought under control, the network of distributors that we have built in these +extra-ordinary times will serve us well in sales of other diagnostic tests. +The +molecular diagnostics market is a fast-growing portion of the in vitro (test tube-based, controlled environment) diagnostics market. +There are several advantages of molecular tests, such as the ones we market and sell, over other forms of diagnostic testing. +These advantages include higher specificity and sensitivity, the ability to perform multiplex tests and the ability to test for +drug resistance or for individual genes. +7 +Mosquito +Vector Control Services +In +response to market demand, we introduced our first diagnostics tests to be used exclusively to test for mosquito borne pathogens +in June 2019. Municipalities in the US and many other countries in the world are concerned about the diseases carried by mosquitos +and which infect the human population. To prevent outbreaks of potentially harmful viruses, such as Zika or West Nile, from infecting +the public the municipalities conduct spraying operations to eliminate the mosquito populations carrying the diseases. Because +it is too expensive and potentially harmful to the environment to spray all mosquito breeding areas, the solution is to identify +which particular area has mosquitos that are carrying the harmful viruses. To know where the host mosquitos with the harmful viruses +are located, traps are set, mosquitos collected and then tested to find the areas that most needed spraying. There are over 3,000 +mosquito abatement districts throughout the United States and almost all of them conduct testing to help make the spraying more +effective. +Our +first vector related test was a triplex test that tests for West Nile, western equine and St. Louis encephalitis. We began shipping +the tests in June 2019. We added a second test that tests mosquitos for Zika, chikungunya and dengue in a triplex test. Finally, +in November 2019, we completed a test for West Nile, eastern equine and St. Louis encephalitis, specifically for use in the eastern +United States. As a result, mosquito abatement districts can test for three target viruses in one test as compared to performing +three different tests using other market available tests, which saves our customers money. Additionally, the districts are more +effective because they can get test results in a matter of hours using our product instead of weeks when they have to wait for +a central lab to process the mosquito tests. +We +have sold our Vector Smart test products and/or related lab equipment to testing districts in different sections of the country +and are marketing our products through trade shows, electronic and regular mail solicitations and have hired additional sales +personnel in the eastern US to more economically and efficiently market to the east coast areas. +Competitive +Advantages of Co-Diagnostics +We +believe that we have the following competitive advantages: +● +Affordability: +Lower-cost test kits and low-cost MDx-device. +● +Flexibility: +CDI’s tests have been designed to run on many vendors’ DNA/RNA diagnostic testing machines. These tests +are particularly well suited to the new generation of “lab-on-a-chip” and “point-of-care” (“LOC +and POC”), highly portable analysis machinery for field, clinic and office applications. +● +Speed : +We believe our rapid assay design system software provides shorter time to product release. This has been demonstrated +with the conception, design, product manufacture, clinical verification and submission for a CE Mark for our Logix Smart coronavirus +disease (COVID-19) test being approximately 30 days. +● +Accuracy : +We believe our tests are more sensitive and specific than competitors’ and can detect more strains of viruses. +● +Exclusivity : +We own all patents and all intellectual property used in preparation of our tests. +● +Personalized +Medicine : We project that rising health care costs in developed and developing nations will increasingly require that +health care systems be patient specific to eliminate waste, misdiagnoses, and ineffectiveness. A critical component will be +accurate, more affordable DNA-based diagnostics, which we plan to offer. +● +Low-cost +Provider : We plan to keep our overhead low. Our platform technology obviates the need to pay patent royalties typically +required of our competitors, which use patented test platforms to design their tests. +8 +● +Worldwide +Footprint : With a dynamic technology that encompasses markets worldwide, we anticipate that we can identify the best +target markets, not only in high burden developing countries (HBDC’s) but also in developed nations. +● +Growth +Industry Category : We believe that DNA testing is the fastest-growing segment of in-vitro diagnostic testing. +● +Combination +Product Offering : Our ultra-sensitive tests can be a well-designed match for a new generation of handheld and other +small point-of-care (POC) devices now entering the market. Used together, these affordable tests and devices may revolutionize +the molecular diagnostics industry in cost, speed of test results and simplification. +● +Multi-plexing: +Our existing multiplexed tests demonstrate that our CoPrimer designed tests are able to test for multiple targets +in the same sample without the distortion caused by false negatives and false positives that generally occur in multiplexed +tests. +Liquid +Biopsy for Cancer Screening +The +development of liquid biopsy tests is expected to spur low-cost testing in many countries. We believe that our liquid biopsy cancer +screening may be ready for testing in the foreseeable future. Medical applications of our SNP detection technology can determine +the presence of cancer cells or cell-free genetic material in a liquid or tissue biopsy, and to determine the distinct type of +cancer involved. A real-life example of this includes being able to identify specific mutation(s) in genes linked to breast cancer +in order to determine a patient’s prognosis, initiate the most effective and affordable treatment and to determine whether +chemotherapy is necessary. After diagnosis the relative cost of our technology would allow for frequent testing to measure the +effectiveness of the treatment and thus could be a companion diagnostic for a range of treatments. +Our +technology has for all practical purposes essentially eliminated, primer-dimers, which opens up some very unique applications +for liquid biopsy for cancer detection. Our ability to multiplex the reaction in testing for several DNA targets allows technicians +to detect multiple cancers as free-circulating DNA fragments or whole cells in a blood sample at the same time +Agricultural +Applications +SNP +detection is also used in the agricultural industry to identify variations in crop genomes to achieve improved seed viability +and other desired characteristics, including drought resistance, disease resistance, pest resistance and higher yield. +In +mid-2017, the Company was first approached by a large agribusiness to evaluate our ability to multiplex certain target genomes. +The results of the development project have successfully demonstrated our ability to not only multiplex the target genomes, but +targeted SNP’s as well. The project was undertaken in conjunction with the manufacturer of our CoPrimer tests. The results +of the project encouraged the parent of our manufacturer to seek a world-wide licensing arrangement for our CoPrimers in the agricultural +industry, which was completed in October 2018. Pursuant to the exclusive license for the agronomics industry, the licensee pays +us a royalty for all CoPrimers sold to the licensee’s customers. In January 2019, the licensee formally introduced the product +at a large agricultural conference and has branded the product under the name “BHQ CoPrimers”. +Additional +Licensing and Assay Development +In +addition, the unique properties of our CoPrimer technology make them ideally suited to a variety of applications where sensitivity +is key to optimal results, including multiplexing several targets, enhanced SNP detection and enrichment for next generation sequencing. +Our licensee for our agricultural testing requested an expansion of our license agreement to include test design services for +their customers and potential customers, both in the infectious disease arena as well as for agricultural customers. The license +was amended in July 2019 and we expect to derive a license fee from our licensee for its design services. If any of its customers +desire to commercialize the tests designed, they will need to seek a commercial license directly from us. Because of these unique +characteristics of CoPrimers, research companies and institutions have requested that we design diagnostics to locate and identify +uncommon gene sequences and SNPs and create tests for the target sequences in a multiplexed reaction. This application of our +technology is in its beginning stages, but we believe that the results from our initial research indicate a significant step forward +in defining the capabilities of our technology, which we believe can be translated to revenue producing licensing arrangements. +9 +Intellectual +Property +Because +much of our future success and value depends on our proprietary technology, our patent and intellectual property strategy is of +critical importance. Five of our initial U.S. patents related to our technology have been granted by the U.S. Patent and Trademark +Office (PTO), including the patent for our CoPrimer technology, which we consider our most important patent. One of our patents +has been issued in Great Britain, but is still pending in the United States. As of March 2021, we had two additional patents pending +in the U.S. and foreign counterpart applications. Two of our issued US patents expire in 2034, one in 2036 and one in 2038. +We +have identified additional applications of the technology, which represent potential patents that further define specific applications +of the processes that are covered by the original patents. We intend to continue building our intellectual property portfolio +as development continues and resources are available. +We +have copyrighted our development software that is used by us to develop diagnostic tests based on our technology. We have allowed +one potential customer access to our development software and intend to sell customized reagents through that customer to labs +serviced by that customer throughout the world. To date we have not sold any products to that customer. +Major +Customers +We +had certain customers which were each responsible for generating 10% or more of our total revenue for the year ended December +31, 2020. Two customers together accounted for approximately 38% of total revenue for the year ended December 31, 2020. These +customers may not account for the same percentage of sales in future periods. If +we were to sell nothing to those customers in the future, it would have a material adverse effect on our financial condition unless +we were able to replace those customers with others. +Competition +The +molecular diagnostics industry is extremely competitive. There are many firms that provide some or all of the products we provide +and provide many diagnostic tests that we have yet to develop. Many of these competitors are larger than us and have significantly +greater financial resources. Because we are not established, many of our competitors have a competitive advantage in the diagnostic +testing industry because they also have other lines of business in the pharmaceutical industry from which they derive revenues +and for which they are well known and respected in the medical profession. We will need to overcome the disadvantage of being +a start up with no history of success and no significant respect from the medical and testing professionals, although this is +changing as we continue to market our LogixSmart COVID-19 tests and other tests in the United States to well-known and successful +laboratories. In the diagnostic testing industry, we compete with such companies as BioMerieux, Siemens, Qiagen, and Cepheid and +with such pharmaceutical companies as Abbott Laboratories, Becton Dickinson and Johnson and Johnson. +Many +of these competitors already have an established customer base with industry standard technology, which we must overcome to be +successful. +Competition +is, and will likely continue to be, particularly intense in the market for COVID-19 diagnostic tests. Numerous companies in the +United States and internationally have announced their intention to offer new products, services and technologies that could be +used in substitution for our LogixSmart COVID-19 tests. Many of those competitors are significantly larger, and have substantially +greater financial, engineering and other resources, than our company. Existing and potential competitors in the market for COVID-19 +diagnostic tests include developers of both serological and molecular tests. We also compete with companies from Asia in certain +markets who are willing to sell their tests for much less than we sell our tests, which creates price pressure on us to reduce +the price of tests to compete. +10 +We +expect competition to continue to increase as other established and emerging companies enter the market, as customer requirements +evolve, and as new products, services and technologies are introduced. The entrance of new competitors is being encouraged by +governmental authorities, who are offering funding to support development of testing solutions for COVID-19. Some of our existing +or new competitors may have strong relationships with current and potential customers, including governmental authorities, and, +as a result, may be able to respond more quickly to new or changing regulatory requirements, new or emerging technologies, and +changes in customer requirements. +Government +Regulation +In +the United States, we are regulated by the FDA and our products must be approved by the FDA before we will be allowed to sell +our tests in the United States. However, the FDA granted us an EUA to manufacture and sell our Logix Smart COVID-19 test to CLIA +labs in the United States. Because our lab is ISO certified, we are allowed to apply for CE-Marking, which will allow us to sell +any CE Marked test in most countries in Europe, South America and Asia. We currently have CE Marks issued for our Logix Smart +COVID-19 test, tuberculosis test, our Zika virus test, a triplex test that tests for Zika, dengue, and chikungunya simultaneously +and a triplex test that distinguishes between Flu A, Flu B and Covid-19. In addition, our Logix Smart COVID-19 has received the +license to manufacture and sell in India from India’s CDSCO and the National Epidemiology Institute in Mexico evaluated +our Logix Smart COVID-19 test and approved it for sale in Mexico. We have also received approval to sell in Australia. We are +in the process of registering for sale our Logix Smart COVID-19 test in a number of major countries around the world. +Employees +As +of December 31, 2020, we had 37 full-time employees at our executive offices and lab facilities in Salt Lake City, Utah, and two +employees outside of Utah. We have engaged independent contractors in India to promote the use of our products and develop outlets +for products and employ the services of independent sales representatives on an “as needed” basis. +Organizational +History and Corporate Information +We +were incorporated as Co-Diagnostics, Inc., in Utah on April 18, 2013. Our principal executive office is located 2401 S. Foothill +Drive, Salt Lake City, Utah 84109. Our telephone number is (801) 438-1036. Our web address is www.codiagnostics.com . The +contents of our website are not incorporated by reference in this Annual Report. +Implications +of Being an Emerging Growth Company +We +are an “emerging growth company,” as defined in the Jumpstart Our Business Startups Act of 2012. We will remain an +emerging growth company until the earlier of (i) the last day of the fiscal year following the fifth anniversary of July 12, 2017, +the date of the first sale of our common stock pursuant to an effective registration statement under the Securities Act of 1933, +as amended (the “Securities Act”); (ii) the last day of the fiscal year in which we have total annual gross revenues +of $1 billion or more; (iii) the date on which we have issued more than $1 billion in nonconvertible debt during the previous +three years; or (iv) the date on which we are deemed to be a large accelerated filer under applicable SEC rules. We expect that +we will remain an emerging growth company for the foreseeable future, but cannot retain our emerging growth company status indefinitely. +We refer to the Jumpstart Our Business Startups Act of 2012 herein as the “JOBS Act”. For so long as we remain an +emerging growth company, we are permitted and intend to rely on exemptions from specified disclosure requirements that are applicable +to other public companies that are not emerging growth companies. These exemptions include: +● +being +permitted to provide only two years of audited financial statements, in addition to any required unaudited interim financial +statements, with correspondingly reduced “Management’s Discussion and Analysis of Financial Condition and Results +of Operations” disclosure; +● +not +being required to comply with the requirement of auditor attestation of our internal controls over financial reporting; +11 +● +not +being required to comply with any requirement that may be adopted by the Public Company Accounting Oversight Board regarding +mandatory audit firm rotation or a supplement to the auditor’s report providing additional information about the audit +and the financial statements; +● +reduced +disclosure obligations regarding executive compensation; and +● +not +being required to hold a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute +payments not previously approved. +For +as long as we continue to be an emerging growth company, we expect that we will take advantage of the reduced disclosure obligations +available to us as a result of that classification. Accordingly, the information contained herein may be different than the information +you receive from other public companies in which you hold stock. +An +emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities +Act for complying with new or revised accounting standards. This allows an emerging growth company to delay the adoption of certain +accounting standards until those standards would otherwise apply to private companies. We have irrevocably elected to avail ourselves +of this extended transition period and, as a result, we will not be required to adopt new or revised accounting standards on the +dates on which adoption of such standards is required for other public reporting companies. +We +are also a “smaller reporting company” as defined in Rule 12b-2 of the Securities Exchange Act of 1934, as amended, +or the Exchange Act, and have elected to take advantage of certain of the scaled disclosure available for smaller reporting companies. +ITEM +1A. RISK FACTORS +Risks +Related to Our Business and Industry +We +have a limited commercial history upon which to base our prospects and until this year, we have not generated profits and are +not certain that we will sustain profitability in the future. +We +began operations in April 2013, and we have a limited operating history. While we were profitable for the year ended December +31, 2020, we realized a net loss for the years ended December 31, 2019 and December 31, 2018 of $6.2 million and $6.3 million, +respectively. Our accumulated retained earnings were $20.5 million as of December 31, 2020 and we had accumulated deficits of +$25.0 million and $18.7 million as of December 31, 2019 and December 31, 2018, respectively. We realized net income for the first +time for the three months ended June 30, 2020. We were able to achieve net income because we were able to develop and market our +LogixSmart COVID-19 test, but we do not have any way to predict how long our market for that test will continue. Potential investors +should be aware of the difficulties normally encountered by a new enterprise, many of which are beyond our control, including +substantial risks and expenses in the course of developing new diagnostic tests, establishing or entering new markets, organizing +operations and marketing procedures. The likelihood of our success must be considered in light of these risks, expenses, complications +and delays, and the competitive environment in which we operate. There is, therefore, nothing at this time upon which to base +an assumption that our business plan will continue to prove successful, and we may not be able to generate significant revenue, +raise additional capital or operate profitably. We will continue to encounter risks and difficulties frequently experienced by +early commercial stage companies, including scaling up our infrastructure and headcount, and may encounter unforeseen expenses, +difficulties or delays in connection with our growth. In addition, as a result of the start-up nature of our business, we can +be expected to continue to sustain substantial operating expenses and may not be able to continue generating sufficient revenues +to cover expenditures. Any investment in our company is therefore highly speculative and could result in the loss of any investment. +Our +near-term success has been dependent on the market for our COVID-19 test and future success is dependent on continued demand for +the COVID-19 test and upon our ability to develop and market other commercially accepted diagnostic tests. +12 +Our +future success will depend, in part, on the continued market for our LogixSmart COVID-19 test and upon our ability to develop +and sell sufficient quantities of other diagnostics tests. Attracting new customers and distribution networks requires substantial +time and expense. Any failure to continue sales of our tests in sufficient quantities to maintain profitability would adversely +affect our operating results. Many factors could affect the market acceptance and commercial success of any of our diagnostic +tests, including: +● +Our +ability to develop additional infectious disease diagnostic tests for which there is a commercial market. +● +our +ability to convince our potential customers of the advantages and economic value of our tests over competing technologies +and diagnostic tests; +● +the +breadth of our test menu relative to competitors; +● +changes +to policies, procedures or currently accepted best practices in clinical diagnostic testing; +● +the +extent and success of our marketing and sales efforts; and +● +our +ability to manufacture in quantity our commercial diagnostic tests and meet demand in a timely fashion. +General +Risk Factors +The +price of our common stock may fluctuate substantially. +The +market price of our common stock may be subject to wide fluctuation in response to various factors, some of which are beyond our +control. Some factors that may cause the market price of our common stock to fluctuate, in addition to the other risks mentioned +in this “Risk Factors” section and elsewhere in this report, are: +● +sales +of our common stock by our shareholders, executives, and directors; +● +our +ability to enter new markets; +● +actual +or un-anticipated fluctuations in our annual and quarterly financial results; +● +our +ability to obtain financings to continue and expand our commercial activities, expand our manufacturing operations, conduct +research and development activities including, but not limited to, human clinical trials, and other business activities; +● +our +ability to secure resources and the necessary personnel to continue and expand our commercial activities, develop additional +diagnostic tests, conduct clinical trials and gain approval for our diagnostic tests on our desired schedule; +● +commencement, +enrollment or results of our clinical trials of our diagnostic tests or any future clinical trials we may conduct; +● +changes +in the development status of our diagnostic tests; +● +any +delays or adverse developments or perceived adverse developments with respect to review by the FDA or other similar foreign +regulatory authorities of our planned clinical trials; +● +any +delay in our submission for studies or test approvals or adverse regulatory decisions, including failure to receive regulatory +approval for our diagnostic tests; +● +our +announcements or our competitors’ announcements regarding new tests, enhancements, significant contracts, acquisitions +or strategic investments; +● +failures +to meet external expectations or management guidance; +● +changes +in our capital structure or dividend policy, including as a result of future issuances of securities and sales of large blocks +of common stock by our shareholders; +● +announcements +and events surrounding financing efforts, including debt and equity securities; +● +competition +from existing technologies and diagnostic tests or new technologies and diagnostic tests that may emerge; +● +announcements +of acquisitions, partnerships, collaborations, joint ventures, new diagnostic tests, capital commitments, or other events +by us or our competitors; +● +changes +in general economic, political and market conditions in any of the regions in which we conduct our business; +● +changes +in industry conditions or perceptions; +● +changes +in valuations of similar companies or groups of companies; +● +analyst +research reports, recommendations and changes in recommendations, price targets and withdrawals of coverage; +● +departures +and additions of key personnel; +13 +● +disputes +and litigations related to intellectual properties, proprietary rights, and contractual obligations; +● +changes +in applicable laws, rules, regulations, or accounting practices and other dynamics; +● +actions +taken by our principal shareholders and release or expiry of lockup or other transfer restrictions; and +● +other +events or factors, many of which may be out of our control. +In +addition, if the market for stocks in our industry or industries related to our industry, or the stock market in general, experiences +a loss of investor confidence, the trading price of our common stock could decline for reasons unrelated to our business, financial +condition and results of operations. If any of the foregoing occurs, it could cause our stock price to fall and may expose us +to lawsuits that, even if unsuccessful, could be costly to defend and a distraction to management. +Future +sales of our common stock in the public market may cause our stock price to decline and impair our ability to raise future capital +through the sale of our equity securities. +There +are a substantial number of shares of our common stock held by shareholders who owned shares of our capital stock prior to our +initial public offering that may be able to sell in the public market. Sales by such shareholders of a substantial number of shares +could significantly reduce the market price of our common stock. +Shares +issued by us upon exercise of options granted under our equity plan will be eligible for sale in the public market. If any of +these holders cause a large number of securities to be sold in the public market, the sales could reduce the trading price of +our common stock. These sales also could impede our ability to raise capital in the future. +Anti-takeover +provisions in our charter documents and Utah law could discourage delay or prevent a change of control of our Company and may +affect the trading price of our common stock. +We +are a Utah corporation and the anti-takeover provisions of the Utah Control Shares Acquisition Act may discourage, delay or prevent +a change of control by limiting the voting rights of control shares acquired in a control share acquisition. In addition, our +Articles of Incorporation and Bylaws may discourage, delay or prevent a change in our management or control over us that shareholders +may consider favorable. Among other things, our Amended and Restated Articles of Incorporation and Bylaws: +● +authorize +the issuance of “blank check” preferred stock that could be issued by our board of directors in response to a +takeover attempt; +● +provide +that vacancies on our board of directors, including newly created directorships, may be filled only by a majority vote of +directors then in office, except a vacancy occurring by reason of the removal of a director without cause shall be filled +by vote of the shareholders; and +● +limit +who may call special meetings of shareholders. +These +provisions could have the effect of delaying or preventing a change of control, whether or not it is desired by, or beneficial +to, our shareholders. +NASDAQ +may delist our common stock from its exchange, which could limit investors’ ability to make transactions in our common stock +and subject us to additional trading restrictions. +Should +we fail to satisfy the continued listing requirements of the NASDAQ Capital Market, such as the corporate governance requirements +or the minimum closing bid price requirement, NASDAQ may take steps to delist our common stock. Such a delisting would likely +have a negative effect on the price of our common stock, and would impair your ability to sell or purchase our common stock when +you wish to do so. In the event of a delisting, we would take actions to restore our compliance with the NASDAQ Capital Market’s +listing requirements, but we can provide no assurance that any such action taken by us would allow our common stock to become +listed again, stabilize the market price or improve the liquidity of our common stock, prevent our common stock from dropping +below the NASDAQ Capital Market’s minimum bid price requirement or prevent future non-compliance with the NASDAQ Capital +Market’s listing requirements. +14 +If +the NASDAQ Capital Market does not maintain the listing of our securities for trading on its exchange, we could face significant +material adverse consequences, including: +● +a +limited availability of market quotations for our securities; +● +reduced +liquidity with respect to our securities; +● +a +determination that our shares of common stock are “penny stock” which will require brokers trading in our shares +of common stock to adhere to more stringent rules, possibly resulting in a reduced level of trading activity in the secondary +trading market for our shares of common stock; +● +a +limited amount of news and analyst coverage for our company; and +● +decreased +ability to issue additional securities or obtain additional financing in the future. +Therefore, +it may be difficult for our shareholders to sell any shares if they desire or need to sell them. +We +do not currently intend to pay dividends on our common stock. +We +do not expect to pay cash dividends on our common stock. Any future dividend payments are within the absolute discretion of our +board of directors and will depend on, among other things, our results of operations, working capital requirements, capital expenditure +requirements, financial condition, contractual restrictions, business opportunities, anticipated cash needs, provisions of applicable +law and other factors that our board of directors may deem relevant. We may not generate sufficient cash from operations in the +future to pay dividends on our common stock. +We +are an “emerging growth company” and will be able to avail ourselves of reduced disclosure requirements applicable +to emerging growth companies, which could make our common stock less attractive to investors. +We +are an “emerging growth company,” as defined in the Jumpstart Our Business Startups Act of 2012, or the JOBS Act, +and we intend to take advantage of certain exemptions from various reporting requirements that are applicable to other public +companies that are not “emerging growth companies” including not being required to comply with the auditor attestation +requirements of Section 404(b) of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in our +periodic reports and proxy statements, and exemptions from the requirements of holding a nonbinding advisory vote on executive +compensation and shareholder approval of any golden parachute payments not previously approved. Investors may find our common +stock less attractive because we may rely on these exemptions. If some investors find our common stock less attractive as a result, +there may be a less active trading market for our common stock and our stock price may be more volatile. We may take advantage +of these reporting exemptions until we are no longer an “emerging growth company.” We will remain an “emerging +growth company” until the earliest of (i) the last day of the fiscal year in which we have total annual gross revenues of +$1.0 billion or more; (ii) the last day of our fiscal year following the fifth anniversary of the date of the completion of our +initial public offering; (iii) the date on which we have issued more than $1.0 billion in nonconvertible debt during the previous +three years; or (iv) the date on which we are deemed to be a large accelerated filer under the rules of the Securities and Exchange +Commission. +We +have elected to use the extended transition periods for complying with new or revised accounting standards. +We +have elected to use the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new +or revised accounting standards that have different effective dates for public and private companies until the earlier of the +date we (i) are no longer an emerging growth company or (ii) affirmatively and irrevocably opt out of the extended transaction +period provided in Section 7(a)(2)(B). As a result, our financial statements may not be comparable to those of companies that +comply with public company effective dates. +15 +Our +management is required to devote substantial time to compliance initiatives. +As +a public company, we incur significant legal, accounting and other expenses that we did not incur as a newly formed entity. The +Sarbanes-Oxley Act, as well as rules subsequently implemented by the Securities and Exchange Commission, and NASDAQ, have imposed +various new requirements on public companies, including requiring establishment and maintenance of effective disclosure and financial +controls and changes in corporate governance practices. Our management and other personnel devote a substantial amount of time +to these new compliance initiatives. Moreover, these rules and regulations increase our legal and financial compliance costs and +make some activities more time consuming and costly. We expect these rules and regulations to make it more difficult and more +expensive for us to obtain director and officer liability insurance and we may be required to incur substantial costs to maintain +the same or similar coverage. +ITEM +1B. UNRESOLVED STAFF COMMENTS +None. +ITEM +2. PROPERTIES +Our +headquarters are located at 2401 S. Foothill Drive, Salt Lake City, Utah. Our current facility has approximately 14,000 square +feet of lab and office space under a lease that expires in February 2024. We have no other properties. We believe the facility +we lease is sufficient to meet our needs for the immediate future. +ITEM +3. LEGAL PROCEEDINGS +In +July 2020, we were served in an action filed in the United States District Court for the District of Utah claiming that the Company +promulgated false and misleading press releases to increase the price of our stock to improperly benefit the officers and directors +of the Company. The Plaintiff, Gelt Trading, Ltd., a Cayman Islands limited company, demands compensatory damages sustained as +a result of our alleged wrongdoing in an amount to be proven at trial. We will vigorously defend this action as we do not believe +it has any merit. +In +July 2020, we were served in an action filed in the United States District Court for the District of Utah claiming that the Company +promulgated false and misleading press releases to increase the price of our stock to improperly benefit the officers and directors +of the Company. The Plaintiff, Fernando Hernandez demands compensatory damages sustained as a result of our alleged wrongdoing +in an amount to be proven at trial. We will vigorously defend this action as we do not believe it has any merit. +In +September 2020, we were served in an action filed in the United States District Court for the District of Utah claiming that the +officers and the directors harmed the Company by promulgating false and misleading press releases to increase the price of our +stock to improperly benefit the officers and directors of the Company. The Plaintiff, Luis Aguliera, on behalf of Co-Diagnostics, +Inc. seeks damages from the individual defendants and attorneys’ fees. We will vigorously defend this as we do not believe +it has any merit. +In +December 2020, we were served in an action filed in the United States District Court for the District of Utah claiming that the +officers and the directors harmed the Company by promulgating false and misleading press releases to increase the price of our +stock to improperly benefit the officers and directors of the Company. The Plaintiff, Melvyn Klein, on behalf of Co-Diagnostics, +Inc. seeks damages from the individual defendants and attorneys’ fees. We will vigorously defend this as we do not believe +it has any merit. +In +December 2020, we were served in an action filed in the United States District Court for the District of Utah claiming that the +officers and the directors harmed the Company by promulgating false and misleading press releases to increase the price of our +stock to improperly benefit the officers and directors of the Company. The Plaintiff, Mathew Wallace, on behalf of Co-Diagnostics, +Inc. seeks damages from the individual defendants and attorneys’ fees. We will vigorously defend this as we do not believe +it has any merit. +From +time to time, we may become involved in litigation relating to claims arising out of our operations in the normal course of business. +Although we have received inquiries from FINRA, NASDAQ and the SEC, to which we have responded, to the best of our knowledge, +no governmental authority is contemplating any proceeding to which we are a party or to which any of our properties or businesses +are subject, which would reasonably be likely to have a material adverse effect on the Company. +16 +ITEM +4. MINE SAFETY DISCLOSURES +Not +applicable. +PART +II +ITEM +5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER EQUITY SECURITIES +Market +Information +Our +common stock has been quoted on the NASDAQ market under the symbol “CODX” since July 12, 2017. The following table +sets forth the high and low prices for our common stock for the periods indicated, as reported by NASDAQ. +Calendar Quarter Ended: +High +Low +March 31, 2020 +$ 21.75 +$ 0.88 +June 30, 2020 +$ 29.72 +$ 6.81 +September 30, 2020 +$ 30.99 +$ 8.07 +December 31, 2020 +$ 16.96 +$ 9.01 +Calendar Quarter Ended: +High +Low +March 31, 2019 +$ 3.77 +$ 0.90 +June 30, 2019 +$ 1.20 +$ 0.69 +September 30, 2019 +$ 2.00 +$ 0.79 +December 31, 2019 +$ 1.20 +$ 0.85 +Holders +As +of March 18, 2021, the last reported sales price reported on NASDAQ for our common stock was $13.69 per share. As of March 18, +2021, we had approximately 150 record holders of our common stock. The number of record holders was determined from the records +of our transfer agent and does not include beneficial owners of common stock whose shares are held in the names of various security +brokers, dealers, and registered clearing agencies. The transfer agent for our common stock is VStock Transfer LLC located at +18 Lafayette Pl, Woodmere, New York 11598. +Dividends +We +have never declared or paid any cash dividends on our capital stock. The payment of dividends on our common stock in the future +will depend on our earnings, capital requirements, operating and financial condition and such other factors as our Board of Directors +may consider appropriate. We currently expect to use all available funds to finance the future development and expansion of our +business and do not anticipate paying dividends on our common stock in the foreseeable future. +Recent +Sales of Unregistered Securities +We +issued the unregistered securities below. For the issuances of unregistered securities, we relied on the exemption from registration +requirements of the Securities Act of 1933, as amended, available under Section 4(a)(2) promulgated thereunder due to the fact +that such issuances did not involve a public offering of securities. +● +On +January 20, 2021, we issued an aggregate of 4,290 shares of our common stock for services rendered pursuant to consulting +agreements +17 +Purchases +of Equity Securities by the Issuer and Affiliated Purchasers +None. +ITEM +6. SELECTED FINANCIAL DATA +Not +required. +ITEM +7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULT OF OPERATIONS +The +following management’s discussion and analysis of financial condition and results of operations describes the principal +factors affecting the results of our operations, financial condition, and changes in financial condition. This discussion should +be read in conjunction with the accompanying audited financial statements, and notes thereto, included elsewhere in this report. +The information contained in this discussion is subject to a number of risks and uncertainties. We urge you to review carefully +the sections of this report entitled “ Risk Factors ” in other filings with the SEC and “ Forward-Looking +Statements ” in this Annual Report for a more complete discussion of the risks and uncertainties associated with an investment +in our securities. +Business +Overview +Co-Diagnostics, +Inc., a Utah corporation (“Company,” or “CDI,”) is developing robust and innovative molecular tools for +detection of infectious diseases, liquid biopsy for cancer screening, and agricultural applications. We have developed and we +manufacture and sell reagents used for diagnostic tests that function via the detection and/or analysis of nucleic acid molecules +(DNA or RNA). In connection with the sale of our tests we may sell diagnostic equipment from other manufacturers as self-contained +lab systems (which we refer to as the “MDx device”). +Our +diagnostics systems enable very rapid, low-cost, molecular testing for organisms and genetic diseases by automating historically +complex procedures in both the development and administration of tests. CDI’s newest technical advance involves a novel +approach to Polymerase Chain Reaction (“PCR”) test design (“Co-Primers”) that eliminates one of the key +vexing issues of PCR amplification, the exponential growth of primer-dimer pairs (false positives and false negatives) which adversely +interferes with identification of the target DNA/RNA. +Our +proprietary molecular diagnostics technology is paving the way for innovation in disease detection and life sciences research +through our enhanced detection of genetic material. Because we own our platform, we are able to accomplish this faster and more +economically, allowing for wider margins while still positioning Co-Diagnostics to be a low-cost provider of molecular diagnostics +and screening services. +In +addition, continued development has demonstrated the unique properties of our Co-Primer technology that make them ideally suited +to a variety of applications where specificity is key to optimal results, including multiplexing several targets, enhanced Single +Nucleotide Polymorphism (“SNP”) detection and enrichment for next gen sequencing. +Our +scientists use the complex mathematics of DNA test design, to “engineer” a DNA test and to automate algorithms that +rapidly screen millions of possible options to pinpoint the optimum design. Dr. Satterfield, our Chief Technology Officer, developed +the Company’s intellectual property consisting of the predictive mathematical algorithms and proprietary reagents used in +the testing process, which together represent a major advance in PCR testing systems. CDI technologies are now protected by seven +granted or pending US and foreign patents, as well as certain trade secrets and copyrights. Ownership of our proprietary platform +permits us the advantage of avoiding payment of patent royalties required by other PCR test systems, which enables the sale of +diagnostic tests at a lower price than competitors, while generating a profit margin. +18 +We +may either sell or lease the MDX Device to labs and diagnostic centers, through sale or lease agreements, and sell the reagents +that comprise our proprietary tests to those laboratories and testing facilities. +We +designed our tests by identifying the optimal locations on the target gene for amplification and paired the location with the +optimized primer and probe structure to achieve outputs that meet the design input requirements identified from market research. +This is done by following planned and documented processes, procedures and testing. In other words, the data resulting from our +tests verify that we succeeded in designing what we intended at the outset. Verification is a series of testing that concludes +that the product is ready to proceed to validation in a clinical evaluation setting using initial production tests to confirm +that the product as designed meets the user needs. +Using +its proprietary test design system and proprietary reagents, CDI has designed and obtained regulatory approval to sell PCR diagnostic +tests for COVID-19, a multiplex test for Flu A, Flu B and COVID-19, tuberculosis, hepatitis B and C, human papilloma virus, Malaria, +chikungunya, dengue, and the Zika virus. +In +addition to testing for infectious disease, the technology lends itself to identifying any section of a DNA strand that describe +any type of genetic trait, which creates a number of significant applications. We are active in designing and licensing tests +that identify genetic traits in plant and animal genomes. We also have a number of tests developed to test mosquitos for the identification +of diseases carried by the mosquitos to enable municipalities to concentrate their efforts in spraying mosquito populations on +the specific areas known to be breeding the mosquitos that carry deadly viruses. +RESULTS +OF OPERATIONS +Results +of Operations for the Years Ended December 31, 2020 and 2019 +The +table below provides a comparison of our operating results for the year ended December 31, 2020 as compared to the year ended +December 31, 2019. +Years Ended December 31, +Year Change +2020 +2019 +Change +% +Revenue +$ 74,552,758 +$ 214,974 +$ 74,337,784 +34580 % +Cost of revenue +16,591,346 +112,431 +16,478,915 +14657 % +Gross profit +57,961,412 +102,543 +57,858,869 +56424 % +Operating expenses +Sales and marketing +4,665,113 +1,061,676 +3,603,437 +339 % +General and administrative +8,278,734 +3,497,273 +4,781,461 +137 % +Research and development +3,185,290 +1,371,433 +1,813,857 +132 % +Depreciation and amortization +138,635 +65,902 +72,733 +110 % +Total operating expenses +16,267,772 +5,996,284 +10,271,488 +171 % +Income (loss) from operations +41,693,640 +(5,893,741 ) +47,587,381 +807 % +Other income (expense) +Interest income +97,215 +36,652 +60,563 +165 % +Interest expense +- +(106,437 ) +106,437 +100 % +Gain (loss) on disposition of assets +(175 ) +850 +(1,025 ) +-121 % +Gain (loss) on equity method investment in joint venture +778,385 +(232,881 ) +1,011,266 +434 % +Total other income (expense) +875,425 +(301,816 ) +1,177,241 +390 % +Income (loss) before income taxes +42,569,065 +(6,195,557 ) +48,764,622 +787 % +Income tax provision +90,536 +- +90,536 +N/A +Net income (loss) +$ 42,478,529 +$ (6,195,557 ) +$ 48,674,086 +786 % +19 +Revenues +For +the year ended December 31, 2020, we generated $74.5 million of revenue compared to revenue of $0.2 million in the year ended +December 31, 2019. The increase in revenue of $74.3 million was primarily due to sales of our LogixSmart COVID-19 test throughout +the world, which was developed in response to the current COVID-19 pandemic. Of the total revenue in 2020, $3.7 million was from +the sale of third party manufactured equipment and supplies that we sourced and sold to customers to facilitate usage of our test. +The majority of our revenue in 2019 was from sales of equipment and tests to mosquito abatement districts and the remainder was +sales of our test reagents and licensing revenue. +Cost +of Revenues and Gross Profit +Cost +of revenues increased by $16.5 million from $0.1 million for the year ended December 31, 2019 to $16.6 million for the year ended +December 31, 2020. The increase in cost of revenues was due to the significant increase in revenue discussed above. Our gross +margin was 77.7% for the year ended December 31, 2020 compared to 47.7% for the year ended December 31, 2019. The increase +in gross margin was due to the mix of products we sold, as the majority of our 2020 revenue came from sales of our test reagents, +which has a higher profit margin than sales of equipment. In 2019, the majority of the revenue was generated from equipment sales. +Operating +Expenses +We +incurred total operating expenses of $16.3 million for the year ended December 31, 2020 compared to total operating expenses of +$6.0 million for the year ended December 31, 2019. The increase in operating expenses was primarily due to the increase in business +activities experienced as a result of our increase in revenue. +General +and administrative expenses increased $4.8 million from $3.5 million for the year ended December 31, 2019 to $8.3 million for +the year ended December 31, 2020. The increase in general and administrative expenses was primarily due to increased activity +to support the growth of our business. The primary drivers of the increased expenses related to increases in stock-based compensation, +employee related expenses and increased expenses for professional services. +Our +sales and marketing expenses for the year ended December 31, 2020 were $4.7 million compared to $1.1 million for the year ended +December 31, 2019. The increase of $3.6 million was primarily a result of increased personnel related expenses, including commissions +paid to our sales team and distributors, due to the growth in revenue noted above. +Our +research and development expenses increased by $1.8 million from $1.4 million for the year ended December 31, 2019, to $3.2 million +for the year ended December 31, 2020. The increase was primarily due to an increase in salaries and related benefits, including +stock-based compensation, as we have added additional employees to our research and development team to increase our product development +activities. Additionally, there has been an increase in professional and lab services utilized to further help us in our research +and product development activities. +Other +Income (Expense) +Other +income was $875,000 for the year ended December 31, 2020 compared to other expense of $302,000 for the year ended December 31, +2019. The increase in other income of $1.2 million was primarily related to recording a gain of $778,000 from our India joint +venture and incurring no interest expense during 2020. For the year ended December 31, 2019 we had recorded a loss $233,000 from +our India joint venture and incurred interest expense of $106,000. +Net +Income (Loss) +We +realized net income for the year ended December 31, 2020 of $42.5 million compared with a net loss of $6.2 million for the year +ended December 31, 2019. The increase in net income of $48.7 million was primarily the result of sales of our LogixSmart COVID-19 +test and resulting margins from those sales offset by increased operating expenses as discussed above. Additionally, we recorded +an income tax expense of $0.1 million during the year ended December 31, 2020 as a result of our net income for 2020. During 2020, +we released our deferred tax asset valuation allowance and recorded a deferred tax asset since we utilized our net operating losses +from prior years during the year ended December 31, 2020. +20 +LIQUIDITY +AND CAPITAL RESOURCES +In +prior years, we financed our operations through the issuance of equity and debt. In 2020, we financed our operations primarily +through profitable operations and secondarily through the issuance of common stock. +At +December 31, 2020, we had cash and cash equivalents of $43.0 million and marketable investment securities of $4.3 million that +could readily be converted into cash if needed. Additionally, our total current assets at December 31, 2020, were $68.4 million +compared to total current liabilities of $4.5 million. +Net +cash provided by operating activities during the year ended December 31, 2020 was $28.2 million, compared to cash used in operating +activities of $5.5 million for the year ended December 31, 2019. The increase in cash from operating activities was primarily +due to our increased revenue offset by increases in accounts receivable and inventory. +We +used $5.8 million of our cash for investing activities during the year ended December 31, 2020 as compared to $0.4 million during +the year ended December 31, 2019. The increase in cash used for investing activities is primarily due to purchasing marketable +investment securities, increased purchases of property and equipment needed to support our increased revenue and additional investment +in our India joint venture offset by proceeds received from maturities of marketable investment securities. +Net +cash provided by financing activities was $19.7 million for the year ended December 31, 2020, compared to $5.9 million for the +year ended December 31, 2019. The increase is primarily due to net proceeds of $18.0 million received from a series of three registered +direct offerings in January and February 2020 pursuant to our shelf registration in addition to receiving $1.7 million from the +exercise of warrants and options for the year ended December 31, 2020. Net proceeds of $5.9 million was received during the year +ended December 31, 2019 from the sale of common and preferred stock. +Since +commencing sales of our Logix Smart COVID-19 test in March 2020, we have used our cash generated from those sales to fund the +increase in our inventories and receivables and pay our operating expenses. We have increased our work force primarily in the +area of research and development to complete development of additional tests to enable us to use our distributor network to sell +other products throughout the world and remain profitable in the future. +We +believe that our existing capital resources and the cash generated from future sales will be sufficient to meet our projected +operating requirements for the next 12 months. However, our available capital resources +may be consumed more rapidly than currently expected and we may need or want to raise additional financing for strategic opportunities. +If needed, we expect additional investment capital to come from (i) additional issuances of our common stock with existing and +new investors or (ii) the private placement of other securities with investors similar to those that have provided funding in +the past. We may not be able to secure such financing in a timely manner or on favorable terms, if at all. +On +October 30, 2020, we filed a Registration Statement on Form S-3 (File No: 333-249651) with the Securities and Exchange Commission +(the “SEC”). The SEC declared the Form S-3 effective on November 5, 2020. Pursuant to a prospectus supplement to the +Form S-3, we may offer and sell up to $100 million of the following securities separately or together, in one or more series or +classes and in amounts, at prices and on terms described in one or more offerings: common stock; preferred stock; warrants to +purchase our securities, each of which may be convertible into equity securities; or units comprised of, or other combinations +of, the foregoing securities through underwriting syndicates managed or co-managed by one or more underwriters or dealers, through +agents or directly to purchasers. Each time our securities are offered, we will provide a prospectus supplement to the Form S-3 +containing more specific information about the particular offering. To date, we have not filed a prospectus supplement to, or +sold any securities under, this Form S-3. +21 +Below +is a summary of the direct offerings done in 2020: +● +In +January 2020, we sold an aggregate of 3,448,278 shares of common stock to institutional investors for $1.45 per share for +gross proceeds of approximately $5.0 million pursuant to a shelf-registration statement on Form S-3 (File No: 333-226835) +declared effective by the SEC on September 7, 2018 (the “Shelf Registration Statement”). +● +On +February 10, 2020, the Company entered into securities purchase agreements with certain institutional investors pursuant to +which such investors purchased an aggregate of 3,324,676 shares of common stock at a purchase price of $ 3.08 per share in +a registered direct offering pursuant to the Shelf Registration Statement. The aggregate gross proceeds for the sale of the +shares were approximately $10.2 million. The closing of the offering occurred on or about February 13, 2020. +● +On +February 28, 2020, the Company entered into securities purchase agreements with certain institutional investors pursuant to +which such investors purchased an aggregate of 470,000 shares of common stock at a purchase price of $9.00 per share in a +registered direct offering pursuant to the Shelf Registration Statement. The aggregate gross proceeds for the sale of the +shares were approximately $4.0 million. The closing of the offering occurred on or about February 28, 2020. +The +foregoing estimates, expectations and forward-looking statements are subject to change as we make strategic operating decisions +from time to time and as our revenue and expenses fluctuate from period to period. +Off-Balance +Sheet Arrangements +As +of December 31, 2020, we had no off-balance sheet arrangements. +ITEM +7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Not +required. +22 +ITEM +8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. +CONSOLIDATED +FINANCIAL STATEMENTS +DECEMBER +31, 2020 AND 2019 +Table +of Contents +Report of Independent Registered Public Accounting Firm +24 +Balance Sheets +25 +Statements of Operations +26 +Statement of Changes in Stockholders’ Equity (Deficit) +27 +Statements of Cash Flows +28 +Notes to Financial Statements +29 +23 +REPORT +OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +To +the Board of Directors and Stockholders of Co-Diagnostics, Inc. +Opinion +on the Financial Statements +We +have audited the accompanying balance sheets of Co-Diagnostics, Inc. (the Company) as of December 31, 2020 and 2019, and the related +statements of operations, changes in stockholders’ equity (deficit), and cash flows for each of the years in the two-year +period ended December 31, 2020, and the related notes (collectively referred to as the financial statements). In our opinion, +the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020 +and 2019 and the results of its operations and its cash flows for each of the years in the two-year period ended December 31, +2020, in conformity with accounting principles generally accepted in the United States of America. +Basis +for Opinion +These +financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on +the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company +Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance +with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the +PCAOB. +We +conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit +to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error +or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial +reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting, but +not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. +Accordingly, we express no such opinion. +Our +audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to +error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence +regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles +used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. +We believe that our audits provide a reasonable basis for our opinion. +Haynie +& Company +Salt +Lake City, Utah +March +25, 2021 +We +have served as the Company’s auditor since 2016. +24 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +CONSOLIDATED +BALANCE SHEETS +December 31, +2020 +2019 +Assets +Current assets +Cash and cash equivalents +$ 42,976,713 +$ 893,138 +Marketable investment securities +4,335,446 +- +Accounts receivable, net +12,136,833 +131,382 +Inventory +7,995,189 +197,168 +Prepaid expenses +369,028 +362,566 +Deferred tax asset +547,224 +- +Total current assets +68,360,433 +1,584,254 +Property and equipment, net +949,639 +196,832 +Investment in joint venture +1,927,125 +434,240 +Total assets +$ 71,237,197 +$ 2,215,326 +Liabilities and stockholders’ equity +Current liabilities +Accounts payable +$ 598,318 +$ 5,959 +Accrued expenses +3,487,063 +200,788 +Accrued expenses (related party) +120,000 +120,000 +Deferred revenue +305,307 +1,323 +Total current liabilities +4,510,688 +328,070 +Accrued expenses-long-term (related party) +30,000 +150,000 +Total liabilities +4,540,688 +478,070 +Commitments and contingencies (Note 11) +Stockholders’ equity +Convertible preferred stock, $0.001 par value; 5,000,000 shares authorized; 0 and 25,600 shares issued and outstanding as of December 31, 2020 and December 31, 2019, respectively +- +26 +Common stock, $0.001 par value; 100,000,000 shares authorized; 28,558,033 and 17,342,922 shares issued and outstanding as of December 31, 2020 and December 31, 2019, respectively +28,558 +17,343 +Additional paid-in capital +49,157,236 +26,687,701 +Accumulated earnings (deficit) +17,510,715 +(24,967,814 ) +Total stockholders’ equity +66,696,509 +1,737,256 +Total liabilities and stockholders’ equity +$ 71,237,197 +$ 2,215,326 +See +accompanying notes to consolidated financial statements. +25 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF OPERATIONS +Years Ended December 31, +2020 +2019 +Revenue +$ 74,552,758 +$ 214,974 +Cost of revenue +16,591,346 +112,431 +Gross profit +57,961,412 +102,543 +Operating expenses +Sales and marketing +4,665,113 +1,061,676 +General and administrative +8,278,734 +3,497,273 +Research and development +3,185,290 +1,371,433 +Depreciation and amortization +138,635 +65,902 +Total operating expenses +16,267,772 +5,996,284 +Income (loss) from operations +41,693,640 +(5,893,741 ) +Other income (expense) +Interest income +97,215 +36,652 +Interest expense +- +(106,437 ) +Gain (loss) on disposition of assets +(175 ) +850 +Gain (loss) on equity method investment in joint venture +778,385 +(232,881 ) +Total other income (expense) +875,425 +(301,816 ) +Income (loss) before income taxes +42,569,065 +(6,195,557 ) +Income tax provision +90,536 +- +Net income (loss) +$ 42,478,529 +$ (6,195,557 ) +Earnings (loss) per common share: +Basic +$ 1.59 +$ (0.37 ) +Diluted +$ 1.52 +$ (0.37 ) +Weighted average shares outstanding: +Basic +26,720,133 +16,756,912 +Diluted +28,000,341 +16,756,912 +See +accompanying notes to consolidated financial statements. +26 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY (DEFICIT) +Convertible Preferred Stock +Common Stock +Additional Paid-in +Accumulated Earnings +Total Stockholders’ +Equity +Shares +Amount +Shares +Amount +Capital +(Deficit) +(Deficit) +Balance as of December 31, 2018 +- +$ - +12,923,383 +$ 12,923 +$ 17,622,433 +$ (18,694,167 ) +$ (1,058,811 ) +Public offering, net of offering costs of $592,764 +- +- +3,925,716 +3,926 +4,899,312 +- +4,903,238 +Issuance of preferred stock +30,000 +30 +- +- +2,999,970 +- +3,000,000 +Conversion of preferred stock to common +(4,400 ) +(4 ) +366,667 +367 +(363 ) +- +- +Warrant exercise price reset +- +- +- +- +78,090 +(78,090 ) +- +Stock-based compensation +- +- +127,156 +127 +1,088,259 +- +1,088,386 +Net loss +- +- +- +- +- +(6,195,557 ) +(6,195,557 ) +Balance as of December 31, 2019 +25,600 +$ 26 +17,342,922 +$ 17,343 +$ 26,687,701 +$ (24,967,814 ) +$ 1,737,256 +Public offering, net of offering costs of $1,457,922 +- +- +7,242,954 +7,243 +18,004,840 +- +18,012,083 +Common stock issued for warrant exercises +- +- +856,660 +857 +269,143 +- +270,000 +Common stock issued for option exercises +- +- +871,229 +871 +1,459,728 +- +1,460,599 +Stock-based compensation expense +- +- +110,935 +111 +2,737,931 +- +2,738,042 +Conversion of preferred stock to common +(25,600 ) +(26 ) +2,133,333 +2,133 +(2,107 ) +- +- +Net income +- +- +- +- +- +42,478,529 +42,478,529 +Balance as of December 31, 2020 +- +$ - +28,558,033 +$ 28,558 +$ 49,157,236 +$ 17,510,715 +$ 66,696,509 +See +accompanying notes to consolidated financial statements. +27 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF CASH FLOWS +Years Ended December 31, +2020 +2019 +Cash flows from operating activities +Net income (loss) +$ 42,478,529 +$ (6,195,557 ) +Adjustments to reconcile net income (loss) to cash used in operating activities: +Depreciation and amortization +138,635 +65,902 +Stock-based compensation expense +2,738,041 +1,088,386 +Accretion of notes payable discount +- +91,428 +Loss (gain) on disposition of assets +175 +(850 ) +Loss (gain) from equity method investment +(778,385 ) +232,881 +Bad debt expense +954,804 +11,000 +Deferred income taxes +(547,224 ) +- +Changes in assets and liabilities: +Accounts and other receivable +(12,960,255 ) +(121,462 ) +Prepaid and other assets +(6,462 ) +(292,463 ) +Inventory +(7,915,241 ) +(179,015 ) +Deferred revenue +303,984 +1,323 +Accounts payable and accrued expenses +3,758,634 +(226,664 ) +Net cash provided by (used in) operating activities +28,165,235 +(5,525,091 ) +Cash flows from investing activities +Purchases of property and equipment +(774,397 ) +(113,246 ) +Purchases of marketable investment securities +(9,310,000 ) +- +Proceeds from maturities of marketable investment securities +4,974,554 +- +Investment in joint venture +(714,500 ) +(322,000 ) +Net cash used in investing activities +(5,824,343 ) +(435,246 ) +Cash flows from financing activities +Proceeds from sale of common stock +19,470,005 +5,496,002 +Proceeds from sale of preferred stock +- +1,000,000 +Proceeds from exercise of options and warrants +1,730,599 +- +Payment of offering costs +(1,457,921 ) +(592,764 ) +Net cash provided by financing activities +19,742,683 +5,903,238 +Net increase in cash and cash equivalents +42,083,575 +(57,099 ) +Cash and cash equivalents at beginning of period +893,138 +950,237 +Cash and cash equivalents at end of period +$ 42,976,713 +$ 893,138 +Supplemental disclosure of cash flow information +Interest paid +$ - +$ 15,000 +Income taxes paid +$ - +$ - +Supplemental disclosure of non-cash investing and financing transactions +Inventory moved to property, plant and equipment +$ 117,220 +$ - +Warrants issued for services +$ - +$ 379,487 +Conversion of preferred stock to common +$ - +$ 440,000 +Conversion of debt for preferred stock +$ - +$ 2,000,000 +See +accompanying notes to consolidated financial statements. +28 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS +YEARS +ENDED DECEMBER 31, 2020 AND 2019 +Note +1 – Overview and Basis of Presentation +Description +of Business +Co-Diagnostics, +Inc., a Utah corporation (the “Company” or “CDI”), is developing robust and innovative molecular tools +for detection of infectious diseases, liquid biopsy for cancer screening, and agricultural applications. The Company develops, +manufactures and sells reagents used for diagnostic tests that function via the detection and/or analysis of nucleic acid molecules +(DNA or RNA). In connection with the sale of these tests, the Company may sell diagnostic equipment and supplies from other manufacturers. +Use +of Estimates +The +preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates +and assumptions that affect the amounts reported in the financial statements and the accompanying notes. Such estimates include +receivables and other long-lived assets, legal and regulatory contingencies, income taxes, share based arrangements, and others. +These estimates and assumptions are based on management’s best estimates and judgments. Actual amounts and results could +differ from those estimates. +Basis +of Presentation +The +accompanying audited consolidated financial statements of Co-Diagnostics, Inc. and its wholly owned subsidiary have been prepared +to reflect the financial position, results of operations and cash flows of the Company and have been prepared in accordance with +accounting principles generally accepted in the United States of America (“GAAP”). All intercompany balances and transactions +have been eliminated. +Note +2 – Summary of Significant Accounting Policies +Cash +and Cash Equivalents +Cash +and cash equivalents consist of cash on hand, money market funds and highly liquid investments with an original maturity date +of 90 days or less from the date of purchase. The fair value of cash equivalents approximated their carrying value as of December +31, 2020 and December 31, 2019. The Company has its cash and cash equivalents with a large +creditworthy financial institution and the balance exceeded federally insured limits. The Company has not experienced any losses +in such accounts, and management believes the Company is not exposed to any significant credit risk on cash and cash equivalents. +Marketable +Investment Securities +The +Company’s marketable investment securities are comprised of investments in certificates of deposit. The Company determines +the appropriate classification of its marketable investment securities at the time of purchase and reevaluates such designation +at each balance sheet date. The Company has classified and accounted for its marketable investment securities as available-for-sale +securities as the Company may sell these securities at any time for use in its current operations or for other purposes, even +prior to maturity. As a result, the Company classifies its marketable investment securities, +including securities with stated maturities beyond twelve months, within current assets in the condensed consolidated balance +sheets. Any unrealized gains or losses are immaterial. +Accounts +Receivable +Trade +accounts receivable are recorded at the invoiced amount (net of allowance) and do not bear interest. The Company maintains an +allowance for doubtful accounts for amounts the Company does not expect to collect. In establishing the required allowance, management +considers historical losses, current market condition, customers’ financial condition, the age of receivables, and current +payment patterns. Account balances are written off against the allowance once the receivable is deemed uncollectible. Recoveries +of trade receivables previously written off are recorded when collected. At December 31, 2020 total accounts receivable was $12,928,633 +with an allowance for uncollectable accounts of $791,800 resulting in a net amount of $12,136,833. At December 31, 2019 total +accounts receivable was $142,382 with an allowance for uncollectable accounts of $11,000 resulting in a net amount of $131,382. +29 +Equity-Method +Investments +Our +equity method investments are initially recorded at cost and are included in other long-term assets in the accompanying condensed +consolidated balance sheet. We adjust the carrying value of our investment based on our share of the earnings or losses in the +periods which they are reported by the investee until the carrying amount is zero. The earnings or losses are included in other +income (expense) in the accompanying condensed consolidated statements of operations. +Inventory +Inventory +is stated at the lower of cost or net-realizable value. Inventory cost is determined on a first-in first-out basis that approximates +average cost in accordance with ASC 330-10-30-12. At December 31, 2020, the Company had $7,995,189 in inventory, of which $598,881 +was finished goods and $7,396,308 was raw materials. At December 31, 2019, the $197,168 of inventory was finished goods. The Company +establishes reserves to reduce low-moving, obsolete, or unusable inventories to their estimated useful or scrap values. +Property +and Equipment +Property +and equipment are stated at cost less accumulated depreciation and amortization. Depreciation is provided using the straight-line +method over the estimated useful lives of the property, generally from three to five years. Repairs and maintenance costs are +expensed as incurred except when such repairs significantly add to the useful life or productive capacity of the asset, in which +case the repairs are capitalized. +The +Company reviews its long-lived assets, including property and equipment, for impairment whenever an event or change in facts and +circumstances indicates that their carrying amounts may not be recoverable. Recoverability of these assets is measured by comparing +the carrying amount to the estimated undiscounted future cash flows expected to be generated. If the carrying amount exceeds the +undiscounted cash flows, the assets are determined to be impaired and an impairment charge is recognized as the amount by which +the carrying amount exceeds fair value. +Revenue +Recognition +The +Company generates revenue from product sales and license sales. The Company recognizes revenue when all of the following criteria +are satisfied: (i) identification of the promised goods or services in the contract; (ii) determination of whether the promised +goods or services are performance obligations, including whether they are distinct in the context of the contract; (iii) measurement +of the transaction price, including the constraint on variable consideration; (iv) allocation of the transaction price to the +performance obligations; and (v) recognition of revenue when, or as the Company satisfies each performance obligation. Based on +the criteria above, the Company typically recognizes revenue upon delivery. +The +Company constrains revenue by giving consideration to factors that could otherwise lead to a probable reversal of revenue. The +Company records any payments received from customers prior to the Company fulfilling its performance obligation(s) as deferred +revenue. +Deferred +Revenue +Deferred +revenue primarily consists of payments received from customers prior to the Company fulfilling its performance obligation of providing +the product. When this occurs, the Company records a contract liability as deferred revenue. Deferred revenue is recognized as +revenue as the related performance obligations are satisfied. +30 +Research +and Development +Research +and development costs are expensed when incurred. The Company expensed $3,185,290 and $1,371,433 of research and development costs +for the years ended December 31, 2020 and 2019, respectively. +Stock-based +Compensation +The +Company has granted stock-based awards, including restricted stock, stock options, stock warrants and restricted stock units (“RSUs”), +to its employees, certain consultants and members of its board of directors. The Company records stock-based compensation based +on the grant date fair value of the awards and recognizes the fair value of those awards as expense using the straight-line method +over the requisite service period of the award. The Company estimates the grant date fair value of stock options using the Black-Scholes +option-pricing model. When an award is forfeited prior to the vesting date, the Company +recognizes an adjustment for the previously recognized expense in the period of the forfeiture. +Income +Taxes +The +Company accounts for income taxes in accordance with the liability method of accounting for income taxes. Under this method, d eferred +income tax assets and deferred income tax liabilities represent the tax effect of temporary differences between financial reporting +and tax reporting measured at enacted tax rates in effect for the year in which the differences are expected to reverse. The Company +recognizes only the impact of tax positions that, based on their technical merits, are more likely than not to be sustained upon +an audit by the taxing authority. +Valuation +allowances are provided when it is more-likely-than-not that some or all of the deferred income tax assets may not be realized. +In assessing the need for a valuation allowance, the Company has considered its historical levels of income, expectations of future +taxable income and ongoing tax planning strategies. +Developing +the provision for income taxes, including the effective tax rate and analysis of potential tax exposure items, if any, requires +significant judgment and expertise in federal and state income tax laws, regulations and strategies, including the determination +of deferred income tax assets and liabilities and any estimated valuation allowances deemed necessary to value deferred income +tax assets. Judgments and tax strategies are subject to audit by various taxing authorities. While the Company believes it has +no significant uncertain income tax positions in the consolidated financial statements, adverse determinations by these taxing +authorities could have a material adverse effect on the consolidated financial positions, result of operations, or cash flows. +Net +Income (Loss) per Share +Basic +net income or loss per common share is computed by dividing net income or loss applicable to common shareholders by the weighted +average number of shares outstanding during each period. +Diluted +net income or loss per share is computed by dividing net income or loss attributable to common stockholders by the weighted-average +number of shares of common stock outstanding during the period increased by common shares that could be issued upon conversion +or exercise of other outstanding securities to the extent those additional common shares would be dilutive. The dilutive effect +of potentially dilutive securities is reflected in diluted net income or loss per share by application of the treasury stock method. +During periods when the Company is in a net loss position, basic net loss per share is the same as diluted net loss per share +as the effects of potentially dilutive securities are anti-dilutive +Concentrations +Risk and Significant Customers +The +Company had certain customers which are each responsible for generating 10% or more of the total revenue for the year ended December +31, 2020. Two customers together accounted for approximately 38% of total revenue for the year ended December 31, 2020. +31 +Two +customers each accounted for more than 10% of accounts receivable at December 31, 2020. These two customers together accounted +for approximately 48% of accounts receivable at December 31, 2020. +Recently +Issued Accounting Standards +From +time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”) that are +adopted by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued +standards, which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption. +As +an emerging growth company (“EGC”), the Company has elected to take advantage of the benefits of the extended transition +period provided for in Section 7(a)(2)(B) of the Securities Act of 1933, as amended, for complying with new or revised accounting +standards which allows the Company to defer adoption of certain accounting standards until those standards would otherwise apply +to private companies. +In +February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which requires recognition of leased assets and liabilities +on the balance sheet and disclosing key information about leasing arrangements. This update is effective for annual periods and +interim periods with those periods beginning after December 15, 2021, for public EGC companies like us. The Company expects to +use the modified retrospective transition method with the option to recognize a cumulative-effect adjustment at the date of adoption. +The Company expects its balance sheet will be impacted as it records right-of-use assets and lease liabilities on its consolidated +balance sheet, but does not expect the adoption of this standard will have a material impact on its consolidated statements of +operations and cash flows. +In +June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326) (“ASU 2016-13”), which +requires the measurement and recognition of expected credit losses for certain financial instruments, which includes the Company’s +accounts receivable. ASU 2016-13 replaces the existing incurred loss impairment model with an expected loss methodology, which will result +in more timely recognition of credit losses. The update is effective for annual periods and interim periods with those periods beginning +after December 15, 2021, for public EGC companies like us, but the Company may adopt it upon election on January 1, 2021. The standard +requires a cumulative effect adjustment to the balance sheet as of the beginning of the first early reporting period in which the guidance +is effective. The Company is evaluating the impact of the adoption of ASU 2016-13 on its consolidated financial statements and when it +plans to adopt it. +In +December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740) (“ASU 2019-12”), which removes certain exceptions +for investments, intra-period allocations and interim calculations and adds guidance to reduce complexity in accounting for income +taxes. ASU 2019-12 is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, +2020; early adoption is permitted. The Company does not believe the adoption of this standard will have a material impact on its +consolidated financial statements and related disclosures. +Note +3 – Fair Value Measurements +The +Company measures and records certain financial assets at fair value on a recurring basis. Fair value is based on the price that +would be received from selling an asset or paid to transfer a liability in an orderly transaction between market participants +at the measurement date. +The +Company’s financial instruments that are measured at fair value on a recurring basis consist of money market funds. The +following three levels of inputs are used to measure the fair value of financial instruments: +Level +1: Quoted market prices in active markets for identical assets or liabilities. +Level +2: Observable market-based inputs or unobservable inputs that are corroborated by market data. +Level +3: Unobservable inputs that are not corroborated by market data. +32 +The +Company’s financial instruments that are measured at fair value on a recurring basis consist of certificates of deposit. +The following table summarizes the assets measured at fair value on a recurring basis as of December 31, 2020 by level within +the fair value hierarchy: +December 31, 2020 +(Level 1) +(Level 2) +(Level 3) +Total +Marketable investment securities: +Certificates of deposit +$ - +$ 4,335,446 +$ - +$ 4,335,446 +Fair +Value of Other Financial Instruments +The +carrying amounts of certain financial instruments, including cash held in banks, accounts receivable, accounts payable, accrued +liabilities, and other liabilities approximate fair value due to their short-term maturities and are excluded from the fair value +tables above. +Note +4 – Property and Equipment +Property +and equipment, net consisted of the following: +Estimated +Useful Lives +December 31, +in years +2020 +2019 +Lab equipment +3 - 5 +$ 1,212,561 +$ 386,802 +Leasehold improvements +3 +3,157 +- +Office equipment, furniture and other +2 - 5 +38,344 +7,133 +Less accumulated depreciation and amortization +(304,423 ) +(197,103 ) +Fixed assets, net +$ 949,639 +$ 196,832 +Note +5 – Revenue +The +following table sets forth revenue by geographic area: +Years Ended December 31, +2020 +2019 +United States +$ 44,862,751 +$ 214,974 +Rest of World +29,690,007 +- +Total +$ 74,552,758 +$ 214,974 +Percentage of revenue by area: +United States +60 % +100 % +Rest of World +40 % +0 % +Deferred +Revenue +Changes +in the Company’s deferred revenue balance for the year ended December 31, 2020 were as follows: +Balance as of December 31, 2019 +$ 1,323 +Revenue recognized that was included in deferred revenue balance at the beginning of the period +(1,323 ) +Increase due to prepayments from customers +305,307 +Balance as of December 31, 2020 +$ 305,307 +33 +The +Company expects to perform its performance obligation and recognize the deferred revenue as revenue during the year ended December +31, 2021. +Note +6 – Stockholders’ Equity +Common +Stock and Preferred Stock +On +January 28, 2020, the Company completed the sale of 3,448,278 shares of the Company’s common stock, par value $0.001 per +share, at a purchase price of $1.45 per share in a registered direct offering. The aggregate gross proceeds for the sale of the +shares were $5,000,003 and the Company received net proceeds of $4,517,102 after deducting offering costs of $482,901. +On +February 13, 2020, the Company completed the sale of 3,324,676 shares of the Company’s common stock, par value $0.001 per +share, at a purchase price of $3.08 per share in a registered direct offering. The aggregate gross proceeds for the sale of the +shares were $10,240,002 and the Company received net proceeds of $9,612,561 after deducting offering costs of $627,441. +On +March 2, 2020, the Company completed the sale of 470,000 shares of the Company’s common stock, par value $0.001 per share, +at a purchase price of $9.00 per share in a registered direct offering. The aggregate gross proceeds for the sale of the shares +were $4,230,000 and the Company received net proceeds of $3,882,420 after deducting offering costs of $347,580. +During +the year ended December 31, 2020, the Company issued an aggregate of 2,133,333 shares of common stock upon conversion of all of +the Company’s convertible preferred stock outstanding as of December 31, 2019. +During +the year ended December 31, 2020, the Company issued 856,660 shares of common stock upon the exercise of warrants and received +$270,000. +During +the year ended December 31, 2020, the Company issued 871,229 shares of common stock upon the exercise of options and received +$1,460,599. +During +the year ended December 31, 2020, the Company issued 83,935 shares of common stock for services provided by third parties primarily +related to investment relations services. +In +January 2019, we entered into a securities purchase agreement with investors, whereby the investors purchased from the Company +30,000 shares of Series A Convertible Preferred Stock of the Company for a purchase price of $3,000,000. The Series A Convertible +Preferred Stock was convertible to common stock at a conversion price calculated by multiplying the number of preferred shares +being converted by $100 and dividing the result by $1.20. +During +the year ended December 31, 2019, 366,667 shares of our common stock were issued for the conversion of 4,400 shares of Series +A Preferred Stock. +In +February 2019, the Company completed the sale of 3,925,716 shares of the Company’s common stock, par value $0.001 per share, +at a purchase price of $1.40 per share in a registered direct offering. The aggregate gross proceeds for the sale of the shares +were $5,496,002 and the Company received net proceeds of $4,903,238 after deducting offering costs of $592,764. +During +the year ended December 31, 2019, the Company issued an aggregate of 127,516 shares of common stock for services provided by third +parties primarily related to investment relations services. +34 +Note +7 – Earnings per Share +The +following table reconciles the numerator and the denominator used to calculate basic and diluted earnings per share for years +ended December 31, 2020 and 2019: +Years Ended December 31, +2020 +2019 +Numerator +Net income (loss), as reported +$ 42,478,529 +$ (6,195,557 ) +Denominator +Weighted average shares, basic +26,720,133 +16,756,912 +Dilutive effect of stock options, warrants and RSUs +1,280,208 +- +Shares used to compute diluted earnings per share +28,000,341 +16,756,912 +Basic earnings per share +$ 1.59 +$ (0.37 ) +Diluted earnings per share +$ 1.52 +$ (0.37 ) +50,000 +options were excluded from the computation of diluted earnings per share for the year ended December 31, 2020, because the effect +would have been anti-dilutive. +As +a result of incurring a net loss for the year ended December 31, 2019, no potentially dilutive securities are included in the +calculation of diluted earnings per share because such effect would be anti-dilutive. The Company had potentially dilutive securities +as of December 31, 2019, consisting of: (i) 2,021,817 options, (ii) 983,535 warrants and (iii) 2,133,333 for shares of convertible +preferred stock. +Note +8 – Stock-Based Compensation +Stock +Incentive Plans +The +Co-Diagnostics, Inc. 2015 Long Term Incentive Plan (the “Incentive Plan”) reserves an aggregate of 6,000,000 shares +of common stock issuable upon the grant of awards under the Incentive Plan. The number of awards available for issuance under +the Incentive Plan was 3,278,683 at December 31, 2020. +Stock +Options +The +following table summarizes option activity during the year ended December 31, 2020: +Number of +Options +Weighted +Average +Exercise Price +Weighted +Average Fair +Value +Weighted +Average +Remaining +Contractual Life +(Years) +Outstanding at December 31, 2019 +2,021,817 +$ 1.69 +$ 0.83 +Granted +150,000 +8.14 +4.74 +Expired +- +- +- +Forfeited/Cancelled +- +- +- +Exercised +(871,229 ) +1.68 +0.89 +Outstanding at December 31, 2020 +1,300,588 +$ 2.44 +$ 1.24 +7.90 +Exercisable at December 31, 2020 +1,003,921 +$ 2.32 +$ 1.18 +7.68 +The +total intrinsic value of options exercised during the year ended December 31, 2020 was approximately $11.8 million. The aggregate +intrinsic value of outstanding options at December 31, 2020 was approximately $7.1 million. There were 296,667 of unvested options +as of December 31, 2020. +35 +Stock-based +compensation cost is measured at the grant date based on the fair value of the award granted and recognized as expense over the +vesting period using the straight-line method. The Company uses the Black-Scholes model to value options granted. The following +weighted average assumptions were used in estimating the grant date fair value of options: +Years Ended December 31, +2020 +2019 +Risk-free interest rate +1.05 % +1.56 % +Expected life (years) +7.3 +10.0 +Expected volatility +62.82 % +63.65 % +Expected dividend yield +None +None +As +of December 31, 2020, there were 296,667 of unvested options and $270,147 of unrecognized stock-based compensation expense related +to options. The unrecognized stock-based compensation expense is expected to be recognized over 1.5 years. +Restricted +Stock Units +The +grant date fair value of RSUs granted is determined using the closing market price of the Company’s common stock on the +grant date with the associated compensation expense amortized over the vesting period of the awards. The following table sets +forth the outstanding RSUs and related activity for the year ended December 31, 2020: +Number of RSUs +Weighted Average +Grant Date Fair Value +Outstanding at December 31, 2019 +- +$ - +Granted +549,500 +10.49 +Vested +(27,000 ) +10.49 +Forfeited/Cancelled +- +- +Outstanding at December 31, 2020 +522,500 +$ 10.49 +As +of December 31, 2020, there was $5.2 million of unrecognized stock-based compensation expense related to outstanding RSUs which +is expected to be recognized over a weighted-average period of 2.8 years. +Warrants +The +Company has issued warrants related to past financings and as compensation to third parties for services provided. The Company +estimates the fair value of issued warrants on the date of issuance as determined using a Black-Scholes pricing model. The Company +amortizes the fair value of issued warrants using a vesting schedule based on the terms and conditions of each warrant if granted +for services. +36 +The +following table summarizes warrant activity during the year ended December 31, 2020: +Number of +Warrants +Weighted +Average +Exercise Price +Weighted +Average Fair +Value +Weighted +Average +Remaining +Contractual Life +(Years) +Outstanding at December 31, 2019 +983,535 +$ 1.44 +$ 1.03 +Granted +20,000 +1.40 +15.19 +Expired +(9,090 ) +6.00 +0.17 +Forfeited/Cancelled +- +- +- +Exercised +(924,445 ) +1.42 +1.43 +Outstanding at December 31, 2020 +70,000 +$ 1.83 +$ 5.21 +3.3 +The +intrinsic value of warrants exercised during the year ended December 31, 2020 was approximately $9.7 million. The aggregate intrinsic +value of outstanding warrants at December 31, 2020 was approximately $523,000. +The +fair values for the warrants issued were estimated at the date of grant using the Black Scholes model with the following weighted +average assumptions: +Years Ended December 31, +2020 +2019 +Risk-free interest rate +0.34 % +1.98 % +Expected life (years) +5.0 +5.0 +Expected volatility +61.42 % +50.88 % +Expected dividend yield +None +None +All +outstanding warrants are exercisable at December 31, 2020 and there was no unrecognized stock-based compensation expense related +to warrants. +Stock +Issued for Services +The +Company has issued restricted stock to third parties for services provided. The grant date fair value of the restricted stock +granted is determined using the closing market price of the Company’s common stock on the grant date with the associated +compensation expense amortized over the vesting period of the stock awards. The Company has issued 83,935 of restricted stock +for services during the year ended December 31, 2020 and there was no unrecognized stock-based compensation expense related to +restricted stock issued. +Stock-Based +Compensation Expense +The +Company recognized stock-based compensation expense related to the types of awards discussed above as follows: +Years Ended December 31, +2020 +2019 +Options +$ 901,345 +$ 589,684 +Restricted stock units +500,861 +- +Warrants +303,802 +390,265 +Stock +1,032,033 +108,437 +Total stock-based compensation expense +$ 2,738,041 +$ 1,088,386 +37 +Note +9 – Income Taxes +The +components of the provision for income taxes consists of the following for the years ended December 31, 2020 and 2019: +Year Ended December 31, +2020 +2019 +Current: +Federal +$ - +$ - +State +637,760 +- +Total current +$ 637,760 +$ - +Deferred: +Federal +(452,544 ) +- +State +(94,680 ) +- +Total deferred +(547,224 ) +- +Total income tax expense +$ 90,536 +$ - +The +income tax provision differs from the amount of income tax determined by applying the U.S. federal income tax rate to income (loss) +before income taxes for the years ended December 31, 2020 and 2019 due to the following: +Year Ended December 31, +2020 +2019 +Federal income tax benefit at statutory rate +$ 8,939,504 +$ (1,610,800 ) +State income tax benefit, net of federal tax benefit +1,395,541 +- +Permanent differences +(4,633,255 ) +9,000 +Change in valuation allowance +(5,161,500 ) +1,258,300 +Other +(449,754 ) +343,500 +90,536 +- +38 +Net +deferred tax assets consist of the following components as of December 31, 2020 and 2019: +December 31, +2020 +2019 +Deferred tax assets: +Accrued liabilities +$ 37,898 +$ - +Reserves and allowances +200,049 +- +Deferred compensation +241,652 +- +Research and development credits +423,001 +- +Net operating loss carryforwards +- +5,131,100 +SEC 179 carry-forwards +- +1,600 +Depreciation +- +28,800 +Total deferred tax assets +902,600 +5,161,500 +Deferred tax liabilities: +Property and equipment, net +(233,951 ) +- +Prepaids +(66,456 ) +- +Other +(54,969 ) +- +Total deferred tax liabilities +(355,376 ) +- +Net deferred tax assets +547,224 +5,161,500 +Less valuation allowance +- +(5,161,500 ) +Net deferred tax assets +$ 547,224 +$ - +At +December 31, 2020, the Company had no federal or state net operating loss carryforwards. At December 31, 2020, the Company had +$750,634 of federal research and development credit carryforward. This credit has been offset by a liability for unrecognized +tax benefits of $375,317. If not utilized, the credit will expire beginning in 2036. At December 31, 2020, the Company had $120,198 +of state research and development credit carryforward. This credit has been offset by a liability for unrecognized tax benefits +of $72,514. If not utilized, the credit will expire beginning in 2032. +As +of each reporting date, management considers new evidence, both positive and negative, that could affect its view of the future +realization of deferred tax assets. As of December 31, 2020, in part because in the current year we achieved three years of cumulative +pre-tax income, management determined that there is sufficient positive evidence to conclude that it is more likely than not that +its deferred taxes are realizable. It therefore fully reduced its valuation allowance accordingly by $5,161,500. +ASC +Topic 740-10-05 requires that the impact of a tax position be recognized in the financial statements if that position is more +likely than not of being sustained on audit, based on the technical merits of the position. At December 31, 2020, the Company +had a $447,831 liability for unrecognized tax benefits which is fully netted against deferred tax assets for related carryforward +credits. The Company expects no material changes to the liability for unrecognized tax benefits in the next 12 months. Interest +and penalties associated with uncertain tax positions are recorded as a component of income tax expense. A reconciliation of the +beginning and ending amount of unrecognized benefits is as follows: +December 31, +2020 +2019 +Unrecognized tax benefits at the beginning of the year +$ - +$ - +Gross increases - current year tax positions +232,145 +- +Gross increases - prior year tax positions +215,686 +- +Gross decreases - prior year tax positions +- +- +Unrecognized tax benefits at end of year +$ 447,831 +$ - +Interest and penalties in year-end balance +$ - +$ - +39 +The +Company is subject to taxation in the United States and other state jurisdictions. The tax years from December 31, 2016 through +December 31, 2020 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which +the Company is subject. The Company is not currently under examination by any taxing authority. +The +Coronavirus Aid, Relief and Economic Security (“CARES”) Act was signed into law on March 27, 2020. The income tax +provisions of the CARES Act include temporary changes to income-based tax laws, including the ability to utilize net operating +losses, interest expense deductions, alternative minimum tax credit refunds, charitable contributions, and depreciation of qualified +improvement property. The income tax provisions of the CARES Act did not have a material impact on our consolidated financial +statements for the year ended December 31, 2020. +Note +10 – Related Party Transactions +The +Company acquired the exclusive rights to the CoPrimer technology pursuant to an exclusive license agreement, dated April 2014 +(the “Exclusive License Agreement”), between the Company and DNA Logix, Inc., which was assigned to Dr. Brent Satterfield, +an executive officer, prior to the Company’s acquisition of DNA Logix, Inc. On March 1, 2017, the Company entered into an +amendment to its Exclusive License Agreement for its Cooperative Primers (“License”) technology with Dr. Satterfield. +The amendment provided in part that all accrued royalties under the License ceased as of January 1, 2017, and the Company agreed +to pay to Dr. Satterfield $700,000 of accrued royalties at the rate of $10,000 per month starting in January 2017. At December +31, 2020, the aggregate balance of this related party liability was $150,000. +Note +11 – Commitments and Contingencies +Lease +Obligations +The +Company’s offices are located at 2401 S. Foothill Dr., Suite D, Salt Lake City, Utah 84109-1479. In February 2020, the Company +entered into a 4-year lease agreement for its office space and in March 2020, the Company entered into an addendum with our landlord +for additional space. The new aggregate space consists of approximately 13,687 square feet at a monthly rate of $28,825 and expires +in February 2024. For the years ended December 31, 2020 and 2019, the Company expensed $311,963 and $175,137, respectively, for +rent. The Company’s future minimum lease payments were as follows as of December 31, 2020: +Year Ending December 31, +2021 +$ 284,406 +2022 +293,595 +2023 +303,059 +2024 +50,774 +Total lease payments +$ 931,834 +Litigation +Liabilities +for loss contingencies arising from claims, assessments, litigation, fines, and penalties and other sources are recorded when +it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection +with loss contingencies are expensed as incurred. +Five +different securities class action complaints were filed in July, September and December by certain stockholders of the Company +against the Company claiming that the Company promulgated false and misleading press releases to increase the price of our stock +to improperly benefit the officers and directors of the Company. The plaintiffs demand compensatory damages sustained as a result +of the Company’s alleged wrongdoing in an amount to be proven at trial. The Company believes these lawsuits are without +merit and intends to defend the cases vigorously. The Company is unable to estimate a range of loss, if any, that could result +were there to be an adverse final decision in these cases. As of the date of this report, the Company does not believe it is probable +that these cases will result in an unfavorable outcome; however, if an unfavorable outcome were to occur in these cases, it is +possible that the impact could be material to the Company’s results of operations in the period(s) in which any such outcome +becomes probable and estimable. +Note +12 – Subsequent Events +The +Company evaluated subsequent events pursuant to ACS Topic 855 and determined that there are no additional events that need to +be reported. +40 +ITEM +9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. +None. +ITEM +9A. CONTROLS AND PROCEDURES +Evaluation +of Disclosure Controls and Procedures +We +maintain a set of disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) designed to ensure that +information required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, +and reported within the time periods specified in rules and forms adopted by the SEC. Disclosure controls and procedures include, +without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports +that it files or submits under the Exchange Act is accumulated and communicated to the Company’s management, including its +principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. +Our +management, with the participation of our Chief Executive Officer and our Chief Financial Officer, evaluated the effectiveness +of our disclosure controls and procedures as of December 31, 2020. Based on the evaluation, management has concluded that our +disclosure controls and procedures are effective as of December 31, 2020 to provide reasonable assurance regarding the reliability +of our financial reporting and the preparation of our financial statements for external +reporting purposes in accordance with U.S. generally accepted accounting principles. +Changes +in Internal Control Over Financial Reporting +There +have not been any changes in the Company’s internal control over financial reporting (as such term is defined in Rules 13a- +15(f) and 15d-15(f) under the Exchange Act) during the fourth quarter of 2020 that have materially affected, or are reasonably +likely to materially affect, the Company’s internal control over financial reporting, except as follows +Material +Weakness Remediation +A +material weakness previously identified during management’s assessment and reported in our 2019 Form 10-K was the lack of +sufficient technical expertise on certain accounting and tax requirements for new and unusual transactions. These control deficiencies +could have resulted in a material misstatement of accounts or disclosures that would result in a material misstatement to our +interim or annual financial statements that would not be prevented or detected. +To +address the material weakness reported in our 2019 Form 10-K, we have hired an additional employee in our accounting team and +have increased the involvement of consultants with the required expertise to help ensure new and unusual transactions are appropriately +recorded and reviewed in order to remediate the material weakness. +In +connection with the identification of an error that resulted in the restatement of our condensed consolidated financial statements +included in our Quarterly Report on Form 10-Q/A for the period ended June 30, 2020, we also identified a material weakness related +to controls over the purchasing and receiving of inventory. Specifically, there was a lack of formalized purchasing and receiving +processes and controls and the functions were decentralized. +To +address the material weakness reported in our Quarterly Report on Form 10-Q/A for the period ended June 30, 2020, we have centralized +the purchasing and receiving functions and have added new processes and controls to ensure purchasing and receiving are recorded +completely and accurately. Furthermore, we have ensured inventory is counted on a quarterly basis to help ensure inventory is +recorded accurately. +As +a result of these efforts, the Company determined that the material weaknesses were remediated, and our internal control over +financial reporting was effective as of December 31, 2020. +41 +Management’s +Annual Report on Internal Control over Financial Reporting +Our +management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule +13a-15(f) under the Exchange Act). Our management, including our Chief Executive Officer and Chief Financial Officer, conducted +an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2020. In making its evaluation, +management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal +Control – Integrated Framework (2013). +Based +on this evaluation, management determined that our internal control over financial reporting was effective as of December 31, +2020. +This +Annual Report does not include an attestation report by our independent registered public accounting firm regarding internal control +over financial reporting since we are an emerging growth company. Management’s report was not subject to attestation by +our registered public accounting firm pursuant to rules of the SEC that permit emerging growth companies to provide only management’s +report in the 10-K. +Inherent +Limitations on Effectiveness of Controls +Our +management, including our Chief Executive Officer and Chief Financial Officer, believes that our disclosure controls and procedures +and internal control over financial reporting are intended to be designed to provide reasonable assurance of achieving their objectives. +However, our management does not expect that our disclosure controls and procedures or our internal control over financial reporting +will prevent or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only +reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system +must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. +Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all +control issues and instances of fraud, if any, have been detected. These inherent limitations include the realities that judgments +in decision making can be faulty, and that breakdowns can occur because of a simple error or mistake. Additionally, controls can +be circumvented by the individual acts of some persons, by collusion of two or more people or by management override of the controls. +The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and +there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions; over +time, controls may become inadequate because of changes in conditions, or the degree of compliance with policies or procedures +may deteriorate. Because of the inherent limitations in a cost–effective control system, misstatements due to error or fraud +may occur and not be detected. +ITEM +9B. OTHER INFORMATION +None. +PART +III +ITEM +10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE. +The +following table sets forth the names, ages and positions of our executive officers and directors as of March 25, 2021. Our Board +of Directors is currently comprised of five members, who are elected annually to serve for one year or until their successor is +duly elected and qualified, or until their earlier resignation or removal. Executive officers serve at the discretion of the Board +of Directors. +42 +Name +Age +Position +Dwight +Egan +67 +Chief +Executive Officer, President and Chairman of the Board +Reed +Benson +74 +General +Counsel, Secretary and former Chief Financial Officer +Brian +Brown +45 +Chief +Financial Officer +Eugene +Durenard +51 +Director +James +Nelson +67 +Director +Richard +Serbin +76 +Director +Ted +Murphy +56 +Director +Dwight +Egan serves as our President and Chief Executive Officer and has been an officer and director since April 2013. Mr. Egan has +been engaged in private investment business from February 1999 to the present. He was a senior executive at Data Broadcasting +Corporation, a leading provider of wireless, real-time financial market data, news and sophisticated fixed- income portfolio analytics +to 27,000 individual and professional investors from 1995 to 1999. He co-founded and served as CEO and Chairman of the Board of +Broadcast International, Inc. from 1984 to 1995, when Data Broadcasting Corporation acquired Broadcast International and created +CBS MarketWatch , a leading financial news site and participated in its initial public offering. Mr. Egan’s prior +experience in directing a public company and working with capital markets gives him valuable experience in advising the board +on matters of finance and operations. +Reed +Benson has been Secretary from November 2014 to the present and was our Chief Financial Officer from November 2014 to February +2021. He currently is our General Counsel and was a director from November 2014 to May 2017. Since September 2008 to the present, +in addition to the private practice of law, he is a founder and partner of Legends Capital Group, LLC, a privately held venture +capital group that identifies investment opportunities in natural resources, bio tech and technology fields. From October 2004 +to September 2008, he was employed as Chief Financial Officer, Secretary, and General Counsel and member of Board of Directors +of Broadcast International, Inc., a publicly traded communications services company. From 2001 to October 2004, he was in the +private practice of law where his practice focused on tax and business-related matters. From July 1995 to January 2001, he was +secretary and general counsel for Data Broadcasting Corporation, a provider of market information to individual investors. Mr. +Benson received his J.D. degree from the University of Utah School of Law in 1976 and a Bachelor of Science Degree in Accounting +from the University of Utah in 1971. Mr. Benson became a Certified Public Accountant in 1974. Mr. Benson’s experience in +finance, accounting and business consulting, and prior public company directorship, provide Mr. Benson with expertise enabling +critical input to our company. +Brian +Brown became our Chief Financial Officer in February 2021. From July 2020 until February 2021, Mr. Brown served as the Chief +Financial Officer of A-Core Concrete Cutting, Inc. where his duties included overseeing the company’s accounting and finance +departments, mergers and acquisitions and was responsible for financial forecasting and budgeting. From August 2019 to December +2019, Mr. Brown served as the Vice President of Accounting, Treasury and Investor Relations at Sportsman’s Warehouse Holdings, +Inc., a public company reporting on Nasdaq Global Select under the symbol SPWH, where his duties included overseeing the company’s +accounting, treasury and investor relations departments, preparing the company’s annual, quarterly and current reports with +the SEC, overseeing all aspects of the company’s annual audit, including, but not limited to, the preparation and review +of audit support schedules, preparation of financial statements and footnotes, and providing support to the company’s independent +auditors. From October 2009 to August 2019, Mr. Brown served as the Director of Finance of Sportsman’s Warehouse Holdings, +Inc. where he assisted with the Company’s initial public offering in April 2014 as well as effecting private and secondary +public offerings, acquisitions of a group of retail stores and preparing the company’s periodic and current reports with +the SEC under the Exchange Act and complying with the Sarbanes Oxley Act. From May 2005 to October 2009, Mr. Brown served as the +Corporate Controller of Franklin Covey Products where he developed and maintained the company’s internal controls over financial +reporting structure in accordance with the control standards required under Section 404 of the Sarbanes Oxley Act. From July 2001 +to May 2005, Mr. Brown served as an Assurance Senior at KPMG, LLP where he provided audit services to various clients in multiple +industries. Mr. Brown holds a Bachelor of Arts in Accounting and Masters of Professional Accountancy from the University of Utah. +Mr. Brown is a licensed CPA in Utah. +43 +Eugene +Durenard has been a member of our Board of Directors since June 2019. Dr. Durenard is the Founder and CEO of Hyperbolic Holdings, +a Swiss-based holding, management consulting and strategy advisory company specialized in healthcare. Dr. Durenard brings an investment +and entrepreneurial experience spanning 20 years. For the last 7 years he has been working with family offices on direct investments +and philanthropy focused on life sciences. He serves on the advisory board of several private companies in the biotech and MedTech +sectors as well as an impact venture fund focused on healthcare. After an initial career in proprietary research and trading at +Salomon Brothers and Credit Suisse in London, he co-founded Orion Investment Management in Bermuda specializing in quantitative +asset and liability management for institutions and private clients. He subsequently sold it to Capital G Bank and co-headed their +asset management. Dr. Durenard spent several years establishing personal connections with representatives of 40+ clusters of life +science innovation, families operating healthcare businesses and industry leaders globally. He regularly visits labs and incubators, +meets with leading scientists and innovators in order to keep abreast of current trends and developments. His advice is based +on a thorough analysis that combines in-depth knowledge of science, competitive forces and financial expertise. He has published +several articles in asset-liability management industry magazines as well as the book “Professional Automated Trading — +Theory and Practice” (Wiley 2013). He has a PhD in Mathematics from Harvard University. Dr. Durenard brings a thorough multi-asset +class investment and entrepreneurial experience spanning 20 years to the Company’s Board of Directors. +Edward +Murphy has been a member of our Board of Directors since June 2019. Mr. Murphy currently serves as a senior vice president +and a partner of Dover Investments Ltd., a private investment firm. Throughout his career, Mr. Murphy’s duties have included +investment analysis of various types of investment projects in real estate and financial services. Currently, Mr. Murphy serves +on the board of directors of several Canadian publicly reporting companies that have interests in various industries. He has been +a Director at Empire Minerals Corporation Inc. since January 2016, at Digicrypts Blockchain Solutions Inc. since June 2011, at +Lakefield Marketing Corporation since February 2018, CEO/CFO and Director of Credo Resources Inc. since September 2019, and at +the Mosport Park Entertainment Corporation since April 30, 1997. He served as a Director at Aurquest Resources from May 2003 to +December 2017. Mr. Murphy’s experience in the capital markets outside the United States and his involvement in investment +analysis is a benefit to the Board of Directors. +Richard +Serbin has been a member of our Board of Directors since May 2017. Mr. Serbin currently serves as a consultant to many companies +in the healthcare industry. He was the President of Corporate Development and In-House Legal Counsel at Life Science Institute, +LLC, from June 1, 2013 to July 15, 2014. Mr. Serbin is a global strategy advisor, pharmacist and entrepreneur with credentials +both in pharmacy and law, complemented by more than 40 years of service as an FDA regulatory attorney and patent attorney in the +healthcare industry. He was appointed to the Advisory Board of Cure Pharmaceutical in January 2017 and has been a Member of Advisory +Board at Prime Access, Inc. since September 2015. Mr. Serbin has been a Director at Rapid Nutrition Plc since November 18, 2014. +He served as Director at Viropro Inc. from May 2013 to June 2014. He was Head of Business Advisory Board at Mazal Plant Pharmaceuticals +Inc. from October 2006 to September 2007 and also served as its Member of Business Advisory Board. He served as Chief Executive +Officer of Optigenex Inc. from July 2002 to September 15, 2005 and a director from July 2004 to September 2005. From January 1999 +until July 2002 Mr. Serbin served as a consultant to various pharmaceutical companies. He served as the President of Bradley Pharmaceuticals. +He served as Vice President of Corporate Development at Ortho Pharmaceuticals, a Johnson & Johnson subsidiary, and practiced +Patent and FDA law at Revlon Johnson & Johnson and Schering-Plough. He served as Patent Attorney for Schering Plough Corporation +and Chief FDA Counsel for Revlon Corporation and Johnson and Johnson Corporation. Subsequently, he worked at Revlon Corporation, +as its Chief Food, Drug and Cosmetic Counsel. He founded Radius Scientific Corporation. He was J&J’s Vice President +of Corporate Development, and later led a successful public offering venture based on technology developed at Stanford Medical +School. Mr. Serbin spent a large portion of his career focusing on international markets and clients. While at J&J, Mr. Serbin +served on the Board of Directors of 16 US and international subsidiary companies, including Ethicon, Ortho, J&J Consumer Products, +Pittman-Moore, Mc Neil, and J&J Development Corporation. He worked on multiple international acquisitions and strategic relationships, +and sat on the Board of Directors of several of its international subsidiaries, including those in India, Hong Kong, Japan, Taiwan, +Germany, and England. Mr. Serbin has a B.S. and a B. Pharmacy from Rutgers University and Rutgers University College of Pharmacy, +a J.D. degree from Seton Hall Law School and a Master’s Degree in Trade Regulations and Law from NYU Law School. Mr. Serbin’s +experience in business, law and medicine and knowledge gained as an advisor to the healthcare industry is critical to our Board +of Directors as we continue to commercialize our products. +44 +James +Nelson has been a member of our Board of Directors +since June 2019. Mr. Nelson is the retired Chairman and CEO of Sunworks, Inc., a NASDAQ +traded commercial, agriculture, and residential solar Integrator which he helped found in October 2010. Mr. Nelson currently serves +as strategic advisor to three other publicly traded companies. Jim has spent most of his career working in private equity as a +general partner with Peterson Partners and with Millennial Capital Partners. In addition to his investment and financial responsibilities, +he served as CEO of two of his firms’ portfolio companies. Prior to his years in private equity, Mr. Nelson served as Vice +President of Marketing at Banana Republic, where he managed company-wide marketing, as well as the company’s international +expansion initiative. He was also general manager for Banana Republic’s catalog division. He was Vice President of Marketing +and Corporate Development at Saga Corporation, a multi-billion-dollar food service company. Jim began his executive career over +35 years ago at Bain and Company, a business strategy consulting firm, where he managed teams of consultants on four continents. +Mr. Nelson received his MBA from Brigham Young University, where he graduated summa cum laude and was named the Outstanding Master +of Business Administration Graduate. Mr. Nelson’s advice to the Board of Directors from his experiences as a chief executive +officer and strategic advisor is useful to the Board of Directors. +Involvement +in Certain Legal Proceedings +To +the best of our knowledge, none of our directors or executive officers have, during the past ten years, been involved in any legal +proceedings described in subparagraph (f) of Item 401 of Regulation S-K. +Board +and Committee Matters +We +maintain an audit committee of the board, a compensation committee of the board and a corporate governance committee and a nominating +committee of the board, each of which is discussed below. We did not have a nominating committee of the board until December 2020. +Our board has determined that Messrs. Durenard, Nelson, Murphy and Serbin are “independent” under the definition of +independence in the Marketplace Rules of the NASDAQ listing requirements. +Audit +Committee and Financial Expert +Our +audit committee currently is comprised of Messrs. Durenard, Nelson, Murphy and Serbin with Mr. Durenard serving as chairman of +the audit committee. The functions of the audit committee include engaging an independent registered public accounting firm to +audit our annual financial statements, reviewing the independence of our auditors, the financial statements and the auditors’ +report, and reviewing management’s administration of our system of internal control over financial reporting and disclosure +controls and procedures. The Board of Directors has adopted a written audit committee charter. A current copy of the audit committee +charter is available to security holders on our website at www.codiagnostics.com. Our board has determined that all of our directors +that are serving on the audit committee are “independent” under the definition of independence in the Marketplace +Rules of the NASDAQ listing standards. +Our +Board of Directors has determined that Mr. Durenard meets the requirements of an “audit committee financial expert” +as defined in applicable SEC regulations. +Compensation +Committee +Our +compensation committee currently includes Messrs. Serbin, Nelson, Murphy and Durenard with Mr. Serbin serving as chairman of the +compensation committee. The functions of the compensation committee include reviewing and approving corporate goals relevant to +compensation for executive officers, evaluating the effectiveness of our compensation practices, evaluating and approving the +compensation of our chief executive officer and other executives, recommending compensation for board members, and reviewing and +making recommendations regarding incentive compensation and other employee benefit plans. The Board of Directors has adopted a +written compensation committee charter. A current copy of the compensation committee charter is available to shareholders on our +website at www.codiagnostics.com . Our board has determined that all of our directors serving on the compensation committee +are “independent” under the definition of independence in the Marketplace Rules of the NASDAQ listing standards. +45 +Corporate +Governance Committee +Our +corporate governance committee currently include Messrs. Nelson, Murphy, Durenard and Serbin with Mr. Nelson serving as chairman +of the corporate governance committee. The functions of the corporate governance committee is to periodically evaluate and assess +the performance of the officers and directors to ascertain if the officers and directors are in compliance with the Company’s +stated policies and procedures and in compliance with the rules and regulations of the SEC and NASDAQ and the committee also reviews +the composition of each committee of the Board of Directors. A current copy of the corporate governance a committee charter is +available to shareholders on our website at www.codiagnostics.com . Our board has determined all directors serving on the +corporate governance committee are “independent” under the definition of independence in the Marketplace Rules of +the NASDAQ listing standards. +Nominating +Committee +Our +nominating committee currently is comprised of Messrs. Durenard, Nelson, Murphy and Serbin with Mr. Murphy serving as chairman +of the nominating committee. The nominating committee reviews the qualifications for candidates for the Board of Directors and +assists in identifying, interviewing, and recruiting candidates for the Board of Directors. A current copy of the nominating committee +charter is available to shareholders on our website at www.codiagnostics.com . Our board has determined all directors serving +on the nominating committee are “independent” under the definition of independence in the Marketplace Rules of the +NASDAQ listing standards. +We +do not have a formal policy concerning shareholder recommendations of candidates for board of director membership. Our board views +that such a formal policy is not necessary at the present time given the board’s willingness to consider candidates recommended +by shareholders. Shareholders may recommend candidates by writing to our Secretary at our principal offices: 2401 S. Foothill +Drive, Suite D, Salt Lake City, Utah 84109, giving the candidate’s name, contact information, biographical data and qualifications. +A written statement from the candidate consenting to be named as a candidate and, if nominated and elected, to serve as a director +should accompany any such recommendation. Shareholders who wish to nominate a director for election are generally advised to submit +a shareholder proposal no later than December 31 for the next year’s annual meeting of shareholders. +Communication +with the Board +We +have not, to date, developed a formal process for shareholder communications with the board of directors. We believe our current +informal process, in which any communication sent to the board of directors, either generally or in care of the chief executive +officer, secretary or other corporate officer or director, is forwarded to all members of the board of directors, has served the +board’s and the shareholders’ needs. +Conflicts +of Interests +On +an annual basis, each director and executive officer is obligated to complete a director and officer questionnaire that requires +disclosure of any transactions with our company, including related person transactions reportable under SEC rules, in which the +director or executive officer, or any member of his or her immediate family, have a direct or indirect material interest. Under +our company’s standards of conduct for employees, all employees, including the executive officers, are expected to avoid +conflicts of interest. Pursuant to our code of ethics for the chief executive officer and senior finance officers (as discussed +below), such officers are prohibited from engaging in any conflict of interest unless a specific exception has been granted by +the board. All of our directors are subject to general fiduciary standards to act in the best interests of our company and our +shareholders. Conflicts of interest involving an executive officer or a director are generally resolved by the board. +Delinquent +Section 16(a) Reports +Section +16(a) of the Exchange Act requires our directors and executive officers, and persons who own more than 10% of our common stock, +to file with the SEC initial reports of ownership and reports of changes in ownership of our common stock and other equity securities. +Executive officers, directors and greater than 10% shareholders are required by SEC regulations to furnish us with copies of all +Section 16(a) forms they file. +The Company +prepares these reports for its directors and executive officers who request it on the basis on information obtained from them +and the Company’s records. The Company believes that applicable Section 16(a) filing requirements were met during 2020 by +its directors and executive errors, except that due to inadvertent administrative errors, a Form 3 and two Forms 4 for Eugene +Durenard that were filed late, one Form 4 for Dwight Egan that was filed late, and three Forms 4 for Richard Serbin that were +filed late. +46 +Code +of Ethics +We +have adopted a code of ethics for our principal executive officer, principal financial officer, controller, or persons performing +similar functions. A copy of the code of ethics is included on our website at www.codiagnostics.com. +Family +Relationships +There +are no family relationships among our directors and executive officers. +ITEM +11. EXECUTIVE COMPENSATION +Throughout +this section, the individuals who served as our chief executive officer and chief financial officer during 2020 and 2019 are collectively +referred to as the “named executive officers.” +The +compensation committee has overall responsibility to review and approve our compensation structure, policy and programs and to +assess whether the compensation structure establishes appropriate incentives for management and employees. The compensation committee +annually reviews and determines the salary and any bonus and equity compensation that may be awarded to our chief executive officer, +or CEO, and our chief financial officer, or CFO. The compensation committee oversees the administration of our long-term incentive +plan and employee benefit plans. +The +compensation committee’s chairman regularly reports to the board on compensation committee actions and recommendations. +The compensation committee has authority to retain, at our expense, outside counsel, experts, compensation consultants and other +advisors as needed. +Company +Performance . Because of the stage of our company’s development, the compensation committee looks at various factors +in evaluating the progress the company has made and the services provided by the named executive officers. In considering executive +compensation, the compensation committee noted certain aspects of our financial performance and accomplishments in 2020 and 2019 +including the following: (a) The Company’s extraordinary performance during the pandemic that resulted in the Company’s +first profitable year (b) Development Milestones, (c) Financial Milestones and (d) Sales and Marketing Milestones. +Compensation +Philosophy . Our general compensation philosophy is designed to link an employee’s total cash compensation with our performance, +the employee’s department goals and individual performance. Given our stage of operations and until recently, limited capital +resources, we were subject to various financial restraints in our compensation practices. As an employee’s level of responsibility +increases, there is a more significant level of variability and compensation at risk. The compensation committee believes linking +incentive compensation to our performance creates an environment in which our employees are stakeholders in our success and, thus, +benefits all shareholders. +Executive +Compensation Policy . Our executive compensation policy is designed to establish an appropriate relationship between executive +pay and our annual performance, our long-term growth objectives, individual performance of the executive officer and our ability +to attract and retain qualified executive officers. The compensation committee attempts to achieve these goals by integrating +competitive annual base salaries with bonuses based on corporate performance and on the achievement of specified performance objectives, +and to a lesser extent, awards through our long-term incentive plan. The compensation committee believes that cash compensation +in the form of salary and bonus provides our executives with short-term rewards for success in operations. The compensation committee +also believes our executive compensation policy and programs do not promote inappropriate risk-taking behavior by executive officers +that could threaten the value of our company. +47 +In +making compensation decisions, the compensation committee compares each element of total compensation against companies referred +to as the “compensation peer group.” The compensation peer group is a group of companies that the compensation committee +selected from readily available information about small companies engaged in similar businesses and with similar resources. The +compensation committee selected these companies from research on its own and with limited consultation with outside consultants +given the size of the company and its resources to retain such experts. The types of companies selected for the peer group included +publicly-traded technology development companies in the diagnostic testing industry. Since there are relatively few companies +in the rather narrow field of diagnostic testing the comparisons were limited to those that are publicly traded whose financial +information could be readily accessed. The compensation committee determined these companies were appropriate for inclusion in +the peer group because of the similar nature of their businesses and their general stage of development and financial resources. +Role +of Executive Officers in Compensation Decisions +The +compensation committee makes all compensation decisions for the named executive officers and approves recommendations regarding +equity awards to all of our other senior management personnel. The CEO annually reviews the performance of the CFO and other senior +management. The conclusions reached and recommendations based on these reviews, including with respect to salary adjustments and +annual award amounts, are presented to the compensation committee. The compensation committee is charged with the responsibility +of ensuring a consistent compensation plan throughout the company and providing an independent evaluation of the proposed adjustments +or awards at all levels of management. As such, the compensation committee has determined that it have the discretion to modify +or adjust any proposed awards and changes to management compensation to be able to satisfy these responsibilities. +Equity +Incentive Plans +Under +our Amended and Restated 2015 Long-term Incentive Plan (the “2015 Plan”), the board of directors may issue incentive +stock-based awards to employees, directors and consultants of the company. Options awarded generally expire ten years after being +granted. Any stock-based awards granted vest in accordance with the vesting schedule determined by the board of directors. Should +an employee’s director’s or consultant’s relationship with the company terminate before the vesting period is +completed, the unvested portion of each grant is forfeited. We continue to maintain and grant awards under the 2015 Plan which +will remain in effect its expiration by its terms. The number of unissued stock-based awards authorized under the 2015 Plan at +December 31, 2020 was 3,278,683. In 2020, we issued 75,000 RSUs to our CEO, 27,500 RSUs to our CFO, 17,000 RSUs to an independent +director and 10,000 RSUs to an independent director. In January 2021, we issued an aggregate of 150,000 RSUs to the four independent +members of our Board of Directors. In February 2021, we issued 30,000 RSUs to our newly appointed CFO. +The +purpose of our incentive plan is to advance the interests of our stockholders by enhancing our ability to attract, retain and +motivate persons who are expected to make important contributions to the company by providing them with both equity ownership +opportunities and performance-based incentives intended to align their interests with those of our stockholders. These plans are +designed to provide us with flexibility to select from among various equity-based compensation methods, and to be able to address +changing accounting and tax rules and corporate governance practices by optimally utilizing stock-based awards. +Summary +Compensation Table +The +table below summarizes the total compensation paid or earned by each of the named executive officers in their respective capacities +for the fiscal years ended December 31, 2020 and 2019. When setting total compensation for each of the named executive officers, +the compensation committee reviewed tally sheets which show the executive’s current compensation, including equity and non-equity-based +compensation. We have omitted in this report certain columns otherwise required to be included because there was no compensation +made with respect to such columns, as permitted by applicable SEC regulations. +48 +Name and Principal Position +Year +Salary +Bonus (1) +Stock +Awards (2) +Option +Awards (3) +All Other +Comp (4) +Total +Compensation +Dwight Egan +2020 +$ 309,375 +$ 350,000 +$ 786,750 +$ - +$ 17,500 +$ 1,463,625 +President & Chief Executive Officer +2019 +$ 275,000 +$ 20,000 +$ - +$ 165,000 +$ - +$ 460,000 +Reed Benson +2020 +$ 211,458 +$ 225,000 +$ 288,475 +$ - +$ 17,500 +$ 742,433 +Chief Financial Officer and Secretary +2019 +$ 200,000 +$ 15,000 +$ - +$ 137,500 +$ - +$ 352,500 +(1) +Bonuses +for the year ended December 31, 2020 include accrued bonus payments of $272,500 to Mr. Egan and $180,000 to Mr. Benson that +were paid in February 2021. +(2) +The +amounts reported in this column represent the aggregate grant date fair value of the restricted stock units, or RSUs, granted +under our 2015 Plan as computed in accordance with FASB ASC Topic 718. Note that the amounts reported in this column reflect +the accounting value for these equity awards and do not correspond to the actual economic value that may be received from +the equity awards as the RSUs vest over three years. +(3) +The +amounts reported in this column represent the aggregate grant date fair value of the options granted under our 2015 Plan as +computed in accordance with FASB ASC Topic 718. Note that the amounts reported in this column reflect the accounting value +for these option awards and do not correspond to the actual economic value that may be received from the options. The options +vest over two years. +(4) +Reflects +the amount of royalty payments made to Dr. Satterfield pursuant to a technology license agreement that was amended in January +2017 to terminate the ongoing royalties. The payments reduced accrued royalties. The amounts for Mr. Egan and Mr. Benson represent +Company profit sharing payments to the Company’s 401 K Plan. +Other +Compensation +We +do not have any non-qualified deferred compensation plan. +Outstanding +Equity Awards at Fiscal Year-End 2020 +The +following table contain certain information concerning outstanding equity awards for the Named Executive Officers as of December +31, 2020. +Option Awards +Stock Awards +Number of Securities +Underlying Unexercised +Options (#) +Option +Exercise +Option Expiration +Number of +Shares or +Units of +Stock That +Have Not +Market Value +of Shares or +Units of Stock +That Have +Not Vested +Number of +Unearned +Shares, Units +or Other +Rights That +Have Not +Market or +Payout Value +of Unearned +Shares, Units +or Other +Rights That +Have Not +Name +Exercisable +Unexercisable +Price +Date +Vested (#) +($)(1) +Vested (#) +Vested ($) +Dwight Egan +100,000 +- +$ 2.63 +09/20/28 +- +- +- +- +- +50,000 +$ 1.10 +09/02/29 +- +- +- +- +- +- +- +- +75,000 +$ 697,500 +- +- +Reed Benson +108,333 +- +$ 2.63 +09/20/28 +- +- +- +- +- +41,667 +$ 1.10 +09/02/29 +- +- +- +- +- +- +- +- +27,500 +$ 255,750 +- +- +(1) +Based +on $9.30 per share which was the closing price of our common stock on December 31, 2020. +49 +Potential +Payments Upon Termination or Change of Control +There +is no compensation payable to the named executive officers upon voluntary termination, retirement, involuntary not-for-cause termination, +termination following a change of control or in the event of disability or death of the executive. +Compensation +Committee Interlocks and Insider Participation in Compensation Decisions +None +of our executive officers served as a member of the compensation committee or as a director of any other company. +Director +Compensation +We +use a combination of cash and stock-based incentive compensation to attract and retain qualified candidates to serve on its board +of directors. In setting director compensation, we consider the significant amount of time that directors expend in fulfilling +their duties as well as the skill-level required by our members of the board. +Our +non-employee directors in 2020 generally received fees of $35,000 per year, paid quarterly, $10,000 per year for serving as chairman +of any Board committee and $5,000 for serving as a member of other Board committees. In addition, each director receives an initial +grant of stock options to purchase 25,000 shares (thereafter annual grants of 25,000 options or restricted stock units) of our +common stock with an exercise price equal to the fair market value of the stock on the date of grant. The board approved and the +non-employee directors accepted the 2020 and 2019 compensation set forth in the director summary compensation table below. Beginning +in 2021, non-employee director cash compensation will be $75,000 per year. In addition, the directors will receive 37,500 RSU’s +vesting 1/3 rd equally in January 2021, 2022, and 2023. In addition, non-employee directors may be entitled to receive +special awards of stock options or RSUs from time to time as determined by the board. The chairman of the board and the chairman +of each of the audit and compensation committees receive no additional fees for serving in such capacities, except as shown above. +There is no additional compensation for meeting attendance. Directors who are employees of the Company receive no additional compensation +for serving as directors. All stock options granted to outside directors are immediately exercisable and expire ten years from +the date of grant or 30 days after the date they cease to be directors. Directors are reimbursed for ordinary expenses incurred +in connection with attending board and committee meetings. +Director +Summary Compensation Table +The +table below summarizes the compensation paid or accrued by us to our directors for the fiscal year ended December 31, 2020. +Name +Fees +Earned or +Paid in Cash +Stock +Awards: +Value of Options +(1) +Stock +Awards: +Value of +Restricted +Stock +Units (2) +Total +Dwight Egan (3) +$ - +$ - +$ - +$ - +Richard Serbin +$ 68,500 +$ 70,000 +$ 178,330 +$ 316,830 +James Nelson +$ 55,000 +$ 70,000 +$ - +$ 125,000 +Edward Murphy +$ 36,000 +$ 70,000 +$ - +$ 106,000 +Eugene Durenard +$ 55,000 +$ 70,000 +$ 104,900 +$ 229,900 +(1) +The +amounts reported in this column represent the aggregate grant date fair value of the options granted under our 2015 Plan as +computed in accordance with FASB ASC Topic 718. Note that the amounts reported in this column reflect the accounting value +for these option awards and do not correspond to the actual economic value that may be received from the options. The options +vest immediately upon grant. +(2) +The +amounts reported in this column represent the aggregate grant date fair value of the restricted stock units, or RSUs, granted +under our 2015 Plan as computed in accordance with FASB ASC Topic 718. Note that the amounts reported in this column reflect +the accounting value for these equity awards and do not correspond to the actual economic value that may be received from +the equity awards. The RSUs vested immediately upon grant. +(3) +Mr. +Egan receives no compensation for serving as a director, but is compensated in his capacity as the Company’s President. +50 +ITEM +12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The +following table sets forth certain information, as of March 17, 2021, with respect to the holdings of (1) each person who is the +beneficial owner of more than 5% of our Common Stock, (2) each of our directors, (3) each named executive officer, and (4) all +of our current directors and executive officers as a group. +Beneficial +ownership of the common stock is determined in accordance with the rules of the Securities and Exchange Commission and includes +any shares of common stock over which a person exercises sole or shared voting or investment power, or of which a person has a +right to acquire ownership at any time within 60 days of March 17, 2021. Except as otherwise indicated, we believe that the persons +named in this table have sole voting and investment power with respect to all shares of common stock held by them. Applicable +percentage ownership in the following table is based on 28,665,714 shares of common stock plus, for each individual, any securities +that individual has the right to acquire within 60 days of March 17, 2021. +To +the best of our knowledge, except as otherwise indicated, each of the persons named in the table has sole voting and investment +power with respect to the shares of our common stock beneficially owned by such person, except to the extent such power may be +shared with a spouse. To our knowledge, none of the shares listed below are held under a voting trust or similar agreement, except +as noted. To our knowledge, there is no arrangement, including any pledge by any person of securities of the Company, the operation +of which may at a subsequent date result in a change in control of the Company. The information in the tables below is based on +information known to us or ascertained by us from public filings made by the stockholders. Except as otherwise indicated in the +table below, addresses of the director, executive officers and named beneficial owners are in care of Co-Diagnostics, Inc., 2401 +S. Foothill Drive, Suite D, Salt Lake City, Utah 84109. +Number of Shares Beneficially Owned +Percentage +of Class (1) +5% Stockholders +Reagents, LLC (1) +1,746,796 +6.1 % +Vanguard Group (2) +1,613,884 +5.6 % +Blackrock, Inc. (3) +1,921,670 +6.7 % +Named Executive Officers and Directors +Dwight Egan (4) +50,000 +* +Reed Benson (5) +108,333 +* +Brian Brown +- +* +Edward Murphy (6) +62,500 +* +Eugene Durenard +- +* +James Nelson (7) +50,000 +* +Richard Serbin (8) +20,445 +* +All Directors and Executive Officers as a Group (7 persons) +291,278 +1.0 % +*Represents +beneficial ownership of less than 1%. +(1) +Reagents, +LLC, with an address of 8160 S. Highland Drive, Salt Lake City, UT 84093, is beneficially owned by Seth Egan. +(2) +Vanguard +Group with an address of 100 Vanguard Blvd, Malvern, PA, 19355; +(3) +Blackrock, +Inc. with an address of 55 E 52 Street, New York, NY, 10055. +(4) +Consists +of exercisable options to acquire 50,000 shares of common stock. +(5) +Consists +of exercisable options to acquire 108,333 shares of common stock. +(6) +Consists +of exercisable options to acquire 50,000 shares of common stock. +(7) +Consists +of exercisable options to acquire 50,000 shares of common stock. +(8) +Consists +of exercisable options to acquire 50,000 shares of common stock. +51 +ITEM +13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +The +Company acquired the exclusive rights to the CoPrimer technology pursuant to a license agreement dated April 2014, between us +and DNA Logix, Inc., which was assigned to Dr. Satterfield prior to our acquisition of DNA Logix, Inc. Pursuant to the license +the Company was to pay Dr. Satterfield minimum royalty payments of $30,000 per month until the Company receives an equity funding +of at least $4,000,000, at which time the payments increase to $60,000 per month for the remainder of the year. The payment terms +were orally modified to maintain the monthly royalties at $30,000 per month through December 2016. On March 1, 2017, the Company +entered into an amendment effective January 1, 2017, to its Exclusive License Agreement for its CoPrimer (“License”) +technology with Dr. Satterfield, a former member of our Board of Directors. The amendment provides in part that all royalties +under the License cease as of January 1, 2017, and we began in January 2017 to pay $700,000 of accrued royalties at the rate of +$10,000 per month. In 2020 and 2019, we paid Dr. Satterfield $120,000 and $110,000, respectively, in payment of the accrued royalties. +The +Company entered into a consulting arrangement with its director, Richard Serbin, for consulting services during the year ended +December 31, 2019. Pursuant to the consulting agreement, we paid Mr. Serbin a one-time fee of $30,000. In payment for extra ordinary +services during the year, we granted our directors Richard Serbin and Eugene Durenard 17,000 RSUs and 10,000 RSUs, respectively. +ITEM +14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +The +following table presents aggregate fees for professional services rendered by our independent auditors for the respective periods. +Years Ended December 31, +2020 +2019 +Audit fees +$ 115,000 +$ 74,000 +Audit related fees +- +- +Other consulting fees +- +- +Tax fees +1,000 +3,000 +Total fees +$ 116,000 +$ 77,000 +Audit +fees consist of fees for professional services provided in connection with the audit of our annual consolidated financial statements, +review of our quarterly consolidated financial statements and our offerings. +Tax +fees included fees associated with tax compliance and tax consultations. +The +audit committee has adopted a policy that requires advance approval of all services performed by the independent auditor when +fees are expected to exceed $15,000. The audit committee has delegated to the audit committee chairman, Mr. Durenard, the authority +to approve services, subject to ratification by the audit committee at its next committee meeting. All fees incurred were pre-approved +by the audit committee. +52 +PART +IV +Item +15. Exhibits, Financial Statement Schedules. +Exhibit +Number +Description +3.1 +Articles of Incorporation (1) +3.1.1 +Amendment to the Articles of Incorporation (1) +3.2 +Bylaws (1) +4.1 +Description of Registrant’s securities +10.1 +Subscription Agreement between Co-Diagnostics, Inc. and Co-Diagnostics, Ltd., dated April 30, 2013 (1) +10.1.1 +Amendment to Subscription Agreement between Co-Diagnostics, Inc. and CoDiagnostics, Ltd., dated May 1, 2015 (1) +10.2 +Exclusive Agreement between Co-Diagnostics, Inc. and DNA Logix, Inc., dated April 18, 2014 (1) +10.3 +Stock Exchange Agreement among Co-Diagnostics, Inc., DNA Logix, Inc., and the Shareholders of DNA Logix, Inc., dated January 22, 2015 (1) +10.4 +Revolving Line of Credit Promissory Note between Co-Diagnostics, Inc. and Co-Diagnostics, LTD, dated August 1, 2015 (1) +10.5 +10% Convertible Note between Co-Diagnostics, Inc. and Robert Salna for $200,000, dated September 1, 2016 (1) +10.6 +Exclusive License Agreement between Co-Diagnostics, Inc. and Watermark Group Inc., dated October 13, 2016 (1) +10.7 +Securities Purchase Agreement with Exhibits between Co-Diagnostics and Senior Holders, dated December 12, 2016 (1) +10.7.1 +Form of Amendment Agreement (6) +10.8 +Securities Purchase Agreement with Exhibits between Co-Diagnostics and Beaufort Capital Partners, LLC, dated December 12, 2016 (1) +10.9 +2015 Long-Term Incentive Plan (2) +10.10 +Subscription Agreement between Co-Diagnostics and Co-Diagnostics, Ltd. for 454,545 shares of Co-Diagnostic’s common stock, dated April 20, 2013 (3) +10.11 +Subscription Agreement between Co-Diagnostics and Prosperity Investments for $100,000, dated June 2014. (3) +10.12 +12% Convertible Note between Co-Diagnostics, Inc. and Beaufort Capital Partners, LLC for $500,000, dated May 15, 2015 (3) +10.13 +Form Revolving Line of Credit Promissory Note between Co-Diagnostics and Turks and Caicos Limited Company, Pine Valley Investments, LLC, Clavo Rico Incorporated, Legends Capital Group, LLC, Hamilton Mining Resources, Inc., and Machan 1988 Property Trust. (3) +53 +10.13.1 +Amendment to 12% Revolving Line of Credit Promissory Note, dated August 1, 2015, between Co-Diagnostics and Co-Diagnostics, Ltd., for $750,000, dated September 14, 2016. (3) +10.13.2 +Amendment to 12% Revolving Line of Credit Promissory Note, December 30, 2015, between Co-Diagnostics and Pine Valley Investments, LLC for $100,000, dated September 14, 2016. (3) +10.13.3 +Amendment to 12% Revolving Line of Credit Promissory Note, February 22, 2016, between Co-Diagnostics and Clavo Rico Incorporated for $10,000, dated September 14, 2016. (3) +10.13.4 +Amendment to 12% Revolving Line of Credit Promissory Note, March 1, 2016, between Co-Diagnostics and Legends Capital Group, LLC for $100,000, dated September 14, 2016. (3) +10.13.5 +Amendment to 12% Revolving Line of Credit Promissory Note, May 15, 2016, between Co-Diagnostics and Hamilton Mining Resources, Inc. for $75,000, dated September 14, 2016. (3) +10.13.6 +Amendment to 12% Revolving Line of Credit Promissory Note, May 30, 2016, between Co-Diagnostics and Machan 1988 Property Trust for $50,000, dated September 14, 2016. (3) +10.13.7 +Form Second Amendment to 12% Revolving Line of Credit Promissory Note Due 2017 between Co-Diagnostics, Inc. and CoDiagnostics, Ltd., Pine Valley Investments, LLC, Clavo Rico Incorporated, Legends Capital Group, LLC, and Hamilton Mining Resources, Inc. (4) +10.13.8 +Form of Indemnification Agreement. (4) +10.14 +Form 8.5% Convertible Note between Co-Diagnostics and Legends Capital Group, LLC for $100,000, dated November 12, 2015 and R. Phillip Zobrist for $100,000, dated December 1, 2015. (3) +10.15 +Form 10% Convertible Note between Co-Diagnostics and Legends Capital Opportunity Fund, LLC for $15,000, DAV Capital Management Corp. for $15,000, April Kameka for $40,000, and Mark Kovacic for $50,000. (3) +10.16 +Shareholders’ Agreement between Co-Diagnostics and Synbiotics Limited, dated January 27, 2017. (3) +10.17 +Amended Exclusive License Agreement between Co-Diagnostics, Brent Satterfield, and DNA Logix, Inc., dated January 1, 2017. (3) +10.18 +Stock Purchase Agreement between Co-Diagnostics and Ted Murphy for 1,800,000 shares of Watermark Group, Inc.’s common stock, dated September 22, 2016. (3) +10.19 +Non-Interest Bearing Note between Co-Diagnostics and Zika Diagnostics, Inc. f/k/a/ Watermark Group, Inc. for $445,000, dated March 20, 2017. (3) +10.20 +Mutual Rescission Agreement of the Stock Purchase Agreement, dated September 22, 2016, and the License Agreement, dated October 13, 2016, between Co-Diagnostics, Robert Salna, and Ted Murphy, dated March 30, 2017. (3) +14.1 +Code of Ethics of the Company (7) +21.1 +Subsidiaries of Registrant (1) +23.1 +Consent of Haynie & Company +31.1 +Certification of Chief Executive Officer pursuant to section 302 of the Sarbanes-Oxley Act of 2002 +31.2 +Certification of Principal Financial Officer pursuant to section 302 of the Sarbanes-Oxley Act of 2002 +32.1 +Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 +32.2 +Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 +* +Management +contract or compensatory plan or arrangement. +(1) +Incorporated +by reference to the Draft Registration Statement filed with the SEC on January 11, 2017. +(2) +Incorporated +by reference to the Draft Registration Statement filed with the SEC on March 27, 2017. +(3) +Incorporated +by reference to the Form S-1 filed with the SEC on April 28, 2017. +(4) +Incorporated +by reference to the Form S-1/A filed with the SEC on May 24, 2017. +(5) +Incorporated +by reference to the Form S-1/A filed with the SEC on June 9, 2017. +(6) +Incorporated +by reference to the Form S-1/A filed with the SEC on June 23, 2017. +(7) +Incorporated +by reference to the Form 10-K for the fiscal year ended December 31, 2019 filed, with the SEC on March 30, 2020 +54 +SIGNATURES +Pursuant +to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf +by the undersigned thereunto duly authorized. +CO-DIAGNOSTICS, +INC. +Date: +March 25, 2021 +By: +/s/ +Dwight Egan +Dwight +Egan +Chief +Executive Officer, President and Director +(Principal +Executive Officer) +By: +/s/ +Brian Brown +Brian +Brown +Chief +Financial Officer +(Principal +Financial and Accounting Officer +In +accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in +the capacities Indicated. +Signature +Title +Date +/s/ +Dwight Egan +Chief +Executive Officer, President and Director +March +25, 2021 +Dwight +Egan +(Principal +Executive Officer) +/s/ +Brian Brown +Chief +Financial Officer +March +25, 2021 +Brian +Brown +(Principal +Financial and Accounting Officer) +/s/ +Eugen Durenard +Director +March +25, 2021 +Eugene +Durenard +/s/ +Edward Murphy +Director +March +25, 2021 +Edward +Murphy +/s/ +James Nelson +Director +March +25, 2021 +James +Nelson +/s/ +Richard Serbin +Director +March +25, 2021 +Richard +Serbin +55 \ No newline at end of file diff --git a/raw/filings/0001692415/2020/0001493152-21-006810/filing_metadata.csv b/raw/filings/0001692415/2020/0001493152-21-006810/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..54fe8fd1bdfba67e45a195bb3cafd9254f8da038 --- /dev/null +++ b/raw/filings/0001692415/2020/0001493152-21-006810/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001692415,CODX,"Co-Diagnostics, Inc.",10-K,2021-03-25,2020-12-31,2021-03-26T00:16:56.000Z,0001493152-21-006810,form10k.htm,,3746825,1,0,https://www.sec.gov/Archives/edgar/data/1692415/000149315221006810/form10k.htm,https://www.sec.gov/Archives/edgar/data/1692415/000149315221006810/,2020,2020,1 diff --git a/raw/filings/0001692415/2020/0001493152-21-006810/item13.txt b/raw/filings/0001692415/2020/0001493152-21-006810/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001692415/2020/0001493152-21-006810/rp_note.txt b/raw/filings/0001692415/2020/0001493152-21-006810/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..54aa7e6667f6d551e542057dd769434d637ed90f --- /dev/null +++ b/raw/filings/0001692415/2020/0001493152-21-006810/rp_note.txt @@ -0,0 +1,10 @@ +10 – Related Party Transactions +The +Company acquired the exclusive rights to the CoPrimer technology pursuant to an exclusive license agreement, dated April 2014 +(the “Exclusive License Agreement”), between the Company and DNA Logix, Inc., which was assigned to Dr. Brent Satterfield, +an executive officer, prior to the Company’s acquisition of DNA Logix, Inc. On March 1, 2017, the Company entered into an +amendment to its Exclusive License Agreement for its Cooperative Primers (“License”) technology with Dr. Satterfield. +The amendment provided in part that all accrued royalties under the License ceased as of January 1, 2017, and the Company agreed +to pay to Dr. Satterfield $700,000 of accrued royalties at the rate of $10,000 per month starting in January 2017. At December +31, 2020, the aggregate balance of this related party liability was $150,000. +Note \ No newline at end of file diff --git a/raw/filings/0001692415/2020/0001493152-21-006810/rpt_disclosure.txt b/raw/filings/0001692415/2020/0001493152-21-006810/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001692415/2021/0001493152-22-007662/filing.txt b/raw/filings/0001692415/2021/0001493152-22-007662/filing.txt new file mode 100644 index 0000000000000000000000000000000000000000..c20fcd1a9d3b7948b108796713612f5be6688412 --- /dev/null +++ b/raw/filings/0001692415/2021/0001493152-22-007662/filing.txt @@ -0,0 +1,4479 @@ +0001692415 +false +FY +P3Y +2024-02-29 +0001692415 +2021-01-01 +2021-12-31 +0001692415 +2021-06-30 +0001692415 +2022-03-23 +0001692415 +2021-12-31 +0001692415 +2020-12-31 +0001692415 +2020-01-01 +2020-12-31 +0001692415 +us-gaap:ConvertiblePreferredStockMember 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15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For +the transition period from_______to_______ +Commission +File Number 001-38148 +CO-DIAGNOSTICS, +INC. +(Exact +Name of Registrant as Specified in Its Charter) +Utah +3841 +46-2609396 +(State +or other jurisdiction of +incorporation +or organization) +(Primary +Standard Industrial +Classification +Code Number) +(I.R.S. +Employer +Identification +Number) +2401 +S. Foothill Drive , Salt Lake City , Utah 84109 +(Address +of principal executive offices and zip code) +(801) +438-1036 +(Registrant’s +telephone number including area code) +Securities +registered pursuant to Section 12(b) of the Act: +Title +of each class +Trading +Symbol(s) +Name +of each exchange on which registered +Common Stock +CODX +The Nasdaq Capital Market +Securities +registered pursuant to Section 12(g) of the Act: None +Indicate +by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No +☒ +Indicate +by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ☐ No +☒ +Indicate +by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act of 1934 +during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject +to such filing requirements for the past 90 days. Yes ☒ No ☐ +Indicate +by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data +File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding +12 months (or such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐ +Indicate +by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting +company or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller +reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. +Large accelerated +filer +☐ +Accelerated +filer +☐ +Non-accelerated filer +☐ +Smaller reporting company +☒ +Emerging growth company +☒ +If +an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying +with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ +Indicate +by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness +of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered +public accounting firm that prepared or issued its audit report. ☐ +Indicate +by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒ +The +aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which +the common stock was last sold as of the last business day of the registrant’s most recently completed second fiscal quarter was +approximately $ 229,000,000 . +As +of March 23, 2022, there were 33,965,318 +shares of common stock, par value $0.001 +per share, outstanding. +Table +of Contents +Page +PART I +Item +1. +Business. +4 +Item +1A. +Risk Factors. +13 +Item +1B. +Unresolved Staff Comments. +16 +Item +2. +Properties. +16 +Item +3. +Legal Proceedings. +16 +Item +4. +Mine Safety Disclosures. +17 +PART II +Item +5. +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. +17 +Item +6. +[Reserved.] +18 +Item +7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations. +18 +Item +7A. +Quantitative and Qualitative Disclosures About Market Risk. +22 +Item +8. +Financial Statements and Supplementary Data. +23 +Item +9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +44 +Item +9A. +Controls and Procedures. +44 +Item +9B. +Other Information. +45 +Item +9C. +Disclosure Regarding Foreign Jurisdictions that Prevent Inspections. +45 +PART III +Item +10. +Directors, Executive Officers and Corporate Governance. +45 +Item +11. +Executive Compensation. +50 +Item +12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. +54 +Item +13. +Certain Relationships and Related Transactions, and Director Independence. +55 +Item +14. +Principal Accountant Fees and Services. +56 +PART IV +Item +15. +Exhibits and Financial Statement Schedules. +56 +2 +PART +I +Forward-Looking +Statements +This +Annual Report on Form 10-K contains “forward-looking statements” that involve risks and uncertainties. All statements other +than statements of historical fact contained in this Annual Report and the documents incorporated by reference herein, including statements +regarding future events, our future financial performance, business strategy, and plans and objectives of management for future operations, +are forward-looking statements. We have attempted to identify forward-looking statements by terminology including “anticipates,” +“believes,” “can,” “continue,” “could,” “estimates,” “expects,” +“intends,” “may,” “plans,” “potential,” “predicts,” “should,” +or “will” or the negative of these terms or other comparable terminology. Although we do not make forward looking statements +unless we believe we have a reasonable basis for doing so, we cannot guarantee their accuracy. These statements are only predictions +and involve known and unknown risks, uncertainties and other factors and the documents incorporated by reference herein, which may affect +our or our industry’s actual results, levels of activity, performance or achievements expressed or implied by these forward-looking +statements. Moreover, we operate in a highly regulated, very competitive, and rapidly changing environment. New risks emerge from time +to time and it is not possible for us to predict all risk factors, nor can we address the impact of all factors on our business or the +extent to which any factor, or combination of factors, may cause our actual results to differ materially from those contained in any +forward-looking statements. +We +have based these forward-looking statements largely on our current expectations and projections about future events and financial trends +that we believe may affect our financial condition, results of operations, business strategy, short term and long-term business operations, +and financial needs. These forward-looking statements are subject to certain risks and uncertainties that could cause our actual results +to differ materially from those reflected in the forward-looking statements. Factors that could cause or contribute to such differences +include, but are not limited to, those discussed in this Annual Report, and in particular, the risks discussed below and under the heading +“Risk Factors” in other documents we file with the SEC. The following discussion should be read in conjunction with the consolidated +financial statements for the fiscal years ended December 31, 2021 and 2020 and notes incorporated by reference therein. We undertake +no obligation to revise or publicly release the results of any revision to these forward-looking statements, except as required by law. +In light of these risks, uncertainties and assumptions, the forward-looking events and circumstances discussed in this Annual Report +may not occur and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statement. +You +should not place undue reliance on any forward-looking statement, each of which applies only as of the date of this Annual Report. Except +as required by law, we undertake no obligation to update or revise publicly any of the forward-looking statements after the date of this +Annual Report to conform our statements to actual results or changed expectations. +You +are advised, however, to consult any further disclosures we make on related subjects in our reports on Forms 10-Q, 8-K and 10-K filed +with the SEC. You should understand that it is not possible to predict or identify all risk factors. Consequently, you should not consider +this list to be a complete set of all potential risks or uncertainties. +Important +factors that could cause actual results to differ materially from those in the forward-looking statements include, without limitation: +● +the results of clinical +trials and the regulatory approval process; +● +market acceptance of any +products that may be approved for commercialization; +● +our ability to protect +our intellectual property rights; +● +the impact of any infringement +actions or other litigation brought against us; +● +competition from other +providers and products; +● +our ability to develop +and commercialize new and improved products and services; +● +changes in government regulation; +● +and other factors (including +the risks contained in the section entitled “Risk Factors” in other documents we file with the SEC) relating to our industry, +our operations and results of operations. +3 +Should +one or more of these risks or uncertainties materialize, or should the underlying assumptions prove incorrect, actual results may differ +significantly from those anticipated, believed, estimated, expected, intended or planned. +Factors +or events that could cause our actual results to differ may emerge from time to time, and it is not possible for us to predict all of +them. We cannot guarantee future results, levels of activity, performance or achievements. Except as required by applicable law, including +the securities laws of the United States, we do not intend to update any of the forward-looking statements to conform these statements +to actual results. +As +used in this Annual Report, the terms “we”, “us”, “our”, “Company” and “Co-Diagnostics” +means Co-Diagnostics, Inc., a Utah corporation and its consolidated subsidiaries (the “Company”), unless otherwise indicated. +ITEM +1: BUSINESS +Overview +Co-Diagnostics, +Inc., a Utah corporation (the “Company” or “CODX”), develops, manufactures and sells reagents used for +diagnostic tests that function via the detection and/or analysis of nucleic acid molecules (DNA or RNA), including robust and innovative +molecular tools for detection of infectious diseases, liquid biopsy for cancer screening, and agricultural applications. In connection +with the sale of our tests we may sell diagnostic equipment from other manufacturers as self-contained lab systems (which we refer to +as the “MDx Device”). We have also developed a unique, groundbreaking portable PCR device (the “CODX YourTest +PCR™ Device”) that has been designed to bring affordable, reliable gold-standard polymerase chain reaction (“PCR”) +to patients in point-of-care and even at-home settings. +Our +diagnostics systems enable dependable, low-cost, molecular testing for organisms and genetic diseases by automating historically complex +procedures in both the development and administration of tests. CODX’s technical advance involves a novel, patented approach +to PCR test design of primer and probe structure (“CoPrimers™”) that eliminates one of the key vexing issues +of PCR amplification, the exponential growth of primer-dimer pairs (false positives and false negatives) which adversely interferes with +identification of the target DNA/RNA. +We +believe our proprietary molecular diagnostics technology is paving the way for innovation in disease detection and life sciences research +through our enhanced detection of genetic material. For various reasons, including owning our own our platform, we believe we will be +able to accomplish this faster and more economically, allowing for significant margins while still positioning the Company to be a low-cost +provider of molecular diagnostics and screening services. +In +addition, continued development has demonstrated the unique properties of our CoPrimer technology that we believe makes it ideally suited +for a variety of applications where specificity is key to optimal results, including multiplexing several targets, enhanced Single Nucleotide +Polymorphism (“SNP”) detection and enrichment for next generation sequencing. +Our +scientists use the complex mathematics of DNA/RNA test design to engineer and optimize DNA/RNA tests and to automate algorithms that +rapidly screen millions of possible options to pinpoint the optimum design. Dr. Brent Satterfield, our founder, developed the Company’s +intellectual property consisting of the predictive mathematical algorithms and patented molecular structure used in the testing process, +which together represent a major advance in PCR testing systems. CODX technologies are now protected by more than 20 granted or pending +US and foreign patents, as well as certain trade secrets and copyrights. Ownership of our proprietary platform permits us the advantage +of avoiding payment of patent royalties required by other PCR test systems, which may allow the sale of diagnostic PCR tests at a lower +price than competitors, while enabling us to maintain profit margins. +We +may either sell or lease the MDx Device to labs and diagnostic centers, through sale or lease agreements, and sell the reagents that +comprise our proprietary tests to those laboratories and testing facilities. +Our +proprietary test design process involves identifying the optimal locations on the target genes for amplification and pair the locations +with the optimized primer and probe structure to achieve outputs that meet the design input requirements identified from market research. +This is done by following planned and documented processes, procedures and testing. In other words, we use the data resulting from our +tests to verify whether we succeeded in designing what we intended at the outset. Verification is a series of testing that concludes +that the product is ready to proceed to validation in an evaluation either in our laboratory or in an independent laboratory setting +using initial production tests to confirm that the product as designed meets the user needs. +4 +Using +our proprietary test design system and proprietary reagents, we have designed and obtained regulatory approval in the European Community +and/or in India to sell PCR diagnostic tests for the detection of COVID-19, influenza, tuberculosis, hepatitis B and C, human papillomavirus, +malaria, chikungunya, dengue, and the zika virus. In the United States, CODX has obtained Emergency Use Authorization (“EUA”) +for its Logix Smart ™ COVID-19 detection test from the Food and Drug Administration, +or FDA, and sells that test to qualified labs. In addition, our COVID-19 detection test and certain of our other suite of COVID-19 products +have been approved for sale in countries such as the United Kingdom, Australia and Mexico by the regulatory bodies in those countries +and have been registered for sale in many more countries. +In +addition to testing for infectious disease, the technology lends itself to identifying any section of a DNA or RNA strand that describe +any type of genetic trait, which creates a number of significant applications. We, in conjunction with our customers, are active in designing +and licensing tests that identify genetic traits in plant and animal genomes. We also have three multiplexed tests developed to test +mosquitos for the identification of diseases carried by the mosquitos to enable municipalities to concentrate their efforts in managing +mosquito populations on the specific areas known to be breeding the mosquitos that carry deadly viruses. +On +January 23, 2020, we announced the completion of the principal design work for a PCR test for the new coronavirus, later named COVID-19, +intended to address the potential need for detection of the virus. This test features the Company’s patented CoPrimer technology, +and was designed using our proprietary software system, following the guidelines published by the World Health Organization (WHO) and +Centers for Disease Control (CDC). +On +February 24, 2020, we announced that this test had obtained regulatory clearance to be sold as an IVD for the diagnosis of COVID-19 in +markets that accept CE-marking as valid regulatory approval, and became available for purchase from the Company’s Utah-based ISO-13485:2016 +certified facility—the first US-based company to obtain such a marking for a COVID-19 test. +We +commenced sales of the COVID-19 tests in February and March of 2020 to international customers and to date have since sold over 30,000,000 +of this and other COVID tests in numerous countries around the world through an expanding distributor network. +On +April 6, 2020, we announced that we had received an Emergency Use Authorization from the FDA allowing us to commence sales of our Logix +Smart™ COVID-19 test to laboratories certified by the Center for Medicare and Medicaid Services under the Clinical Laboratories +Improvements Act (“CLIA”) to accept human samples for diagnostics testing throughout the United States and have sold our +Logix Smart™ COVID-19 test to such CLIA labs since that time. +Because +we believe that testing for COVID-19 is going to be a consideration for public health worldwide even after the current pandemic has subsided, +we have initiated the Eikon platform to facilitate frequent testing in homes, schools, businesses, and the hospitality industry. We believe +this may be accomplished through the development of a low-cost testing device, easy to use by non-professionals, that can provide PCR +test results in around 30 minutes. The initial project built on this platform, an at-home and point-of-care COVID-19 PCR test, was ultimately +facilitated by our development of a saliva or nasal swab-based PCR test that does not require the RNA/DNA extraction. While the final +result is believed to be approximately equivalent to those processed by a high-complexity clinical laboratory, it has the advantages +of increased speed and ease of handling thanks to lyophilization (or freeze-drying) of our testing reagents to allow for stability at +room temperatures. +On +February 15, 2021, we engaged the services of a group of professionals at Idaho Molecular, Inc and Advanced Conceptions, Inc (the “Entities,”) +with the expertise to develop the hardware for such a device using our CoPrimers™ as the reagent chemistry. On December +22, 2021, we announced that we would be acquiring the Entities along with all existing and future assets and intellectual property related +to the platform and device. It is expected that the device and test will be available to homes, schools, offices, and the travel industry +among other locations at a cost that will allow screening frequently to prevent spread of the COVID-19 virus in the future. The device +would also be available to test for other pathogens detectable through saliva or other samples as we develop those tests and offer them +to the marketplace. All such tests will be subject to regulatory approval. +5 +Infectious +Disease Product Offering +Using +our proprietary test design system and proprietary reagents, we and CoSara Diagnostics Pvt Ltd (“CoSara”), our joint venture +for manufacturing in India, design and sell PCR diagnostic tests for detection of diseases and pathogens such as COVID-19, tuberculosis, +hepatitis B and C, malaria, dengue, human papillomavirus, chikungunya, and Zika virus, all of which tests have been designed and verified +in our laboratories. Our tuberculosis test and Zika test received a CE Mark in 2018, and a triplex test for Zika, dengue and chikungunya +received a CE Mark in 2019, qualifying the tests to be sold throughout the European community and in most countries in central and South +America. In December, 2019, CoSara received a license to manufacture and sell tuberculosis, hepatitis B, hepatitis C, human papillomavirus +16/18 and malaria tests in India from the Central Drugs Standard Control Organization (“CDSCO”). In February 2020, we received +a CE Mark for our Logix Smart™ COVID-19 test followed by an Emergency Use Authorization by the FDA a few weeks later, and +in April 2020, our COVID-19 test was approved for manufacture and sale in India by the CDSCO and in Mexico by the INDRE, Mexico’s +equivalent to the United States Center for Disease Control. In August 2020, we received approval from the Australian Department of Health +Therapeutic Goods Division to sell our COVID-19 test in Australia. Other regulatory approvals and registrations followed those listed +here. +As +explained above, our Logix Smart™ COVID-19 test was designed, developed, submitted for regulatory approval and ready to be +used as an IVD in countries that accept a CE Mark as approval for use of the test in a period of just over 30 days. This is a real-world +example of how the CODX technology can be used in an evolving epidemic to get diagnostic tools in the hands of medical professionals +without delay. It can be similarly used to design a test for mutated strains of the virus should they not be detectable using currently +available tests. +Caribbean +and Central and South America +Our +initial sales were to entities located in South and Central America. In some of those countries, there are limited regulatory hurdles +so we started offering our tests immediately. We have applied for and received registrations for our tests in many of those countries +that require registration, and our distributors in those countries have provided us with in country assistance in completing such registrations. +We +first offered our Zika test in this region because of the demand for such a test, followed by tests for tuberculosis, our triplex test +for Zika, chikungunya, and dengue. Sales of those tests have not been material, but with the granting of a CE mark for our Logix Smart™ +COVID-19, we began significant sales in this region. Products are manufactured for sale upon receipt of purchase orders from distributors, +labs and hospitals. +India +In +January 2017, the Company entered into an agreement to manufacture diagnostics tests for seven infectious diseases with a pharmaceutical +manufacturing company in India and formed an Indian joint venture organized as CoSara Diagnostics, Pvt Ltd (“CoSara”). The +agreement provided for the construction of a manufacturing plant and the manufacture of the tests named above and the joint sales and +marketing of those tests in India. We have received a license for the plant in Ranoli, India to manufacture approved tests and is being +used for testing and manufacturing of our products for the Indian market. +As +mentioned above, the CDSCO has given us the approval for manufacture and sale of the nine tests referred above and the Company has begun +manufacture and sale of those tests. The Company has commenced a reagent rental program in India with thermocyclers purchased from third-party +vendors and which we refer to as our MDx Device. Each of the reagent rental placements requires the purchase of a minimum number of tests +per month. The placement of thermocyclers in India has facilitated the sale of the SaraGene COVID-19 tests in India. The World Health +Organization (“WHO”) 2019 Global Tuberculosis Report indicates that India is the country with the highest number of cases +of tuberculosis in the world. WHO tuberculosis statistics for India for 2018 give an estimated incidence figure of 2.69 million cases +of tuberculosis for India out of a global incidence of approximately 10.0 million. +6 +On +March 19, 2020, we announced that CoSara received authorization to begin manufacture and sale of COVID-19 tests in India. Those tests +in India are branded as SaraGene COVID-19 tests and are sold exclusively by CoSara. The Indian government places restrictions on the +price that could be charged for COVID-19 tests which has limited the revenue in India more than we have experienced in other parts of +the world. At the time of this report, CoSara has received CDSCO clearance for RT-PCR tests for Mycobacterium tuberculosis, malaria, +hepatitis B, hepatitis C, human papillomavirus (HPV), two COVID-19 assays, chikungunya, dengue, a dengue/chikungunya duplex test, and +an influenza A/influenza B/COVID-19 (“ABC”) multiplex test. +Europe +Molecular +diagnostics, such as our tests, are governed in Europe by the framework for in vitro diagnostics (IVDs), which encompasses diagnostic +products such as reagents, instruments and systems intended for use in diagnosis of disease. The regulatory system for some IVDs allows +for a self-certification procedure, placing heavy responsibility on manufacturers. Non self-certified products are subject to the same +standards as self-certified products but are also subject to audit and review by a notified body prior to receiving approval to be CE-marked. +A CE-marking is a manufacturer’s declaration that a product meets the requirements of the applicable European Commission directive. +Examples of current obligations include having in place a qualitative manufacturing process, user instructions that are clear and fit +for purpose, and ensuring that the ‘physical’ features of devices and diagnostics do not pose any danger. If a product fulfils +these and other related control requirements, it may be CE-marked as an indication that the product is compliant with EU legislation +and sold in the European Union. We have received CE Marks for six of our tests including for COVID-19, COVID-19 (2 gene test), ABC (a +triplex test for Flu A, Flu B and COVID-19), a DS (Direct Saliva, extraction-free) COVID-19 test, tuberculosis, Zika, and our Zika, dengue, +chikungunya triplex tests. +We +are ISO 13485:2016 certified, relating to the design and manufacture of our medical device products. The ISO certification indicates +that we meet the standards required to self-certify certain of our products and affix a CE-marking for sales of our products in countries +accepting the CE marking (not in the United States) with only minimal further governmental approvals and registrations in most countries. +United +States +The +U.S. Food and Drug Administration (FDA) has granted permission for us to export all of our IVD products. The FDA’s permission to +export was granted under Section 801(e) of the Federal Food, Drug, and Cosmetic Act, as amended (the “FDC Act”). Section +801(e) of the FDA Act covers certain medical devices that have not yet received an approved Premarket Approval in the United States by +the FDA, such as our products. We have not commenced any Premarket Approval steps with the FDA. Section 801(e) of the FDA Act applies +to medical devices that are acceptable to the importing country and that are manufactured under the FDA’s Good Manufacturing Practices. +We have received EUA for our COVID-19 test, which allows sales to qualified labs in the United States. +Under +our EUA, we are actively selling our Logix Smart™ COVID-19 test to CLIA certified laboratories in the United States and +the CLIA labs are able to use our test as it is or further validate our COVID-19 or other tests as Laboratory Developed Tests (LDTs), +which refers to a diagnostic test that has been validated for use in the CLIA lab. LDTs may be used by the lab only in that laboratory. +CLIA laboratories develop the performance characteristics, perform the analytical validation for their LDTs and obtain licenses to offer +them as diagnostic services. The FDA has publicly announced its intention to regulate certain LDTs in a phased-in approach, but draft +guidance that was published a couple of years ago was withdrawn at the end of the Obama administration and replaced by an informal non-enforceable +discussion paper reflecting some of the feedback that it received on LDT regulation. We are currently marketing our Logix Smart™ +COVID-19 test to CLIA laboratories throughout the US. +Market +Opportunity +The +market opportunity for our tests changed radically with the emergence of the COVID-19 pandemic. Because we were able to respond rapidly +and produce a quality product, we have been able to build a distribution network that extends to +more than 80 countries with over 50 active distributors, most of which have been the sales network that has allowed us to export products +throughout the world. We believe that after the pandemic is brought under control, the network of distributors that we have built +in these extra-ordinary times will serve us well in sales of other diagnostic tests. +7 +The +molecular diagnostics market is a fast-growing portion of the in vitro (test tube-based, controlled environment) diagnostics market. +There are several advantages of PCR tests, such as the ones we market and sell, over other forms of diagnostic testing. These advantages +include higher specificity and sensitivity, the ability to perform multiplex tests and the ability to test for drug resistance or for +individual genes. +Mosquito +Vector Control Services +In +response to market demand, we introduced our first diagnostics tests to be used exclusively to test for mosquito borne pathogens in June +2019. Municipalities in the US and many other countries in the world are concerned about the diseases carried by mosquitos and which +infect the human population. To prevent outbreaks of potentially harmful viruses, such as Zika or West Nile, from infecting the public +the municipalities conduct mitigation operations to eliminate the mosquito populations carrying the diseases. Because it is too expensive +and potentially harmful to the environment to spray all mosquito breeding areas, the solution is to identify which particular area has +mosquitos that are carrying the harmful viruses. To know where the host mosquitos with the harmful viruses are located, traps are set, +mosquitos collected and then tested to find the areas that most needed spraying. There are over 3,000 mosquito abatement districts throughout +the United States and almost all of them conduct testing to help make the spraying more effective. +Our +first vector related test was a triplex test that tests for West Nile, western equine and St. Louis encephalitis. We began shipping the +tests in June 2019. We added a second test that tests mosquitos for Zika, chikungunya and dengue in a triplex test. Finally, in November +2019, we completed a test for West Nile, eastern equine and St. Louis encephalitis, specifically for use in the eastern United States. +As a result, mosquito abatement districts can test for three target viruses in one test as compared to performing three different tests +using other market available tests, which saves our customers money. Additionally, the districts are more effective because they can +get test results in a matter of hours using our product instead of weeks when they might otherwise have to wait for a central lab to +process the mosquito tests. +We +have sold our Vector Smart test products and/or related lab equipment to testing districts in different sections of the country and are +marketing our products through trade shows, electronic and regular mail solicitations. +Competitive +Advantages of Co-Diagnostics +We +believe that we have the following competitive advantages: +● +Affordability: Lower-cost +test kits and low-cost MDx-device. +● +Flexibility: +CODX’s tests have been designed to run on many vendors’ DNA/RNA diagnostic testing machines. These tests +are particularly well suited to the new generation of “lab-on-a-chip” and “point-of-care” (“LOC and +POC”), highly portable analysis machinery for field, clinical and office applications. +● +Speed : +We believe our rapid assay design system software provides shorter time to product release. This has been demonstrated with the +conception, design, product manufacture, clinical verification and submission for a CE Mark for our Logix Smart™ coronavirus +disease (COVID-19) test being approximately 30 days. +● +Accuracy : +We believe our technology allows us to build tests that are highly sensitive and specific, the two benchmarks for accuracy in PCR +testing. +● +Personalized +Medicine : We project that rising health care costs in developed and developing nations will increasingly require that health +care systems be patient-specific to eliminate waste, misdiagnoses, and ineffectiveness. A critical component will be accurate, +more affordable DNA-based diagnostics, especially in at-home and POC settings, which we plan to offer. +● +Low-cost Provider : +Our platform technology obviates the need to pay patent royalties typically required of our competitors, which use patented test +platforms to design their tests. +8 +● +Worldwide Footprint : +With a dynamic technology that encompasses markets worldwide, we anticipate that we can identify the best target markets, not +only in high burden developing countries but also in developed nations. +● +Growth Industry Category : +We believe that DNA/RNA testing is the fastest-growing segment of in-vitro diagnostic testing. +● +Combination +Product Offering : Our sensitive tests can be a well-designed match for a new generation of handheld and other small POC devices +now entering the market, including our own MDx and YourTest PCR™ devices. Used together, these affordable tests and +devices may revolutionize the molecular diagnostics industry in cost, speed of test results and simplification. +● +Multiplexing: Our +existing multiplexed tests demonstrate that our CoPrimer-designed tests are able to test for multiple targets in the same sample +without the distortion caused by false negatives and false positives that often occur in multiplexed tests. +Liquid +Biopsy for Cancer Screening +The +enhanced specificity of our technology opens up some unique applications for liquid biopsy, demonstrating its ability to detect small +quantities of mutations associated with cancer within an environment of large amounts of normal DNA, as we position the Company to take +part in this historic and challenging development in human health care. +Agricultural +Applications +SNP +detection is also used in the agricultural industry to identify variations in crop genomes to achieve improved seed viability and other +desired characteristics, including drought resistance, disease resistance, pest resistance and higher yield. +In +mid-2017, the Company was first approached by a large agribusiness to evaluate our ability to multiplex certain target genomes. The results +of the development project have successfully demonstrated our ability to not only multiplex the target genomes, but targeted SNP’s +as well. The project was undertaken in conjunction with the manufacturer of our CoPrimer tests. The results of the project encouraged +the parent of our manufacturer to seek a world-wide licensing arrangement for our CoPrimers™ in the agricultural industry, +which was completed in October 2018. Pursuant to the exclusive license for the agronomics industry, the licensee pays us a royalty for +all CoPrimers™ sold to the licensee’s customers. In January 2019, the licensee formally introduced the product at +a large agricultural conference and has branded the product under the name “BHQ CoPrimers™”. +9 +Additional +Licensing and Assay Development +In +addition, the unique properties of our CoPrimer technology make them ideally suited to a variety of applications where sensitivity is +key to optimal results, including multiplexing several targets, enhanced SNP detection and enrichment for next generation sequencing. +Our licensee for our agricultural testing requested an expansion of our license agreement to include test design services for their customers +and potential customers, both in the infectious disease arena as well as for agricultural customers. The license was amended in July +2019 and we expect to derive a license fee from our licensee for its design services. If any of its customers desire to commercialize +the tests designed, they will need to seek a commercial license directly from us. Because of these unique characteristics of CoPrimers™, +research companies and institutions have requested that we design diagnostics to locate and identify uncommon gene sequences and +SNPs and create tests for the target sequences in a multiplexed reaction. This application of our technology is in its beginning stages, +but we believe that the results from our initial research indicate a significant step forward in defining the capabilities of our technology, +which we believe can be translated to revenue producing licensing arrangements. +Intellectual +Property +Because +much of our future success and value depends on our proprietary technology, our patent and intellectual property strategy is of critical +importance. Five of our initial U.S. patents related to our technology have been granted by the U.S. Patent and Trademark Office (PTO), +including the patent for our CoPrimer technology, which we consider our most important patent. One of our patents has been issued in +Great Britain but still pending in the United States, and another has been granted in South Korea. As of March 2022, we have an issued +patent in Great Britain and India on “Rapid Oligo Probes.” We also have an issued patent in the U.S. on “Primers for +Nucleic Acid Extension or Amplification Reactions.” We have another issued patent in the U.S. on “Detection of Primers for +Nucleic Acid Extension or Amplification Reactions.” We have 3 patents issued in the US, as well as patents issued in Australia, +Korea, and Mexico on “Cooperative Primers, Probes, and Applications Thereof.” We have applications pending in Australia, +Canada, Europe, and the U.S. for “Methods and Compositions for Next Generation Sequencing (NGS) Library Preparation.” We +have applications pending in the U.S. and internationally as a PCT application for “Allele-Specific Design of Cooperative Primers +for Improved Nucleic Acid Variant Genotyping.” Lastly, we have a provisional application on file in the U.S. for “Methods +and Compositions Related to Cooperative Primers and Reverse Transcription. +We +have identified additional applications of the technology, which represent potential patents that further define specific applications +of the processes that are covered by the original patents. We intend to continue building our intellectual property portfolio as development +continues and resources are available. +We +have copyrighted our development software that is used by us to develop diagnostic tests based on our technology. +Major +Customers +We +had certain customers which were each responsible for generating 10% or more of our total revenue for the year ended December 31, 2021. +Two customers together accounted for approximately 48% of total revenue for the year ended December 31, 2021. These customers may not +account for the same percentage of sales in future periods. If +we were to sell nothing to those customers in the future, it would have a material adverse effect on our financial condition unless we +were able to replace those customers with others. +Competition +The +molecular diagnostics industry is extremely competitive. There are many firms that provide some or all of the products we provide and +provide many diagnostic tests that we have yet to develop. Many of these competitors are larger than us and have significantly greater +financial resources. Because are more recently established, many of our competitors have a competitive advantage in the diagnostic testing +industry because they also have other lines of business in the pharmaceutical industry from which they derive revenues and for which +they are well known and respected in the medical profession. We will need to overcome the disadvantage of being perceived as a start +up with no significant respect from the medical and testing professionals, although this is changing as we continue to market our Logix +Smart™ COVID-19 tests and other tests in the United States to well-known and successful laboratories. In the diagnostic +testing industry, we compete with such companies as BioMerieux, Siemens, Qiagen, Cue Health, Lumira Dx and Cepheid and with such pharmaceutical +companies as Abbott Laboratories, Becton Dickinson and Johnson and Johnson. +10 +Many +of these competitors already have an established customer base with industry standard technology, which we must overcome to be successful. +Competition +is, and will likely continue to be, particularly intense in the market for COVID-19 diagnostic tests. Numerous companies in the United +States and internationally have announced their intention to offer new products, services and technologies that could be used in substitution +for our Logix Smart™ COVID-19 tests. Many of those competitors are significantly larger, and have substantially greater +financial, engineering and other resources, than our company. Existing and potential competitors in the market for COVID-19 diagnostic +tests include developers of serological, antigen and molecular tests. We also compete with companies from Asia in certain markets who +are willing to sell their tests for much less than we sell our tests, which creates competitive price pressure on us. +We +expect competition to continue to increase as other established and emerging companies enter the market, as customer requirements evolve, +and as new products, services and technologies are introduced. The entrance of new competitors is being encouraged by governmental authorities, +who are offering funding to support development of testing solutions for COVID-19. Some of our existing or new competitors may have strong +relationships with current and potential customers, including governmental authorities, and, as a result, may be able to respond more +quickly to new or changing regulatory requirements, new or emerging technologies, and changes in customer requirements. +Government +Regulation +In +the United States, we are regulated by the FDA and our products must be approved, cleared, or authorized by the FDA before we are allowed +to sell our tests in the United States as in vitro diagnostics. The FDA granted us an EUA to manufacture and sell our Logix Smart™ +COVID-19 test to CLIA labs in the United States. Being ISO certified greatly facilitates our applications for CE-Marking, which allows +us to sell any CE Marked test in most countries in Europe, South America and Asia, depending on the country and following that country’s +registration process. We currently have CE Markings issued for our Logix Smart™ COVID-19 test, tuberculosis test, our Zika +virus test, a triplex test that tests for Zika, dengue, and chikungunya simultaneously, a triplex “ABC” test that identifies +and distinguishes between Flu A, Flu B and Covid-19, our SARS-CoV-2 2-gene multiplex test, and our DS (Direct Saliva, extraction-free) +COVID-19 test. In addition, our Logix Smart™ COVID-19 has received the license to manufacture and sell in India from India’s +CDSCO and the National Epidemiology Institute in Mexico evaluated our Logix Smart™ COVID-19 and ABC tests and approved them +for sale in Mexico. We have also received approval to sell in Australia. We are in the process of registering for sale our Logix Smart™ +COVID-19 and other tests in a number of major countries around the world. +Employees +As +of December 31, 2021, we had 101 full-time and part-time employees at our executive offices and lab facilities in Salt Lake City, Utah. +We have engaged independent contractors in India to promote the use of our products and develop outlets for products and employ the services +of independent sales representatives on an “as needed” basis. +Organizational +History and Corporate Information +We +were incorporated as Co-Diagnostics, Inc., in Utah on April 18, 2013. Our principal executive office is located 2401 S. Foothill Drive, +Salt Lake City, Utah 84109. Our telephone number is (801) 438-1036. Our web address is www.codiagnostics.com . The contents of +our website are not incorporated by reference in this Annual Report. +11 +Implications +of Being an Emerging Growth Company +We +are an “emerging growth company,” as defined in the Jumpstart Our Business Startups Act of 2012. We will remain an emerging +growth company until the earlier of (i) the last day of the fiscal year following the fifth anniversary of July 12, 2017, the date of +the first sale of our common stock pursuant to an effective registration statement under the Securities Act of 1933, as amended (the +“Securities Act”); (ii) the last day of the fiscal year in which we have total annual gross revenues of $1 billion or more; +(iii) the date on which we have issued more than $1 billion in nonconvertible debt during the previous three years; or (iv) the date +on which we are deemed to be a large accelerated filer under applicable SEC rules. We expect that we will remain an emerging growth company +for the foreseeable future, but cannot retain our emerging growth company status indefinitely. We refer to the Jumpstart Our Business +Startups Act of 2012 herein as the “JOBS Act”. For so long as we remain an emerging growth company, we are permitted and +intend to rely on exemptions from specified disclosure requirements that are applicable to other public companies that are not emerging +growth companies. These exemptions include: +● +being +permitted to provide only two years of audited financial statements, in addition to any required unaudited interim financial statements, +with correspondingly reduced “Management’s Discussion and Analysis of Financial Condition and Results of Operations” +disclosure; +● +not +being required to comply with the requirement of auditor attestation of our internal controls over financial reporting; +● +not +being required to comply with any requirement that may be adopted by the Public Company Accounting Oversight Board regarding mandatory +audit firm rotation or a supplement to the auditor’s report providing additional information about the audit and the financial +statements; +● +reduced +disclosure obligations regarding executive compensation; and +● +not +being required to hold a nonbinding advisory vote on executive compensation and shareholder approval of any golden parachute payments +not previously approved. +For +as long as we continue to be an emerging growth company, we expect that we will take advantage of the reduced disclosure obligations +available to us as a result of that classification. Accordingly, the information contained herein may be different than the information +received from other public companies. +An +emerging growth company can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for +complying with new or revised accounting standards. This allows an emerging growth company to delay the adoption of certain accounting +standards until those standards would otherwise apply to private companies. We have irrevocably elected to avail ourselves of this extended +transition period and, as a result, we will not be required to adopt new or revised accounting standards on the dates on which adoption +of such standards is required for other public reporting companies. +We +are also a “smaller reporting company” as defined in Rule 12b-2 of the Securities Exchange Act of 1934, as amended, or the +Exchange Act, and have elected to take advantage of certain of the scaled disclosure available for smaller reporting companies. +12 +ITEM +1A. RISK FACTORS +Risks +Related to Our Business and Industry +We +have a limited commercial history upon which to base our prospects and are not certain +that we will sustain profitability in the future. +We +began operations in April 2013, and we have a limited operating history. We were profitable for the years ended December 31, 2021 and +2020, respectively. Our accumulated retained earnings were $54.2 million and $17.5 million as of December 31, 2021 and 2020, respectively. +We realized net income for the first time for the three months ended June 30, 2020. We were able to achieve net income during the prior +two fiscal years because we were able to develop, market and profitably sell our LogixSmart COVID-19 and other COVID-19 tests, but we +do not have any way to predict how long our market for that test will continue. Potential investors should be aware of the difficulties +normally encountered by a new enterprise, many of which are beyond our control, including substantial risks and expenses in the course +of developing new diagnostic tests, establishing or entering new markets, organizing operations and marketing procedures. The likelihood +of our success must be considered in light of these risks, expenses, complications and delays, and the competitive environment in which +we operate. There is, therefore, nothing at this time upon which to base an assumption that our business plan will continue to prove +successful, and we may not be able to generate significant revenue, raise additional capital or operate profitably. We will continue +to encounter risks and difficulties frequently experienced by early commercial stage companies, including scaling up our infrastructure +and headcount, and may encounter unforeseen expenses, difficulties or delays in connection with our growth. In addition, as a result +of the start-up nature of our business, we can be expected to continue to sustain substantial operating expenses and may not be able +to continue generating sufficient revenues to cover expenditures. Any investment in our company is therefore highly speculative and could +result in the loss of any investment. +Our +near-term success has been dependent on the market for our COVID-19 tests and future success is dependent on continued demand for COVID-19 +diagnostics and upon our ability to develop and market other commercially accepted diagnostic tests. +Our +future success will depend, in part, on the continued market for COVID-19 tests, our ability to develop and sell sufficient quantities +of other diagnostics tests, and our ability to successfully receive regulatory approval for and profitably market our “YourTest +PCR™ Device.” Attracting new customers and distribution networks requires substantial time and expense. Any failure to +continue sales of our tests in sufficient quantities to maintain profitability would adversely affect our operating results. Many factors +could affect the market acceptance and commercial success of any of our diagnostic tests and devices, including: +● +Our ability to develop +additional infectious disease diagnostic tests for which there is a commercial market. +● +our ability to convince +our potential customers of the advantages and economic value of our tests over competing technologies and diagnostic tests; +● +the breadth of our test +menu relative to competitors; +● +changes to policies, procedures +or currently accepted best practices in clinical diagnostic testing; +● +the extent and success +of our marketing and sales efforts; and +● +our ability to manufacture +in quantity our commercial diagnostic tests and meet demand in a timely fashion. +General +Risk Factors +The +price of our common stock may fluctuate substantially. +The +market price of our common stock may be subject to wide fluctuation in response to various factors, some of which are beyond our control. +Some factors that may cause the market price of our common stock to fluctuate, in addition to the other risks mentioned in this “Risk +Factors” section and elsewhere in this report, are: +● +sales of our common stock +by our shareholders, executives, and directors; +● +our ability to enter new +markets; +● +actual or un-anticipated +fluctuations in our annual and quarterly financial results; +● +our ability to obtain financings +to continue and expand our commercial activities, expand our manufacturing operations, conduct research and development activities +including, but not limited to, human clinical trials, and other business activities; +13 +● +our +ability to secure resources and the necessary personnel to continue and expand our commercial activities, develop additional diagnostic +tests, conduct clinical trials and gain approval for our diagnostic tests on our desired schedule; +● +commencement, +enrollment or results of our clinical trials of our diagnostic tests or any future clinical trials we may conduct; +● +changes +in the development status of our diagnostic tests; +● +any +delays or adverse developments or perceived adverse developments with respect to review by the FDA or other similar foreign regulatory +authorities of our planned clinical trials; +● +any +delay in our submission for studies or test approvals or adverse regulatory decisions, including failure to receive regulatory approval +for our diagnostic tests; +● +our +announcements or our competitors’ announcements regarding new tests, enhancements, significant contracts, acquisitions or strategic +investments; +● +failures +to meet external expectations or management guidance; +● +changes +in our capital structure or dividend policy, including as a result of future issuances of securities and sales of large blocks of +common stock by our shareholders; +● +announcements +and events surrounding financing efforts, including debt and equity securities; +● +competition +from existing technologies and diagnostic tests or new technologies and diagnostic tests that may emerge; +● +announcements +of acquisitions, partnerships, collaborations, joint ventures, new diagnostic tests, capital commitments, or other events by us or +our competitors; +● +changes +in general economic, political and market conditions in any of the regions in which we conduct our business; +● +changes +in industry conditions or perceptions; +● +changes +in valuations of similar companies or groups of companies; +● +analyst +research reports, recommendations and changes in recommendations, price targets and withdrawals of coverage; +● +departures +and additions of key personnel; +● +disputes +and litigations related to intellectual properties, proprietary rights, and contractual obligations; +● +changes +in applicable laws, rules, regulations, or accounting practices and other dynamics; +● +actions +taken by our principal shareholders and release or expiry of lockup or other transfer restrictions; and +● +other +events or factors, many of which may be out of our control. +In +addition, if the market for stocks in our industry or industries related to our industry, or the stock market in general, experiences +a loss of investor confidence, the trading price of our common stock could decline for reasons unrelated to our business, financial condition +and results of operations. If any of the foregoing occurs, it could cause our stock price to fall and may expose us to lawsuits that, +even if unsuccessful, could be costly to defend and a distraction to management. +Future +sales of our common stock in the public market may cause our stock price to decline and impair our ability to raise future capital through +the sale of our equity securities. +There +are a substantial number of shares of our common stock held by shareholders who owned shares of our capital stock prior to our initial +public offering that may be able to sell in the public market. Sales by such shareholders of a substantial number of shares could significantly +reduce the market price of our common stock. +Shares +issued by us upon exercise of options granted under our equity plan will be eligible for sale in the public market. If any of these holders +cause a large number of securities to be sold in the public market, the sales could reduce the trading price of our common stock. These +sales also could impede our ability to raise capital in the future. +Anti-takeover +provisions in our charter documents and Utah law could discourage delay or prevent a change of control of our Company and may affect +the trading price of our common stock. +We +are a Utah corporation and the anti-takeover provisions of the Utah Control Shares Acquisition Act may discourage, delay or prevent a +change of control by limiting the voting rights of control shares acquired in a control share acquisition. In addition, our Articles +of Incorporation and Bylaws may discourage, delay or prevent a change in our management or control over us that shareholders may consider +favorable. Among other things, our Amended and Restated Articles of Incorporation and Bylaws: +● +authorize the issuance +of “blank check” preferred stock that could be issued by our board of directors in response to a takeover attempt; +● +provide that vacancies +on our board of directors, including newly created directorships, may be filled only by a majority vote of directors then in office, +except a vacancy occurring by reason of the removal of a director without cause shall be filled by vote of the shareholders; and +● +limit who may call special +meetings of shareholders. +14 +These +provisions could have the effect of delaying or preventing a change of control, whether or not it is desired by, or beneficial to, our +shareholders. +NASDAQ +may delist our common stock from its exchange, which could limit investors’ ability to make transactions in our common stock and +subject us to additional trading restrictions. +Should +we fail to satisfy the continued listing requirements of the NASDAQ Capital Market, such as the corporate governance requirements or +the minimum closing bid price requirement, NASDAQ may take steps to delist our common stock. Such a delisting would likely have a negative +effect on the price of our common stock and would impair your ability to sell or purchase our common stock when you wish to do so. In +the event of a delisting, we would take actions to restore our compliance with the NASDAQ Capital Market’s listing requirements, +but we can provide no assurance that any such action taken by us would allow our common stock to become listed again, stabilize the market +price or improve the liquidity of our common stock, prevent our common stock from dropping below the NASDAQ Capital Market’s minimum +bid price requirement or prevent future non-compliance with the NASDAQ Capital Market’s listing requirements. +If +the NASDAQ Capital Market does not maintain the listing of our securities for trading on its exchange, we could face significant material +adverse consequences, including: +● +a limited availability +of market quotations for our securities; +● +reduced liquidity with +respect to our securities; +● +a determination that our +shares of common stock are “penny stock” which will require brokers trading in our shares of common stock to adhere to +more stringent rules, possibly resulting in a reduced level of trading activity in the secondary trading market for our shares of +common stock; +● +a limited amount of news +and analyst coverage for our company; and +● +decreased ability to issue +additional securities or obtain additional financing in the future. +Therefore, +it may be difficult for our shareholders to sell any shares if they desire or need to sell them. +We +do not currently intend to pay dividends on our common stock. +We +do not expect to pay cash dividends on our common stock. Any future dividend payments are within the absolute discretion of our board +of directors and will depend on, among other things, our results of operations, working capital requirements, capital expenditure requirements, +financial condition, contractual restrictions, business opportunities, anticipated cash needs, provisions of applicable law and other +factors that our board of directors may deem relevant. We may not generate sufficient cash from operations in the future to pay dividends +on our common stock. +We +are an “emerging growth company” and will be able to avail ourselves of reduced disclosure requirements applicable to emerging +growth companies, which could make our common stock less attractive to investors. +We +are an “emerging growth company,” as defined in the Jumpstart Our Business Startups Act of 2012, or the JOBS Act, and we +intend to take advantage of certain exemptions from various reporting requirements that are applicable to other public companies that +are not “emerging growth companies” including not being required to comply with the auditor attestation requirements of Section +404(b) of the Sarbanes-Oxley Act, reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements, +and exemptions from the requirements of holding a nonbinding advisory vote on executive compensation and shareholder approval of any +golden parachute payments not previously approved. Investors may find our common stock less attractive because we may rely on these exemptions. +If some investors find our common stock less attractive as a result, there may be a less active trading market for our common stock and +our stock price may be more volatile. We may take advantage of these reporting exemptions until we are no longer an “emerging growth +company.” We will remain an “emerging growth company” until the earliest of (i) the last day of the fiscal year in +which we have total annual gross revenues of $1.0 billion or more; (ii) the last day of our fiscal year following the fifth anniversary +of the date of the completion of our initial public offering; (iii) the date on which we have issued more than $1.0 billion in nonconvertible +debt during the previous three years; or (iv) the date on which we are deemed to be a large accelerated filer under the rules of the +Securities and Exchange Commission. +15 +We +have elected to use the extended transition periods for complying with new or revised accounting standards. +We +have elected to use the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised +accounting standards that have different effective dates for public and private companies until the earlier of the date we (i) are no +longer an emerging growth company or (ii) affirmatively and irrevocably opt out of the extended transaction period provided in Section +7(a)(2)(B). As a result, our financial statements may not be comparable to those of companies that comply with public company effective +dates. +Our +management is required to devote substantial time to compliance initiatives. +As +a public company, we incur significant legal, accounting and other expenses that we did not incur as a newly formed entity. The Sarbanes-Oxley +Act, as well as rules subsequently implemented by the Securities and Exchange Commission, and NASDAQ, have imposed various new requirements +on public companies, including requiring establishment and maintenance of effective disclosure and financial controls and changes in +corporate governance practices. Our management and other personnel devote a substantial amount of time to these new compliance initiatives. +Moreover, these rules and regulations increase our legal and financial compliance costs and make some activities more time consuming +and costly. We expect these rules and regulations to make it more difficult and more expensive for us to obtain director and officer +liability insurance and we may be required to incur substantial costs to maintain the same or similar coverage. +ITEM +1B. UNRESOLVED STAFF COMMENTS +None. +ITEM +2. PROPERTIES +Our +headquarters are located at 2401 S. Foothill Drive, Salt Lake City, Utah. Our current facility has approximately 14,000 square feet of +laboratory and office space under a lease that expires in February 2024. Our recently acquired subsidiaries also lease additional laboratory +and office space under month-to-month leases. We believe the facility we lease is sufficient to meet our needs for the immediate future. +ITEM +3. LEGAL PROCEEDINGS +In +July 2020, we were served in an action filed in the United States District Court for the District of Utah claiming that the Company promulgated +false and misleading press releases to increase the price of our stock to improperly benefit the officers and directors of the Company. +The Plaintiff, Gelt Trading, Ltd., a Cayman Islands limited company, demands compensatory damages sustained as a result of our alleged +wrongdoing in an amount to be proven at trial. We will vigorously defend this action as we do not believe it has any merit. +In +July 2020, we were served in an action filed in the United States District Court for the District of Utah claiming that the Company promulgated +false and misleading press releases to increase the price of our stock to improperly benefit the officers and directors of the Company. +The Plaintiff, Fernando Hernandez demands compensatory damages sustained as a result of our alleged wrongdoing in an amount to be proven +at trial. We will vigorously defend this action as we do not believe it has any merit. +In +September 2020, we were served in an action filed in the United States District Court for the District of Utah claiming that the officers +and the directors harmed the Company by promulgating false and misleading press releases to increase the price of our stock to improperly +benefit the officers and directors of the Company. The Plaintiff, Luis Aguliera, on behalf of Co-Diagnostics, Inc. seeks damages from +the individual defendants and attorneys’ fees. We will vigorously defend this as we do not believe it has any merit. +16 +In +December 2020, we were served in an action filed in the United States District Court for the District of Utah claiming that the officers +and the directors harmed the Company by promulgating false and misleading press releases to increase the price of our stock to improperly +benefit the officers and directors of the Company. The Plaintiff, Melvyn Klein, on behalf of Co-Diagnostics, Inc. seeks damages from +the individual defendants and attorneys’ fees. We will vigorously defend this as we do not believe it has any merit. +In +December 2020, we were served in an action filed in the United States District Court for the District of Utah claiming that the officers +and the directors harmed the Company by promulgating false and misleading press releases to increase the price of our stock to improperly +benefit the officers and directors of the Company. The Plaintiff, Mathew Wallace, on behalf of Co-Diagnostics, Inc. seeks damages from +the individual defendants and attorneys’ fees. We will vigorously defend this as we do not believe it has any merit. +From +time to time, we may become involved in litigation relating to claims arising out of our operations in the normal course of business. +Although we have received inquiries from FINRA, NASDAQ and the SEC, to which we have responded, to the best of our knowledge, no governmental +authority is contemplating any proceeding to which we are a party or to which any of our properties or businesses are subject, which +would reasonably be likely to have a material adverse effect on the Company. +ITEM +4. MINE SAFETY DISCLOSURES +Not +applicable. +PART +II +ITEM +5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER EQUITY SECURITIES +Market +Information +Our +common stock has been quoted on the NASDAQ market under the symbol “CODX” since July 12, 2017. The following table sets forth +the high and low prices for our common stock for the periods indicated, as reported by NASDAQ. +Calendar Quarter Ended: +High +Low +March 31, 2021 +$ 20.69 +$ 7.86 +June 30, 2021 +$ 9.91 +$ 7.01 +September 30, 2021 +$ 11.82 +$ 7.35 +December 31, 2021 +$ 10.90 +$ 7.90 +Calendar Quarter Ended: +High +Low +March 31, 2020 +$ 21.75 +$ 0.88 +June 30, 2020 +$ 29.72 +$ 6.81 +September 30, 2020 +$ 30.99 +$ 8.07 +December 31, 2020 +$ 16.96 +$ 9.01 +Holders +As of March 22, 2022, +the last reported sales price reported on NASDAQ for our common stock was $6.47 per share. As of March 22, 2022, we had +approximately 154 record holders of our common stock. The number of record holders was determined from the records of our transfer +agent and does not include beneficial owners of common stock whose shares are held in the names of various security brokers, dealers, +and registered clearing agencies. The transfer agent for our common stock is VStock Transfer LLC located at 18 Lafayette Pl, Woodmere, +New York 11598. +17 +Dividends +We +have never declared or paid any cash dividends on our capital stock. The payment of dividends on our common stock in the future will +depend on our earnings, capital requirements, operating and financial condition and such other factors as our Board of Directors may +consider appropriate. We do not anticipate paying dividends on our common stock in the foreseeable future. +Recent +Sales of Unregistered Securities +We +issued the unregistered securities below. For the issuances of unregistered securities, we relied on the exemption from registration +requirements of the Securities Act of 1933, as amended, available under Section 4(a)(2) promulgated thereunder due to the fact that such +issuances did not involve a public offering of securities. +● +During the year ended December +31, 2021, we issued an aggregate of 5,548 shares of our common stock for services rendered pursuant to consulting agreements. +Purchases +of Equity Securities by the Issuer and Affiliated Purchasers +None. +ITEM +6. RESERVED +ITEM +7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULT OF OPERATIONS +The +following management’s discussion and analysis of financial condition and results of operations describes the principal factors +affecting the results of our operations, financial condition, and changes in financial condition. This discussion should be read in conjunction +with the accompanying audited financial statements, and notes thereto, included elsewhere in this report. In addition to historical information, +this Annual Report contains forward-looking statements that involve risks, uncertainties, and assumptions. Our actual results may differ +materially from those anticipated in these forward-looking statements as a result of certain factors, including but not limited to those +set forth under the caption “Item 1A. Risk Factors” in this Annual Report on Form 10-K. +Business +Overview +Co-Diagnostics, +Inc., a Utah corporation (the “Company” or “CODX”), develops, manufactures and sells reagents used for +diagnostic tests that function via the detection and/or analysis of nucleic acid molecules (DNA or RNA), including robust and innovative +molecular tools for detection of infectious diseases, liquid biopsy for cancer screening, and agricultural applications. In connection +with the sale of our tests we may sell diagnostic equipment from other manufacturers as self-contained lab systems (which we refer to +as the “MDx Device”). We have also developed a unique, groundbreaking portable PCR device (the “YourTest PCR™ +Device”) that has been designed to bring affordable, reliable gold-standard polymerase chain reaction to patients in point-of-care +and even at-home settings. +Our +diagnostics systems enable dependable, low-cost, molecular testing for organisms and genetic diseases by automating historically complex +procedures in both the development and administration of tests. CODX’s technical advance involves a novel, patented approach +to PCR test design of primer and probe structure (“CoPrimers™”) that eliminates one of the key vexing issues +of PCR amplification, the exponential growth of primer-dimer pairs (false positives and false negatives) which adversely interferes with +identification of the target DNA/RNA. +We +believe our proprietary molecular diagnostics technology is paving the way for innovation in disease detection and life sciences research +through our enhanced detection of genetic material. For various reasons, including owning our own our platform, we believe we will be +able to accomplish this faster and more economically, allowing for significant margins while still positioning the Company to be a low-cost +provider of molecular diagnostics and screening services. +18 +In +addition, continued development has demonstrated the unique properties of our CoPrimer technology that we believe makes it ideally suited +for a variety of applications where specificity is key to optimal results, including multiplexing several targets, enhanced Single Nucleotide +Polymorphism (“SNP”) detection and enrichment for next generation sequencing. +Our +scientists use the complex mathematics of DNA/RNA test design to engineer and optimize DNA/RNA tests and to automate algorithms that +rapidly screen millions of possible options to pinpoint the optimum design. Dr. Brent Satterfield, our founder, developed the Company’s +intellectual property consisting of the predictive mathematical algorithms and patented molecular structure used in the testing process, +which together represent a major advance in PCR testing systems. CODX technologies are now protected by more than 20 granted or pending +US and foreign patents, as well as certain trade secrets and copyrights. Ownership of our proprietary platform permits us the advantage +of avoiding payment of patent royalties required by other PCR test systems, which may allow the sale of diagnostic PCR tests at a lower +price than competitors, while enabling us to maintain profit margins. +We +may either sell or lease the MDx Device to labs and diagnostic centers, through sale or lease agreements, and sell the reagents that +comprise our proprietary tests to those laboratories and testing facilities. +Our +proprietary test design process involves identifying the optimal locations on the target genes for amplification and pair the locations +with the optimized primer and probe structure to achieve outputs that meet the design input requirements identified from market research. +This is done by following planned and documented processes, procedures and testing. In other words, we use the data resulting from our +tests to verify whether we succeeded in designing what we intended at the outset. Verification is a series of testing that concludes +that the product is ready to proceed to validation in an evaluation either in our laboratory or in an independent laboratory setting +using initial production tests to confirm that the product as designed meets the user needs. +Using +our proprietary test design system and proprietary reagents, we have designed and obtained regulatory approval in the European Community +and/or in India to sell PCR diagnostic tests for the detection of COVID-19, influenza, tuberculosis, hepatitis B and C, human papillomavirus, +malaria, chikungunya, dengue, and the zika virus. In the United States, CODX has obtained Emergency Use Authorization (“EUA”) +for its Logix Smart™ COVID-19 detection test from the Food and Drug Administration, or FDA, and sells that test to qualified labs. +In addition, our COVID-19 detection test and certain of our other suite of COVID-19 products have been approved for sale in countries +such as the United Kingdom, Australia and Mexico by the regulatory bodies in those countries and have been registered for sale in many +more countries. +In +addition to testing for infectious disease, the technology lends itself to identifying any section of a DNA or RNA strand that describe +any type of genetic trait, which creates a number of significant applications. We, in conjunction with our customers, are active in designing +and licensing tests that identify genetic traits in plant and animal genomes. We also have three multiplexed tests developed to test +mosquitos for the identification of diseases carried by the mosquitos to enable municipalities to concentrate their efforts in managing +mosquito populations on the specific areas known to be breeding the mosquitos that carry deadly viruses. +19 +RESULTS +OF OPERATIONS +Results +of Operations for the Years Ended December 31, 2021 and 2020 +The +table below provides a comparison of our operating results for the year ended December 31, 2021 as compared to the year ended December +31, 2020. +Years Ended December 31, +Year Change +2021 +2020 +Change +% +Revenue +$ 97,885,603 +$ 74,552,758 +$ 23,332,845 +31 % +Cost of revenue +11,574,944 +16,591,346 +(5,016,402 ) +-30 % +Gross profit +86,310,659 +57,961,412 +28,349,247 +49 % +Operating expenses +Sales and marketing +13,397,813 +4,665,113 +8,732,700 +187 % +General and administrative +11,550,615 +8,278,734 +3,271,881 +40 % +Research and development +14,961,916 +3,185,290 +11,776,626 +370 % +Depreciation and amortization +335,363 +138,635 +196,728 +142 % +Total operating expenses +40,245,707 +16,267,772 +23,977,935 +147 % +Income from operations +46,064,952 +41,693,640 +4,371,312 +10 % +Other income (expense) +Interest income +45,631 +97,215 +(51,584 ) +-53 % +Loss on disposition of assets +(44,355 ) +(175 ) +(44,180 ) +25246 % +Gain (loss) on equity method investment in joint venture +(430,433 ) +778,385 +(1,208,818 ) +-155 % +Total other income (expense) +(429,157 ) +875,425 +(1,304,582 ) +-149 % +Income before income taxes +45,635,795 +42,569,065 +3,066,730 +7 % +Income tax provision +8,977,231 +90,536 +8,886,695 +9816 % +Net income +$ 36,658,564 +$ 42,478,529 +$ (5,819,965 ) +-14 % +Revenues +For +the year ended December 31, 2021, we generated $97.9 million of revenue compared to revenue of $74.5 million in the year ended December +31, 2020. The increase in revenue of $23.3 million was primarily due to sales of our LogixSmart COVID-19 test throughout the world, which +was developed in response to the current COVID-19 pandemic. Of the total revenue in 2021 and 2020, respectively, $0.5 million and $3.7 +million was from the sale of third party manufactured equipment and supplies that we sourced and sold to customers to facilitate usage +of our test. +Cost +of Revenues and Gross Profit +Cost +of revenues decreased by $5.0 million from $16.6 million for the year ended December 31, 2020 to $11.6 million for the year ended December +31, 2021. The decrease in cost of revenues was due to a reduction of production costs and the reduction in sales of third-party equipment, +which have a higher cost of sales than tests, and the commission structure of certain sales of tests sold during the year. Our gross +margin was 88.2% for the year ended December 31, 2021 compared to 77.7% for the year ended December 31, 2020. The increase in gross margin +was due to the reduction of production costs, as well as the mix of products we sold, with the majority of our 2021 revenue came from +sales of our test reagents, which has a higher profit margin than sales of equipment. +Operating +Expenses +We +incurred total operating expenses of $40.2 million for the year ended December 31, 2021 compared to total operating expenses of $16.3 +million for the year ended December 31, 2020. The increase in operating expenses was primarily due to the increase in business activities +experienced as a result of our increase in revenue, increased third party sales commissions, reflected in sales and marketing, and increased +investment in research and development. +Sales +and marketing expenses for the year ended December 31, 2021 were $13.4 million compared to $4.7 million for the year ended December 31, +2020. The increase of $8.7 million was primarily a result of increased expenses related to stock-based compensation, and personnel related +expenses, including commissions paid to our sales team and distributors, due to the growth in revenue noted above. +20 +General +and administrative expenses increased $3.3 million from $8.3 million for the year ended December 31, 2020 to $11.6 million for the year +ended December 31, 2021. The increase in general and administrative expenses was primarily due to increased activity to support the growth +of our business. The primary drivers of the increased expenses related to increases in stock-based compensation, employee related expenses +and increased expenses for professional services. +Our +research and development expenses increased by $11.8 million from $3.2 million for the year ended December 31, 2020, to $15.0 million +for the year ended December 31, 2021. The primary increase in expenses related to expenditures of over $9.2 million for our point-of-care +device, as well as increases in salaries and related benefits, including stock-based compensation, as we have added additional employees +to our research and development team to increase our product development activities. Additionally, there has been an increase in professional +and lab services utilized to further help us in our research and product development activities. +Other +Income (Expense) +Other +expense was $0.4 million for the year ended December 31, 2021, compared to other income of $0.9 million for the year ended December 31, +2020. The decrease in other income of $1.3 million was primarily related to recording a loss of $0.4 million in 2021 from our India joint +venture. For the year ended December 31, 2020 we recorded a gain of $0.8 million from our India joint venture. +Net +Income +We +realized net income for the year ended December 31, 2021 of $36.7 million compared to net income of $42.5 million for the year ended +December 31, 2020. The decrease in net income of $5.8 million was primarily the result of sales of our LogixSmart COVID-19 test and resulting +margins from those sales offset by increased operating expenses as discussed above. Additionally, we recorded income tax expense of $9.0 +million during the year ended December 31, 2021, compared to $0.1 million for the year ended December 31, 2020. During 2020, we released +our deferred tax asset valuation allowance and recorded a deferred tax asset since we utilized our net operating losses from prior years +during the year ended December 31, 2020. +LIQUIDITY +AND CAPITAL RESOURCES +At +December 31, 2021, we had cash and cash equivalents of $88.6 million and marketable investment securities of $1.3 million that could +readily be converted into cash if needed. Additionally, our total current assets at December 31, 2021, were $115.1 million compared to +total current liabilities of $12.6 million. +Net +cash provided by operating activities during the year ended December 31, 2021 was $41.1 million, compared to $28.2 million for the year +ended December 31, 2020. The increase in cash from operating activities was primarily due to our increased revenue and decrease in inventory, +offset by increases in accounts receivable. +We +received $4.1 million of cash from investing activities during the year ended December 31, 2021 as compared to $5.8 million of cash used +in investing activities during the year ended December 31, 2020. The increase in cash provided by investing activities is primarily due +to net cash acquired from business acquisitions and proceeds received from maturities of marketable investment securities. +Net +cash provided by financing activities was $0.5 million for the year ended December 31, 2021, compared to $19.7 million for the year ended +December 31, 2020. The decrease is primarily due to net proceeds of $18.0 million received from a series of three registered direct offerings +in 2020 pursuant to our shelf registration in addition to receiving $1.7 million from the exercise of warrants and options for the year +ended December 31, 2020. +Since +commencing sales of our Logix Smart™ COVID-19 test in March 2020, we have used our cash generated from those sales to fund +the purchase of inventories and the development of our point-of-care device, and to pay our operating expenses. We have increased our +work force most significantly in research and development in order to continue development of a new device and additional tests that +will enable continued use of our distributor network to sell additional products throughout the world. +21 +We +believe that our existing capital resources and the cash generated from future sales will be sufficient to meet our projected operating +requirements for the next 12 months. However, our available capital resources may be consumed more +rapidly than currently expected and we may need or want to raise additional financing for strategic opportunities. If needed, we expect +additional investment capital to come from (i) additional issuances of our common stock with existing and new investors or (ii) the private +placement of other securities with investors similar to those that have provided funding in the past. We may not be able to secure such +financing in a timely manner or on favorable terms, if at all. +On +October 30, 2020, we filed a Registration Statement on Form S-3 (File No: 333-249651) with the Securities and Exchange Commission (the +“SEC”). The SEC declared the Form S-3 effective on November 5, 2020. Pursuant to a prospectus supplement to the Form S-3, +we may offer and sell up to $100 million of the following securities separately or together, in one or more series or classes and in +amounts, at prices and on terms described in one or more offerings: common stock; preferred stock; warrants to purchase our securities, +each of which may be convertible into equity securities; or units comprised of, or other combinations of, the foregoing securities through +underwriting syndicates managed or co-managed by one or more underwriters or dealers, through agents or directly to purchasers. Each +time our securities are offered, we will provide a prospectus supplement to the Form S-3 containing more specific information about the +particular offering. To date, we have not filed a prospectus supplement to, or sold any securities under, this Form S-3. +Below +is a summary of the direct offerings done in 2020: +● +In January 2020, we sold +an aggregate of 3,448,278 shares of common stock to institutional investors for $1.45 per share for gross proceeds of approximately +$5.0 million pursuant to a shelf-registration statement on Form S-3 (File No: 333-226835) declared effective by the SEC on September +7, 2018 (the “Shelf Registration Statement”). +● +On February 10, 2020, the +Company entered into securities purchase agreements with certain institutional investors pursuant to which such investors purchased +an aggregate of 3,324,676 shares of common stock at a purchase price of $ 3.08 per share in a registered direct offering pursuant +to the Shelf Registration Statement. The aggregate gross proceeds for the sale of the shares were approximately $10.2 million. The +closing of the offering occurred on or about February 13, 2020. +● +On February 28, 2020, the +Company entered into securities purchase agreements with certain institutional investors pursuant to which such investors purchased +an aggregate of 470,000 shares of common stock at a purchase price of $9.00 per share in a registered direct offering pursuant to +the Shelf Registration Statement. The aggregate gross proceeds for the sale of the shares were approximately $4.0 million. The closing +of the offering occurred on or about February 28, 2020. +The +foregoing estimates, expectations and forward-looking statements are subject to change as we make strategic operating decisions from +time to time and as our revenue and expenses fluctuate from period to period. +Off-Balance +Sheet Arrangements +As +of December 31, 2021 and 2020, we had no off-balance sheet arrangements. +ITEM +7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Not +required. +22 +ITEM +8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. +CONSOLIDATED +FINANCIAL STATEMENTS +DECEMBER +31, 2021 AND 2020 +Table +of Contents +Report of Independent Registered Public Accounting Firm (PCAOB ID No. 457 ) +23 +Balance Sheets +24 +Statements of Operations +25 +Statement of Changes in Stockholders’ Equity +26 +Statements of Cash Flows +27 +Notes to Financial Statements +28 +REPORT +OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +To +the Board of Directors and Stockholders of Co-Diagnostics, Inc. +Opinion +on the Financial Statements +We +have audited the accompanying balance sheets of Co-Diagnostics, Inc. (the Company) as of December 31, 2021 and 2020, and the related +statements of operations, changes in stockholders’ equity, and cash flows for each of the years in the two-year period +ended December 31, 2021, and the related notes (collectively referred to as the financial statements). In our opinion, the financial +statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020 and the results +of its operations and its cash flows for each of the years in the two-year period ended December 31, 2021, in conformity with accounting +principles generally accepted in the United States of America. +Basis +for Opinion +These +financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s +financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board +(United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities +laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We +conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain +reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company +is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, +we are required to obtain an understanding of internal control over financial reporting, but not for the purpose of expressing an opinion +on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. +Our +audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error +or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding +the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant +estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits +provide a reasonable basis for our opinion. +Haynie +& Company +Salt +Lake City, Utah +March +24, 2022 +We +have served as the Company’s auditor since 2016. +23 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +CONSOLIDATED +BALANCE SHEETS +December 31, 2021 +December 31, 2020 +Assets +Current assets +Cash and cash equivalents +$ 88,607,234 +$ 42,976,713 +Marketable investment securities +1,255,266 +4,335,446 +Accounts receivable, net +20,839,182 +12,136,833 +Inventory +2,004,169 +7,995,189 +Prepaid expenses +2,338,444 +369,028 +Note receivable +75,000 +- +Total current assets +115,119,295 +67,813,209 +Property and equipment, net +1,933,216 +949,639 +Goodwill +14,706,818 +- +Intangible assets, net +27,195,000 +- +Investment in joint venture +1,004,953 +1,927,125 +Deferred tax asset +- +547,224 +Note receivable +75,000 +- +Total assets +$ 160,034,282 +$ 71,237,197 +Liabilities and stockholders’ equity +Current liabilities +Accounts payable +$ 607,506 +$ 598,318 +Accrued expenses, current +3,859,652 +2,849,503 +Accrued expenses (related party), current +- +120,000 +Contingent consideration liabilities, current +5,767,304 +- +Income taxes payable +2,213,088 +189,729 +Deferred revenue +150,000 +305,307 +Total current liabilities +12,597,550 +4,062,857 +Long-term liabilities +Income taxes payable +1,067,853 +447,831 +Deferred tax liability +7,228,444 +- +Contingent consideration liabilities +4,665,337 +- +Accrued expenses (related party), noncurrent +- +30,000 +Total long-term liabilities +12,961,634 +477,831 +Total liabilities +25,559,184 +4,540,688 +Commitments and contingencies (Note 14) +- +- +Stockholders’ equity +Convertible preferred stock, $ 0.001 par value; 5,000,000 shares authorized; 0 shares issued and outstanding as of December 31, 2021 and December 31, 2020 +- +- +Common stock, $ 0.001 par value; 100,000,000 shares authorized; 33,819,862 and 28,558,033 shares issued and outstanding as of December 31, 2021 and December 31, 2020, respectively +33,820 +28,558 +Additional paid-in capital +80,271,999 +49,157,236 +Accumulated earnings +54,169,279 +17,510,715 +Total stockholders’ equity +134,475,098 +66,696,509 +Total liabilities and stockholders’ equity +$ 160,034,282 +$ 71,237,197 +See +accompanying notes to consolidated financial statements. +24 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF OPERATIONS +2021 +2020 +Years Ended December 31, +2021 +2020 +Revenue +$ 97,885,603 +$ 74,552,758 +Cost of revenue +11,574,944 +16,591,346 +Gross profit +86,310,659 +57,961,412 +Operating expenses +Sales and marketing +13,397,813 +4,665,113 +General and administrative +11,550,615 +8,278,734 +Research and development +14,961,916 +3,185,290 +Depreciation and amortization +335,363 +138,635 +Total operating expenses +40,245,707 +16,267,772 +Income from operations +46,064,952 +41,693,640 +Other income (expense) +Interest income +45,631 +97,215 +Loss on disposition of assets +( 44,355 ) +( 175 ) +Gain (loss) on equity method investment in joint venture +( 430,433 ) +778,385 +Total other income (expense) +( 429,157 ) +875,425 +Income before income taxes +45,635,795 +42,569,065 +Income tax provision +8,977,231 +90,536 +Net income +$ 36,658,564 +$ 42,478,529 +Earnings per common share: +Basic +$ 1.27 +$ 1.59 +Diluted +$ 1.23 +$ 1.52 +Weighted average shares outstanding: +Basic +28,874,555 +26,720,133 +Diluted +29,903,686 +28,000,341 +See +accompanying notes to consolidated financial statements. +25 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY +Convertible +Preferred Stock +Common +Stock +Additional +Paid-in +Accumulated +Earnings +Total +Stockholders’ +Shares +Amount +Shares +Amount +Capital +(Deficit) +Equity +Balance as of December 31, 2019 +25,600 +$ 26 +17,342,922 +$ 17,343 +$ 26,687,701 +$ ( 24,967,814 ) +$ 1,737,256 +Public offering, net of offering costs of $ 1,457,922 +- +- +7,242,954 +7,243 +18,004,840 +- +18,012,083 +Common stock issued for warrant exercises +- +- +856,660 +857 +269,143 +- +270,000 +Common stock issued for option exercises +- +- +871,229 +871 +1,459,729 +- +1,460,600 +Stock-based compensation expense +- +- +110,935 +111 +2,737,930 +- +2,738,041 +Conversion of preferred stock to common +( 25,600 ) +( 26 ) +2,133,333 +2,133 +( 2,107 ) +- +- +Common stock issued for acquisitions +Common stock issued for acquisitions , shares +Net income +- +- +- +- +- +42,478,529 +42,478,529 +Balance as of December 31, 2020 +- +$ - +28,558,033 +$ 28,558 +$ 49,157,236 +$ 17,510,715 +$ 66,696,509 +Common stock issued for option exercises +- +- +189,225 +189 +450,209 +- +450,398 +Stock-based compensation expense +- +- +444,050 +444 +5,508,960 +- +5,509,404 +Common stock issued for acquisitions +- +- +4,628,554 +4,629 +25,155,594 +- +25,160,223 +Net income +- +- +- +- +- +36,658,564 +36,658,564 +Balance as of December 31, 2021 +- +$ - +33,819,862 +$ 33,820 +$ 80,271,999 +$ 54,169,279 +$ 134,475,098 +See +accompanying notes to consolidated financial statements. +26 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF CASH FLOWS +2021 +2020 +Years Ended December 31, +2021 +2020 +Cash flows from operating activities +Net income +$ 36,658,564 +$ 42,478,529 +Adjustments to reconcile net income to cash used in operating activities: +Depreciation and amortization +335,363 +138,635 +Stock-based compensation expense +5,509,404 +2,738,041 +Loss (gain) from equity method investment +430,433 +( 778,385 ) +Loss on disposition of assets +44,355 +175 +Deferred income taxes +930,081 +( 547,224 ) +Bad debt expense +69,672 +954,804 +Changes in assets and liabilities: +Accounts receivable +( 8,740,851 ) +( 12,960,255 ) +Prepaid expenses +( 2,049,095 ) +( 6,462 ) +Inventory +5,705,361 +( 7,915,241 ) +Deferred revenue +( 155,307 ) +303,984 +Income taxes payable +2,643,381 +- +Accounts payable and accrued expenses +( 299,937 ) +3,758,634 +Net cash provided by operating activities +41,081,424 +28,165,235 +Cash flows from investing activities +Purchases of property and equipment +( 669,463 ) +( 774,397 ) +Purchases of marketable investment securities +- +( 9,310,000 ) +Proceeds from maturities of marketable investment securities +3,080,180 +4,974,554 +Investment in joint venture +491,739 +( 714,500 ) +Business combinations, net of cash acquired +1,196,243 +- +Net cash provided by (used in) investing activities +4,098,699 +( 5,824,343 ) +Cash flows from financing activities +Proceeds from sale of common stock +- +19,470,005 +Proceeds from exercise of options and warrants +450,398 +1,730,599 +Payment of offering costs +- +( 1,457,921 ) +Net cash provided by financing activities +450,398 +19,742,683 +Net increase in cash and cash equivalents +45,630,521 +42,083,575 +Cash and cash equivalents at beginning of period +42,976,713 +893,138 +Cash and cash equivalents at end of period +$ 88,607,234 +$ 42,976,713 +Supplemental disclosure of cash flow information +Interest paid +$ - +$ - +Income taxes paid +$ 5,403,769 +$ - +Supplemental disclosure of non-cash investing and financing transactions +Inventory moved to property, plant and equipment +$ 285,659 +$ 117,220 +Fair value of common stock issued as consideration for business acquisitions +$ 25,160,223 +$ - +Fair value of contingent common stock and warrants issued as consideration for business acquisitions +$ 10,432,641 +$ - +See +accompanying notes to consolidated financial statements. +27 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS +YEARS +ENDED DECEMBER 31, 2021 AND 2020 +Note +1 – Overview and Basis of Presentation +Description +of Business +Co-Diagnostics, +Inc., a Utah corporation (the “Company” or “CODX”), is developing robust and innovative molecular tools +for detection of infectious diseases, liquid biopsy for cancer screening, and agricultural applications. The Company develops, manufactures +and sells reagents used for diagnostic tests that function via the detection and/or analysis of nucleic acid molecules (DNA or RNA). +In connection with the sale of these tests, the Company may sell diagnostic equipment and supplies from other manufacturers. +Use +of Estimates +The +preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates +and assumptions that affect the amounts reported in the financial statements and the accompanying notes. Such estimates include receivables +and other long-lived assets, legal and regulatory contingencies, income taxes, share based arrangements, and others. These estimates +and assumptions are based on management’s best estimates and judgments. Actual amounts and results could differ from those estimates. +Basis +of Presentation +The +accompanying audited consolidated financial statements of Co-Diagnostics, Inc. and its wholly owned subsidiaries have been prepared to +reflect the financial position, results of operations and cash flows of the Company and have been prepared in accordance with accounting +principles generally accepted in the United States of America (“GAAP”). All intercompany balances and transactions have been +eliminated. +Note +2 – Summary of Significant Accounting Policies +Reclassifications +Certain +prior year amounts have been reclassified to conform with the current year’s presentation. These reclassifications have no impact +on the previously reported results. +Cash +and Cash Equivalents +Cash +and cash equivalents consist of cash on hand, money market funds and highly liquid investments with an original maturity date of 90 days +or less from the date of purchase. The fair value of cash equivalents approximated their carrying value as of December 31, 2021 and December +31, 2020. The Company has its cash and cash equivalents with a large creditworthy financial institution +and the balance exceeded federally insured limits. The Company has not experienced any losses in such accounts, and management believes +the Company is not exposed to any significant credit risk on cash and cash equivalents. +Marketable +Investment Securities +The +Company’s marketable investment securities are comprised of investments in certificates of deposit. The Company determines the +appropriate classification of its marketable investment securities at the time of purchase and reevaluates such designation at each balance +sheet date. The Company has classified and accounted for its marketable investment securities as available-for-sale securities as the +Company may sell these securities at any time for use in its current operations or for other purposes, even prior to maturity. As +a result, the Company classifies its marketable investment securities, including securities with stated maturities beyond twelve months, +within current assets in the consolidated balance sheets. Any unrealized gains or losses are immaterial. +Accounts +Receivable +Trade +accounts receivable are recorded at the invoiced amount (net of allowance) and do not bear interest. The Company maintains an allowance +for doubtful accounts for amounts the Company does not expect to collect. In establishing the required allowance, management considers +historical losses, current market condition, customers’ financial condition, the age of receivables, and current payment patterns. +Account balances are written off against the allowance once the receivable is deemed uncollectible. Recoveries of trade receivables previously +written off are recorded when collected. At December 31, 2021 total accounts receivable was $ 21,508,779 with an allowance for uncollectable +accounts of $ 669,597 resulting in a net amount of $ 20,839,182 . At December 31, 2020 total accounts receivable was $ 12,928,633 with an +allowance for uncollectable accounts of $ 791,800 resulting in a net amount of $ 12,136,833 . +28 +Equity-Method +Investments +Our +equity method investments are initially recorded at cost and are included in other long-term assets in the accompanying consolidated +balance sheet. We adjust the carrying value of our investment based on our share of the earnings or losses in the periods which they +are reported by the investee until the carrying amount is zero. The earnings or losses are included in other income (expense) in the +accompanying consolidated statements of operations. +Inventory +Inventory +is stated at the lower of cost or net-realizable value. Inventory cost is determined on a first-in first-out basis that approximates +average cost in accordance with ASC 330-10-30-12. At December 31, 2021, the Company had $ 2,004,169 in inventory, of which $ 983,088 was +finished goods and $ 1,021,081 was raw materials. At December 31, 2020, the Company had $ 7,995,189 in inventory, of which $ 598,881 was +finished goods and $ 7,396,308 was raw materials. The Company establishes reserves to reduce low-moving, obsolete, or unusable inventories +to their estimated useful or scrap values. +Property +and Equipment +Property +and equipment are stated at cost less accumulated depreciation and amortization. Depreciation is provided using the straight-line method +over the estimated useful lives of the property, generally from three to five years . Repairs and maintenance costs are expensed as incurred +except when such repairs significantly add to the useful life or productive capacity of the asset, in which case the repairs are capitalized. +The +Company reviews its long-lived assets, including property and equipment, for impairment whenever an event or change in facts and circumstances +indicates that their carrying amounts may not be recoverable. Recoverability of these assets is measured by comparing the carrying amount +to the estimated undiscounted future cash flows expected to be generated. If the carrying amount exceeds the undiscounted cash flows, +the assets are determined to be impaired and an impairment charge is recognized as the amount by which the carrying amount exceeds fair +value. +Business +Combinations +We +estimate the fair value of assets acquired and liabilities assumed in a business combination. Goodwill as of the acquisition date is +measured as the excess of consideration transferred over the net of the acquisition date fair values of the assets acquired and the liabilities +assumed. Such valuations require management to make significant estimates and assumptions, especially with respect to intangible assets. +Management’s estimates of fair value are based upon assumptions believed to be reasonable, but which are inherently uncertain and +unpredictable, and as a result, actual results may differ from estimates. +Revenue +Recognition +The +Company generates revenue from product sales and license sales. The Company recognizes revenue when all of the following criteria are +satisfied: (i) identification of the promised goods or services in the contract; (ii) determination of whether the promised goods or +services are performance obligations, including whether they are distinct in the context of the contract; (iii) measurement of the transaction +price, including the constraint on variable consideration; (iv) allocation of the transaction price to the performance obligations; and +(v) recognition of revenue when, or as the Company satisfies each performance obligation. Based on the criteria above, the Company typically +recognizes revenue upon delivery. +The +Company constrains revenue by giving consideration to factors that could otherwise lead to a probable reversal of revenue. The Company +records any payments received from customers prior to the Company fulfilling its performance obligation(s) as deferred revenue. +Deferred +Revenue +Deferred +revenue primarily consists of payments received from customers prior to the Company fulfilling its performance obligation of providing +the product. When this occurs, the Company records a contract liability as deferred revenue. Deferred revenue is recognized as revenue +as the related performance obligations are satisfied. +29 +Research +and Development +Research +and development costs are expensed when incurred. The Company expensed $ 14,961,916 and $ 3,185,290 of research and development costs for +the years ended December 31, 2021 and 2020, respectively. +Stock-based +Compensation +The +Company has granted stock-based awards, including restricted stock, stock options, stock warrants and restricted stock units (“RSUs”), +to its employees, certain consultants and members of its board of directors. The Company records stock-based compensation based on the +grant date fair value of the awards and recognizes the fair value of those awards as expense using the straight-line method over the +requisite service period of the award. The Company estimates the grant date fair value of stock options using the Black-Scholes option-pricing +model. When an award is forfeited prior to the vesting date, the Company recognizes an adjustment +for the previously recognized expense in the period of the forfeiture. +Income +Taxes +The +Company accounts for income taxes in accordance with the liability method of accounting for income taxes. Under this method, d eferred +income tax assets and deferred income tax liabilities represent the tax effect of temporary differences between financial reporting and +tax reporting measured at enacted tax rates in effect for the year in which the differences are expected to reverse. The Company recognizes +only the impact of tax positions that, based on their technical merits, are more likely than not to be sustained upon an audit by the +taxing authority. +Valuation +allowances are provided when it is more-likely-than-not that some or all of the deferred income tax assets may not be realized. In assessing +the need for a valuation allowance, the Company has considered its historical levels of income, expectations of future taxable income +and ongoing tax planning strategies. +Developing +the provision for income taxes, including the effective tax rate and analysis of potential tax exposure items, if any, requires significant +judgment and expertise in federal and state income tax laws, regulations and strategies, including the determination of deferred income +tax assets and liabilities and any estimated valuation allowances deemed necessary to value deferred income tax assets. Judgments and +tax strategies are subject to audit by various taxing authorities. While the Company believes it has no significant uncertain income +tax positions in the consolidated financial statements, adverse determinations by these taxing authorities could have a material adverse +effect on the consolidated financial positions, result of operations, or cash flows. +Net +Income per Share +Basic +net income or loss per common share is computed by dividing net income or loss applicable to common shareholders by the weighted average +number of shares outstanding during each period. +Diluted +net income or loss per share is computed by dividing net income or loss attributable to common stockholders by the weighted-average number +of shares of common stock outstanding during the period increased by common shares that could be issued upon conversion or exercise of +other outstanding securities to the extent those additional common shares would be dilutive. The dilutive effect of potentially dilutive +securities is reflected in diluted net income or loss per share by application of the treasury stock method. During periods when the +Company is in a net loss position, basic net loss per share is the same as diluted net loss per share as the effects of potentially dilutive +securities are anti-dilutive +Concentrations +Risk and Significant Customers +The +Company had certain customers which are each responsible for generating 10% or more of the total revenue for the years ended December +31, 2021 and 2020. Two customers together accounted for approximately 48 % and 38 % of total revenue for the years ended December 31, 2021 +and 2020, respectively. +Two +customers each accounted for more than 10% of accounts receivable at December 31, 2021 and 2020. These two customers together accounted +for approximately 66 % and 48 % of accounts receivable at December 31, 2021 and 2020, respectively. +30 +Recently +Issued Accounting Standards +From +time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”) that are adopted +by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, +which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption. +As +an emerging growth company (“EGC”), the Company has elected to take advantage of the benefits of the extended transition +period provided for in Section 7(a)(2)(B) of the Securities Act of 1933, as amended, for complying with new or revised accounting standards +which allows the Company to defer adoption of certain accounting standards until those standards would otherwise apply to private companies. +In +February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), which requires recognition of leased assets and liabilities on the +balance sheet and disclosing key information about leasing arrangements. This update is effective for annual periods and interim periods +with those periods beginning after December 15, 2021, for public EGC companies like us. The Company will use the modified retrospective +transition method with the option to recognize a cumulative-effect adjustment at the date of adoption. The Company’s balance +sheet will be impacted as it records right-of-use assets and lease liabilities on its consolidated balance sheets, but the Company +does not expect the adoption of this standard will have a material impact on its consolidated statements of operations and cash flows. +In +June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326) (“ASU 2016-13”), which requires +the measurement and recognition of expected credit losses for certain financial instruments, which includes the Company’s accounts +receivable. ASU 2016-13 replaces the existing incurred loss impairment model with an expected loss methodology, which will result in +more timely recognition of credit losses. The update is effective for annual periods and interim periods with those periods beginning +after December 15, 2021, for public EGC companies. The standard requires a cumulative effect adjustment to the balance sheet as of the +beginning of the first early reporting period in which the guidance is effective. The Company is evaluating the impact of the adoption +of ASU 2016-13 on its consolidated financial statements but does not expect the adoption of this standard will have a material impact +on its consolidated financial statements. +Note +3 – Business Combinations +On +December 31, 2021, the Company completed its acquisition of Advanced Conceptions, Inc. (“ACI”) and Idaho Molecular Inc. (“IdMo”), +which were related entities developing, with the Company, an at-home/point-of-care medical diagnostic device. Upon the completion of +the acquisition, all outstanding ACI and Idaho Molecular common stock was exchanged for approximately 3.2 +million shares of the Company’s common +stock and contingent consideration that includes up to approximately 1.4 +million shares and approximately 456,000 +warrants to purchase shares of the Company’s +common stock. The contingent consideration is based on the achievement of certain milestones, which include regulatory approval for identified +products, as well as production and net revenue targets. The purchase consideration also includes a payable to a shareholder of ACI of +$ 100,000 . +In connection with the acquisition, the Company incurred transaction costs of approximately $ 151,000 , +which is included in general and administrative expenses. Upon the completion of the acquisition, both ACI and IdMo became 100 % +wholly-owned subsidiaries of the Company . +31 +The +fair value of assets acquired and liabilities assumed was based on a preliminary valuation, and our estimates and assumptions are subject +to change within the measurement period. The primary area that remains preliminary relates to the evaluation of certain tax-related items +and potential minor adjustments to the purchase consideration. The total purchase consideration was allocated to the assets acquired +and liabilities assumed as set forth below: +Schedule +of Assets and Liabilities assumed +Fair value of common shares issued +$ 25,160,223 +Payable to shareholder +100,000 +Fair value of contingent shares +8,684,669 +Fair value of contingent warrants +1,747,972 +Total fair value of consideration transferred +$ 35,692,864 +Identifiable assets acquired and liabilities assumed +Cash +$ 1,196,243 +Accounts receivable +31,170 +Prepaid expenses and other current assets +70,321 +Property and equipment +408,173 +Technology - In-process research and development +26,101,000 +Non-competition agreements +1,094,000 +Accounts payable and accrued other expenses +( 1,069,274 ) +Deferred tax liability +( 6,845,587 ) +Total identifiable net assets +20,986,046 +Goodwill +14,706,818 +Total +$ 35,692,864 +The +excess of the purchase price over the net assets acquired was recorded as goodwill. Goodwill generated from the acquisition is primarily +attributable to assembled workforce and expected growth from future technologies, sales to future customers and buyer specific synergies. +Goodwill will not be amortized but instead will be tested for impairment at least annually and more frequently if certain indicators +of impairment are present. As a result of the structure of the transaction, the balance of goodwill is not amortizable for tax purposes. +The +in-process research and development is considered an indefinite-lived intangible until the completion or abandonment of the research +and development activities. The non-competition agreements are being amortized over a range of 1.5 to 3 years. +As +the acquisition was completed on December 31, 2021, the acquired entities did not contribute to the net revenues or to the net income +of the Company during the year ended December 31, 2021. Pro forma revenue and results of operations have not been presented because the +historical results of ACI and IdMo are not material to the Company’s consolidated financial statements in any period presented. +Note +4 – Fair Value Measurements +The +Company measures and records certain financial assets and liabilities at fair value on a recurring basis. Fair value is based on the +price that would be received from selling an asset or paid to transfer a liability in an orderly transaction between market participants +at the measurement date. +The +following three levels of inputs are used to measure the fair value of financial assets and liabilities: +Level +1: Quoted market prices in active markets for identical assets or liabilities. +Level +2: Observable market-based inputs or unobservable inputs that are corroborated by market data. +Level +3: Unobservable inputs that are not corroborated by market data. +32 +The +following table summarizes the assets and liabilities measured at fair value on a recurring basis as of December 31, 2021 and December +31, 2020, by level within the fair value hierarchy: +Schedule +of Fair Value Assets and Liabilities +December 31, 2021 +(Level 1) +(Level 2) +(Level 3) +Total +Assets: +Marketable securities (certificates of deposit) +$ - +$ 1,255,266 +$ - +$ 1,255,266 +Total assets measured at fair value +$ - +$ 1,255,266 +$ - +$ 1,255,266 +Liabilities: +Contingent consideration - common stock +$ - +$ - +$ 8,684,669 +$ 8,684,669 +Contingent consideration - warrants +- +- +1,747,972 +1,747,972 +Total liabilities measured at fair value +$ - +$ - +$ 10,432,641 +$ 10,432,641 +December 31, 2020 +(Level 1) +(Level 2) +(Level 3) +Total +Assets: +Marketable securities (certificates of deposit) +$ - +$ 4,335,446 +$ - +$ 4,335,446 +Total assets measured at fair value +$ - +$ 4,335,446 +$ - +$ 4,335,446 +The +Company’s financial instruments that are measured at fair value on a recurring basis consist of certificates of deposit. +In +connection with the acquisitions of Idaho Molecular, Inc and Advanced Conceptions, Inc. on December 31, 2021, the Company recorded a +liability for contingent consideration in the form of shares of common stock and warrants to purchase common stock. The fair value of +contingent consideration is calculated using a discounted probability weighted valuation model. Discount rates used in such calculation +are a significant assumption that are not observed in the market, and therefore, the resulting fair value represents a Level 3 measurement. +The +changes for Level 3 items measured at fair value on a recurring basis are as follows: +Schedule +of Changes in Fair Value Measurement +Fair value as of December 31, 2020 +$ - +Contingent considered issued for business acquisitions +10,432,641 +Fair value as of December 31, 2021 +$ 10,432,641 +The +fair value of the contingent consideration is based on the fair value of the contingent consideration-common stock and contingent consideration-warrants. +The fair value of the contingent consideration-common stock is equal to the probability-adjusted value of the Company’s common +stock as of December 31, 2021. The fair value of the contingent consideration-warrants is equal to the probability adjusted value of +a call option with terms consistent with the terms of the warrants as of December 31, 2021. Prior to the probability adjustments, +the warrants were valued based on the following inputs: +Schedule +of Contingent Consideration Common Stock and Warrants +December 31, 2021 +Stock price +$ 8.93 +Strike price +$ 9.13 +Volatility +80.00 % +Risk-free rate +1.30 % +Expected term +5.0 +33 +In +order to calculate the probability-adjusted value of the contingent consideration-common stock and contingent consideration-warrants, +the Company estimated the probability of achieving certain milestones, which include regulatory approval for identified products, as +well as production and net revenue targets. The probability of achieving the milestone related to net revenues was estimated using a +Monte Carlo simulation valuation model. The unobservable significant inputs to the valuation model were as follows: +December 31, 2021 +Stock price +$ 8.93 +Risk-free rate +1.30 % +Expected term +5.0 +Weighted-average cost of capital +27.00 % +Revenue discount rate +9.50 % +Equity volatility +80.00 % +Asset volatility +80.00 % +Revenue volatility +30.00 % +Fair +Value of Other Financial Instruments +The +carrying amounts of certain financial instruments, including cash held in banks, accounts receivable, notes receivable, accounts +payable, accrued liabilities, and other liabilities approximate fair value due to their short-term maturities and are excluded from the +fair value tables above. +Note +5 – Property and Equipment +Property +and equipment, net consisted of the following: +Schedule +of Property and Equipment +Estimated +Useful Lives in +December 31, +years +2021 +2020 +Lab equipment +3 - 5 +$ 2,476,813 +$ 1,212,561 +Leasehold improvements +3 +3,157 +3,157 +Office equipment, furniture and other +2 - 5 +75,401 +38,344 +Less accumulated depreciation and amortization +( 622,155 ) +( 304,423 ) +Fixed assets, net +$ 1,933,216 +$ 949,639 +Note +6 - Goodwill and Intangible Assets +Intangible +assets, net consisted of the following: +Schedule +of Intangible Assets +Estimated +Useful Lives in +December 31, +years +2021 +2020 +In-process research and development +Indefinite +$ 26,101,000 +$ - +Non-competition agreements +1.5 - 3 +1,094,000 +- +Less accumulated amortization +- +- +Intangible assets, net +$ 27,195,000 +$ - +34 +The +expected future annual amortization expense of the Company’s intangible assets held as of December 31, 2021 is as follows: +Schedule +of Future Amortization Expense +Year Ending December 31, +Amortization Expense +2022 +$ 426,660 +2023 +364,668 +2024 +302,672 +Total +$ 1,094,000 +The +Company had goodwill of $14.7 million as of December 31, 2021. +Note +7 - Accrued Expenses +Accrued +expenses consisted of the following: +Schedule +of Accrued Expenses +December 31, 2021 +December 31, 2020 +Payroll liabilities +$ 2,455,694 +$ 1,627,957 +Distributor commissions +509,500 +1,070,000 +Sales tax payable +- +52,526 +Other accrued liabilities +894,458 +99,020 +Total accrued expenses +$ 3,859,652 +$ 2,849,503 +Note +8 – Revenue +The +following table sets forth revenue by geographic area: +Summary of Revenue by Geographic Area +Years Ended December 31, +2021 +2020 +United States +$ 52,185,812 +$ 44,862,751 +Rest of World +45,699,791 +29,690,007 +Total +$ 97,885,603 +$ 74,552,758 +Percentage of revenue by area: +United States +53 % +60 % +Rest of World +47 % +40 % +Deferred +Revenue +Changes +in the Company’s deferred revenue balance for the years ended December 31, 2021 and 2020 were as follows: +Schedule of Deferred Revenue +Balance as of December 31, 2019 +$ 1,323 +Revenue recognized included in deferred revenue balance at the beginning of the period +( 1,323 ) +Increase due to prepayments from customers +305,307 +Balance as of December 31, 2020 +305,307 +Revenue recognized included in deferred revenue balance at the beginning of the period +( 256,110 ) +Increase due to prepayments from customers +79,213 +Increase due to note receivable +150,000 +Decrease due to refunds to customers and application to open balances +( 128,410 ) +Balance as of December 31, 2021 +$ 150,000 +The +Company expects to perform its performance obligation and recognize the deferred revenue as revenue during the year ended December 31, +2022. +35 +Note +9 – Stockholders’ Equity +Common +Stock +During +the year ended December 31, 2021, the Company issued 189,225 +shares of common stock upon the exercise of options +and received $ 450,398 +in proceeds from the exercises. +During +the year ended December 31, 2021, the Company issued 5,548 shares of common stock for services provided by third parties primarily related +to investor relations services. +During +the year ended December 31, 2021, the Company issued 438,502 shares of common stock upon the vest and release of restricted stock units. +During +the year ended December 31, 2021, the Company issued 4,628,554 +shares of common stock related to the acquisitions +of Idaho Molecular, Inc. and Advanced Conceptions, Inc., 1,390,430 +of which are subject to forfeiture in favor +of the Company if certain milestones are not achieved on or before January 1, 2027. +During +the year ended December 31, 2020, the Company completed the sale of 3,448,278 shares of the Company’s common stock, par value $ 0.001 +per share, at a purchase price of $ 1.45 per share in a registered direct offering. The aggregate gross proceeds for the sale of the shares +were $ 5,000,003 and the Company received net proceeds of $ 4,517,102 after deducting offering costs of $ 482,901 . +During +the year ended December 31, 2020, the Company completed the sale of 3,324,676 shares of the Company’s common stock, par value $ 0.001 +per share, at a purchase price of $ 3.08 per share in a registered direct offering. The aggregate gross proceeds for the sale of the shares +were $ 10,240,002 and the Company received net proceeds of $ 9,612,561 after deducting offering costs of $ 627,441 . +During +the year ended December 31, 2020, the Company completed the sale of 470,000 shares of the Company’s common stock, par value $ 0.001 +per share, at a purchase price of $ 9.00 per share in a registered direct offering. The aggregate gross proceeds for the sale of the shares +were $ 4,230,000 and the Company received net proceeds of $ 3,882,420 after deducting offering costs of $ 347,580 . +During +the year ended December 31, 2020, the Company issued an aggregate of 2,133,333 shares of common stock upon conversion of all of the Company’s +convertible preferred stock outstanding as of December 31, 2019. +During +the year ended December 31, 2020, the Company issued 856,660 shares of common stock upon the exercise of warrants and received $ 270,000 . +During +the year ended December 31, 2020, the Company issued 871,229 +shares of common stock upon the exercise of options +and received $ 1,460,600 . +During +the year ended December 31, 2020, the Company issued 83,935 shares of common stock for services provided by third parties primarily related +to investor relations services. +36 +Note +10 – Earnings per Share +The +following table reconciles the numerator and the denominator used to calculate basic and diluted earnings per share for years ended December +31, 2021 and 2020: +Schedule of Basic and Diluted Earnings Per Share +2021 +2020 +Years Ended December 31, +2021 +2020 +Numerator +Net income, as reported +$ 36,658,564 +$ 42,478,529 +Denominator +Weighted average shares, basic +28,874,555 +26,720,133 +Dilutive effect of stock options, warrants and RSUs +1,029,131 +1,280,208 +Shares used to compute diluted earnings per share +29,903,686 +28,000,341 +Basic earnings per share +$ 1.27 +$ 1.59 +Diluted earnings per share +$ 1.23 +$ 1.52 +For +the years ended December 31, 2021 and 2020, respectively, potentially dilutive securities of 154,644 and 50,000 were +excluded from the computation of diluted earnings per share because the effect would have been anti-dilutive. The computation of +diluted earnings per share for the year ended December 31, 2021 also excludes the approximately 1.4 million shares of common stock +and approximately 456,000 warrants to purchase shares of common stock mentioned in Note 3 that are contingent upon the achievement +of certain milestones. +Note +11 – Stock-Based Compensation +Stock +Incentive Plans +The +Co-Diagnostics, Inc. 2015 Long Term Incentive Plan (the “Incentive Plan”) reserves an aggregate of 6,000,000 shares of common +stock issuable upon the grant of awards under the Incentive Plan. The number of awards available for issuance under the Incentive Plan +was 2,095,266 at December 31, 2021. +37 +Stock +Options +The +following table summarizes option activity during the years ended December 31, 2021 and 2020: +Schedule of Option Activity +Number of Options +Weighted Average Exercise Price +Weighted Average Fair Value +Weighted Average Remaining Contractual Life (Years) +Outstanding at December 31, 2019 +2,021,817 +$ 1.69 +$ 0.83 +Granted +150,000 +8.14 +4.74 +Expired +- +- +- +Forfeited/Cancelled +- +- +- +Exercised +( 871,229 ) +1.68 +0.89 +Outstanding at December 31, 2020 +1,300,588 +$ 2.44 +$ 1.24 +Granted +- +- +- +Expired +- +- +- +Forfeited/Cancelled +- +- +- +Exercised +( 189,225 ) +2.38 +1.12 +Outstanding at December 31, 2021 +1,111,363 +$ 2.12 +$ 1.31 +6.62 +Exercisable at December 31, 2021 +1,094,697 +$ 2.01 +$ 1.18 +6.59 +The +total intrinsic value of options exercised during the years ended December 31, 2021 and 2020 was approximately $ 1.3 +million and $ 11.8 +million, respectively. The aggregate intrinsic +value of outstanding options at December 31, 2021 and 2020 was approximately $ 7.6 +million and $ 7.1 +million, respectively. +As of December 31, 2021, there were 16,666 +unvested options and $ 78,115 +of unrecognized stock-based compensation +expense related to options. The unrecognized stock-based compensation expense is expected to be recognized over 0.5 +years. +Stock-based +compensation cost is measured at the grant date based on the fair value of the award granted and recognized as expense over the vesting +period using the straight-line method. The Company uses the Black-Scholes model to value options granted. The following weighted average +assumptions were used in estimating the grant date fair value of options: +Schedule of Fair Value of Options Weighted Average Assumptions +Years Ended December 31, +2021 +2020 +Risk-free interest rate +- +1.05 % +Expected life (years) +- +7.3 +Expected volatility +- +62.82 % +Expected dividend yield +- +None +38 +Restricted +Stock Units +The +grant date fair value of RSUs granted is determined using the closing market price of the Company’s common stock on the grant date +with the associated compensation expense amortized over the vesting period of the awards. The following table sets forth the outstanding +RSUs and related activity for the years ended December 31, 2021 and 2020: +Schedule of Outstanding Restricted Stock Units and Related Activity +Number of RSUs +Weighted Average Grant Date Fair Value +Unvested at December 31, 2019 +- +$ - +Granted +549,500 +10.49 +Vested +( 27,000 ) +10.49 +Forfeited/Cancelled +- +- +Unvested at December 31, 2020 +522,500 +$ 10.49 +Granted +1,217,500 +9.76 +Vested +( 438,502 ) +10.10 +Forfeited/Cancelled +( 34,083 ) +9.91 +Unvested at December 31, 2021 +1,267,415 +$ 9.94 +As +of December 31, 2021, there was $ 11.6 million of unrecognized stock-based compensation expense related to outstanding RSUs which is expected +to be recognized over a weighted-average period of 2.3 years. +Warrants +The +Company has issued warrants related to financings, acquisitions and as compensation to third parties for services provided. The Company +estimates the fair value of issued warrants on the date of issuance as determined using a Black-Scholes pricing model. The Company amortizes +the fair value of issued warrants using a vesting schedule based on the terms and conditions of each warrant if granted for services. +The +following table summarizes warrant activity during the years ended December 31, 2021 and 2020: +Schedule of Warrant Activity +Number of Warrants +Weighted Average Exercise Price +Weighted Average Fair Value +Weighted Average Remaining Contractual Life (Years) +Outstanding at December 31, 2019 +983,535 +$ 1.44 +$ 1.03 +Granted +20,000 +1.40 +15.19 +Expired +( 9,090 ) +6.00 +0.17 +Forfeited/Cancelled +- +- +- +Exercised +( 924,445 ) +1.42 +1.43 +Outstanding at December 31, 2020 +70,000 +$ 1.83 +$ 5.21 +3.3 +Granted +456,281 +9.13 +3.83 +Expired +- +- +- +Forfeited/Cancelled +- +- +- +Exercised +- +- +- +Outstanding at December 31, 2021 +526,281 +$ 8.15 +$ 4.01 +4.7 +The +intrinsic value of warrants exercised during the years ended December 31, 2021 and 2020 was $ 0 and approximately $ 9.7 million, respectively. +The aggregate intrinsic value of outstanding warrants at December 31, 2021 was approximately $ 497,000 . +39 +70,000 +warrants are exercisable at December 31, 2021. As discussed in Note 3 and Note 4, approximately 456,000 warrants to purchase shares of +the Company’s common stock were issued in connection with the acquisition of ACI and IdMo. The ability to exercise the warrants +is contingent upon the achievement of certain development and revenue milestones on or before January 1, 2027. There was no unrecognized +stock-based compensation expense related to warrants. +See +Note 4 for additional information regarding the fair value calculation of the warrants issued during the year ended December 31, 2021. +The fair values for the warrants issued during the year ended December 31, 2020 were estimated at the date of grant using the Black Scholes +model with the following weighted average assumptions: +Schedule of Fair Value of Warrants Assumptions +Year Ended December 31, +2020 +Risk-free interest rate +0.34 % +Expected life (years) +5.0 +Expected volatility +61.42 % +Expected dividend yield +None +Stock +Issued for Services +The +Company has issued restricted stock to third parties for services provided. The grant date fair value of the restricted stock granted +is determined using the closing market price of the Company’s common stock on the grant date with the associated compensation expense +amortized over the vesting period of the stock awards. The Company issued 5,548 and 83,935 shares of restricted stock for services during +the years ended December 31, 2021 and 2020, respectively, and there was no unrecognized stock-based compensation expense related to restricted +stock issued. +Stock-Based +Compensation Expense +The +Company recognized stock-based compensation expense related to the types of awards discussed above as follows: +Schedule of Recognized Stock-based Compensation Expense +2021 +2020 +Years Ended December 31, +2021 +2020 +Options +$ 292,754 +$ 901,345 +Restricted stock units +5,164,750 +500,861 +Warrants +- +303,802 +Stock +51,900 +1,032,033 +Total stock-based compensation expense +$ 5,509,404 +$ 2,738,041 +40 +Note +12 – Income Taxes +The +components of the provision for income taxes consists of the following for the years ended December 31, 2021 and 2020: +Schedule +of Components Income Tax Provision +2021 +2020 +Year Ended December 31, +2021 +2020 +Current: +Federal +$ 6,092,730 +$ - +State +886,173 +637,760 +Total current +$ 6,978,903 +$ 637,760 +Deferred: +Federal +1,394,686 +( 452,544 ) +State +603,642 +( 94,680 ) +Total deferred +1,998,328 +( 547,224 ) +Total income tax expense +$ 8,977,231 +$ 90,536 +A +reconciliation of income tax expense at the statutory federal income tax rate and income taxes as reflected in the financial statements +is as follows: +Schedule +of Benefit from Income Taxes and Effective Tax Rates +2021 +2020 +Year Ended December 31, +2021 +2020 +Federal income tax expense at statutory rate +21.0 % +21.0 % +State income tax expense, net of federal tax benefit +3.9 +3.3 +Permanent differences: +- Foreign derived intangible income deduction +( 3.5 ) +( 1.7 ) +- Stock based compensation +0.2 +( 8.8 ) +- Other permanent differences +0.3 +( 0.4 ) +Research and development credits +( 2.6 ) +( 2.0 ) +Change in uncertain tax positions +1.4 +1.1 +Change in valuation allowance +0.0 +( 12.1 ) +Other +( 1.0 ) +( 0.2 ) +Effective income tax rate +19.7 % +0.2 % +41 +Net +deferred tax assets consist of the following components as of December 31, 2021 and 2020: +Schedule +of Deferred Tax Assets +2021 +2020 +December 31, +2021 +2020 +Deferred tax assets: +Accrued liabilities +$ - +$ 37,898 +Reserves and allowances +166,050 +200,049 +Deferred compensation +393,871 +241,652 +Research and development credits +- +423,001 +Total deferred tax assets +559,921 +902,600 +Deferred tax liabilities: +Property and equipment, net +( 477,542 ) +( 233,951 ) +Intangibles, net +( 6,743,972 ) +- +Prepaids +( 560,093 ) +( 66,456 ) +Other +( 6,758 ) +( 54,969 ) +Total deferred tax liabilities +( 7,788,365 ) +( 355,376 ) +Net deferred tax assets (liabilities) +( 7,228,444 ) +547,224 +Less valuation allowance +- +- +Net deferred tax assets (liabilities) +$ ( 7,228,444 ) +$ 547,224 +At +December 31, 2021, the Company had no federal or state net operating loss carryforwards and no federal or state research and development +credit carryforwards. +As +of each reporting date, management considers new evidence, both positive and negative, that could affect its view of the future realization +of deferred tax assets. As of December 31, 2020, in part because in that year the Company achieved three years of cumulative pre-tax +income, management determined that there was sufficient positive evidence to conclude that it was more likely than not that its deferred +taxes were realizable. The Company therefore fully reduced its valuation allowance accordingly by $ 5,161,500 . +ASC +Topic 740-10-05 requires that the impact of a tax position be recognized in the financial statements if that position is more likely +than not of being sustained on audit, based on the technical merits of the position. Our unrecognized tax benefit balances included $ 1,067,853 +at December 31, 2021 and $ 447,831 at December 31, 2020 of tax positions that, if recognized, would impact our effective tax rate. The +Company expects no material changes to the liability for unrecognized tax benefits in the next 12 months. Interest and penalties associated +with uncertain tax positions are recorded as a component of income tax expense. A reconciliation of the beginning and ending amount of +unrecognized benefits is as follows: +Schedule +of Unrecognized Tax Benefits +December 31, +2021 +2020 +Unrecognized tax benefits at the beginning of the year +$ 447,831 +$ - +Gross increases - current year tax positions +770,069 +232,145 +Gross increases - prior year tax positions +- +215,686 +Gross decreases - prior year tax positions +( 150,047 ) +- +Unrecognized tax benefits at end of year +$ 1,067,853 +$ 447,831 +Interest and penalties in year-end balance +$ - +$ - +42 +The +Company is subject to taxation in the United States and other state jurisdictions. The tax years from December 31, 2017 through December +31, 2021 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which the Company +is subject. The Company is not currently under examination by any taxing authority. +Note +13 – Related Party Transactions +The +Company acquired the exclusive rights to the CoPrimer technology pursuant to an exclusive license agreement, dated April 2014 (the “Exclusive +License Agreement”), between the Company and DNA Logix, Inc., which was assigned to Dr. Brent Satterfield, an executive officer, +prior to the Company’s acquisition of DNA Logix, Inc. On March 1, 2017, the Company entered into an amendment to its Exclusive +License Agreement for its Cooperative Primers (“License”) technology with Dr. Satterfield. The amendment provided in part +that all accrued royalties under the License ceased as of January 1, 2017, and the Company agreed to pay to Dr. Satterfield $ 700,000 +of accrued royalties at the rate of $ 10,000 per month starting in January 2017. At December 31, 2021, the aggregate balance of this related +party liability was $ 0 . +Note +14 – Commitments and Contingencies +Lease +Obligations +The +Company’s offices are located at 2401 S. Foothill Dr., Suite D, Salt Lake City, Utah 84109-1479. In February 2020, the Company +entered into a 4 -year lease agreement for its office space and in March 2020, the Company entered into an addendum with our landlord +for additional space. The aggregate space consists of approximately 13,687 square feet at a monthly rate of $ 28,825 and expires in February +2024 . As a result of business acquisitions during the year ended December 31, 2021, the Company also leases additional laboratory and +office space under two month-to-month leases. For the years ended December 31, 2021 and 2020, the Company expensed $ 346,350 and $ 311,963 , +respectively, for rent. The Company’s future minimum lease payments were as follows as of December 31, 2021: +Schedule +of Future Minimum Lease Payments +Year Ending December 31, +2022 +$ 293,595 +2023 +303,059 +2024 +50,774 +Total lease payments +$ 647,428 +Litigation +Liabilities +for loss contingencies arising from claims, assessments, litigation, fines, and penalties and other sources are recorded when it is probable +that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss contingencies +are expensed as incurred. +Five +different securities class action complaints were filed in July, September and December by certain stockholders of the Company against +the Company claiming that the Company promulgated false and misleading press releases to increase the price of our stock to improperly +benefit the officers and directors of the Company. The plaintiffs demand compensatory damages sustained as a result of the Company’s +alleged wrongdoing in an amount to be proven at trial. The Company believes these lawsuits are without merit and intends to defend the +cases vigorously. The Company is unable to estimate a range of loss, if any, that could result were there to be an adverse final decision +in these cases. As of the date of this report, the Company does not believe it is probable that these cases will result in an unfavorable +outcome; however, if an unfavorable outcome were to occur in these cases, it is possible that the impact could be material to the Company’s +results of operations in the period(s) in which any such outcome becomes probable and estimable. +43 +Note +15 – Subsequent Events +In +March 2022, the Company’s Board of Directors authorized a share repurchase program that would allow the Company to repurchase up +to $ 30 million of CODX common stock. The repurchase program does not obligate the Company to acquire any particular amount of common +shares, and the repurchase program may be suspended or discontinued at any time at the Company’s discretion. The timing and amount +of any share repurchases under the share repurchase program will be determined by Co-Diagnostics’ management at its discretion +based on ongoing assessments of the capital needs of the business, the market price of the Company’s common stock, corporate and +regulatory requirements, and general market conditions. Share repurchases under the program may be made through a variety of methods, +which may include open market purchases, in block trades, accelerated share repurchase transactions, exchange transactions, the use of +trading plans intended to qualify under Rule 10b5-1 under the Securities Exchange Act of 1934, as amended, or any combination of such +methods. +ITEM +9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. +None. +ITEM +9A. CONTROLS AND PROCEDURES +Evaluation +of Disclosure Controls and Procedures +We +maintain a set of disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) designed to ensure that information +required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within +the time periods specified in rules and forms adopted by the SEC. Disclosure controls and procedures include, without limitation, controls +and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under +the Exchange Act is accumulated and communicated to the Company’s management, including its principal executive and principal financial +officers, as appropriate to allow timely decisions regarding required disclosure. +Our +management, with the participation of our Chief Executive Officer and our Chief Financial Officer, evaluated the effectiveness of our +disclosure controls and procedures as of December 31, 2021. Based on the evaluation, management has concluded that our disclosure controls +and procedures are effective as of December 31, 2021 to provide reasonable assurance regarding the reliability of +our financial reporting and the preparation of our financial statements for external reporting purposes in accordance with U.S. generally +accepted accounting principles. +Changes +in Internal Control Over Financial Reporting +There +have not been any changes in the Company’s internal control over financial reporting (as such term is defined in Rules 13a- 15(f) +and 15d-15(f) under the Exchange Act) during the fourth quarter of 2021 that have materially affected, or are reasonably likely to materially +affect, the Company’s internal control over financial reporting. +Management’s +Annual Report on Internal Control over Financial Reporting +Our +management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) +under the Exchange Act). Our management, including our Chief Executive Officer and Chief Financial Officer, conducted an evaluation of +the effectiveness of our internal control over financial reporting as of December 31, 2021. In making its evaluation, management used +the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated +Framework (2013). +Based +on this evaluation, management determined that our internal control over financial reporting was effective as of December 31, 2021. +44 +This +Annual Report does not include an attestation report by our independent registered public accounting firm regarding internal control +over financial reporting since we are an emerging growth company. Management’s report was not subject to attestation by our registered +public accounting firm pursuant to rules of the SEC that permit emerging growth companies to provide only management’s report in +the 10-K. +Inherent +Limitations on Effectiveness of Controls +Our +management, including our Chief Executive Officer and Chief Financial Officer, believes that our disclosure controls and procedures and +internal control over financial reporting are intended to be designed to provide reasonable assurance of achieving their objectives. +However, our management does not expect that our disclosure controls and procedures or our internal control over financial reporting +will prevent or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, +not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact +that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent +limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of +fraud, if any, have been detected. These inherent limitations include the realities that judgments in decision making can be faulty, +and that breakdowns can occur because of a simple error or mistake. Additionally, controls can be circumvented by the individual acts +of some persons, by collusion of two or more people or by management override of the controls. The design of any system of controls also +is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed +in achieving its stated goals under all potential future conditions; over time, controls may become inadequate because of changes in +conditions, or the degree of compliance with policies or procedures may deteriorate. Because of the inherent limitations in a cost–effective +control system, misstatements due to error or fraud may occur and not be detected. +ITEM +9B. OTHER INFORMATION +None. +ITEM +9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS. +None. +PART +III +ITEM +10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE. +The +following table sets forth the names, ages and positions of our executive officers and directors as of March 24, 2022. Our Board of Directors +is currently comprised of five members, who are elected annually to serve for one year or until their successor is duly elected and qualified, +or until their earlier resignation or removal. Executive officers serve at the discretion of the Board of Directors. +Name +Age +Position +Dwight +Egan +68 +Chief +Executive Officer, President and Chairman of the Board +Brian +Brown +46 +Chief +Financial Officer and Secretary +Eugene +Durenard +52 +Director +James +Nelson +69 +Director +Richard +Serbin +77 +Director +Ted +Murphy +57 +Director +Dwight +Egan serves as our President and Chief Executive Officer and has been an officer and director of the Company since April 2013. Mr. +Egan has been engaged in private investment business from February 1999 to the present. He was a senior executive at Data Broadcasting +Corporation, a leading provider of wireless, real-time financial market data, news and sophisticated fixed- income portfolio analytics +to 27,000 individual and professional investors from 1995 to 1999. He co-founded and served as CEO and Chairman of the Board of Broadcast +International, Inc. from 1984 to 1995, when Data Broadcasting Corporation acquired Broadcast International and created CBS MarketWatch , +a leading financial news site and participated in its initial public offering. Mr. Egan’s prior experience in executive leadership +positions with public companies and working with capital markets qualifies him to serve as our Chairman, President and Chief Executive +Officer. +45 +Brian +Brown became our Chief Financial Officer in February 2021. From July 2020 until February 2021, Mr. Brown served as the Chief Financial +Officer of A-Core Concrete Cutting, Inc. where his duties included overseeing the company’s accounting and finance departments, +mergers and acquisitions and responsibility for financial forecasting and budgeting. From August 2019 to December 2019, Mr. Brown served +as the Vice President of Accounting, Treasury and Investor Relations at Sportsman’s Warehouse Holdings, Inc., a public company +reporting on Nasdaq Global Select under the symbol SPWH, where his duties included overseeing the company’s accounting, treasury +and investor relations departments, preparing the company’s annual, quarterly and current reports with the SEC, overseeing all +aspects of the company’s annual audit, including, but not limited to, the preparation and review of audit support schedules, preparation +of financial statements and footnotes, and providing support to the company’s independent auditors. From October 2009 to August +2019, Mr. Brown served as the Director of Finance of Sportsman’s Warehouse Holdings, Inc. where he assisted with the company’s +initial public offering in April 2014 as well as effecting private and secondary public offerings, acquisitions of a group of retail +stores and preparing the company’s periodic and current reports with the SEC and complying with the Sarbanes Oxley Act. From May +2005 to October 2009, Mr. Brown served as the Corporate Controller of Franklin Covey Products where he developed and maintained the company’s +internal controls over financial reporting structure in accordance with the control standards required under Section 404 of the Sarbanes +Oxley Act. From July 2001 to May 2005, Mr. Brown served as an Assurance Senior at KPMG, LLP where he provided audit services to various +clients in multiple industries. Mr. Brown holds a Bachelor of Arts in Accounting and Masters of Professional Accountancy from the University +of Utah. Mr. Brown is a licensed CPA in Utah. +Eugene +Durenard has been a member of our Board of Directors since June 2019. Dr. Durenard is the Founder and CEO of Hyperbolic Holdings, +a Swiss-based holding, management consulting and strategy advisory company specialized in healthcare. Dr. Durenard brings an investment +and entrepreneurial experience spanning 20 years. For the last 7 years he has been working with family offices on direct investments +and philanthropy focused on life sciences. He serves on the advisory board of several private companies in the biotech and MedTech sectors +as well as an impact venture fund focused on healthcare. After an initial career in proprietary research and trading at Salomon Brothers +and Credit Suisse in London, he co-founded Orion Investment Management in Bermuda specializing in quantitative asset and liability management +for institutions and private clients. He subsequently sold it to Capital G Bank and co-headed their asset management. Dr. Durenard spent +several years establishing personal connections with representatives of 40+ clusters of life science innovation, families operating healthcare +businesses and industry leaders globally. He regularly visits labs and incubators, meets with leading scientists and innovators in order +to keep abreast of current trends and developments. His advice is based on a thorough analysis that combines in-depth knowledge of science, +competitive forces and financial expertise. He has published several articles in asset-liability management industry magazines as well +as the book “Professional Automated Trading — Theory and Practice” (Wiley 2013). He has a PhD in Mathematics from Harvard +University. Dr. Durenard brings a thorough multi-asset class investment and entrepreneurial experience spanning 20 years to the Company’s +Board of Directors. +Edward +Murphy has been a member of our Board of Directors since June 2019. Mr. Murphy currently serves as a senior vice president and a +partner of Dover Investments Ltd., a private investment firm. Throughout his career, Mr. Murphy’s duties have included investment +analysis of various types of investment projects in real estate and financial services. Currently, Mr. Murphy serves on the board of +directors of several Canadian publicly reporting companies that have interests in various industries. He has been a Director at Empire +Minerals Corporation Inc. since January 2016, at Digicrypts Blockchain Solutions Inc. since June 2011, at Lakefield Marketing Corporation +since February 2018, CEO/CFO and Director of Credo Resources Inc. since September 2019, and at the Mosport Park Entertainment Corporation +since April 30, 1997. He served as a Director at Aurquest Resources from May 2003 to December 2017. Mr. Murphy’s experience in +the capital markets outside the United States and his involvement in investment analysis is a benefit to the Board of Directors. +46 +Richard +Serbin has been a member of our Board of Directors since May 2017. Mr. Serbin currently serves as a consultant to many companies +in the healthcare industry. He was the President of Corporate Development and In-House Legal Counsel at Life Science Institute, LLC, +from June 1, 2013 to July 15, 2014. Mr. Serbin is a global strategy advisor, pharmacist and entrepreneur with credentials both in pharmacy +and law, complemented by more than 40 years of service as an FDA regulatory attorney and patent attorney in the healthcare industry. +He was appointed to the Advisory Board of Cure Pharmaceutical in January 2017 and has been a Member of Advisory Board at Prime Access, +Inc. since September 2015. Mr. Serbin has been a Director at Rapid Nutrition Plc since November 18, 2014. He served as Director at Viropro +Inc. from May 2013 to June 2014. He was Head of Business Advisory Board at Mazal Plant Pharmaceuticals Inc. from October 2006 to September +2007 and also served as its Member of Business Advisory Board. He served as Chief Executive Officer of Optigenex Inc. from July 2002 +to September 15, 2005 and a director from July 2004 to September 2005. From January 1999 until July 2002 Mr. Serbin served as a consultant +to various pharmaceutical companies. He served as the President of Bradley Pharmaceuticals. He served as Vice President of Corporate +Development at Ortho Pharmaceuticals, a Johnson & Johnson subsidiary, and practiced Patent and FDA law at Revlon Johnson & Johnson +and Schering-Plough. He served as Patent Attorney for Schering Plough Corporation and Chief FDA Counsel for Revlon Corporation and Johnson +and Johnson Corporation. Subsequently, he worked at Revlon Corporation, as its Chief Food, Drug and Cosmetic Counsel. He founded Radius +Scientific Corporation. He was J&J’s Vice President of Corporate Development, and later led a successful public offering venture +based on technology developed at Stanford Medical School. Mr. Serbin spent a large portion of his career focusing on international markets +and clients. While at J&J, Mr. Serbin served on the Board of Directors of 16 US and international subsidiary companies, including +Ethicon, Ortho, J&J Consumer Products, Pittman-Moore, Mc Neil, and J&J Development Corporation. He worked on multiple international +acquisitions and strategic relationships, and sat on the Board of Directors of several of its international subsidiaries, including those +in India, Hong Kong, Japan, Taiwan, Germany, and England. Mr. Serbin has a B.S. and a B. Pharmacy from Rutgers University and Rutgers +University College of Pharmacy, a J.D. degree from Seton Hall Law School and a Master’s Degree in Trade Regulations and Law from +NYU Law School. Mr. Serbin’s experience in business, law and medicine and knowledge gained as an advisor to the healthcare industry +is critical to our Board of Directors as we continue to commercialize our products. +James +Nelson has been a member of our Board of Directors +since June 2019. Mr. Nelson is the retired Chairman and CEO of Sunworks, Inc., a NASDAQ traded +commercial, agriculture, and residential solar Integrator which he helped found in October 2010. Mr. Nelson currently serves as strategic +advisor to three other publicly traded companies. Jim has spent most of his career working in private equity as a general partner with +Peterson Partners and with Millennial Capital Partners. In addition to his investment and financial responsibilities, he served as CEO +of two of his firms’ portfolio companies. Prior to his years in private equity, Mr. Nelson served as Vice President of Marketing +at Banana Republic, where he managed company-wide marketing, as well as the company’s international expansion initiative. He was +also general manager for Banana Republic’s catalog division. He was Vice President of Marketing and Corporate Development at Saga +Corporation, a multi-billion-dollar food service company. Jim began his executive career over 35 years ago at Bain and Company, a business +strategy consulting firm, where he managed teams of consultants on four continents. Mr. Nelson received his MBA from Brigham Young University, +where he graduated summa cum laude and was named the Outstanding Master of Business Administration Graduate. Mr. Nelson’s advice +to the Board of Directors from his experiences as a chief executive officer and strategic advisor is useful to the Board of Directors. +Involvement +in Certain Legal Proceedings +To +the best of our knowledge, none of our directors or executive officers has been involved in any bankruptcy or criminal proceedings (other +than traffic and other minor offenses) or been subject to any of the items set forth under Item 401(f) of Regulation S-K, nor have there +been any judgments or injunctions brought against any of our directors or executive officers during the last ten years that we consider +material to the evaluation of the ability and integrity of any director or executive officer. +Board +and Committee Matters +Our +Board of Directors has five members. The Chairman of the Board and our Chief Executive Officer, Dwight Egan, is a member of the Board +and is a full-time employee of the Company, Eugene Durenard, Edward Murphy, James Nelson and Richard Serbin are non-employee directors, +and the Board has determined that these persons (who constitute a majority of the Board) are “independent directors” under +the criteria set forth in Rule 5605(a)(2) of the Nasdaq Listing Rules. The Board met seven times during the year ended December 31, 2021. +All directors attended more than seventy-five percent (75%) of the meetings of the Board and committee meetings of which such director +was a member held during 2021. +47 +We +maintain an audit committee of the board, a compensation committee of the board and a corporate governance/nominating committee of the +board, each of which is discussed below. Our board has determined that Messrs. Durenard, Nelson, Murphy and Serbin are “independent” +under the definition of independence in the Marketplace Rules of the NASDAQ listing requirements. Our Board of Directors may from time +to time establish other standing committees. In addition, from time to time, special committees may be established under the direction +of our Board of Directors when necessary to address specific issues. +The +following table sets forth a description of the three permanent Board committees and the chairpersons and members of those committees, +all of whom are independent directors: +Committee +Independent +Chairperson +Independent +Members +Audit Committee +Eugene Durenard +Edward Murphy +James Nelson +Richard S. Serbin +Compensation Committee +Richard S. Serbin +Edward Murphy +Eugene Durenard +James Nelson +Governance/Nominating Committee +James Nelson +Edward Murphy +Eugene Durenard +Richard S. Serbin +Audit +Committee and Financial Expert +Our +audit committee currently is comprised of Messrs. Durenard, Nelson, Murphy and Serbin with Mr. Durenard serving as chairperson of the +audit committee. The functions of the audit committee include engaging an independent registered public accounting firm to audit our +annual financial statements, reviewing the independence of our auditors, the financial statements and the auditors’ report, and +reviewing management’s administration of our system of internal control over financial reporting and disclosure controls and procedures. +The Board of Directors has adopted a written audit committee charter. A current copy of the audit committee charter is available to security +holders on our website at www.codiagnostics.com. Our board has determined that all of our directors that are serving on the audit committee +are “independent” under the definition of independence in the Marketplace Rules of the NASDAQ listing standards. The Audit +Committee met four times during the year ended December 31, 2021. All committee members attended more than seventy-five percent (75%) +of the meetings of the Audit Committee held during 2021. +Our +Board of Directors has determined that Mr. Durenard meets the requirements of an “audit committee financial expert” as defined +in applicable SEC regulations. +Compensation +Committee +Our +compensation committee currently includes Messrs. Serbin, Nelson, Murphy and Durenard with Mr. Serbin serving as chairperson of the compensation +committee. The functions of the compensation committee include reviewing and approving corporate goals relevant to compensation for executive +officers, evaluating the effectiveness of our compensation practices, evaluating and approving the compensation of our chief executive +officer and other executives, recommending compensation for board members, and reviewing and making recommendations regarding incentive +compensation and other employee benefit plans. The Board of Directors has adopted a written compensation committee charter. A current +copy of the compensation committee charter is available to shareholders on our website at www.codiagnostics.com . Our board has +determined that all of our directors serving on the compensation committee are “independent” under the definition of independence +in the Marketplace Rules of the NASDAQ listing standards. The Compensation Committee met four times during the year ended December 31, +2021. All committee members attended more than seventy-five percent (75%) of the meetings of the Compensation Committee held during +2021. +48 +Corporate +Governance/Nominating Committee +Our +corporate governance/nominating committee currently include Messrs. Nelson, Murphy, Durenard and Serbin with Mr. Nelson serving as chairperson +of the corporate governance/nominating committee. Among other items, the committee is tasked by the Board of Directors to: develop and +recommend to the Board the Corporate Governance Guidelines of the Company and oversee compliance therewith; assist the Board in effecting +Board organization, membership and function including identifying qualified Board nominees; assist the Board in effecting the organization, +membership and function of Board committees including the composition of Board committees and recommending qualified candidates therefor; +evaluate and provide successor planning for the Chief Executive Officer and other executive officers; and to develop criteria for Board +membership, such as independence, term limits, age limits and ability of former employees to serve on the Board and the evaluation of +candidates’ qualifications for nominations to the Board, its committees as well as removal therefrom, respectively. A current copy +of the corporate governance/nominating committee charter is available to shareholders on our website at www.codiagnostics.com . Our +board has determined all directors serving on the corporate governance committee are “independent” under the definition of +independence in the Marketplace Rules of the NASDAQ listing standards. The Corporate Governance/Nominating Committee met four times during +the year ended December 31, 2021. All committee members attended more than seventy-five percent (75%) of the meetings of the Audit Committee +held during 2021. The nominating committee reviews the qualifications for candidates for the Board of Directors and assists in identifying, +interviewing, and recruiting candidates for the Board of Directors. +Board +Nominations +In +considering Board candidates, the Board seeks individuals of proven judgment and competence who have strong reputations in their respective +fields. Although we do not have a formal diversity policy, the Board considers such factors as experience, education, employment history, +special talents or personal attributes, anticipated participation in Board activities, and geographic and diversity factors. The process +for identifying and evaluating nominees would include detailed consideration of the recommendations and opinions of members of our Board, +our executive officers, and our stockholders. There would be no difference in the process of evaluation of candidates recommended by +a stockholder and those recommended by other sources. +We +do not have a formal policy concerning shareholder recommendations of candidates for board of director membership. Our board views that +such a formal policy is not necessary at the present time given the board’s willingness to consider candidates recommended by shareholders. +Shareholders may recommend candidates by writing to our Secretary at our principal offices: 2401 S. Foothill Drive, Suite D, Salt Lake +City, Utah 84109, giving the candidate’s name, contact information, biographical data and qualifications. A written statement from +the candidate consenting to be named as a candidate and, if nominated and elected, to serve as a director should accompany any such recommendation. +Shareholders who wish to nominate a director for election are generally advised to submit a shareholder proposal no later than December +31 for the next year’s annual meeting of shareholders. +Communication +with the Board +We +have not, to date, developed a formal process for shareholder communications with the board of directors. We believe our current informal +process, in which any communication sent to the board of directors, either generally or in care of the chief executive officer, secretary +or other corporate officer or director, is forwarded to all members of the board of directors, has served the board’s and the shareholders’ +needs. +Conflicts +of Interests +On +an annual basis, each director and executive officer is obligated to complete a director and officer questionnaire that requires disclosure +of any transactions with our company, including related person transactions reportable under SEC rules, in which the director or executive +officer, or any member of his or her immediate family, have a direct or indirect material interest. Under our company’s standards +of conduct for employees, all employees, including the executive officers, are expected to avoid conflicts of interest. Pursuant to our +code of ethics for the chief executive officer and senior finance officers (as discussed below), such officers are prohibited from engaging +in any conflict of interest unless a specific exception has been granted by the board. All of our directors are subject to general fiduciary +standards to act in the best interests of our company and our shareholders. Conflicts of interest involving an executive officer or a +director are generally resolved by the board. +49 +Role +of the Board in Risk Oversight +Risk +is inherent with every business, and how well a business manages risk can ultimately determine its success. Management is responsible +for the day-to-day management of the risks that we face, while our Board of Directors, as a whole and through its committees, has responsibility +for the oversight of risk management. In its risk oversight role, our Board of Directors is responsible for satisfying itself that the +risk management processes designed and implemented by management are adequate and functioning as designed. +Our +Board of Directors does not have a standing risk management committee, but rather administers this oversight function directly through +our Board of Directors as a whole, as well as through various standing committees of the Board of Directors that address risks inherent +in their respective areas of oversight. In particular, our Board of Directors is responsible for monitoring and assessing strategic risk +exposure, including a determination of the nature and level of risk appropriate for us. Our Audit Committee has the responsibility to +consider and discuss our major financial risk exposures and the steps our management has taken to monitor and control these exposures, +including guidelines and policies to govern the process by which risk assessment and management is undertaken. The Audit Committee also +monitors oversight of the performance of our internal audit function. Our Corporate Governance/Nominating Committee monitors the effectiveness +of our corporate governance guidelines, including whether they are successful in preventing illegal or improper liability-creating conduct. +Our Compensation Committee assesses and monitors whether any of our compensation policies and programs have the potential to encourage +excessive risk-taking or promote behaviors contra to our Code of Business Conduct. +Delinquent +Section 16(a) Reports +Section +16(a) of the Exchange Act requires our directors and executive officers, and persons who own more than 10% of our common stock, to file +with the SEC initial reports of ownership and reports of changes in ownership of our common stock and other equity securities. Executive +officers, directors and greater than 10% shareholders are required by SEC regulations to furnish us with copies of all Section 16(a) +forms they file. +The +Company prepares these reports for its directors and executive officers who request it on the basis on information obtained from them +and the Company’s records. The Company believes that applicable Section 16(a) filing requirements were met during 2021 by its directors +and executive officers, except that due to an inadvertent administrative error, one Form 4 for Eugene Durenard was filed +late. +Code +of Ethics +We +have adopted a code of ethics for our principal executive officer, principal financial officer, controller, or persons performing similar +functions. A copy of the code of ethics is included on our website at www.codiagnostics.com. +Family +Relationships +There +are no family relationships among our directors and executive officers. +ITEM +11. EXECUTIVE COMPENSATION +We +are an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012 and a “smaller reporting +company” as defined in the rules and regulations of the SEC. As an emerging growth company and as a smaller reporting company we +may take advantage of specified reduced disclosure and other requirements that are otherwise applicable, in general, to public companies +that are not emerging growth companies or smaller reporting companies. Accordingly, this Report includes reduced disclosure about our +executive compensation arrangements. +Summary +Compensation Table +The +table below summarizes the total compensation paid or earned by each of the named executive officers in their respective capacities for +the fiscal years ended December 31, 2021 and 2020. We have omitted in this report certain columns otherwise required to be included because +there was no compensation made with respect to such columns, as permitted by applicable SEC regulations. +50 +Name and Principal Position +Year +Salary +Bonus (1) +Stock +Awards (2) +All Other +Comp (3) +Total +Compensation +Dwight Egan +President & Chief Executive Officer +2021 +$ 350,000 +$ 638,459 +$ 1,208,750 +$ 26,793 +$ 2,224,002 +2020 +$ 309,375 +$ 350,000 +$ 786,750 +$ 17,500 +$ 1,463,625 +Brian Brown +Chief Financial Officer and Secretary +2021 +$ 209,731 +$ 475,014 +$ 1,441,600 +$ +26,793 +$ 2,153,138 +Reed Benson (4) +Former Chief Financial Officer and Secretary +2021 +$ 136,250 +$ 154,682 +$ - +$ +26,793 +$ 317,725 +2020 +$ 211,458 +$ 225,000 +$ 288,475 +$ 17,500 +$ 742,433 +(1) +Bonuses +for the year ended December 31, 2021 include accrued bonus payments of $281,597 to +Mr. Egan and $223,248 to Mr. Brown that were paid in February 2022. Bonuses for the +year ended December 31, 2020 include accrued bonus payments of $272,500 to Mr. Egan and $180,000 +to Mr. Benson that were paid in February 2021. +(2) +The +amounts reported in this column represent the aggregate grant date fair value of the restricted stock units, or RSUs, granted under our +2015 Plan as computed in accordance with FASB ASC Topic 718. Note that the amounts reported in this column reflect the accounting value +for these equity awards and do not correspond to the actual economic value that may be received from the equity awards as the RSUs vest +over three years. +(3) +Company profit sharing payments to the Company’s +401 K Plan. +(4) +Mr. +Benson is no longer an executive officer of the Company as of August 2021. +51 +Outstanding +Equity Awards at Fiscal Year-End 2021 +The +following table contain certain information concerning outstanding equity awards for the Named Executive Officers as of December 31, +2021. +Option Awards +Stock Awards +Number of Securities Underlying Unexercised Options (#) +Option Exercise +Option Expiration +Number of Shares or Units of Stock That Have Not +Market Value of Shares or Units of Stock That Have Not Vested +Number of Unearned Shares, Units or Other Rights That Have Not +Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not +Name +Exercisable +Unexercisable +Price +Date +Vested (#) +($) (1) +Vested (#) +Vested ($) +Dwight Egan +50,000 +- +$ 2.63 +09/20/28 +- +- +- +- +50,000 +- +$ 1.10 +09/02/29 +- +- +- +- +- +- +- +- +154,167 +$ +1,376,711 +- +- +Brian Brown +- +- +- +- +103,333 +$ +922,764 +- +- +Reed Benson +41,666 +- +$ 1.10 +09/02/29 +- +- +- +- +- +- +- +- +18,332 +$ +163,705 +- +- +(1) +Based on $8.93 per share which was the closing price +of our common stock on December 31, 2021. +We +do not have written employment agreements with any of our executive officers. All of our executive officers serve on an at-will basis. +The base salaries, bonuses and equity awards for our named executive officers were determined by our compensation committee after reviewing +a number of factors, including: company performance, achievement of goals, the responsibilities associated with the position, the seniority +of the executive’s position, the base salary level in prior years, and our financial position; and for executive officers other +than our Chief Executive Officer, recommendations made by our Chief Executive Officer. +Potential +Payments Upon Termination or Change of Control +There +is no compensation payable to the named executive officers upon voluntary termination, retirement, involuntary not-for-cause termination, +termination following a change of control or in the event of disability or death of the executive. +Director +Compensation +We +use a combination of cash and stock-based incentive compensation to attract and retain qualified candidates to serve on its board of +directors. In setting director compensation, we consider the significant amount of time that directors expend in fulfilling their duties +as well as the skill-level required by our members of the board. +52 +Director +Summary Compensation Table +The +table below summarizes the compensation paid or accrued by us to each of our non-employee directors for the fiscal year ended December +31, 2021. +Name +Fees Earned or +Paid in Cash +Stock Awards: +Value of Restricted +Stock Units (1) +Total +Richard Serbin +$ 100,000 +$ 413,250 +$ 513,250 +James Nelson +$ 100,000 +$ 413,250 +$ 513,250 +Edward Murphy +$ 100,000 +$ 413,250 +$ 513,250 +Eugene Durenard +$ 100,000 +$ 413,250 +$ 513,250 +(1) +The amounts reported in +this column represent the aggregate grant date fair value of the restricted stock units, or RSUs, granted under our 2015 Plan as +computed in accordance with FASB ASC Topic 718. Note that the amounts reported in this column reflect the accounting value for these +equity awards and do not correspond to the actual economic value that may be received from the equity awards. The RSUs vested immediately +upon grant. +Our +non-employee directors receive cash compensation of $75,000 per year, paid quarterly. The non-employee directors also each received 37,500 +RSU’s vesting 1/3 rd equally in January 2021, 2022, and 2023. In addition, non-employee directors may be entitled to +receive special awards of stock options or RSUs from time to time as determined by the board. During 2021, the non-employee directors +were also each awarded an additional $25,000 bonus. The chairman of the board and the chairperson of each of the audit, corporate governance/nomination, +and compensation committees receive no additional fees for serving in such capacities. There is no additional compensation for meeting +attendance. Directors who are employees of the Company receive no additional compensation for serving as directors. All stock options +granted to outside directors are immediately exercisable and expire ten years from the date of grant or 30 days after the date they cease +to be directors. Directors are reimbursed for ordinary expenses incurred in connection with attending board and committee meetings. +53 +Equity +Compensation Plan Information +Plan Category +(a) Number of Shares to be Issued upon Exercise of Outstanding Options and Rights +(b) Weighted-average Exercise Price of Outstanding Options and Rights +(c) Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Referenced in Column (a)) +Equity compensation plans approved by stockholders +2,378,778 (1) +$ 2.12 (2) +2,095,266 +Equity compensation plans not approved by stockholders +- +$ - +- +Total +2,378,778 (1) +$ 2.12 (2) +2,095,266 +(1) +Includes options and restricted +stock units outstanding under our 2015 Equity Incentive Plan. +(2) +Represents weighted-average +exercise price per share of common stock acquirable upon exercise of outstanding stock options. +Equity +Incentive Plans +Under +our Amended and Restated 2015 Long-term Incentive Plan (the “2015 Plan”), the board of directors may issue incentive stock-based +awards to employees, directors and consultants of the company. Options awarded generally expire ten years after being granted. Any stock-based +awards granted vest in accordance with the vesting schedule determined by the board of directors. Should an employee’s director’s +or consultant’s relationship with the company terminate before the vesting period is completed, the unvested portion of each grant +is forfeited. We continue to maintain and grant awards under the 2015 Plan which will remain in effect its expiration by its terms. +The +purpose of our incentive plan is to advance the interests of our stockholders by enhancing our ability to attract, retain and motivate +persons who are expected to make important contributions to the company by providing them with both equity ownership opportunities and +performance-based incentives intended to align their interests with those of our stockholders. These plans are designed to provide us +with flexibility to select from among various equity-based compensation methods, and to be able to address changing accounting and tax +rules and corporate governance practices by optimally utilizing stock-based awards. +ITEM +12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The +following table sets forth certain information, as of March 22, 2022, with respect to the holdings of (1) each person who is the +beneficial owner of more than 5% of our Common Stock, (2) each of our directors, (3) each named executive officer, and (4) all of our +current directors and executive officers as a group. +Beneficial +ownership of the common stock is determined in accordance with the rules of the Securities and Exchange Commission and includes any shares +of common stock over which a person exercises sole or shared voting or investment power, or of which a person has a right to acquire +ownership at any time within 60 days of March 22, 2022. Except as otherwise indicated, we believe that the persons named in this +table have sole voting and investment power with respect to all shares of common stock held by them. Applicable percentage ownership +in the following table is based on 33,965,318 shares of common stock plus, for each individual, any securities that individual +has the right to acquire within 60 days of March 22, 2022. +54 +To +the best of our knowledge, except as otherwise indicated, each of the persons named in the table has sole voting and investment power +with respect to the shares of our common stock beneficially owned by such person, except to the extent such power may be shared with +a spouse. To our knowledge, none of the shares listed below are held under a voting trust or similar agreement, except as noted. To our +knowledge, there is no arrangement, including any pledge by any person of securities of the Company, the operation of which may at a +subsequent date result in a change in control of the Company. The information in the tables below is based on information known to us +or ascertained by us from public filings made by the stockholders. Except as otherwise indicated in the table below, addresses of the +director, executive officers and named beneficial owners are in care of Co-Diagnostics, Inc., 2401 S. Foothill Drive, Suite D, Salt Lake +City, Utah 84109. +Number of Shares Beneficially Owned +Percentage +of Class (1) +5% Stockholders +Vanguard Group (1) +1,795,057 +5.3 % +Named Executive Officers and Directors +Dwight Egan (2) +124,661 +* +Reed Benson (3) +44,836 +* +Brian Brown +18,459 +* +Edward Murphy (4) +75,000 +* +Eugene Durenard +12,500 +* +James Nelson (5) +62,500 +* +Richard Serbin (6) +35,445 +* +All Directors and Executive Officers as a Group (7 persons) +373,401 +1.1 % +*Represents +beneficial ownership of less than 1%. +(1) +Information obtained from +Schedule 13G/A filed with the SEC on February 2, 2022. Vanguard Group has an address of 100 Vanguard Blvd, Malvern, PA, 19355. +(2) +Includes exercisable options +to acquire 100,000 shares of common stock. +(3) +Includes exercisable options +to acquire 41,666 shares of common stock. +(4) +Includes exercisable options +to acquire 50,000 shares of common stock. +(5) +Includes exercisable options +to acquire 50,000 shares of common stock. +(6) +Includes exercisable options +to acquire 20,445 shares of common stock. +ITEM +13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +The +Company acquired the exclusive rights to the CoPrimer technology pursuant to a license agreement dated April 2014, between us and DNA +Logix, Inc., which was assigned to Dr. Satterfield prior to our acquisition of DNA Logix, Inc. Pursuant to the license the Company was +to pay Dr. Satterfield minimum royalty payments of $30,000 per month until the Company receives an equity funding of at least $4,000,000, +at which time the payments increase to $60,000 per month for the remainder of the year. The payment terms were orally modified to maintain +the monthly royalties at $30,000 per month through December 2016. On March 1, 2017, the Company entered into an amendment effective January +1, 2017, to its Exclusive License Agreement for its CoPrimer (“License”) technology with Dr. Satterfield, a former member +of our Board of Directors. The amendment provides in part that all royalties under the License cease as of January 1, 2017, and we began +in January 2017 to pay $700,000 of accrued royalties at the rate of $10,000 per month. In 2021 and 2020, we paid Dr. Satterfield $150,000 +and $120,000, respectively, in payment of the accrued royalties. +55 +The +Company employs two persons who are related to current or former executive officers. Seth Egan is the Company’s Director of Sales +and Marketing, and is the son of Dwight Egan, the Company’s President and Chief Executive Officer. Andrew Benson is the Company’s +Director of Investor Relations, and is the son of Reed Benson, the Company’s former Chief Financial Officer and Secretary. During +the year ended December 31, 2021, the total compensation paid to or earned by these persons, including salaries, bonuses, and the grant +date fair value of equity awards which vest over three years, was $1,512,457 and $1,285,790, respectively. During the +year ended December 31, 2020, the total compensation paid to or earned by these persons, including salaries, bonuses, and the grant date +fair value of equity awards which vest over three years, was $1,113,440 and $1,109,303, respectively. +ITEM +14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +The +following table presents aggregate fees for professional services rendered by our independent auditors for the respective periods. +Years Ended December 31, +2021 +2020 +Audit fees +$ 113,100 +$ 115,000 +Audit related fees +- +- +Other consulting fees +- +- +Tax fees +- +1,000 +Total fees +$ 113,100 +$ 116,000 +Audit +fees consist of fees for professional services provided in connection with the audit of our annual consolidated financial statements, +review of our quarterly consolidated financial statements and our offerings. +Tax +fees included fees associated with tax compliance and tax consultations. +The +audit committee has adopted a policy that requires advance approval of all services performed by the independent auditor when fees are +expected to exceed $15,000. The audit committee has delegated to the audit committee chairperson, Mr. Durenard, the authority to approve +services, subject to ratification by the audit committee at its next committee meeting. All fees incurred were pre-approved by the audit +committee. +PART +IV +Item +15. Exhibits, Financial Statement Schedules. +(a) +The +following documents are filed as part of this Annual Report on Form 10-K: +(1) +Financial +Statements. The Consolidated Financial Statements filed as part of this Annual Report on Form 10-K are included in Part II, Item +8 of this Annual Report on Form 10-K. +(2) +Financial +statement schedules. There are no financial statements schedules included because they are either not applicable or the required +information is shown in the consolidated financial statements or the notes thereto. +(3) +Exhibits. +The exhibits required by Item 601 of Regulation S-K and Item 15(b) of this Annual Report are listed in the Exhibit Index below. The +exhibits listed in the Exhibit Index are incorporated by reference herein. +56 +Exhibit +Number +Exhibit +Description +Filed +with this +Report +Incorporated +by +Reference +herein from Form or Schedule +Filing +Date +SEC +File/Reg. +Number +2.1*+ +Agreement and Plan of Merger by and between Co-Diagnostics, Inc, IDMO Acquisition Corp., Idaho Molecular Inc., and Company Representative dated as of December 21, 2021. +Form 8-K (Exhibit 2.1) +12/23/21 +001-38148 +2.2*+ +Agreement and Plan of Merger by and between Co-Diagnostics, Inc, ACI Acquisition Corp., Advanced Conceptions, Inc., and Company Representative dated as of December 21, 2021 +Form 8-K (Exhibit 2.2) +12/23/21 +001-38148 +3.1 +Articles of Incorporation +Draft Registration Statement +(Exhibit 3.1) +01/12/17 +377-01467 +3.1.1 +Amendment to the Articles of Incorporation +Draft Registration Statement +(Exhibit 3.1.1) +01/12/17 +377-01467 +3.1.2 +Articles of Amendment to Articles of Incorporation +Form 8-K (Exhibit 3.2) +01/03/19 +001-38148 +3.1.3 +Articles of Amendment +X +3.2 +Bylaws +Draft Registration Statement +(Exhibit 3.2) +01/12/17 +377-01467 +4.1 +Description of Registrant’s securities +X +10.1 +Exclusive Agreement between Co-Diagnostics, Inc. and DNA Logix, Inc., dated April 18, 2014 +Draft Registration Statement +(Exhibit 10.2) +01/12/17 +377-01467 +10.2 # +Co-Diagnostics, Inc. Amended and Restated 2015 Long Term Incentive Plan +Form S-8/A +11/20/20 +333-237684 +10.3 +Form of Indemnification Agreement +Form S-1/A (Exhibit 10.13.8) +05/24/17 +333-217542 +10.4 +Shareholders’ Agreement between Co-Diagnostics and Synbiotics Limited, dated January 27, 2017 +Form S-1 (Exhibit 10.16) +04/28/17 +333-217542 +10.5 +Amended Exclusive License Agreement between Co-Diagnostics, Brent Satterfield, and DNA Logix, Inc., dated January 1, 2017 +Form S-1 (Exhibit 10.17) +04/28/17 +333-217542 +10.6 +Warrant Agreement between Co-Diagnostics, Inc and VStock Transfer, LLC. Dated December 31, 2021 (ACI Warrant) +X +57 +10.7 +Warrant Agreement between Co-Diagnostics, Inc and VStock Transfer, LLC. Dated December 31, 2021 (IDMO Warrant) +X +10.8 +Form of Securities Purchase Agreement, dated February 27, 2020 +Form +8-K (Exhibit 10.1) +02/27/20 +001-38148 +10.9 +Lease Agreement 2401 Foothill Drive +X +10.9.1 +Amendment #1 to Lease +X +10.9.2 +Amendment #2 to Lease +X +14.1 +Code of Ethics for Senior Financial Officers +Form +10-K (Exhibit 14.1) +03/30/20 +001-38148 +21.1 +Subsidiaries of Registrant +X +23.1 +Consent +of Haynie & Company +X +31.1 +Certification +of Chief Executive Officer pursuant to section 302 of the Sarbanes-Oxley Act of 2002 +X +31.2 +Certification +of Principal Financial Officer pursuant to section 302 of the Sarbanes-Oxley Act of 2002 +X +32.1 +Certification +of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 +X +32.2 +Certification +of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of +2002 +X +101 +SCH +Inline +XBRL Taxonomy Extension Schema Document (A) +X +101.CAL +Inline +XBRL Taxonomy Extension Calculation Linkbase Document (A) +X +101.DEF +Inline +XBRL Taxonomy Extension Definition Linkbase Document (A) +X +101.LAB +Inline +XBRL Taxonomy Extension Label Linkbase Document (A) +X +101.PRE +Inline +XBRL Taxonomy Extension Presentation Linkbase Document (A) +X +104 +Cover +Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) +X +(A) +iXBRL +(INline Extensible Business Reporting Language) information +is furnished and not filed for purposes of Section 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange +Act of 1934. +X +# Management +Contract or Compensatory Plan or Arrangement +*Schedules +and exhibits to these Exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company agrees to furnish supplementally +a copy of any omitted schedule or exhibit to the SEC upon request. ++ +Portions of Exhibit 2.1 and Exhibit 2.2 have been omitted as they contain information that (i) is not material and (ii) is the type of +information the issuer both customarily and actually treats as private and confidential. +58 +SIGNATURES +Pursuant +to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed +on its behalf by the undersigned thereunto duly authorized. +CO-DIAGNOSTICS, +INC. +Date: March 24, 2022 +By: +/s/ +Dwight Egan +Dwight Egan +Chief +Executive Officer, President and Director +(Principal +Executive Officer) +By: +/s/ +Brian Brown +Brian +Brown +Chief +Financial Officer +(Principal +Financial and Accounting Officer +Pursuant +to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the +registrant and in the capacities and on the date indicated. +Signature +Title +Date +/s/ Dwight +Egan +Chief Executive Officer, +President and Director +March 24, 2022 +Dwight Egan +(Principal Executive Officer) +/s/ Brian +Brown +Chief Financial Officer +March 24, 2022 +Brian Brown +(Principal Financial and +Accounting Officer) +/s/ Eugen +Durenard +Director +March 24, 2022 +Eugene Durenard +/s/ Edward +Murphy +Director +March 24, 2022 +Edward Murphy +/s/ James +Nelson +Director +March 24, 2022 +James Nelson +/s/ Richard +Serbin +Director +March 24, 2022 +Richard Serbin +59 \ No newline at end of file diff --git a/raw/filings/0001692415/2021/0001493152-22-007662/filing_metadata.csv b/raw/filings/0001692415/2021/0001493152-22-007662/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..7deed24a69959b59a0e758e71d165901778f8195 --- /dev/null +++ b/raw/filings/0001692415/2021/0001493152-22-007662/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001692415,CODX,"Co-Diagnostics, Inc.",10-K,2022-03-24,2021-12-31,2022-03-25T00:08:29.000Z,0001493152-22-007662,form10-k.htm,,6948562,1,1,https://www.sec.gov/Archives/edgar/data/1692415/000149315222007662/form10-k.htm,https://www.sec.gov/Archives/edgar/data/1692415/000149315222007662/,2021,2021,1 diff --git a/raw/filings/0001692415/2021/0001493152-22-007662/item1.txt b/raw/filings/0001692415/2021/0001493152-22-007662/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001692415/2021/0001493152-22-007662/item13.txt b/raw/filings/0001692415/2021/0001493152-22-007662/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001692415/2021/0001493152-22-007662/item9a.txt b/raw/filings/0001692415/2021/0001493152-22-007662/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001692415/2021/0001493152-22-007662/rp_note.txt b/raw/filings/0001692415/2021/0001493152-22-007662/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..69d56468a168a8e72c1c65f7146fed0197e2efb4 --- /dev/null +++ b/raw/filings/0001692415/2021/0001493152-22-007662/rp_note.txt @@ -0,0 +1,10 @@ +13 – Related Party Transactions +The +Company acquired the exclusive rights to the CoPrimer technology pursuant to an exclusive license agreement, dated April 2014 (the “Exclusive +License Agreement”), between the Company and DNA Logix, Inc., which was assigned to Dr. Brent Satterfield, an executive officer, +prior to the Company’s acquisition of DNA Logix, Inc. On March 1, 2017, the Company entered into an amendment to its Exclusive +License Agreement for its Cooperative Primers (“License”) technology with Dr. Satterfield. The amendment provided in part +that all accrued royalties under the License ceased as of January 1, 2017, and the Company agreed to pay to Dr. Satterfield $ 700,000 +of accrued royalties at the rate of $ 10,000 per month starting in January 2017. 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+incorporation +or organization) +(Primary +Standard Industrial +Classification +Code Number) +(I.R.S. +Employer +Identification +Number) +2401 +S. Foothill Drive , Salt Lake City , Utah 84109 +(Address +of principal executive offices and zip code) +(801) +438-1036 +(Registrant’s +telephone number including area code) +Securities +registered pursuant to Section 12(b) of the Act: +Title +of each class +Trading +Symbol(s) +Name +of each exchange on which registered +Common Stock +CODX +The Nasdaq Capital Market +Securities +registered pursuant to Section 12(g) of the Act: None +Indicate +by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒ +Indicate +by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ☐ No ☒ +Indicate +by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act of 1934 +during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject +to such filing requirements for the past 90 days. Yes ☒ No ☐ +Indicate +by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data +File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding +12 months (or such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐ +Indicate +by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting +company or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller +reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. +Large accelerated +filer +☐ +Accelerated +filer +☐ +Non-accelerated filer +☒ +Smaller reporting company +☒ +Emerging growth company +☐ +If +an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying +with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ +Indicate +by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness +of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered +public accounting firm that prepared or issued its audit report. ☐ +If +securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant +included in the filing reflect the correction of an error to previously issued financial statements. ☐ +Indicate +by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation +received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). +☐ +Indicate +by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒ +The +aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which +the common stock was last sold as of the last business day of the registrant’s most recently completed second fiscal quarter was +approximately $ 187,000,000 . +As +of March 14, 2023, there were 30,922,607 shares of common stock, par value $0.001 per share, outstanding. +Table +of Contents +Page +PART I +Item +1. +Business. +4 +Item +1A. +Risk Factors. +12 +Item +1B. +Unresolved Staff Comments. +23 +Item +2. +Properties. +24 +Item +3. +Legal Proceedings. +24 +Item +4. +Mine Safety Disclosures. +25 +PART II +Item +5. +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. +26 +Item +6. +[Reserved.] +27 +Item +7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations. +27 +Item +7A. +Quantitative and Qualitative Disclosures About Market Risk. +32 +Item +8. +Financial Statements and Supplementary Data. +33 +Item +9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +57 +Item +9A. +Controls and Procedures. +57 +Item +9B. +Other Information. +58 +Item +9C. +Disclosure Regarding Foreign Jurisdictions that Prevent Inspections. +58 +PART III +Item +10. +Directors, Executive Officers and Corporate Governance. +5 8 +Item +11. +Executive Compensation. +64 +Item +12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. +68 +Item +13. +Certain Relationships and Related Transactions, and Director Independence. +69 +Item +14. +Principal Accountant Fees and Services. +69 +PART IV +Item +15. +Exhibits and Financial Statement Schedules. +70 +2 +PART +I +Forward-Looking +Statements +This +Annual Report on Form 10-K contains “forward-looking statements” that involve risks and uncertainties. All statements other +than statements of historical fact contained in this Annual Report and the documents incorporated by reference herein, including statements +regarding future events, our future financial performance, business strategy, and plans and objectives of management for future operations, +are forward-looking statements. We have attempted to identify forward-looking statements by terminology including “anticipates,” +“believes,” “can,” “continue,” “could,” “estimates,” “expects,” +“intends,” “may,” “plans,” “potential,” “predicts,” “should,” +or “will” or the negative of these terms or other comparable terminology. Although we do not make forward looking statements +unless we believe we have a reasonable basis for doing so, we cannot guarantee their accuracy. These statements are only predictions +and involve known and unknown risks, uncertainties and other factors which may affect our or our industry’s actual results, levels +of activity, performance or achievements expressed or implied by these forward-looking statements. Moreover, we operate in a highly regulated, +very competitive, and rapidly changing environment. New risks emerge from time to time, and it is not possible for us to predict all +risk factors, nor can we address the impact of all factors on our business or the extent to which any factor, or combination of factors, +may cause our actual results to differ materially from those contained in any forward-looking statements. +We +have based these forward-looking statements largely on our current expectations and projections about future events and financial trends +that we believe may affect our financial condition, results of operations, business strategy, short term and long-term business operations, +and financial needs. These forward-looking statements are subject to certain risks and uncertainties that could cause our actual results +to differ materially from those reflected in the forward-looking statements. Factors that could cause or contribute to such differences +include, but are not limited to, those discussed in this Annual Report, and in particular, the risks discussed under “ Item 1, +Business,” “Item 1A, Risk Factors,” and “Item 7, Management’s Discussion and Analysis of Financial Condition +and Results of Operations,” and those discussed in other documents we file with the Securities and Exchange Commission (the +“SEC”). In light of these risks, uncertainties and assumptions, the forward-looking events and circumstances discussed in +this Annual Report may not occur as described and actual results could differ materially and adversely from those anticipated or implied +in the forward-looking statement. +Important +factors that could cause actual results to differ materially from those in the forward-looking statements include, without limitation: +● +the +results of clinical evaluations and the regulatory approval process; +● +market +acceptance of any products that may be approved for commercialization; +● +our +ability to protect our intellectual property rights; +● +the +impact of any infringement actions or other litigation brought against us; +● +competition +from other providers and products; +● +our +ability to develop and commercialize new and improved products and services; +● +changes +in government regulation; +● +and +other factors (including the risks contained in the section entitled “Risk Factors” in other documents we file with the +SEC) relating to our industry, our operations and results of operations. +Should +one or more of these risks or uncertainties materialize, or should the underlying assumptions prove incorrect, actual results may differ +significantly from those anticipated, believed, estimated, expected, intended or planned. +Given +these risks and uncertainties, readers are cautioned not to place undue reliance on any forward-looking statements. Forward-looking statements +contained in this Annual Report speak only as of the date of this Annual Report. We undertake no obligation to update any forward-looking +statements as a result of new information, events or circumstances or other factors arising or coming to our attention after the date +hereof. +3 +As +used in this Annual Report, the terms “we”, “us”, “our”, “Company” and “Co-Diagnostics” +means Co-Diagnostics, Inc., a Utah corporation and its consolidated subsidiaries (the “Company”), unless otherwise indicated. +ITEM +1: BUSINESS +Overview +Co-Diagnostics, +Inc., a Utah corporation (the “Company” or “CODX”), develops, manufactures and sells reagents used for diagnostic +tests that function via the detection and/or analysis of nucleic acid molecules (DNA or RNA), including robust and innovative molecular +tools for detection of infectious diseases, liquid biopsy for cancer screening, and agricultural applications. In connection with the +sale of our tests we may sell diagnostic equipment from other manufacturers as self-contained lab systems (which we refer to as the “MDx +Device”). We are also developing a unique, groundbreaking portable PCR device and proprietary test cups (the “Co-Dx PCR Home™ +platform”) that have been designed to bring affordable, reliable polymerase chain reaction (“PCR”) to patients in point-of-care +and even at-home settings. This platform is subject to U.S. Food and Drug Administration (“FDA”) review and is not available +for sale at the time of this filing. There is no guarantee that our Co-Dx PCR Home platform will receive the necessary regulatory approvals +for commercialization, or that, if regulatory approval is received, we will be able to successfully commercialize this platform. +Our +diagnostics systems enable dependable, low-cost, molecular testing for organisms and genetic diseases by automating or simplifying historically +complex procedures in both the development and administration of tests. CODX’s technical advance involves a novel, patented approach +to PCR test design of primer and probe structure (“CoPrimers™”) that eliminates one of the key vexing issues of PCR +amplification: the exponential growth of primer-dimer pairs (false positives and false negatives) which adversely interferes with identification +of the target DNA/RNA. +We +believe our proprietary molecular diagnostics technology is paving the way for innovation in disease detection and life sciences research +through our enhanced detection of genetic material. For various reasons, including owning our own platform, we believe we will be able +to accomplish this faster and more economically than some competitors, allowing for significant margins while still positioning ourselves +as a low-cost provider of molecular diagnostics and screening services. +In +addition, continued development has demonstrated the unique properties of our CoPrimer technology that we believe makes it ideally suited +for a variety of applications where specificity is key to optimal results, including multiplexing several targets, enhanced Single Nucleotide +Polymorphism (“SNP”) detection and enrichment for next generation sequencing. +Our +scientists use the complex mathematics of DNA/RNA PCR test design to engineer and optimize PCR tests and to automate algorithms that +rapidly screen millions of possible options to pinpoint the optimum design. Dr. Brent Satterfield, our founder, developed the intellectual +property we use in our business, consisting of the predictive mathematical algorithms and patented molecular structure used in the testing +process, which together represent a major advance in PCR testing systems. CODX technologies are now protected by more than 20 granted +or pending US and foreign patents, as well as certain trade secrets and copyrights. Ownership of our proprietary platform permits us +the advantage of avoiding payment of patent royalties required by other PCR test systems, which may allow the sale of diagnostic PCR +tests at a lower price than competitors, while enabling us to maintain profit margins. +Our +proprietary test design process involves identifying the optimal locations on the target genes for amplification and pair the locations +with the optimized primer and probe structure to achieve outputs that meet the design input requirements identified from market research. +This is done by following planned and documented processes, procedures and testing. In other words, we use the data resulting from our +tests to verify whether we succeeded in designing what we intended. Verification involves a series of testing that concludes that the +product is ready to proceed to validation in an evaluation either in our laboratory or in an independent laboratory setting using initial +production tests to confirm that the product as designed meets the user needs. +We +may either sell or lease the MDx Device to labs and diagnostic centers, through sale or lease agreements, and sell the reagents that +comprise our proprietary tests to those laboratories and testing facilities. +4 +Using +our proprietary test design system and proprietary reagents, we have designed and obtained regulatory approval in the European Community +and/or in India to sell PCR diagnostic tests for the detection of COVID-19, influenza, tuberculosis, hepatitis B and C, human papillomavirus, +malaria, chikungunya, dengue, and the Zika virus. In the United States, we obtained Emergency Use Authorization (“EUA”) for +our Logix Smart ™ COVID-19 detection test from the Food and Drug Administration, or +FDA, and we sell that test to qualified labs. In addition, our COVID-19 detection test and certain of our other suite of COVID-19 products +have been approved for sale in countries such as the United Kingdom, Australia and Mexico by the regulatory bodies in those countries +and have been registered for sale in many more countries. +In +addition to testing for infectious disease, the technology lends itself to identifying any section of a DNA or RNA strand that describes +any type of genetic trait, which creates several significant applications. We, in conjunction with our customers, are active in designing +and licensing tests that identify genetic traits in plant and animal genomes. We also have three multiplexed tests developed to test +mosquitos for the identification of diseases carried by the mosquitos to enable municipalities to concentrate their efforts in managing +mosquito populations on the specific areas known to be breeding the mosquitos that carry deadly viruses. +On +January 23, 2020, we announced the completion of the principal design work for a PCR test for COVID-19, intended to address the potential +need for detection of the virus. This test features our patented CoPrimers technology, and was designed using our proprietary software +system, following the guidelines published by the World Health Organization (WHO) and Centers for Disease Control (CDC). +On +February 24, 2020, we announced that this test had obtained regulatory clearance to be sold as an in vitro diagnostic (“IVD”) +for the diagnosis of COVID-19 in markets that accept CE-marking as valid regulatory approval and became available for purchase from our +Utah-based ISO-13485:2016 certified facility. +We +commenced sales of the COVID-19 tests in February and March of 2020 to international customers and to date have since sold over 34,000,000 +of this and other COVID tests in numerous countries around the world through an expanding distributor network. +On +April 6, 2020, we announced that we had received an EUA from the FDA allowing us to commence sales of our Logix Smart COVID-19 test to +laboratories certified by the Center for Medicare and Medicaid Services under the Clinical Laboratories Improvements Act (“CLIA”) +to accept human samples for diagnostics testing throughout the United States and have sold our Logix Smart COVID-19 test to such CLIA +labs since that time. +Because +we believe that testing for COVID-19 will continue to be a consideration for public health worldwide, we have initiated the Co-Dx PCR +Home platform to facilitate frequent testing in homes, schools, businesses, and the hospitality industry. We believe this may be accomplished +through the development of a compact, relatively low-cost testing device, easy to use by non-professionals, that can provide PCR test +results in around 30 minutes. The initial project built on this platform, an at-home and point-of-care COVID-19 PCR test, was ultimately +facilitated by our development of a saliva or nasal swab-based PCR test that does not require the RNA/DNA extraction. While we believe +the final result is believed to be approximately equivalent to those processed by a high-complexity clinical laboratory, it our COVID-19 +PCR test has the advantages of increased speed and ease of handling thanks to lyophilization (or freeze-drying) of our testing reagents +to allow for stability at room temperatures. +On +February 15, 2021, we engaged the services of a group of professionals at Idaho Molecular, Inc (“IdMo”) and Advanced Conceptions, +Inc (“ACI”), with the expertise to develop the hardware for a device using our CoPrimers as the reagent chemistry. In December +2021, we announced the closing of the acquisitions of IdMo and ACI along with all existing and future assets and intellectual property +related to the platform and device. It is expected that the device and test will be available to homes, schools, offices, and the travel +industry among other locations, at a cost that will allow screening frequently to prevent spread of the COVID-19 virus in the future, +as well as other diseases as additional single- and multiplex tests are developed and validated for use on the device. The device would +also be available to test for other pathogens detectable through saliva or other samples as we develop those tests and offer them to +the marketplace. All such tests will be subject to regulatory approval. +5 +On +February 22, 2023, we announced that clinical evaluations for the device and its initial test for COVID-19 had begun. Because the evaluations +are dependent on identifying and enrolling a particular number of both symptomatic and asymptomatic COVID-19-positive and -negative patients +at testing sites, the Company did not provide projected timelines for completion at that time. +Infectious +Disease Product Offering +Using our proprietary test design system and proprietary reagents, we and +CoSara Diagnostics Pvt Ltd (“CoSara”), our joint venture for manufacturing in India, design and sell PCR diagnostic tests +for detection of diseases and pathogens such as COVID-19, influenza, tuberculosis, hepatitis B and C, malaria, dengue, human papillomavirus, +chikungunya, and Zika virus, all of which tests have been designed and verified in our laboratories. Our tuberculosis test and Zika test +received a CE Mark in 2018, and a triplex test for Zika, dengue and chikungunya received a CE Mark in 2019, qualifying the tests to be +sold throughout the European community and in most countries in Central and South America. In December 2019, CoSara received a license +to manufacture and sell tuberculosis, hepatitis B, hepatitis C, human papillomavirus 16/18 and malaria tests in India from the Central +Drugs Standard Control Organization (“CDSCO”). In February 2020, we received a CE Mark for our Logix Smart COVID-19 test followed +by an EUA by the FDA in April 2020. Also, in April 2020, our COVID-19 test was approved for manufacture and sale in India by the CDSCO +and in Mexico by the INDRE, Mexico’s equivalent to the United States Center for Disease Control. In August 2020, we received approval +from the Australian Department of Health Therapeutic Goods Division to sell our COVID-19 test in Australia. +As +explained above, our Logix Smart COVID-19 test was designed, developed, submitted for regulatory approval and ready to be used as an in +vitro diagnostic or IVD in countries that accept a CE Mark as approval for use of the test in a period of just over 30 days. +This is a real-world example of how the CODX technology can be used in an evolving epidemic or pandemic to get diagnostic tools in +the hands of medical professionals in a timely manner. It can be similarly used to design a test for mutated +strains of the virus should they not be detectable using currently available tests. +Caribbean +and Central and South America +We +began selling PCR diagnostic tests to entities located in South and Central America and the Caribbean in +2018. In some of those countries, there are limited regulatory hurdles, allowing us to begin offering our tests immediately. We have +applied for and received registrations for our tests in many of those countries that require registration, and our distributors in +those countries have provided us with in-country assistance in completing such registrations. +We +first offered our Zika test in this region because of the demand for such a test, followed by tests for tuberculosis, and our +triplex test for Zika, chikungunya, and dengue. Sales of those tests have not been material, but with the granting of a CE mark for +our Logix Smart COVID-19, we experienced an increase in sales in this region. +India +In +January 2017, the Company entered into an agreement to manufacture diagnostics tests for seven infectious diseases with a pharmaceutical +manufacturing company in India and formed CoSara as an Indian joint venture. The agreement provided for the construction of a manufacturing +plant and the manufacture of the tests named above and the joint sales and marketing of those tests in India. We have received a license +for the plant in Ranoli, India to manufacture approved tests and it is being used for testing and manufacturing of our products for the +Indian market. +As +mentioned above, the CDSCO has given us the approval for manufacture and sale of the nine tests referred to above, and the Company’s joint venture has begun manufacture and sale of those tests. The Company has +commenced a reagent rental program in India with thermocyclers purchased from third-party vendors and which we refer to as our MDx Device. +Each of the reagent rental placements requires the purchase of a minimum number of tests per month. The placement of thermocyclers in +India has facilitated the sale of the SaraGene COVID-19 tests in India. The WHO 2019 Global Tuberculosis Report indicates that India +is the country with the highest number of cases of tuberculosis in the world. WHO tuberculosis statistics for India for 2018 give an +estimated incidence figure of 2.69 million cases of tuberculosis for India out of a global incidence of approximately 10.0 million. +6 +On +March 19, 2020, we announced that CoSara received authorization to begin manufacture and sale of COVID-19 tests in India. Those tests +in India are branded as SaraGene COVID-19 tests and are sold exclusively by CoSara. The Indian government places restrictions on the +price that could be charged for COVID-19 tests which limited the revenue in India more than we experienced in other parts of the world. +At the time of this report, CoSara has received CDSCO clearance for RT-PCR tests for Mycobacterium tuberculosis, malaria, hepatitis B, +hepatitis C (including viral load tests for both hepatitis B and C), human papillomavirus (HPV), a test for high-risk HPV, two COVID-19 +assays, chikungunya, dengue, a dengue/chikungunya duplex test, an influenza A/influenza B/COVID-19 (“ABC”) multiplex test. +Europe +Molecular +diagnostics, such as our tests, are governed in Europe by the framework for IVDs, which encompasses diagnostic products such as reagents, +instruments and systems intended for use in diagnosis of disease. The regulatory system for some IVDs has historically allowed for a +self-certification procedure, placing heavy responsibility on manufacturers. Non self-certified products were subject to the same standards +as self-certified products but were also subject to audit and review by a notified body prior to receiving approval to be CE-marked. +A CE-marking is a manufacturer’s declaration that a product meets the requirements of the applicable European Commission directive. +Examples of current obligations include having in place a qualitative manufacturing process, user instructions that are clear and fit +for purpose, and ensuring that the ‘physical’ features of devices and diagnostics do not pose any danger. If a product fulfils +these and other related control requirements, it may be CE-marked, as an indication that the product is compliant with EU legislation +and sold in the European Union. We have received CE Marks for six of our tests including for COVID-19, COVID-19 (2 gene test), ABC (a +triplex test for Flu A, Flu B and COVID-19), a DS (Direct Saliva, extraction-free) COVID-19 test, tuberculosis, Zika, and our Zika, dengue, +chikungunya triplex tests. Recently, the European Commission has revised its directive governing the CE- marking of IVDs, which included +reclassifying which IVDs may be self-certified, and which may not. As a result of this change in directive and reclassification, substantially +all of the Company’s products are now subject to audit and review by a notified body, as well as a more rigorous clinical evaluation +process, prior to receiving approval to be CE-marked. +We +are ISO 13485:2016 certified, relating to the design and manufacture of our medical device products. The ISO certification indicates +that we meet the standards required to pursue CE-marking for certain of our products and affix a CE-marking for sales of our products +in countries accepting CE-marking (not in the United States). +United +States +The +FDA has granted permission for us to export all of our IVD products. The FDA’s permission to export was granted under Section 801(e) +of the Federal Food, Drug, and Cosmetic Act, as amended (the “FDC Act”). Section 801(e) of the FDA Act covers certain medical +devices that have not yet received an approved Premarket Approval in the United States by the FDA, such as our products. We have not +commenced any Premarket Approval steps with the FDA. Section 801(e) of the FDA Act applies to medical devices that are acceptable to +the importing country and that are manufactured under the FDA’s Good Manufacturing Practices. We have received EUA for our COVID-19 +test, which allows sales to qualified labs in the United States, and facilitates the registration for sale in other countries as well. +Under the FDA’s existing policy the FDA continues to review a prioritized subset of COVID-19 tests for EUAs, and emphasizes that +traditional device premarket review pathways remain open to all developers. We intend to pursue all appropriate FDA review pathways for +products under development, including traditional premarket review pathways. +Under +our EUA, we are actively selling our Logix Smart COVID-19 test to CLIA certified laboratories in the United States. The CLIA labs are +able to use our test, or to further validate our COVID-19 tests (or other tests) as Laboratory Developed Tests (LDTs), which +refers to a diagnostic test that has been validated for use in the CLIA lab. LDTs may be used by the lab only in that laboratory. CLIA +laboratories develop the performance characteristics, perform the analytical validation for their LDTs and obtain licenses to offer them +as diagnostic services. We are currently marketing our Logix Smart COVID-19 test to CLIA laboratories +throughout the US. +7 +Market +Opportunity +The +market opportunity for our tests changed radically with the emergence of the COVID-19 pandemic. Because we were able to respond rapidly +and produce a quality product, we have been able to build a distribution network that extends to +more than 80 countries with over 50 distributors, most of which have been the sales network that has allowed us to export products throughout +the world. We believe that after the pandemic is brought under control, the network of distributors that we have built in these +extraordinary times will serve us well in sales of other diagnostic tests. +The +molecular diagnostics market is a fast-growing portion of the in vitro (test tube-based, controlled environment) diagnostics market. +There are several advantages of PCR tests, such as the ones we market and sell, over other forms of diagnostic testing. These advantages +include higher specificity and sensitivity, the ability to perform multiplex tests and the ability to test for drug resistance or for +individual genes. +Mosquito +Vector Control Services +In +response to market demand, in June 2019 we introduced our first diagnostics tests to be used exclusively to test for mosquito borne pathogens +in mosquito populations. Municipalities in the US and many other countries in the world are concerned about the diseases carried by mosquitos, +which infect the human population. To prevent outbreaks of potentially harmful viruses such as Zika or West Nile from infecting the public, +many municipalities conduct mitigation operations to eliminate the mosquito populations carrying the diseases. Because it is too expensive +and potentially harmful to the environment to spray all mosquito breeding areas, municipalities identify which particular area has mosquitos +that are carrying the harmful viruses. To know where the host mosquitos with the harmful viruses are located, traps are set, mosquitos +collected and then tested to find the areas that most needed spraying. There are over 3,000 mosquito abatement districts throughout the +United States and almost all of them conduct testing to help make the spraying more effective. +Our +first vector related test was a triplex test that tests for West Nile, western equine and St. Louis encephalitis. We began shipping the +tests in June 2019. We added a second test that tests mosquitos for Zika, chikungunya and dengue in a triplex test. Finally, in November +2019, we completed a test for West Nile, eastern equine and St. Louis encephalitis, specifically for use in the eastern United States. +As a result, mosquito abatement districts can test for three target viruses in one test as compared to performing three different tests +using other market available tests. Our products allow municipalities to obtain test results in a matter of hours, instead of the weeks +they might otherwise have to wait for a central lab to process the mosquito tests. +We +have sold our Vector Smart™ test products and/or related lab equipment to testing districts in different sections of the country +and are marketing our products through trade shows, electronic and regular mail solicitations. +Liquid +Biopsy for Cancer Screening +The +enhanced specificity of our technology opens up some unique applications for liquid biopsy, demonstrating its ability to detect small +quantities of mutations associated with cancer within an environment of large amounts of normal DNA, as we position the Company to take +part in this historic and challenging development in human health care. +Agricultural +Applications +SNP +detection is also used in the agricultural industry to identify variations in crop genomes to achieve improved seed viability and other +desired characteristics, including drought resistance, disease resistance, pest resistance and higher yield. +In +mid-2017, the Company was first approached by a large agribusiness to evaluate our ability to multiplex certain target genomes. The results +of the development project have successfully demonstrated our ability to not only multiplex the target genomes, but targeted SNP’s +as well. The project was undertaken in conjunction with the manufacturer of our CoPrimers tests. The results of the project encouraged +the parent of our manufacturer to seek a world-wide licensing arrangement for our CoPrimers in the agricultural industry, which was completed +in October 2018. Pursuant to the exclusive license for the agronomics industry, the licensee pays us a royalty for all CoPrimers sold +to the licensee’s customers. In January 2019, the licensee formally introduced the product at a large agricultural conference and +has branded the product under the name “BHQ CoPrimers”. +8 +Additional +Licensing and Assay Development +We +believe the unique properties of our CoPrimers technology make them ideally suited to a variety of applications where sensitivity is +key to optimal results, including multiplexing several targets, enhanced SNP detection and enrichment for next generation sequencing. +Our licensee for our agricultural testing requested an expansion of our license agreement to include test design services for their customers +and potential customers, both in the infectious disease arena as well as for agricultural customers. The license was amended in July +2019 and we expect to derive a license fee from our licensee for its design services. If any of its customers desire to commercialize +the tests designed, they will need to seek a commercial license directly from us. Because of these unique characteristics of CoPrimers, +research companies and institutions have requested that we design diagnostics to locate and identify uncommon gene sequences and SNPs +and create tests for the target sequences in a multiplexed reaction. This application of our technology is in its beginning stages, but +we believe that the results from our initial research indicate a significant step forward in defining the capabilities of our technology, +which we believe can be translated to revenue producing licensing arrangements. However, there can be no guarantee that we will be able +to develop the requested capabilities, or that we will be able to successfully commercialize this application of our technology. +Competitive Advantages of Co-Diagnostics +We believe that we have the following competitive advantages: +● +Affordability: +Lower-cost test kits, a low-cost MDx-device, and an affordable Co-Dx PCR Home platform for at-home and point-of-care testing +(the platform is subject to FDA review and not available for sale at the time of this filing). +● +Flexibility: +CODX’s tests have been designed to run on many customers’ DNA/RNA diagnostic testing machines. Our technology +is well suited to the new generation of point-of-care testing (“POCT”), compact and portable analysis machinery for field, +clinical and office applications. +● +Speed : +We believe our rapid assay design system software provides shorter time to product release. This has been demonstrated with the +conception, design, product manufacture, clinical verification and submission for a CE Mark for our Logix Smart COVID-19 test being +approximately 30 days. +● +Accuracy : +We believe our technology allows us to build tests that are highly sensitive and specific, the two benchmarks for accuracy in PCR +testing. +● +Personalized +Medicine : We project that rising health care costs in developed and developing nations will increasingly require that health +care systems be patient-specific to eliminate waste, misdiagnoses, and ineffectiveness. A critical component will be accurate, more +affordable DNA-based diagnostics, especially in at-home and POCT settings, for which we are developing products. +● +Low-cost +Provider : Our platform technology obviates the need to pay patent royalties typically required of our competitors, which +use patented test platforms to design their tests. +● +Worldwide +Footprint : With a dynamic technology that encompasses markets worldwide, we anticipate that we can identify the best target +markets, not only in high burden developing countries but also in developed nations. +● +Growth +Industry Category : We believe that real-time PCR testing is the fastest-growing segment of in vitro diagnostic testing. +● +Combination +Product Offering : Our sensitive tests can be a well-designed match for a new generation of compact and other small POCT devices +now entering the market, including our own MDx and Co-Dx PCR Home devices. Used together, we believe these affordable tests and devices +have the potential to revolutionize the molecular diagnostics industry in cost, speed of test results and simplification. +● +Multiplexing: +Our existing multiplexed tests demonstrate that our CoPrimer-designed tests are able to test for multiple targets in the +same sample without the distortion caused by false negatives and false positives that often occur in multiplexed tests. +9 +Intellectual +Property +Much +of our future success and value depends on our proprietary technology, and therefore, our patent and intellectual property strategy is +of critical importance. Currently, our flagship CoPrimers technology is covered by two U.S. patents titled “Cooperative primers, +probes, and applications thereof” as well as by granted and pending foreign counterparts. We have another three U.S. patents directed +to our earlier work in primer and assay designs. For more recent works, we have filed international and U.S. patent applications directed +to “Methods and Compositions for Next Generation Sequencing (NGS) Library Preparation,” “Allele-Specific Design of +Cooperative Primers for Improved Nucleic Acid Variant Genotyping,” “Methods and Compositions Related to Cooperative Primers +and Reverse Transcription,” and “Systems, Methods, and Apparatus for Automated Self-Contained Biological Analysis” +which is the basis of our at-home and point-of-care PCR system. We intend to continue building our patent portfolio as development continues +and resources are available. +We +also protect some of our technology and know-how as trade secrets and, where appropriate, we use and register trademarks to protect and +strengthen our products and proprietary brands. All trademarks, trade/product names, graphics and logos of Co-Diagnostics contained herein +are trademarks of Co-Diagnostics or its subsidiary, as applicable, in the U.S. and/or other countries. Solely for convenience, we may +refer to trademarks in this Annual Report on Form 10-K without the ™ or ® symbols, but such references are not intended to +indicate, in any way, that we will not assert, to the fullest extent permitted by law, our rights to our trademarks. +Major +Customers +We +had certain customers which were each responsible for generating 10% or more of our total revenue for the years ended December 31, 2022 +and 2021, respectively. One customer accounted for approximately 37% of total revenue for the year ended December 31, 2022 and two customers +together accounted for approximately 48% of total revenue for the year ended December 31, 2021. These customers may not account for the +same percentage of sales in future periods. If we were +to sell nothing to those customers in the future, it would have a material adverse effect on our financial condition unless we were able +to replace those customers with others. +Competition +The +molecular diagnostics industry is extremely competitive. There are many firms that provide some or all of the products we provide and +provide many diagnostic tests that we have yet to develop. Many of these competitors are larger than us and have significantly greater +financial resources. Because we are more recently established, many of our competitors have a competitive advantage in the diagnostic +testing industry because they also have other lines of business in the pharmaceutical industry from which they derive revenues and for +which they are well known and respected in the medical profession. We will need to overcome the disadvantage of being perceived as a +start up with no significant recognition from the medical and testing professionals, although we believe this is changing as we continue +to market our Logix Smart COVID-19 tests and other tests in the United States to well-known and successful laboratories. Many of these +competitors already have an established customer base with industry standard technology, which we must overcome to be successful. In +the diagnostic testing and POCT industries, we compete with such companies as BioMerieux, Siemens, Qiagen, Cue Health, Lumira Dx and +Cepheid and with such pharmaceutical companies as Abbott Laboratories, Becton Dickinson and Johnson and Johnson. +10 +Competition +has been particularly intense in the market for COVID-19 diagnostic tests. Numerous companies in the United States and internationally +have announced their intention to offer new products, services and technologies that could be used in substitution for our Logix Smart +COVID-19 tests. Many of those competitors are significantly larger, and have substantially greater financial, engineering and other resources, +than our company. Existing and potential competitors in the market for COVID-19 diagnostic tests include developers of serological, antigen +and molecular tests. We also compete with companies from Asia in certain markets who are willing to sell their tests for much less than +we sell our tests, which creates competitive price pressure on us in certain regions, particularly Asia and Latin America. +We +expect competition to continue to increase as other established and emerging companies enter the market, as customer requirements evolve, +and as new products, services and technologies are introduced. The entrance of new competitors is being encouraged by governmental authorities, +who are offering funding to support development of testing solutions for COVID-19. Some of our existing or new competitors may have strong +relationships with current and potential customers, including governmental authorities, and, as a result, may be able to respond more +quickly to new or changing regulatory requirements, new or emerging technologies, and changes in customer requirements. +Government +Regulation +In +the United States, we are regulated by the FDA and our products must be approved, cleared, or authorized by the FDA before we are allowed +to sell our tests in the United States as in vitro diagnostics. The FDA granted us an EUA to manufacture and sell our Logix Smart +COVID-19 test to CLIA labs in the United States. We are ISO 13485:2016 certified, relating to the design and manufacture of our medical +device products. Being ISO certified greatly facilitates our applications for CE-Marking, which allows us to sell any CE Marked test +in most countries in Europe, South America and Asia, depending on the country and following that country’s registration process. +We currently have CE Markings issued for our Logix Smart COVID-19 test, tuberculosis test, our Zika virus test, a triplex test that tests +for Zika, dengue, and chikungunya simultaneously, a triplex “ABC” test that identifies and distinguishes between Flu A, Flu +B and Covid-19, our SARS-CoV-2 2-gene multiplex test, and our DS (Direct Saliva, extraction-free) COVID-19 test. In addition, our Logix +Smart COVID-19 has received the required license to manufacture and sell in India from India’s CDSCO, and The National Epidemiology +Institute in Mexico evaluated our Logix Smart COVID-19 and ABC tests and approved them for sale in Mexico. We have also received approval +to sell in Australia. We are in the process of registering for sale our Logix Smart COVID-19 and other tests in a number of major countries +around the world. +Employees +As +of December 31, 2022, we had 145 full-time and part-time employees at our executive offices and lab facilities in Salt Lake City, Utah. +We have engaged independent contractors in India to promote the use of our products and develop outlets for products and employ the services +of independent sales representatives on an “as needed” basis. +We consider our people and the way we work to support each other and serve +our customers to be critical to our success. The key human capital measures and objectives that we focus on in managing our business are: +maintaining a strong and collaborative company culture, increasing our diversity, inclusion and belonging, offering fair and competitive +compensation and benefits, investing in people and organizational development, protecting and enriching employee health and wellness, +and sustaining a culture of respectful and effective communications. +Organizational +History and Corporate Information +We +were incorporated as Co-Diagnostics, Inc., in Utah on April 18, 2013. Our principal executive office is located at 2401 S. Foothill Drive, +Salt Lake City, Utah 84109. Our telephone number is (801) 438-1036. Our web address is www.codiagnostics.com . The contents of +our website are not incorporated by reference in this Annual Report. +11 +ITEM +1A. RISK FACTORS +Risks +Related to Our Business and Industry +We +have limited commercial history upon which to base our prospects and are not certain that we will achieve profitability in the future. +We +have a limited operating history. We began operations in April 2013. Our accumulated retained earnings were $39.9 million and $54.2 million +as of December 31, 2022 and 2021, respectively. We were able to achieve net income during the calendar year ending December 31, 2021 +due to the high demand for our Logix Smart COVID-19 and other COVID-19 tests during the COVID pandemic. During the calendar year ending +December 31, 2022 we experienced a decline in demand for our Logix Smart COVID-19 and other COVID-19 tests and operated at a net loss +during the period. We do not have any way of predicting when or if we will achieve profitability again. Potential investors should be +aware of the difficulties normally encountered by a new enterprise, many of which are beyond our control, including substantial risks +and expenses in the course of developing new diagnostic tests, establishing or entering new markets, organizing operations and marketing +procedures. The likelihood of our success must be considered in light of these risks, expenses, complications and delays, and the competitive +environment in which we operate. There is, therefore, nothing at this time upon which to base an assumption that our business plan will +prove successful, and we may not be able to generate significant revenue, raise additional capital or operate profitably. We will continue +to encounter risks and difficulties frequently experienced by early commercial stage companies, including scaling up our infrastructure +and headcount, and may encounter unforeseen expenses, difficulties or delays in connection with our growth. In addition, as a result +of the start-up nature of our business, we expect to continue to sustain substantial operating expenses and may not be able to continue +generating sufficient revenues to cover expenditures. Any investment in our company is therefore highly speculative and could result +in the loss of any investment. +Our +future success is dependent on demand for COVID-19 and other infectious disease diagnostics and upon our ability to develop and market +other commercially accepted diagnostic tests and our “at-home” and POCT platforms. +Our +future success will depend, in part, on the continued market for COVID-19 tests, our ability to develop and sell sufficient quantities +of other diagnostics tests, and our ability to successfully obtain regulatory approval for and profitably market our Co-Dx PCR Home at-home +and POCT platform. Attracting new customers and distribution networks requires substantial time and expense. Any failure to obtain regulatory +approval for our product candidates and to increase sales of our diagnostic tests in sufficient quantities to achieve profitability in +a timely manner would adversely affect our operating results. Many factors could affect the market acceptance and commercial success +of any of our diagnostic tests and devices, including: +● +Our ability to develop +additional infectious disease diagnostic tests for which there is a commercial market; +● +Our ability to obtain regulatory +clearance to commercialize our product candidates; +● +our ability to convince +our potential customers of the advantages and economic value of our tests over competing technologies and diagnostic tests; +● +the breadth of our test +menu relative to competitors; +● +changes to policies, procedures +or currently accepted best practices in clinical diagnostic testing; +● +the extent and success +of our marketing and sales efforts; and +● +our ability to manufacture +in quantity our commercial diagnostic tests and meet demand in a timely fashion. +We +may not realize anticipated revenue from our Logix Smart COVID-19 and other COVID-19 tests. +Currently, +our business is substantially dependent on sales of our Logix Smart COVID-19 and other COVID-19 tests. Other companies are working to +produce or have produced rapid tests for COVID-19 which may lead to the diversion of customers, including governmental and quasi-governmental +entities, away from us and toward other companies. Moreover, the dangers posed by COVID-19 may subside over time. A number of preventative +vaccines have been approved for use in human populations by regulatory agencies in the U.S. and around the world. The uptake of these +vaccines will likely limit the spread of COVID-19 and potentially reduce the market size for COVID-19 testing. +We +expect that, if and when the current COVID-19 pandemic subsides, there could be significantly reduced demand for testing, and thus, for +our Logix Smart COVID-19 and other COVID-19 tests. We have seen a reduction in the prevalence of COVID-19 since the height of the pandemic, +and in 2022 experienced a significant decrease in revenue from our COVID-19 testing products. Revenues relating to our COVID-19 testing +products could decline in the future if the prevalence of COVID-19 remains low and as attention from governments and individuals to COVID-19 +wanes. +Further, +if the COVID-19 pandemic becomes a seasonal virus or experiences fluctuations in prevalence, we could experience fluctuations in +our revenues associated with our COVID-19 tests. While there is still demand for COVID-19 testing products, there is no guarantee that +current or anticipated demand will continue, or if demand does continue, that we will be able to produce our COVID-19 tests in sufficient +quantities to meet demand. A significant decline in demand for our COVID-19 testing products without a corresponding increase in our +other businesses could have a material, adverse effect on our results of operations, cash flow and financial position. +The +diagnostic market is highly competitive, and we may not be able to compete effectively against the larger, well-established companies +that dominate this market or emerging and small innovative companies that may seek to obtain or increase their share of the market. +The +markets for diagnostic products are intensely competitive, and many of our competitors are much larger and have substantially more financial +and human resources than we do. Many have long histories and strong reputations within the industry, and a relatively small number of +companies dominate these markets. +These +companies enjoy significant competitive advantages over us, including: +● +broad product +offerings, which address the needs of health care providers in a wide range of applications; +● +products that are supported +by long-term clinical data; +● +greater experience in, +and resources for, launching, marketing, distributing and selling products, including strong sales forces and established distribution +networks; +● +extensive intellectual +property portfolios and greater resources for patent protection; +● +greater financial and other +resources for product research and development; +● +greater experience in obtaining +and maintaining FDA and other regulatory clearances and approvals for products and product enhancements; +12 +● +established manufacturing +operations and contract manufacturing relationships; +● +significantly greater name +recognition and widely recognized trademarks; and +● +established relationships +with healthcare providers and payers. +Our +products and any product candidates that we may introduce into the market may not enable us to overcome the competitive advantages of +these large and dominant companies. In addition, even if we successfully introduce additional product candidates into the market, emerging +and small innovative companies may seek to increase their market share and they may eventually possess competitive advantages, which +could adversely impact our business. Our competitors may also employ pricing strategies that could adversely affect the pricing of our +products. +We +depend on a limited number of third-party suppliers for key raw materials used in the manufacturing of our products, and the loss of +these third-party suppliers or their inability to supply us with adequate raw materials could harm our business. +We +rely on a limited number of third-party suppliers for the raw materials required for the production of our diagnostic products and product +candidates. Our dependence on a limited number of third-party suppliers involves several risks, including limited control over pricing, +availability, quality, and delivery schedules for raw materials. We have no supply agreements in place with any of our suppliers and +cannot be certain that our current suppliers will continue to provide us with the quantities of raw materials that we require or that +satisfy our anticipated specifications and quality requirements. Any supply interruption in limited or single sourced raw materials could +materially harm our ability to manufacture our products until a new source of supply, if any, could be identified and qualified. We may +be unable to find a sufficient alternative supply channel within a reasonable time or on commercially reasonable terms. Any performance +failure on the part of our suppliers could delay the production of our products and product candidates and delay the development and +commercialization of our product candidates, including limiting supplies necessary for commercial sale, clinical trials and regulatory +approvals, which could have a material adverse effect on our business. +In +order to be successful, we must expand our available product lines by commercializing new product candidates, but we may not be able +to do so in a timely fashion and at expected costs, or at all. +Although +we are currently manufacturing diagnostic kits for commercialization, in order to be successful, we will need to expand our product lines +to include other diagnostic products. To succeed in our commercialization efforts, we must effectively continue product development and +testing, find new strategic partners, obtain regulatory clearances and approvals, and enhance our sales and marketing capabilities. Because +of these uncertainties, there is no assurance that we will succeed in bringing any of our current or future product candidates to market. +If we fail in bringing our product candidates to market, or experience delays in doing so, we will not generate revenues as planned and +will need to curtail operations or seek additional financing earlier than otherwise anticipated. +We +are dependent on our senior management team, scientific team, and external advisors, and the loss of any of them could harm our business, +including by adversely affecting our ability to effectuate our business strategy. +The +members of our current senior management team may not be able to successfully implement our strategy. In addition, we have not entered +into employment agreements with any of the members of our senior management team. There are no assurances that the services of any of +these individuals will be available to us for any specified period of time. The successful integration of our senior management team, +the loss of members of our senior management team, scientific team and key external advisors, or our inability to attract or retain other +qualified personnel or advisors could have a material adverse effect on our business, financial condition and results of operations. +We may not have a sufficient number of qualified personnel to effectuate our business strategy, which could have a material adverse effect +on our business, financial condition and results of operations. +13 +If +we experience significant disruptions in our information technology systems, our business, results of operations and financial condition +could be adversely affected. +The +efficient operation of our business depends on our information technology systems. We rely on our information technology systems to effectively +manage our sales and marketing, accounting and financial functions; manufacturing processes; inventory; scientific and product development +functions; and our research and development functions. As such, our information technology systems are vulnerable to damage or interruption +including from earthquakes, fires, floods and other natural disasters; terrorist attacks and attacks by computer viruses or hackers; +power losses; and computer systems, or Internet, telecommunications or data network failures. The failure of our information technology +systems to perform as we anticipate or our failure to effectively implement new systems could disrupt our entire operation and could +result in decreased sales, increased overhead costs, excess inventory and product shortages, all of which could have a material adverse +effect on our reputation, business, results of operations and financial condition. +Cyber +security risks and the failure to maintain the integrity of company, employee or guest data could expose us to data loss, litigation +and liability, and our reputation could be significantly harmed. +We +and third-party service providers collect and retain large volumes of data, including personally identifiable information regarding clinical trial participants +and others, for business purposes, including for regulatory, research and development and commercialization purposes, and our collaborators’ +various information technology systems enter, process, summarize and report such data. We also maintain personally identifiable information +about our employees. The integrity and protection of our company, employee and clinical data is critical to our business. We are subject +to significant data security and privacy laws and regulations. These regulations impose significant requirements on how we maintain, +use, and protect such information. Maintaining compliance with these evolving regulations and requirements could be difficult and may +increase our expenses. In addition, a penetrated or compromised data system or the intentional, inadvertent or negligent release or disclosure +of data could result in theft, loss or fraudulent or unlawful use of company, employee or clinical data which could harm our reputation, +disrupt our operations, or result in remedial and other costs, fines or lawsuits. +Risks +Related to Regulatory Approval of Our Products and Other Government Regulations +We +received Emergency Use Authorization or EUA and intend to seek additional and/or amended EUAs for our COVID-19 test. The FDA may not +timely grant any additional or amended EUAs, if at all. For our existing EUA and any new EUA, the FDA may revoke any EUA where it is +determined that the underlying health emergency no longer exists or warrants such authorization, which would adversely impact our ability +to market our COVID-19 test in the United States. +The +FDA has the authority to grant an EUA to allow unapproved medical products to be used in an emergency to diagnose, treat or prevent serious +or life-threatening diseases or conditions when there are no adequate, approved and available alternatives. On January 31, 2020, the +Secretary of the U.S. Department of Health and Human Services, or U.S. HHS, issued a declaration of a public health emergency related +to COVID-19. On February 4, 2020, U.S. HHS determined that COVID-19 represents a public health emergency that has a significant potential +to affect national security or the health and security of U.S. citizens living abroad and, subsequently, declared on March 24, 2020, +that circumstances exist to justify the authorization of emergency use of medical devices, including alternative products used as medical +devices, during the COVID-19 pandemic, subject to the terms of any authorization as issued by the FDA. On February 29, 2020, the FDA +issued an immediately in effect guidance with policy specific to development of in vitro diagnostic tests during the COVID-19 +public health emergency. This guidance was updated on March 16, 2020, May 4, 2020 and May 11, 2020. It is uncertain whether the widespread +availability of approved and effective vaccinations could expedite or influence any such decision making with respect to the underlying +health emergency. +On +April 3, 2020, we received an EUA from the FDA for our Logix Smart Coronavirus Disease 2019 (COVID-19) kit for use on individuals who +are suspected of COVID-19 by their healthcare provider. We cannot predict how long the EUA for +our COVID-19 test will remain in place. +There +can be no assurances that the FDA will authorize any request for additional and/or amended EUAs and if we do not receive the authorization, +our business, financial condition, results of operations and future growth prospects could be materially and adversely affected. +14 +The +FDA may revoke an EUA where it is determined that the underlying health emergency no longer exists or warrants such authorization. The +FDA may take such a position at any time and without notice and, therefore, we cannot predict how long our EUAs will remain in place. +The FDA may also revoke an EUA when the circumstances justifying its issuance no longer exist, such as when an alternative is authorized +for marketing through the standard procedures, including through a 510(k) clearance. +FDA +policies regarding diagnostic tests, therapies and other products used to diagnose, treat or mitigate COVID-19 remain in flux as the +FDA responds to new and evolving public health information and clinical evidence. Changes to FDA regulations or requirements could require +changes to our authorized test, necessitate additional measures, or make it impractical or impossible for us to market our test. The +revocation of an EUA, if granted, could necessitate that we pursue the lengthy and expensive 510(k) clearance process, if available, +or another similarly burdensome marketing authorization process, such as a de novo classification. Indeed, FDA has recommended that manufacturers +of tests subject to an EUA pursue pre-market submissions such as a 510(k), de novo classification, or pre-market approval, or PMA, as +applicable, during the declared public health emergency so that their devices can remain on the market after the emergency terminates. +If +either of our existing EUAs is revoked prior to us having received regulatory approval to commercialize our COVID-19 test through a traditional +pathway, we may not be able to obtain required clearances or approvals in a timely manner, or at all, and one or more of our competitors +may obtain the necessary clearances or approvals for their products before we do. In addition, we would be required to cease our commercialization +efforts, which would substantially and negatively impact our business. As a result, any such revocation could adversely impact our business, +financial condition and results of operations. +Our +long-term success depends substantially on our ability to obtain regulatory clearance or approval and thereafter commercialize our product +candidates; we cannot be certain that we will be able to do so in a timely manner or at all. +The +process of obtaining regulatory clearances or approvals to market a medical diagnostic from the FDA or similar regulatory authorities +outside of the United States can be costly and time consuming, and there can be no assurance that such clearances or approvals will be +granted on a timely basis, or at all. The FDA’s 510(k) clearance process generally takes one to six months from the date of submission, +depending on whether a special or traditional 510(k) premarket notification has been submitted, but can take significantly longer. An +application for premarket approval, or PMA, must be submitted to the FDA if the device cannot be cleared through the 510(k) clearance +process or is not exempt from premarket review by the FDA. The PMA process almost always requires one or more clinical trials and can +take two to three years from the date of filing, or even longer. +If +we are required to obtain approval of any of our products through the PMA process, the costs associated with such a process will be significant, +which could adversely affect our financial performance and results of operations. In addition, a submission through the PMA process would +require us to delay commercialization of such product candidates until after approval is received, if ever. If we are unable to commercialize +our product candidates in a timely manner, or at all, our business will be adversely affected. +Similar +to our compliance with U.S. regulatory requirements, we must obtain and comply with international requirements, in order to market and +sell our products outside of the United States and we may only promote and market our products, if approved, as permitted by applicable +regulatory authorities. There is no guarantee that we will receive the necessary regulatory approvals for our product candidates either +inside the United States or internationally. If our product candidates do not receive necessary regulatory approvals, our business could +be materially and adversely affected. +15 +Our +current and future relationships with third-party payers and current and potential customers in the United States and elsewhere may be +subject, directly or indirectly, to applicable anti-kickback, fraud and abuse, false claims, transparency, health information privacy +and security and other healthcare laws and regulations, which could expose us to criminal sanctions, civil penalties, contractual damages, +reputational harm administrative burdens and diminished profits and future earnings. +Our +current and future arrangements with third-party payers and current and potential customers, including providers and physicians, may +expose us to broadly applicable fraud and abuse and other healthcare laws and regulations, including, without limitation, the federal +Anti-Kickback Statute and the federal False Claims Act, which may constrain the business or financial arrangements and relationships +through which we sell, market and distribute our products. In addition, we may be subject to transparency laws and patient privacy regulations +by U.S. federal and state governments and by governments in foreign jurisdictions in which we conduct our business. The applicable federal, +state and foreign healthcare laws and regulations that may affect our ability to operate include: +● +the federal Anti-Kickback +Statute, which prohibits, among other things, persons from knowingly and willfully soliciting, offering, receiving or providing remuneration, +directly or indirectly, in cash or in kind, to induce or reward, or in return for, either the referral of an individual for, or the +purchase, order or recommendation of, any good or service, for which payment may be made under federal healthcare programs, such +as Medicare and Medicaid; +● +federal civil and criminal +false claims laws and civil monetary penalty laws, including the federal False Claims Act, which impose criminal and civil penalties, +including civil whistleblower or qui tam actions, against individuals or entities for knowingly presenting, or causing to be presented, +to the federal government, including the Medicare and Medicaid programs, claims for payment that are false or fraudulent or making +a false statement to avoid, decrease or conceal an obligation to pay money to the federal government; +● +the federal Health Insurance +Portability and Accountability Act of 1996, or HIPAA, which imposes criminal and civil liability for executing a scheme to defraud +any healthcare benefit program or making false statements relating to healthcare matters; +● +HIPAA, as amended by the +Health Information Technology for Economic and Clinical Health Act of 2009, or HITECH, and their respective implementing regulations, +which impose obligations on covered healthcare providers, health plans, and healthcare clearinghouses, as well as their business +associates that create, receive, maintain or transmit individually identifiable health information for or on behalf of a covered +entity, with respect to safeguarding the privacy, security and transmission of individually identifiable health information; +● +the Physician Payments +Sunshine Act, which requires (i) manufacturers of drugs, devices, biologics and medical supplies for which payment is available under +Medicare, Medicaid or the Children’s Health Insurance Program, with specific exceptions, to report annually to CMS information +related to certain “payments or other transfers of value” made to physicians, which is defined to include doctors, dentists, +optometrists, podiatrists and chiropractors, and teaching hospitals, (ii) applicable manufacturers and applicable group purchasing +organizations to report annually to CMS ownership and investment interests held in such entities by physicians and their immediate +family members, with data collection beginning on August 1, 2013, (iii) manufacturers to submit reports to CMS by the 90th day of +each calendar year, and (iv) disclosure of such information by CMS on a publicly available website; and +● +analogous state and foreign +laws and regulations, such as state anti-kickback and false claims laws, which may apply to sales or marketing arrangements and claims +involving healthcare items or services reimbursed by non-governmental third-party payers, including private insurers; state and foreign +laws that require medical device companies to comply with the medical device industry’s voluntary compliance guidelines and +the relevant compliance guidance promulgated by the federal government or otherwise restrict payments that may be made to healthcare +providers; state and foreign laws that require medical device manufacturers to report information related to payments and other transfers +of value to physicians and other healthcare providers or marketing expenditures; and state and foreign laws governing the privacy +and security of health information in certain circumstances, many of which differ from each other in significant ways and often are +not preempted by HIPAA, thus complicating compliance efforts. +16 +Efforts +to ensure that our business arrangements with third parties will comply with applicable healthcare laws and regulations may involve substantial +costs. It is possible that governmental authorities will conclude that our business practices may not comply with current or future statutes, +regulations or case law involving applicable fraud and abuse or other healthcare laws and regulations. If our operations are found to +be in violation of any of these laws or any other governmental regulations that may apply to us, we may be subject to significant civil, +criminal and administrative penalties, including, without limitation, damages, fines, imprisonment, exclusion from participation in government +healthcare programs, such as Medicare and Medicaid, and the curtailment or restructuring of our operations, which could have a material +adverse effect on our business. If any of the physicians or other healthcare providers or entities with whom we expect to do business, +including our collaborators, are found not to be in compliance with applicable laws, they may be subject to criminal, civil or administrative +sanctions, including exclusions from participation in government healthcare programs, which could also materially affect our business. +We +are subject to stringent and changing data protection laws, privacy policies and data protection obligations, which continue to evolve and change over time. The actual or perceived +failure by us or our third-party service providers or vendors to comply with such obligations could harm our reputation, subject us to +significant fines and liability, or otherwise adversely affect our business. +We +are subject to numerous data protection laws that govern the processing of individually identifiable information and health information +and other sensitive and personal information in the jurisdictions in which we operate. In many instances, these data protection laws, +regulations and standards apply not only to disclosures to third parties, but also to transfers of information between or among us and +other parties with which we have commercial relationships. The regulatory framework for data privacy, data security and data transfers +worldwide is rapidly evolving and, as a result, interpretation and implementation standards and enforcement practices are likely to remain +uncertain for the foreseeable future. These data protection laws may be interpreted and applied differently over time and from jurisdiction +to jurisdiction, and it is possible that they will be interpreted and applied in ways that will materially and adversely affect our business, +financial condition and results of operations. Failure to comply with any of these data protection laws could result in enforcement actions +against us, including fines, imprisonment of company officials and public censure, claims for damages by affected individuals, damage +to our reputation and loss of goodwill, any of which could have a material adverse effect on our business. +There +are numerous U.S. federal and state laws and regulations related to the privacy and security of personal information. These laws and +regulations include the Health Insurance Portability and Accountability Act of 1996, or HIPAA, as amended by the Health Information Technology +for Economic and Clinical Health Act of 2009, or HITECH, and their implementing regulations, or collectively referred to as the HIPAA +Rules, which establish a set of national privacy and security standards to safeguard Protected Health Information, or PHI, by health +plans, healthcare clearinghouses and certain healthcare providers, referred to as covered entities, and the business associates and their +subcontractors with whom such covered entities contract for services that involve the creation, receipt, maintenance or transmission +of PHI for or on behalf of a covered entity or another business associate. HIPAA requires covered entities and business associates to, +among other things, develop and maintain policies and procedures with respect to PHI that is used or disclosed, including the adoption +of administrative, physical and technical safeguards to protect such information and ensure the confidentiality, integrity and availability +of electronic PHI. As this applies to our business, we are required to maintain security standards for any PHI that we create, receive, +maintain or transmit. For example, we plan to offer cloud-based portal software to help our customers more efficiently use our products. +The software will maintain security safeguards that are designed to be consistent with the HIPAA Rules, but we cannot guarantee that +these safeguards will not fail or that they will not be deemed inadequate in the future. In addition, we could be subject to periodic +audits for compliance with the HIPAA Privacy and Security Standards by the U.S. HHS, and our customers. The U.S. HHS Office for Civil +Rights may impose significant penalties on entities subject to HIPAA for a failure to comply with a requirement of the HIPAA Rules. If +we are unable to properly protect the privacy and security of the PHI of our customers, we could be found to have breached our contracts. +Determining whether PHI has been handled in compliance with applicable privacy standards and our contractual obligations can be complex +and we cannot be sure how these regulations will be interpreted, enforced or applied to our operations. +In +addition, many states in which we operate have laws that protect the privacy and security of sensitive and personal information, including +health-related information. Certain state laws may be more stringent or broader in scope, or offer greater individual rights, with respect +to sensitive and personal information than federal, international or other state laws, and such laws may differ from each other, which +may complicate compliance efforts. +17 +Laws, +regulations and standards in many other jurisdictions also apply broadly to the Processing of personal information, which impose significant +compliance obligations. Complying with these numerous, complex and often changing regulations is expensive and difficult, and failure +to comply with any Data Protection Laws or any security incident or breach involving the misappropriation, loss or other unauthorized +use or disclosure of sensitive or confidential information, whether by us, one of our service providers or another third party, could +negatively affect our business, financial condition and results of operations, including but not limited to: investigation costs, material +fines and penalties; compensatory, special, punitive and statutory damages; litigation; consent orders regarding our privacy and security +practices; requirements that we provide notices, credit monitoring services or credit restoration services or other relevant services +to impacted individuals; adverse actions against our licenses to do business; and injunctive relief. +Many +statutory requirements, both in the United States and abroad, include obligations for companies to notify individuals of security breaches +involving certain personal information, which could result from breaches experienced by us or our third-party service providers. For +example, laws in all 50 U.S. states and the District of Columbia require businesses to provide notice to consumers whose unencrypted +personal information has been disclosed as a result of a data breach. These laws are not consistent, and compliance in the event of a +widespread data breach is difficult and may be costly. Moreover, states have been frequently amending existing laws, requiring attention +to changing regulatory requirements. We also may be contractually required to notify affected customers, regulators, credit reporting +agencies or other affected individuals of a security breach. Such notifications are costly, and the disclosures or the failure to comply +with such requirements, could lead to material adverse effects, including without limitation, negative publicity, a loss of customer +confidence in our services or security measures or breach of contract claims. There can be no assurance that the limitations of liability +in our contracts would be enforceable or adequate or would otherwise protect us from liabilities or damages if we fail to comply with +applicable Data Protection Laws, Data Protection Obligations or other legal obligations. In addition, although we may have contractual +protections with our third-party service providers, contractors and consultants, any actual or perceived security breach by our subcontractors +could harm our reputation and brand, expose us to potential liability or require us to expend significant resources on data security +and in responding to any such actual or perceived breach. Any contractual protections we may have from our third-party service providers, +contractors or consultants may not be sufficient to adequately protect us from any such liabilities and losses, and we may be unable +to enforce any such contractual protections. +We +expect that there will continue to be new proposed laws and regulations concerning data privacy and security, and we cannot yet determine +the impact such future laws, regulations and standards may have on our business. New laws, amendments to or re-interpretations of existing +laws, regulations, standards and other obligations may require us to incur additional costs and restrict our business operations. Because +the interpretation and application of health-related and Data Protection Laws and other obligations are still uncertain, and often contradictory +and in flux, it is possible that the scope and requirements of these laws may be interpreted and applied in a manner that is inconsistent +with our practices and our efforts to comply with the evolving data protection rules may be unsuccessful. If so, this could result in +government-imposed fines or orders requiring that we change our practices, which could adversely affect our business. +We +cannot assure you that our third-party partners and service providers with access to our or our customers’, suppliers’ and +employees’ personally identifiable and other sensitive or confidential information in relation to which we are responsible will +not breach contractual obligations imposed by us or violate Data Protection Laws, or that they will not experience security breaches +or attempts thereof, which could have a corresponding effect on our business, including putting us in breach of our obligations under +the Data Protection Laws, which could in turn adversely affect our business, results of operations and financial condition. We cannot +assure you that our contractual measures and our own privacy- and security-related safeguards will protect us from the risks associated +with the third-party processing, storage and transmission of such information. +We +may receive inquiries or be subject to investigations, proceedings or actions, by various government entities regarding our privacy and +information security practices and Processing (“Regulatory Proceedings”). These Regulatory Proceedings could result in a +material adverse effect, including without limitation, interruptions of, or required changes to, our business practices, the diversion +resources and the attention of management from our business, regulatory oversights and audits, discontinuance of necessary Processing, +or other remedies that adversely affect our business. +18 +In +addition to the possibility of fines, lawsuits, regulatory investigations, public censure, other claims and penalties, and significant +costs for remediation and damage to our reputation, we could be materially and adversely affected if legislation or regulations are expanded +to require changes in our data processing practices and policies or if governing jurisdictions interpret or implement their legislation +or regulations in ways that negatively impact our business. Complying with these various laws could cause us to incur substantial costs +or require us to change our business practices and compliance procedures in a manner adverse to our business. Any inability to adequately +address data privacy or security-related concerns, even if unfounded, or to comply with applicable laws, regulations, standards and other +obligations relating to data privacy and security, could result in additional cost and liability to us, harm our reputation and brand, +damage our relationships with customers and have a material and adverse impact on our business. +While +we maintain general liability insurance coverage, cyber insurance coverage and other insurance, we cannot assure that such coverage will +be adequate or otherwise protect us from or adequately mitigate liabilities or damages with respect to claims, costs, expenses, litigation, +fines, penalties, business loss, data loss, regulatory actions or material adverse effects arising out of our privacy and security practices, +Processing or security breaches we may experience, or that such coverage will continue to be available on acceptable terms or at all. +The successful assertion of one or more large claims against us that exceeds our available insurance coverage, or results in changes +to our insurance policies (including premium increases or the imposition of large deductible or co-insurance requirements), could have +an adverse effect on our business. In addition, we cannot be sure that our existing insurance coverage will continue to be available +on acceptable terms or that our insurers will not deny coverage as to any future claim. +We +may incur substantial costs in our efforts to comply with evolving global data protection laws and regulations, and any failure or perceived +failure by us to comply with such laws and regulations may harm our business and operations. +The +global data protection landscape is rapidly evolving, and we may be or become subject to or affected by numerous federal, state and foreign +laws and regulations, as well as regulatory guidance, governing the collection, use, disclosure, transfer, security and processing of +personal data, such as information that we collect about subjects and health care providers in connection with clinical trials. Implementation +standards and enforcement practices are likely to remain uncertain for the foreseeable future, which may create uncertainty in our business; +affect our or our service providers’ ability to operate in certain jurisdictions or to collect, store, transfer use and share personal +data; result in liability; or impose additional compliance or other costs on us. Any failure or perceived failure by us to comply with +federal, state, or foreign laws or self-regulatory standards could result in negative publicity, diversion of management time and effort +and proceedings against us by governmental entities or others. +In +the United States, numerous federal and state laws and regulations, including federal health information privacy laws (e.g., the Health +Insurance Portability and Accountability Act, as amended by the Health Information Technology for Economic and Clinical Health Act, or +collectively HIPAA), state data breach notification laws, state health information privacy laws, and federal and state consumer protection +laws (e.g., Section 5 of the Federal Trade Commission Act), that govern the collection, use, disclosure and protection of health-related +and other personal information could apply to our operations or the operations of our collaborators. In addition, we may obtain health +information from third parties (including research institutions from which we obtain clinical trial data) that are subject to privacy +and security requirements under HIPAA or other privacy and data security laws. Depending on the facts and circumstances, we could be +subject to criminal penalties if we knowingly obtain, use, or disclose protected health information maintained by a HIPAA-covered entity +in a manner that is not authorized or permitted by HIPAA. However, determining whether protected health information has been handled +in compliance with applicable privacy standards and our contractual obligations can be complex and may be subject to changing interpretation. +If +we are unable to properly protect the privacy and security of protected health information or other personal, sensitive, or confidential +information in our possession, we could be found to have breached our contracts. Further, if we fail to comply with applicable privacy +laws, including applicable HIPAA privacy and security standards, we could face significant administrative, civil and criminal penalties. +Enforcement activity can also result in financial liability and reputational harm, and responses to such enforcement activity can consume +significant internal and outside resources. Furthermore, state attorneys general are authorized to bring civil actions seeking either +injunctions or damages in response to violations that threaten the privacy of state residents. In addition, our ongoing efforts to comply +with evolving laws and regulations at the federal and state level may be costly and require continuous modifications to our compliance +policies, procedures, and systems. +Many +state laws govern the privacy and security of personal information and data in specified circumstances, many of which differ from each +other in significant ways, are often not pre-empted by HIPAA, and may have a more prohibitive effect than HIPAA, thus complicating compliance +efforts. For example, the California Consumer Privacy Act of 2018 (the “CCPA”), which went into effect in January 2020 and +provides new data privacy rights for consumers and new operational requirements for companies, which may increase our compliance costs +and potential liability. The CCPA gives California residents expanded rights to access and delete their personal information, opt out +of certain personal information sharing, and receive detailed information about how their personal information is used. The CCPA provides +for civil penalties for violations, as well as a private right of action for data breaches that is expected to increase data breach litigation. +While there is currently an exception for protected health information that is subject to HIPAA and clinical trial regulations, as currently +written, the CCPA may impact certain of our business activities. In addition, the California Consumer Rights Act, or CPRA, was recently +enacted to strengthen elements of the CCPA and became effective on January 1, 2023. The CPRA imposes additional data protection +obligations on covered businesses, including additional consumer rights processes, limitations on data uses, new audit requirements for +higher risk data, and opt outs for certain uses of sensitive data and expands the application of the CCPA to all human resources personal +information of California-based employees. In addition, the CPRA created a new California data protection agency authorized to issue +substantive regulations and is expected to result in increased privacy and information security enforcement. A number of other states +have considered similar privacy proposals, and states have recently enacted their own privacy laws. For example, the Virginia Consumer +Data Protection Act became effective on January 1, 2023, and Colorado and Utah enacted similar laws that will also become effective in +2023, increasing the complexity of compliance and the risk of failures to comply. These privacy laws may impact our business activities +and exemplify the vulnerability of our business to the evolving regulatory environment related to personal data. +In +addition to our operations in the United States, which may be subject to health care and other laws relating to the privacy and security +of health information and other personal information, we may be or become subject to European data privacy laws, regulations and guidelines. +The General Data Protection Regulation, (EU) 2016/679 (“GDPR”) became effective on May 25, 2018, and deals with the collection, +use, storage, disclosure, transfer, or other processing of personal data, including personal health data, regarding individuals in the +EEA. The GDPR imposes a broad range of strict requirements on companies subject to the GDPR, including requirements relating to having +legal bases for processing personal information relating to identifiable individuals and transferring such information outside the EEA, +including to the United States, providing details to those individuals regarding the processing of their personal health and other sensitive +data, obtaining consent of the individuals to whom the personal data relates, keeping personal information secure, having data processing +agreements with third parties who process personal information, responding to individuals’ requests to exercise their rights in +respect of their personal information, reporting security breaches involving personal data to the competent national data protection +authority and affected individuals, appointing data protection officers, conducting data protection impact assessments, and record-keeping. +The GDPR increases substantially the penalties to which we could be subject in the event of any non-compliance, including fines of up +to €10,000,000 or up to 2% of our total worldwide annual turnover for certain comparatively minor offenses, or up to €20,000,000 +or up to 4% of our total worldwide annual turnover, whichever is greater, for more serious offenses. The GDPR also confers a private +right of action on data subjects and consumer associations to lodge complaints with supervisory authorities, seek judicial remedies, +and obtain compensation for damages resulting from violations of the GDPR. In addition, the GDPR includes restrictions on cross-border +data transfers. +19 +Following +the United Kingdom’s withdrawal from the European Union (i.e., Brexit), and the expiry of the Brexit transition period, which ended +on December 31, 2020, the EU GDPR has been implemented in the United Kingdom (as the UK GDPR). The UK GDPR sits alongside the UK Data +Protection Act 2018 which implements certain derogations in the EU GDPR into UK law. Under the UK GDPR, companies not established in +the UK but who process personal data in relation to the offering of goods or services to individuals in the UK, or to monitor their behavior +will be subject to the UK GDPR – the requirements of which are (at this time) largely aligned with those under the EU GDPR and +as such, may lead to similar compliance and operational costs with potential fines of up to £17.5 million or 4% of global turnover. +In 2022, the government of the United Kingdom proposed and debated the Data Protection and Digital Information Bill to harmonize the +2018 Data Protection Act, UK GDPR, and the Privacy and Electronic Communications Regulations under one legislative framework. However, +progress on the bill stalled as the government continues to assess the most optimal approach to data protection reform. +We +currently sell some of our products in the EEA, and the GDPR increases our responsibility and liability in relation to personal data +that we process where such processing is subject to the GDPR, and we are required to have in place additional mechanisms and safeguards +to ensure compliance with the GDPR, including as implemented by individual countries. Compliance with the GDPR is a rigorous and time-intensive +process that increase our cost of doing business or require us to change our business practices, and despite those efforts, there is +a risk that we may be subject to fines and penalties, litigation, and reputational harm in connection with our European activities. We +expect that we will continue to face uncertainty as to whether our efforts to comply with any obligations under European privacy laws +will be sufficient. If we are investigated by a European data protection authority, we may face fines and other penalties. Any such investigation +or charges by European data protection authorities could have a negative effect on our existing business and on our ability to attract +and retain new clients or partners. +Proposed +legislation in the U.S. Congress, including changes in U.S. tax law, and the recently enacted Inflation Reduction Act of 2022 may adversely +impact us and the value of common shares, pre-funded warrants, and Warrants. +Changes +to U.S. tax laws (which changes may have retroactive application) could adversely affect us or holders of common shares. In recent years, +many changes to U.S. federal income tax laws have been proposed and made, and additional changes to U.S. federal income tax laws are +likely to continue to occur in the future. +The +U.S. Congress is currently considering numerous items of legislation which may be enacted prospectively or with retroactive effect, which +legislation could adversely impact our financial performance and the value of common shares. If enacted, most of the proposals would +be effective for the current or later years. The proposed legislation remains subject to change, and its impact on us and the holders +of common shares is uncertain. +In +addition, the Inflation Reduction Act of 2022 was recently signed into law and includes provisions that will impact the U.S. federal +income taxation of corporations. Among other items, this legislation includes provisions that will impose a minimum tax on the book income +of certain large corporations and an excise tax on certain corporate stock repurchases that would be imposed on the corporation repurchasing +such stock. It is unclear how this legislation will be implemented by the U.S. Department of the Treasury, and we cannot predict how +this legislation or any future changes in tax laws might affect us or holders of common shares, pre-funded warrants or Warrants. +Risks +Related to Our Intellectual Property +If +the combination of patents, trade secrets and contractual provisions that we rely on to protect our intellectual property is inadequate, +our ability to commercialize our products successfully will be harmed, and we may not be able to operate our business profitably. +Our +success depends significantly on our ability to protect our proprietary rights to the technologies incorporated in our products. We rely +on a combination of patent protection, trade secret laws and nondisclosure, confidentiality and other contractual restrictions to protect +our proprietary technology. However, these may not adequately protect our rights or permit us to gain or keep any competitive advantage. +The +issuance of a patent is not conclusive as to its scope, validity or enforceability. The scope, validity or enforceability of our issued +patents can be challenged in litigation or proceedings before the U.S. Patent and Trademark Office, or the USPTO, or foreign patent offices. +In addition, our pending patent applications include claims to numerous important aspects of our products under development that are +not currently protected by any of our issued patents. We cannot assure you that any of our pending patent applications will result in +the issuance of patents to us. The USPTO or foreign patent offices may deny or require significant narrowing of claims in our pending +patent applications. Patents issued as a result of the pending patent applications, if any, may not provide us with significant commercial +protection or be issued in a form that is advantageous to us. Proceedings before the USPTO or foreign patent offices could result in +adverse decisions as to the priority of our inventions and the narrowing or invalidation of claims in issued patents. The laws of some +foreign countries may not protect our intellectual property rights to the same extent as the laws of the United States, if at all. +Our +competitors may successfully challenge and invalidate or render unenforceable our issued patents, including any patents that may issue +in the future, which could prevent or limit our ability to market our products and could limit our ability to stop competitors from marketing +products that are substantially equivalent to ours. In addition, competitors may be able to design around our patents or develop products +that provide outcomes that are comparable to our products but that are not covered by our patents. +In +the event a competitor infringes upon any of our patents or other intellectual property rights, enforcing our rights may be difficult, +time-consuming and expensive, and would divert management’s attention from managing our business. There can be no assurance that +we will be successful on the merits in any enforcement effort. In addition, we may not have sufficient resources to litigate, enforce +or defend our intellectual property rights. +We +could become subject to intellectual property litigation that could be costly, result in the diversion of management’s time and +efforts, require us to pay damages, prevent us from marketing our commercially available products or product candidates and/or reduce +the margins we may realize from our products that we may commercialize. +Whether +a product infringes a patent involves complex legal and factual issues, and the determination is often uncertain. There may be existing +patents of which we are unaware that our products under development may inadvertently infringe. The likelihood that patent infringement +claims may be brought against us increases as the number of participants in the in vitro diagnostics market increases and as we +achieve more visibility in the marketplace and introduce products to market. +Any +infringement claim against us, even if without merit, may cause us to incur substantial costs, and would place a significant strain on +our financial resources, divert the attention of management from our core business, and harm our reputation. In some cases, litigation +may be threatened or brought by a patent holding company or other adverse patent owner who has no relevant product revenues and against +whom our patents may provide little or no deterrence. If we were found to infringe any patents, we could be required to pay substantial +damages, including triple damages if an infringement is found to be willful, and royalties and could be prevented from selling our products +unless we obtain a license or are able to redesign our products to avoid infringement. We may not be able to obtain a license enabling +us to sell our products on reasonable terms, or at all, and there can be no assurance that we would be able to redesign our products +in a way that would not infringe those patents. If we fail to obtain any required licenses or make any necessary changes to our technologies +or the products that incorporate them, we may be unable to commercialize one or more of our products or may have to withdraw products +from the market, all of which would have a material adverse effect on our business, financial condition and results of operations. +20 +We +rely substantially on our trademarks and trade names. If our trademarks and trade names are not adequately protected, then we may not +be able to build name recognition in our markets of interest and our business may be harmed. +We +rely substantially upon trademarks to build and maintain the integrity of our brand. Our registered and unregistered trademarks or trade +names may be challenged, infringed, circumvented, declared unenforceable or determined to be violating or infringing on other intellectual +property rights. We may not be able to protect or enforce our rights to these trademarks and trade names, which we rely upon to build +name recognition among potential partners and customers in our markets of interest. At times, competitors or other third parties may +adopt trade names or trademarks similar to ours, thereby impeding our ability to build brand identity and possibly leading to market +confusion. Asserting claims against such third parties may be prohibitively expensive. In addition, there could be potential trade name +or trademark infringement, or dilution claims brought by owners of other trademarks against us. Over the long term, if we are unable +to establish name recognition based on our trademarks and trade names, then we may not be able to compete effectively, and our business +may be adversely affected. Our efforts to enforce or protect our proprietary rights related to trademarks, trade secrets, domain names +or other intellectual property may be ineffective, could result in substantial costs and diversion of resources and could harm our business, +financial condition and results of operations. +Risks +Related to Litigation from Operating Our Business +We +may become subject to potential product liability claims, and we may be required to pay damages that exceed our insurance coverage. +Our +business exposes us to potential product liability claims that are inherent in the design, testing, manufacture, sale and distribution +of our currently marketed products and each of our product candidates that we are seeking to introduce to the market. Someone may allege +that our diagnostic tests identified inaccurate or incomplete information or otherwise failed to perform as designed. We may also be +subject to liability for errors in, a misunderstanding of or inappropriate reliance upon, the information we provide in the ordinary +course of our business activities. In addition, we may be subject to product liability claims resulting from misuse or off-label use +of our products and product candidates. Any product liability claim brought against us, with or without merit, could result in an increase +of our product liability insurance rates or in our inability to secure coverage in the future on commercially reasonable terms, if at +all. In addition, if our product liability insurance proves to be inadequate to pay a damage award, we may have to pay the excess of +this award out of our cash reserves, which could significantly harm our financial condition. A product liability claim, even one without +merit, could harm our reputation in the industry, lead to significant legal fees, and result in the diversion of management’s attention +from managing our business. +Current +or future litigation, government investigations and other legal proceedings may harm our business. +We +have been, currently are and may in the future become, involved in legal proceedings that could have a negative impact on our reputation, +business and financial condition and divert the attention of our management from the operation of our business. The types of legal proceedings +we may be or become subject to include patent and other intellectual property claims, product liability claims, employee claims, tort +or contract claims, federal or state regulatory investigations, securities class actions, and other legal proceedings, investigations +or claims. For example, we are currently parties to two securities class action claims and three derivative actions. On March 20, 2020, +we received a voluntary request for documents from the SEC relating to disclosures regarding our COVID-19 test and other matters. Since +that time we and certain of our current and former officers have been cooperating with the SEC and providing documents and information. +The Company has entered into negotiations with the SEC in an attempt to reach a consensual resolution of the matters raised in the SEC’s +investigation. Any such resolution may include the imposition of civil penalties, injunctive and other relief against the Company, senior +management and related individuals. We cannot predict the outcome of these negotiations or of the SEC’s investigation at this time, +however, to the best of our knowledge, we do not believe that the matter is reasonably likely to result in financial penalties having +a material adverse effect on the Company. Litigation and other legal proceedings are inherently unpredictable and can result in excessive +or unanticipated verdicts and/or injunctive relief that affect how we operate our business. We could incur judgments or enter into settlements +of claims for monetary damages or for agreements to change the way we operate our business, or both. There may be an increase in the +scope of these matters or there may be additional lawsuits, claims, proceedings or investigations in the future, which could harm our +business, financial condition and results of operations. Adverse publicity about regulatory or legal action against us could damage our +reputation and brand image, undermine our customers’ confidence and reduce long-term demand for any of our products or other offerings, +even if the regulatory or legal action is unfounded or not material to our operations. For additional information, see “Item 3. +Legal Proceedings.” +21 +General +Risk Factors +The +price of our common stock may fluctuate substantially. +The +market price of our common stock may be subject to wide fluctuation in response to various factors, some of which are beyond our control. +Some factors that may cause the market price of our common stock to fluctuate, in addition to the other risks mentioned in this “Risk +Factors” section and elsewhere in this report, are: +● +sales of our common stock +by our shareholders, executives, and directors; +● +o ur +ability to obtain regulatory approval to commercialize our “at-home” and POCT product candidates on a timely basis or at +all; +● +our ability to enter new +markets; +● +actual or unanticipated +fluctuations in our annual and quarterly financial results; +● +our ability to obtain financings +to continue and expand our commercial activities, expand our manufacturing operations, conduct research and development activities +including, but not limited to, human clinical trials, and other business activities; +● +our ability to secure resources +and the necessary personnel to continue and expand our commercial activities, develop additional diagnostic tests, conduct clinical +trials and gain approval for our diagnostic tests on our desired schedule; +● +commencement, enrollment +or results of our clinical trials of our diagnostic tests or any future clinical trials we may conduct; +● +changes in the development +status of our diagnostic tests; +● +any delays or adverse developments +or perceived adverse developments with respect to review by the FDA or other similar foreign regulatory authorities of our planned +clinical trials; +● +any delay in our submission +for studies or test approvals or adverse regulatory decisions, including failure to receive regulatory approval or clearance for +our diagnostic tests; +● +our announcements or our +competitors’ announcements regarding new tests, enhancements, significant contracts, acquisitions or strategic investments; +● +failures to meet external +expectations or management guidance; +● +changes in our capital +structure or dividend policy, including as a result of future issuances of securities and sales of large blocks of common stock by +our shareholders; +● +announcements and events +surrounding financing efforts, including debt and equity securities; +● +competition from existing +technologies and diagnostic tests or new technologies and diagnostic tests that may emerge; +● +announcements of acquisitions, +partnerships, collaborations, joint ventures, new diagnostic tests, capital commitments, or other events by us or our competitors; +● +changes in general economic, +political and market conditions in any of the regions in which we conduct our business; +● +changes in industry conditions +or perceptions; +● +changes in valuations of +similar companies or groups of companies; +● +analyst research reports, +recommendations and changes in recommendations, price targets and withdrawals of coverage; +● +departures and additions +of key personnel; +● +disputes and litigations +related to intellectual properties, proprietary rights, and contractual obligations; +● +changes in applicable laws, +rules, regulations, or accounting practices and other dynamics; +● +other events or factors, +many of which may be out of our control. +In +addition, if the market for stocks in our industry or industries related to our industry, or the stock market in general, experiences +a loss of investor confidence, the trading price of our common stock could decline for reasons unrelated to our business, financial condition +and results of operations. If any of the foregoing occurs, it could cause our stock price to fall and may expose us to lawsuits that, +even if unsuccessful, could be costly to defend and a distraction to management. +22 +Anti-takeover +provisions in our charter documents and Utah law could discourage, delay, or prevent a change of control of our Company and may affect +the trading price of our common stock. +We +are a Utah corporation and the anti-takeover provisions of the Utah Control Shares Acquisition Act may discourage, delay or prevent a +change of control by limiting the voting rights of control shares acquired in a control share acquisition. In addition, our Articles +of Incorporation and Bylaws may discourage, delay or prevent a change in our management or control over us that shareholders may consider +favorable. Among other things, our Amended and Restated Articles of Incorporation and Bylaws: +● +authorize the issuance +of “blank check” preferred stock that could be issued by our board of directors in response to a takeover attempt; +● +provide that vacancies +on our board of directors, including newly created directorships, may be filled only by a majority vote of directors then in office, +except a vacancy occurring by reason of the removal of a director without cause shall be filled by vote of the shareholders; +● +no right to cumulative +voting; +● +limit who may call special +meetings of shareholders; and +● +Provide for a staggered +board of directors +These +provisions could have the effect of delaying or preventing a change of control, whether or not it is desired by, or beneficial to, our +shareholders. +We +do not currently intend to pay dividends on our common stock. +We +do not expect to pay cash dividends on our common stock. Any future dividend payments are within the absolute discretion of our board +of directors and will depend on, among other things, our results of operations, working capital requirements, capital expenditure requirements, +financial condition, contractual restrictions, business opportunities, anticipated cash needs, provisions of applicable law and other +factors that our board of directors may deem relevant. We may not generate sufficient cash from operations in the future to pay dividends +on our common stock. +We +are a “smaller reporting company” and the reduced disclosure requirements applicable to smaller reporting companies may make +our common stock less attractive to investors. +We +are currently a “smaller reporting company” as defined in the Securities Exchange Act of 1934. Smaller reporting companies +are able to provide simplified executive compensation disclosures in their filings, and have certain other decreased disclosure obligations in their SEC filings, including, +among other things, only being required to provide two years of audited financial statements in annual reports. We cannot predict whether +investors will find our common stock less attractive because of our reliance on any of these exemptions. If some investors find our common +stock less attractive as a result, there may be a less active trading market for our common stock and our stock price may be more volatile. +We +incur substantial costs as a result of being a public company and our management expects to devote substantial time to public company +compliance programs. +As +a public company, we incur significant legal, insurance, accounting and other expenses, including costs associated with public company +reporting. We intend to invest resources to comply with evolving laws, regulations and standards, and this investment will result in +increased general and administrative expenses and may divert management’s time and attention from product development and commercialization +activities. If our efforts to comply with new laws, regulations and standards differ from the activities intended by regulatory or governing +bodies due to ambiguities related to practice, regulatory authorities may initiate legal proceedings against us, and our business may +be harmed. These laws and regulations could make it more difficult and costlier for us to obtain director and officer liability insurance +for our directors and officers, and we may be required to accept reduced coverage or incur substantially higher costs to obtain coverage. +These factors could also make it more difficult for us to attract and retain qualified executive officers and qualified members of our +board of directors, particularly to serve on our audit and compensation committees. In addition, if we are unable to continue to meet +the legal, regulatory and other requirements related to being a public company, we may not be able to maintain the listing of our common +stock on The NASDAQ Capital Market, which would likely have a material adverse effect on the trading price of our common stock. +ITEM +1B. UNRESOLVED STAFF COMMENTS +None. +23 +ITEM +2. PROPERTIES +Our +headquarters are located at 2401 S. Foothill Drive, Salt Lake City, Utah. Our current facility has approximately 14,000 square feet of +laboratory and office space under a lease that expires in February 2024. Our recently acquired subsidiaries also lease additional laboratory +and office space under month-to-month leases. We believe the facility we lease is sufficient to meet our needs for the foreseeable future. +ITEM +3. LEGAL PROCEEDINGS +In +the ordinary course of business, we are at times subject to various legal proceedings and disputes, including the proceedings specifically +discussed below. We assess our liabilities and contingencies in connection with outstanding legal proceedings utilizing the latest information +available. Where it is probable that we will incur a loss and the amount of the loss can be reasonably estimated, we record a liability +in our consolidated financial statements. These legal reserves may be increased or decreased to reflect any relevant developments on +a quarterly basis. Where a loss is not probable or the amount of loss is not estimable, we do not accrue legal reserves. While the outcome +of legal proceedings is inherently uncertain, based on information currently available and available insurance coverage, our management +believes that it has established appropriate legal reserves. Any incremental liabilities arising from pending legal proceedings are not +expected to have a material adverse effect on our consolidated financial position, consolidated results of operations, or consolidated +cash flows. However, it is possible that the ultimate resolution of these matters, if unfavorable, may be material to our consolidated +financial position, consolidated results of operations, or consolidated cash flows. +Class +Actions and Shareholder Derivative Suits +Gelt +Securities Class Action (District of Utah) +On +June 15, 2020, Gelt Trading Co. (“Gelt”) filed a lawsuit in the United States District Court for the District of Utah (“District +of Utah”), against the Company and certain of our directors and officers, on behalf of itself and a putative class, seeking to +recover damages for alleged violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 (“Gelt Litigation”). +The complaint alleges that Co-Diagnostics and the individual defendants overstated the accuracy of the Company’s Logix Smart COVID-19 +test in statements on April 30, 2020 and May 1, 2020, and that plaintiff suffered losses when the Company’s stock price dropped +after public reports questioned the accuracy of the Logix Smart test on May 14, 2020. On July 15, 2020, plaintiff filed an amended complaint. +On March 10, 2021, the court appointed Gelt as Lead Plaintiff, and on April 7, 2021, Lead Plaintiff filed a second amended complaint +(“SAC”), which asserts the same Sections 10(b) and 20(a) claims against the same defendants on largely the same theory. On +May 5, 2021, the defendants moved to dismiss the SAC. On March 9, 2022, the court entered a Decision & Order denying the motion to +dismiss, and on April 13, 2022, the defendants filed an answer to the SAC. On October 17, 2022, Gelt filed a motion to certify the putative +class. Discovery is currently underway and the motion to certify the class is pending. The defendants believe the claims are without +merit and intend to defend vigorously against them, but there can be no assurances as to the outcome. +Shareholder +Derivative Lawsuits (District of Utah & Utah State Court) +On +September 17, 2020, a shareholder derivative lawsuit was filed in the District of Utah by Luis Aguilera, allegedly on behalf of Co-Diagnostics, +Inc., that substantially piggybacks on the Gelt Litigation referenced above. The lawsuit asserts that the defendants failed to prevent +the alleged securities law violations largely asserted in the Gelt Litigation. On December 2, 2020, a second shareholder derivative lawsuit +was filed in the District of Utah by Melvyn Klein asserting essentially the same claims, allegedly on behalf of Co-Diagnostics, as the +Aguilera shareholder derivative action. And on April 29, 2021, the District of Utah consolidated the two shareholder derivative cases, +with the Aguilera case serving as the lead case under the caption In re Co-Diagnostics, Inc. Derivative Litigation . On May 3, +2022, plaintiffs filed an amended complaint asserting claims for breach of fiduciary duty, unjust enrichment, and contribution under +Sections 10(b) and 21D of the Securities Exchange Act of 1934. Defendants answered the amended complaint on June 24, 2022. +24 +On +November 24, 2020, an additional shareholder derivative lawsuit was filed in the District of Utah by Matthew Wallace, allegedly on behalf +of Co-Diagnostics, Inc., that also piggybacks on the Gelt Litigation referenced above. It named the same defendants and asserted essentially +the same claims, allegedly on behalf of Co-Diagnostics, as in the other District of Utah shareholder derivative actions referenced above. +On January 25, 2021, another shareholder derivative lawsuit was filed in the District of Utah by Jason Reagan, asserting essentially +the same claims as in the Wallace lawsuit. On March 18, 2021, the court consolidated the two lawsuits, with the Wallace lawsuit serving +as the lead case. On April 30, 2021, plaintiffs filed an amended complaint asserting claims for breach of fiduciary duty against defendants +and claims for insider trading. +On +March 29, 2021, an additional shareholder derivative lawsuit was filed in the Third District Court in and for Salt Lake County, State +of Utah (“Utah State Court”) by Hua Ding, allegedly on behalf of Co-Diagnostics, Inc., that also piggybacks on the Gelt Litigation +referenced above. It names the same defendants and asserts essentially the same claims as in In re Co-Diagnostics, Inc. Derivative +Litigation pending in the District of Utah referenced above. On December 12, 2022, a second shareholder derivative lawsuit was filed +in Utah State Court by Kathryn Matuch asserting essentially the same claims, allegedly on behalf of Co-Diagnostics, as the Ding shareholder +derivative action. +The +defendants believe the claims asserted in all of the shareholder derivative lawsuits referenced above are without merit and intend to +defend vigorously against them, but there can be no assurances as to the outcome. +Stadium +Capital Securities Class Action (Southern District of New York) +On +August 16, 2022, Stadium Capital LLC (“Stadium”) filed a lawsuit in the United States District Court for the Southern District +of New York, against Co-Diagnostics, Inc., and certain of our officers, on behalf of itself and a putative class, seeking to recover +damages for alleged violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934. The complaint alleges that Co-Diagnostics +and the individual defendants overstated the demand for the Company’s Logix Smart COVID-19 test in statements on May 12, 2022 and +June 15, 2022. The complaint alleges that plaintiff suffered losses when the Company’s stock price dropped after the Company disclosed +its financial results for the quarter ended June 30, 2022 in a press release on August 11, 2022. On October 31, 2022, Stadium filed a +motion seeking to be appointed as Lead Plaintiff and for Kaplan Fox & Kilsheimer LLP to be appointed as lead counsel. That motion +is pending before the U.S. District Court. The defendants believe the claims are without merit and intend to defend vigorously against +them, but there can be no assurances as to the outcome. +Commercial +Litigation +Co-Diagnostics, +Inc. v. Hukui Technology, Inc., et al. (Third Judicial District Court, Salt Lake County, State of Utah, Civil No. 210902131, filed on +April 21, 2021). +The +Company filed a complaint against Defendants Hukui Technology, Inc., Hukui Tech, Inc., and Hukui Bio Co., Ltd (collectively, “Hukui”) +seeking a declaratory judgment that the Company is not obligated to any of them in any amount. On August 24, 2021, Hukui filed their +Answer and Counterclaim seeking damages on a number of theories, including breach of contract for letter agreements, breach of oral agreement, +promissory estoppel, unjust enrichment, and interference with economic relations. Hukui requested a money judgment against the Company +in an amount to be determined at trial. On September 20, 2021, Hukui filed their Unopposed Motion for Leave to Amend Answer to the Complaint, +Affirmative Defenses, and Counterclaims and, on October 14, 2021, Hukui filed their Amended Answer and Counterclaims seeking damages +on declaratory judgment, as well as breach of contract for letters of authorization, breach of oral agreement, promissory estoppel, unjust +enrichment, and interference with economic relations. In 2022 the parties exchanged their initial disclosures, exchanged written discovery +requests, and conducted a number of depositions on each side that were concluded in January 2023. The Company believes the claims are +without merit and intends to defend vigorously against them, but there can be no assurances as to the outcome. +Co-Diagnostics, +Inc. v. Pantheon International Advisors Ltd. (Third Judicial District Court, Salt Lake County, State of Utah, Civil No. 210902609, filed +on May 14, 2021). +The +Company filed a complaint against Pantheon International Advisors (“Pantheon”) asking the court to declare that the Company +has no ongoing contractual business relationship with Pantheon, no monies owing, nor does Pantheon have any interest, right, title or +claim to any stock issued by the Company or ownership of any kind in the Company. Pantheon was served with a 30-Day Summons on September +9, 2021 to which it failed to respond, and a default judgement against Pantheon International Advisors was entered by the Court on November +28, 2021. The time to appeal from the judgment or seek to vacate the judgment has passed. +After +learning that the Company had initiated suit in Utah, and after learning of Company’s intent to serve it with process of that suit, +on May 24, 2021, Pantheon filed a claim against the Company in the Royal Courts of Justice Group, Queens Bench Division, Claim No. QB-21-002245, +stating that the Company owes Pantheon $2,860,809.79 for alleged breach of contract for failing to make payments purportedly due under +a contract allegedly entered into on October 18, 2018. The Company is being represented locally in the UK by Freshfields Bruckhaus Deringer +LLP in that matter. On March 4, 2022, the Company filed a jurisdictional challenge to the UK suit, alleging that there was no 2018 agreement, +and that the Company is not subject to jurisdiction in the UK. The oral argument and presentation of evidence on solely the jurisdictional +claim took place on November 9, 2022, with the court taking the matter of jurisdiction over the Company under advisement. The court has +not yet ruled on the motion to dismiss, and it is not yet known when the court will rule upon that motion. The Company intends to vigorously +defend against the UK claims and will seek to the full extent possible to enforce its rights under the Declaratory Judgment already obtained +in Utah but there can be no assurances as to the outcome. +From +time to time, we may become involved in litigation and other proceedings relating to claims arising out of our operations in the normal +course of business and to inquiries from FINRA, NASDAQ and the U.S. Securities and Exchange Commission (the SEC). On March 20, +2020, the Company received a voluntary request for documents from the SEC relating to disclosures regarding our COVID-19 test and other +matters. Since that time we and certain of our current and former officers have been cooperating with the SEC and providing documents +and information. The Company has entered into negotiations with the SEC in an attempt to reach a consensual resolution of the matters +raised in the SEC’s investigation. Any such resolution may include the imposition of civil penalties, injunctive and other relief +against the Company, senior management and related individuals. We cannot predict the outcome of these negotiations or of the SEC’s +investigation at this time, however, to the best of our knowledge, we do not believe that the matter is reasonably likely to result in +financial penalties having a material adverse effect on the Company. +ITEM +4. MINE SAFETY DISCLOSURES +Not +applicable. +25 +PART +II +ITEM +5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER EQUITY SECURITIES +Market +Information +Our +common stock has been quoted on the NASDAQ market under the symbol “CODX” since July 12, 2017. +Holders +As +of March 14, 2023, the last reported sales price reported on NASDAQ for our common stock was $2.99 per share. As of March 14, 2023, we +had approximately 154 record holders of our common stock. The number of record holders was determined from the records of our transfer +agent and does not include beneficial owners of common stock whose shares are held in the names of various security brokers, dealers, +and registered clearing agencies. The transfer agent for our common stock is VStock Transfer LLC located at 18 Lafayette Pl, Woodmere, +New York 11598. +Dividends +We +have never declared or paid any cash dividends on our capital stock. The payment of dividends on our common stock in the future will +depend on our earnings, capital requirements, operating and financial condition and such other factors as our board of directors may +consider appropriate. We currently expect to use all available funds to finance the future development and expansion of our business +and do not anticipate paying dividends on our common stock in the foreseeable future. +Pursuant +to Section 16-10a-640 of the Utah Revised Business Corporation Act, no distribution may be made if, after giving it effect: +(a) +the corporation would not +be able to pay its debts as they become due in the usual course of business; or +(b) +the corporation’s +total assets would be less than the sum of its total liabilities plus, unless the articles of incorporation permit otherwise, the +amount that would be needed, if the corporation were to be dissolved at the time of the distribution, to satisfy the preferential +rights upon dissolution of shareholders whose preferential rights are superior to those receiving the distribution. +Recent +Sales of Unregistered Securities +None. +26 +Purchases +of Equity Securities by the Issuer and Affiliated Purchasers +Share +Repurchase Program +Issuer Purchase of Equity Securities +Period +(a) Total number of shares purchased (1) +(b) Average price paid per share (1) +(c ) Total number of shares purchased as part of publicly announced plans or programs (1) +(d) Maximum number (or approximate dollar value) of shares that may yet be purchased under the plans or programs (1) +10/01/22 - 10/31/22 +- +$ - +- +$ 17,005,627 +11/01/22 - 11/30/22 +4,750 +$ 3.01 +4,750 +$ 16,991,319 +12/01/22 - 12/31/22 +462,582 +$ 2.60 +462,582 +$ 15,788,134 +Total +467,332 +$ 2.61 +467,332 +$ 15,788,134 +(1) +In March 2022, the company +announced that its board of directors authorized the repurchase of up to $30.0 million of the company’s outstanding common +stock. The extent to which the company repurchases its shares, and the timing of such repurchases, will depend upon a variety of +factors, including trading volume, market conditions, legal requirements, business conditions and other factors. The repurchase program +may be discontinued at any time, and the program does not obligate the company to acquire any specific number of shares of its common +stock. +ITEM +6. RESERVED +ITEM +7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULT OF OPERATIONS +The +following management’s discussion and analysis of financial condition and results of operations describes the principal factors +affecting the results of our operations, financial condition, and changes in financial condition. This discussion should be read in conjunction +with the accompanying audited financial statements, and notes thereto, included elsewhere in this report. In addition to historical information, +this Annual Report contains forward-looking statements that involve risks, uncertainties, and assumptions. Our actual results may differ +materially from those anticipated in these forward-looking statements as a result of certain factors, including but not limited to those +set forth under the caption “Item 1A. Risk Factors” in this Annual Report on Form 10-K. +27 +Business +Overview +Co-Diagnostics, +Inc., a Utah corporation (the “Company” or “CODX”), develops, manufactures and sells reagents used for diagnostic +tests that function via the detection and/or analysis of nucleic acid molecules (DNA or RNA), including robust and innovative molecular +tools for detection of infectious diseases, liquid biopsy for cancer screening, and agricultural applications. In connection with the +sale of our tests we may sell diagnostic equipment from other manufacturers as self-contained lab systems (which we refer to as the “MDx +Device”). We are also developing a unique, groundbreaking portable PCR device and proprietary test cups (the “Co-Dx PCR Home +platform”) that have been designed to bring affordable, reliable polymerase chain reaction (“PCR”) to patients in point-of-care +and even at-home settings. This platform is subject to U.S. Food and Drug Administration (“FDA”) review and is not available +for sale at the time of this filing. There is no guarantee the our Co-Dx PCR Home platform will receive the necessary regulatory approvals +for commercialization, or that, if regulatory approval is received, we will be able to successfully commercialize this platform. +Our +diagnostics systems enable dependable, low-cost, molecular testing for organisms and genetic diseases by automating or simplifying historically +complex procedures in both the development and administration of tests. CODX’s technical advance involves a novel, patented approach +to PCR test design of primer and probe structure (“CoPrimers”) that eliminates one of the key vexing issues of PCR amplification: +the exponential growth of primer-dimer pairs (false positives and false negatives) which adversely interferes with identification of +the target DNA/RNA. +We +believe our proprietary molecular diagnostics technology is paving the way for innovation in disease detection and life sciences research +through our enhanced detection of genetic material. For various reasons, including owning our own platform, we believe we will be able +to accomplish this faster and more economically than some competitors, allowing for significant margins while still positioning ourselves +as a low-cost provider of molecular diagnostics and screening services. +In +addition, continued development has demonstrated the unique properties of our CoPrimer technology that we believe makes it ideally suited +for a variety of applications where specificity is key to optimal results, including multiplexing several targets, enhanced Single Nucleotide +Polymorphism (“SNP”) detection and enrichment for next generation sequencing. +Our +scientists use the complex mathematics of DNA/RNA PCR test design to engineer and optimize PCR tests and to automate algorithms that +rapidly screen millions of possible options to pinpoint the optimum design. Dr. Brent Satterfield, our founder, developed the intellectual +property we use in our business, consisting of the predictive mathematical algorithms and patented molecular structure used in the testing +process, which together represent a major advance in PCR testing systems. CODX technologies are now protected by more than 20 granted +or pending US and foreign patents, as well as certain trade secrets and copyrights. Ownership of our proprietary platform permits us +the advantage of avoiding payment of patent royalties required by other PCR test systems, which may allow the sale of diagnostic PCR +tests at a lower price than competitors, while enabling us to maintain profit margins. +Our +proprietary test design process involves identifying the optimal locations on the target genes for amplification and pair the locations +with the optimized primer and probe structure to achieve outputs that meet the design input requirements identified from market research. +This is done by following planned and documented processes, procedures and testing. In other words, we use the data resulting from our +tests to verify whether we succeeded in designing what we intended. Verification involves a series of testing that concludes that the +product is ready to proceed to validation in an evaluation either in our laboratory or in an independent laboratory setting using initial +production tests to confirm that the product as designed meets the user needs. +We +may either sell or lease the MDx Device to labs and diagnostic centers, through sale or lease agreements, and sell the reagents that +comprise our proprietary tests to those laboratories and testing facilities. +Using +our proprietary test design system and proprietary reagents, we have designed and obtained regulatory approval in the European Community +and/or in India to sell PCR diagnostic tests for the detection of COVID-19, influenza, tuberculosis, hepatitis B and C, human papillomavirus, +malaria, chikungunya, dengue, and the Zika virus. In the United States, we obtained Emergency Use Authorization (“EUA”) for +our Logix Smart COVID-19 detection test from the Food and Drug Administration, or FDA, and we sell that test to qualified labs. In addition, +our COVID-19 detection test and certain of our other suite of COVID-19 products have been approved for sale in countries such as the +United Kingdom, Australia and Mexico by the regulatory bodies in those countries and have been registered for sale in many more countries. +28 +In +addition to testing for infectious disease, the technology lends itself to identifying any section of a DNA or RNA strand that describes +any type of genetic trait, which creates several significant applications. We, in conjunction with our customers, are active in designing +and licensing tests that identify genetic traits in plant and animal genomes. We also have three multiplexed tests developed to test +mosquitos for the identification of diseases carried by the mosquitos to enable municipalities to concentrate their efforts in managing +mosquito populations on the specific areas known to be breeding the mosquitos that carry deadly viruses. +RESULTS +OF OPERATIONS +Results +of Operations for the Years Ended December 31, 2022 and 2021 +The +table below provides a comparison of our operating results for the year ended December 31, 2022 as compared to the year ended December +31, 2021. +Years Ended December 31, +Year Change +2022 +2021 +Change +% +Revenue +$ 34,218,209 +$ 97,885,603 +$ (63,667,394 ) +-65 % +Cost of revenue +5,481,092 +11,574,944 +(6,093,852 ) +-53 % +Gross profit +28,737,117 +86,310,659 +(57,573,542 ) +-67 % +Operating expenses +Sales and marketing +7,344,628 +13,397,813 +(6,053,185 ) +-45 % +General and administrative +14,262,963 +11,550,615 +2,712,348 +23 % +Research and development +17,438,098 +14,961,916 +2,476,182 +17 % +Depreciation and amortization +1,282,718 +335,363 +947,355 +282 % +Goodwill impairment charges +15,388,546 +- +15,388,546 +- +Total operating expenses +55,716,953 +40,245,707 +15,471,246 +38 % +Income (loss) from operations +(26,979,836 ) +46,064,952 +(73,044,788 ) +-159 % +Other income (expense) +Interest income +704,044 +45,631 +658,413 +1443 % +Loss on disposition of assets +(138,117 ) +(44,355 ) +(93,762 ) +211 % +Gain on remeasurement of acquisition contingencies +7,899,644 +- +7,899,644 +- +Loss on equity method investment in joint venture +(332,969 ) +(430,433 ) +97,464 +-23 % +Total other income (expense) +8,132,602 +(429,157 ) +8,561,759 +-1995 % +Income (loss) before income taxes +(18,847,234 ) +45,635,795 +(64,483,029 ) +-141 % +Income tax provision (benefit) +(4,608,985 ) +8,977,231 +(13,586,216 ) +-151 % +Net income (loss) +$ (14,238,249 ) +$ 36,658,564 +$ (50,896,813 ) +-139 % +29 +Revenues +For +the year ended December 31, 2022, we generated $34.2 million of revenue compared to revenue of $97.9 million in the year ended December +31, 2021. The decrease in revenue of $63.7 million was primarily due to lower sales of our Logix Smart COVID-19 test throughout the world, +which was developed in response to the current COVID-19 pandemic. As global attention and regulatory responses to the COVID-19 pandemic have eased, we have experienced significantly +decreases in demand for our COVID-19 test. We anticipate that demand for our COVID-19 test will continue to normalize as concerns relating +to COVID-19 further wane. +Cost +of Revenues and Gross Profit +Cost +of revenues decreased by $6.1 million from $11.6 million for the year ended December 31, 2021 to $5.5 million for the year ended December +31, 2022. The decrease in revenues combined with a larger percentage of fixed product manufacturing costs resulted in a lower cost of +revenues and gross margin percentage. Our gross margin was 84.0% for the year ended December 31, 2022 compared to 88.2% for the year +ended December 31, 2021. +Operating +Expenses +We +incurred total operating expenses of $55.7 million for the year ended December 31, 2022 compared to total operating expenses of $40.2 +million for the year ended December 31, 2021. The increase in operating expenses was primarily due to the impairment of goodwill recorded +in conjunction with the acquisitions of IdMo and ACI, increases in depreciation and amortization of capital and intangible assets, increased +expenses related to personnel, including stock-based compensation, and increased investment in research and development, offset by decreased +sales and marketing expenses, including third party sales commissions, in relation to the reduction of revenue. +Sales +and marketing expenses for the year ended December 31, 2022 were $7.3 million compared to $13.4 million for the year ended December 31, +2021. The decrease of $6.1 million was primarily a result of decreased variable compensation, such as bonuses and commissions, and decreased +third-party sales commissions, partially offset by increased stock-based compensation expense. +General +and administrative expenses increased $2.7 million from $11.6 million for the year ended December 31, 2021 to $14.3 million for the year +ended December 31, 2022. The increase in general and administrative expenses was primarily due to increased insurance expense and professional, +legal, and advisory fees, as well as increased stock-based compensation expense, partially offset by decreased variable compensation +expense. +Our +research and development expenses increased by $2.4 million from $15.0 million for the year ended December 31, 2021, to $17.4 million +for the year ended December 31, 2022. The primary increase in expenses related to increased personnel expenses in conjunction with our +acquisitions of IdMo and ACI on December 31, 2021, the primary focus of which relates to the point-of-care device development, as well +as increased stock-based compensation expense. Additionally, there has been an increase in professional and lab services utilized to +further help us in our research and product development activities. +During +the year ended December 31, 2022, the Company recognized impairment charges of $15,388,546 related to goodwill recorded in conjunction +with the acquisitions of IdMo and ACI on December 31, 2021. +Other +Income (Expense) +Other +income was $8.1 million for the year ended December 31, 2022, compared to other expense of $0.4 million for the year ended December +31, 2021. The increase in other income of $8.6 million was primarily due to a change in the fair value of contingent consideration +liabilities recorded in conjunction with the acquisitions of IdMo and ACI and driven by changes in the Company’s stock price, as well as increased interest income due to higher +investment balances and interest rates in 2022 compared to 2021. +30 +Net +Income +We +realized a net loss for the year ended December 31, 2022 of $14.2 million compared to net income of $36.7 million for the year ended +December 31, 2021. The decrease in net income of $50.9 million was primarily the result of reduced sales of our Logix Smart COVID-19 +test, increased operating expenses as discussed above, and impairment of the goodwill recorded in conjunction with the acquisitions of +IdMo and ACI, partially offset by gains related to change in the fair value of acquisition related contingent liabilities. Additionally, +we recorded an income tax benefit of $4.6 million during the year ended December 31, 2022, compared to income tax expense of $9.0 million +for the year ended December 31, 2021. +LIQUIDITY +AND CAPITAL RESOURCES +At +December 31, 2022, we had cash and cash equivalents of $23.0 million and marketable investment securities of $58.3 million. We consider +our marketable investment securities an important part of our liquidity and focus such investments in securities that can readily be +converted into cash if needed. Additionally, our total current assets at December 31, 2022, were $92.7 million compared to total current +liabilities of $3.9 million. +Net +cash provided by operating activities during the year ended December 31, 2022 was $6.6 million, compared to $41.1 million for the year +ended December 31, 2021. The decrease in cash from operating activities was primarily due to our decreased revenue and accounts receivable. +We +used $58.2 million of cash in investing activities during the year ended December 31, 2022 as compared to $4.1 million of cash from investing +activities during the year ended December 31, 2021. The increase in cash used in investing activities is primarily due to purchases of +marketable investment securities. +Net +cash used in financing activities was $14.0 million for the year ended December 31, 2022, compared to $0.5 million of cash from financing +activities for the year ended December 31, 2021. The decrease is primarily due to the repurchase of outstanding common shares during +the current fiscal year. +Since +commencing sales of our Logix Smart COVID-19 test in March 2020, we have used our cash generated from those sales to fund the purchase +of inventories and the development of our point-of-care device, and to pay our operating expenses. We have increased our work force most +significantly in research and development in order to continue development of a new device and additional tests that will enable continued +use of our distributor network to sell additional products throughout the world. +We +believe that our existing capital resources and the cash generated from future sales will be sufficient to meet our projected operating +requirements for the next 12 months. However, our available capital resources may be consumed more +rapidly than currently expected and we may need or want to raise additional financing for strategic opportunities. If needed, we expect +additional investment capital to come from (i) additional issuances of our common stock with existing and new investors or (ii) the private +placement of other securities with investors similar to those that have provided funding in the past. We may not be able to secure such +financing in a timely manner or on favorable terms, if at all. +CRITICAL +ACCOUNTING POLICIES AND ESTIMATES +Our +management’s discussion and analysis of our financial condition and results of operations is based on our consolidated financial +statements, which have been prepared in accordance with United States generally accepted accounting principles (“GAAP”). +The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets +and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, as well as the reported +revenues and expenses incurred during the reporting periods. Our estimates are based on our historical experience and on various other +factors that we believe are reasonable under the circumstances. Actual results may differ from these estimates under different assumptions +or conditions. While our significant accounting policies are described in Item 8 of this Annual Report on Form 10-K, within Note 2 of +our consolidated financial statements in the section titled “Summary of Significant Accounting Policies”, we believe that +the accounting policies discussed below are critical to understanding our historical and future performance, as these policies relate +to the more significant areas involving management’s judgments and estimates. +Accounts +Receivable +Trade +accounts receivable are recorded at the invoiced amount, net of any allowance. The Company maintains an allowance for doubtful accounts +for amounts the Company does not expect to collect. In establishing the required allowance, management considers historical losses, current +market condition, customers’ financial condition, the age of receivables, and current payment patterns. Account balances are written +off against the allowance once the receivable is deemed uncollectible. If actual accounts receivable collections are less favorable than +those projected by management at the time of the assessment, however, additional accounts receivable write-downs may be required, which +could reduce our earnings. +31 +Goodwill +and Intangible Assets +The +useful lives of intangible assets with definite lives are based on the expected number of years the asset will generate revenue or otherwise +be used by us and the related amortization is based on the straight-line method. Goodwill, which has an indefinite life, is not amortized +but instead is tested at least annually for impairment, or more frequently when events or changes in circumstances indicate that the +asset might be impaired. Examples of such events or circumstances include: +● the +asset’s ability to continue to generate income from operations and positive cash flow in future periods; +● +any volatility or significant decline in our stock price and market capitalization compared to our net book value; +● +loss of legal ownership or title to an asset; +● significant +changes in our strategic business objectives and utilization of our assets; and +● the +impact of significant negative industry or economic trends. +If +a change were to occur in any of the above-mentioned factors or estimates, the likelihood of a material change in our reported results +would increase. For goodwill, the entity has the option to first assess qualitative factors to determine whether it is necessary to perform +the quantitative goodwill impairment test. The quantitative impairment test compares the fair value of a reporting unit with the carrying +amount, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill is considered not impaired; otherwise, +goodwill is impaired and the loss is recorded. We completed our annual evaluation for impairment of goodwill as of December 31, 2022 +and recorded a goodwill impairment charge of $15,388,546. +Accounting +for Business Combinations +Under +the acquisition method of accounting, the cost of an acquired business is assigned to the tangible and identifiable intangible assets +acquired and liabilities assumed on the basis of the estimated fair values at the date of acquisition. We assess fair value, which is +the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants +at the measurement date, using a variety of methods including, but not limited to, an income approach and a market approach, such as +the estimation of future cash flows of the acquired business and current selling prices of similar assets. These valuations require us +to make estimates and assumptions, especially with respect to intangible assets. Fair value of the assets acquired and liabilities assumed, +including intangible assets, in-process research and development, and contingent payments, are measured based on the assumptions and +estimations with regards to variable factors such as the amount and timing of future cash flows for the asset or liability being measured, +appropriate risk-adjusted discount rates, or other factors that market participants would consider. Upon acquisition, we determine the +estimated economic lives of the acquired intangible assets for amortization purposes, which are based on the underlying expected cash +flows of such assets. Goodwill is an asset representing the future economic benefits arising from other assets acquired in a business +combination that is not individually identified and separately recognized. Actual results may vary from projected results and assumptions +used in the fair value assessments. If the initial accounting for a business combination is incomplete by the end of a reporting period +that falls within the measurement period, we report provisional amounts in our financial statements. During the measurement period, we +adjust the provisional amounts recognized at the acquisition date to reflect new information obtained about facts and circumstances that +existed as of the acquisition date that, if known, would have affected the measurement of the amounts recognized as of that date. We +record these adjustments to the provisional amounts with a corresponding offset to goodwill. Any adjustments identified after the measurement +period are recorded in the Consolidated Statements of Operations and Comprehensive Income (Loss). +Inventories +We +periodically review inventory for both potential obsolescence and potential declines in anticipated selling prices. In this review, we +make assumptions about the future demand for and market value of the inventory and based on these assumptions estimate the amount of +any obsolete, unmarketable, slow moving or overvalued inventory. We write down the value of our inventories by an amount equal to the +difference between the cost of the inventory and the net realizable value. If actual market conditions are less favorable than those +projected by management at the time of the assessment, however, additional inventory write-downs may be required, which could reduce +our earnings. +Income +Taxes +Significant +judgment is required in determining our provision for income taxes, current tax assets and liabilities, deferred tax assets and liabilities, +and our future taxable income, both as a whole and in various tax jurisdictions, for purposes of assessing our ability to realize future +benefit from our deferred tax assets. We recognize in the financial statements the impact of a tax position if that position is more +likely than not to be sustained during an audit, including resolution of related appeals or litigation processes, if any. While we believe +that we have appropriate support for the positions taken on our tax returns, we regularly assess the potential outcome of examinations +by tax authorities in determining the adequacy of our provision for income taxes. See Note 12 to our Consolidated Financial Statements +for more information on income taxes. +The +foregoing estimates, expectations and forward-looking statements are subject to change as we make strategic operating decisions from +time to time and as our revenue and expenses fluctuate from period to period. +ITEM +7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Not +required. +32 +ITEM +8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. +CONSOLIDATED +FINANCIAL STATEMENTS +DECEMBER +31, 2022 AND 2021 +Table +of Contents +Report of Independent Registered Public Accounting Firm (PCAOB ID No. 457 ) +34 +Balance Sheets +35 +Statements of Operations +36 +Statement of Changes in Stockholders’ Equity +37 +Statements of Cash Flows +38 +Notes to Financial Statements +39 +33 +REPORT +OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +To +the Board of Directors and Stockholders of Co-Diagnostics, Inc. +Opinion +on the Financial Statements +We have audited the accompanying consolidated balance sheets of Co-Diagnostics, +Inc (the Company) as of December 31, 2022 and 2021, and the related consolidated statements of operations and comprehensive income (loss), +changes in stockholders’ equity, and cash flows for each of the years in the two-year period ended December 31, 2022, and the related +notes (collectively referred to as the financial statements). In our opinion, the financial statements present fairly, in all material +respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows +for each of the years in the two-year period ended December 31, 2022, in conformity with accounting principles generally accepted in the +United States of America. +Basis +for Opinion +These +financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s +financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board +(United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities +laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We +conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain +reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company +is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, +we are required to obtain an understanding of internal control over financial reporting, but not for the purpose of expressing an opinion +on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. +Our +audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error +or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding +the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant +estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits +provide a reasonable basis for our opinion. +Critical +Audit Matters +The +critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated +or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial +statements and (2) involved especially challenging, subjective, or complex judgments. The communication of critical audit matters does +not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters +below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate. +Goodwill +and Intangible Assets +As +discussed in Note 4 and in Note 7 to the consolidated financial statements, the Company acquired Idaho Molecular, Inc., and Advanced +Conceptions, Inc. in December 2021. As part of the transaction, the Company acquired intangible assets totaling $27,195,000, and goodwill +totaling $15,388,546. The Company assesses these assets for impairment at least annually or whenever events or changes in circumstances +occur that may indicate impairment. The Company’s analysis for the year ended December 31, 2022, required significant judgment +to create a valuation based on future cash flows. As a result of their analysis, the Company fully impaired its goodwill, while no impairment +was recorded for the intangible assets. +We +identified the carrying amount of goodwill and intangible assets as a critical audit matter because management’s assessment of +the acquisition is highly subjective. This required an increased amount of effort, including the need to involve our internal valuation +specialist, when performing audit procedures to evaluate the reasonableness of management’s estimates and assumptions. +Addressing +the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated +financial statements. These procedures included, among others, gaining an understanding of management’s process for developing the fair +value estimate. We also evaluated the expertise, qualifications, and independence of management’s specialist engaged to complete +the evaluation. We used professionals inside our firm with specialized skills and knowledge to assess the Company’s methodology. +We considered the inputs, sources of data used, assumptions, and estimates used in the valuation model. We tested the mathematical accuracy +of the underlying schedules used in the valuation assessment to ensure the completeness and accuracy of the reports. Finally, we considered +the sensitivity of changes to key assumptions in the model. +/s/ +Haynie & Company +Salt +Lake City, Utah +March +16, 2023 +We +have served as the Company’s auditor since 2016. +34 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +CONSOLIDATED +BALANCE SHEETS +December 31, 2022 +December 31, 2021 +Assets +Current assets +Cash and cash equivalents +$ 22,973,803 +$ 88,607,234 +Marketable investment securities +58,289,066 +1,255,266 +Accounts receivable, net +3,453,723 +20,839,182 +Inventory +5,310,473 +2,004,169 +Income taxes receivable +1,870,419 +- +Prepaid expenses and other current assets +761,186 +2,338,444 +Note receivable +75,000 +75,000 +Total current assets +92,733,670 +115,119,295 +Property and equipment, net +2,539,483 +1,933,216 +Operating lease right-of-use asset +372,115 +- +Goodwill +- +14,706,818 +Intangible assets, net +26,768,333 +27,195,000 +Investment in joint venture +672,679 +1,004,953 +Note receivable +- +75,000 +Total assets +$ 123,086,280 +$ 160,034,282 +Liabilities and stockholders’ equity +Current liabilities +Accounts payable +$ 952,297 +$ 607,506 +Accrued expenses, current +934,447 +3,859,652 +Operating lease liability, current +297,209 +- +Contingent consideration liabilities, current +1,689,471 +5,767,304 +Income taxes payable +- +2,213,088 +Deferred revenue +- +150,000 +Total current liabilities +3,873,424 +12,597,550 +Long-term liabilities +Income taxes payable +1,181,284 +1,067,853 +Deferred tax liability +2,417,987 +7,228,444 +Operating lease liability +50,708 +- +Contingent consideration liabilities +1,042,885 +4,665,337 +Total long-term liabilities +4,692,864 +12,961,634 +Total liabilities +8,566,288 +25,559,184 +Commitments and contingencies (Note 13) +Stockholders’ equity +Convertible preferred stock, $ 0.001 par value; 5,000,000 shares authorized; 0 shares issued and outstanding as of December 31, 2022 and December 31, 2021, respectively +- +- +Common stock, $ 0.001 par value; 100,000,000 shares authorized; 34,754,265 shares issued and 30,872,607 shares outstanding as of December 31, 2022 and 33,819,862 shares issued and outstanding as of December 31, 2021 +34,754 +33,820 +Treasury stock, at cost; 3,881,658 and 0 shares held as of December 31, 2022 and December 31, 2021, respectively +( 14,211,866 ) +- +Additional paid-in capital +88,472,934 +80,271,999 +Accumulated other comprehensive income +293,140 +- +Accumulated earnings +39,931,030 +54,169,279 +Total stockholders’ equity +114,519,992 +134,475,098 +Total liabilities and stockholders’ equity +$ 123,086,280 +$ 160,034,282 +See +accompanying notes to consolidated financial statements. +35 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) +2022 +2021 +Years Ended December 31, +2022 +2021 +Revenue +$ 34,218,209 +$ 97,885,603 +Cost of revenue +5,481,092 +11,574,944 +Gross profit +28,737,117 +86,310,659 +Operating expenses +Sales and marketing +7,344,628 +13,397,813 +General and administrative +14,262,963 +11,550,615 +Research and development +17,438,098 +14,961,916 +Depreciation and amortization +1,282,718 +335,363 +Goodwill impairment charges +15,388,546 +- +Total operating expenses +55,716,953 +40,245,707 +Income (loss) from operations +( 26,979,836 ) +46,064,952 +Other income (expense) +Interest income +704,044 +45,631 +Loss on disposition of assets +( 138,117 ) +( 44,355 ) +Gain on remeasurement of acquisition contingencies +7,899,644 +- +Loss on equity method investment in joint venture +( 332,969 ) +( 430,433 ) +Total other income (expense) +8,132,602 +( 429,157 ) +Income (loss) before income taxes +( 18,847,234 ) +45,635,795 +Income tax provision (benefit) +( 4,608,985 ) +8,977,231 +Net income (loss) +$ ( 14,238,249 ) +$ 36,658,564 +Other comprehensive income +Change in net unrealized gains on marketable securities, net of tax +$ 293,140 +$ - +Total other comprehensive income +$ 293,140 +$ - +Comprehensive income (loss) +$ ( 13,945,109 ) +$ 36,658,564 +Earnings per common share: +Basic +$ ( 0.45 ) +$ 1.27 +Diluted +$ ( 0.45 ) +$ 1.23 +Weighted average shares outstanding: +Basic +31,479,028 +28,874,555 +Diluted +31,479,028 +29,903,686 +See +accompanying notes to consolidated financial statements. +36 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY +Shares +Amount +Shares +Amount +Stock +Capital +Income +Earnings +Equity +Convertible +Preferred Stock +Common +Stock +Treasury +Additional +Paid-in +Accumulated +Other Comprehensive +Accumulated +Total +Stockholders’ +Shares +Amount +Shares +Amount +Stock +Capital +Income +Earnings +Equity +Balance as of December 31, 2020 +- +$ - +28,558,033 +$ 28,558 +$ - +$ 49,157,236 +$ - +$ 17,510,715 +$ 66,696,509 +Common stock issued for option +exercises +- +- +189,225 +189 +450,209 +- +- +450,398 +Stock-based compensation expense +- +- +444,050 +444 +- +5,508,960 +- +- +5,509,404 +Common stock issued for acquisitions +- +- +4,628,554 +4,629 +25,155,594 +- +- +25,160,223 +Net income +- +- +- +- +- +- +36,658,564 +36,658,564 +Balance as of December 31, 2021 +- +$ - +33,819,862 +$ 33,820 +$ - +$ 80,271,999 +$ - +$ 54,169,279 +$ 134,475,098 +Balance +- +$ - +33,819,862 +$ 33,820 +$ - +$ 80,271,999 +$ - +$ 54,169,279 +$ 134,475,098 +Common stock issued for option +exercises +- +- +70,791 +70 +- +77,800 +- +- +77,870 +Common stock issued for warrant +exercises +- +- +50,000 +50 +- +99,950 +- +- +100,000 +Stock-based compensation expense +- +- +725,166 +725 +- +7,542,498 +- +- +7,543,223 +Common stock issued for acquisitions +- +- +88,446 +89 +- +480,687 +- +- +480,776 +Repurchases of common stock +- +- +- +- +( 14,211,866 ) +- +- +- +( 14,211,866 ) +Other comprehensive income, +net of tax +- +- +- +- +- +- +293,140 +- +293,140 +Net income +- +- +- +- +- +- +- +( 14,238,249 ) +( 14,238,249 ) +Balance as of December 31, 2022 +- +$ - +34,754,265 +$ 34,754 +$ ( 14,211,866 ) +$ 88,472,934 +$ 293,140 +$ 39,931,030 +$ 114,519,992 +Balance +- +$ - +34,754,265 +$ 34,754 +$ ( 14,211,866 ) +$ 88,472,934 +$ 293,140 +$ 39,931,030 +$ 114,519,992 +See +accompanying notes to consolidated financial statements. +37 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF CASH FLOWS +2022 +2021 +Years Ended December 31, +2022 +2021 +Cash flows from operating activities +Net income +$ ( 14,238,249 ) +$ 36,658,564 +Adjustments to reconcile net income to cash used in operating activities: +Depreciation and amortization +1,282,718 +335,363 +Goodwill impairment charges +15,388,546 +- +Stock-based compensation expense +7,543,223 +5,509,404 +Change in fair value of acquisition contingencies +( 7,899,644 ) +- +Non-cash lease expense +30,430 +- +Loss from equity method investment +332,969 +430,433 +Loss on disposition of assets +138,117 +44,355 +Deferred income taxes +( 4,810,457 ) +930,081 +Bad debt expense +2,428,930 +69,672 +Changes in assets and liabilities: +Accounts receivable +14,956,529 +( 8,740,851 ) +Prepaid expenses +( 224,094 ) +( 2,049,095 ) +Inventory +( 3,525,210 ) +5,705,361 +Deferred revenue +( 150,000 ) +( 155,307 ) +Income taxes payable +( 2,201,250 ) +2,643,381 +Accounts payable, accrued expenses and other liabilities +( 2,483,821 ) +( 299,937 ) +Net cash provided by operating activities +6,568,737 +41,081,424 +Cash flows from investing activities +Purchases of property and equipment +( 1,427,512 ) +( 669,463 ) +Proceeds from maturities of marketable investment securities +11,255,266 +3,080,180 +Purchases of marketable securities +( 67,995,926 ) +- +Investment in joint venture +- +491,739 +Business combinations, net of cash acquired +- +1,196,243 +Net cash (used in) provided by investing activities +( 58,168,172 ) +4,098,699 +Cash flows from financing activities +Proceeds from exercise of options and warrants +177,870 +450,398 +Repurchases of common stock +( 14,211,866 ) +- +Net cash (used in) provided by financing activities +( 14,033,996 ) +450,398 +Net increase in cash and cash equivalents +( 65,633,431 ) +45,630,521 +Cash and cash equivalents at beginning of period +88,607,234 +42,976,713 +Cash and cash equivalents at end of period +$ 22,973,803 +$ 88,607,234 +Supplemental disclosure of cash flow information +Interest paid +$ - +$ - +Income taxes paid +$ 4,498,742 +$ 5,403,769 +Supplemental disclosure of non-cash investing and financing transactions +Inventory moved to property, plant and equipment +$ 218,906 +$ 285,659 +Right-of-use assets obtained in exchange for new operating lease liabilities +$ 681,327 +$ - +Business acquisition measurement period adjustments +$ 1,593 +$ - +Fair value of common stock issued as consideration for business acquisitions +$ +480,776 +$ 25,160,223 +Fair value of contingent common stock issued as consideration for business acquisitions +$ +199,359 +$ 10,432,641 +See +accompanying notes to consolidated financial statements. +38 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS +YEARS +ENDED DECEMBER 31, 2022 AND 2021 +Note +1 – Overview and Basis of Presentation +Description +of Business +Co-Diagnostics, +Inc., a Utah corporation (the “Company” or “CODX”), is developing robust and innovative molecular tools for detection +of infectious diseases, liquid biopsy for cancer screening, and agricultural applications. The Company develops, manufactures, and sells +reagents used for diagnostic tests that function via the detection and/or analysis of nucleic acid molecules (DNA or RNA), including +robust and innovative molecular tools for detection of infectious diseases, liquid biopsy for cancer screening, and agricultural applications. +In connection with the sale of our tests we may sell diagnostic equipment from other manufacturers as self-contained lab systems. +Use +of Estimates +The +preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates +and assumptions that affect the amounts reported in the financial statements and the accompanying notes. Such estimates include receivables +and other long-lived assets, legal and regulatory contingencies, income taxes, share based arrangements, and others. These estimates +and assumptions are based on management’s best estimates and judgments. Actual amounts and results could differ from those estimates. +Basis +of Presentation +The +accompanying audited consolidated financial statements of Co-Diagnostics, Inc. and its wholly owned subsidiaries have been prepared to +reflect the financial position, results of operations and cash flows of the Company and have been prepared in accordance with accounting +principles generally accepted in the United States of America (“GAAP”). All intercompany balances and transactions have been +eliminated. +Note +2 – Summary of Significant Accounting Policies +Cash +and Cash Equivalents +Cash +and cash equivalents consist of cash on hand, money market funds and highly liquid investments with an original maturity date of 90 days +or less from the date of purchase. The fair value of cash equivalents approximated their carrying value as of December 31, 2022 and December +31, 2021. The Company has its cash and cash equivalents with a large creditworthy financial institution +and the balance exceeded federally insured limits. The Company has not experienced any losses in such accounts, and management believes +the Company is not exposed to any significant credit risk on cash and cash equivalents. +39 +Marketable +Investment Securities +The +Company’s marketable investment securities are comprised of investments in certificates of deposit and U.S. Treasury bills and +notes. The Company designates investments in debt securities as available-for-sale. Available-for-sale debt securities with original +maturities of three months or less from the date of purchase are classified within cash and cash equivalents. Available-for-sale debt +securities with original maturities longer than three months are available to fund current operations and are classified as marketable +investment securities, within current assets on the consolidated balance sheets. The Company may sell these securities at any time for +use in its current operations or for other purposes, even prior to maturity. Available-for-sale debt securities are reported at fair +value with the related unrealized gains and losses included in accumulated other comprehensive income (loss), a component of stockholders’ +equity, net of tax. Realized gains and losses on the sale of marketable securities are determined using the average cost method on a +first-in, first-out basis and recorded in total other income (expense), net in the condensed consolidated statements of operations and +comprehensive income. +The +available-for-sale debt securities are subject to a periodic impairment review. For investments in an unrealized loss position, the Company +writes down the amortized cost basis of the investment if it is more likely than not that the Company will be required or will intend +to sell the investment before recovery of its amortized cost basis. For investments not likely to be sold before recovery of the amortized +cost basis, the Company determines whether a credit loss exists by considering information about the collectability of the instrument, +current market conditions, and reasonable and supportable forecasts of economic conditions. The Company recognizes an allowance for credit +losses up to the amount of the unrealized loss when appropriate. Allowances for credit losses and write-downs are recognized in total +other income (expense), net, and unrealized losses not related to credit losses are recognized in accumulated other comprehensive income +(loss). There are no allowances for credit losses recorded for the periods presented. +Accounts +Receivable +Trade +accounts receivable are recorded at the invoiced amount (net of allowance) and do not bear interest. The Company maintains an allowance +for doubtful accounts for amounts the Company does not expect to collect. In establishing the required allowance, management considers +historical losses, current market condition, customers’ financial condition, the age of receivables, and current payment patterns. +Account balances are written off against the allowance once the receivable is deemed uncollectible. Recoveries of trade receivables previously +written off are recorded when collected. At December 31, 2022 total accounts receivable was $ 6,552,249 with an allowance for uncollectable +accounts of $ 3,098,526 resulting in a net amount of $ 3,453,723 . At December 31, 2021 total accounts receivable was $ 21,508,779 with an +allowance for uncollectable accounts of $ 669,597 resulting in a net amount of $ 20,839,182 . +Equity-Method +Investments +Our +equity method investments are initially recorded at cost and are included in other long-term assets in the accompanying consolidated +balance sheet. We adjust the carrying value of our investment based on our share of the earnings or losses in the periods which they +are reported by the investee until the carrying amount is zero. The earnings or losses are included in other income (expense) in the +accompanying consolidated statements of operations. +Inventory +Inventory +is stated at the lower of cost or net-realizable value. Inventory cost is determined on a first-in first-out basis that approximates +average cost in accordance with ASC 330-10-30-12. At December 31, 2022, the Company had $ 5,310,473 in inventory, of which $ 1,327,264 +was finished goods and $ 3,983,209 was raw materials. At December 31, 2021, the Company had $ 2,004,169 in inventory, of which $ 983,088 +was finished goods and $ 1,021,081 was raw materials. The Company establishes reserves to reduce low-moving, obsolete, or unusable inventories +to their estimated useful or scrap values. +40 +Goodwill +and Intangible Assets +Goodwill +represents the excess of the purchase price and related costs over the value assigned to net tangible and identifiable intangible assets +acquired in business combinations. Goodwill and indefinite-lived intangible assets are not amortized, but rather tested for impairment +at least annually on December 31, or more often if and when circumstances indicate that the carrying value may not be recoverable. Finite-lived +intangible assets are amortized over their useful lives. +During +the year ended December 31, 2022, the Company recognized impairment charges related to goodwill of $ 15,388,546 . +Long-lived +Assets +Long-lived +assets, such as property and equipment, are stated at cost less accumulated depreciation and amortization. Depreciation is provided using +the straight-line method over the estimated useful lives of the property, generally from three to five years. Repairs and maintenance +costs are expensed as incurred except when such repairs significantly add to the useful life or productive capacity of the asset, in +which case the repairs are capitalized. +The +Company reviews its long-lived assets, including property and equipment, finite-lived intangible assets, and ROU assets, for impairment +whenever an event or change in facts and circumstances indicates that their carrying amounts may not be recoverable. Recoverability of +these assets is measured by comparing the carrying amount to the estimated undiscounted future cash flows expected to be generated. If +the carrying amount exceeds the undiscounted cash flows, the assets are determined to be impaired and an impairment charge is recognized +as the amount by which the carrying amount exceeds fair value. +Business +Combinations +We +estimate the fair value of assets acquired and liabilities assumed in a business combination. Goodwill as of the acquisition date is +measured as the excess of consideration transferred over the net of the acquisition date fair values of the assets acquired and the liabilities +assumed. Such valuations require management to make significant estimates and assumptions, especially with respect to intangible assets. +Management’s estimates of fair value are based upon assumptions believed to be reasonable, but which are inherently uncertain and +unpredictable, and as a result, actual results may differ from estimates. +Revenue +Recognition +The +Company generates revenue from product sales and license sales. The Company recognizes revenue when all of the following criteria are +satisfied: (i) identification of the promised goods or services in the contract; (ii) determination of whether the promised goods or +services are performance obligations, including whether they are distinct in the context of the contract; (iii) measurement of the transaction +price, including the constraint on variable consideration; (iv) allocation of the transaction price to the performance obligations; and +(v) recognition of revenue when, or as the Company satisfies each performance obligation. Based on the criteria above, the Company typically +recognizes revenue upon delivery. +The +Company constrains revenue by giving consideration to factors that could otherwise lead to a probable reversal of revenue. The Company +records any payments received from customers prior to the Company fulfilling its performance obligation(s) as deferred revenue. +Deferred +Revenue +Deferred +revenue primarily consists of payments received from customers prior to the Company fulfilling its performance obligation of providing +the product. When this occurs, the Company records a contract liability as deferred revenue. Deferred revenue is recognized as revenue +as the related performance obligations are satisfied. +41 +Research +and Development +Research +and development costs are expensed when incurred. The Company expensed $ 17,438,098 and $ 14,961,916 of research and development costs +for the years ended December 31, 2022 and 2021, respectively. +Stock-based +Compensation +The +Company has granted stock-based awards, including restricted stock, stock options, stock warrants and restricted stock units (“RSUs”), +to its employees, certain consultants and members of its board of directors. The Company records stock-based compensation based on the +grant date fair value of the awards and recognizes the fair value of those awards as expense using the straight-line method over the +requisite service period of the award. The Company estimates the grant date fair value of stock options using the Black-Scholes option-pricing +model. When an award is forfeited prior to the vesting date, the Company recognizes an adjustment +for the previously recognized expense in the period of the forfeiture. +Income +Taxes +The +Company accounts for income taxes in accordance with the liability method of accounting for income taxes. Under this method, d eferred +income tax assets and deferred income tax liabilities represent the tax effect of temporary differences between financial reporting and +tax reporting measured at enacted tax rates in effect for the year in which the differences are expected to reverse. The Company recognizes +only the impact of tax positions that, based on their technical merits, are more likely than not to be sustained upon an audit by the +taxing authority. +Valuation +allowances are provided when it is more-likely-than-not that some or all of the deferred income tax assets may not be realized. In assessing +the need for a valuation allowance, the Company has considered its historical levels of income, expectations of future taxable income +and ongoing tax planning strategies. +Developing +the provision for income taxes, including the effective tax rate and analysis of potential tax exposure items, if any, requires +significant judgment and expertise in federal and state income tax laws, regulations and strategies, including the determination of +deferred income tax assets and liabilities and any estimated valuation allowances deemed necessary to value deferred income tax +assets. Judgments and tax strategies are subject to audit by various taxing authorities. The Company has uncertain income tax +positions in the consolidated financial statements, and adverse determinations by these taxing authorities could have a material +adverse effect on the consolidated financial positions, result of operations, or cash flows. +Net +Income per Share +Basic +net income or loss per common share is computed by dividing net income or loss applicable to common shareholders by the weighted average +number of shares outstanding during each period. +Diluted +net income or loss per share is computed by dividing net income or loss attributable to common stockholders by the weighted-average number +of shares of common stock outstanding during the period increased by common shares that could be issued upon conversion or exercise of +other outstanding securities to the extent those additional common shares would be dilutive. The dilutive effect of potentially dilutive +securities is reflected in diluted net income or loss per share by application of the treasury stock method. During periods when the +Company is in a net loss position, basic net loss per share is the same as diluted net loss per share as the effects of potentially dilutive +securities are anti-dilutive. +Comprehensive +Income +Comprehensive +income is comprised of unrealized gains and losses on marketable securities, net of income taxes. +Concentrations +Risk and Significant Customers +The +Company had certain customers which are each responsible for generating 10 % or more of the total revenue for the years ended December +31, 2022 and 2021. One customer accounted for approximately 37 % and two customers together accounted for approximately 48 % of total revenue +for the years ended December 31, 2022 and 2021, respectively. +42 +Three +customers accounted for more than 10 % of accounts receivable, and two customers each accounted for more than 10 % of accounts receivable, +at December 31, 2022 and 2021, respectively. These customers together accounted for approximately 61 % and 66 % of accounts receivable +at December 31, 2022 and 2021, respectively. +Recently +Issued Accounting Standards +From +time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”) that are adopted +by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, +which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption. +In +June 2016, the FASB issued ASU No. 2016-13, Financial Instruments-Credit Losses (Topic 326) (“ASU 2016-13”), which requires +the measurement and recognition of expected credit losses for certain financial instruments, which includes the Company’s accounts +receivable. ASU 2016-13 replaces the existing incurred loss impairment model with an expected loss methodology, which will result in +more timely recognition of credit losses. The Company adopted ASU 2016-13 on January 1, 2022. The adoption did not have an impact on +the Company’s financial statements. +In +February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which requires a lessee to recognize +most leases on the balance sheet as lease liabilities with corresponding right-of-use assets. The objective of ASU 2016-02 is to increase +transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing +key information about leasing arrangements. The recognized lease liabilities and lease assets represent the obligation to make payments +and the right to use or control the use of a specified asset for the lease term, respectively. +On +January 1, 2022, the Company adopted Topic 842 using the modified retrospective approach with the effective date as the date of +initial application. Consequently, results for the year ended December 31, 2022 are presented under Topic +842. No prior period amounts were adjusted and continue to be reported in accordance with previous lease guidance, ASC Topic 840, +Leases. The Company elected the practical expedients available under the provisions of the new standard, including not reassessing +whether expired or existing contracts are or contain leases; not reassessing the classification of expired or existing leases; and +not reassessing the initial direct cost for any existing leases. Upon adoption, the Company recognized an operating lease liability +of $ 626,699 +and a corresponding operating right-of-use asset of $ 681,327 . +43 +Note +3 - Cash, Cash Equivalents, and Financial Instruments +The +following table shows the Company’s cash, cash equivalents, and marketable investment securities by significant investment category +as of December 31, 2022: +Schedule +of Cash, Cash Equivalents, and Marketable Investment Securities +December 31, 2022 +Adjusted Cost +Allowance for Credit Losses +Total Unrealized Gains / (Losses) +Fair Value +Cash and Cash Equivalents +Marketable Securities +Cash +$ 12,834,444 +$ - +$ - +$ 12,834,444 +$ 12,834,444 +$ - +Level 1: +Money market funds +146,359 +- +- +146,359 +146,359 +- +Subtotal +146,359 +- +- +146,359 +146,359 +- +Level 2: +U.S. treasury securities +67,892,825 +- +389,241 +68,282,066 +9,993,000 +58,289,066 +Subtotal +67,892,825 +- +389,241 +68,282,066 +9,993,000 +58,289,066 +Total +$ 80,873,628 +$ - +$ 389,241 +$ 81,262,869 +$ 22,973,803 +$ 58,289,066 +Marketable +investment securities held as of December 31, 2022 mature over the next 12 months. +Note +4 – Business Combinations +On +December 31, 2021, the Company completed its acquisitions of Advanced Conceptions, Inc. (“ACI”) and Idaho Molecular, Inc. (“IdMo”), which were related +entities developing, with the Company, an at-home/point-of-care medical diagnostic device. Upon the completion of the acquisition, +all outstanding ACI and IdMo common stock was initially exchanged for approximately 3.2 +million shares of the Company’s common stock and contingent consideration that includes up to approximately 1.4 +million shares and approximately 456,000 +warrants to purchase shares of the Company’s common stock. The contingent consideration is based on the achievement of certain +milestones, which include regulatory approval for identified products, as well as production and net revenue targets. Upon the +completion of the acquisition, both ACI and IdMo became 100 % +wholly-owned subsidiaries of the Company. +The +fair value of assets acquired and liabilities assumed was based on a preliminary valuation, with estimates and assumptions subject to +change within the measurement period. During 2022, the Company finalized negotiations that were ongoing as of December 31, 2021 with +one remaining shareholder of ACI, which resulted in an increase to the purchase consideration of $ 580,135 . Additionally, there was an +increase of $ 101,593 in the estimated tax liabilities that resulted from the acquisition. Due to the change in purchase consideration +and estimated tax liabilities, a measurement period adjustment was recorded, resulting in an increase to goodwill of $ 681,728 . +Following +the resolution with the remaining shareholder, the total number of shares exchanged as purchase consideration was approximately 3.3 million +shares. Additionally, the updated purchase consideration includes contingent consideration of up to approximately 1.4 million shares +and 465,000 warrants to purchase shares of the Company’s common stock. +In +addition, the adjustments to the provisional purchase consideration amount resulted in an increase in the gain on remeasurement of acquisition +contingencies of $ 78,617 . +44 +The +total purchase consideration, including adjustment during the measurement period, was allocated to the assets acquired and liabilities +assumed as set forth below: +Schedule +of Assets and Liabilities assumed +Amounts Recognized as of Acquisition Date (as previously reported) +Measurement Period Adjustments +Amounts Recognized as of Acquisition Date (as adjusted) +Purchase Consideration +Fair value of common shares issued +$ 25,160,223 +$ 480,776 +$ 25,640,999 +Payable to shareholder +100,000 +( 100,000 ) +- +Fair value of contingent shares +8,684,669 +165,957 +8,850,626 +Fair value of contingent warrants +1,747,972 +33,402 +1,781,374 +Total fair value of consideration transferred +$ 35,692,864 +$ 580,135 +$ 36,272,999 +Identifiable assets acquired and liabilities assumed +Cash +$ 1,196,243 +$ - +$ 1,196,243 +Accounts receivable +31,170 +- +31,170 +Prepaid expenses and other current assets +70,321 +- +70,321 +Property and equipment +408,173 +- +408,173 +Technology - In-process research and development +26,101,000 +- +26,101,000 +Non-competition agreements +1,094,000 +- +1,094,000 +Accounts payable and accrued other expenses +( 1,069,274 ) +( 101,593 ) +( 1,170,867 ) +Deferred tax liability +( 6,845,587 ) +- +( 6,845,587 ) +Total identifiable net assets +20,986,046 +( 101,593 ) +20,884,453 +Goodwill +14,706,818 +681,728 +15,388,546 +Total +$ 35,692,864 +$ 580,135 +$ 36,272,999 +The +in-process research and development is considered an indefinite-lived intangible until the completion or abandonment of the research +and development activities. The non-competition agreements are being amortized over a range of 1.5 to 3 years. +Note +5 – Fair Value Measurements +The +Company measures and records certain financial assets and liabilities at fair value on a recurring basis. Fair value is based on the +price that would be received from selling an asset or paid to transfer a liability in an orderly transaction between market participants +at the measurement date. +The +following three levels of inputs are used to measure the fair value of financial assets and liabilities: +Level +1: Quoted market prices in active markets for identical assets or liabilities. +Level +2: Observable market-based inputs or unobservable inputs that are corroborated by market data. +Level +3: Unobservable inputs that are not corroborated by market data. +45 +The +following table summarizes the assets and liabilities measured at fair value on a recurring basis as of December 31, 2022 and December +31, 2021, by level within the fair value hierarchy: +Schedule of Fair Value Assets and Liabilities +(Level 1) +(Level 2) +(Level 3) +Total +December 31, 2022 +(Level 1) +(Level 2) +(Level 3) +Total +Assets: +Cash equivalents +$ - +$ 10,179,667 +$ - +$ 10,179,667 +Marketable securities (U.S. treasury bills and notes) +- +58,289,066 +- +58,289,066 +Total assets measured at fair value +$ - +$ 68,468,733 +$ - +$ 68,468,733 +Liabilities: +Contingent consideration - common stock +$ - +$ - +$ 2,499,147 +$ 2,499,147 +Contingent consideration - warrants +- +- +233,209 +233,209 +Total liabilities measured at fair value +$ - +$ - +$ 2,732,356 +$ 2,732,356 +(Level 1) +(Level 2) +(Level 3) +Total +December 31, 2021 +(Level 1) +(Level 2) +(Level 3) +Total +Assets: +Marketable securities (certificates of deposit) +$ - +$ 1,255,266 +$ - +$ 1,255,266 +Total assets measured at fair value +$ - +$ 1,255,266 +$ - +$ 1,255,266 +Liabilities: +Contingent consideration - common stock +$ - +$ - +$ 8,684,669 +$ 8,684,669 +Contingent consideration - warrants +- +- +1,747,972 +1,747,972 +Total liabilities measured at fair value +$ - +$ - +$ 10,432,641 +$ 10,432,641 +The +Company’s financial instruments that are measured at fair value on a recurring basis consist of certificates of deposit and U.S. +treasury bills and notes as of December 31, 2021 and 2022, respectively. +In +connection with the acquisitions of IdMo and ACI on December 31, 2021, the Company recorded a liability for contingent consideration +in the form of shares of common stock and warrants to purchase common stock. The fair value of contingent consideration is calculated +using a discounted probability weighted valuation model. Discount rates used in such calculations are a significant assumption that are +not observed in the market, and therefore, the resulting fair value represents a Level 3 measurement. +The +changes for Level 3 items measured at fair value on a recurring basis are as follows: +Schedule of Changes in Fair Value Measurement +Fair value as of December 31, 2021 +$ 10,432,641 +Change in contingent purchase consideration for measurement period adjustments +199,359 +Change in fair value of contingent consideration issued for business acquisitions +( 7,899,644 ) +Fair value as of December 31, 2022 +$ 2,732,356 +46 +The +fair value of the contingent consideration is based on the fair value of the contingent consideration-common stock and contingent consideration-warrants. +The fair value of the contingent consideration-common stock is equal to the probability-adjusted value of the Company’s common +stock as of the valuation date. The fair value of the contingent consideration-warrants is equal to the probability adjusted value of +a call option with terms consistent with the terms of the warrants as of the valuation date. Prior to the probability adjustments, the +warrants were valued based on the following inputs: +Schedule of Contingent Consideration Common Stock and Warrants +December 31, 2022 +December 31, 2021 +Stock price +$ 2.52 +$ 8.93 +Strike price +$ 9.13 +$ 9.13 +Volatility +75.00 % +80.00 % +Risk-free rate +4.10 % +1.30 % +Expected term +4.0 +5.0 +In +order to calculate the probability-adjusted value of the contingent consideration-common stock and contingent +consideration-warrants, the Company estimated the probability as of the valuation date of achieving certain milestones, which +include regulatory approval for identified products, as well as production and net revenue targets. The probability of achieving the +milestone related to net revenues was estimated as of the acquisition date using a Monte Carlo simulation valuation model. +Significant inputs other than the fair value assumptions noted above were consistent as of the valuation date. The unobservable +significant inputs to the valuation model were as follows: +December 31, 2022 +December 31, 2021 +Stock price +$ +2.52 +$ 8.93 +Risk-free rate +4.10 +% +1.30 % +Expected term +4.0 +5.0 +Weighted-average cost of capital +27.00 +% +27.00 % +Revenue discount rate +9.50 +% +9.50 % +Equity volatility +75.00 +% +80.00 % +Asset volatility +80.00 +% +80.00 % +Revenue volatility +30.00 +% +30.00 % +Fair +Value of Other Financial Instruments +The +carrying amounts of certain financial instruments, including cash held in banks, accounts receivable, notes receivable, accounts payable, +accrued liabilities, and other liabilities approximate fair value due to their short-term maturities and are excluded from the fair value +tables above. +47 +Note +6 – Property and Equipment +Property +and equipment, net consisted of the following: +Schedule +of Property and Equipment +Estimated Useful Lives +December 31, +in years +2022 +2021 +Lab equipment +3 - 5 +$ 3,574,730 +$ 2,476,813 +Leasehold improvements +0 - 3 +224,957 +3,157 +Office equipment, furniture and other +2 - 5 +112,044 +75,401 +Less accumulated depreciation and amortization +( 1,372,248 ) +( 622,155 ) +Fixed assets, net +$ 2,539,483 +$ 1,933,216 +Note +7 - Goodwill and Intangible Assets +Goodwill +Goodwill +represents the excess of purchase price and related costs over the value assigned to net tangible and identifiable intangible assets +acquired in business combinations. The following table presents the changes in the carrying amount of goodwill for the year ended December +31, 2022: +Schedule +of Goodwill +Balance as of December 31, 2021 +$ 14,706,818 +Measurement period adjustments +681,728 +Goodwill impairment charges +( 15,388,546 ) +Balance as of December 31, 2022 +$ - +The +Company assesses goodwill for impairment at the reporting unit level on an annual basis, or whenever events or changes in circumstances +occur that indicate that the fair value of a reporting unit is below its carrying amount. The Company estimates the fair value of its +reporting unit by using forecasts of discounted future cash flows and peer market multiples. If the fair value is less than the carrying +value, impairment will be recognized in the amount by which the carrying value exceeds the fair value. The Company performed a qualitative +and quantitative goodwill impairment assessment as of December 31, 2022. Based on the impairment assessment performed the Company concluded +that it was more likely than not that the fair value of the Company’s reporting unit was less than it’s carrying amount. +Accordingly, the Company recorded an impairment charge to reduce the carrying value of goodwill to $ 0 . +Intangible +Assets, Net +Intangible +assets, net consisted of the following: +Schedule of Intangible Assets, Net +December 31, 2022 +Weighted-Average +Gross +Net +Useful Life (1) +Carrying +Accumulated +Carrying +(in Years) +Amount +Amortization +Amount +In-process research and development +Indefinite +$ 26,101,000 +$ - +$ 26,101,000 +Non-competition agreements +2.7 +1,094,000 +( 426,667 ) +667,333 +Total intangible assets +$ 27,195,000 +$ ( 426,667 +) +$ 26,768,333 +48 +December 31, 2021 +Weighted-Average +Gross +Net +Useful Life (1) +Carrying +Accumulated +Carrying +(in Years) +Amount +Amortization +Amount +In-process research and development +Indefinite +$ 26,101,000 +$ - +$ 26,101,000 +Non-competition agreements +2.7 +1,094,000 +- +1,094,000 +Total intangible assets +$ 27,195,000 +$ - +$ 27,195,000 +The +expected future annual amortization expense of the Company’s intangible assets held as of December 31, 2022 is as follows: +Schedule +of Future Amortization Expense +Year Ending December 31, +Amortization Expense +2023 +364,668 +2024 +302,665 +Total +$ 667,333 +Note +8 - Accrued Expenses +Accrued +expenses consisted of the following: +Schedule of Accrued Expenses +December 31, 2022 +December 31, 2021 +Payroll liabilities +$ 428,354 +$ 2,455,694 +Distributor commissions +159,725 +509,500 +Other accrued liabilities +346,368 +894,458 +Total accrued expenses +$ 934,447 +$ 3,859,652 +49 +Note +9 – Revenue +The +following table sets forth revenue by geographic area: +Summary of Revenue by Geographic Area +Years Ended December 31, +2022 +2021 +United States +$ 24,671,554 +$ 52,185,812 +Rest of World +9,546,655 +45,699,791 +Total +$ 34,218,209 +$ 97,885,603 +Percentage of revenue by area: +United States +72 % +53 % +Rest of World +28 % +47 % +Deferred +Revenue +Changes +in the Company’s deferred revenue balance for the years ended December 31, 2022 and 2021 were as follows: +Schedule of Deferred Revenue +Balance as of December 31, 2020 +305,307 +Revenue recognized included in deferred revenue balance at the beginning of the period +( 256,110 ) +Increase due to prepayments from customers +79,213 +Increase due to note receivable +150,000 +Decrease due to refunds to customers and application to open balances +( 128,410 ) +Balance as of December 31, 2021 +$ 150,000 +Revenue recognized included in deferred revenue balance at the beginning of the period +( 150,000 ) +Balance as of December 31, 2022 +$ - +Note +10 – Earnings per Share +The +following table reconciles the numerator and the denominator used to calculate basic and diluted earnings per share for years ended December +31, 2022 and 2021: +Schedule of Basic and Diluted Earnings Per Share +2022 +2021 +Years Ended December 31, +2022 +2021 +Numerator +Net income, as reported +$ ( 14,238,249 ) +$ 36,658,564 +Denominator +Weighted average shares, basic +31,479,028 +28,874,555 +Dilutive effect of stock options, warrants and RSUs +- +1,029,131 +Shares used to compute diluted earnings per share +31,479,028 +29,903,686 +Basic earnings per share +$ ( 0.45 ) +$ 1.27 +Diluted earnings per share +$ ( 0.45 ) +$ 1.23 +50 +For +the year ended December 31, 2021, potentially dilutive securities of 154,644 were excluded from the computation of diluted earnings per +share because the effect would have been anti-dilutive. The computation of diluted earnings per share for the years ended December 31, +2022 and December 31, 2021 also excludes the approximately 1.4 million shares of common stock and approximately 465,000 warrants to purchase +shares of common stock mentioned in Note 4 that are contingent upon the achievement of certain milestones. +As +a result of incurring a net loss for the year ended December 31, 2022, no potentially dilutive securities are included in the calculation +of diluted earnings per share because such effect would be anti-dilutive. The Company had potentially dilutive securities as of December +31, 2022, consisting of: (i) 1,443,238 restricted stock units and (ii) 50,000 options. +Note +11 – Stock-Based Compensation +Stock +Incentive Plans +The +Company’s board of directors adopted, and shareholders approved, the Co-Diagnostics, Inc. Amended and Restated 2015 Long Term Incentive +Plan (the “Incentive Plan”) providing for the issuance of stock-based incentive awards to employees, officers, consultants, +directors and independent contractors. On August 31, 2022 the shareholders approved an increase in the number of awards available for +issuance under the Incentive Plan to an aggregate of 12,000,000 shares of common stock. The number of awards available for issuance under +the Incentive Plan was 6,210,790 at December 31, 2022. +Stock +Options +The +following table summarizes option activity during the years ended December 31, 2022 and 2021: +Schedule of Option Activity +Number of Options +Weighted Average Exercise Price +Weighted Average Fair Value +Weighted Average Remaining Contractual Life (Years) +Outstanding at December 31, 2020 +1,300,588 +$ 2.44 +$ 1.24 +Granted +- +- +- +Expired +- +- +- +Forfeited/Cancelled +- +- +- +Exercised +( 189,225 ) +2.38 +1.12 +Outstanding at December 31, 2021 +1,111,363 +$ 2.12 +$ 1.31 +Granted +- +- +- +Expired +- +- +- +Forfeited/Cancelled +- +- +- +Exercised +( 70,791 ) +1.10 +0.51 +Outstanding at December 31, 2022 +1,040,572 +$ 2.19 +$ 1.37 +5.88 +Exercisable at December 31, 2022 +1,040,572 +$ 2.19 +$ 1.37 +5.88 +51 +The +total intrinsic value of options exercised during the years ended December 31, 2022 and 2021 was approximately $ 0.4 million and $ 1.3 +million, respectively. The aggregate intrinsic value of outstanding options at December 31, 2022 and 2021 was approximately $ 0.8 million +and $ 7.6 million, respectively. As of December 31, 2022, there were no unvested options and no unrecognized stock-based compensation +expense related to options. +Restricted +Stock Units +The +grant date fair value of RSUs granted is determined using the closing market price of the Company’s common stock on the grant date +with the associated compensation expense amortized over the vesting period of the awards. The following table sets forth the outstanding +RSUs and related activity for the years ended December 31, 2022 and 2021: +Schedule of Outstanding Restricted Stock Units and Related Activity +Number of RSUs +Weighted Average Grant Date Fair Value +Unvested at December 31, 2020 +522,500 +$ 10.49 +Granted +1,217,500 +9.76 +Vested +( 438,502 ) +10.10 +Forfeited/Cancelled +( 34,083 ) +9.91 +Unvested at December 31, 2021 +1,267,415 +$ 9.94 +Granted +1,925,476 +5.66 +Vested +( 725,166 ) +8.66 +Forfeited/Cancelled +( 41,000 ) +8.31 +Unvested at December 31, 2022 +2,426,725 +$ 7.06 +As +of December 31, 2022, there was $ 14.7 million of unrecognized stock-based compensation expense related to outstanding RSUs which is expected +to be recognized over a weighted-average period of 2.2 years. +Warrants +The +Company has issued warrants related to financings, acquisitions and as compensation to third parties for services provided. The Company +estimates the fair value of issued warrants on the date of issuance as determined using a Black-Scholes pricing model. The Company amortizes +the fair value of issued warrants using a vesting schedule based on the terms and conditions of each warrant if granted for services. +52 +The +following table summarizes warrant activity during the years ended December 31, 2022 and 2021: +Schedule of Warrant Activity +Number of Warrants +Weighted Average Exercise Price +Weighted Average Fair Value +Weighted Average Remaining Contractual Life (Years) +Outstanding at December 31, 2020 +70,000 +$ 1.83 +$ 5.21 +3.3 +Granted +456,281 +9.13 +3.83 +Expired +- +- +- +Forfeited/Cancelled +- +- +- +Exercised +- +- +- +Outstanding at December 31, 2021 +526,281 +$ 8.15 +$ 4.01 +4.7 +Issued for adjustments to contingent purchase consideration +8,719 +9.13 +1.88 +Granted +- +- +- +Expired +- +- +- +Forfeited/Cancelled +- +- +- +Exercised +( 50,000 ) +2.00 +1.22 +Outstanding at December 31, 2022 +485,000 +$ 8.81 +$ 2.43 +4.0 +The +intrinsic value of warrants exercised during the years ended December 31, 2022 and 2021 was $ 0.3 million and $ 0.0 million, respectively. +The aggregate intrinsic value of outstanding warrants at December 31, 2022 was approximately $ 22,000 . +20,000 +warrants are exercisable at December 31, 2022. As discussed in Note 3 and Note 4, approximately 456,000 warrants to purchase shares of +the Company’s common stock were issued in connection with the acquisition of ACI and IdMo. The ability to exercise the warrants +is contingent upon the achievement of certain development and revenue milestones on or before January 1, 2027. There was no unrecognized +stock-based compensation expense related to warrants. +See +Note 5 for additional information regarding the fair value calculation of the warrants issued during the year ended December 31, 2021. +Stock +Issued for Services +The +Company has issued restricted stock to third parties for services provided. The grant date fair value of the restricted stock granted +is determined using the closing market price of the Company’s common stock on the grant date with the associated compensation expense +amortized over the vesting period of the stock awards. The Company issued 0 and 5,548 shares of restricted stock for services during +the years ended December 31, 2022 and 2021, respectively, and there was no unrecognized stock-based compensation expense related to restricted +stock issued. +53 +Stock-Based +Compensation Expense +The +Company recognized stock-based compensation expense related to the types of awards discussed above as follows: +Schedule of Recognized +Stock-based Compensation Expense +2022 +2021 +Years Ended December 31, +2022 +2021 +Options +$ 78,115 +$ 292,754 +Restricted stock units +7,465,108 +5,164,750 +Stock +- +51,900 +Total stock-based compensation expense +$ 7,543,223 +$ 5,509,404 +Note +12 – Income Taxes +The +components of the provision for income taxes consists of the following for the years ended December 31, 2022 and 2021: +Schedule +of Components Income Tax Provision +2022 +2021 +Year Ended December 31, +2022 +2021 +Current: +Federal +$ 563,821 +$ 6,092,730 +State +( 266,248 ) +886,173 +Total current +$ 297,573 +$ 6,978,903 +Deferred: +Federal +( 3,945,090 ) +1,394,686 +State +( 961,468 ) +603,642 +Total deferred +( 4,906,558 ) +1,998,328 +Total income tax (benefit) expense +$ ( 4,608,985 ) +$ 8,977,231 +A +reconciliation of income tax expense at the statutory federal income tax rate and income taxes as reflected in the financial statements +is as follows: +Schedule +of Benefit from Income Taxes and Effective Tax Rates +2022 +2021 +Year Ended December 31, +2022 +2021 +Federal income tax expense at statutory rate +21.0 % +21.0 % +State income tax expense, net of federal tax benefit +4.8 % +3.9 % +Permanent differences: +- Foreign derived intangible income deduction +1.4 % +- 3.5 % +- Stock based compensation +- 3.6 % +0.2 % +- Contingent consideration remeasurement +8.8 % +0.0 % +- Goodwill impairment +- 17.1 % +0.0 % +- Other permanent differences +- 0.6 % +0.3 % +Research and development credits +11.1 % +- 2.6 % +Change in uncertain tax positions +- 2.1 % +1.4 % +Change in valuation allowance +0.0 % +0.0 % +Other +0.8 % +- 1.0 % +Effective income tax rate +24.5 % +19.7 % +Net +deferred tax liabilities consist of the following components as of December 31, 2022 and 2021: +Schedule +of Deferred Tax Assets +2022 +2021 +December 31, +2022 +2021 +Deferred tax assets: +Accrued liabilities +$ 98,141 +$ - +Reserves and allowances +765,004 +166,050 +Deferred compensation +566,076 +393,871 +Research and development credits +3,460,159 +- +Lease liability +85,899 +- +UNICAP +168,936 +- +Total deferred tax assets +5,144,215 +559,921 +Deferred tax liabilities: +Property and equipment, net +( 609,261 ) +( 477,542 ) +Intangibles, net +( 6,608,914 ) +( 6,743,972 ) +Prepaids +( 156,053 ) +( 560,093 ) +Right of use asset +( 91,873 ) +- +Other comprehensive income +( 96,101 ) +- +Other +- +( 6,758 ) +Total deferred tax liabilities +( 7,562,202 ) +( 7,788,365 ) +Net deferred tax (liabilities) +( 2,417,987 ) +( 7,228,444 ) +Less valuation allowance +- +- +Net deferred tax (liabilities) +$ ( 2,417,987 ) +$ ( 7,228,444 ) +At +December 31, 2022, the Company had no federal net operating loss carryforwards and no federal research and development credit carryforwards. +At December 31, 2022, the Company had no state net operating loss carryforwards and $ 288,292 of state research and development credit +carryforwards. If unused, the state research credit carryforward will expire in 2036. +54 +ASC +Topic 740-10-05 requires that the impact of a tax position be recognized in the financial statements if that position is more likely +than not of being sustained on audit, based on the technical merits of the position. Our unrecognized tax benefit balances included $ 1,469,577 +at December 31, 2022 and $ 1,067,853 at December 31, 2021 of tax positions that, if recognized, would impact our effective tax rate. The +Company expects no material changes to the liability for unrecognized tax benefits in the next 12 months. Interest and penalties associated +with uncertain tax positions are recorded as a component of income tax expense. A reconciliation of the beginning and ending amount of +unrecognized benefits is as follows: +Schedule +of Unrecognized Tax Benefits +December 31, +2022 +2021 +Unrecognized tax benefits at the beginning of the year +$ 1,067,853 +$ 447,831 +Gross increases - current year tax positions +1,045,590 +770,069 +Gross increases - prior year tax positions +34,035 +- +Gross decreases - prior year tax positions +( 677,901 ) +( 150,047 ) +Unrecognized tax benefits at end of year +$ 1,469,577 +$ 1,067,853 +Interest and penalties in year-end balance +$ 34,035 +$ - +The +Company is subject to taxation in the United States and other state jurisdictions. The tax years from December 31, 2019 through December +31, 2022 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which the Company +is subject. The Company is not currently under examination by any taxing authority. +Note +13 – Commitments and Contingencies +Lease +Obligations +The +Company leases office space under a non-cancellable operating lease and leases cancellable with one month notice. The Company expenses +the cancelable leases in the period incurred in accordance with the practical expedient elected. As such, one lease makes up the entirety +of the right-of-use asset and lease liability disclosed. +For +the year ended December 31, 2022, components of lease expense are summarized as follows: +Schedule +of Lease Expense +Year Ended December, 2022 +Operating lease costs +$ 346,349 +Short-term lease costs +384,902 +Total lease costs +$ 731,251 +Short-term +lease costs under month-to-month lease agreements are paid to related parties. +As +of December 31, 2022, the maturities of the Company’s lease liabilities are as follows: +Schedule +of Maturities on Company Lease Liabilities +Year Ending +December 31, +2023 +$ 303,059 +2024 +50,773 +2025 +- +2026 +- +2027 +- +Thereafter +- +Total lease payments +353,832 +Less: imputed interest +5,915 +Present value of operating lease liabilities +347,917 +Less: current portion +297,209 +Long-term portion +$ 50,708 +55 +Other +information related to operating leases was as follows: +Schedule +of Other Information Related to Operating Lease +Year Ended +December 31, 2022 +Cash paid for operating leases included in operating cash flows +$ 700,821 +Remaining lease term of operating leases +1 year +Discount rate of operating leases +3.1 % +Litigation +Liabilities +for loss contingencies arising from claims, assessments, litigation, fines, and penalties and other sources are recorded when it is probable +that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss contingencies +are expensed as incurred. +The Company is a defendant in two class action claims and three derivative +actions claiming that the Company promulgated false and misleading press releases to increase the price of our stock to improperly +benefit the officers and directors of the Company. The plaintiffs demand compensatory damages sustained as a result of the Company’s +alleged wrongdoing in an amount to be proven at trial. The Company believes these lawsuits are without merit and intends to defend the +cases vigorously. The Company is unable to estimate a range of loss, if any, that could result were there to be an adverse final decision +in these cases. As of the date of this report, the Company does not believe it is probable that these cases will result in an unfavorable +outcome; however, if an unfavorable outcome were to occur in these cases, it is possible that the impact could be material to the Company’s +results of operations in the period(s) in which any such outcome becomes probable and estimable. +Note +14 – Share Repurchase Program +In +March 2022, the Company’s board of directors authorized a share repurchase program that would allow the Company to repurchase up +to $ 30.0 million of CODX common stock. The repurchase program does not obligate the Company to acquire any particular number of common +shares, and the repurchase program may be suspended or discontinued at any time at the Company’s discretion. The timing and amount +of any share repurchases under the share repurchase program will be determined by Co-Diagnostics’ management at its discretion +based on ongoing assessments of the capital needs of the business, the market price of the Company’s common stock, corporate and +regulatory requirements, and general market conditions. +For +accounting purposes, common stock repurchased under the stock repurchase program is recorded based upon the transaction date of the applicable +trade. Such repurchased shares are held in treasury and are presented using the cost method. These shares are not retired and are considered +issued but not outstanding. The following table shows the changes in treasury stock for the periods presented: +Schedule +of Treasury Stock +Year Ended +December 31, 2022 +Balance, beginning of period +- +Repurchases of common stock +3,881,658 +Balance, end of period +3,881,658 +56 +Note +15 – Subsequent Events +None. +ITEM +9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. +None. +ITEM +9A. CONTROLS AND PROCEDURES +Evaluation +of Disclosure Controls and Procedures +We +maintain a set of disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) designed to ensure that information +required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within +the time periods specified in rules and forms adopted by the SEC. Disclosure controls and procedures include, without limitation, controls +and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under +the Exchange Act is accumulated and communicated to the Company’s management, including its principal executive and principal financial +officers, as appropriate to allow timely decisions regarding required disclosure. +Our +management, with the participation of our Chief Executive Officer and our Chief Financial Officer, evaluated the effectiveness of our +disclosure controls and procedures as of December 31, 2022. Based on the evaluation, management has concluded that our disclosure controls +and procedures are effective as of December 31, 2022 to provide reasonable assurance regarding the reliability of +our financial reporting and the preparation of our financial statements for external reporting purposes in accordance with U.S. generally +accepted accounting principles. +Changes +in Internal Control Over Financial Reporting +There +have not been any changes in the Company’s internal control over financial reporting (as such term is defined in Rules 13a- 15(f) +and 15d-15(f) under the Exchange Act) during the fourth quarter of 2022 that have materially affected, or are reasonably likely to materially +affect, the Company’s internal control over financial reporting. +Management’s +Annual Report on Internal Control over Financial Reporting +Our +management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) +under the Exchange Act). Our management, including our Chief Executive Officer and Chief Financial Officer, conducted an evaluation of +the effectiveness of our internal control over financial reporting as of December 31, 2022. In making its evaluation, management used +the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated +Framework (2013). +Based +on this evaluation, management determined that our internal control over financial reporting was effective as of December 31, 2022. +This +Annual Report does not include an attestation report by our independent registered public accounting firm regarding internal control +over financial reporting since we are a non-accelerated filer. Management’s report was not subject to attestation by our registered +public accounting firm pursuant to rules of the SEC that permit non-accelerated filers to provide only management’s report in the +10-K. +57 +Inherent +Limitations on Effectiveness of Controls +Our +management, including our Chief Executive Officer and Chief Financial Officer, believes that our disclosure controls and procedures and +internal control over financial reporting are intended to be designed to provide reasonable assurance of achieving their objectives. +However, our management does not expect that our disclosure controls and procedures or our internal control over financial reporting +will prevent or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, +not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact +that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent +limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of +fraud, if any, have been detected. These inherent limitations include the realities that judgments in decision making can be faulty, +and that breakdowns can occur because of a simple error or mistake. Additionally, controls can be circumvented by the individual acts +of some persons, by collusion of two or more people or by management override of the controls. The design of any system of controls also +is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed +in achieving its stated goals under all potential future conditions; over time, controls may become inadequate because of changes in +conditions, or the degree of compliance with policies or procedures may deteriorate. Because of the inherent limitations in a cost–effective +control system, misstatements due to error or fraud may occur and not be detected. +ITEM +9B. OTHER INFORMATION +None. +ITEM +9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS. +None. +PART +III +ITEM +10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE. +The +following table sets forth the names, ages and positions of our executive officers and directors as of March 16, 2023. The following is information +on the business experience of each director and executive officer now serving and a discussion of the qualifications, attributes and +skills that led to the board of directors’ conclusion that each one is qualified to serve as a director or as an executive officer +as the case may be. Executive officers serve at the discretion of the board of directors. +Name +Age +Position +Dwight Egan +69 +Chief Executive Officer, +President and Chairman of the Board +Brian +Brown +47 +Chief +Financial Officer and Secretary +Eugene Durenard +53 +Director +James Nelson +70 +Director +Richard Serbin +78 +Director +Ted +Murphy +58 +Director +The +following is a brief summary of the background of each of our directors: +Edward +Murphy has been a member of our board of directors since June 2019. Since December 1999, Mr. Murphy has served as a senior +vice president and a partner of Dover Investments Ltd., a private investment firm. Throughout his career, Mr. Murphy’s duties +have included investment analysis of various types of investment projects in real estate and financial services. Currently, Mr. +Murphy serves on the board of directors of several Canadian publicly reporting companies that have interests in various industries. +He has been a Director at Empire Minerals Corporation Inc. since January 2016, at Digicrypts Blockchain Solutions Inc. from June +2011 to November 2022, at Lakefield Marketing Corporation since February 2018, CEO/CFO and Director of Credo Resources Inc. since +September 2019, at the Mosport Park Entertainment Corporation since April 30, 1997, at Essex Oil Ltd. Since July 2021, and at +Darkhorse Technologies Ltd. since November 2021. He served as a Director at Aurquest Resources from May 2003 to December 2017. Mr. +Murphy’s experience in the capital markets outside the United States and his involvement in investment analysis is a benefit +to the board of directors. +58 +Richard +Serbin has been a member of our board of directors since May 2017. Mr. Serbin currently serves as a consultant to many companies +in the healthcare industry. He was the President of Corporate Development and In-House Legal Counsel at Life Science Institute, LLC, +from June 1, 2013 to July 15, 2014. He was appointed to the Advisory Board of Cure Pharmaceutical in January 2017 and has been a Member of Advisory Board at Prime Access, +Inc. since September 2015. Mr. Serbin has been a Director at Rapid Nutrition Plc since November 18, 2014. He served as Director at Viropro +Inc. from May 2013 to June 2014. He was Head of Business Advisory Board at Mazal Plant Pharmaceuticals Inc. from October 2006 to September +2007 and also served as its Member of Business Advisory Board. He served as Chief Executive Officer of Optigenex Inc. from July 2002 +to September 15, 2005 and a director from July 2004 to September 2005. From January 1999 until July 2002 Mr. Serbin served as a consultant +to various pharmaceutical companies. He served as the President of Bradley Pharmaceuticals. He served as Vice President of Corporate +Development at Ortho Pharmaceuticals, a Johnson & Johnson subsidiary, and practiced Patent and FDA law at Revlon Johnson & Johnson +and Schering-Plough. He served as Patent Attorney for Schering Plough Corporation and Chief FDA Counsel for Revlon Corporation and Johnson +and Johnson Corporation. Subsequently, he worked at Revlon Corporation, as its Chief Food, Drug and Cosmetic Counsel. He founded Radius +Scientific Corporation. He was J&J’s Vice President of Corporate Development, and later led a successful public offering venture +based on technology developed at Stanford Medical School. Mr. Serbin spent a large portion of his career focusing on international markets +and clients. While at J&J, Mr. Serbin served on the board of directors of 16 US and international subsidiary companies, including +Ethicon, Ortho, J&J Consumer Products, Pittman-Moore, Mc Neil, and J&J Development Corporation. He worked on multiple international +acquisitions and strategic relationships, and sat on the board of directors of several of its international subsidiaries, including those +in India, Hong Kong, Japan, Taiwan, Germany, and England. Mr. Serbin has a B.S. and a B. Pharmacy from Rutgers University and Rutgers +University College of Pharmacy, a J.D. degree from Seton Hall Law School and a Master’s Degree in Trade Regulations and Law from +NYU Law School. Mr. Serbin’s experience in business, law and medicine and knowledge gained as an advisor to the healthcare industry +is critical to our board of directors as we continue to commercialize our products. +Dwight +Egan serves as our President and Chief Executive Officer and has been an officer and director of the Company since April 2013. Mr. +Egan has been engaged in private investment business from February 1999 to the present. He was a senior executive at Data Broadcasting +Corporation, a leading provider of wireless, real-time financial market data, news and sophisticated fixed- income portfolio analytics +to 27,000 individual and professional investors from 1995 to 1999. He co-founded and served as CEO and Chairman of the Board of Broadcast +International, Inc. from 1984 to 1995, when Data Broadcasting Corporation acquired Broadcast International and created CBS MarketWatch , +a leading financial news site and participated in its initial public offering. Mr. Egan’s prior experience in executive leadership +positions with public companies and working with capital markets qualifies him to serve as our Chairman, President and Chief Executive +Officer. +Eugene +Durenard has been a member of our board of directors since June 2019. Dr. Durenard is the Founder and CEO of Hyperbolic Holdings, +a Swiss-based holding, management consulting and strategy advisory company specialized in healthcare. Dr. Durenard brings investment +and entrepreneurial experience spanning 20 years. For the last 7 years he has been working with family offices on direct investments +and philanthropy focused on life sciences. He serves on the advisory board of several private companies in the biotech and MedTech sectors. +After an initial career in proprietary research and trading at Salomon Brothers and Credit Suisse in London, he co-founded Orion Investment +Management in Bermuda specializing in quantitative asset and liability management for institutions and private clients. He subsequently +sold it to Capital G Bank and co-headed their asset management. Dr. Durenard spent several years establishing personal connections with +representatives of 40+ clusters of life science innovation, families operating healthcare businesses and industry leaders globally. He +regularly visits labs and incubators, meets with leading scientists and innovators in order to keep abreast of current trends and developments. +His advice is based on a thorough analysis that combines in-depth knowledge of science, competitive forces and financial expertise. He +has published several articles in asset-liability management industry magazines as well as the book “Professional Automated Trading +— Theory and Practice” (Wiley 2013). He has a PhD in Mathematics from Harvard University. Dr. Durenard brings a thorough +multi-asset class investment and entrepreneurial experience spanning 25 years to the Company’s board of directors. +59 +James +Nelson has been a member of our board of directors +since June 2019. Mr. Nelson is the retired Chairman and CEO of Sunworks, Inc., a NASDAQ traded +commercial, agriculture, and residential solar Integrator which he helped found in October 2010. Mr. Nelson spent most of his career +working in private equity as a general partner with Peterson Partners and with Millennial Capital Partners. In addition to his investment +and financial responsibilities, he served as CEO of two of his firms’ portfolio companies. Prior to his years in private equity, +Mr. Nelson served as Vice President of Marketing at Banana Republic, where he managed company-wide marketing, as well as the company’s +international expansion initiative. He was also general manager for Banana Republic’s catalog division. He was Vice President of +Marketing and Corporate Development at Saga Corporation, a multi-billion-dollar food service company. Mr. Nelson began his executive +career over 35 years ago at Bain and Company, a business strategy consulting firm, where he managed teams of consultants on four continents. +Mr. Nelson received his MBA from Brigham Young University, where he graduated summa cum laude and was named the Outstanding Master of +Business Administration Graduate. Mr. Nelson’s advice to the board of directors from his experiences as a chief executive officer +and strategic advisor is useful to the board of directors. +The +following is a brief summary of the background of each of our executive officers. +Dwight +Egan - See narrative description above. +Brian +Brown became our Chief Financial Officer in February 2021. From July 2020 until February 2021, Mr. Brown served as the Chief +Financial Officer of A-Core Concrete Cutting, Inc. where his duties included overseeing the company’s accounting and finance +departments, mergers and acquisitions and responsibility for financial forecasting and budgeting. From January 2020 to July 2020, +Mr. Brown was an independent consultant. From August 2019 to December 2019, Mr. Brown served as the Vice President of Accounting, +Treasury and Investor Relations at Sportsman’s Warehouse Holdings, Inc., a public company reporting on Nasdaq Global Select +under the symbol SPWH, where his duties included overseeing the company’s accounting, treasury and investor relations +departments, preparing the company’s annual, quarterly and current reports with the SEC, overseeing all aspects of the +company’s annual audit, including, but not limited to, the preparation and review of audit support schedules, preparation of +financial statements and footnotes, and providing support to the company’s independent auditors. From October 2009 to August +2019, Mr. Brown served as the Director of Finance of Sportsman’s Warehouse Holdings, Inc. where he assisted with the +company’s initial public offering in April 2014 as well as effecting private and secondary public offerings, acquisitions of a +group of retail stores and preparing the company’s periodic and current reports with the SEC and complying with the Sarbanes +Oxley Act. From May 2005 to October 2009, Mr. Brown served as the Corporate Controller of Franklin Covey Products where he developed +and maintained the company’s internal controls over financial reporting structure in accordance with the control standards +required under Section 404 of the Sarbanes Oxley Act. From July 2001 to May 2005, Mr. Brown served as an Assurance Senior at KPMG, +LLP where he provided audit services to various clients in multiple industries. Mr. Brown holds a Bachelor of Arts in Accounting and +Masters of Professional Accountancy from the University of Utah. Mr. Brown is a licensed CPA in Utah. +60 +Involvement +in Certain Legal Proceedings +To +the best of our knowledge, none of our directors or executive officers has been involved in any bankruptcy or criminal proceedings (other +than traffic and other minor offenses) or been subject to any of the items set forth under Item 401(f) of Regulation S-K, nor have there +been any judgments or injunctions brought against any of our directors or executive officers during the last ten years that we consider +material to the evaluation of the ability and integrity of any director or executive officer. +Board +and Committee Matters +Our +board of directors has five members. The Chairman of the Board and our Chief Executive Officer, Dwight Egan, is a member of the board +and is a full-time employee of the Company. Eugene Durenard, Edward Murphy, James Nelson and Richard Serbin are non-employee directors, +and the board has determined that these persons (who constitute a majority of the board) are “independent directors” under +the criteria set forth in Rule 5605(a)(2) of the Nasdaq Listing Rules. The board met eleven times during the year ended December 31, +2022. All directors attended more than seventy-five percent (75%) of the meetings of the board and committee meetings of which such director +was a member held during 2022. +We +maintain an audit committee of the board, a compensation committee of the board and a corporate governance/nominating committee of the +board, each of which is discussed below. Our board has determined that Messrs. Durenard, Nelson, Murphy and Serbin are “independent” +under the definition of independence in the Marketplace Rules of the NASDAQ listing requirements. Our board of directors may from time +to time establish other standing committees. In addition, from time to time, special committees may be established under the direction +of our board of directors when necessary to address specific issues. +The +following table sets forth a description of the three permanent board committees and the chairpersons and members of those committees, +all of whom are independent directors: +Committee +Independent +Chairperson +Independent +Members +Audit Committee +Eugene Durenard +Edward Murphy +James Nelson +Richard S. Serbin +Compensation Committee +Richard S. Serbin +Edward Murphy +Eugene Durenard +James Nelson +Governance Committee +James Nelson +Edward Murphy +Eugene Durenard +Richard S. Serbin +Nominating Committee +Edward Murphy +James Nelson +Eugene Durenard +Richard S. Serbin +Audit +Committee and Financial Expert +Our +audit committee currently is comprised of Messrs. Durenard, Nelson, Murphy and Serbin with Mr. Durenard serving as chairperson of the +audit committee. The functions of the audit committee include engaging an independent registered public accounting firm to audit our +annual financial statements, reviewing the independence of our auditors, the financial statements and the auditors’ report, and +reviewing management’s administration of our system of internal control over financial reporting and disclosure controls and procedures. +The board of directors has adopted a written audit committee charter. A current copy of the audit committee charter is available to security +holders on our website at www.codiagnostics.com. Our board has determined that all our directors that are serving on the audit committee +are “independent” under the definition of independence in the Marketplace Rules of the NASDAQ listing standards. The Audit +Committee met five times during the year ended December 31, 2022. All committee members attended more than seventy-five percent (75%) +of the meetings of the Audit Committee held during 2022. +Our +board of directors has determined that Mr. Durenard meets the requirements of an “audit committee financial expert” as defined +in applicable SEC regulations. +61 +Compensation +Committee +Our +compensation committee currently includes Messrs. Serbin, Nelson, Murphy and Durenard with Mr. Serbin serving as chairperson of the compensation +committee. The functions of the compensation committee include reviewing and approving corporate goals relevant to compensation for executive +officers, evaluating the effectiveness of our compensation practices, evaluating and approving the compensation of our chief executive +officer and other executives, recommending compensation for board members, and reviewing and making recommendations regarding incentive +compensation and other employee benefit plans. The board of directors has adopted a written compensation committee charter. A current +copy of the compensation committee charter is available to shareholders on our website at www.codiagnostics.com. Our board has determined +that all of our directors serving on the compensation committee are “independent” under the definition of independence in +the Marketplace Rules of the NASDAQ listing standards. The Compensation Committee did not meet as a separate committee in 2022, but rather, +because the committee is comprised of all four independent directors, committee matters were addressed as necessary in meetings of the +board. during the year ended December 31, 2022. +Corporate +Governance Committee +Our +Corporate Governance Committee currently includes Messrs. Nelson, Murphy, Durenard and Serbin with Mr. Nelson serving as chairperson +of the Corporate Governance Committee. Among other items, the committee is tasked by the board of directors to: develop and recommend +to the board the Corporate Governance Guidelines of the Company and oversee compliance therewith and evaluate and provide successor planning +for the Chief Executive Officer and other executive officers. A current copy of the Corporate Governance committee charter is available +to shareholders on our website at www.codiagnostics.com. Our board has determined all directors serving on the Corporate Governance committee +are “independent” under the definition of independence in the Marketplace Rules of the NASDAQ listing standards. The Corporate +Governance Committee did not meet as a separate committee in 2022, but rather, because the committee is comprised of all four independent +directors, committee matters were addressed as necessary in meetings of the board the year ended December 31, 2022. +Nominating +Committee +Our +Nominating Committee was split from the Corporate Governance Committee in 2022 and currently includes Messrs. Nelson, Murphy, Durenard +and Serbin with Mr. Murphy serving as chairperson of the Nominating Committee. The Nominating Committee has been established by the board, +among other things to: assist the board in effecting board organization, membership and function including identifying qualified board +nominees; assist the board in effecting the organization, membership and function of board committees including the composition of board +committees and recommending qualified candidates therefor; evaluate and provide successor planning for the Chief Executive Officer and +other executive officers; and develop criteria for board membership, such as independence, term limits, age limits and ability of former +employees to serve on the board and the evaluation of candidates’ qualifications for nominations to the board and its committees +as well as removal therefrom. The Nominating Committee did not meet as a separate committee in 2022, but rather, because the committee +is comprised of all four independent directors, committee matters were addressed as necessary in meetings of the board for the year ended +December 31, 2022. +Board +Nominations +In +considering board candidates, the board seeks individuals of proven judgment and competence who have strong reputations in their respective +fields. Although we do not have a formal diversity policy, the board considers such factors as experience, education, employment history, +special talents or personal attributes, anticipated participation in board activities, and geographic and diversity factors. The process +for identifying and evaluating nominees would include detailed consideration of the recommendations and opinions of members of our board, +our executive officers, and our stockholders. There would be no difference in the process of evaluation of candidates recommended by +a stockholder and those recommended by other sources. +62 +Our +Amended and Restated Bylaws (the “Bylaws”) set forth procedures for shareholders to recommend nominees to the Company’s +board. Nominations of persons for election to the board of directors to be considered by the stockholders may be made at an annual meeting +of stockholders (i) pursuant to the Company’s notice of meeting, (ii) by or at the direction of the board of directors, or (iii) +by any stockholder of the Company who (A) was a stockholder of record at the time of giving of the notice, (B) is entitled to vote with +respect to such matter at the meeting, and (C) complies with the notice procedures set forth in the Bylaws. +The +following is a summary of key provisions from our Bylaws. For nominations to be properly brought before an annual meeting by a stockholder, +the stockholder making such nominations must have given timely notice in writing to the secretary of the Company. To be timely, a stockholder’s +notice shall be delivered to the secretary at the principal executive offices of the Company not later than the close of business on +the 75th day nor earlier than the close of business on the 125th day prior to the first anniversary of the preceding year’s annual +meeting; provided, however, that in the event that the date of the annual meeting is more than 30 days before or more than 60 days after +such anniversary date, notice by the stockholder to be timely must be so delivered not later than the close of business on the later +of (x) the 75th day prior to the scheduled date of such annual meeting or (y) the 15th day following the day on which public announcement +of the date of such meeting is first made by the Company. To be in proper form, a stockholder’s notice to the secretary must: set +forth, as to the stockholder giving the notice and the beneficial owner, if any, on whose behalf the nomination or proposal is made (A) +the name and address of such stockholder, as they appear on the Company’s books, and of such beneficial owner, if any, (B) the +class or series and number of shares of the Company that are, directly or indirectly, owned beneficially and of record by such stockholder +and such beneficial owner, if any, as of the date of such notice, and (C) any other information relating to such stockholder and beneficial +owner, if any, that would be required to be disclosed in a proxy statement or other filings required to be made in connection with solicitations +of proxies for, as applicable, the proposal and/or for the election of directors in a contested election pursuant to Section 14 of the +Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder (the “Exchange Act”). In +addition, shareholders who intend to solicit proxies in support of director nominees other than the company’s nominees must also +comply with the additional requirements of Rule 14a-19(b). +The +notice shall set forth, as to each person, if any, whom the stockholder proposes to nominate for election or reelection as a director +(A) all information relating to such person that would be required to be disclosed in a proxy statement or other filings required to +be made in connection with solicitations of proxies for election of directors in a contested election pursuant to Section 14 of the Exchange +Act (including such person’s written consent to being named in the proxy statement as a nominee and to serving as a director if +elected) and (B) a description of all direct and indirect compensation and other monetary agreements, arrangements and understandings +during the past three years, and any other relationships, between or among such stockholder and beneficial owner, if any, and their respective +affiliates and associates, or others acting in concert therewith, on the one hand, and each proposed nominee, and his or her respective +affiliates and associates, or others acting in concert therewith, on the other hand, including, without limitation all information that +would be required to be disclosed pursuant to Rule 404 promulgated under Regulation S-K if the stockholder making the nomination and +any beneficial owner on whose behalf the nomination is made, if any, or any affiliate or associate thereof or person acting in concert +therewith, were the “registrant” for purposes of such rule and the nominee were a director or executive officer of such registrant; +and with respect to each nominee for election or reelection to the board of directors, include the completed and signed questionnaire, +representation, and agreement required by the Bylaws. The Company may require any proposed nominee to furnish such other information +as may reasonably be required by the Company to determine the eligibility of such proposed nominee to serve as an independent director +of the Company or that could be material to a reasonable stockholder’s understanding of the independence, or lack thereof, of such +nominee. +Communication +with the Board +We +have not, to date, developed a formal process for shareholder communications with the board of directors. We believe our current informal +process, in which any communication sent to the board of directors, either generally or in care of the chief executive officer, secretary +or other corporate officer or director, is forwarded to all members of the board of directors, has served the board’s and the shareholders’ +needs. +63 +Conflicts +of Interests +On +an annual basis, each director and executive officer is obligated to complete a director and officer questionnaire that requires disclosure +of any transactions with our company, including related person transactions reportable under SEC rules, in which the director or executive +officer, or any member of his or her immediate family, have a direct or indirect material interest. Under our company’s standards +of conduct for employees, all employees, including the executive officers, are expected to avoid conflicts of interest. Pursuant to our +code of ethics for the chief executive officer and senior finance officers (as discussed below), such officers are prohibited from engaging +in any conflict of interest unless a specific exception has been granted by the board. All of our directors are subject to general fiduciary +standards to act in the best interests of our company and our shareholders. Conflicts of interest involving an executive officer or a +director are generally resolved by the board. +Role +of the Board in Risk Oversight +Risk +is inherent with every business, and how well a business manages risk can ultimately determine its success. Management is responsible +for the day-to-day management of the risks that we face, while our board of directors, as a whole and through its committees, has responsibility +for the oversight of risk management. In its risk oversight role, our board of directors is responsible for satisfying itself that the +risk management processes designed and implemented by management are adequate and functioning as designed. +Our +board of directors does not have a standing risk management committee, but rather administers this oversight function directly through +our board of directors as a whole, as well as through various standing committees of the board of directors that address risks inherent +in their respective areas of oversight. In particular, our board of directors is responsible for monitoring and assessing strategic risk +exposure, including a determination of the nature and level of risk appropriate for us. Our Audit Committee has the responsibility to +consider and discuss our major financial risk exposures and the steps our management has taken to monitor and control these exposures, +including guidelines and policies to govern the process by which risk assessment and management is undertaken. The Audit Committee also +monitors oversight of the performance of our internal audit function. Our Corporate Governance/Nominating Committee monitors the effectiveness +of our corporate governance guidelines, including whether they are successful in preventing illegal or improper liability-creating conduct. +Our Compensation Committee assesses and monitors whether any of our compensation policies and programs have the potential to encourage +excessive risk-taking or promote behaviors contra to our Code of Business Conduct. +Code +of Ethics +We +have adopted a code of ethics for our principal executive officer, principal financial officer, controller, or persons performing similar +functions. A copy of the code of ethics is included on our website at www.codiagnostics.com. +Family +Relationships +There +are no family relationships among our directors and executive officers. +ITEM +11. EXECUTIVE COMPENSATION +We +are a “smaller reporting company” as defined in the rules and regulations of the SEC. As a smaller reporting company, we +may take advantage of specified reduced disclosure and other requirements that are otherwise applicable, in general, to public companies +that are not smaller reporting companies. Accordingly, this Report includes reduced disclosure about our executive compensation arrangements. +Summary +Compensation Table +The +table below summarizes the total compensation paid or earned by each of the named executive officers in their respective capacities for +the fiscal years ended December 31, 2022 and 2021. We have omitted in this report certain columns otherwise required to be included because +there was no compensation made with respect to such columns, as permitted by applicable SEC regulations. +64 +Name and Principal Position +Year +Salary +Bonus (1) +Stock +Awards (2) +All Other +Comp (3) +Total +Compensation +Dwight Egan +2022 +$ 366,146 +$ 146,245 +$ 1,454,750 +$ - +$ 1,967,141 +President & Chief Executive Officer +2021 +$ 350,000 +$ 638,459 +$ 1,208,750 +$ 26,793 +$ 2,224,002 +Brian Brown +2022 +$ 280,875 +$ 106,647 +$ 1,190,250 +$ - +$ 1,577,772 +Chief Financial Officer and Secretary +2021 +$ 209,731 +$ 475,014 +$ 1,441,600 +$ 26,793 +$ 2,153,138 +(1) +Bonuses for the year ended +December 31, 2021 include accrued bonus payments of $281,597 to Mr. Egan and $223,248 to Mr. Brown that were paid in February 2022. +(2) +The amounts reported in +this column represent the aggregate grant date fair value of the restricted stock units, or RSUs, granted under our 2015 Plan as +computed in accordance with FASB ASC Topic 718. Note that the amounts reported in this column reflect the accounting value for these +equity awards and do not correspond to the actual economic value that may be received from the equity awards as the RSUs vest over +three years. +(3) +Company profit sharing +payments to the Company’s 401 K Plan. +Narrative +Disclosure to Summary Compensation Table: We do not have written employment agreements with any of our executive officers. All of +our executive officers serve on an at-will basis. The base salaries for our named executive officers were determined by our compensation +committee after reviewing a number of factors, including: the responsibilities associated with the position, the seniority of the executive’s +position, the base salary level in prior years, and our financial position; and for executive officers other than our Chief Executive +Officer, recommendations made by our Chief Executive Officer. By utilizing a combination of objective and subjective performance factors +critical to our success, the board will award cash bonuses intended to incentivize our executive officers to achieve results that benefit +them and the Company. Performance factors include the achievement of predetermined financial performance objectives, adherence to financial +discipline measures and achievement of business development, product development and long-term business stability. The board may modify +or re-weight the objectives during the course of the fiscal year, if necessary, to reflect changes in our business plan. +65 +Outstanding +Equity Awards at Fiscal Year-End 2022 +The +following table contains certain information concerning outstanding equity awards for the Named Executive Officers as of December 31, +2022. +Option Awards +Stock Awards +Number of Securities +Underlying Unexercised +Options (#) +Option +Exercise +Option +Expiration +Number of Shares or Units of Stock That Have Not +Vested +Market Value of Shares or Units of Stock That Have Not +Vested +Number of Unearned Shares, Units or Other Rights That +Have Not +Market or Payout Value of Unearned Shares, Units or +Other Rights That Have Not +Name +Exercisable +Unexercisable +Price +Date +(#) +($) (1) +Vested (#) +Vested ($) +Dwight Egan +50,000 +- +$ 2.63 +09/20/28 +- +- +- +- +50,000 +- +$ 1.10 +09/02/29 +- +- +- +- +- +- +- +- +25,000 (2) +$ 63,000 +- +- +- +- +- +- +62,500 (4) +$ 157,500 +- +- +- +- +- +- +229,167 (5) +$ 577,501 +- +- +Brian Brown +- +- +- +- +10,000 (3) +$ 25,200 +- +- +- +- +- +- +50,000 (4) +$ 126,000 +- +- +- +- +- +- +187,500 (5) +$ 472,500 +- +- +(1) +Based +on $2.52 per share, which was the closing price of our common stock on December 31, 2022. +(2) +Consists +of restricted stock units granted on 11/23/2020, which vest in 6 installments commencing on 5/23/2021 and continuing every six months +thereafter. +(3) +Consists +of restricted stock units granted on 2/22/2021, which vest in 6 installments commencing on 5/23/2021 and continuing every six months +thereafter. +(4) +Consists +of restricted stock units granted on 8/12/2021, which vest in 6 installments commencing on 11/23/2021 and continuing every six months +thereafter. +(5) +Consists +of restricted stock units granted on 6/6/2022, which vest in 6 installments commencing on 11/23/2022 and continuing every six months +thereafter. +Potential +Payments Upon Termination or Change of Control +There +is no compensation payable to the named executive officers upon voluntary termination, retirement, involuntary not-for-cause termination, +termination following a change of control or in the event of disability or death of the executive. +Director +Compensation +We +use a combination of cash and stock-based incentive compensation to attract and retain qualified candidates to serve on its board of +directors. In setting director compensation, we consider the significant amount of time that directors expend in fulfilling their duties +as well as the skill level required by our members of the board. +66 +The +table below summarizes the compensation paid or accrued by us to each of our non-employee directors for the fiscal year ended December +31, 2022. +Name +Fees Earned or +Paid in Cash +Stock Awards: +Value of Restricted +Stock Units (1) +Total +Richard Serbin (2) +$ 87,500 +$ 429,100 +$ 516,600 +James Nelson (3) +$ 87,500 +$ 429,100 +$ 516,600 +Edward Murphy (4) +$ 87,500 +$ 429,100 +$ 516,600 +Eugene Durenard (5) +$ 87,500 +$ 429,100 +$ 516,600 +(1) +The amounts reported in +this column represent the aggregate grant date fair value of the restricted stock units, or RSUs, granted under our 2015 Plan as +computed in accordance with FASB ASC Topic 718. Note that the amounts reported in this column reflect the accounting value for these +equity awards and do not correspond to the actual economic value that may be received from the equity awards. The RSUs vested immediately +upon grant. +(2) +As of December 31, 2022, +Mr. Serbin had 70,833 RSU awards outstanding. +(3) +As of December 31, 2022, +Mr. Nelson had 70,833 RSU awards outstanding. +(4) +As of December 31, 2022, +Mr. Murphy had 70,833 RSU awards outstanding. +(5) +As of December 31, 2022, +Mr. Durenard had 70,833 RSU awards outstanding. +Our +non-employee directors receive cash compensation of $100,000 per year, paid quarterly. In 2021, the non-employee directors also each +received 37,500 RSU’s vesting 1/3 rd equally in January 2021, 2022, and 2023. In 2022, they also received 70,000 +RSU’s vesting 1/6 th equally in November 2022, 2023, and 2024 and May 2023, 2024, and 2025. In addition, +non-employee directors may be entitled to receive special awards of stock options or RSUs from time to time as determined by the +board. The chairman of the board and the chairperson of each of the audit, corporate governance/nomination, and compensation +committees receive no additional fees for serving in such capacities. There is no additional compensation for meeting attendance. +Directors who are employees of the Company receive no additional compensation for serving as directors. All stock options granted to +outside directors are immediately exercisable and expire ten years from the date of grant or 30 days after the date they cease to be +directors. Directors are reimbursed for ordinary expenses incurred in connection with attending board and committee +meetings. +67 +Equity +Incentive Plans +Under +our Amended and Restated 2015 Long-term Incentive Plan (the “2015 Plan”), the board of directors may issue incentive stock-based +awards to employees, directors and consultants of the company. Options awarded generally expire ten years after being granted. Any stock-based +awards granted vest in accordance with the vesting schedule determined by the board of directors. Should an employee’s director’s +or consultant’s relationship with the company terminate before the vesting period is completed, the unvested portion of each grant +is forfeited. We continue to maintain and grant awards under the 2015 Plan which will remain in effect until its expiration by its terms. +The +purpose of our incentive plan is to advance the interests of our stockholders by enhancing our ability to attract, retain and motivate +persons who are expected to make important contributions to the company by providing them with both equity ownership opportunities and +performance-based incentives intended to align their interests with those of our stockholders. These plans are designed to provide us +with flexibility to select from among various equity-based compensation methods, and to be able to address changing accounting and tax +rules and corporate governance practices by optimally utilizing stock-based awards. +ITEM +12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The +following table sets forth certain information, as of March 14, 2023, with respect to the holdings of (1) each person who is the beneficial +owner of more than 5% of our Common Stock, (2) each of our directors, (3) each named executive officer, and (4) all of our current directors +and executive officers as a group. +Beneficial +ownership of the common stock is determined in accordance with the rules of the Securities and Exchange Commission and includes any shares +of common stock over which a person exercises sole or shared voting or investment power, or of which a person has a right to acquire +ownership at any time within 60 days of March 14, 2023. Applicable percentage ownership in the following table is based on 30,922,607 +shares of common stock plus, for each individual, any securities that individual has the right to acquire within 60 days of March 14, +2023. +The +information in the table below is based on information known to us or ascertained by us from public filings made by the stockholders. +Except as otherwise indicated in the table below, addresses of the director, executive officers and named beneficial owners are in care +of Co-Diagnostics, Inc., 2401 S. Foothill Drive, Suite D, Salt Lake City, Utah 84109. +Number of Shares Beneficially Owned +Percentage +of Class (1) +5% Stockholders +Vanguard Group (1) +1,781,283 +5.8 % +Named Executive Officers and Directors +Dwight Egan (2) +193,197 +* +Brian Brown +73,236 +* +Edward Murphy (3) +99,167 +* +Eugene Durenard +36,667 +* +James Nelson (4) +86,667 +* +Richard Serbin (5) +59,612 +* +All Directors and Executive Officers as a Group (6 persons) +548,546 +1.7 % +*Represents +beneficial ownership of less than 1%. +(1) +Information obtained from +Schedule 13G/A filed with the SEC on February 9, 2023. Vanguard Group has an address of 100 Vanguard Blvd, Malvern, PA, 19355. +(2) +Includes exercisable options +to acquire 100,000 shares of common stock. +(3) +Includes exercisable options +to acquire 50,000 shares of common stock. +(4) +Includes exercisable options +to acquire 50,000 shares of common stock. +(5) +Includes exercisable options +to acquire 20,445 shares of common stock. +Equity +Compensation Plan Information +Plan Category +(a) Number of Shares to be Issued upon Exercise of Outstanding Options and Rights +(b) Weighted-average Exercise Price of Outstanding Options and Rights +(c) Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Referenced in Column (a)) +Equity compensation plans approved by stockholders +3,467,297 (1) +$ 2.19 (2) +6,210,790 +Equity compensation plans not approved by stockholders +- +$ - +- +Total +3,467,297 (1) +$ 2.19 (2) +6,210,790 +(1) +Includes options and restricted +stock units outstanding under our 2015 Equity Incentive Plan. +(2) +Represents weighted-average +exercise price per share of common stock acquirable upon exercise of outstanding stock options. +68 +ITEM +13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +The +Company employs two persons who are related to current or former executive officers. Seth Egan is the Company’s Director of Sales +and Marketing, and is the son of Dwight Egan, the Company’s President and Chief Executive Officer. Andrew Benson is the Company’s +Director of Investor Relations, and is the son of Reed Benson, the Company’s former Chief Financial Officer and Secretary. During +the year ended December 31, 2022, the total compensation paid to or earned by these persons, including salaries, bonuses, and the grant +date fair value of equity awards which vest over three years, was $962,800 and $489,000, respectively. +Policy for Review of Related Party Transactions +The review of transactions with related persons policy +is set forth in our Corporate Governance Committee Charter. The Corporate Governance Committee is to oversee the administration of any +related party transactions policy in effect with respect to transactions in which the Company is a participant and involving directors, +nominees for director, executive officers of the Company or holders of more than 5% of the Company’s common stock or immediate +family members of any such person. +Director Independence +For information regarding the independence of our directors, see “Directors, +Executive Officers and Corporate Governance” in Part III, Item 10 of this Form 10-K. +ITEM +14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +The +following table presents aggregate fees for professional services rendered by our independent auditors for the respective periods. +Years Ended December 31, +2022 +2021 +Audit fees +$ 136,600 +$ 113,100 +Audit related fees +- +- +Other consulting fees +- +- +Tax fees +- +- +Total fees +$ 136,600 +$ 113,100 +Audit +fees consist of fees for professional services provided in connection with the audit of our annual consolidated financial statements, +review of our quarterly consolidated financial statements and our offerings. +The +audit committee has adopted a policy that requires advance approval of all services performed by the independent auditor when fees are +expected to exceed $15,000. The audit committee has delegated to the audit committee chairperson, Mr. Durenard, the authority to approve +services, subject to ratification by the audit committee at its next committee meeting. All fees incurred were pre-approved by the audit +committee. +69 +PART +IV +Item +15. Exhibits, Financial Statement Schedules. +(a) +The following documents are filed as part of this Annual +Report on Form 10-K: +(1) +Financial Statements. +The Consolidated Financial Statements filed as part of this Annual Report on Form 10-K are included in Part II, Item 8 of this +Annual Report on Form 10-K. +(2) +Financial statement +schedules. There are no financial statements schedules included because they are either not applicable or the required information +is shown in the consolidated financial statements or the notes thereto. +(3) +Exhibits. The exhibits +required by Item 601 of Regulation S-K and Item 15(b) of this Annual Report are listed in the Exhibit Index below. The exhibits listed +in the Exhibit Index are incorporated by reference herein. +Exhibit +Number +Exhibit +Description +Filed +with this +Report +Incorporated +by +Reference +herein from Form or Schedule +Filing +Date +SEC +File/Reg. +Number +2.1*+ +Agreement and Plan of Merger by and between Co-Diagnostics, Inc, IDMO Acquisition Corp., Idaho Molecular Inc., and Company Representative dated as of December 21, 2021. +Form 8-K (Exhibit 2.1) +12/23/21 +001-38148 +2.1.2 +Amendment to Agreement and Plan of Merger by and among Co-Diagnostics, Inc., Idaho Molecular, Inc., and Kirk Ririe, as Company Representative +Form 8-K (Exhibit 2.2) +06/16/22 +001-38148 +2.2*+ +Agreement and Plan of Merger by and between Co-Diagnostics, Inc, ACI Acquisition Corp., Advanced Conceptions, Inc., and Company Representative dated as of December 21, 2021 +Form 8-K (Exhibit 2.2) +12/23/21 +001-38148 +2.2.1 +Amendment to Agreement and Plan of Merger by and among Co-Diagnostics, Inc., Advanced Conceptions, Inc., and Richard Abbott, as Company Representative +Form 8-K (Exhibit 2.1) +06/16/22 +001-38148 +3.1 +Articles of Incorporation +Draft Registration Statement +(Exhibit 3.1) +01/12/17 +377-01467 +3.1.1 +Amendment to the Articles of Incorporation +Draft Registration Statement +(Exhibit 3.1.1) +01/12/17 +377-01467 +3.1.2 +Articles of Amendment to Articles of Incorporation +Form 8-K (Exhibit 3.2) +01/03/19 +001-38148 +3.1.3 +Articles of Amendment +Form 10-K (Exhibit 3.1.3) +03/24/22 +001-38148 +3.1.3 +Articles of Amendment +X +3.2 +Amended and Restated Bylaws of Co-Diagnostics, Inc. +Form 8-K (Exhibit 3.1) +04/01/22 +001-38148 +4.1 +Description of Registrant’s securities +X +10.1 +Exclusive Agreement between Co-Diagnostics, Inc. and DNA Logix, Inc., dated April 18, 2014 +Draft Registration Statement +(Exhibit 10.2) +01/12/17 +377-01467 +10.2 # +Co-Diagnostics, Inc. Amended and Restated 2015 Long Term Incentive Plan +Form S-8/A +11/20/20 +333-237684 +10.3 +Form of Indemnification Agreement +Form S-1/A (Exhibit 10.13.8) +05/24/17 +333-217542 +10.4 +Shareholders’ Agreement between Co-Diagnostics and Synbiotics Limited, dated January 27, 2017 +Form S-1 (Exhibit 10.16) +04/28/17 +333-217542 +10.5 +Amended Exclusive License Agreement between Co-Diagnostics, Brent Satterfield, and DNA Logix, Inc., dated January 1, 2017 +Form S-1 (Exhibit 10.17) +04/28/17 +333-217542 +10.6 +Warrant Agreement between Co-Diagnostics, Inc and VStock Transfer, LLC. Dated December 31, 2021 (ACI Warrant) +Form 10-K (Exhibit 10.6) +03/24/22 +001-38148 +70 +10.7 +Warrant Agreement between Co-Diagnostics, Inc and VStock Transfer, LLC. Dated December 31, 2021 (IDMO Warrant) +Form 10-K (Exhibit +10.7) +03/24/22 +001-38148 +10.8 +Form of Securities Purchase Agreement, dated February 27, 2020 +Form 8-K (Exhibit 10.1) +02/27/20 +001-38148 +10.9 +Lease Agreement 2401 Foothill Drive +Form 10-K (Exhibit +10.9) +03/24/22 +001-38148 +10.9.1 +Amendment #1 to Lease +Form 10-K (Exhibit 10.9.1) +03/24/22 +001-38148 +10.9.2 +Amendment #2 to Lease +Form 10-K (Exhibit +10.9.2) +03/24/22 +001-38148 +14.1 +Code of Ethics for Senior Financial Officers +Form 10-K (Exhibit 14.1) +03/30/20 +001-38148 +21.1 +Subsidiaries of Registrant +X +23.1 +Consent of Haynie & Company +X +31.1 +Certification of Chief Executive Officer pursuant to section 302 of the Sarbanes-Oxley Act of 2002 +X +31.2 +Certification of Principal Financial Officer pursuant to section 302 of the Sarbanes-Oxley Act of 2002 +X +32.1 +Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 +X +32.2 +Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 +X +101 SCH +Inline XBRL Taxonomy Extension +Schema Document (A) +X +101.CAL +Inline XBRL Taxonomy Extension +Calculation Linkbase Document (A) +X +101.DEF +Inline XBRL Taxonomy Extension +Definition Linkbase Document (A) +X +101.LAB +Inline XBRL Taxonomy Extension +Label Linkbase Document (A) +X +101.PRE +Inline XBRL Taxonomy Extension +Presentation Linkbase Document (A) +X +104 +Cover Page Interactive +Data File (formatted as Inline XBRL and contained in Exhibit 101) +X +(A) +iXBRL +(INline Extensible Business Reporting Language) information +is furnished and not filed for purposes of Section 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange +Act of 1934. +X +# Management +Contract or Compensatory Plan or Arrangement +*Schedules +and exhibits to these Exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company agrees to furnish supplementally +a copy of any omitted schedule or exhibit to the SEC upon request. ++ +Portions of Exhibit 2.1 and Exhibit 2.2 have been omitted as they contain information that (i) is not material and (ii) is the type of +information the issuer both customarily and actually treats as private and confidential. +Item 16. Form 10-K Summary. +None +71 +SIGNATURES +Pursuant +to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed +on its behalf by the undersigned thereunto duly authorized. +CO-DIAGNOSTICS, +INC. +Date: March 16, 2023 +By: +/s/ +Dwight Egan +Dwight Egan +Chief +Executive Officer, President and Director +(Principal +Executive Officer) +By: +/s/ +Brian Brown +Brian +Brown +Chief +Financial Officer +(Principal +Financial and Accounting Officer +Pursuant +to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the +registrant and in the capacities and on the date indicated. +Signature +Title +Date +/s/ Dwight +Egan +Chief Executive Officer, +President and Director +March 16, 2023 +Dwight Egan +(Principal Executive Officer) +/s/ Brian +Brown +Chief Financial Officer +March 16, 2023 +Brian Brown +(Principal Financial and +Accounting Officer) +/s/ Eugene +Durenard +Director +March 16, 2023 +Eugene Durenard +/s/ Edward +Murphy +Director +March 16, 2023 +Edward Murphy +/s/ James +Nelson +Director +March 16, 2023 +James Nelson +/s/ Richard +Serbin +Director +March 16, 2023 +Richard Serbin +72 \ No newline at end of file diff --git a/raw/filings/0001692415/2022/0001493152-23-007925/filing_metadata.csv b/raw/filings/0001692415/2022/0001493152-23-007925/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..4db6301b9629b1b045389046c7cdabacf6a33ef0 --- /dev/null +++ b/raw/filings/0001692415/2022/0001493152-23-007925/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001692415,CODX,"Co-Diagnostics, Inc.",10-K,2023-03-16,2022-12-31,2023-03-17T00:30:51.000Z,0001493152-23-007925,form10-k.htm,,7342149,1,1,https://www.sec.gov/Archives/edgar/data/1692415/000149315223007925/form10-k.htm,https://www.sec.gov/Archives/edgar/data/1692415/000149315223007925/,2022,2022,1 diff --git a/raw/filings/0001692415/2022/0001493152-23-007925/item1.txt b/raw/filings/0001692415/2022/0001493152-23-007925/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001692415/2022/0001493152-23-007925/item13.txt b/raw/filings/0001692415/2022/0001493152-23-007925/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001692415/2022/0001493152-23-007925/item9a.txt b/raw/filings/0001692415/2022/0001493152-23-007925/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001692415/2022/0001493152-23-007925/rp_note.txt b/raw/filings/0001692415/2022/0001493152-23-007925/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001692415/2022/0001493152-23-007925/rpt_disclosure.txt b/raw/filings/0001692415/2022/0001493152-23-007925/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..2dee567c86c36c76bcfe8ef44ca145b198d26ec0 --- /dev/null +++ b/raw/filings/0001692415/2022/0001493152-23-007925/rpt_disclosure.txt @@ -0,0 +1,188 @@ +for Review of Related Party Transactions +The +review of transactions with related persons policy is set forth in our Corporate Governance Committee Charter. The Corporate Governance +Committee is to oversee the administration of any related party transactions policy in effect with respect to transactions in which the +Company is a participant and involving directors, nominees for director, executive officers of the Company or holders of more than 5% +of the Company’s common stock or immediate family members of any such person. +Pay +versus Performance +In +accordance with rules adopted by the Securities and Exchange Commission (“SEC”) pursuant to the Dodd-Frank Wall Street Reform +and Consumer Protection Act of 2010, we provide the following disclosure regarding executive “Compensation Actually Paid” +(“CAP”) and certain performance measures required for Smaller Reporting Companies. The following table provides the information +required for our NEOs for each of the fiscal years ended December 31, 2022 and December 31, 2021, along with the financial information +required for each fiscal year: +Year +Summary compensation table total CEO ($)(1)(2) +Compensation +actually paid to CEO ($)(1)(3) +Average summary compensation table total for non-CEO NEOs ($) (2)(4) +Average compensation actually paid to non-CEO NEOs(3)(4) +Value of Initial Fixed $100 Investment based on Total shareholder return($) +Net Income (in millions) ($) +2022 +1,967,141 +371,557 +1,577,772 +399,514 +27.10 +(14 ) +2021 +2,224,001 +2,148,168 +2,153,138 +1,857,321 +96.02 +37 +(1) +For +each year shown the CEO was Dwight Egan. +(2) +Amounts in this column represent the “Total” column set +forth in the Summary Compensation Table (“SCT”) on page 14. See the footnotes to the SCT for further detail regarding +the amounts in these columns. +(3) +The +dollar amounts reported in these columns represent the amounts of “compensation actually paid.” The Amounts are computed +in accordance with Item 402(v) of Regulation S-K by deducting and adding the following amounts from the “Total” column +of the SCT (pursuant to SEC rules, fair value at each measurement date is computed in a manner consistent with the fair value methodology +used to account for share-based payments in our financial statements under GAAP). +(4) +Non-CEO +NEOs reflect the compensation of Brian Brown, CFO, who was the only Non-CEO NEO for the periods indicated. +18 +2022 +2021 +Dwight +Egan +Average +Non-CEO NEOs +Dwight +Egan +Average +Non-CEO NEOs +Total +Compensation from Summary Compensation Table +$ 1,967,141 +$ 1,577,772 +$ 2,224,001 +$ 2,153,138 +Adjustments +for Equity Awards +Adjustment +for grant date values in the Summary Compensation Table +$ (1,454,750 ) +$ (1,190,250 ) +$ (1,208,750 ) +$ (1,441,600 ) +Year-end +fair value of unvested awards granted in the current year +$ 577,501 +$ 472,500 +$ 930,211 +$ 922,764 +Year-over-year +difference of year-end fair values for unvested awards granted in prior years +$ (560,875 ) +$ (384,600 ) +$ (18,500 ) +$ - +Fair +values at vest date for awards granted and vested in current year +$ 157,207 +$ 128,625 +$ 175,831 +$ 223,019 +Difference +in fair values between prior year-end fair values and vest date fair values for awards granted in prior years +$ (314,667 ) +$ (204,533 ) +$ 45,375 +$ - +Forfeitures +during current year equal to prior year-end fair value +$ - +$ - +$ - +$ - +Dividends +or dividend equivalents not otherwise included in total compensation +$ - +$ - +$ - +$ - +Total +Adjustments for Equity Awards +$ (1,595,584 ) +$ (1,178,258 ) +$ (75,833 ) +$ (295,817 ) +Compensation +Actually Paid (as calculated) +$ 371,557 +$ 399,514 +$ 2,148,168 +$ 1,857,321 +Narrative +Disclosure: Pay Versus Performance Table +The +illustrations below provide a graphical description of CAP (as calculated in accordance with the SEC rules) and the following measures: +● +Co-Diagnostics’ +cumulative TSR; and +● +Co-Diagnostics’ +Net Income +CAP and Cumulative TSR +CAP and Net Income +19 +STOCK +OWNERSHIP +The +following table sets forth certain information, as of June 30, 2023, with respect to the holdings of (1) each person who is the beneficial +owner of more than 5% of our Common Stock, (2) each of our directors, (3) each named executive officer, and (4) all of our current directors +and executive officers as a group. +Beneficial +ownership of the common stock is determined in accordance with the rules of the Securities and Exchange Commission and includes any shares +of common stock over which a person exercises sole or shared voting or investment power, or of which a person has a right to acquire +ownership at any time within 60 days of June 30, 2023. Applicable percentage ownership in the following table is based on 30,788,871 +shares of common stock plus, for each individual, any securities that individual has the right to acquire within 60 days of June 30, +2023. +The +information in the table below is based on information known to us or ascertained by us from public filings made by the stockholders. +Except as otherwise indicated in the table below, addresses of the director, executive officers and named beneficial owners are in care +of Co-Diagnostics, Inc., 2401 S. Foothill Drive, Suite D, Salt Lake City, Utah 84109. +Number of Shares Beneficially Owned +Percentage +of Class +5% Stockholders +Vanguard Group (1) +1,781,283 +5.8 % +Named Executive Officers and Directors +Dwight Egan (2) +266,094 +* +Brian Brown +131,013 +* +Edward Murphy (3) +117,500 +* +Eugene Durenard +55,000 +* +James Nelson (4) +105,000 +* +Richard Serbin (5) +77,945 +* +All Directors and Executive Officers as a Group (6 persons) +752,552 +2.4 % +*Represents +beneficial ownership of less than 1%. +(1) +Information +obtained from Schedule 13G/A filed with the SEC on February 9, 2023. 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+2023-12-31 +0001692415 +CODX:CoSaraDiagnosticsPvtLtdMember +2023-01-01 +2023-12-31 +0001692415 +2023-10-01 +2023-12-31 +iso4217:USD +xbrli:shares +iso4217:USD +xbrli:shares +xbrli:pure +UNITED +STATES +SECURITIES +AND EXCHANGE COMMISSION +Washington, +D.C. 20549. +Form +10-K +(Mark +One) +☒ +ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For +the fiscal year ended December 31 , 2023 +OR +☐ +TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 +For +the transition period from_______to_______ +Commission +File Number 001-38148 +CO-DIAGNOSTICS, +INC. +(Exact +Name of Registrant as Specified in Its Charter) +Utah +46-2609396 +(State +or other jurisdiction of +incorporation +or organization) +(I.R.S. +Employer +Identification +Number) +2401 +S. Foothill Drive , Salt Lake City , Utah 84109 +(Address +of principal executive offices and zip code) +(801) +438-1036 +(Registrant’s +telephone number including area code) +Securities +registered pursuant to Section 12(b) of the Act: +Title +of each class +Trading +Symbol(s) +Name +of each exchange on which registered +Common +Stock +CODX +The +Nasdaq Capital Market +Securities +registered pursuant to Section 12(g) of the Act: None +Indicate +by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒ +Indicate +by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ☐ No ☒ +Indicate +by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act of 1934 +during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject +to such filing requirements for the past 90 days. Yes ☒ No ☐ +Indicate +by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data +File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding +12 months (or such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐ +Indicate +by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting +company or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller +reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. +Large +accelerated filer +☐ +Accelerated +filer +☐ +Non-accelerated +filer +☒ +Smaller +reporting company +☒ +Emerging +growth company +☐ +If +an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying +with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ +Indicate +by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness +of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered +public accounting firm that prepared or issued its audit report. ☐ +If +securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant +included in the filing reflect the correction of an error to previously issued financial statements. ☐ +Indicate +by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation +received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐ +Indicate +by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒ +The +aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which +the common stock was last sold as of the last business day of the registrant’s most recently completed second fiscal quarter was +approximately $ 33,000,000 . +As +of March 12, 2024, there were 31,259,668 shares of common stock, par value $0.001 per share, outstanding. +Table +of Contents +Page +PART I +Item +1. +Business. +4 +Item +1A. +Risk Factors. +12 +Item +1B. +Unresolved Staff Comments. +23 +Item +1C. +Cybersecurity +24 +Item +2. +Properties. +25 +Item +3. +Legal Proceedings. +25 +Item +4. +Mine Safety Disclosures. +26 +PART II +Item +5. +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. +27 +Item +6. +[Reserved.] +28 +Item +7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations. +28 +Item +7A. +Quantitative and Qualitative Disclosures About Market Risk. +32 +Item +8. +Financial Statements and Supplementary Data. +33 +Item +9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +55 +Item +9A. +Controls and Procedures. +55 +Item +9B. +Other Information. +56 +Item +9C. +Disclosure Regarding Foreign Jurisdictions that Prevent Inspections. +56 +PART III +Item +10. +Directors, Executive Officers and Corporate Governance. +56 +Item +11. +Executive Compensation. +61 +Item +12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. +64 +Item +13. +Certain Relationships and Related Transactions, and Director Independence. +65 +Item +14. +Principal Accountant Fees and Services. +65 +PART IV +Item +15. +Exhibits and Financial Statement Schedules. +66 +2 +PART +I +Forward-Looking +Statements +This +Annual Report on Form 10-K contains “forward-looking statements” that involve risks and uncertainties. All statements other +than statements of historical fact contained in this Annual Report and the documents incorporated by reference herein, including statements +regarding future events, our future financial performance, business strategy, and plans and objectives of management for future operations, +are forward-looking statements. We have attempted to identify forward-looking statements by terminology including “anticipates,” +“believes,” “can,” “continue,” “could,” “estimates,” “expects,” +“intends,” “may,” “plans,” “potential,” “predicts,” “should,” +or “will” or the negative of these terms or other comparable terminology. Although we do not make forward looking statements +unless we believe we have a reasonable basis for doing so, we cannot guarantee their accuracy. These statements are only predictions +and involve known and unknown risks, uncertainties and other factors which may affect our or our industry’s actual results, levels +of activity, performance or achievements expressed or implied by these forward-looking statements. Moreover, we operate in a highly regulated, +very competitive, and rapidly changing environment. New risks emerge from time to time, and it is not possible for us to predict all +risk factors, nor can we address the impact of all factors on our business or the extent to which any factor, or combination of factors, +may cause our actual results to differ materially from those contained in any forward-looking statements. +We +have based these forward-looking statements largely on our current expectations and projections about future events and financial trends +that we believe may affect our financial condition, results of operations, business strategy, short term and long-term business operations, +and financial needs. These forward-looking statements are subject to certain risks and uncertainties that could cause our actual results +to differ materially from those reflected in the forward-looking statements. Factors that could cause or contribute to such differences +include, but are not limited to, those discussed in this Annual Report, and in particular, the risks discussed under “ Item 1, +Business,” “Item 1A, Risk Factors,” and “Item 7, Management’s Discussion and Analysis of Financial Condition +and Results of Operations,” and those discussed in other documents we file with the Securities and Exchange Commission (the +“SEC”). In light of these risks, uncertainties and assumptions, the forward-looking events and circumstances discussed in +this Annual Report may not occur as described and actual results could differ materially and adversely from those anticipated or implied +in the forward-looking statement. +Important +factors that could cause actual results to differ materially from those in the forward-looking statements include, without limitation: +● +the +results of clinical evaluations and the regulatory approval process; +● +market +acceptance of any products that may be approved for commercialization; +● +our +ability to protect our intellectual property rights; +● +the +impact of any infringement actions or other litigation brought against us; +● +competition +from other providers and products; +● +our +ability to develop and commercialize new and improved products and services; +● +changes +in government regulation; +● +and +other factors (including the risks contained in the section entitled “Risk Factors” in other documents we file with the +SEC) relating to our industry, our operations and results of operations. +Should +one or more of these risks or uncertainties materialize, or should the underlying assumptions prove incorrect, actual results may differ +significantly from those anticipated, believed, estimated, expected, intended or planned. +Given +these risks and uncertainties, readers are cautioned not to place undue reliance on any forward-looking statements. Forward-looking statements +contained in this Annual Report speak only as of the date of this Annual Report. We undertake no obligation to update any forward-looking +statements as a result of new information, events or circumstances or other factors arising or coming to our attention after the date +hereof. +3 +As +used in this Annual Report, the terms “we”, “us”, “our”, “Company”, “CODX” +and “Co-Diagnostics” means Co-Diagnostics, Inc., a Utah corporation and its consolidated subsidiaries (the “Company”), +unless otherwise indicated. +ITEM +1: BUSINESS +Overview +Co-Diagnostics, Inc., a Utah corporation (the “Company” or +“CODX”), develops, manufactures and sells reagents used for diagnostic tests that function via the detection and/or analysis +of nucleic acid molecules (DNA or RNA), including robust and innovative molecular tools for detection of infectious diseases, liquid biopsy +for cancer screening, and agricultural applications. Our diagnostics systems enable dependable, low-cost, molecular testing for organisms +and genetic diseases by automating or simplifying historically complex procedures in both the development and administration of tests. +CODX’s technical advance involves a novel, patented approach to PCR test design of primer and probe structure (“CoPrimers™”) +that eliminates one of the key vexing issues of PCR amplification: the exponential growth of primer-dimer pairs (false positives and false +negatives) which adversely interferes with identification of the target DNA/RNA. Using our proprietary test design system and proprietary +reagents, we have designed and obtained regulatory approval to sell PCR diagnostic tests for the detection of COVID-19, influenza, tuberculosis, +hepatitis B and C, human papillomavirus, malaria, chikungunya, dengue, and the Zika virus. These initial diagnostic tests were cleared +for use in clinical labs only and not for point-of-care or at-home use. +We +are currently developing a unique, groundbreaking portable diagnostic device and test system designed for point-of-care and at-home +use. The system is comprised of our PCR instrument that we refer to as the Co-Dx™ PCR Pro™ instrument, our proprietary +diagnostic test cup system and a mobile application to be installed on the user’s mobile device. We refer to the system as the +“Co-Dx™ PCR platform that is being designed to bring affordable, reliable polymerase chain reaction (“PCR”) +testing to patients in point-of-care and at-home settings. The Co-Dx PCR platform is subject to U.S. Food and Drug Administration +(“FDA”) review and is not available for sale at the time of this filing. In December 2023, we submitted the Co-Dx PCR +platform for review by the U.S. Food and Drug Administration (FDA) for Emergency Use Authorization (EUA). The submission included +the PCR Pro instrument, Co-Dx PCR COVID-19 detection test cups, and mobile app, all designed for use in point-of-care and at-home +settings. There is no guarantee that our Co-Dx PCR platform will receive the necessary regulatory approvals for commercialization, +or that, if regulatory approval is received, we will be able to successfully commercialize this platform. +Technology +We +believe our proprietary molecular diagnostics technology is paving the way for innovation in disease detection and life sciences research +through our enhanced detection of genetic material. For various reasons, including owning our own platform, we believe we will be able +to accomplish this faster and more economically than some competitors, allowing for significant margins while still positioning ourselves +as a low-cost provider of molecular diagnostics and screening services. For example, we were the first US-based company to receive a +CE-marking for a COVID-19 test in early 2020, as we worked to help slow the spread of the pandemic through our global network of distributors +covering clinical labs in more than 50 countries. Our Logix Smart COVID-19 test was designed, developed, submitted for regulatory approval +and ready to be used as an in vitro diagnostic or IVD in countries that accept a CE Mark as approval for use of the test in a period +of just over 30 days. This is a real-world example of how the CODX technology can be used in an evolving epidemic or pandemic to get +diagnostic tools in the hands of medical professionals in a timely manner. It can be similarly used to design a test for mutated strains +of the virus should they not be detectable using currently available tests. +In +addition, continued development has demonstrated the unique properties of our CoPrimer technology that we believe makes it ideally suited +for a variety of applications where specificity is key to optimal results, including multiplexing several targets, enhanced Single Nucleotide +Polymorphism (“SNP”) detection and enrichment for next generation sequencing. +Our +scientists use the complex mathematics of DNA/RNA PCR test design to engineer and optimize PCR tests and to automate algorithms that +rapidly screen millions of possible options to pinpoint the optimum design. The intellectual property we use in our business, consisting +of the predictive mathematical algorithms and patented molecular structure used in the testing process, which together represents a major +advance in PCR testing systems. CODX technologies are now protected by more than 20 granted or pending US and foreign patents, as well +as certain trade secrets and copyrights. Ownership of our proprietary platform permits us the advantage of avoiding payment of patent +royalties required by other PCR test systems, which may allow the sale of diagnostic PCR tests at a lower price than competitors, while +enabling us to maintain profit margins. +Our +proprietary test design process involves identifying the optimal locations on the target genes for amplification and pair the locations +with the optimized primer and probe structure to achieve outputs that meet the design input requirements identified from market research. +This is done by following planned and documented processes, procedures and testing. In other words, we use the data resulting from our +tests to verify whether we succeeded in designing what we intended. Verification involves a series of testing that concludes that the +product is ready to proceed to validation in an evaluation either in our laboratory or in an independent laboratory setting using initial +production tests to confirm that the product as designed meets the user needs. +4 +Using +our proprietary test design system and proprietary reagents, we have designed and obtained regulatory approval in the European Community +and in India to sell PCR diagnostic tests for the detection of COVID-19, influenza, tuberculosis, hepatitis B and C, human papillomavirus, +malaria, chikungunya, dengue, and the Zika virus. In the United States, we obtained Emergency Use Authorization (“EUA”) for +our Logix Smart ® COVID-19 detection test from the Food and Drug Administration, or +FDA, and we sell that test to qualified labs. In addition, our COVID-19 detection test and certain of our other suite of COVID-19 products +have been approved for sale in countries such as the United Kingdom, Australia and Mexico by the regulatory bodies in those countries +and have been registered for sale in many more countries. In connection with the sale of our tests we may sell diagnostic equipment from other manufacturers as self-contained +lab systems (which we refer to as the “MDx Device”). +In +addition to testing for infectious disease, the technology lends itself to identifying any section of a DNA or RNA strand that describes +any type of genetic trait, which creates several significant applications. We, in conjunction with our customers, have designed and licensed tests that identify genetic traits in plant and animal genomes. We also have three multiplexed tests developed +to test mosquitos for the identification of diseases carried by the mosquitos to enable municipalities to concentrate their efforts in +managing mosquito populations on the specific areas known to be breeding the mosquitos that carry deadly viruses. +Co-Dx +PCR Platform +We believe the benefits of affordable, +high-quality diagnostics should be available to everyone. High-quality point-of-care PCR testing plays a crucial role in healthcare. +It enables rapid diagnosis of infectious diseases, such as COVID-19 or tuberculosis, facilitating timely treatment and containment +measures. By delivering results on-site, it eliminates the need for sample transportation, reducing the risk that the sample is +transported incorrectly or lost enroute, reducing turnaround time to results, and allowing for immediate decision-making. The +quality of PCR testing at the point of care ensures reliable detection of pathogens, minimizing incorrect results. In short, +high-quality PCR testing at home and at the point of care enhances patient care, public health response, and helps control the +spread of infectious diseases. That is why we are developing the Co-Dx PCR platform utilizing our Co-Primers™ real-time PCR +technology for at-home and point-of-care testing. Because we believe that testing for COVID-19 and other infectious diseases will +continue to be a consideration for public health worldwide, we initiated the Co-Dx PCR platform to facilitate frequent, affordable, +reliable polymerase chain reaction (“PCR”) testing to patients in point-of-care and at-home settings, including schools, +businesses, and the hospitality industry. We believe this may be accomplished through the development of a testing system comprised +of a compact, relatively low-cost testing device, the Co-Dx PCR Pro instrument, together with proprietary diagnostic test cups that +work with the Co-Dx Pro instrument and a mobile application, that is easy to use by professionals and non-professionals, that can +provide PCR test results in around 30 minutes. We believe that as user test results are gathered in the cloud following completion +of tests, the data may be useful for governmental health agencies and the World Health Organization to determine where outbreaks of +infectious diseases may be occurring and enable them to act more quickly and efficiently and slow-down or perhaps even prevent +further spread. +The 6 ½” x 4 1/2” x 6”, 2 +lbs. Co-Dx PCR Pro instrument operates via a smartphone app with simple-to-follow instructions that includes videos to walk users through +every step, some sample swab collection to the straightforward instrument operation. Results are processed in the cloud and delivered +back to the user’s smartphone or tablet in about 30 minutes using software designed from the ground-up for this specific use. The +PCR tests themselves (contained in the simple but unique, innovative test collection cups) are powered by patented Co-Dx Co-Primers PCR +technology. +The initial diagnostic test designed for use on this +platform, an at-home and point-of-care COVID-19 PCR test, was ultimately facilitated by our development of a saliva or nasal swab-based +PCR test that does not require RNA/DNA extraction. The final result is believed to be approximately equivalent to those processed by a +high-complexity clinical laboratory. Our COVID-19 PCR platform test has the advantages of increased speed and ease of handling thanks +to lyophilization (or freeze-drying) of our testing reagents to allow for stability at room temperatures. In December 2023, we submitted +our proprietary Co-Dx PCR COVID-19 test cups with the Co-Dx PCR Pro instrument and mobile application, all designed for use in point-of-care +and at-home settings, for review by the U.S. Food and Drug Administration (FDA) for Emergency Use Authorization (EUA). We are also preparing +a 510K for submission to the FDA should the FDA decline to grant our emergency use authorization request. +We expect to develop further diagnostic tests for +use with the PCR Pro instrument, including a multiplex test for influenza, RSV and COVID-19. To that effect, we were awarded $1.2 million +in funding from the National Institutes of Health (NIH) as part of the Rapid Acceleration of Diagnostics (RADx®) Tech program for +completion of our upper respiratory panel diagnostic test for use on the Company’s Co-Dx PCR platform. We will utilize the funds from +the RADx Tech award to complete development of our flu A/B, COVID-19, and RSV multiplex test, preparatory for that test to begin clinical +trials on the Co-Dx PCR Pro instrument. The NIH launched the RADx initiative on April 29, 2020, with the goal of speeding innovation in +the development, commercialization, and implementation of technologies for COVID-19 testing, leveraging the existing NIH Point-of-Care +Technology Research Network. The RADx Tech program is managed by the National Institute of Biomedical Imaging and Bioengineering (NIBIB), +to support the accelerated development of tests and provide regulatory guidance during the COVID-19 pandemic and beyond. +5 +We +are also developing diagnostics tests for TB and HPV for use with our Co-Dx PCR platform. We have been awarded two grants in the amounts +of $10.23 million and $987,000 by the Bill & Melinda Gates Foundation to support the development and manufacture of TB and HPV tests +for our Co-Dx PCR platform. In 2014, all United Nations Member States and the World Health Organization (WHO) committed to ending the +global TB epidemic by 2030, before the COVID-19 pandemic slowed, stalled or reversed progress of global TB targets. The WHO estimates +that roughly 4.2 million cases of TB went unidentified in 2021 worldwide, representing nearly 40% of actual cases, highlighting the need +for a dramatic increase of affordable, high-quality, point-of-care TB diagnostics to enable rapid treatment decisions to be made for +a disease that has a mortality rate of about 50% if left untreated. The National Cancer Institute estimates that high-risk HPVs cause +roughly 5% of all cancers worldwide, with the rate among women being nearly 10 times higher than that for men and leading to an estimated +264,000 cervical cancer deaths each year according to the WHO. More than 85% of these deaths are in low- and middle-income countries, +and all of which the WHO believes can be dramatically reduced by access to diagnostics, vaccinations, and cancer screenings. +Infectious +Disease Product Offering +Using +our proprietary test design system and proprietary reagents, we and CoSara Diagnostics Pvt Ltd (“CoSara”), our joint venture +for manufacturing in India, design and sell PCR diagnostic tests for detection of diseases and pathogens such as COVID-19, influenza, +tuberculosis, hepatitis B and C, malaria, dengue, human papillomavirus, chikungunya, and Zika virus, all of which tests have been designed +and verified in our laboratories. Our tuberculosis test and Zika test received a CE Mark in 2018, and a triplex test for Zika, dengue +and chikungunya received a CE Mark in 2019, qualifying the tests to be sold throughout the European community and in most countries in +Central and South America. In December 2019, CoSara received a license to manufacture and sell tuberculosis, hepatitis B, hepatitis C, +human papillomavirus 16/18 and malaria tests in India from the Central Drugs Standard Control Organization (“CDSCO”). In +February 2020, we received a CE Mark for our Logix Smart COVID-19 test followed by an EUA by the FDA in April 2020. Also, in April 2020, +our COVID-19 test was approved for manufacture and sale in India by the CDSCO and in Mexico by the INDRE, Mexico’s equivalent to +the United States Center for Disease Control. In August 2020, we received approval from the Australian Department of Health Therapeutic +Goods Division to sell our COVID-19 test in Australia. +As +explained above, our Logix Smart COVID-19 test was designed, developed, submitted for regulatory approval and ready to be used as an +in vitro diagnostic or IVD in countries that accept a CE Mark as approval for use of the test in a period of just over 30 days. +This is a real-world example of how the CODX technology can be used in an evolving epidemic or pandemic to get diagnostic tools in the +hands of medical professionals in a timely manner. It can be similarly used to design a test for mutated strains of the virus should +they not be detectable using currently available tests. +Caribbean +and Central and South America +We +began selling PCR diagnostic tests to entities located in South and Central America and the Caribbean in 2018. In some of those countries, +there are limited regulatory hurdles, allowing us to begin offering our tests immediately. We have applied for and received registrations +for our tests in many of those countries that require registration, and our distributors in those countries have provided us with in-country +assistance in completing such registrations. +We +first offered our Zika test in this region because of the demand for such a test, followed by tests for tuberculosis, and our triplex +test for Zika, chikungunya, and dengue. Sales of those tests have not been material, but with the granting of a CE mark for our Logix +Smart COVID-19, we experienced an increase in sales in this region. +India +In +January 2017, the Company entered into an agreement to manufacture diagnostics tests for seven infectious diseases with a pharmaceutical +manufacturing company in India and formed CoSara as an Indian joint venture. The agreement provided for the construction of a manufacturing +plant and the manufacture of the tests named above and the joint sales and marketing of those tests in India. We have received a license +for the plant in Ranoli, India to manufacture approved tests and it is being used for testing and manufacturing of our products for the +Indian market. +As +mentioned above, the CDSCO has given us the approval for manufacture and sale of the 15 tests referred to above, and the Company’s +joint venture manufactures and sells those tests. The Company manages a reagent rental program in India with thermocyclers purchased +from third-party vendors and which we refer to as our MDx Device. The placement of thermocyclers in India has facilitated the sale of +the SaraGene PCR tests in India. The WHO 2022 Global Tuberculosis Report indicates that India is the country with the highest number +of cases of tuberculosis in the world. WHO tuberculosis statistics for India for 2022 give an estimated incidence figure of 2.82 million +cases of tuberculosis for India out of a global incidence of approximately 10.0 million. +6 +On +March 19, 2020, we announced that CoSara received authorization to manufacture and sell COVID-19 tests in India. Those tests in India +are branded as SaraGene COVID-19 tests and are sold exclusively by CoSara. The Indian government places restrictions on the price that +could be charged for COVID-19 tests which limited the revenue in India more than we experienced in other parts of the world. At the time +of this report, CoSara has received CDSCO clearance for RT-PCR tests for Mycobacterium tuberculosis, malaria, hepatitis B, hepatitis +C (including viral load tests for both hepatitis B and C), human papillomavirus (HPV), a test for high-risk HPV, two COVID-19 assays, +chikungunya, dengue, a dengue/chikungunya duplex test, an influenza A/influenza B/COVID-19 (“ABC”) multiplex test, and in +2024 CDSCO cleared the manufacture and sell SARAPLEX™ Influenza Multiplex (IFM) Test Kit to clinical laboratories as an in vitro +diagnostic for the detection and differentiation of Influenza A and Influenza B. +Europe +Molecular +diagnostics, such as our tests, are governed in Europe by the framework for IVDs, which encompasses diagnostic products such as reagents, +instruments and systems intended for use in diagnosis of disease. The regulatory system for some IVDs has historically allowed for a +self-certification procedure, placing heavy responsibility on manufacturers. Non self-certified products were subject to the same standards +as self-certified products but were also subject to audit and review by a notified body prior to receiving approval to be CE-marked. +A CE-marking is a manufacturer’s declaration that a product meets the requirements of the applicable European Commission directive. +Examples of current obligations include having in place a qualitative manufacturing process, user instructions that are clear and fit +for purpose, and ensuring that the ‘physical’ features of devices and diagnostics do not pose any danger. If a product fulfils +these and other related control requirements, it may be CE-marked, as an indication that the product is compliant with EU legislation +and sold in the European Union. We have received CE Marks for six of our tests including for COVID-19, COVID-19 (2 gene test), ABC (a +triplex test for Flu A, Flu B and COVID-19), a DS (Direct Saliva, extraction-free) COVID-19 test, tuberculosis, Zika, and our Zika, dengue, +chikungunya triplex tests. The European Commission has revised its directive governing the CE- marking of IVDs, which included +reclassifying which IVDs may be self-certified, and which may not. As a result of this change in directive and reclassification, substantially +all of the Company’s products are now subject to audit and review by a notified body, as well as a more rigorous clinical evaluation +process, prior to receiving approval to be CE-marked. +We +are ISO 13485:2016 certified, relating to the design and manufacture of our medical device products. The ISO certification indicates +that we meet the standards required to pursue CE-marking for certain of our products and affix a CE-marking for sales of our products +in countries accepting CE-marking (not in the United States). +United +States +The +FDA has granted permission for us to export all of our IVD products. The FDA’s permission to export was granted under Section 801(e) +of the Federal Food, Drug, and Cosmetic Act, as amended (the “FDC Act”). Section 801(e) of the FDA Act covers certain medical +devices that have not yet received an approved Premarket Approval in the United States by the FDA, such as our products. We have not +commenced any Premarket Approval steps with the FDA. Section 801(e) of the FDA Act applies to medical devices that are acceptable to +the importing country and that are manufactured under the FDA’s Good Manufacturing Practices. We have received EUA for our COVID-19 +test, which allows sales to qualified labs in the United States and facilitates the registration for sale in other countries as well. +Under the FDA’s existing policy, the FDA continues to review a prioritized subset of COVID-19 tests for EUAs, and emphasizes that +traditional device premarket review pathways remain open to all developers. We intend to pursue all appropriate FDA review pathways for +products under development, including traditional premarket review pathways. +Under +our EUA, we are actively selling our Logix Smart COVID-19 test to CLIA certified laboratories in the United States. The CLIA labs are +able to use our test, or to further validate our COVID-19 tests (or other tests) as Laboratory Developed Tests (LDTs), which refers to +a diagnostic test that has been validated for use in the CLIA lab. LDTs may be used by the lab only in that laboratory. CLIA laboratories +develop the performance characteristics, perform the analytical validation for their LDTs and obtain licenses to offer them as diagnostic +services. We are currently marketing our Logix Smart COVID-19 test to CLIA laboratories throughout the US. +7 +Market +Opportunity +The +market opportunity for our tests changed radically with the emergence of the COVID-19 pandemic. Because we were able to respond rapidly +and produce a quality product, we have been able to build a worldwide distribution network, most +of which have been the sales network that has allowed us to export products throughout the world. Our network of distributors +that we have built over the past three years will serve us well in sales and distribution of other diagnostic tests and our forthcoming +PCR diagnostic platform. +The +molecular diagnostics market is a fast-growing portion of the in vitro (test tube-based, controlled environment) diagnostics market. +There are several advantages of PCR tests, such as the ones we market and sell, over other forms of diagnostic testing. These advantages +include higher specificity and sensitivity, the ability to perform multiplex tests and the ability to test for drug resistance or for +individual genes. +Mosquito +Vector Control Services +In +response to market demand, in June 2019 we introduced our first diagnostics tests to be used exclusively to test for mosquito borne pathogens +in mosquito populations. Municipalities in the US and many other countries in the world are concerned about the diseases carried by mosquitos, +which infect the human population. To prevent outbreaks of potentially harmful viruses such as Zika or West Nile from infecting the public, +many municipalities conduct mitigation operations to eliminate the mosquito populations carrying the diseases. Because it is too expensive +and potentially harmful to the environment to spray all mosquito breeding areas, municipalities identify which particular area has mosquitos +that are carrying the harmful viruses. To know where the host mosquitos with the harmful viruses are located, traps are set, mosquitos +collected and then tested to find the areas that most needed spraying. There are over 3,000 mosquito abatement districts throughout the +United States and almost all of them conduct testing to help make the spraying more effective. +Our +first vector related test was a triplex test that tests for West Nile, western equine and St. Louis encephalitis. We began shipping the +tests in June 2019. We added a second test that tests mosquitos for Zika, chikungunya and dengue in a triplex test. Finally, in November +2019, we completed a test for West Nile, eastern equine and St. Louis encephalitis, specifically for use in the eastern United States. +As a result, mosquito abatement districts can test for three target viruses in one test as compared to performing three different tests +using other market available tests. Our products allow municipalities to obtain test results in a matter of hours, instead of the weeks +they might otherwise have to wait for a central lab to process the mosquito tests. +We +have sold our Vector Smart™ test products and/or related lab equipment to testing districts in different sections of the country +and are marketing our products through trade shows, electronic and regular mail solicitations. +Liquid +Biopsy for Cancer Screening +The +enhanced specificity of our technology opens up some unique applications for liquid biopsy, demonstrating its ability to detect small +quantities of mutations associated with cancer within an environment of large amounts of normal DNA, as we position the Company to take +part in this historic and challenging development in human health care. +Agricultural +Applications +SNP +detection is also used in the agricultural industry to identify variations in crop genomes to achieve improved seed viability and other +desired characteristics, including drought resistance, disease resistance, pest resistance and higher yield. +In +mid-2017, the Company was first approached by a large agribusiness to evaluate our ability to multiplex certain target genomes. The results +of the development project have successfully demonstrated our ability to not only multiplex the target genomes, but targeted SNP’s +as well. The project was undertaken in conjunction with the manufacturer of our CoPrimers tests. The results of the project encouraged +the parent of our manufacturer to seek a world-wide licensing arrangement for our CoPrimers in the agricultural industry, which was completed +in October 2018. Pursuant to the exclusive license for the agronomics industry, the licensee pays us a royalty for all CoPrimers sold +to the licensee’s customers. In January 2019, the licensee formally introduced the product at a large agricultural conference and +has branded the product under the name “BHQ CoPrimers”. +8 +Additional +Licensing and Assay Development +We +believe the unique properties of our CoPrimers technology make them ideally suited to a variety of applications where sensitivity is +key to optimal results, including multiplexing several targets, enhanced SNP detection and enrichment for next generation sequencing. +Our licensee for our agricultural testing requested an expansion of our license agreement to include test design services for their customers +and potential customers, both in the infectious disease arena as well as for agricultural customers. The license was amended in July +2019 and we expect to derive a license fee from our licensee for its design services. If any of its customers desire to commercialize +the tests designed, they will need to seek a commercial license directly from us. Thanks to these unique characteristics of CoPrimers, +research companies and institutions have requested that we design diagnostics to locate and identify uncommon gene sequences and SNPs +and create tests for the target sequences in a multiplexed reaction. This application of our technology is in its beginning stages, but +we believe that the results from our initial research indicate a significant step forward in defining the capabilities of our technology, +which we believe can be translated to revenue producing licensing arrangements. However, there can be no guarantee that we will be able +to develop the requested capabilities, or that we will be able to successfully commercialize this application of our technology. +Competitive +Advantages of Co-Diagnostics +We +believe that we have the following competitive advantages: +● +Affordability: +Lower-cost test kits, a low-cost MDx-device, and an affordable Co-Dx PCR platform for at-home and point-of-care testing (the +platform is subject to FDA review and not available for sale at the time of this filing). +● +Flexibility: +CODX’s tests have been designed to run on many customers’ DNA/RNA diagnostic testing machines. Our technology +is well suited to the new generation of point-of-care testing (“POCT”), compact and portable analysis machinery for field, +clinical and office applications. +● +Speed : +We believe our rapid assay design system software provides shorter time to product release. This has been demonstrated with the +conception, design, product manufacture, clinical verification and submission for a CE Mark for our Logix Smart COVID-19 test being +approximately 30 days. +● +Accuracy : +We believe our technology allows us to build tests that are highly sensitive and specific, the two benchmarks for accuracy in PCR +testing. +● +Personalized +Medicine : We project that rising health care costs in developed and developing nations will increasingly require that health +care systems be patient-specific to eliminate waste, misdiagnoses, and ineffectiveness. A critical component will be accurate, more +affordable DNA-based diagnostics, especially in at-home and POCT settings, for which we are developing products. +● +Low-cost +Provider : Our platform technology obviates the need to pay patent royalties typically required of our competitors, which +use third-party patented test platforms to design their tests. +● +Worldwide +Footprint : With a dynamic technology that encompasses markets worldwide, we anticipate that we can identify the best target +markets, not only in high burden developing countries but also in developed nations. +● +Data Collection : With the anticipated deployment +of the Co-Dx PCR platform we expect to play a role in centralizing global data collection on infectious diseases that may contribute +to faster vaccination and therapeutic responses from health authorities. +● +Growth +Industry Category : We believe that real-time PCR testing is the fastest-growing segment of in vitro diagnostic testing. +● +Combination +Product Offering : Our sensitive tests can be a well-designed match for a new generation of compact and other small POCT devices +now entering the market, including our own MDx and Co-Dx PCR Pro instruments. Used together, we believe these affordable tests and +devices have the potential to revolutionize the molecular diagnostics industry in cost, speed of test results and simplification. +● +Multiplexing: +Our existing multiplexed tests demonstrate that our CoPrimer-designed tests are able to test for multiple targets in the +same sample without the distortion caused by false negatives and false positives that often occur in multiplexed tests. +9 +Intellectual +Property +Much +of our future success and value depends on our proprietary technology, and therefore, our patent and intellectual property strategy is +of critical importance. Currently, our flagship CoPrimers technology is covered by two U.S. patents titled “Cooperative primers, +probes, and applications thereof” as well as by granted and pending foreign counterparts. We have another three U.S. patents directed +to our earlier work in primer and assay designs. For more recent works, we have filed international and U.S. patent applications directed +to “Methods and Compositions for Next Generation Sequencing (NGS) Library Preparation,” “Allele-Specific Design of +Cooperative Primers for Improved Nucleic Acid Variant Genotyping,” “Methods and Compositions Related to Cooperative Primers +and Reverse Transcription,” and “Systems, Methods, and Apparatus for Automated Self-Contained Biological Analysis” +which is the basis of our at-home and point-of-care PCR system. We intend to continue building our patent portfolio as development continues +and resources are available. +We +also protect some of our technology and know-how as trade secrets and, where appropriate, we use and register trademarks to protect and +strengthen our products and proprietary brands. All trademarks, trade/product names, graphics and logos of Co-Diagnostics contained herein +are trademarks of Co-Diagnostics or its subsidiary, as applicable, in the U.S. and/or other countries. Solely for convenience, we may +refer to trademarks in this Annual Report on Form 10-K without the ™ or ® symbols, but such references are not intended to +indicate, in any way, that we will not assert, to the fullest extent permitted by law, our rights to our trademarks. +Major +Customers +The +Company had certain customers which were each responsible for generating 10% or more of the total revenue for the years ended December +31, 2023 and 2022, respectively. Two customers accounted for approximately 28% of product revenue for the year ended December 31, 2023 +and one customer accounted for approximately 37% of product revenue for the year ended December 31, 2022. One granting agency accounted +for 100% of grant revenue for the year ended December 31, 2023. These customers and granting agencies may not account for the same percentage +of product revenue or grant revenue in future periods. If +we were to sell nothing to those customers in the future, it would have a material adverse effect on our financial condition unless we +were able to replace those customers with others. +Competition +The +molecular diagnostics industry is extremely competitive. There are many firms that provide some or all of the products we provide and +provide many diagnostic tests that we have yet to develop. Many of these competitors are larger than us and have significantly greater +financial resources. Because we are more recently established, many of our competitors have a competitive advantage in the diagnostic +testing industry because they also have other lines of business in the pharmaceutical industry from which they derive revenues and for +which they are well known and respected in the medical profession. We will need to overcome the disadvantage of being perceived as a +start up with no significant recognition from the medical and testing professionals, although we believe this is changing as we continue +to market our Logix Smart COVID-19 tests and other tests in the United States to well-known and successful laboratories. Many of these +competitors already have an established customer base with industry standard technology, which we must overcome to be successful. In +the diagnostic testing and POCT industries, we compete with such companies as BioMerieux, Siemens, Qiagen, Cue Health, Lumira Dx and +Cepheid and with such pharmaceutical companies as Abbott Laboratories, Becton Dickinson and Johnson and Johnson. We also compete with +companies from Asia in certain markets who are willing to sell their tests for much less than we sell our tests, which creates competitive +price pressure on us in certain regions, particularly Asia and Latin America. +10 +We +expect competition to continue to increase as other established and emerging companies enter the market, as customer requirements evolve, +and as new products, services and technologies are introduced. Some of our existing or new competitors may have strong +relationships with current and potential customers, including governmental authorities, and, as a result, may be able to respond more +quickly to new or changing regulatory requirements, new or emerging technologies, and changes in customer requirements. +Government +Regulation +In +the United States, we are regulated by the FDA and our products must be approved, cleared, or authorized by the FDA before we are allowed +to sell our tests in the United States as in vitro diagnostics. The FDA granted us an EUA to manufacture and sell our Logix Smart +COVID-19 test to CLIA labs in the United States. We are ISO 13485:2016 certified, relating to the design and manufacture of our medical +device products. Being ISO certified greatly facilitates our applications for CE-Marking, which allows us to sell any CE Marked test +in most countries in Europe, South America and Asia, depending on the country and following that country’s registration process. +We currently have CE Markings issued for our Logix Smart COVID-19 test, tuberculosis test, our Zika virus test, a triplex test that tests +for Zika, dengue, and chikungunya simultaneously, a triplex “ABC” test that identifies and distinguishes between Flu A, Flu +B and Covid-19, our SARS-CoV-2 2-gene multiplex test, and our DS (Direct Saliva, extraction-free) COVID-19 test. In addition, our Logix +Smart COVID-19 has received the required license to manufacture and sell in India from India’s CDSCO, and The National Epidemiology +Institute in Mexico evaluated our Logix Smart COVID-19 and ABC tests and approved them for sale in Mexico. We have also received approval +to sell in Australia. +Employees +As +of December 31, 2023, we had 155 full-time and part-time employees at our executive offices and lab facilities in Salt Lake City, Utah. +We have engaged independent contractors to promote the use of our products and develop outlets for products and employ the services of +independent sales representatives on an “as needed” basis. +We +consider our people and the way we work to support each other and serve our customers to be critical to our success. The key human capital +measures and objectives that we focus on in managing our business are: maintaining a strong and collaborative company culture, increasing +our diversity, inclusion and belonging, offering fair and competitive compensation and benefits, investing in people and organizational +development, protecting and enriching employee health and wellness, and sustaining a culture of respectful and effective communications. +Organizational +History and Corporate Information +We +were incorporated as Co-Diagnostics, Inc., in Utah on April 18, 2013. Our principal executive office is located at 2401 S. Foothill Drive, +Salt Lake City, Utah 84109. Our telephone number is (801) 438-1036. Our web address is www.codiagnostics.com . The contents of +our website are not incorporated by reference in this Annual Report. +11 +ITEM +1A. RISK FACTORS +Risks +Related to Our Business and Industry +We +have limited commercial history upon which to base our prospects and are not certain that we will achieve profitability in the future. +We +have a limited operating history. We began operations in April 2013. Our accumulated retained earnings were $4.6 million and $39.9 million +as of December 31, 2023 and 2022, respectively. During the calendar years ending December 31, 2023 and 2022 we experienced a decline +in demand for our Logix Smart COVID-19 and other COVID-19 tests and operated at a net loss during the periods. We do not have any way +of predicting when or if we will achieve profitability again. Potential investors should be aware of the difficulties normally encountered +by a new enterprise, many of which are beyond our control, including substantial risks and expenses in the course of developing new diagnostic +tests, establishing or entering new markets, organizing operations and marketing procedures. The likelihood of our success must be considered +in light of these risks, expenses, complications and delays, and the competitive environment in which we operate. There is, therefore, +nothing at this time upon which to base an assumption that our business plan will prove successful, and we may not be able to generate +significant revenue, raise additional capital or operate profitably. We will continue to encounter risks and difficulties frequently +experienced by early commercial stage companies, including scaling up our infrastructure and headcount, and may encounter unforeseen +expenses, difficulties or delays in connection with our growth. In addition, as a result of the start-up nature of our business, we expect +to continue to sustain substantial operating expenses and may not be able to continue generating sufficient revenues to cover expenditures. +Any investment in our company is therefore highly speculative and could result in the loss of any investment. +Our +future success is dependent on our development of our Co-Dx PCR platform and securing regulatory approval for the platform including +the PCR Pro instrument and related diagnostic tests, demand for infectious disease diagnostics and upon our ability to develop and market +other commercially accepted diagnostic tests for our PCR platform. +Our +future success will depend, in part, on our development of our Co-Dx PCR platform and securing regulatory approval for the platform including +the PCR Pro instrument and related diagnostic tests, our ability to develop and sell sufficient quantities of other diagnostics tests, +and our ability to successfully and profitably market our Co-Dx PCR platform. Attracting new customers and distribution networks requires +substantial time and expense. Any failure to obtain regulatory approval for our product candidates and to increase sales of our diagnostic +tests in sufficient quantities to achieve profitability in a timely manner would adversely affect our operating results. Many factors +could affect the market acceptance and commercial success of any of our diagnostic tests and devices, including: +● +Our +ability to develop additional infectious disease diagnostic tests for which there is a commercial market; +● +Our +ability to obtain regulatory clearance to commercialize our product candidates; +● +our +ability to convince our potential customers of the advantages and economic value of our tests over competing technologies and diagnostic +tests; +● +the +breadth of our test menu relative to competitors; +● +changes +to policies, procedures or currently accepted best practices in clinical diagnostic testing; +● +the +extent and success of our marketing and sales efforts; and +● +our +ability to manufacture in quantity our commercial diagnostic tests and meet demand in a timely fashion. +12 +The +diagnostic market is highly competitive, and we may not be able to compete effectively against the larger, well-established companies +that dominate this market or emerging and small innovative companies that may seek to obtain or increase their share of the market. +The +markets for diagnostic products are intensely competitive, and many of our competitors are much larger and have substantially more financial +and human resources than we do. Many have long histories and strong reputations within the industry, and a relatively small number of +companies dominate these markets. +These +companies enjoy significant competitive advantages over us, including: +● +broad +product offerings, which address the needs of health care providers in a wide range of applications; +● +products +that are supported by long-term clinical data; +● +greater +experience in, and resources for, launching, marketing, distributing and selling products, including strong sales forces and established +distribution networks; +● +extensive +intellectual property portfolios and greater resources for patent protection; +● +greater +financial and other resources for product research and development; +● +greater +experience in obtaining and maintaining FDA and other regulatory clearances and approvals for products and product enhancements; +● +established +manufacturing operations and contract manufacturing relationships; +● +significantly +greater name recognition and widely recognized trademarks; and +● +established +relationships with healthcare providers and payers. +Our +products and any product candidates that we may introduce into the market may not enable us to overcome the competitive advantages of +these large and dominant companies. In addition, even if we successfully introduce additional product candidates into the market, emerging +and small innovative companies may seek to increase their market share and they may eventually possess competitive advantages, which +could adversely impact our business. Our competitors may also employ pricing strategies that could adversely affect the pricing of our +products. +We +depend on a limited number of third-party suppliers for key raw materials used in the manufacturing of our products, and the loss of +these third-party suppliers or their inability to supply us with adequate raw materials could harm our business. +We +rely on a limited number of third-party suppliers for the raw materials required for the production of our diagnostic products and product +candidates. Our dependence on a limited number of third-party suppliers involves several risks, including limited control over pricing, +availability, quality, and delivery schedules for raw materials. We have no supply agreements in place with any of our suppliers and +cannot be certain that our current suppliers will continue to provide us with the quantities of raw materials that we require or that +satisfy our anticipated specifications and quality requirements. Any supply interruption in limited or single sourced raw materials could +materially harm our ability to manufacture our products until a new source of supply, if any, could be identified and qualified. We may +be unable to find a sufficient alternative supply channel within a reasonable time or on commercially reasonable terms. Any performance +failure on the part of our suppliers could delay the production of our products and product candidates and delay the development and +commercialization of our product candidates, including limiting supplies necessary for commercial sale, clinical trials and regulatory +approvals, which could have a material adverse effect on our business. +In +order to be successful, we must expand our available product lines by commercializing new product candidates, but we may not be able +to do so in a timely fashion and at expected costs, or at all. +Although +we are currently manufacturing diagnostic kits for commercialization, in order to be successful, we will need to expand our product lines +to include other diagnostic products. To succeed in our commercialization efforts, we must effectively continue product development and +testing, find new strategic partners, obtain regulatory clearances and approvals, and enhance our sales and marketing capabilities. Because +of these uncertainties, there is no assurance that we will succeed in bringing any of our current or future product candidates to market. +If we fail in bringing our product candidates to market, or experience delays in doing so, we will not generate revenues as planned and +will need to curtail operations or seek additional financing earlier than otherwise anticipated. +We +are dependent on our senior management team, scientific team, and external advisors, and the loss of any of them could harm our business, +including by adversely affecting our ability to effectuate our business strategy. +The +members of our current senior management team may not be able to successfully implement our strategy. In addition, we have not entered +into employment agreements with any of the members of our senior management team. There are no assurances that the services of any of +these individuals will be available to us for any specified period of time. The successful integration of our senior management team, +the loss of members of our senior management team, scientific team and key external advisors, or our inability to attract or retain other +qualified personnel or advisors could have a material adverse effect on our business, financial condition and results of operations. +We may not have a sufficient number of qualified personnel to effectuate our business strategy, which could have a material adverse effect +on our business, financial condition and results of operations. +13 +If +we experience significant disruptions in our information technology systems, our business, results of operations and financial condition +could be adversely affected. +The +efficient operation of our business depends on our information technology systems. We rely on our information technology systems to effectively +manage our sales and marketing, accounting and financial functions; manufacturing processes; inventory; scientific and product development +functions; and our research and development functions. As such, our information technology systems are vulnerable to damage or interruption +including from earthquakes, fires, floods and other natural disasters; terrorist attacks and attacks by computer viruses or hackers; +power losses; and computer systems, or Internet, telecommunications or data network failures. The failure of our information technology +systems to perform as we anticipate or our failure to effectively implement new systems could disrupt our entire operation and could +result in decreased sales, increased overhead costs, excess inventory and product shortages, all of which could have a material adverse +effect on our reputation, business, results of operations and financial condition. +Cybersecurity +risks and the failure to maintain the integrity of company, employee or customer data could expose us to data loss, litigation and liability, +and our reputation could be significantly harmed. +We +and third-party service providers collect and retain large volumes of data, including personally identifiable information regarding clinical +trial participants and others, for business purposes, including for regulatory, research and development and commercialization purposes, +and our collaborators’ various information technology systems enter, process, summarize and report such data. We also maintain +personally identifiable information about our employees. The integrity and protection of our company, employee and clinical data is critical +to our business. We are subject to significant data security and privacy laws and regulations. These regulations impose significant requirements +on how we maintain, use, and protect such information. Maintaining compliance with these evolving regulations and requirements could +be difficult and may increase our expenses. In addition, a penetrated or compromised data system or the intentional, inadvertent or negligent +release or disclosure of data could result in theft, loss or fraudulent or unlawful use of company, employee or clinical data which could +harm our reputation, disrupt our operations, or result in remedial and other costs, fines or lawsuits. +Risks +Related to Regulatory Approval of Our Products and Other Government Regulations +We +received Emergency Use Authorization or EUA for our COVID-19 test in US. We applied for Emergency Use Authorization for our PCR platform +which included the PCR Pro instrument and the COVID 19 diagnostic test cup and mobile app. The FDA may not timely grant the EUA we filed +for the PCR platform or may require that we submit a 510K application rather than EUA. For our existing EUA and any new EUA, the FDA +may revoke any EUA where it is determined that the underlying health emergency no longer exists or warrants such authorization, which +would adversely impact our ability to market our COVID-19 test in the United States. +The +FDA has the authority to grant an EUA to allow unapproved medical products to be used in an emergency to diagnose, treat or prevent serious +or life-threatening diseases or conditions when there are no adequate, approved and available alternatives. During the COVID 19 pandemic +the FDA determined that circumstances exist to justify the authorization of emergency use of medical devices, including alternative products +used as medical devices, during the COVID-19 pandemic. On April 3, 2020, we received an EUA from the FDA for our Logix Smart Coronavirus +Disease 2019 (COVID-19) kit for use on individuals who are suspected of COVID-19 by their healthcare provider. We +cannot predict how long the EUA for our COVID-19 test will remain in place. The FDA may revoke an EUA where it is determined that +the underlying health emergency no longer exists or warrants such authorization. The FDA may take such a position at any time and without +notice and, therefore, we cannot predict how long our EUAs will remain in place. The FDA may also revoke an EUA when the circumstances +justifying its issuance no longer exist, such as when an alternative is authorized for marketing through the standard procedures, including +through a 510(k) clearance. +We +applied for Emergency Use Authorization for our PCR platform which included the PCR Pro instrument and the COVID 19 diagnostic test cup +and mobile app. The FDA may not timely grant the EUA we filed for the PCR platform or may require that we submit a 510K application rather +than EUA which could extend the time for authorization to begin commercializing the PCR platform. There can be no assurances that the +FDA will authorize any request for additional and/or amended EUAs and if we do not receive the authorization, our business, financial +condition, results of operations and future growth prospects could be materially and adversely affected. +If +either of our existing EUAs is revoked or our existing EUA applications are denied prior to us having received regulatory approval to +commercialize our COVID-19 test through a traditional pathway, we may not be able to obtain required clearances or approvals in a timely +manner, or at all, and one or more of our competitors may obtain the necessary clearances or approvals for their products before we do. +In addition, we would be required to cease our commercialization efforts, which would substantially and negatively impact our business. +As a result, any such revocation could adversely impact our business, financial condition and results of operations. +14 +Our +long-term success depends substantially on our ability to obtain regulatory clearance or approval and thereafter commercialize our product +candidates; we cannot be certain that we will be able to do so in a timely manner or at all. +The +process of obtaining regulatory clearances or approvals to market a medical diagnostic from the FDA or similar regulatory authorities +outside of the United States can be costly and time consuming, and there can be no assurance that such clearances or approvals will be +granted on a timely basis, or at all. The FDA’s 510(k) clearance process generally takes one to six months from the date of submission, +depending on whether a special or traditional 510(k) premarket notification has been submitted, but can take significantly longer. An +application for premarket approval, or PMA, must be submitted to the FDA if the device cannot be cleared through the 510(k) clearance +process or is not exempt from premarket review by the FDA. The PMA process almost always requires one or more clinical trials and can +take two to three years from the date of filing, or even longer. +If +we are required to obtain approval of any of our products through the PMA process, the costs associated with such a process will be significant, +which could adversely affect our financial performance and results of operations. In addition, a submission through the PMA process would +require us to delay commercialization of such product candidates until after approval is received, if ever. If we are unable to commercialize +our product candidates in a timely manner, or at all, our business will be adversely affected. +Similar +to our compliance with U.S. regulatory requirements, we must obtain and comply with international requirements, in order to market and +sell our products outside of the United States and we may only promote and market our products, if approved, as permitted by applicable +regulatory authorities. There is no guarantee that we will receive the necessary regulatory approvals for our product candidates either +inside the United States or internationally. If our product candidates do not receive necessary regulatory approvals, our business could +be materially and adversely affected. +Our +current and future relationships with third-party payers and current and potential customers in the United States and elsewhere may be +subject, directly or indirectly, to applicable anti-kickback, fraud and abuse, false claims, transparency, health information privacy +and security and other healthcare laws and regulations, which could expose us to criminal sanctions, civil penalties, contractual damages, +reputational harm administrative burdens and diminished profits and future earnings. +Our +current and future arrangements with third-party payers and current and potential customers, including providers and physicians, may +expose us to broadly applicable fraud and abuse and other healthcare laws and regulations, including, without limitation, the federal +Anti-Kickback Statute and the federal False Claims Act, which may constrain the business or financial arrangements and relationships +through which we sell, market and distribute our products. In addition, we may be subject to transparency laws and patient privacy regulations +by U.S. federal and state governments and by governments in foreign jurisdictions in which we conduct our business. The applicable federal, +state and foreign healthcare laws and regulations that may affect our ability to operate include: +● +the +federal Anti-Kickback Statute, which prohibits, among other things, persons from knowingly and willfully soliciting, offering, receiving +or providing remuneration, directly or indirectly, in cash or in kind, to induce or reward, or in return for, either the referral +of an individual for, or the purchase, order or recommendation of, any good or service, for which payment may be made under federal +healthcare programs, such as Medicare and Medicaid; +● +federal +civil and criminal false claims laws and civil monetary penalty laws, including the federal False Claims Act, which impose criminal +and civil penalties, including civil whistleblower or qui tam actions, against individuals or entities for knowingly presenting, +or causing to be presented, to the federal government, including the Medicare and Medicaid programs, claims for payment that are +false or fraudulent or making a false statement to avoid, decrease or conceal an obligation to pay money to the federal government; +● +the +federal Health Insurance Portability and Accountability Act of 1996, or HIPAA, which imposes criminal and civil liability for executing +a scheme to defraud any healthcare benefit program or making false statements relating to healthcare matters; +● +HIPAA, +as amended by the Health Information Technology for Economic and Clinical Health Act of 2009, or HITECH, and their respective implementing +regulations, which impose obligations on covered healthcare providers, health plans, and healthcare clearinghouses, as well as their +business associates that create, receive, maintain or transmit individually identifiable health information for or on behalf of a +covered entity, with respect to safeguarding the privacy, security and transmission of individually identifiable health information; +● +the +Physician Payments Sunshine Act, which requires (i) manufacturers of drugs, devices, biologics and medical supplies for which payment +is available under Medicare, Medicaid or the Children’s Health Insurance Program, with specific exceptions, to report annually +to CMS information related to certain “payments or other transfers of value” made to physicians, which is defined to +include doctors, dentists, optometrists, podiatrists and chiropractors, and teaching hospitals, (ii) applicable manufacturers and +applicable group purchasing organizations to report annually to CMS ownership and investment interests held in such entities by physicians +and their immediate family members, with data collection beginning on August 1, 2013, (iii) manufacturers to submit reports to CMS +by the 90 th day of each calendar year, and (iv) disclosure of such information by CMS on a publicly available website; +and +● +analogous +state and foreign laws and regulations, such as state anti-kickback and false claims laws, which may apply to sales or marketing +arrangements and claims involving healthcare items or services reimbursed by non-governmental third-party payers, including private +insurers; state and foreign laws that require medical device companies to comply with the medical device industry’s voluntary +compliance guidelines and the relevant compliance guidance promulgated by the federal government or otherwise restrict payments that +may be made to healthcare providers; state and foreign laws that require medical device manufacturers to report information related +to payments and other transfers of value to physicians and other healthcare providers or marketing expenditures; and state and foreign +laws governing the privacy and security of health information in certain circumstances, many of which differ from each other in significant +ways and often are not preempted by HIPAA, thus complicating compliance efforts. +15 +Efforts +to ensure that our business arrangements with third parties will comply with applicable healthcare laws and regulations may involve substantial +costs. It is possible that governmental authorities will conclude that our business practices may not comply with current or future statutes, +regulations or case law involving applicable fraud and abuse or other healthcare laws and regulations. If our operations are found to +be in violation of any of these laws or any other governmental regulations that may apply to us, we may be subject to significant civil, +criminal and administrative penalties, including, without limitation, damages, fines, imprisonment, exclusion from participation in government +healthcare programs, such as Medicare and Medicaid, and the curtailment or restructuring of our operations, which could have a material +adverse effect on our business. If any of the physicians or other healthcare providers or entities with whom we expect to do business, +including our collaborators, are found not to be in compliance with applicable laws, they may be subject to criminal, civil or administrative +sanctions, including exclusions from participation in government healthcare programs, which could also materially affect our business. +We +are subject to stringent and changing data protection laws, privacy policies and data protection obligations, which continue to evolve +and change over time. The actual or perceived failure by us or our third-party service providers or vendors to comply with such obligations +could harm our reputation, subject us to significant fines and liability, or otherwise adversely affect our business. +We +are subject to numerous data protection laws that govern the processing of individually identifiable information and health information +and other sensitive and personal information in the jurisdictions in which we operate. In many instances, these data protection laws, +regulations and standards apply not only to disclosures to third parties, but also to transfers of information between or among us and +other parties with which we have commercial relationships. The regulatory framework for data privacy, data security and data transfers +worldwide is rapidly evolving and, as a result, interpretation and implementation standards and enforcement practices are likely to remain +uncertain for the foreseeable future. These data protection laws may be interpreted and applied differently over time and from jurisdiction +to jurisdiction, and it is possible that they will be interpreted and applied in ways that will materially and adversely affect our business, +financial condition and results of operations. Failure to comply with any of these data protection laws could result in enforcement actions +against us, including fines, imprisonment of company officials and public censure, claims for damages by affected individuals, damage +to our reputation and loss of goodwill, any of which could have a material adverse effect on our business. +There +are numerous U.S. federal and state laws and regulations related to the privacy and security of personal information. These laws and +regulations include the Health Insurance Portability and Accountability Act of 1996, or HIPAA, as amended by the Health Information Technology +for Economic and Clinical Health Act of 2009, or HITECH, and their implementing regulations, or collectively referred to as the HIPAA +Rules, which establish a set of national privacy and security standards to safeguard Protected Health Information, or PHI, by health +plans, healthcare clearinghouses and certain healthcare providers, referred to as covered entities, and the business associates and their +subcontractors with whom such covered entities contract for services that involve the creation, receipt, maintenance or transmission +of PHI for or on behalf of a covered entity or another business associate. HIPAA requires covered entities and business associates to, +among other things, develop and maintain policies and procedures with respect to PHI that is used or disclosed, including the adoption +of administrative, physical and technical safeguards to protect such information and ensure the confidentiality, integrity and availability +of electronic PHI. As this applies to our business, we are required to maintain security standards for any PHI that we create, receive, +maintain or transmit. For example, we plan to offer cloud-based portal software to help our customers more efficiently use our products. +The software will maintain security safeguards that are designed to be consistent with the HIPAA Rules, but we cannot guarantee that +these safeguards will not fail or that they will not be deemed inadequate in the future. In addition, we could be subject to periodic +audits for compliance with the HIPAA Privacy and Security Standards by the U.S. HHS, and our customers. The U.S. HHS Office for Civil +Rights may impose significant penalties on entities subject to HIPAA for a failure to comply with a requirement of the HIPAA Rules. If +we are unable to properly protect the privacy and security of the PHI of our customers, we could be found to have breached our contracts. +Determining whether PHI has been handled in compliance with applicable privacy standards and our contractual obligations can be complex +and we cannot be sure how these regulations will be interpreted, enforced or applied to our operations. +In +addition, many states in which we operate have laws that protect the privacy and security of sensitive and personal information, including +health-related information. Certain state laws may be more stringent or broader in scope, or offer greater individual rights, with respect +to sensitive and personal information than federal, international or other state laws, and such laws may differ from each other, which +may complicate compliance efforts. +16 +Laws, +regulations and standards in many other jurisdictions also apply broadly to the Processing of personal information, which impose significant +compliance obligations. Complying with these numerous, complex and often changing regulations is expensive and difficult, and failure +to comply with any Data Protection Laws or any security incident or breach involving the misappropriation, loss or other unauthorized +use or disclosure of sensitive or confidential information, whether by us, one of our service providers or another third party, could +negatively affect our business, financial condition and results of operations, including but not limited to: investigation costs, material +fines and penalties; compensatory, special, punitive and statutory damages; litigation; consent orders regarding our privacy and security +practices; requirements that we provide notices, credit monitoring services or credit restoration services or other relevant services +to impacted individuals; adverse actions against our licenses to do business; and injunctive relief. +Many +statutory requirements, both in the United States and abroad, include obligations for companies to notify individuals of security breaches +involving certain personal information, which could result from breaches experienced by us or our third-party service providers. For +example, laws in all 50 U.S. states and the District of Columbia require businesses to provide notice to consumers whose unencrypted +personal information has been disclosed as a result of a data breach. These laws are not consistent, and compliance in the event of a +widespread data breach is difficult and may be costly. Moreover, states have been frequently amending existing laws, requiring attention +to changing regulatory requirements. We also may be contractually required to notify affected customers, regulators, credit reporting +agencies or other affected individuals of a security breach. Such notifications are costly, and the disclosures or the failure to comply +with such requirements, could lead to material adverse effects, including without limitation, negative publicity, a loss of customer +confidence in our services or security measures or breach of contract claims. There can be no assurance that the limitations of liability +in our contracts would be enforceable or adequate or would otherwise protect us from liabilities or damages if we fail to comply with +applicable Data Protection Laws, Data Protection Obligations or other legal obligations. In addition, although we may have contractual +protections with our third-party service providers, contractors and consultants, any actual or perceived security breach by our subcontractors +could harm our reputation and brand, expose us to potential liability or require us to expend significant resources on data security +and in responding to any such actual or perceived breach. Any contractual protections we may have from our third-party service providers, +contractors or consultants may not be sufficient to adequately protect us from any such liabilities and losses, and we may be unable +to enforce any such contractual protections. +We +expect that there will continue to be new proposed laws and regulations concerning data privacy and security, and we cannot yet determine +the impact such future laws, regulations and standards may have on our business. New laws, amendments to or re-interpretations of existing +laws, regulations, standards and other obligations may require us to incur additional costs and restrict our business operations. Because +the interpretation and application of health-related and Data Protection Laws and other obligations are still uncertain, and often contradictory +and in flux, it is possible that the scope and requirements of these laws may be interpreted and applied in a manner that is inconsistent +with our practices and our efforts to comply with the evolving data protection rules may be unsuccessful. If so, this could result in +government-imposed fines or orders requiring that we change our practices, which could adversely affect our business. +We +cannot assure you that our third-party partners and service providers with access to our or our customers’, suppliers’ and +employees’ personally identifiable and other sensitive or confidential information in relation to which we are responsible will +not breach contractual obligations imposed by us or violate Data Protection Laws, or that they will not experience security breaches +or attempts thereof, which could have a corresponding effect on our business, including putting us in breach of our obligations under +the Data Protection Laws, which could in turn adversely affect our business, results of operations and financial condition. We cannot +assure you that our contractual measures and our own privacy- and security-related safeguards will protect us from the risks associated +with the third-party processing, storage and transmission of such information. +We +may receive inquiries or be subject to investigations, proceedings or actions, by various government entities regarding our privacy and +information security practices and Processing (“Regulatory Proceedings”). These Regulatory Proceedings could result in a +material adverse effect, including without limitation, interruptions of, or required changes to, our business practices, the diversion +resources and the attention of management from our business, regulatory oversights and audits, discontinuance of necessary Processing, +or other remedies that adversely affect our business. +17 +In +addition to the possibility of fines, lawsuits, regulatory investigations, public censure, other claims and penalties, and significant +costs for remediation and damage to our reputation, we could be materially and adversely affected if legislation or regulations are expanded +to require changes in our data processing practices and policies or if governing jurisdictions interpret or implement their legislation +or regulations in ways that negatively impact our business. Complying with these various laws could cause us to incur substantial costs +or require us to change our business practices and compliance procedures in a manner adverse to our business. Any inability to adequately +address data privacy or security-related concerns, even if unfounded, or to comply with applicable laws, regulations, standards and other +obligations relating to data privacy and security, could result in additional cost and liability to us, harm our reputation and brand, +damage our relationships with customers and have a material and adverse impact on our business. +While +we maintain general liability insurance coverage, cyber insurance coverage and other insurance, we cannot assure that such coverage will +be adequate or otherwise protect us from or adequately mitigate liabilities or damages with respect to claims, costs, expenses, litigation, +fines, penalties, business loss, data loss, regulatory actions or material adverse effects arising out of our privacy and security practices, +Processing or security breaches we may experience, or that such coverage will continue to be available on acceptable terms or at all. +The successful assertion of one or more large claims against us that exceeds our available insurance coverage, or results in changes +to our insurance policies (including premium increases or the imposition of large deductible or co-insurance requirements), could have +an adverse effect on our business. In addition, we cannot be sure that our existing insurance coverage will continue to be available +on acceptable terms or that our insurers will not deny coverage as to any future claim. +We +may incur substantial costs in our efforts to comply with evolving global data protection laws and regulations, and any failure or perceived +failure by us to comply with such laws and regulations may harm our business and operations. +The +global data protection landscape is rapidly evolving, and we may be or become subject to or affected by numerous federal, state and foreign +laws and regulations, as well as regulatory guidance, governing the collection, use, disclosure, transfer, security and processing of +personal data, such as information that we collect about subjects and health care providers in connection with clinical trials. Implementation +standards and enforcement practices are likely to remain uncertain for the foreseeable future, which may create uncertainty in our business; +affect our or our service providers’ ability to operate in certain jurisdictions or to collect, store, transfer use and share personal +data; result in liability; or impose additional compliance or other costs on us. Any failure or perceived failure by us to comply with +federal, state, or foreign laws or self-regulatory standards could result in negative publicity, diversion of management time and effort +and proceedings against us by governmental entities or others. +In +the United States, numerous federal and state laws and regulations, including federal health information privacy laws (e.g., the Health +Insurance Portability and Accountability Act, as amended by the Health Information Technology for Economic and Clinical Health Act, or +collectively HIPAA), state data breach notification laws, state health information privacy laws, and federal and state consumer protection +laws (e.g., Section 5 of the Federal Trade Commission Act), that govern the collection, use, disclosure and protection of health-related +and other personal information could apply to our operations or the operations of our collaborators. In addition, we may obtain health +information from third parties (including research institutions from which we obtain clinical trial data) that are subject to privacy +and security requirements under HIPAA or other privacy and data security laws. Depending on the facts and circumstances, we could be +subject to criminal penalties if we knowingly obtain, use, or disclose protected health information maintained by a HIPAA-covered entity +in a manner that is not authorized or permitted by HIPAA. However, determining whether protected health information has been handled +in compliance with applicable privacy standards and our contractual obligations can be complex and may be subject to changing interpretation. +If +we are unable to properly protect the privacy and security of protected health information or other personal, sensitive, or confidential +information in our possession, we could be found to have breached our contracts. Further, if we fail to comply with applicable privacy +laws, including applicable HIPAA privacy and security standards, we could face significant administrative, civil and criminal penalties. +Enforcement activity can also result in financial liability and reputational harm, and responses to such enforcement activity can consume +significant internal and outside resources. Furthermore, state attorneys general are authorized to bring civil actions seeking either +injunctions or damages in response to violations that threaten the privacy of state residents. In addition, our ongoing efforts to comply +with evolving laws and regulations at the federal and state level may be costly and require continuous modifications to our compliance +policies, procedures, and systems. +18 +Many +state laws govern the privacy and security of personal information and data in specified circumstances, many of which differ from each +other in significant ways, are often not pre-empted by HIPAA, and may have a more prohibitive effect than HIPAA, thus complicating compliance +efforts. For example, the California Consumer Privacy Act of 2018 (the “CCPA”), which went into effect in January 2020 and +provides new data privacy rights for consumers and new operational requirements for companies, which may increase our compliance costs +and potential liability. The CCPA gives California residents expanded rights to access and delete their personal information, opt out +of certain personal information sharing, and receive detailed information about how their personal information is used. The CCPA provides +for civil penalties for violations, as well as a private right of action for data breaches that is expected to increase data breach litigation. +While there is currently an exception for protected health information that is subject to HIPAA and clinical trial regulations, as currently +written, the CCPA may impact certain of our business activities. In addition, the California Consumer Rights Act, or CPRA, was recently +enacted to strengthen elements of the CCPA and became effective on January 1, 2023. The CPRA imposes additional data protection obligations +on covered businesses, including additional consumer rights processes, limitations on data uses, new audit requirements for higher risk +data, and opt outs for certain uses of sensitive data and expands the application of the CCPA to all human resources personal information +of California-based employees. In addition, the CPRA created a new California data protection agency authorized to issue substantive +regulations and is expected to result in increased privacy and information security enforcement. A number of other states have considered +similar privacy proposals, and states have recently enacted their own privacy laws. For example, the Virginia Consumer Data Protection +Act became effective on January 1, 2023, and Colorado and Utah enacted similar laws that became effective in 2023, increasing +the complexity of compliance and the risk of failures to comply. These privacy laws may impact our business activities and exemplify +the vulnerability of our business to the evolving regulatory environment related to personal data. +In +addition to our operations in the United States, which may be subject to health care and other laws relating to the privacy and security +of health information and other personal information, we may be or become subject to European data privacy laws, regulations and guidelines. +The General Data Protection Regulation, (EU) 2016/679 (“GDPR”) became effective on May 25, 2018, and deals with the collection, +use, storage, disclosure, transfer, or other processing of personal data, including personal health data, regarding individuals in the +EEA. The GDPR imposes a broad range of strict requirements on companies subject to the GDPR, including requirements relating to having +legal bases for processing personal information relating to identifiable individuals and transferring such information outside the EEA, +including to the United States, providing details to those individuals regarding the processing of their personal health and other sensitive +data, obtaining consent of the individuals to whom the personal data relates, keeping personal information secure, having data processing +agreements with third parties who process personal information, responding to individuals’ requests to exercise their rights in +respect of their personal information, reporting security breaches involving personal data to the competent national data protection +authority and affected individuals, appointing data protection officers, conducting data protection impact assessments, and record-keeping. +The GDPR increases substantially the penalties to which we could be subject in the event of any non-compliance, including fines of up +to €10,000,000 or up to 2% of our total worldwide annual turnover for certain comparatively minor offenses, or up to €20,000,000 +or up to 4% of our total worldwide annual turnover, whichever is greater, for more serious offenses. The GDPR also confers a private +right of action on data subjects and consumer associations to lodge complaints with supervisory authorities, seek judicial remedies, +and obtain compensation for damages resulting from violations of the GDPR. In addition, the GDPR includes restrictions on cross-border +data transfers. +Following +the United Kingdom’s withdrawal from the European Union (i.e., Brexit), and the expiry of the Brexit transition period, which ended +on December 31, 2020, the EU GDPR has been implemented in the United Kingdom (as the UK GDPR). The UK GDPR sits alongside the UK Data +Protection Act 2018 which implements certain derogations in the EU GDPR into UK law. Under the UK GDPR, companies not established in +the UK but who process personal data in relation to the offering of goods or services to individuals in the UK, or to monitor their behavior +will be subject to the UK GDPR – the requirements of which are (at this time) largely aligned with those under the EU GDPR and +as such, may lead to similar compliance and operational costs with potential fines of up to £17.5 million or 4% of global turnover. +In 2022, the government of the United Kingdom proposed and debated the Data Protection and Digital Information Bill to harmonize the +2018 Data Protection Act, UK GDPR, and the Privacy and Electronic Communications Regulations under one legislative framework. However, +progress on the bill stalled as the government continues to assess the most optimal approach to data protection reform. +19 +We +currently sell some of our products in the EEA, and the GDPR increases our responsibility and liability in relation to personal data +that we process where such processing is subject to the GDPR, and we are required to have in place additional mechanisms and safeguards +to ensure compliance with the GDPR, including as implemented by individual countries. Compliance with the GDPR is a rigorous and time-intensive +process that increase our cost of doing business or require us to change our business practices, and despite those efforts, there is +a risk that we may be subject to fines and penalties, litigation, and reputational harm in connection with our European activities. We +expect that we will continue to face uncertainty as to whether our efforts to comply with any obligations under European privacy laws +will be sufficient. If we are investigated by a European data protection authority, we may face fines and other penalties. Any such investigation +or charges by European data protection authorities could have a negative effect on our existing business and on our ability to attract +and retain new clients or partners. +Risks +Related to Our Intellectual Property +If +the combination of patents, trade secrets and contractual provisions that we rely on to protect our intellectual property is inadequate, +our ability to commercialize our products successfully will be harmed, and we may not be able to operate our business profitably. +Our +success depends significantly on our ability to protect our proprietary rights to the technologies incorporated in our products. We rely +on a combination of patent protection, trade secret laws and nondisclosure, confidentiality and other contractual restrictions to protect +our proprietary technology. However, these may not adequately protect our rights or permit us to gain or keep any competitive advantage. +The +issuance of a patent is not conclusive as to its scope, validity or enforceability. The scope, validity or enforceability of our issued +patents can be challenged in litigation or proceedings before the U.S. Patent and Trademark Office, or the USPTO, or foreign patent offices. +In addition, our pending patent applications include claims to numerous important aspects of our products under development that are +not currently protected by any of our issued patents. We cannot assure you that any of our pending patent applications will result in +the issuance of patents to us. The USPTO or foreign patent offices may deny or require significant narrowing of claims in our pending +patent applications. Patents issued as a result of the pending patent applications, if any, may not provide us with significant commercial +protection or be issued in a form that is advantageous to us. Proceedings before the USPTO or foreign patent offices could result in +adverse decisions as to the priority of our inventions and the narrowing or invalidation of claims in issued patents. The laws of some +foreign countries may not protect our intellectual property rights to the same extent as the laws of the United States, if at all. +Our +competitors may successfully challenge and invalidate or render unenforceable our issued patents, including any patents that may issue +in the future, which could prevent or limit our ability to market our products and could limit our ability to stop competitors from marketing +products that are substantially equivalent to ours. In addition, competitors may be able to design around our patents or develop products +that provide outcomes that are comparable to our products but that are not covered by our patents. +In +the event a competitor infringes upon any of our patents or other intellectual property rights, enforcing our rights may be difficult, +time-consuming and expensive, and would divert management’s attention from managing our business. There can be no assurance that +we will be successful on the merits in any enforcement effort. In addition, we may not have sufficient resources to litigate, enforce +or defend our intellectual property rights. +We +could become subject to intellectual property litigation that could be costly, result in the diversion of management’s time and +efforts, require us to pay damages, prevent us from marketing our commercially available products or product candidates and/or reduce +the margins we may realize from our products that we may commercialize. +Whether +a product infringes a patent involves complex legal and factual issues, and the determination is often uncertain. There may be existing +patents of which we are unaware that our products under development may inadvertently infringe. The likelihood that patent infringement +claims may be brought against us increases as the number of participants in the in vitro diagnostics market increases and as we +achieve more visibility in the marketplace and introduce products to market. +Any +infringement claim against us, even if without merit, may cause us to incur substantial costs, and would place a significant strain on +our financial resources, divert the attention of management from our core business, and harm our reputation. In some cases, litigation +may be threatened or brought by a patent holding company or other adverse patent owner who has no relevant product revenues and against +whom our patents may provide little or no deterrence. If we were found to infringe any patents, we could be required to pay substantial +damages, including triple damages if an infringement is found to be willful, and royalties and could be prevented from selling our products +unless we obtain a license or are able to redesign our products to avoid infringement. We may not be able to obtain a license enabling +us to sell our products on reasonable terms, or at all, and there can be no assurance that we would be able to redesign our products +in a way that would not infringe those patents. If we fail to obtain any required licenses or make any necessary changes to our technologies +or the products that incorporate them, we may be unable to commercialize one or more of our products or may have to withdraw products +from the market, all of which would have a material adverse effect on our business, financial condition and results of operations. +20 +We +rely substantially on our trademarks and trade names. If our trademarks and trade names are not adequately protected, then we may not +be able to build name recognition in our markets of interest and our business may be harmed. +We +rely substantially upon trademarks to build and maintain the integrity of our brand. Our registered and unregistered trademarks or trade +names may be challenged, infringed, circumvented, declared unenforceable or determined to be violating or infringing on other intellectual +property rights. We may not be able to protect or enforce our rights to these trademarks and trade names, which we rely upon to build +name recognition among potential partners and customers in our markets of interest. At times, competitors or other third parties may +adopt trade names or trademarks similar to ours, thereby impeding our ability to build brand identity and possibly leading to market +confusion. Asserting claims against such third parties may be prohibitively expensive. In addition, there could be potential trade name +or trademark infringement, or dilution claims brought by owners of other trademarks against us. Over the long term, if we are unable +to establish name recognition based on our trademarks and trade names, then we may not be able to compete effectively, and our business +may be adversely affected. Our efforts to enforce or protect our proprietary rights related to trademarks, trade secrets, domain names +or other intellectual property may be ineffective, could result in substantial costs and diversion of resources and could harm our business, +financial condition and results of operations. +Risks +Related to Litigation from Operating Our Business +We +may become subject to potential product liability claims, and we may be required to pay damages that exceed our insurance coverage. +Our +business exposes us to potential product liability claims that are inherent in the design, testing, manufacture, sale and distribution +of our currently marketed products and each of our product candidates that we are seeking to introduce to the market. Someone may allege +that our diagnostic tests identified inaccurate or incomplete information or otherwise failed to perform as designed. We may also be +subject to liability for errors in, a misunderstanding of or inappropriate reliance upon, the information we provide in the ordinary +course of our business activities. In addition, we may be subject to product liability claims resulting from misuse or off-label use +of our products and product candidates. Any product liability claim brought against us, with or without merit, could result in an increase +of our product liability insurance rates or in our inability to secure coverage in the future on commercially reasonable terms, if at +all. In addition, if our product liability insurance proves to be inadequate to pay a damage award, we may have to pay the excess of +this award out of our cash reserves, which could significantly harm our financial condition. A product liability claim, even one without +merit, could harm our reputation in the industry, lead to significant legal fees, and result in the diversion of management’s attention +from managing our business. +Current +or future litigation, government investigations and other legal proceedings may harm our business. +We +have been, currently are and may in the future become, involved in legal proceedings that could have a negative impact on our reputation, +business and financial condition and divert the attention of our management from the operation of our business. The types of legal proceedings +we may be or become subject to include patent and other intellectual property claims, product liability claims, employee claims, tort +or contract claims, federal or state regulatory investigations, securities class actions, and other legal proceedings, investigations +or claims. For example, we are currently parties to two securities class action claims and three derivative actions. Litigation and other +legal proceedings are inherently unpredictable and can result in excessive or unanticipated verdicts and/or injunctive relief that affect +how we operate our business. We could incur judgments or enter into settlements of claims for monetary damages or for agreements to change +the way we operate our business, or both. There may be an increase in the scope of these matters or there may be additional lawsuits, +claims, proceedings or investigations in the future, which could harm our business, financial condition and results of operations. Adverse +publicity about regulatory or legal action against us could damage our reputation and brand image, undermine our customers’ confidence +and reduce long-term demand for any of our products or other offerings, even if the regulatory or legal action is unfounded or not material +to our operations. For additional information, see “Item 3. Legal Proceedings.” +21 +General +Risk Factors +The +price of our common stock may fluctuate substantially. +The +market price of our common stock may be subject to wide fluctuation in response to various factors, some of which are beyond our control. +Some factors that may cause the market price of our common stock to fluctuate, in addition to the other risks mentioned in this “Risk +Factors” section and elsewhere in this report, are: +● +sales +or purchases of our common stock by our shareholders, executives, and directors; +● +our +ability to obtain regulatory approval to commercialize our PCR platform on a timely basis or at all; +● +our +ability to enter new markets; +● +actual +or unanticipated fluctuations in our annual and quarterly financial results; +● +our +ability to obtain financings to continue and expand our commercial activities, expand our manufacturing operations, conduct research +and development activities including, but not limited to, human clinical trials, and other business activities; +● +our +ability to secure resources and the necessary personnel to continue and expand our commercial activities, develop additional diagnostic +tests, conduct clinical trials and gain approval for our diagnostic tests on our desired schedule; +● +commencement, +enrollment or results of our clinical trials of our diagnostic tests or any future clinical trials we may conduct; +● +changes +in the development status of our diagnostic tests; +● +any +delays or adverse developments or perceived adverse developments with respect to review by the FDA or other similar foreign regulatory +authorities of our planned clinical trials; +● +any +delay in our submission for studies or test approvals or adverse regulatory decisions, including failure to receive regulatory approval +or clearance for our diagnostic tests; +● +our +announcements or our competitors’ announcements regarding new tests, enhancements, significant contracts, acquisitions or strategic +investments; +● +failures +to meet external expectations or management guidance; +● +changes +in our capital structure or dividend policy, including as a result of future issuances of securities and sales of large blocks of +common stock by our shareholders; +● +announcements +and events surrounding financing efforts, including debt and equity securities; +● +competition +from existing technologies and diagnostic tests or new technologies and diagnostic tests that may emerge; +● +announcements +of acquisitions, partnerships, collaborations, joint ventures, new diagnostic tests, capital commitments, or other events by us or +our competitors; +● +changes +in general economic, political and market conditions in any of the regions in which we conduct our business; +● +changes +in industry conditions or perceptions; +● +changes +in valuations of similar companies or groups of companies; +● +analyst +research reports, recommendations and changes in recommendations, price targets and withdrawals of coverage; +● +departures +and additions of key personnel; +● +disputes +and litigations related to intellectual properties, proprietary rights, and contractual obligations; +● +changes +in applicable laws, rules, regulations, or accounting practices and other dynamics; +● +other +events or factors, many of which may be out of our control. +In +addition, if the market for stocks in our industry or industries related to our industry, or the stock market in general, experiences +a loss of investor confidence, the trading price of our common stock could decline for reasons unrelated to our business, financial condition +and results of operations. If any of the foregoing occurs, it could cause our stock price to fall and may expose us to lawsuits that, +even if unsuccessful, could be costly to defend and a distraction to management. +22 +Anti-takeover +provisions in our charter documents and Utah law could discourage, delay, or prevent a change of control of our Company and may affect +the trading price of our common stock. +We +are a Utah corporation and the anti-takeover provisions of the Utah Control Shares Acquisition Act may discourage, delay or prevent a +change of control by limiting the voting rights of control shares acquired in a control share acquisition. In addition, our Articles +of Incorporation and Bylaws may discourage, delay or prevent a change in our management or control over us that shareholders may consider +favorable. Among other things, our Amended and Restated Articles of Incorporation and Bylaws: +● +authorize +the issuance of “blank check” preferred stock that could be issued by our board of directors in response to a takeover +attempt; +● +provide +that vacancies on our board of directors, including newly created directorships, may be filled only by a majority vote of directors +then in office, except a vacancy occurring by reason of the removal of a director without cause shall be filled by vote of the shareholders; +● +no +right to cumulative voting; +● +limit +who may call special meetings of shareholders; and +● +provide +for a staggered board of directors +These +provisions could have the effect of delaying or preventing a change of control, whether or not it is desired by, or beneficial to, our +shareholders. +We +do not currently intend to pay dividends on our common stock. +We +do not expect to pay cash dividends on our common stock. Any future dividend payments are within the absolute discretion of our board +of directors and will depend on, among other things, our results of operations, working capital requirements, capital expenditure requirements, +financial condition, contractual restrictions, business opportunities, anticipated cash needs, provisions of applicable law and other +factors that our board of directors may deem relevant. We may not generate sufficient cash from operations in the future to pay dividends +on our common stock. +We +are a “smaller reporting company” and the reduced disclosure requirements applicable to smaller reporting companies may make +our common stock less attractive to investors. +We +are currently a “smaller reporting company” as defined in the Securities Exchange Act of 1934. Smaller reporting companies +are able to provide simplified executive compensation disclosures in their filings, and have certain other decreased disclosure obligations +in their SEC filings, including, among other things, only being required to provide two years of audited financial statements in annual +reports. We cannot predict whether investors will find our common stock less attractive because of our reliance on any of these exemptions. +If some investors find our common stock less attractive as a result, there may be a less active trading market for our common stock and +our stock price may be more volatile. +We +incur substantial costs as a result of being a public company and our management expects to devote substantial time to public company +compliance programs. +As +a public company, we incur significant legal, insurance, accounting and other expenses, including costs associated with public company +reporting. We intend to invest resources to comply with evolving laws, regulations and standards, and this investment will result in +increased general and administrative expenses and may divert management’s time and attention from product development and commercialization +activities. If our efforts to comply with new laws, regulations and standards differ from the activities intended by regulatory or governing +bodies due to ambiguities related to practice, regulatory authorities may initiate legal proceedings against us, and our business may +be harmed. These laws and regulations could make it more difficult and costlier for us to obtain director and officer liability insurance +for our directors and officers, and we may be required to accept reduced coverage or incur substantially higher costs to obtain coverage. +These factors could also make it more difficult for us to attract and retain qualified executive officers and qualified members of our +board of directors, particularly to serve on our audit and compensation committees. In addition, if we are unable to continue to meet +the legal, regulatory and other requirements related to being a public company, we may not be able to maintain the listing of our common +stock on The NASDAQ Capital Market, which would likely have a material adverse effect on the trading price of our common stock. +ITEM +1B. UNRESOLVED STAFF COMMENTS +None. +23 +ITEM +1C. CYBERSECURITY +We +understand the importance of preventing, identifying, assessing and managing material risks associated with cybersecurity threats. Cybersecurity +processes to identify, assess and manage risks from cybersecurity threats have been incorporated as a part of our overall risk assessment +process and are designed to help protect our information assets and operations from internal and external cyber threats and protect employee +and customer information from unauthorized access or attack, as well as secure our network and systems. The Company’s cybersecurity +policies, standards, processes, and practices are based on recognized frameworks established by the National Institute of Standards and +Technology (“NIST”) and are included in the Company’s overall risk management system and processes. We have implemented +into our operations these cybersecurity processes, technologies and controls to identify, assess and manage material risks. Specifically, +we engage a third-party cybersecurity firm to assist with network and endpoint monitoring, cloud system monitoring and assessment of +our incident response procedures. Further, we employ periodic internal and external penetration testing by an independent cybersecurity +firm to inform our risk identification and assessment of critical, high, medium and minor material cybersecurity threats. +To +manage our material risks from cybersecurity threats and to protect against, detect, and prepare to respond to cybersecurity incidents, +we undertake the below listed activities: +● +Monitor +evolving cybersecurity standards and emerging data protection laws and implement changes to our processes to comply; +● +risk +assessments designed to help identify material cybersecurity risks to our critical systems, information, products, services, and +our broader enterprise IT environment; +● +The +Company leverages third-party vendors to house critical clinical trial data. These vendors are required to be GxP compliant which +entails strong cybersecurity controls that are validated by a third-party auditor. Furthermore, the Company has begun performing +security risk assessments prior to on-boarding new significant vendors. +● +The +Company provides regular, mandatory training for all levels of employees regarding cybersecurity threats as a means to equip the +Company’s employees with effective tools to address cybersecurity threats, and to communicate the Company’s evolving +information security policies, standards, processes, and practices. +● +Employ +multifactor authentication on internal and external systems; +● +Conduct +regular phishing email simulations for all employees; and +● +Carry +cybersecurity risk insurance that provides protection against the potential losses arising from a cybersecurity incident. +Our +incident response plan coordinates the activities that we and our third-party cybersecurity providers take to prepare to respond and +recover from cybersecurity incidents, which include processes to triage, assess severity, investigate, escalate, contain, and remediate +an incident, as well as to comply with potentially applicable legal obligations and mitigate brand and reputational damage. +As +part of the above processes, we engage with subject matter expert consultants to review our cybersecurity program to help identify areas +for continued focus, improvement, and compliance. +Our +processes also include assessing cybersecurity threat risks associated with our use of third-party services providers in normal course +of business use, including those in our supply chain or who have access to patient and employee data or our systems. Third-party risks +are included within our risk management process discussed above. In addition, we assess cybersecurity considerations in the selection +and oversight of our third-party services providers, including due diligence on the third parties that have access to our systems and +facilities that house systems and data. +We +do not believe that there are currently any known risks from cybersecurity threats that are reasonably likely to materially affect our +business strategy, results of operations or financial condition. However, cybersecurity threats may affect our business. See “ Cyber +security risks and the failure to maintain the integrity of company, employee or guest data could expose us to data loss, litigation +and liability, and our reputation could be significantly harmed. ” in “Item 1A. Risk Factors” of this Annual +Report on Form 10-K. +The +Audit Committee of the Board of Directors is responsible for oversight of our cybersecurity risk assessment, risk management, incident +response procedures and cybersecurity risks and provides updates to the Board of Directors regarding such oversight. Periodically during +each year, the Audit Committee receives an overview from our Vice President, Head of Technology of our cybersecurity threat risk management +and strategy processes, including potential impact on us, the efforts of management to manage the risks that are identified and our incident +response preparations. +Our +cybersecurity risk assessment, management and strategy processes are led by our Chief Technology Officer. Our Chief Technology Officer +has over 15 years of experience in various roles involving managing information security, managing privacy and data protection, developing +cybersecurity strategy, and implementing cybersecurity programs. The Chief Technology Officer was recently promoted and is training to +be a Certified Information Security Manager (CISM), is informed about and monitors the prevention, mitigation, detection, and remediation +of cybersecurity incidents through management of the cybersecurity risk management and strategy processes described above, including +our incident response plan. +24 +ITEM +2. PROPERTIES +Our +headquarters are located at 2401 S. Foothill Drive, Salt Lake City, Utah. Our current facilities have approximately 54,000 square feet +of laboratory, manufacturing, storage and office space under leases that expire in 2026 through 2028. We believe the facilities we lease +are sufficient to meet our needs for the foreseeable future. +ITEM +3. LEGAL PROCEEDINGS +In +the ordinary course of business, we are at times subject to various legal proceedings and disputes, including the proceedings specifically +discussed below. We assess our liabilities and contingencies in connection with outstanding legal proceedings utilizing the latest information +available. Where it is probable that we will incur a loss and the amount of the loss can be reasonably estimated, we record a liability +in our consolidated financial statements. These legal reserves may be increased or decreased to reflect any relevant developments on +a quarterly basis. Where a loss is not probable or the amount of loss is not estimable, we do not accrue legal reserves. While the outcome +of legal proceedings is inherently uncertain, based on information currently available and available insurance coverage, our management +believes that it has established appropriate legal reserves. Any incremental liabilities arising from pending legal proceedings are not +expected to have a material adverse effect on our consolidated financial position, consolidated results of operations, or consolidated +cash flows. However, it is possible that the ultimate resolution of these matters, if unfavorable, may be material to our consolidated +financial position, consolidated results of operations, or consolidated cash flows. +Class +Actions and Shareholder Derivative Suits +Gelt +Securities Class Action (District of Utah) +On +June 15, 2020, Gelt Trading Co. (“Gelt”) filed a lawsuit in the United States District Court for the District of Utah (“District +of Utah”), against the Company and certain of our directors and officers, on behalf of itself and a putative class, seeking to +recover damages for alleged violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 (“Gelt Litigation”). +The complaint alleges that Co-Diagnostics and the individual defendants overstated the accuracy of the Company’s Logix Smart COVID-19 +test in statements on April 30, 2020 and May 1, 2020, and that plaintiff suffered losses when the Company’s stock price dropped +after public reports questioned the accuracy of the Logix Smart test on May 14, 2020. On July 15, 2020, plaintiff filed an amended complaint. +On March 10, 2021, the court appointed Gelt as Lead Plaintiff, and on April 7, 2021, Lead Plaintiff filed a second amended complaint +(“SAC”), which asserts the same Sections 10(b) and 20(a) claims against the same defendants on largely the same theory. On +May 5, 2021, the defendants moved to dismiss the SAC. On March 9, 2022, the court entered a Decision & Order denying the motion to +dismiss, but narrowing the challenged statements to only those made in the May 1, 2020 press release, and on April 13, 2022, the defendants +filed an answer to the SAC. On October 17, 2022, Gelt filed a motion to certify the putative class, and on August 18, 2023, the court +partially granted that motion, certifying a class of all those who purchased Co-Diagnostics securities between May 1, 2020 and May 14, +2020, dates inclusive, and who were damaged thereby. Fact discovery closed on August 18, 2023 and expert discovery is currently underway. +Summary judgment motions and motions to exclude expert testimony are due April 10, 2024; no trial date has yet been set. The defendants +believe the claims are without merit and intend to defend vigorously against them, but there can be no assurances as to the outcome. +Shareholder +Derivative Lawsuits (District of Utah & Utah State Court) +On +September 17, 2020, a shareholder derivative lawsuit was filed in the District of Utah by Luis Aguilera, allegedly on behalf of Co-Diagnostics, +Inc., that substantially piggybacks on the Gelt Litigation referenced above. The lawsuit asserts that the defendants failed to prevent +the alleged securities law violations largely asserted in the Gelt Litigation. On December 2, 2020, a second shareholder derivative lawsuit +was filed in the District of Utah by Melvyn Klein asserting essentially the same claims, allegedly on behalf of Co-Diagnostics, as the +Aguilera shareholder derivative action. And on April 29, 2021, the District of Utah consolidated the two shareholder derivative cases, +with the Aguilera case serving as the lead case under the caption In re Co-Diagnostics, Inc. Derivative Litigation . On May 3, +2022, plaintiffs filed an amended complaint asserting claims for breach of fiduciary duty, unjust enrichment, and contribution under +Sections 10(b) and 21D of the Securities Exchange Act of 1934. Defendants answered the amended complaint on June 24, 2022. On January +25, 2024, the consolidated Aguilera derivative action was voluntarily dismissed without prejudice. +On +November 24, 2020, an additional shareholder derivative lawsuit was filed in the District of Utah by Matthew Wallace, allegedly on behalf +of Co-Diagnostics, Inc., that also piggybacks on the Gelt Litigation referenced above. It named the same defendants and asserted essentially +the same claims, allegedly on behalf of Co-Diagnostics, as in the other District of Utah shareholder derivative actions referenced above. +On January 25, 2021, another shareholder derivative lawsuit was filed in the District of Utah by Jason Reagan, asserting essentially +the same claims as in the Wallace lawsuit. On March 18, 2021, the court consolidated the two lawsuits, with the Wallace lawsuit serving +as the lead case. On April 30, 2021, plaintiffs filed an amended complaint asserting claims for breach of fiduciary duty against defendants +and claims for insider trading. On January 26, 2024, the court ordered the parties’ proposed revised case schedule, setting fact +and expert discovery deadlines throughout 2024 and early 2025; dispositive motions are due June 1, 2025, but no trial date has yet been +set. +25 +On +March 29, 2021, an additional shareholder derivative lawsuit was filed in the Third District Court in and for Salt Lake County, State +of Utah (“Utah State Court”) by Hua Ding, allegedly on behalf of Co-Diagnostics, Inc., that also piggybacks on the Gelt Litigation +referenced above. It names the same defendants and asserts essentially the same claims as in In re Co-Diagnostics, Inc. Derivative +Litigation pending in the District of Utah referenced above. On December 12, 2022, a second shareholder derivative lawsuit was filed +in Utah State Court by Kathryn Matuch asserting essentially the same claims, allegedly on behalf of Co-Diagnostics, as the Ding shareholder +derivative action. +The +defendants believe the claims asserted in all of the shareholder derivative lawsuits referenced above are without merit and intend to +defend vigorously against them, but there can be no assurances as to the outcome. +Stadium +Capital Securities Class Action (Southern District of New York) +On +August 16, 2022, Stadium Capital LLC (“Stadium”) filed a lawsuit in the United States District Court for the Southern District +of New York, against Co-Diagnostics, Inc., and certain of our officers, on behalf of itself and a putative class, seeking to recover +damages for alleged violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934. The complaint alleges that Co-Diagnostics +and the individual defendants overstated the demand for the Company’s Logix Smart COVID-19 test in statements on May 12, 2022 and +June 15, 2022. The complaint alleges that plaintiff suffered losses when the Company’s stock price dropped after the Company disclosed +its financial results for the quarter ended June 30, 2022 in a press release on August 11, 2022. On September 19, 2022, a second plaintiff, +Drew Lee, filed a similar complaint in the same court against the same defendants alleging essentially the same claims. On August 9, +2023, the court consolidated these two securities class actions into the Stadium action and appointed Stadium as lead plaintiff. On September +21, 2023, Stadium filed a consolidated amended complaint, and on October 20, 2023, defendants moved to dismiss. On February 5, 2024, +the Court granted in part and denied in part the defendants’ motion to dismiss. On February 20, 2024, the defendants answered the +consolidated amended complaint, and the parties are now engaged in discovery. The defendants believe the claims are without merit and +intend to defend vigorously against them, but there can be no assurances as to the outcome. +Commercial +Litigation +Co-Diagnostics, +Inc. v. Hukui Technology, Inc., et al. (Third Judicial District Court, Salt Lake County, State of Utah, Civil No. 210902131, filed on +April 21, 2021). +The +Company filed a complaint against Defendants Hukui Technology, Inc., Hukui Tech, Inc., and Hukui Bio Co., Ltd (collectively, “Hukui”) +seeking a declaratory judgment that the Company is not obligated to any of them in any amount. On August 24, 2021, Hukui filed their +Answer and Counterclaim seeking damages on a number of theories, including breach of contract for letter agreements, breach of oral agreement, +promissory estoppel, unjust enrichment, and interference with economic relations. Hukui requested a money judgment against the Company +in an amount to be determined at trial. On September 20, 2021, Hukui filed their Unopposed Motion for Leave to Amend Answer to the Complaint, +Affirmative Defenses, and Counterclaims and, on October 14, 2021, Hukui filed their Amended Answer and Counterclaims seeking damages +on declaratory judgment, as well as breach of contract for letters of authorization, breach of oral agreement, promissory estoppel, unjust +enrichment, and interference with economic relations. In 2022 the parties exchanged their initial disclosures, exchanged written discovery +requests, and conducted a number of depositions on each side that were concluded in January 2023. On June 1, 2023 the Company filed a +Motion for Summary Judgment asking the court for summary judgment on its sole claim for declaratory relief and for summary judgment with +respect to all Hukui counterclaims. On November 7, 2023, the Court issued its decision and granted the Company summary judgment on its +sole claim for declaratory relief and on all Hukui counterclaims. On December 22, 2023, Hukui filed a notice of appeal of the final judgment +in its entirety with the Utah Supreme Court. The Company believes the claims are without merit and intends to defend vigorously against +them, but there can be no assurances as to the outcome. +Co-Diagnostics, +Inc. v. Pantheon International Advisors Ltd. (Third Judicial District Court, Salt Lake County, State of Utah, Civil No. 210902609, filed +on May 14, 2021). +The +Company filed a complaint against Pantheon International Advisors (“Pantheon”) asking the court to declare that the Company +has no ongoing contractual business relationship with Pantheon, no monies owing, nor does Pantheon have any interest, right, title or +claim to any stock issued by the Company or ownership of any kind in the Company. Pantheon was served with a 30-Day Summons on September +9, 2021 to which it failed to respond, and a default judgement against Pantheon International Advisors was entered by the Court on November +28, 2021. The time to appeal from the judgment or seek to vacate the judgment has passed. +After +learning that the Company had initiated suit in Utah, and after learning of Company’s intent to serve it with process of that suit, +on May 24, 2021, Pantheon filed a claim against the Company in the Royal Courts of Justice Group, Queens Bench Division, Claim No. QB-21-002245, +stating that the Company owes Pantheon $2,860,809.79 for alleged breach of contract for failing to make payments purportedly due under +a contract allegedly entered into on October 18, 2018. The Company is being represented locally in the UK by Freshfields Bruckhaus Deringer +LLP in that matter. The Company intends to vigorously defend against the UK claims and will seek to the full extent possible to enforce +its rights under the Declaratory Judgment already obtained in Utah but there can be no assurances as to the outcome. +ITEM +4. MINE SAFETY DISCLOSURES +Not +applicable. +26 +PART +II +ITEM +5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER EQUITY SECURITIES +Market +Information +Our +common stock has been quoted on the NASDAQ market under the symbol “CODX” since July 12, 2017. +Holders +As +of March 12, 2024, the last reported sales price reported on NASDAQ for our common stock was $1.18 per share. As of March 12, 2024, we +had approximately 154 record holders of our common stock. The number of record holders was determined from the records of our transfer +agent and does not include beneficial owners of common stock whose shares are held in the names of various security brokers, dealers, +and registered clearing agencies. The transfer agent for our common stock is VStock Transfer LLC located at 18 Lafayette Pl, Woodmere, +New York 11598. +Dividends +We +have never declared or paid any cash dividends on our capital stock. The payment of dividends on our common stock in the future will +depend on our earnings, capital requirements, operating and financial condition and such other factors as our board of directors may +consider appropriate. We currently expect to use all available funds to finance the future development and expansion of our business +and do not anticipate paying dividends on our common stock in the foreseeable future. +Pursuant +to Section 16-10a-640 of the Utah Revised Business Corporation Act, no distribution may be made if, after giving it effect: +(a) +the +corporation would not be able to pay its debts as they become due in the usual course of business; or +(b) +the +corporation’s total assets would be less than the sum of its total liabilities plus, unless the articles of incorporation permit +otherwise, the amount that would be needed, if the corporation were to be dissolved at the time of the distribution, to satisfy the +preferential rights upon dissolution of shareholders whose preferential rights are superior to those receiving the distribution. +Securities +authorized for issuance under equity compensation plans +Information +about our equity compensation plans in Item 12 of Part III of this Annual Report on Form 10-K is incorporated herein by reference. +Recent +Sales of Unregistered Securities +None. +Purchases +of Equity Securities by the Issuer and Affiliated Purchasers +Share +Repurchase Program +Issuer Purchase of Equity Securities +Period +(a) Total number of shares purchased (1) +(b) Average price paid per share (1) +(c ) Total number of shares purchased as part of publicly announced plans or programs (1) +(d) Maximum number (or approximate dollar value) of shares that may yet be purchased under the plans or programs (1) +10/01/23 – 10/31/23 +77,676 +$ 1.08 +77,676 +$ 14,500,002 +11/01/23 – 11/30/23 +- +$ - +- +$ 14,500,002 +12/01/23 – 12/31/23 +62,482 +$ 1.21 +62,482 +$ 14,424,205 +Total +140,158 +$ 1.14 +140,158 +$ 14,424,205 +(1) +In +March 2022, the company announced that its board of directors authorized the repurchase of up to $30.0 million of the company’s +outstanding common stock. The extent to which the company repurchases its shares, and the timing of such repurchases, will depend +upon a variety of factors, including trading volume, market conditions, legal requirements, business conditions and other factors. +The repurchase program may be discontinued at any time, and the program does not obligate the company to acquire any specific number +of shares of its common stock. +27 +ITEM +6. RESERVED +ITEM +7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULT OF OPERATIONS +The +following management’s discussion and analysis of financial condition and results of operations describes the principal factors +affecting the results of our operations, financial condition, and changes in financial condition. This discussion should be read in conjunction +with the accompanying audited financial statements, and notes thereto, included elsewhere in this report. In addition to historical information, +this Annual Report contains forward-looking statements that involve risks, uncertainties, and assumptions. Our actual results may differ +materially from those anticipated in these forward-looking statements as a result of certain factors, including but not limited to those +set forth under the caption “Item 1A. Risk Factors” in this Annual Report on Form 10-K. +Business +Overview +Co-Diagnostics, Inc., a Utah corporation (the “Company” or +“CODX”), develops, manufactures and sells reagents used for diagnostic tests that function via the detection and/or analysis +of nucleic acid molecules (DNA or RNA), including robust and innovative molecular tools for detection of infectious diseases, liquid biopsy +for cancer screening, and agricultural applications. Our diagnostics systems enable dependable, low-cost, molecular testing for organisms +and genetic diseases by automating or simplifying historically complex procedures in both the development and administration of tests. +CODX’s technical advance involves a novel, patented approach to PCR test design of primer and probe structure (“CoPrimers™”) +that eliminates one of the key vexing issues of PCR amplification: the exponential growth of primer-dimer pairs (false positives and false +negatives) which adversely interferes with identification of the target DNA/RNA. Using our proprietary test design system and proprietary +reagents, we have designed and obtained regulatory approval to sell PCR diagnostic tests for the detection of COVID-19, influenza, tuberculosis, +hepatitis B and C, human papillomavirus, malaria, chikungunya, dengue, and the Zika virus. These initial diagnostic tests were cleared +for use in clinical labs only and not for point-of-care or at-home use. +We +are currently developing a unique, groundbreaking portable diagnostic device and test system designed for point-of-care and at-home +use. The system is comprised of our PCR instrument that we refer to as the Co-Dx™ PCR Pro™ instrument, our proprietary +diagnostic test cup system and a mobile application to be installed on the user’s mobile device. We refer to the system as the +“Co-Dx™ PCR platform that is being designed to bring affordable, reliable polymerase chain reaction (“PCR”) +testing to patients in point-of-care and at-home settings. The Co-Dx PCR platform is subject to U.S. Food and Drug Administration +(“FDA”) review and is not available for sale at the time of this filing. In December 2023, we submitted the Co-Dx PCR +platform for review by the U.S. Food and Drug Administration (FDA) for Emergency Use Authorization (EUA). The submission included +the PCR Pro instrument, Co-Dx PCR COVID-19 detection test cups, and mobile app, all designed for use in point-of-care and at-home +settings. There is no guarantee that our Co-Dx PCR platform will receive the necessary regulatory approvals for commercialization, +or that, if regulatory approval is received, we will be able to successfully commercialize this platform. +Technology +We +believe our proprietary molecular diagnostics technology is paving the way for innovation in disease detection and life sciences research +through our enhanced detection of genetic material. For various reasons, including owning our own platform, we believe we will be able +to accomplish this faster and more economically than some competitors, allowing for significant margins while still positioning ourselves +as a low-cost provider of molecular diagnostics and screening services. For example, we were the first US-based company to receive a +CE-marking for a COVID-19 test in early 2020, as we worked to help slow the spread of the pandemic through our global network of distributors +covering clinical labs in more than 50 countries. Our Logix Smart COVID-19 test was designed, developed, submitted for regulatory approval +and ready to be used as an in vitro diagnostic or IVD in countries that accept a CE Mark as approval for use of the test in a period +of just over 30 days. This is a real-world example of how the CODX technology can be used in an evolving epidemic or pandemic to get +diagnostic tools in the hands of medical professionals in a timely manner. It can be similarly used to design a test for mutated strains +of the virus should they not be detectable using currently available tests. +In +addition, continued development has demonstrated the unique properties of our CoPrimer technology that we believe makes it ideally suited +for a variety of applications where specificity is key to optimal results, including multiplexing several targets, enhanced Single Nucleotide +Polymorphism (“SNP”) detection and enrichment for next generation sequencing. +Our +scientists use the complex mathematics of DNA/RNA PCR test design to engineer and optimize PCR tests and to automate algorithms that +rapidly screen millions of possible options to pinpoint the optimum design. The intellectual property we use in our business, consisting +of the predictive mathematical algorithms and patented molecular structure used in the testing process, which together represents a major +advance in PCR testing systems. CODX technologies are now protected by more than 20 granted or pending US and foreign patents, as well +as certain trade secrets and copyrights. Ownership of our proprietary platform permits us the advantage of avoiding payment of patent +royalties required by other PCR test systems, which may allow the sale of diagnostic PCR tests at a lower price than competitors, while +enabling us to maintain profit margins. +28 +Our +proprietary test design process involves identifying the optimal locations on the target genes for amplification and pair the locations +with the optimized primer and probe structure to achieve outputs that meet the design input requirements identified from market research. +This is done by following planned and documented processes, procedures and testing. In other words, we use the data resulting from our +tests to verify whether we succeeded in designing what we intended. Verification involves a series of testing that concludes that the +product is ready to proceed to validation in an evaluation either in our laboratory or in an independent laboratory setting using initial +production tests to confirm that the product as designed meets the user needs. +Using +our proprietary test design system and proprietary reagents, we have designed and obtained regulatory approval in the European Community +and in India to sell PCR diagnostic tests for the detection of COVID-19, influenza, tuberculosis, hepatitis B and C, human papillomavirus, +malaria, chikungunya, dengue, and the Zika virus. In the United States, we obtained Emergency Use Authorization (“EUA”) for +our Logix Smart ® COVID-19 detection test from the Food and Drug Administration, or +FDA, and we sell that test to qualified labs. In addition, our COVID-19 detection test and certain of our other suite of COVID-19 products +have been approved for sale in countries such as the United Kingdom, Australia and Mexico by the regulatory bodies in those countries +and have been registered for sale in many more countries. In connection with the sale of our tests we may sell diagnostic equipment from other manufacturers as self-contained +lab systems (which we refer to as the “MDx Device”). +In +addition to testing for infectious disease, the technology lends itself to identifying any section of a DNA or RNA strand that describes +any type of genetic trait, which creates several significant applications. We, in conjunction with our customers, have designed and licensed tests that identify genetic traits in plant and animal genomes. We also have three multiplexed tests developed +to test mosquitos for the identification of diseases carried by the mosquitos to enable municipalities to concentrate their efforts in +managing mosquito populations on the specific areas known to be breeding the mosquitos that carry deadly viruses. +RESULTS +OF OPERATIONS +Results +of Operations for the Years Ended December 31, 2023 and 2022 +The +table below provides a comparison of our operating results for the year ended December 31, 2023 as compared to the year ended December +31, 2022. +Years Ended December 31, +Year Change +2023 +2022 +Change +% +Product revenue +$ 991,473 +$ 34,218,209 +$ (33,226,736 ) +-97 % +Grant revenue +5,820,565 +- +5,820,565 +- +Total revenue +6,812,038 +34,218,209 +(27,406,171 ) +-80 % +Cost of revenue +4,184,949 +5,481,093 +(1,296,144 ) +-24 % +Gross profit +2,627,089 +28,737,116 +(26,110,027 ) +-91 % +Operating expenses +Sales and marketing +6,860,815 +7,344,628 +(483,813 ) +-7 % +General and administrative +14,279,441 +14,262,963 +16,478 +0 % +Research and development +22,962,593 +17,438,098 +5,524,495 +32 % +Depreciation and amortization +1,230,474 +1,282,718 +(52,244 ) +-4 % +Goodwill impairment charges +- +15,388,546 +(15,388,546 ) +- +Total operating expenses +45,333,323 +55,716,953 +(10,383,630 ) +-19 % +Loss from operations +(42,706,234 ) +(26,979,837 ) +(15,726,397 ) +58 % +Other income +Interest income +1,161,913 +704,045 +457,868 +65 % +Realized gain on investments +2,243,059 +- +2,243,059 +- +Loss on disposition of assets +(2,578 ) +(138,117 ) +135,539 +-98 % +Gain on remeasurement of acquisition contingencies +1,092,581 +7,899,644 +(6,807,063 ) +-86 % +Gain (loss) on equity method investment in joint venture +100,703 +(332,969 ) +433,672 +-130 % +Total other income +4,595,678 +8,132,603 +(3,536,925 ) +-43 % +Loss before income taxes +(38,110,556 ) +(18,847,234 ) +(19,263,322 ) +102 % +Income tax benefit +(2,777,691 ) +(4,608,985 ) +1,831,294 +-40 % +Net loss +$ (35,332,865 ) +$ (14,238,249 ) +$ (21,094,616 ) +148 % +29 +Revenues +For +the year ended December 31, 2023, we generated $6.8 million of revenue compared to revenue of $34.2 million in the year ended December +31, 2022. The decrease in revenue of $27.4 million was primarily due to lower sales of our Logix Smart COVID-19 test throughout the world. +As global attention and regulatory responses to the COVID-19 pandemic have eased, we have experienced significantly decreased demand +for our COVID-19 test. This decrease was partially offset by the generation of $5.8 million of grant revenue during the year ended December +31, 2023. +Cost +of Revenues and Gross Profit +Cost +of revenues decreased by $1.3 million from $5.5 million for the year ended December 31, 2022 to $4.2 million for the year ended December +31, 2023. Included within cost of revenues for the year ended December 31, 2023 is an increase of approximately $2.8 million related +to reserves against certain raw materials and finished goods inventories. The decrease in revenues combined with a larger percentage +of fixed product manufacturing costs and reserves for obsolete inventory resulted in a lower gross margin percentage. +Operating +Expenses +We +incurred total operating expenses of $45.3 million for the year ended December 31, 2023 compared to total operating expenses of $55.7 +million for the year ended December 31, 2022. The decrease in operating expenses was primarily due to the decreases related to the impairment +of goodwill, bad debt expense, and third party sales commissions, partially offset by increased expenses related to personnel, including +stock-based compensation, increased legal and professional services expenses, and increased investment in research and development. +Sales +and marketing expenses for the year ended December 31, 2023 were $6.9 million compared to $7.3 million for the year ended December 31, +2022. The decrease of $0.4 million was primarily a result of decreased variable compensation, such as bonuses and commissions, and decreased +third-party sales commissions, partially offset by increased professional services and stock-based compensation expense. +General +and administrative expenses were flat at $14.3 million for the years ended December 31, 2023 and 2022, respectively. Increases in professional, +legal, and advisory fees, personnel related expenses, and stock-based compensation expense were offset by decreases in bad debt expense +and insurance expense. +Our +research and development expenses increased by $5.6 million from $17.4 million for the year ended December 31, 2022, to $23.0 million +for the year ended December 31, 2023. The primary increase in expenses related to increased personnel expenses, as well as increases +in supplies expenses and professional and lab services utilized to further help us in our research and product development activities. +During +the year ended December 31, 2022, the Company recognized charges of $15.4 million related to goodwill impairment. +Other +Income +Other +income was $4.6 million for the year ended December 31, 2023, compared to other income of $8.1 million for the year ended December 31, +2022. The decrease in other income of $3.5 million was primarily due to a change in the fair value of contingent consideration liabilities, +driven by changes in the Company’s stock price, and partially offset by increased interest income and realized investment gains +due to the Company’s investing activities. +30 +Net +Loss +We +realized a net loss for the year ended December 31, 2023 of $35.3 million compared to $14.2 million for the year ended December 31, 2022. +The decrease of $21.1 million was primarily the result of reduced sales of our Logix Smart COVID-19 test, increased operating expenses +as discussed above, and a decrease in the gain related to the fair value of acquisition related contingent consideration liabilities, +partially offset by a decrease in impairment charges related to the impairment of goodwill recorded in the prior year and increased interest +income and realized investment gains. Additionally, we recorded an income tax benefit of $2.8 million during the year ended December +31, 2023, compared to an income tax benefit of $4.6 million for the year ended December 31, 2022. +LIQUIDITY +AND CAPITAL RESOURCES +At +December 31, 2023, we had cash and cash equivalents of $14.9 million and marketable investment securities of $43.6 million. We consider +our marketable investment securities an important part of our liquidity and focus such investments in securities that can readily be +converted into cash if needed. Additionally, our total current assets at December 31, 2023, were $62.1 million compared to total current +liabilities of $5.7 million. +Net +cash used in operating activities during the year ended December 31, 2023 was $22.1 million, compared to cash provided by operating activities +of $6.6 million for the year ended December 31, 2022. The decrease in cash from operating activities was primarily due to decreases in +revenue and increases in operating expenses. +Net +cash provided by investing activities was $15.4 million for the year ended December 31, 2023, compared to net cash used in investing +activities of $58.2 million during the year ended December 31, 2022. The increase in cash provided by investing activities is primarily +due to interest and realized gains related to marketable investment securities, as well as the redemption of certain investments as they +matured. +Net +cash used in financing activities was $1.4 million for the year ended December 31, 2023, compared to $14.0 million of cash used in financing +activities for the year ended December 31, 2022. The decrease in cash used in financing activities is primarily due to fewer repurchases +of outstanding common shares during 2023 as compared to 2022. +Since +commencing sales of our Logix Smart COVID-19 test in March 2020, we have used our cash generated from those sales to fund the purchase +of inventories and the development of our Co-Dx PCR Platform, and to pay our operating expenses. We have increased our work force most +significantly in research and development in order to continue development of the Co-Dx PCR platform and additional tests that will enable +continued use of our distributor network to sell additional products throughout the world. +We +believe that our existing capital resources and the cash generated from future sales will be sufficient to meet our projected operating +requirements for the next 12 months. However, our available capital resources may be consumed more +rapidly than currently expected and we may need or want to raise additional financing for strategic opportunities. It is anticipated +that the Company will continue to generate operating losses and use cash in operations in the near term. If +needed, we expect additional investment capital to come from additional issuances of our common stock or other equity based securities +with existing and new investors similar to those that have provided funding in the past. On March 16, 2023, the Company entered into +an Equity Distribution Agreement with Piper Sandler & Co. (“Piper”), pursuant to which we may sell from time to time, +shares of our common stock, having an aggregate offering price of up to $50.0 million through Piper, as agent. No shares have been sold +under the distribution agreement as of December 31, 2023. We may not be able to secure such financing in a timely manner or on favorable +terms, if at all. +CRITICAL +ACCOUNTING POLICIES AND ESTIMATES +Our +management’s discussion and analysis of our financial condition and results of operations is based on our consolidated financial +statements, which have been prepared in accordance with United States generally accepted accounting principles (“GAAP”). +The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets +and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, as well as the reported +revenues and expenses incurred during the reporting periods. Our estimates are based on our historical experience and on various other +factors that we believe are reasonable under the circumstances. Actual results may differ from these estimates under different assumptions +or conditions. While our significant accounting policies are described in Item 8 of this Annual Report on Form 10-K, within Note 2 of +our consolidated financial statements in the section titled “Summary of Significant Accounting Policies”, we believe that +the accounting policies discussed below are critical to understanding our historical and future performance, as these policies relate +to the more significant areas involving management’s judgments and estimates. +Accounts +Receivable +Trade +accounts receivable are recorded at the invoiced amount, net of any allowance. The Company maintains an allowance for doubtful accounts +for amounts the Company does not expect to collect. In establishing the required allowance, management considers historical losses, current +market condition, customers’ financial condition, the age of receivables, and current payment patterns. Account balances are written +off against the allowance once the receivable is deemed uncollectible. If actual accounts receivable collections are less favorable than +those projected by management at the time of the assessment, however, additional accounts receivable write-downs may be required, which +could reduce our earnings. +31 +Goodwill +and Intangible Assets +The +useful lives of intangible assets with definite lives are based on the expected number of years the asset will generate revenue or otherwise +be used by us and the related amortization is based on the straight-line method. Goodwill, which has an indefinite life, is not amortized +but instead is tested at least annually for impairment, or more frequently when events or changes in circumstances indicate that the +asset might be impaired. Examples of such events or circumstances include: +● +the +asset’s ability to continue to generate income from operations and positive cash flow in future periods; +● +any +volatility or significant decline in our stock price and market capitalization compared to our net book value; +● +loss +of legal ownership or title to an asset; +● +significant +changes in our strategic business objectives and utilization of our assets; and +● +the +impact of significant negative industry or economic trends. +If +a change were to occur in any of the above-mentioned factors or estimates, the likelihood of a material change in our reported results +would increase. For goodwill, the entity has the option to first assess qualitative factors to determine whether it is necessary to perform +the quantitative goodwill impairment test. The quantitative impairment test compares the fair value of a reporting unit with the carrying +amount, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill is considered not impaired; otherwise, +goodwill is impaired and the loss is recorded. Upon the completion of our annual evaluation for impairment of goodwill as of December +31, 2022, we recorded a goodwill impairment charge of $15.4 million. +Inventories +We +periodically review inventory for both potential obsolescence and potential declines in anticipated selling prices. In this review, we +make assumptions about the future demand for and market value of the inventory and based on these assumptions estimate the amount of +any obsolete, unmarketable, slow moving or overvalued inventory. We write down the value of our inventories by an amount equal to the +difference between the cost of the inventory and the net realizable value. If actual market conditions are less favorable than those +projected by management at the time of the assessment, however, additional inventory write-downs may be required, which could reduce +our earnings. +Income +Taxes +Significant +judgment is required in determining our provision for income taxes, current tax assets and liabilities, deferred tax assets and liabilities, +and our future taxable income, both as a whole and in various tax jurisdictions, for purposes of assessing our ability to realize future +benefit from our deferred tax assets. We recognize in the financial statements the impact of a tax position if that position is more +likely than not to be sustained during an audit, including resolution of related appeals or litigation processes, if any. While we believe +that we have appropriate support for the positions taken on our tax returns, we regularly assess the potential outcome of examinations +by tax authorities in determining the adequacy of our provision for income taxes. See Note 11 to our Consolidated Financial Statements +for more information on income taxes. +The +foregoing estimates, expectations and forward-looking statements are subject to change as we make strategic operating decisions from +time to time and as our revenue and expenses fluctuate from period to period. +ITEM +7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Not +required. +32 +ITEM +8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. +CONSOLIDATED +FINANCIAL STATEMENTS +DECEMBER +31, 2023 AND 2022 +Table +of Contents +Reports of Independent Registered Public Accounting Firms (PCAOB ID No. 270 and ID No. 457 ) +34 +Consolidated Balance Sheets +36 +Consolidated Statements of Operations +37 +Consolidated Statement of Changes in Stockholders’ Equity +38 +Consolidated Statements of Cash Flows +39 +Notes to Consolidated Financial Statements +40 +33 +Report +of Independent Registered Public Accounting Firm +To +the Board of Directors and Stockholders +Co-Diagnostics, +Inc. +Opinion +on the Consolidated Financial Statements +We +have audited the accompanying consolidated balance sheet of Co-Diagnostics Inc. and subsidiaries (the Company) as of December 31, 2023, +the related consolidated statements of operations and comprehensive loss, changes in stockholders’ equity, and cash flows for the +year then ended, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial +statements referred to above present fairly, in all material respects, the consolidated financial position of the Company as of December +31, 2023, and the consolidated results of its operations and its cash flows for the year then ended, in conformity with accounting principles +generally accepted in the United States of America. +Basis +for Opinion +These +consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion +on the Company’s consolidated financial statements based on our audit. We are a public accounting firm registered with the Public +Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance +with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We +conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain +reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. +The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part +of our audit, we are required to obtain an understanding of internal control over financial reporting, but not for the purpose of expressing +an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. +Our +audit included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due +to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence +regarding the amounts and disclosures in the consolidated financial statements. Our audit also included evaluating the accounting principles +used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. +We believe that our audit provides a reasonable basis for our opinion. +Critical +Audit Matters +The +critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements +that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are +material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The +communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, +and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the +accounts or disclosures to which they relate. +Estimation +of the Fair Value of Intangible Assets +As +more fully described in Notes 2 and 6 to the consolidated financial statements, the Company acquired Idaho Molecular, Inc., and Advanced +Conceptions, Inc. in December 2021. As part of the transaction, the Company acquired in-process research and development indefinite-lived +intangible assets totaling $26,101,000. The Company assesses these assets for impairment at least annually or whenever events or changes +in circumstances occur that may indicate impairment. The Company’s analysis for the year ended December 31, 2023, required significant +judgment to assess qualitative factors in determining whether it is more likely than not that the indefinite-lived intangible asset is +impaired. As a result of their analysis, the Company determined there was no impairment as of year-end. +Auditing +the Company’s annual impairment assessment was complex and highly judgmental due to the significant judgement required in determining +whether it is more likely than not that an indefinite-lived intangible asset is impaired. This required a high degree of auditor judgement, +subjectivity and effort in performing procedures and evaluating audit evidence to evaluate management assessment in evaluating these +indefinite-lived intangibles for impairment. These procedures included among others: (1) evaluating management’s process for evaluating +for impairment, (2) evaluating the factors assessed by management (3) evaluating other relevant factors in making our own determination, +and (4) evaluating and discussing considerations and conclusions made by management. +/s/ +Tanner LLC +We +have served as the Company’s auditor since 2023 +Salt +Lake City, Utah +March +14, 202 4 +34 +REPORT +OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM +To +the Board of Directors and Stockholders of Co-Diagnostics, Inc. +Opinion +on the Financial Statements +We +have audited the accompanying consolidated balance sheet of Co-Diagnostics, Inc (the Company) as of December 31, 2022, and +the related consolidated statements of operations and comprehensive income (loss), changes in stockholders’ equity, and cash flows +for the year ended December 31, 2022, and the related notes (collectively referred to as the financial +statements). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company +as of December 31, 2022, and the results of its operations and its cash flows for the year ended +December 31, 2022, in conformity with accounting principles generally accepted in the United States of America. +Basis +for Opinion +These +financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s +financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board +(United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities +laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. +We +conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain +reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company +is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audit, +we are required to obtain an understanding of internal control over financial reporting, but not for the purpose of expressing an opinion +on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. +Our +audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error +or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding +the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant +estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion. +/s/ +Haynie & Company +Salt +Lake City, Utah +March +16, 2023 +We +began serving as the Company’s auditor in 2016. In 2023, we became the predecessor auditor. +35 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +CONSOLIDATED +BALANCE SHEETS +December 31, 2023 +December 31, 2022 +Assets +Current assets +Cash and cash equivalents +$ 14,916,878 +$ 22,973,803 +Marketable investment securities +43,631,510 +58,289,066 +Accounts receivable, net +303,926 +3,453,723 +Inventory, net +1,664,725 +5,310,473 +Income taxes receivable +26,955 +1,870,419 +Prepaid expenses and other current assets +1,597,114 +761,187 +Note receivable +- +75,000 +Total current assets +62,141,108 +92,733,671 +Property and equipment, net +3,035,729 +2,539,483 +Operating lease right-of-use asset +2,966,774 +372,115 +Intangible assets, net +26,403,667 +26,768,333 +Investment in joint venture +773,382 +672,679 +Total assets +$ 95,320,660 +$ 123,086,281 +Liabilities and stockholders’ equity +Current liabilities +Accounts payable +$ 1,482,109 +$ 952,296 +Accrued expenses +2,172,959 +934,447 +Operating lease liability, current +838,387 +297,209 +Contingent consideration liabilities, current +891,666 +1,689,471 +Deferred revenue +362,449 +- +Total current liabilities +5,747,570 +3,873,423 +Long-term liabilities +Income taxes payable +659,186 +1,181,284 +Deferred tax liability +- +2,417,987 +Operating lease liability +2,152,180 +50,708 +Contingent consideration liabilities +748,109 +1,042,885 +Total long-term liabilities +3,559,475 +4,692,864 +Total liabilities +9,307,045 +8,566,287 +Commitments and contingencies (Note 12) +Stockholders’ equity +Convertible preferred stock, $ 0.001 par value; 5,000,000 shares authorized; 0 shares issued and outstanding as of December 31, 2023 and December 31, 2022, respectively +- +- +Common stock, $ 0.001 par value; 100,000,000 shares authorized; 36,108,346 shares issued and 31,259,668 shares outstanding as of December 31, 2023 and 34,754,265 shares issued and 30,872,607 shares outstanding as of December 31, 2022 +36,108 +34,754 +Treasury stock, at cost; 4,848,678 and 3,881,658 shares held as of December 31, 2023 and December 31, 2022, respectively +( 15,575,795 ) +( 14,211,866 ) +Additional paid-in capital +96,808,436 +88,472,935 +Accumulated other comprehensive income +146,700 +293,140 +Accumulated earnings +4,598,166 +39,931,031 +Total stockholders’ equity +86,013,615 +114,519,994 +Total liabilities and stockholders’ equity +$ 95,320,660 +$ 123,086,281 +See +accompanying notes to consolidated financial statements. +36 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS +Years Ended December 31, +2023 +2022 +Product revenue +$ 991,473 +$ 34,218,209 +Grant revenue +5,820,565 +- +Total revenue +6,812,038 +34,218,209 +Cost of revenue +4,184,949 +5,481,093 +Gross profit +2,627,089 +28,737,116 +Operating expenses +Sales and marketing +6,860,815 +7,344,628 +General and administrative +14,279,441 +14,262,963 +Research and development +22,962,593 +17,438,098 +Depreciation and amortization +1,230,474 +1,282,718 +Goodwill impairment charges +- +15,388,546 +Total operating expenses +45,333,323 +55,716,953 +Loss from operations +( 42,706,234 ) +( 26,979,837 ) +Other income, net +Interest income +1,161,913 +704,045 +Realized gain on investments +2,243,059 +- +Loss on disposition of assets +( 2,578 ) +( 138,117 ) +Gain on remeasurement of acquisition contingencies +1,092,581 +7,899,644 +Gain (loss) on equity method investment in joint venture +100,703 +( 332,969 ) +Total other income, net +4,595,678 +8,132,603 +Loss before income taxes +( 38,110,556 ) +( 18,847,234 ) +Income tax benefit +( 2,777,691 ) +( 4,608,985 ) +Net loss +$ ( 35,332,865 ) +$ ( 14,238,249 ) +Other comprehensive loss +Change in net unrealized gains on marketable securities, net of tax +$ ( 146,440 ) +$ 293,140 +Total other comprehensive income (loss) +$ ( 146,440 ) +$ 293,140 +Comprehensive loss +$ ( 35,479,305 ) +$ ( 13,945,109 ) +Loss per common share: +Basic +$ ( 1.20 ) +$ ( 0.45 ) +Diluted +$ ( 1.20 ) +$ ( 0.45 ) +Weighted average shares outstanding: +Basic +29,346,599 +31,479,028 +Diluted +29,346,599 +31,479,028 +See +accompanying notes to consolidated financial statements. +37 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY +Shares +Amount +Shares +Amount +Stock +Capital +Income +Earnings +Equity +Convertible +Preferred Stock +Common Stock +Treasury +Additional +Paid-in +Accumulated +Other +Comprehensive +Accumulated +Total +Stockholders’ +Shares +Amount +Shares +Amount +Stock +Capital +Income +Earnings +Equity +Balance as of December 31, 2021 +- +$ - +33,819,862 +$ 33,820 +$ - +$ 80,271,999 +$ - +$ 54,169,280 +$ 134,475,099 +Common stock issued for option exercises +- +- +70,791 +70 +- +77,800 +- +- +77,870 +Common stock issued for warrant exercises +- +- +50,000 +50 +- +99,950 +- +- +100,000 +Stock-based compensation expense +- +- +725,166 +725 +- +7,542,498 +- +- +7,543,223 +Common stock issued for acquisitions +- +- +88,446 +89 +- +480,687 +- +- +480,776 +Repurchases of common stock +- +- +- +- +( 14,211,866 ) +- +- +- +( 14,211,866 ) +Other comprehensive income, net of tax +- +- +- +- +- +- +293,140 +- +293,140 +Net loss +- +- +- +- +- +- +- +( 14,238,249 ) +( 14,238,249 ) +Balance as of December 31, 2022 +- +$ - +34,754,265 +$ 34,754 +$ ( 14,211,866 ) +$ 88,472,935 +$ 293,140 +$ 39,931,031 +$ 114,519,994 +Balance +- +$ - +34,754,265 +$ 34,754 +$ ( 14,211,866 ) +$ 88,472,935 +$ 293,140 +$ 39,931,031 +$ 114,519,994 +Stock-based compensation expense +- +- +1,354,081 +1,354 +- +8,335,501 +- +- +8,336,855 +Repurchases of common stock +- +- +- +- +( 1,363,929 ) +- +- +- +( 1,363,929 ) +Other comprehensive loss, net of tax +- +- +- +- +- +- +( 146,440 ) +- +( 146,440 ) +Net loss +- +- +- +- +- +- +- +( 35,332,865 ) +( 35,332,865 ) +Balance as of December 31, 2023 +- +$ - +36,108,346 +$ 36,108 +$ ( 15,575,795 ) +$ 96,808,436 +$ 146,700 +$ 4,598,166 +$ 86,013,615 +Balance +- +$ - +36,108,346 +$ 36,108 +$ ( 15,575,795 ) +$ 96,808,436 +$ 146,700 +$ 4,598,166 +$ 86,013,615 +See +accompanying notes to consolidated financial statements. +38 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF CASH FLOWS +Years Ended December 31, +2023 +2022 +Cash flows from operating activities +Net loss +$ ( 35,332,865 ) +$ ( 14,238,249 ) +Adjustments to reconcile net loss to cash (used in) provided by operating activities: +Depreciation and amortization +1,230,474 +1,282,718 +Goodwill impairment charges +- +15,388,546 +Stock-based compensation expense +8,336,855 +7,543,223 +Change in fair value of acquisition contingencies +( 1,092,581 ) +( 7,899,644 ) +Non-cash lease expense +47,992 +30,430 +Realized gain on investments +( 2,243,059 ) +- +(Gain) loss from equity method investment +( 100,703 ) +332,969 +Loss on disposition of assets +2,578 +138,117 +Deferred income taxes +( 2,417,987 ) +( 4,810,457 ) +Provision for credit losses +612,809 +2,461,032 +Inventory obsolescence expense +3,233,281 +148,099 +Changes in assets and liabilities: +Accounts receivable +2,536,988 +14,924,427 +Prepaid expenses and other assets +1,082,536 +( 224,094 ) +Inventory +413,140 +( 3,673,309 ) +Deferred revenue +362,449 +( 150,000 ) +Income taxes payable +( 522,098 ) +( 2,201,250 ) +Accounts payable, accrued expenses and other liabilities +1,768,326 +( 2,483,821 ) +Net cash (used in) provided by operating activities +( 22,081,865 ) +6,568,737 +Cash flows from investing activities +Purchases of property and equipment +( 1,365,306 ) +( 1,427,512 ) +Proceeds from maturities of marketable investment securities +127,251,619 +11,255,266 +Purchases of marketable securities +( 110,497,444 ) +( 67,995,926 ) +Net cash (used in) provided by investing activities +15,388,869 +( 58,168,172 ) +Cash flows from financing activities +Proceeds from exercise of options and warrants +- +177,870 +Repurchases of common stock +( 1,363,929 ) +( 14,211,866 ) +Net cash (used in) financing activities +( 1,363,929 ) +( 14,033,996 ) +Net decrease in cash and cash equivalents +( 8,056,925 ) +( 65,633,431 ) +Cash and cash equivalents at beginning of period +22,973,803 +88,607,234 +Cash and cash equivalents at end of period +$ 14,916,878 +$ 22,973,803 +Supplemental disclosure of cash flow information +Interest paid +$ - +$ - +Income taxes paid +$ 55,975 +$ 4,498,742 +Supplemental disclosure of non-cash investing and financing transactions +Inventory moved to property, plant and equipment +$ 673 +$ 218,906 +Right-of-use assets obtained in exchange for new operating lease liabilities +$ 3,203,146 +$ 681,327 +Business acquisition measurement period adjustments +$ - +$ 1,593 +Fair value of common stock issued as consideration for business acquisitions +$ - +$ 480,776 +Fair value of contingent common stock issued as consideration for business acquisitions +$ - +$ 199,359 +See +accompanying notes to consolidated financial statements. +39 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS +YEARS +ENDED DECEMBER 31, 2023 AND 2022 +Note +1 – Overview and Basis of Presentation +Description +of Business +Co-Diagnostics, +Inc., a Utah corporation (the “Company” or “CODX”), is a molecular diagnostics company that develops, manufactures +and markets state-of-the-art diagnostics technologies. The Company’s technologies are utilized for tests that are designed using +the detection and/or analysis of nucleic acid molecules (DNA or RNA). The Company also uses its proprietary technology to design specific +tests for its Co-Dx PCR platform and to locate genetic markers for use in applications other than infectious disease. In connection with +the sale of our tests we may sell diagnostic equipment from other manufacturers as self-contained lab systems. +Use +of Estimates +The +preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates +and assumptions that affect the amounts reported in the financial statements and the accompanying notes. Such estimates include inventories, +receivables and other long-lived assets, legal and regulatory contingencies, income taxes, share based arrangements, and others. These +estimates and assumptions are based on management’s best estimates and judgments. Actual amounts and results could differ from +those estimates. +Basis +of Presentation +The +accompanying audited consolidated financial statements of Co-Diagnostics, Inc. and its wholly owned subsidiaries have been prepared to +reflect the financial position, results of operations and cash flows of the Company and have been prepared in accordance with accounting +principles generally accepted in the United States of America (“GAAP”). All intercompany balances and transactions have been +eliminated. +Note +2 – Summary of Significant Accounting Policies +Reclassifications +Certain +prior year amounts have been reclassified to conform with the current year’s presentation. These reclassifications have no impact +on the previously reported results. +Cash +and Cash Equivalents +Cash +and cash equivalents consist of cash on hand, money market funds and highly liquid investments with an original maturity date of 90 days +or less from the date of purchase. The fair value of cash equivalents approximated their carrying value as of December 31, 2023 and December +31, 2022. The Company has its cash and cash equivalents with a large creditworthy financial institution +and the balance exceeded federally insured limits. The Company has not experienced any losses in such accounts, and management believes +the Company is not exposed to any significant credit risk on cash and cash equivalents. +40 +Marketable +Investment Securities +The +Company’s marketable investment securities are comprised of investments in certificates of deposit and U.S. Treasury bills and +notes. The Company designates investments in debt securities as available-for-sale. Available-for-sale debt securities with original +maturities of three months or less from the date of purchase are classified within cash and cash equivalents. Available-for-sale debt +securities with original maturities longer than three months are available to fund current operations and are classified as marketable +investment securities, within current assets on the consolidated balance sheets. The Company may sell these securities at any time for +use in its current operations or for other purposes, even prior to maturity. Available-for-sale debt securities are reported at fair +value with the related unrealized gains and losses included in accumulated other comprehensive income (loss), a component of stockholders’ +equity, net of tax. Realized gains and losses on the sale of marketable securities are determined using the average cost method on a +first-in, first-out basis and recorded in total other income (expense), net in the consolidated statements of operations and +comprehensive loss. +The +available-for-sale debt securities are subject to a periodic impairment review. For investments in an unrealized loss position, the Company +writes down the amortized cost basis of the investment if it is more likely than not that the Company will be required or will intend +to sell the investment before recovery of its amortized cost basis. For investments not likely to be sold before recovery of the amortized +cost basis, the Company determines whether a credit loss exists by considering information about the collectability of the instrument, +current market conditions, and reasonable and supportable forecasts of economic conditions. The Company recognizes an allowance for credit +losses up to the amount of the unrealized loss when appropriate. Allowances for credit losses and write-downs are recognized in total +other income (expense), net, and unrealized losses not related to credit losses are recognized in accumulated other comprehensive income +(loss). There are no allowances for credit losses recorded for the periods presented. +Accounts +Receivable +Trade +accounts receivable are recorded at the invoiced amount (net of allowance) and do not bear interest. The Company maintains an allowance +for doubtful accounts for amounts the Company does not expect to collect. In establishing the required allowance, management considers +historical losses, current market condition, customers’ financial condition, the age of receivables, and current payment patterns. +Account balances are written off against the allowance once the receivable is deemed uncollectible. Recoveries of trade receivables previously +written off are recorded when collected. At December 31, 2023 total accounts receivable was $ 504,264 with an allowance for uncollectable +accounts of $ 200,338 resulting in a net amount of $ 303,926 . At December 31, 2022 total accounts receivable was $ 6,552,249 with an allowance +for uncollectable accounts of $ 3,098,526 resulting in a net amount of $ 3,453,723 . +Equity-Method +Investments +Our +equity method investments are initially recorded at cost and are included in other long-term assets in the accompanying consolidated +balance sheet. We adjust the carrying value of our investment based on our share of the earnings or losses in the periods which they +are reported by the investee until the carrying amount is zero. The earnings or losses are included in other income (expense) in the +accompanying consolidated statements of operations. +Inventory +Inventory +is stated at the lower of cost or net-realizable value. Inventory cost is determined on a first-in first-out basis that approximates +average cost in accordance with ASC 330-10-30-12. At December 31, 2023, the Company had $ 1,664,725 in inventory, of which $ 700,467 was +finished goods and $ 964,258 was raw materials. At December 31, 2022, the Company had $ 5,310,473 in inventory, of which $ 1,327,264 was +finished goods and $ 3,983,209 was raw materials. The Company establishes reserves to reduce low-moving, obsolete, or unusable inventories +to their estimated useful or scrap values. The Company recognized $ 2,760,011 and $ 0 related to the change in inventory reserves during +the years ended December 31, 2023 and 2022, respectively. +41 +Goodwill +and Intangible Assets +Goodwill +represents the excess of the purchase price and related costs over the value assigned to net tangible and identifiable intangible assets +acquired in business combinations. Goodwill and indefinite-lived intangible assets are not amortized, but rather tested for impairment +at least annually on December 31, or more often if and when circumstances indicate that the carrying value may not be recoverable. Finite-lived +intangible assets are amortized over their useful lives. +During +the years ended December 31, 2023 and 2022, the Company recognized impairment charges related to goodwill of $ 0 and $ 15,388,546 , respectively. +Long-lived +Assets +Long-lived +assets, such as property and equipment, are stated at cost less accumulated depreciation and amortization. Depreciation is provided using +the straight-line method over the estimated useful lives of the property, generally from three to five years. Repairs and maintenance +costs are expensed as incurred except when such repairs significantly add to the useful life or productive capacity of the asset, in +which case the repairs are capitalized. +For +in-process research and development projects acquired in business combinations, the in-process research and development project is capitalized +and evaluated for impairment until the development process has been completed. Once the development process has been completed the asset +will be amortized over its remaining estimated useful life. The Company reviews its long-lived assets, including property and equipment, +indefinite-lived and finite-lived intangible assets, and ROU assets, for impairment whenever an event or change in facts and circumstances +indicates that their carrying amounts may not be recoverable. Recoverability of these assets is measured by comparing the carrying amount +to the estimated undiscounted future cash flows expected to be generated. If the carrying amount exceeds the undiscounted cash flows, +the assets are determined to be impaired and an impairment charge is recognized as the amount by which the carrying amount exceeds fair +value. +Revenue +Recognition +The +Company generates revenue from product sales and license sales. The Company recognizes revenue when all of the following criteria are +satisfied: (i) identification of the promised goods or services in the contract; (ii) determination of whether the promised goods or +services are performance obligations, including whether they are distinct in the context of the contract; (iii) measurement of the transaction +price, including the constraint on variable consideration; (iv) allocation of the transaction price to the performance obligations; and +(v) recognition of revenue when, or as the Company satisfies each performance obligation. Based on the criteria above, the Company typically +recognizes revenue upon delivery. +The +Company constrains revenue by giving consideration to factors that could otherwise lead to a probable reversal of revenue. The Company +records any payments received from customers prior to the Company fulfilling its performance obligation(s) as deferred revenue. +Grant +Revenue +The +Company may submit applications to receive grant funding from governmental and non-governmental entities. The Company accounts for grants +by analogizing to the contribution accounting model under ASC 958-605, Not-for-Profit Entities (“ASC 958”). Revenues from +grants, contracts, and awards provided by governmental and non-governmental agencies are recorded based upon the terms of the specific +agreements. The Company recognizes grant funding without conditions or continuing performance obligations as revenue in the consolidated statements of operations and comprehensive income (loss). The Company recognizes grant funding with conditions or continuing +performance obligations as deferred revenue in the consolidated balance sheets if the conditions or performance obligations +have not yet been met. The Company recognized grant funding revenue of $ 5.8 million during the year ended December 31, 2023. At December +31, 2023, the Company has also recorded $ 0.3 million of deferred revenue related to grant funding for which the cash was received, but +the underlying conditions or performance obligations have not yet been met. Cash received from federal grants, contracts, and awards +can be subject to audit by the grantor and, if the examination results in a disallowance of any expenditure, repayment could be required. +Deferred +Revenue +Deferred +revenue primarily consists of payments received from customers prior to the Company fulfilling its performance obligation of providing +the product. When this occurs, the Company records a contract liability as deferred revenue. Deferred revenue is recognized as revenue +as the related performance obligations are satisfied. +42 +Research +and Development +Research +and development costs are expensed when incurred. The Company recorded $ 22,962,593 and $ 17,438,098 of research and development costs +for the years ended December 31, 2023 and 2022, respectively. +Stock-based +Compensation +The +Company has granted stock-based awards, including restricted stock, stock options, stock warrants and restricted stock units (“RSUs”), +to its employees, certain consultants and members of its board of directors. The Company records stock-based compensation based on the +grant date fair value of the awards and recognizes the fair value of those awards as expense using the straight-line method over the +requisite service period of the award. The Company estimates the grant date fair value of stock options using the Black-Scholes option-pricing +model. When an award is forfeited prior to the vesting date, the Company recognizes an adjustment +for the previously recognized expense in the period of the forfeiture. +Income +Taxes +The +Company accounts for income taxes in accordance with the liability method of accounting for income taxes. Under this method, d eferred +income tax assets and deferred income tax liabilities represent the tax effect of temporary differences between financial reporting and +tax reporting measured at enacted tax rates in effect for the year in which the differences are expected to reverse. The Company recognizes +only the impact of tax positions that, based on their technical merits, are more likely than not to be sustained upon an audit by the +taxing authority. +Valuation +allowances are provided when it is more-likely-than-not that some or all of the deferred income tax assets may not be realized. In assessing +the need for a valuation allowance, the Company has considered its historical levels of income, expectations of future taxable income +and ongoing tax planning strategies. +Developing +the provision for income taxes, including the effective tax rate and analysis of potential tax exposure items, if any, requires significant +judgment and expertise in federal and state income tax laws, regulations and strategies, including the determination of deferred income +tax assets and liabilities and any estimated valuation allowances deemed necessary to value deferred income tax assets. Judgments and +tax strategies are subject to audit by various taxing authorities. The Company has uncertain income tax positions in the consolidated +financial statements, and adverse determinations by these taxing authorities could have a material adverse effect on the consolidated +financial positions, result of operations, or cash flows. +Net +Income (Loss) per Share +Basic +net income or loss per common share is computed by dividing net income or loss applicable to common shareholders by the weighted average +number of shares outstanding during each period. +Diluted +net income or loss per share is computed by dividing net income or loss attributable to common stockholders by the weighted-average number +of shares of common stock outstanding during the period increased by common shares that could be issued upon conversion or exercise of +other outstanding securities to the extent those additional common shares would be dilutive. The dilutive effect of potentially dilutive +securities is reflected in diluted net income or loss per share by application of the treasury stock method. During periods when the +Company is in a net loss position, basic net loss per share is the same as diluted net loss per share as the effects of potentially dilutive +securities are anti-dilutive. +Comprehensive +Income (Loss) +Comprehensive +loss is comprised of net loss and unrealized gains and losses on marketable securities, net of income taxes. +Concentrations +Risk and Significant Customers +The +Company had certain customers which were each responsible for generating 10 % or more of the total revenue for the years ended December +31, 2023 and 2022, respectively. Two customers accounted for approximately 28 % of product revenue for the year ended December 31, 2023 +and one customer accounted for approximately 37 % of product revenue for the year ended December 31, 2022. One granting agency accounted +for 100 % of grant revenue for the year ended December 31, 2023. +43 +Three +customers accounted for more than 10 % of accounts receivable at December 31, 2023 and 2022, respectively. These customers together accounted +for approximately 97 % and 61 % of accounts receivable at December 31, 2023 and 2022, respectively. +Recently +Issued Accounting Standards +From +time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”) that are adopted +by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, +which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption. +In +December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which requires an entity +to disclose annually additional information related to the company’s income tax rate reconciliation and income taxes paid during +the period. The guidance should be applied prospectively with the option to apply the standard retrospectively. The standard becomes +effective for the Company for full year 2025 reporting. The Company is currently evaluating the impact of this new standard on its consolidated +financial statements. +Note +3 – Cash, Cash Equivalents, and Financial Instruments +The +following table shows the Company’s cash, cash equivalents, and marketable investment securities by significant investment category: +Schedule +of Cash, Cash Equivalents and Marketable Investment Securities +December 31, 2023 +Adjusted Cost +Allowance for Credit Losses +Total Unrealized Gains / (Losses) +Fair Value +Cash and Cash Equivalents +Marketable Investment Securities +Cash +$ 4,317,449 +$ - +$ - +$ 4,317,449 +$ 4,317,449 +$ - +Level 1: +Money market funds +10,599,429 +- +- +10,599,429 +10,599,429 +- +Subtotal +10,599,429 +- +- +10,599,429 +10,599,429 +- +Level 2: +U.S. treasury securities +43,484,810 +- +146,700 +43,631,510 +- +43,631,510 +Subtotal +43,484,810 +- +146,700 +43,631,510 +- +43,631,510 +Total +$ 58,401,688 +$ - +$ 146,700 +$ 58,548,388 +$ 14,916,878 +$ 43,631,510 +December 31, 2022 +Adjusted Cost +Allowance for Credit Losses +Total Unrealized Gains / (Losses) +Fair Value +Cash and Cash Equivalents +Marketable Securities +Cash +$ 12,834,444 +$ - +$ - +$ 12,834,444 +$ 12,834,444 +$ - +Level 1: +Money market funds +146,359 +- +- +146,359 +146,359 +- +Subtotal +146,359 +- +- +146,359 +146,359 +- +Level 2: +U.S. treasury securities +67,892,825 +- +389,241 +68,282,066 +9,993,000 +58,289,066 +Subtotal +67,892,825 +- +389,241 +68,282,066 +9,993,000 +58,289,066 +Total +$ 80,873,628 +$ - +$ 389,241 +$ 81,262,869 +$ 22,973,803 +$ 58,289,066 +Marketable +investment securities held as of December 31, 2023 mature over the next 12 months. +Note +4 – Fair Value Measurements +The +Company measures and records certain financial assets and liabilities at fair value on a recurring basis. Fair value is based on the +price that would be received from selling an asset or paid to transfer a liability in an orderly transaction between market participants +at the measurement date. +The +following three levels of inputs are used to measure the fair value of financial assets and liabilities: +Level +1: Quoted market prices in active markets for identical assets or liabilities. +Level +2: Observable market-based inputs or unobservable inputs that are corroborated by market data. +Level +3: Unobservable inputs that are not corroborated by market data. +44 +The +following table summarizes the assets and liabilities measured at fair value on a recurring basis as of December 31, 2023 and December +31, 2022, by level within the fair value hierarchy: +Schedule +of Fair Value Assets and Liabilities +(Level 1) +(Level 2) +(Level 3) +Total +December 31, 2023 +(Level 1) +(Level 2) +(Level 3) +Total +Assets: +Cash equivalents +$ 13,806,864 +$ - +$ - +$ 13,806,864 +Marketable securities (U.S. treasury bills and notes) +- +43,631,510 +- +43,631,510 +Total assets measured at fair value +$ 13,806,864 +$ 43,631,510 +$ - +$ 57,438,374 +Liabilities: +Contingent consideration - common stock +$ - +$ - +$ 1,318,995 +$ 1,318,995 +Contingent consideration - warrants +- +- +320,780 +320,780 +Total liabilities measured at fair value +$ - +$ - +$ 1,639,775 +$ 1,639,775 +(Level 1) +(Level 2) +(Level 3) +Total +December 31, 2022 +(Level 1) +(Level 2) +(Level 3) +Total +Assets: +Cash equivalents +$ 186,667 +$ 9,993,000 +$ - +$ 10,179,667 +Marketable securities (U.S. treasury bills and notes) +- +58,289,066 +- +58,289,066 +Total assets measured at fair value +$ 186,667 +$ 68,282,066 +$ - +$ 68,468,733 +Liabilities: +Contingent consideration - common stock +$ - +$ - +$ 2,499,147 +$ 2,499,147 +Contingent consideration - warrants +- +- +233,209 +233,209 +Total liabilities measured at fair value +$ - +$ - +$ 2,732,356 +$ 2,732,356 +The +Company’s financial instruments that are measured at fair value on a recurring basis consist of certificates of deposit and U.S. +treasury bills and notes as of December 31, 2023 and 2022, respectively. +In +connection with prior year acquisitions, the Company recorded a liability for contingent consideration in the form of shares of common +stock and warrants to purchase common stock, both to be issued when certain milestones are achieved. The fair value of contingent consideration is calculated using a discounted probability +weighted valuation model. Discount rates used in such calculations are a significant assumption that are not observed in the market, +and therefore, the resulting fair value represents a Level 3 measurement. +The +changes for Level 3 items measured at fair value on a recurring basis are as follows: +Schedule +of Changes in the Fair Value Measurement +Fair value as of December 31, 2022 +$ 2,732,356 +Change in fair value of contingent consideration issued for business acquisitions +( 1,092,581 ) +Fair value as of December 31, 2023 +$ 1,639,775 +45 +The +fair value of the contingent consideration is based on the fair value of the contingent consideration-common stock and contingent consideration-warrants. +The fair value of the contingent consideration-common stock is equal to the probability-adjusted value of the Company’s common +stock as of the valuation date. The fair value of the contingent consideration-warrants is equal to the probability adjusted value of +a call option with terms consistent with the terms of the warrants as of the valuation date. Prior to the probability adjustments, the +warrants were valued based on the following inputs: +Schedule +of Contingent Consideration Common Stock and Warrants +December 31, 2023 +December 31, 2022 +Stock price +$ 1.33 +$ 2.52 +Strike price +$ 9.13 +$ 9.13 +Volatility +187.5 % +75.0 % +Risk-free rate +4.0 % +4.1 % +Expected term (years) +3.0 +4.0 +Fair +Value of Other Financial Instruments +The +carrying amounts of certain financial instruments, including cash held in banks, accounts receivable, notes receivable, accounts payable, +accrued liabilities, and other liabilities approximate fair value due to their short-term maturities and are excluded from the fair value +tables above. +Note +5 – Property and Equipment +Property +and equipment, net consisted of the following: +Schedule +of Property and Equipment +Estimated +December 31, +Useful Lives in years +2023 +2022 +Lab equipment +3 - 5 +$ 4,545,908 +$ 3,574,730 +Leasehold improvements +0 - 5 +548,648 +224,957 +Office equipment, furniture and other +2 - 5 +173,668 +112,044 +Less accumulated depreciation and amortization +( 2,232,495 ) +( 1,372,248 ) +Fixed assets, net +$ 3,035,729 +$ 2,539,483 +Note +6 – Goodwill and Intangible Assets +Goodwill +Goodwill +represents the excess of purchase price and related costs over the value assigned to net tangible and identifiable intangible assets +acquired in business combinations. The following table presents the changes in the carrying amount of goodwill: +Schedule +of Goodwill +Balance as of December 31, 2021 +$ 14,706,818 +Measurement period adjustments +681,728 +Goodwill impairment charges +( 15,388,546 ) +Balance as of December 31, 2022 +$ - +46 +The +Company assesses goodwill for impairment at the reporting unit level on an annual basis, or whenever events or changes in circumstances +occur that indicate that the fair value of a reporting unit is below its carrying amount. The Company estimates the fair value of its +reporting unit by using forecasts of discounted future cash flows and peer market multiples. If the fair value is less than the carrying +value, impairment will be recognized in the amount by which the carrying value exceeds the fair value. The Company performed a qualitative +and quantitative goodwill impairment assessment as of December 31, 2022. Based on the impairment assessment performed the Company concluded +that it was more likely than not that the fair value of the Company’s reporting unit was less than it’s carrying amount. +Accordingly, the Company recorded an impairment charge to reduce the carrying value of goodwill to $ 0 . +Intangible +Assets, Net +Intangible +assets, net consisted of the following: +Schedule of Intangible Assets, Net +December 31, 2023 +Weighted-Average +Gross +Net +Useful Life (1) +Carrying +Accumulated +Carrying +(in Years) +Amount +Amortization +Amount +In-process research and development +Indefinite +$   26,101,000 +$ - +$ 26,101,000 +Non-competition agreements +2.7 +1,094,000 +( 791,333 ) +302,667 +Total intangible assets +$ 27,195,000 +$ ( 791,333 ) +$ 26,403,667 +December 31, 2022 +Weighted-Average +Gross +Net +Useful Life (1) +Carrying +Accumulated +Carrying +(in Years) +Amount +Amortization +Amount +In-process research and development +Indefinite +$ 26,101,000 +$ - +$ 26,101,000 +Non-competition agreements +2.7 +1,094,000 +( 426,667 ) +667,333 +Total intangible assets +$ 27,195,000 +$ ( 426,667 ) +$ 26,768,333 +(1) Based on weighted-average +useful life established as of the acquisition date. +47 +The +expected future annual amortization expense of the Company’s intangible assets held as of December 31, 2023 is as follows: +Schedule +of Future Amortization Expense +Year Ending December 31, +Amortization Expense +2024 +302,667 +Total +$ 302,667 +Note +7 - Accrued Expenses +Accrued +expenses consisted of the following: +Schedule of Accrued Expenses +December 31, 2023 +December 31, 2022 +Payroll liabilities +$ 1,643,186 +$ 428,354 +Distributor commissions +9,958 +159,725 +Other accrued liabilities +519,815 +346,368 +Total accrued expenses +$ 2,172,959 +$ 934,447 +Note +8 – Revenue +The +following table sets forth revenue by geographic area: +Summary +of Revenue by Geographic Area +2023 +2022 +Years Ended December 31, +2023 +2022 +United States +Product revenue +$ 659,618 +$ 24,671,554 +Grant revenue +5,820,565 +- +Total United States +6,480,183 +24,671,554 +Rest of World +Product revenue +331,855 +9,546,655 +Grant revenue +- +- +Total Rest of World +331,855 +9,546,655 +Total +$ 6,812,038 +$ 34,218,209 +Revenue geographic area +$ 6,812,038 +$ 34,218,209 +Percentage of revenue by area: +United States +95 % +72 % +Rest of World +5 % +28 % +Deferred +Revenue +Changes +in the Company’s deferred revenue balance for the year ended December 31, 2023 were as follows: +Schedule +of Deferred Revenue +Balance as of December 31, 2022 +$ - +Increase due to prepayments from customers +32,570 +Increase due to grant funding awarded +329,879 +Balance as of December, 2023 +$ 362,449 +Note +9 – Earnings per Share +The +following table reconciles the numerator and the denominator used to calculate basic and diluted earnings per share for years ended December +31, 2023 and 2022: +Schedule +of Basis and Diluted Earnings Per Share +2023 +2022 +Years Ended December 31, +2023 +2022 +Numerator +Net loss, as reported +$ ( 35,332,865 ) +$ ( 14,238,249 ) +Denominator +Weighted average shares, basic +29,346,599 +31,479,028 +Dilutive effect of stock options, warrants and RSUs +- +- +Shares used to compute diluted earnings per share +29,346,599 +31,479,028 +Basic earnings per share +$ ( 1.20 ) +$ ( 0.45 ) +Diluted earnings per share +$ ( 1.20 ) +$ ( 0.45 ) +48 +The +computation of diluted earnings per share for the years ended December 31, 2023 and December 31, 2022 also excludes approximately 1.4 +million shares of common stock and approximately 465,000 warrants to purchase shares of common stock that are contingent upon the achievement +of certain milestones. +As +a result of incurring a net loss for the years ended December 31, 2023 and 2022, respectively, no potentially dilutive securities are +included in the calculation of diluted earnings per share because such effect would be anti-dilutive. The Company had potentially dilutive +securities as of December 31, 2023, consisting of: (i) 2,618,362 restricted stock units and (ii) 512,112 options, and potentially dilutive +securities as of December 31, 2022, consisting of: (i) 1,443,238 restricted stock units and (ii) 50,000 options. +Note +10 – Stock-Based Compensation +Stock +Incentive Plans +The +Company’s board of directors adopted, and shareholders approved, the Co-Diagnostics, Inc. Amended and Restated 2015 Long Term Incentive +Plan (the “Incentive Plan”) providing for the issuance of stock-based incentive awards to employees, officers, consultants, +directors and independent contractors. On August 31, 2022 the shareholders approved an increase in the number of awards available for +issuance under the Incentive Plan to an aggregate of 12,000,000 shares of common stock. The number of awards available for issuance under +the Incentive Plan was 4,357,937 at December 31, 2023. +Stock +Options +The +following table summarizes option activity during the years ended December 31, 2023 and 2022: +Schedule +of Option Activity +Number of Options +Weighted Average Exercise Price +Weighted Average Fair Value +Weighted Average Remaining Contractual Life (Years) +Outstanding at December 31, 2021 +1,111,363 +$ 2.12 +$ 1.31 +Granted +- +- +- +Expired +- +- +- +Forfeited/Cancelled +- +- +- +Exercised +( 70,791 ) +1.10 +0.51 +Outstanding at December 31, 2022 +1,040,572 +$ 2.19 +$ 1.37 +5.88 +Granted +- +- +- +Expired +- +- +- +Forfeited/Cancelled +- +- +- +Exercised +- +- +- +Outstanding at December 31, 2023 +1,040,572 +$ 2.19 +$ 1.37 +4.89 +Exercisable at December 31, 2023 +1,040,572 +$ 2.19 +$ 1.37 +4.89 +49 +The +total intrinsic value of options exercised during the years ended December 31, 2023 and 2022, respectively, was $ 0 and approximately +$ 0.4 million. The aggregate intrinsic value of outstanding options at December 31, 2023 and 2022 was approximately $ 0.2 million and $ 0.8 +million, respectively. As of December 31, 2023, there were no unvested options and no unrecognized stock-based compensation expense related +to options. +Restricted +Stock Units +The +grant date fair value of RSUs granted is determined using the closing market price of the Company’s common stock on the grant date +with the associated compensation expense amortized over the vesting period of the awards. The following table sets forth the outstanding +RSUs and related activity for the years ended December 31, 2023 and 2022: +Schedule +of Outstanding Restricted Stock Units and Related Party +Number of RSUs +Weighted +Average Grant Date Fair Value +Unvested at December 31, 2021 +1,267,415 +$ 9.94 +Granted +1,925,476 +5.66 +Vested +( 725,166 ) +8.66 +Forfeited/Cancelled +( 41,000 ) +8.31 +Unvested at December 31, 2022 +2,426,725 +$ 6.95 +Granted +1,948,750 +1.92 +Vested +( 1,354,081 ) +6.17 +Forfeited/Cancelled +( 95,897 ) +6.16 +Unvested at December 31, 2023 +2,925,497 +$ 3.99 +As +of December 31, 2023, there was $ 9.5 million of unrecognized stock-based compensation expense related to outstanding RSUs which is expected +to be recognized over a weighted-average period of 1.7 years. +Warrants +The +Company has issued warrants related to financings, acquisitions and as compensation to third parties for services provided. The Company +estimates the fair value of issued warrants on the date of issuance as determined using a Black-Scholes pricing model. The Company amortizes +the fair value of issued warrants using a vesting schedule based on the terms and conditions of each warrant if granted for services. +50 +The +following table summarizes warrant activity during the years ended December 31, 2023 and 2022: +Schedule +of Warrant Activity +Number of Warrants +Weighted Average Exercise +Price +Weighted Average Fair Value +Weighted Average Remaining Contractual Life (Years) +Outstanding at December 31, 2021 +526,281 +$ 8.15 +$ 4.01 +4.7 +Issued for adjustments to contingent purchase consideration +8,719 +9.13 +1.88 +Granted +- +- +- +Expired +- +- +- +Forfeited/Cancelled +- +- +- +Exercised +( 50,000 ) +2.00 +1.22 +Outstanding at December 31, 2022 +485,000 +$ 8.81 +$ 2.43 +4.0 +Granted +- +- +- +Expired +- +- +- +Forfeited/Cancelled +- +- +- +Exercised +- +- +- +Outstanding at December 31, 2023 +485,000 +$ 8.81 +$ 1.29 +3.0 +The +intrinsic value of warrants exercised during the years ended December 31, 2023 and 2022, respectively, was $ 0 and approximately $ 0.3 +million. The aggregate intrinsic value of outstanding warrants at December 31, 2023 was approximately $ 0 . +The +total number of warrants exercisable at December 31, 2023 is 20,000 . The ability to exercise the approximately 465,000 warrants issued +in connection with acquisitions in prior years is contingent upon the achievement of certain development and revenue milestones on or +before January 1, 2027. There was no unrecognized stock-based compensation expense related to warrants. +Stock-Based +Compensation Expense +The +Company recognized stock-based compensation expense as follows: +Schedule +of Recognized Stock-based Compensation Expense +2023 +2022 +Years Ended December 31, +2023 +2022 +Cost of sales +$ 46,586 +$ 63,058 +Sales and marketing +2,153,974 +1,866,116 +General and administrative +4,933,822 +4,050,967 +Research and development +1,202,473 +1,563,082 +Total stock-based compensation expense +$ 8,336,855 +$ 7,543,223 +Note +11 – Income Taxes +The +components of the provision (benefit) for income taxes consists of the following for the years ended December 31, 2023 and +2022: +Schedule +of Components Income Tax Provision +2023 +2022 +Year Ended December 31, +2023 +2022 +Current: +Federal +$ 84,435 +$ 563,821 +State +( 540,240 ) +( 266,248 ) +Total current +$ ( 455,805 ) +$ 297,573 +Deferred: +Federal +( 7,228,611 ) +( 3,945,090 ) +State +( 2,068,509 ) +( 961,468 ) +Change in valuation allowance +6,975,234 +- +Total deferred +( 2,321,886 ) +( 4,906,558 ) +Total income tax benefit +$ ( 2,777,691 ) +$ ( 4,608,985 ) +51 +A +reconciliation of income tax expense at the statutory federal income tax rate and income taxes as reflected in the financial statements +is as follows: +Schedule +of Benefit from Income Taxes and Effective Tax Rates +2023 +2022 +Year Ended December 31, +2023 +2022 +Federal income tax expense at statutory rate +21.0 % +21.0 % +State income tax expense, net of federal tax benefit +1.6 % +4.8 % +Permanent differences: +- Foreign derived intangible income deduction +0.0 % +1.4 % +- Stock based compensation +- 3.5 % +- 3.6 % +- Contingent consideration remeasurement +0.6 % +8.8 % +- Goodwill impairment +0.0 % +- 17.1 % +- Other permanent differences +- 0.2 % +- 0.6 % +Research and development credits +4.6 % +11.1 % +Change in uncertain tax positions +1.2 % +- 2.1 % +Change in valuation allowance +- 18.3 % +0.0 % +Other +0.3 % +0.8 % +Effective income tax rate +7.3 % +24.5 % +Net +deferred tax liabilities consist of the following components as of December 31, 2023 and 2022: +Schedule +of Deferred Tax Assets and Liabilities +2023 +2022 +December 31, +2023 +2022 +Deferred tax assets: +Accrued liabilities +$ 58,158 +$ 98,141 +Reserves and allowances +734,631 +765,004 +Deferred compensation +620,551 +566,076 +Section 174 costs +7,337,629 +3,460,159 +Lease liability +742,131 +85,899 +UNICAP +43,943 +168,936 +Net operating loss carryforwards +4,040,601 +- +Research and development credits +1,688,255 +- +Total gross deferred tax assets +15,265,899 +5,144,215 +Less valuation allowance +( 6,938,829 ) +- +Total deferred tax assets +8,327,070 +5,144,215 +Deferred tax liabilities: +Property and equipment, net +( 672,416 ) +( 609,261 ) +Intangibles, net +( 6,552,255 ) +( 6,608,914 ) +Prepaids +( 329,768 ) +( 156,053 ) +Right of use asset +( 736,226 ) +( 91,873 ) +Other comprehensive income +( 36,405 ) +( 96,101 ) +Other +- +- +Total deferred tax liabilities +( 8,327,070 ) +( 7,562,202 ) +Net deferred tax liability +$ - +$ ( 2,417,987 ) +At +December 31, 2023, the Company had federal net operating loss carryforwards of $ 16.3 million and federal research and development credit +carryforwards of $ 1.4 million. At December 31, 2023, the Company had state net operating loss carryforwards of $ 16.9 million and $ 0.8 +million of state research and development credit carryforwards. If unused, the state research credit carryforward will expire in 2037. +52 +ASC +Topic 740-10-05 requires that the impact of a tax position be recognized in the financial statements if that position is more likely +than not of being sustained on audit, based on the technical merits of the position. Our unrecognized tax benefit balances included $ 1,078,431 +at December 31, 2023 and $ 1,469,577 at December 31, 2022 of tax positions that, if recognized, would impact our effective tax rate. The +Company expects no material changes to the liability for unrecognized tax benefits in the next 12 months. Interest and penalties associated +with uncertain tax positions are recorded as a component of income tax expense. A reconciliation of the beginning and ending amount of +unrecognized benefits is as follows: +Schedule +of Unrecognized Tax Benefits +December 31, +2023 +2022 +Unrecognized tax benefits at the beginning of the year +$ 1,469,577 +$ 1,067,853 +Gross increases - current year tax positions +273,569 +1,045,590 +Gross increases - prior year tax positions +66,127 +34,035 +Gross decreases - prior year tax positions +( 730,842 ) +( 677,901 ) +Unrecognized tax benefits at end of year +$ 1,078,431 +$ 1,469,577 +Interest and penalties in year-end balance +$ 100,162 +$ 34,035 +The +Company is subject to taxation in the United States and other state jurisdictions. The tax years from December 31, 2020 through December +31, 2023 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which the Company +is subject. The Company is not currently under examination by any taxing authority. +Note +12 – Commitments and Contingencies +Lease +Obligations +The +Company leases administrative, R&D, sales and marketing and manufacturing facilities under non-cancellable operating leases and leases +cancellable with one month notice. The Company expenses the cancelable leases in the period incurred in accordance with the practical +expedient elected. During the year December 31, 2023, the Company amended two operating leases to extend the lease term and entered into +two new operating leases. As a result, the Company recognized additional operating lease liabilities and corresponding operating right-of-use +assets of $ 3,203,146 . +For +the year ended December 31, 2023, components of lease expense are summarized as follows: +Schedule +of Lease Expense +Year Ended +December 31, 2023 +Operating lease costs +$ 813,743 +Short-term lease costs +198,261 +Total lease costs +$ 1,012,004 +As +of December 31, 2023, the maturities of the Company’s lease liabilities are as follows: +Schedule +of Maturities on Company Lease Liabilities +Year Ending +December 31, +2024 +$ 996,676 +2025 +1,018,383 +2026 +714,630 +2027 +300,591 +Thereafter +308,462 +Total lease payments +3,338,742 +Less: imputed interest +348,175 +Present value of operating lease liabilities +2,990,567 +Less: current portion +838,387 +Long-term portion +$ 2,152,180 +53 +Other +information related to operating leases was as follows: +Schedule +of Other Information Related to Operating Lease +Year Ended +December 31, 2023 +Cash paid for operating leases included in operating cash flows +$ 954,013 +Remaining lease term of operating leases +3.7 years +Discount rate of operating leases +6.2 % +Litigation +Liabilities +for loss contingencies arising from claims, assessments, litigation, fines, and penalties and other sources are recorded when it is probable +that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss contingencies +are expensed as incurred. +The +Company is a defendant in two class action claims and three derivative actions claiming that the Company promulgated false and misleading +press releases to increase the price of our stock to improperly benefit the officers and directors of the Company. The plaintiffs demand +compensatory damages sustained as a result of the Company’s alleged wrongdoing in an amount to be proven at trial. The Company +is also a party to two civil actions, one in the US and the other in the United Kingdom. Each of the civil actions is based on breach +of contract claims against the Company. The Company believes these lawsuits are without merit and intends to defend the cases vigorously. +The Company is unable to estimate a range of loss, if any, that could result were there to be an adverse final decision in these cases. +As of the date of this report, the Company does not believe it is probable that these cases will result in an unfavorable outcome; however, +if an unfavorable outcome were to occur in these cases, it is possible that the impact could be material to the Company’s results +of operations in the period(s) in which any such outcome becomes probable and estimable. +Note +13 – Share Repurchase Program +In +March 2022, the Company’s board of directors authorized a share repurchase program that would allow the Company to repurchase up +to $ 30.0 million of CODX common stock. The repurchase program does not obligate the Company to acquire any particular number of common +shares, and the repurchase program may be suspended or discontinued at any time at the Company’s discretion. The timing and amount +of any share repurchases under the share repurchase program will be determined by Co-Diagnostics’ management at its discretion +based on ongoing assessments of the capital needs of the business, the market price of the Company’s common stock, corporate and +regulatory requirements, and general market conditions. +For +accounting purposes, common stock repurchased under the stock repurchase program is recorded based upon the transaction date of the applicable +trade. Such repurchased shares are held in treasury and are presented using the cost method. These shares are not retired and are considered +issued but not outstanding. The following table shows the changes in treasury stock for the periods presented: +Schedule +of Treasury Stock +Year Ended +December 31, 2023 +Balance, beginning of period +3,881,658 +Repurchases of common stock +967,020 +Balance, end of period +4,848,678 +Note 14 – Related Party Transactions +The Company employs one person who is related to +current or former executive officers. Seth Egan is the Company’s Director of Sales and Marketing, and is the son of Dwight +Egan, the Company’s President and Chief Executive Officer and Chairman of the Board. During the year ended December 31, 2023, +the total compensation paid to this person, including salaries, bonuses, and the grant date fair value of equity awards which vest +over three +years , was $ 0.6 +million. The Company also uses the services of Winston Egan as an independent contractor for sales operations consulting. +Winston Egan is also the son of Dwight Egan, the Company’s President and Chief Executive Officer and Chairman of the Board. +During the year ended December 31, 2023, the total compensation paid to this contractor, comprised of consulting fees, was $ 0.1 +million. +In August 2023, the Company entered into a +services agreement with CoSara, the Company’s equity method investment, under which CoSara provides certain research and +development consulting and support services. During the year ended December 31, 2023, the Company recognized $ 0.2 million +of expense related to this agreement. +Note +15 – Subsequent Events +None. +54 +ITEM +9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. +None. +ITEM +9A. CONTROLS AND PROCEDURES +Evaluation +of Disclosure Controls and Procedures +We +maintain a set of disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) designed to ensure that information +required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within +the time periods specified in rules and forms adopted by the SEC. Disclosure controls and procedures include, without limitation, controls +and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under +the Exchange Act is accumulated and communicated to the Company’s management, including its principal executive and principal financial +officers, as appropriate to allow timely decisions regarding required disclosure. +Our +management, with the participation of our Chief Executive Officer and our Chief Financial Officer, evaluated the effectiveness of our +disclosure controls and procedures as of December 31, 2023. Based on the evaluation, management has concluded that our disclosure controls +and procedures are effective as of December 31, 2023 to provide reasonable assurance regarding the reliability of +our financial reporting and the preparation of our financial statements for external reporting purposes in accordance with U.S. generally +accepted accounting principles. +Changes +in Internal Control Over Financial Reporting +There +have not been any changes in the Company’s internal control over financial reporting (as such term is defined in Rules 13a- 15(f) +and 15d-15(f) under the Exchange Act) during the fourth quarter of 2023 that have materially affected, or are reasonably likely to materially +affect, the Company’s internal control over financial reporting. +Management’s +Annual Report on Internal Control over Financial Reporting +Our +management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) +under the Exchange Act). Our management, including our Chief Executive Officer and Chief Financial Officer, conducted an evaluation of +the effectiveness of our internal control over financial reporting as of December 31, 2023. In making its evaluation, management used +the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated +Framework (2013). +Based +on this evaluation, management determined that our internal control over financial reporting was effective as of December 31, 2023. +This +Annual Report does not include an attestation report by our independent registered public accounting firm regarding internal control +over financial reporting since we are a non-accelerated filer. Management’s report was not subject to attestation by our registered +public accounting firm pursuant to rules of the SEC that permit non-accelerated filers to provide only management’s report in the +10-K. +55 +Inherent +Limitations on Effectiveness of Controls +Our +management, including our Chief Executive Officer and Chief Financial Officer, believes that our disclosure controls and procedures and +internal control over financial reporting are intended to be designed to provide reasonable assurance of achieving their objectives. +However, our management does not expect that our disclosure controls and procedures or our internal control over financial reporting +will prevent or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, +not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact +that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent +limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of +fraud, if any, have been detected. These inherent limitations include the realities that judgments in decision making can be faulty, +and that breakdowns can occur because of a simple error or mistake. Additionally, controls can be circumvented by the individual acts +of some persons, by collusion of two or more people or by management override of the controls. The design of any system of controls also +is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed +in achieving its stated goals under all potential future conditions; over time, controls may become inadequate because of changes in +conditions, or the degree of compliance with policies or procedures may deteriorate. Because of the inherent limitations in a cost–effective +control system, misstatements due to error or fraud may occur and not be detected. +ITEM +9B. OTHER INFORMATION +During the three months ended December 31, 2023, none of our directors +or officers adopted or terminated a “Rule 10-b5-1 trading arrangement” or “non-Rule 10-b5-1 trading arrangement” +as each term is identified in Item 408 of Regulation S-K. +ITEM +9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS. +None. +PART +III +ITEM +10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE. +The +following table sets forth the names, ages and positions of our executive officers and directors as of March 12, 2024. The following +is information on the business experience of each director and executive officer now serving and a discussion of the qualifications, +attributes and skills that led to the board of directors’ conclusion that each one is qualified to serve as a director or as an +executive officer as the case may be. Executive officers serve at the discretion of the board of directors. +Name +Age +Position +Dwight +Egan +70 +Chief +Executive Officer, President and Chairman of the Board +Brian +Brown +48 +Chief +Financial Officer and Secretary +Eugene +Durenard +54 +Director +James +Nelson +71 +Director +Richard +Serbin +79 +Director +Edward +Murphy +59 +Director +The +following is a brief summary of the background of each of our executive officers. +Dwight +Egan serves as our President and Chief Executive Officer and has been an officer and director of the Company since April 2013. Mr. +Egan has been engaged in private investment business from February 1999 to the present. He was a senior executive at Data Broadcasting +Corporation, a leading provider of wireless, real-time financial market data, news and sophisticated fixed- income portfolio analytics +to 27,000 individual and professional investors from 1995 to 1999. He co-founded and served as CEO and Chairman of the Board of Broadcast +International, Inc. from 1984 to 1995, when Data Broadcasting Corporation acquired Broadcast International and created CBS MarketWatch , +a leading financial news site and participated in its initial public offering. Mr. Egan’s prior experience in executive leadership +positions with public companies and working with capital markets qualifies him to serve as our Chairman, President and Chief Executive +Officer. +Brian +Brown became our Chief Financial Officer in February 2021. From July 2020 until February 2021, Mr. Brown served as the Chief Financial +Officer of A-Core Concrete Cutting, Inc. where his duties included overseeing the company’s accounting and finance departments, +mergers and acquisitions and responsibility for financial forecasting and budgeting. From January 2020 to July 2020, Mr. Brown was an +independent consultant. From August 2019 to December 2019, Mr. Brown served as the Vice President of Accounting, Treasury and Investor +Relations at Sportsman’s Warehouse Holdings, Inc., a public company reporting on Nasdaq Global Select under the symbol SPWH, where +his duties included overseeing the company’s accounting, treasury and investor relations departments, preparing the company’s +annual, quarterly and current reports with the SEC, overseeing all aspects of the company’s annual audit, including, but not limited +to, the preparation and review of audit support schedules, preparation of financial statements and footnotes, and providing support to +the company’s independent auditors. From October 2009 to August 2019, Mr. Brown served as the Director of Finance of Sportsman’s +Warehouse Holdings, Inc. where he assisted with the company’s initial public offering in April 2014 as well as effecting private +and secondary public offerings, acquisitions of a group of retail stores and preparing the company’s periodic and current reports +with the SEC and complying with the Sarbanes Oxley Act. From May 2005 to October 2009, Mr. Brown served as the Corporate Controller of +Franklin Covey Products where he developed and maintained the company’s internal controls over financial reporting structure in +accordance with the control standards required under Section 404 of the Sarbanes Oxley Act. From July 2001 to May 2005, Mr. Brown served +as an Assurance Senior at KPMG, LLP where he provided audit services to various clients in multiple industries. Mr. Brown holds a Bachelor +of Arts in Accounting and Masters of Professional Accountancy from the University of Utah. Mr. Brown is a licensed CPA in Utah. +56 +The +following is a brief summary of the background of each of our directors: +Eugene +Durenard has been a member of our board of directors since June 2019. Dr. Durenard is the Founder and CEO of Hyperbolic Holdings, +a Swiss-based holding, management consulting and strategy advisory company specialized in healthcare. For the last 7 years he has been working with family offices on direct investments +and philanthropy focused on life sciences. He serves on the advisory board of several private companies in the biotech and MedTech sectors. +After an initial career in proprietary research and trading at Salomon Brothers and Credit Suisse in London, he co-founded Orion Investment +Management in Bermuda specializing in quantitative asset and liability management for institutions and private clients. He subsequently +sold it to Capital G Bank and co-headed their asset management. Dr. Durenard spent several years establishing personal connections with +representatives of 40+ clusters of life science innovation, families operating healthcare businesses and industry leaders globally. He +regularly visits labs and incubators, meets with leading scientists and innovators in order to keep abreast of current trends and developments. +His advice is based on a thorough analysis that combines in-depth knowledge of science, competitive forces and financial expertise. He +has published several articles in asset-liability management industry magazines as well as the book “Professional Automated Trading +— Theory and Practice” (Wiley 2013). He has a PhD in Mathematics from Harvard University. Dr. Durenard brings a thorough +multi-asset class investment and entrepreneurial experience spanning 25 years to the Company’s board of directors. +James +Nelson has been a member of our board of directors +since June 2019. Mr. Nelson is the retired Chairman and CEO of Sunworks, Inc., a NASDAQ traded +commercial, agriculture, and residential solar Integrator which he helped found in October 2010. Mr. Nelson spent most of his career +working in private equity as a general partner with Peterson Partners and with Millennial Capital Partners. In addition to his investment +and financial responsibilities, he served as CEO of two of his firms’ portfolio companies. Prior to his years in private equity, +Mr. Nelson served as Vice President of Marketing at Banana Republic, where he managed company-wide marketing, as well as the company’s +international expansion initiative. He was also general manager for Banana Republic’s catalog division. He was Vice President of +Marketing and Corporate Development at Saga Corporation, a multi-billion-dollar food service company. Mr. Nelson began his executive +career over 35 years ago at Bain and Company, a business strategy consulting firm, where he managed teams of consultants on four continents. +Mr. Nelson received his MBA from Brigham Young University, where he graduated summa cum laude and was named the Outstanding Master of +Business Administration Graduate. Mr. Nelson’s advice to the board of directors from his experiences as a chief executive officer +and strategic advisor is useful to the board of directors. +Richard +Serbin has been a member of our board of directors since May 2017. Mr. Serbin currently serves as a consultant to many companies +in the healthcare industry. He was the President of Corporate Development and In-House Legal Counsel at Life Science Institute, LLC, +from June 1, 2013 to July 15, 2014. He was appointed to the Advisory Board of Cure Pharmaceutical in January 2017 and has been a Member +of Advisory Board at Prime Access, Inc. since September 2015. Mr. Serbin has been a Director at Rapid Nutrition Plc since November 18, +2014. He served as Director at Viropro Inc. from May 2013 to June 2014. He was Head of Business Advisory Board at Mazal Plant Pharmaceuticals +Inc. from October 2006 to September 2007 and also served as its Member of Business Advisory Board. He served as Chief Executive Officer +of Optigenex Inc. from July 2002 to September 15, 2005 and a director from July 2004 to September 2005. From January 1999 until July +2002 Mr. Serbin served as a consultant to various pharmaceutical companies. He served as the President of Bradley Pharmaceuticals. He +served as Vice President of Corporate Development at Ortho Pharmaceuticals, a Johnson & Johnson subsidiary, and practiced Patent +and FDA law at Revlon Johnson & Johnson and Schering-Plough. He served as Patent Attorney for Schering Plough Corporation and Chief +FDA Counsel for Revlon Corporation and Johnson and Johnson Corporation. Subsequently, he worked at Revlon Corporation, as its Chief Food, +Drug and Cosmetic Counsel. He founded Radius Scientific Corporation. He was J&J’s Vice President of Corporate Development, +and later led a successful public offering venture based on technology developed at Stanford Medical School. Mr. Serbin spent a large +portion of his career focusing on international markets and clients. While at J&J, Mr. Serbin served on the board of directors of +16 US and international subsidiary companies, including Ethicon, Ortho, J&J Consumer Products, Pittman-Moore, Mc Neil, and J&J +Development Corporation. He worked on multiple international acquisitions and strategic relationships, and sat on the board of directors +of several of its international subsidiaries, including those in India, Hong Kong, Japan, Taiwan, Germany, and England. Mr. Serbin has +a B.S. and a B. Pharmacy from Rutgers University and Rutgers University College of Pharmacy, a J.D. degree from Seton Hall Law School +and a Master’s Degree in Trade Regulations and Law from NYU Law School. Mr. Serbin’s experience in business, law and medicine +and knowledge gained as an advisor to the healthcare industry is critical to our board of directors as we continue to commercialize our +products. +Edward +Murphy has been a member of our board of directors since June 2019. Since December 1999, Mr. Murphy has served as a senior vice president +and a partner of Dover Investments Ltd., a private investment firm. Throughout his career, Mr. Murphy’s duties have included investment +analysis of various types of investment projects in real estate and financial services. Currently, Mr. Murphy serves on the board of +directors of several Canadian publicly reporting companies that have interests in various industries. He has been a Director at Empire +Minerals Corporation Inc. since January 2016, at Digicrypts Blockchain Solutions Inc. from June 2011 to November 2022, at Lakefield Marketing +Corporation since February 2018, CEO/CFO and Director of Credo Resources Inc. since September 2019, at the Mosport Park Entertainment +Corporation since April 30, 1997, at Essex Oil Ltd. Since July 2021, and at Darkhorse Technologies Ltd. Since November 2021. He served +as a Director at Aurquest Resources from May 2003 to December 2017. Mr. Murphy’s experience in the capital markets outside the +United States and his involvement in investment analysis is a benefit to the board of directors. +Dwight +Egan – See narrative description above. +57 +Involvement +in Certain Legal Proceedings +To +the best of our knowledge, none of our directors or executive officers has been involved in any bankruptcy or criminal proceedings (other +than traffic and other minor offenses) or been subject to any of the items set forth under Item 401(f) of Regulation S-K, nor have there +been any judgments or injunctions brought against any of our directors or executive officers during the last ten years that we consider +material to the evaluation of the ability and integrity of any director or executive officer. +Board +and Committee Matters +Our +board of directors has five members. The Chairman of the Board and our Chief Executive Officer, Dwight Egan, is a member of the board +and is a full-time employee of the Company. Eugene Durenard, Edward Murphy, James Nelson and Richard Serbin are non-employee directors, +and the board has determined that these persons (who constitute a majority of the board) are “independent directors” under +the criteria set forth in Rule 5605(a)(2) of the Nasdaq Listing Rules. The board met nine times during the year ended December 31, 2023. +All directors attended more than seventy-five percent (75%) of the meetings of the board and committee meetings of which such director +was a member held during 2023. +We +maintain an audit committee of the board, a compensation committee of the board, a corporate governance committee of the board and a +nominating committee of the board, each of which is discussed below. Our board of directors may from time to time establish other standing +committees. In addition, from time to time, special committees may be established under the direction of our board of directors when +necessary to address specific issues. +The +following table sets forth a description of the four permanent board committees and the chairpersons and members of those committees, +all of whom are independent directors: +Committee +Independent +Chairperson +Independent +Members +Audit +Committee +Eugene +Durenard +Edward +Murphy +James +Nelson +Richard +S. Serbin +Compensation +Committee +Richard +S. Serbin +Edward +Murphy +Eugene +Durenard +James +Nelson +Governance +Committee +James +Nelson +Edward +Murphy +Eugene +Durenard +Richard +S. Serbin +Nominating +Committee +Edward +Murphy +James +Nelson +Eugene +Durenard +Richard +S. Serbin +Audit +Committee and Financial Expert +Our +audit committee currently is comprised of Messrs. Durenard, Nelson, Murphy and Serbin with Mr. Durenard serving as chairperson of the +audit committee. The functions of the audit committee include engaging an independent registered public accounting firm to audit our +annual financial statements, reviewing the independence of our auditors, the financial statements and the auditors’ report, and +reviewing management’s administration of our system of internal control over financial reporting and disclosure controls and procedures. +The board of directors has adopted a written audit committee charter. A current copy of the audit committee charter is available to security +holders on our website at www.codiagnostics.com. Our board has determined that all our directors that are serving on the audit committee +are “independent” under the definition of independence in the Marketplace rules of the NASDAQ listing standards. The Audit +Committee met four times during the year ended December 31, 2023. All committee members attended more than seventy-five percent (75%) +of the meetings of the Audit Committee held during 2023. +Our +board of directors has determined that Mr. Durenard meets the requirements of an “audit committee financial expert” as defined +in applicable SEC regulations. +58 +Compensation +Committee +Our +compensation committee currently includes Messrs. Serbin, Nelson, Murphy and Durenard with Mr. Serbin serving as chairperson of the compensation +committee. The functions of the compensation committee include reviewing and approving corporate goals relevant to compensation for executive +officers, evaluating the effectiveness of our compensation practices, evaluating and approving the compensation of our chief executive +officer and other executives, recommending compensation for board members, and reviewing and making recommendations regarding incentive +compensation and other employee benefit plans. The board of directors has adopted a written compensation committee charter. A current +copy of the compensation committee charter is available to shareholders on our website at www.codiagnostics.com. Our board has determined +that all of our directors serving on the compensation committee are “independent” under the definition of independence in +the Marketplace Rules of the NASDAQ listing standards. The Compensation Committee met two times as a separate committee in 2023. +Corporate +Governance Committee +Our +Corporate Governance Committee currently includes Messrs. Nelson, Murphy, Durenard and Serbin with Mr. Nelson serving as chairperson +of the Corporate Governance Committee. Among other items, the committee is tasked by the board of directors to develop and recommend +to the board the Corporate Governance Guidelines of the Company and oversee compliance therewith. A current copy of the Corporate Governance committee charter is available +to shareholders on our website at www.codiagnostics.com. Our board has determined all directors serving on the Corporate Governance committee +are “independent” under the definition of independence in the Marketplace Rules of the NASDAQ listing standards. The Corporate +Governance Committee did not meet as a separate committee in 2023, but rather, because the committee is comprised of all four independent +directors, committee matters were addressed as necessary in meetings of the board the year ended December 31, 2023. +Nominating +Committee +Our +Nominating Committee was split from the Corporate Governance Committee in 2022 and currently includes Messrs. Nelson, Murphy, Durenard +and Serbin with Mr. Murphy serving as chairperson of the Nominating Committee. The Nominating Committee has been established by the board, +among other things to: assist the board in effecting board organization, membership and function including identifying qualified board +nominees; assist the board in effecting the organization, membership and function of board committees including the composition of board +committees and recommending qualified candidates therefor; evaluate and provide successor planning for the Chief Executive Officer and +other executive officers; and develop criteria for board membership, such as independence, term limits, age limits and ability of former +employees to serve on the board and the evaluation of candidates’ qualifications for nominations to the board and its committees +as well as removal therefrom. The Nominating Committee did not meet as a separate committee in 2023, but rather, because the committee +is comprised of all four independent directors, committee matters were addressed as necessary in meetings of the board for the year ended +December 31, 2023. +Board +Nominations +In +considering board candidates, the board seeks individuals of proven judgment and competence who have strong reputations in their respective +fields. Although we do not have a formal diversity policy, the board considers such factors as experience, education, employment history, +special talents or personal attributes, anticipated participation in board activities, and geographic and diversity factors. The process +for identifying and evaluating nominees would include detailed consideration of the recommendations and opinions of members of our board, +our executive officers, and our stockholders. There would be no difference in the process of evaluation of candidates recommended by +a stockholder and those recommended by other sources. +59 +Our +Amended and Restated Bylaws (the “Bylaws”) set forth procedures for shareholders to recommend nominees to the Company’s +board. Nominations of persons for election to the board of directors to be considered by the stockholders may be made at an annual meeting +of stockholders (i) pursuant to the Company’s notice of meeting, (ii) by or at the direction of the board of directors, or (iii) +by any stockholder of the Company who (A) was a stockholder of record at the time of giving of the notice, (B) is entitled to vote with +respect to such matter at the meeting, and (C) complies with the notice procedures set forth in the Bylaws. +The +following is a summary of key provisions from our Bylaws. For nominations to be properly brought before an annual meeting by a stockholder, +the stockholder making such nominations must have given timely notice in writing to the secretary of the Company. To be timely, a stockholder’s +notice shall be delivered to the secretary at the principal executive offices of the Company not later than the close of business on +the 7 5t h day nor earlier than the close of business on the 12 5t h day prior to the first anniversary of the preceding +year’s annual meeting; provided, however, that in the event that the date of the annual meeting is more than 30 days before or +more than 60 days after such anniversary date, notice by the stockholder to be timely must be so delivered not later than the close of +business on the later of (x) t he 75th day prior to the scheduled date of such annual meeting or (y) the 15th day following +the day on which public announcement of the date of such meeting is first made by the Company. To be in proper form, a stockholder’s +notice to the secretary must: set forth, as to the stockholder giving the notice and the beneficial owner, if any, on whose behalf the +nomination or proposal is made (A) the name and address of such stockholder, as they appear on the Company’s books, and of such +beneficial owner, if any, (B) the class or series and number of shares of the Company that are, directly or indirectly, owned beneficially +and of record by such stockholder and such beneficial owner, if any, as of the date of such notice, and (C) any other information relating +to such stockholder and beneficial owner, if any, that would be required to be disclosed in a proxy statement or other filings required +to be made in connection with solicitations of proxies for, as applicable, the proposal and/or for the election of directors in a contested +election pursuant to Section 14 of the Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder +(the “Exchange Act”). In addition, shareholders who intend to solicit proxies in support of director nominees other than +the company’s nominees must also comply with the additional requirements of Rule 14a-19(b). +The +notice shall set forth, as to each person, if any, whom the stockholder proposes to nominate for election or reelection as a director +(A) all information relating to such person that would be required to be disclosed in a proxy statement or other filings required to +be made in connection with solicitations of proxies for election of directors in a contested election pursuant to Section 14 of the Exchange +Act (including such person’s written consent to being named in the proxy statement as a nominee and to serving as a director if +elected) and (B) a description of all direct and indirect compensation and other monetary agreements, arrangements and understandings +during the past three years, and any other relationships, between or among such stockholder and beneficial owner, if any, and their respective +affiliates and associates, or others acting in concert therewith, on the one hand, and each proposed nominee, and his or her respective +affiliates and associates, or others acting in concert therewith, on the other hand, including, without limitation all information that +would be required to be disclosed pursuant to Rule 404 promulgated under Regulation S-K if the stockholder making the nomination and +any beneficial owner on whose behalf the nomination is made, if any, or any affiliate or associate thereof or person acting in concert +therewith, were the “registrant” for purposes of such rule and the nominee were a director or executive officer of such registrant; +and with respect to each nominee for election or reelection to the board of directors, include the completed and signed questionnaire, +representation, and agreement required by the Bylaws. The Company may require any proposed nominee to furnish such other information +as may reasonably be required by the Company to determine the eligibility of such proposed nominee to serve as an independent director +of the Company or that could be material to a reasonable stockholder’s understanding of the independence, or lack thereof, of such +nominee. +Communication +with the Board +We +have not, to date, developed a formal process for shareholder communications with the board of directors. We believe our current informal +process, in which any communication sent to the board of directors, either generally or in care of the chief executive officer, secretary +or other corporate officer or director, is forwarded to all members of the board of directors, has served the board’s and the shareholders’ +needs. +Conflicts +of Interests +On +an annual basis, each director and executive officer is obligated to complete a director and officer questionnaire that requires disclosure +of any transactions with our company, including related person transactions reportable under SEC rules, in which the director or executive +officer, or any member of his or her immediate family, have a direct or indirect material interest. Under our company’s standards +of conduct for employees, all employees, including the executive officers, are expected to avoid conflicts of interest. Pursuant to our +code of ethics for the chief executive officer and senior finance officers (as discussed below), such officers are prohibited from engaging +in any conflict of interest unless a specific exception has been granted by the board. All of our directors are subject to general fiduciary +standards to act in the best interests of our company and our shareholders. Conflicts of interest involving an executive officer or a +director are generally resolved by the board. +60 +Role +of the Board in Risk Oversight +Risk +is inherent with every business, and how well a business manages risk can ultimately determine its success. Management is responsible +for the day-to-day management of the risks that we face, while our board of directors, as a whole and through its committees, has responsibility +for the oversight of risk management. In its risk oversight role, our board of directors is responsible for satisfying itself that the +risk management processes designed and implemented by management are adequate and functioning as designed. +Our +board of directors does not have a standing risk management committee, but rather administers this oversight function directly through +our board of directors as a whole, as well as through various standing committees of the board of directors that address risks inherent +in their respective areas of oversight. In particular, our board of directors is responsible for monitoring and assessing strategic risk +exposure, including a determination of the nature and level of risk appropriate for us. Our Audit Committee has the responsibility to +consider and discuss our major financial risk exposures and the steps our management has taken to monitor and control these exposures, +including guidelines and policies to govern the process by which risk assessment and management is undertaken. The Audit Committee also +monitors oversight of the performance of our internal audit function. Our Corporate Governance Committee monitors the effectiveness of +our corporate governance guidelines, including whether they are successful in preventing illegal or improper liability-creating conduct. +Our Compensation Committee assesses and monitors whether any of our compensation policies and programs have the potential to encourage +excessive risk-taking or promote behaviors contra to our Code of Business Conduct. Our Nominating Committee assesses and monitors the +effectiveness of the board and its committees and evaluates board members and nominees for election to the board and succession planning +for the CEO and other executive officers. +Code +of Ethics +We +have adopted a code of ethics for our principal executive officer, principal financial officer, controller, or persons performing similar +functions. A copy of the code of ethics is included on our website at www.codiagnostics.com . +Family +Relationships +There +are no family relationships among our directors and executive officers. +ITEM +11. EXECUTIVE COMPENSATION +We +are a “smaller reporting company” as defined in the rules and regulations of the SEC. As a smaller reporting company, we +may take advantage of specified reduced disclosure and other requirements that are otherwise applicable, in general, to public companies +that are not smaller reporting companies. Accordingly, this Report includes reduced disclosure about our executive compensation arrangements. +Summary +Compensation Table +The +table below summarizes the total compensation paid or earned by each of the named executive officers in their respective capacities for +the fiscal years ended December 31, 2023 and 2022. We have omitted in this report certain columns otherwise required to be included because +there was no compensation made with respect to such columns, as permitted by applicable SEC regulations. +Name and Principal Position +Year +Salary +Bonus (1) +Stock Awards (2) +All Other Comp +Total Compensation +Dwight Egan President & Chief Executive Officer +2023 +$ 375,000 +$ 40,750 +$ 845,550 +$ - +$ 1,261,300 +2022 +$ 366,146 +$ 146,245 +$ 1,454,750 +$ - +$ 1,967,141 +Brian Brown Chief Financial Officer and Secretary +2023 +$ 306,923 +$ 32,000 +$ 701,550 +$ - +$ 1,040,473 +2022 +$ 280,875 +$ 106,647 +$ 1,190,250 +$ - +$ 1,577,772 +(1) +Bonuses +for the year ended December 31, 2023 include accrued bonus payments of $20,750 to Mr. Egan and $17,000 to Mr. Brown that were paid +in January 2024. +(2) +The +amounts reported in this column represent the aggregate grant date fair value of the restricted stock units, or RSUs, granted under +our 2015 Plan as computed in accordance with FASB ASC Topic 718. Note that the amounts reported in this column reflect the accounting +value for these equity awards and do not correspond to the actual economic value that may be received from the equity awards as the +RSUs vest over three years. +Narrative +Disclosure to Summary Compensation Table: We do not have written employment agreements with any of our executive officers. All of +our executive officers serve on an at-will basis. The base salaries for our named executive officers were determined by our compensation +committee after reviewing a number of factors, including: the responsibilities associated with the position, the seniority of the executive’s +position, the base salary level in prior years, and our financial position; and for executive officers other than our Chief Executive +Officer, recommendations made by our Chief Executive Officer. By utilizing a combination of objective and subjective performance factors +critical to our success, the board will award cash bonuses intended to incentivize our executive officers to achieve results that benefit +them and the Company. Performance factors include the achievement of predetermined financial performance objectives, adherence to financial +discipline measures and achievement of business development, product development and long-term business stability. The board may modify +or re-weight the objectives during the course of the fiscal year, if necessary, to reflect changes in our business plan. +61 +Outstanding +Equity Awards at Fiscal Year-End 2023 +The +following table contains certain information concerning outstanding equity awards for the Named Executive Officers as of December 31, +2023. +Option Awards +Stock Awards +Number of Securities +Underlying Unexercised +Options (#) +Option +Exercise +Option +Expiration +Number of Shares or Units of Stock That Have Not Vested +Market Value of Shares or Units of Stock That Have Not Vested +Number of Unearned Shares, Units or Other Rights That Have Not Vested +Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested +Name +Exercisable +Unexercisable +Price +Date +(#) +($) (1) +(#) +($) +Dwight Egan +50,000 +- +$ 2.63 +09/20/28 +- +- +- +- +50,000 +- +$ 1.10 +09/02/29 +- +- +- +- +- +- +- +- +20,833 (2) +$ 27,708 +- +- +- +- +- +- +137,500 (3) +$ 182,875 +- +- +- +- +- +- +103,333 (4) +$ 137,433 +- +- +- +- +- +- +229,167 (5) +$ 304,792 +- +- +Brian Brown +- +- +- +- +16,667 (2) +$ 22,167 +- +- +- +- +- +- +112,500 (3) +$ 149,625 +- +- +- +- +- +86,667 (4) +$ 115,267 +- +- +- +- +- +187,500 (5) +$ 249,375 +- +- +(1) +Based on $1.33 per share, which was the closing price of our common stock on December 31, 2023. +(2) +Consists of restricted stock units granted on 8/12/2021, which vest in 6 installments commencing on 11/23/2021 and continuing every six +months thereafter. +(3) +Consists of restricted stock units granted on 6/6/2022, which vest in 6 installments commencing on 11/23/2022 and continuing every six +months thereafter. +(4) +Consists of restricted stock units granted on 1/13/2023, which vest in 6 installments commencing on 5/23/2023 and continuing every six +months thereafter. +(5) +Consists of restricted stock units granted on 5/15/2023, which vest in 6 installments commencing on 11/23/2023 and continuing every six +months thereafter. +Potential +Payments Upon Termination or Change of Control +At +the recommendation of the compensation committee of the board of directors, the Board approved the Co-Diagnostics, Inc. Change in Control +Severance Plan (the “Plan”). The Plan provides severance benefits to a select group of designated management or highly compensated +participants in the event their employment or affiliation with the Company or an affiliate is terminated due to a change in control (as +defined in the Plan). Participants entitled to benefits under the Plan are designated from time-to-time by the Compensation Committee +pursuant to the terms of an “Award Notice,” the form of which is appended to the Plan. The Award Notice identifies the eligible +participant and the Severance Multiplier (as defined in the Plan) to which the participant is entitled. The Compensation Committee approved +participation in the Plan for certain executives of the Company, including the Company’s CEO, Dwight Egan, with a Severance Multiplier +of three times his severance benefit and the Company’s CFO, Brian Brown, with a Severance Multiplier of two times his severance +benefit. +Under +the Plan, if a participant’s employment or affiliation is terminated without “cause” or by the participant for “good +reason” (each, as defined in the Plan) during the two-year period following a change in control, a participant will be entitled +to a severance benefit equal to the participant’s Severance Multiplier as set forth in the participant’s Award Notice, times +the sum of: (i) the participant’s annual base salary; and (ii) the greater of the participant’s target bonus or the average +of the three highest actual annual cash bonuses paid to participant over the five preceding completed years. +The +participant’s receipt of any of the payments or benefits is subject to the participant’s delivery to the Company of a separation +agreement of the type that are ordinarily entered into in similar situations, in a form acceptable to the Company, in its sole discretion, +which separation agreement may include a requirement for the participant to remain in the employ or service of the Company for a reasonable +period of time after completion of the Change in Control transaction to assist in any transition activities for which participant’s +services would be required. +Director +Compensation +We +use a combination of cash and stock-based incentive compensation to attract and retain qualified candidates to serve on its board of +directors. In setting director compensation, we consider the significant amount of time that directors expend in fulfilling their duties +as well as the skill level required by our members of the board. +62 +The +table below summarizes the compensation paid or accrued by us to each of our non-employee directors for the fiscal year ended December +31, 2023. +Name +Fees Earned or +Paid in Cash +Stock Awards: +Value of Restricted +Stock Units (1) +Total +Richard Serbin (2) +$ 100,000 +$ 198,000 +$ 298,000 +James Nelson (3) +$ 100,000 +$ 198,000 +$ 298,000 +Edward Murphy (4) +$ 100,000 +$ 198,000 +$ 298,000 +Eugene Durenard (5) +$ 100,000 +$ 198,000 +$ 298,000 +(1) +The +amounts reported in this column represent the aggregate grant date fair value of the restricted stock units, or RSUs, granted under +our 2015 Plan as computed in accordance with FASB ASC Topic 718. Note that the amounts reported in this column reflect the accounting +value for these equity awards and do not correspond to the actual economic value that may be received from the equity awards. The +RSUs vested immediately upon grant. +(2) +As +of December 31, 2023, Mr. Serbin had 120,000 RSU awards outstanding. +(3) +As +of December 31, 2023, Mr. Nelson had 120,000 RSU awards outstanding. +(4) +As +of December 31, 2023, Mr. Murphy had 120,000 RSU awards outstanding. +(5) +As +of December 31, 2023, Mr. Durenard had 120,000 RSU awards outstanding. +Our +non-employee directors receive cash compensation of $100,000 per year, paid quarterly. In 2022, they also received 70,000 RSU’s +vesting 1/6 th equally in May 2023, 2024, and 2025 and November 2023, 2024 and 2025. In 2023, they also received 40,000 RSU’s +vesting 1/6 th equally in November 2022, 2023, and 2024 and May 2023, 2024, and 2025, as well as 70,000 RSU’s vesting +1/6 th equally in November 2023, 2024 and 2025 and May 2024, 2025 and 2026. In addition, non-employee directors may be entitled +to receive special awards of stock options or RSUs from time to time as determined by the board. The chairman of the board and the chairperson +of each of the audit, corporate governance, nomination, and compensation committees receive no additional fees for serving in such capacities. +There is no additional compensation for meeting attendance. Directors who are employees of the Company receive no additional compensation +for serving as directors. All stock options granted to outside directors are immediately exercisable and expire ten years from the date +of grant or 30 days after the date they cease to be directors. Directors are reimbursed for ordinary expenses incurred in connection +with attending board and committee meetings. +63 +Equity +Incentive Plans +Under +our Amended and Restated 2015 Long-term Incentive Plan (the “2015 Plan”), the board of directors may issue incentive stock-based +awards to employees, directors and consultants of the company. Options awarded generally expire ten years after being granted. Any stock-based +awards granted vest in accordance with the vesting schedule determined by the board of directors. Should an employee’s director’s +or consultant’s relationship with the company terminate before the vesting period is completed, the unvested portion of each grant +is forfeited. We continue to maintain and grant awards under the 2015 Plan which will remain in effect until its expiration by its terms. +The +purpose of our incentive plan is to advance the interests of our stockholders by enhancing our ability to attract, retain and motivate +persons who are expected to make important contributions to the company by providing them with both equity ownership opportunities and +performance-based incentives intended to align their interests with those of our stockholders. These plans are designed to provide us +with flexibility to select from among various equity-based compensation methods, and to be able to address changing accounting and tax +rules and corporate governance practices by optimally utilizing stock-based awards. +ITEM +12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The +following table sets forth certain information, as of March 12, 2024, with respect to the holdings of (1) each person who is the beneficial +owner of more than 5% of our Common Stock, (2) each of our directors, (3) each named executive officer, and (4) all of our current directors +and executive officers as a group. +Beneficial +ownership of the common stock is determined in accordance with the rules of the Securities and Exchange Commission and includes any shares +of common stock over which a person exercises sole or shared voting or investment power, or of which a person has a right to acquire +ownership at any time within 60 days of March 12, 2024. Applicable percentage ownership in the following table is based on 31,259,668 +shares of common stock plus, for each individual, any securities that individual has the right to acquire within 60 days of March 12, +2024. +The +information in the table below is based on information known to us or ascertained by us from public filings made by the stockholders. +Except as otherwise indicated in the table below, addresses of the director, executive officers and named beneficial owners are in care +of Co-Diagnostics, Inc., 2401 S. Foothill Drive, Suite D, Salt Lake City, Utah 84109. +Number of Shares Beneficially Owned +Percentage +of Class (1) +5% Stockholders +Vanguard Group (1) +1,781,283 +5.7 % +Named Executive Officers and Directors +Dwight Egan (2) +370,881 +* +Brian Brown +213,220 +* +Edward Murphy (3) +147,500 +* +Eugene Durenard +85,000 +* +James Nelson (4) +135,000 +* +Richard Serbin (5) +107,945 +* +All Directors and Executive Officers as a Group (6 persons) +1,059,546 +3.3 % +*Represents +beneficial ownership of less than 1%. +(1) +Information +obtained from Schedule 13G/A filed with the SEC on February 13, 2024. Vanguard Group has an address of 100 Vanguard Blvd, Malvern, +PA, 19355. +(2) +Includes +exercisable options to acquire 100,000 shares of common stock. +(3) +Includes +exercisable options to acquire 50,000 shares of common stock. +(4) +Includes +exercisable options to acquire 50,000 shares of common stock. +(5) +Includes +exercisable options to acquire 20,445 shares of common stock. +Equity +Compensation Plan Information +Plan Category +(a) Number of Shares to be Issued upon Exercise of Outstanding Options and Rights +(b) Weighted-average Exercise Price of Outstanding Options and Rights +(c) Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Referenced in Column (a)) +Equity compensation plans approved by stockholders +3,966,069 (1) +$ 2.19 (2) +4,357,937 +Equity compensation plans not approved by stockholders +- +$ - +- +Total +3,966,069 (1) +$ 2.19 (2) +4,357,937 +(1) +Includes +options and restricted stock units outstanding under our 2015 Equity Incentive Plan. +(2) +Represents +weighted-average exercise price per share of common stock acquirable upon exercise of outstanding stock options. +64 +ITEM +13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +The +Company employs one person who is related to current or former executive officers. Seth Egan is the Company’s Director of Sales +and Marketing, and is the son of Dwight Egan, the Company’s President and Chief Executive Officer and Chairman of the Board. During +the year ended December 31, 2023, the total compensation paid to this person, including salaries, bonuses, and the grant date fair value +of equity awards which vest over three years, was $648,201. The Company also uses the services of Winston Egan as an independent contractor +for sales operations consulting. Winston Egan is also the son of Dwight Egan, the Company’s President and Chief Executive Officer +and Chairman of the Board. During the year ended December 31, 2023, the total compensation paid to this contractor, comprised of consulting +fees, was $120,000. +Policy +for Review of Related Party Transactions +The +review of transactions with related persons policy is set forth in our Corporate Governance Committee Charter. The Corporate Governance +Committee is to oversee the administration of any related party transactions policy in effect with respect to transactions in which the +Company is a participant and involving directors, nominees for director, executive officers of the Company or holders of more than 5% +of the Company’s common stock or immediate family members of any such person. +Director +Independence +For +information regarding the independence of our directors, see “Directors, Executive Officers and Corporate Governance” in +Part III, Item 10 of this Form 10-K. +ITEM +14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +The +aggregate fees and expenses for professional services rendered by our principal accounting firm, Tanner LLC for 2023 and Haynie & +Company for 2022, are separately presented and are as follows: +Years Ended December 31, +2023 +2022 +Audit fees +$ 154,811 +$ 136,600 +Audit related fees +- +- +Other consulting fees +287,838 +- +Tax fees +- +- +Total fees +$ 442,649 +$ 136,600 +Audit +fees consist of fees for professional services provided in connection with the audit of our annual consolidated financial statements, +review of our quarterly consolidated financial statements and our offerings. +Other consulting fees relate to fees for products +and services other than the services reported above and consist of federal and state research tax credit consulting services (at a fixed +fee). +The +audit committee has adopted a policy that requires advance approval of all services performed by the independent auditor when fees are +expected to exceed $15,000. The audit committee has delegated to the audit committee chairperson, Mr. Durenard, the authority to approve +services, subject to ratification by the audit committee at its next committee meeting. All fees incurred were pre-approved by the audit +committee. +65 +PART +IV +Item +15. Exhibits and Financial Statement Schedules. +(a) +The +following documents are filed as part of this Annual Report on Form 10-K: +(1) +Financial +Statements. The Consolidated Financial Statements filed as part of this Annual Report on Form 10-K are included in Part II, Item +8 of this Annual Report on Form 10-K. +(2) +Financial +statement schedules. There are no financial statements schedules included because they are either not applicable or the required +information is shown in the consolidated financial statements or the notes thereto. +(3) +Exhibits. +The exhibits required by Item 601 of Regulation S-K and Item 15(b) of this Annual Report are listed in the Exhibit Index below. The +exhibits listed in the Exhibit Index are incorporated by reference herein. +Exhibit +Number +Exhibit +Description +Filed +with this +Report +Incorporated +by +Reference +herein from Form or Schedule +Filing +Date +SEC +File/Reg. +Number +2.1*+ +Agreement +and Plan of Merger by and between Co-Diagnostics, Inc, IDMO Acquisition Corp., Idaho Molecular Inc., and Company Representative dated +as of December 21, 2021. +Form +8-K (Exhibit 2.1) +12/23/21 +001-38148 +2.1.2 +Amendment +to Agreement and Plan of Merger by and among Co-Diagnostics, Inc., Idaho Molecular, Inc., and Kirk Ririe, as Company Representative +Form +8-K (Exhibit 2.2) +06/16/22 +001-38148 +2.2*+ +Agreement +and Plan of Merger by and between Co-Diagnostics, Inc, ACI Acquisition Corp., Advanced Conceptions, Inc., and Company Representative +dated as of December 21, 2021 +Form +8-K (Exhibit 2.2) +12/23/21 +001-38148 +2.2.1 +Amendment +to Agreement and Plan of Merger by and among Co-Diagnostics, Inc., Advanced Conceptions, Inc., and Richard Abbott, as Company Representative +Form +8-K (Exhibit 2.1) +06/16/22 +001-38148 +3.1 +Articles +of Incorporation +Draft +Registration Statement (Exhibit 3.1) +01/12/17 +377-01467 +3.1.1 +Amendment +to the Articles of Incorporation +Draft +Registration Statement (Exhibit 3.1.1) +01/12/17 +377-01467 +3.1.2 +Articles +of Amendment to Articles of Incorporation +Form +8-K (Exhibit 3.2) +01/03/19 +001-38148 +3.1.3 +Articles of Amendment +Form +10-K (Exhibit 3.1.3) +03/24/22 +001-38148 +3.1.3 +Articles of Amendment +Form +10-K (Exhibit 3.1.3) +03/16/2023 +001-38148 +3.2 +Amended +and Restated Bylaws of Co-Diagnostics, Inc. +Form +8-K (Exhibit 3.1) +04/01/22 +001-38148 +4.1 +Description of Registrant’s securities +X +4.2 +Form of Indenture +Registration +Statement (Exhibit 4.1) +03/16/23 +333-270628 +10.1 +Exclusive +Agreement between Co-Diagnostics, Inc. and DNA Logix, Inc., dated April 18, 2014 +Draft +Registration Statement (Exhibit 10.2) +01/12/17 +377-01467 +10.2 # +Co-Diagnostics, +Inc. Amended and Restated 2015 Long Term Incentive Plan +Form +S-8/A +11/20/20 +333-237684 +10.3 +Form +of Indemnification Agreement +Form +S-1/A (Exhibit 10.13.8) +05/24/17 +333-217542 +10.4 +Shareholders’ +Agreement between Co-Diagnostics and Synbiotics Limited, dated January 27, 2017 +Form +S-1 (Exhibit 10.16) +04/28/17 +333-217542 +10.5 +Amended +Exclusive License Agreement between Co-Diagnostics, Brent Satterfield, and DNA Logix, Inc., dated January 1, 2017 +Form +S-1 (Exhibit 10.17) +04/28/17 +333-217542 +10.6 +Warrant +Agreement between Co-Diagnostics, Inc and VStock Transfer, LLC. Dated December 31, 2021 (ACI Warrant) +Form +10-K (Exhibit 10.6) +03/24/22 +001-38148 +66 +10.7 +Warrant +Agreement between Co-Diagnostics, Inc and VStock Transfer, LLC. Dated December 31, 2021 (IDMO Warrant) +Form +10-K (Exhibit 10.7) +03/24/22 +001-38148 +10.8 +Form +of Securities Purchase Agreement, dated February 27, 2020 +Form +8-K (Exhibit 10.1) +02/27/20 +001-38148 +10.9 +Lease +Agreement 2401 Foothill Drive +Form +10-K (Exhibit 10.9) +03/24/22 +001-38148 +10.9.1 +Amendment +#1 to Lease +Form +10-K (Exhibit 10.9.1) +03/24/22 +001-38148 +10.9.2 +Amendment +#2 to Lease +Form +10-K (Exhibit 10.9.2) +03/24/22 +001-38148 +10.10# +Co-Diagnostics, Inc. Change in Control Plan +Form +8-K (Exhibit 10.1) +05/16/23 +001-38148 +10.11 +Commercial +Lease Agreement, dated June 1, 2023, between Ozone Biotech, LLC and Co-Diagnostics, Inc. +Form +10-Q (Exhibit 10.1) +08/10/23 +001-38148 +10.12 +Commercial Lease Agreement, dated September 18, 2023, between Ge Estate, LLC and Co-Diagnostics, Inc. +Form +10-Q (Exhibit 10.1) +11/09/23 +001-38148 +10.13 +Common Stock Purchase Warrant issued to Coltrin & Associates dated October 31, 2019 +Registration +Statement (Exhibit 4.9) +03/16/23 +333-270628 +10.14 +Common Stock Purchase Warrant issued to Coltrin & Associates dated February 6, 2020 +Registration +Statement (Exhibit 4.10) +03/16/23 +333-270628 +10.15 +Common Stock Purchase Warrant issued to Coltrin & Associates dated February 6, 2020 +Registration +Statement (Exhibit 4.11) +03/16/23 +333-270628 +10.16 +Amendment dated July 31, 2020 to Common Stock Purchase Warrant issued to Coltrin & Associates dated October 31, 2019 +Registration +Statement (Exhibit 4.12) +03/16/23 +333-270628 +14.1 +Code +of Ethics for Senior Financial Officers +Form +10-K (Exhibit 14.1) +03/30/20 +001-38148 +21.1 +Subsidiaries of Registrant +X +23.1 +Consent of Tanner LLC +X +23.2 +Consent of Haynie & Company +X +31.1 +Certification of Chief Executive Officer pursuant to section 302 of the Sarbanes-Oxley Act of 2002 +X +31.2 +Certification of Principal Financial Officer pursuant to section 302 of the Sarbanes-Oxley Act of 2002 +X +32.1 +Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 +X +32.2 +Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 +X +97 +Co-Diagnostics, Inc. Clawback Policy +X +101 +SCH +Inline +XBRL Taxonomy Extension Schema Document (A) +X +101.CAL +Inline +XBRL Taxonomy Extension Calculation Linkbase Document (A) +X +101.DEF +Inline +XBRL Taxonomy Extension Definition Linkbase Document (A) +X +101.LAB +Inline +XBRL Taxonomy Extension Label Linkbase Document (A) +X +101.PRE +Inline +XBRL Taxonomy Extension Presentation Linkbase Document (A) +X +104 +Cover +Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) +X +(A) +iXBRL +(INline Extensible Business Reporting Language) information +is furnished and not filed for purposes of Section 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange +Act of 1934. +X +# Management +Contract or Compensatory Plan or Arrangement +*Schedules +and exhibits to these Exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company agrees to furnish supplementally +a copy of any omitted schedule or exhibit to the SEC upon request. ++ +Portions of Exhibit 2.1 and Exhibit 2.2 have been omitted as they contain information that (i) is not material and (ii) is the type of +information the issuer both customarily and actually treats as private and confidential. +Item +16. Form 10-K Summary. +None +67 +SIGNATURES +Pursuant +to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed +on its behalf by the undersigned thereunto duly authorized. +CO-DIAGNOSTICS, +INC. +Date: +March 14, 2024 +By: +/s/ +Dwight Egan +Dwight +Egan +Chief +Executive Officer, President and Director +(Principal +Executive Officer) +By: +/s/ +Brian Brown +Brian +Brown +Chief +Financial Officer +(Principal +Financial and Accounting Officer +Pursuant +to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the +registrant and in the capacities and on the date indicated. +Signature +Title +Date +/s/ +Dwight Egan +Chief +Executive Officer, President and Director +March +14, 2024 +Dwight +Egan +(Principal +Executive Officer) +/s/ +Brian Brown +Chief +Financial Officer +March +14, 2024 +Brian +Brown +(Principal +Financial and Accounting Officer) +/s/ +Eugene Durenard +Director +March +14, 2024 +Eugene +Durenard +/s/ +Edward Murphy +Director +March +14, 2024 +Edward +Murphy +/s/ +James Nelson +Director +March +14, 2024 +James +Nelson +/s/ +Richard Serbin +Director +March +14, 2024 +Richard +Serbin +68 \ No newline at end of file diff --git a/raw/filings/0001692415/2023/0001493152-24-009955/filing_metadata.csv b/raw/filings/0001692415/2023/0001493152-24-009955/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..555306e60915c50820ae274f8ea7166fa6d37970 --- /dev/null +++ b/raw/filings/0001692415/2023/0001493152-24-009955/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001692415,CODX,"Co-Diagnostics, Inc.",10-K,2024-03-14,2023-12-31,2024-03-15T00:05:56.000Z,0001493152-24-009955,form10-k.htm,,7420999,1,1,https://www.sec.gov/Archives/edgar/data/1692415/000149315224009955/form10-k.htm,https://www.sec.gov/Archives/edgar/data/1692415/000149315224009955/,2023,2023,1 diff --git a/raw/filings/0001692415/2023/0001493152-24-009955/item1.txt b/raw/filings/0001692415/2023/0001493152-24-009955/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001692415/2023/0001493152-24-009955/item13.txt b/raw/filings/0001692415/2023/0001493152-24-009955/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001692415/2023/0001493152-24-009955/item9a.txt b/raw/filings/0001692415/2023/0001493152-24-009955/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001692415/2023/0001493152-24-009955/rp_note.txt b/raw/filings/0001692415/2023/0001493152-24-009955/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..9965eca6492e41a5db005c6b9123b7e2e2311876 --- /dev/null +++ b/raw/filings/0001692415/2023/0001493152-24-009955/rp_note.txt @@ -0,0 +1,16 @@ +Note 14 – Related Party Transactions +The Company employs one person who is related to +current or former executive officers. Seth Egan is the Company’s Director of Sales and Marketing, and is the son of Dwight +Egan, the Company’s President and Chief Executive Officer and Chairman of the Board. During the year ended December 31, 2023, +the total compensation paid to this person, including salaries, bonuses, and the grant date fair value of equity awards which vest +over three +years , was $ 0.6 +million. The Company also uses the services of Winston Egan as an independent contractor for sales operations consulting. +Winston Egan is also the son of Dwight Egan, the Company’s President and Chief Executive Officer and Chairman of the Board. +During the year ended December 31, 2023, the total compensation paid to this contractor, comprised of consulting fees, was $ 0.1 +million. +In August 2023, the Company entered into a +services agreement with CoSara, the Company’s equity method investment, under which CoSara provides certain research and +development consulting and support services. During the year ended December 31, 2023, the Company recognized $ 0.2 million +of expense related to this agreement. +Note \ No newline at end of file diff --git a/raw/filings/0001692415/2023/0001493152-24-009955/rpt_disclosure.txt b/raw/filings/0001692415/2023/0001493152-24-009955/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..94635aadd778638d52061ea4650b6d8159d8f8eb --- /dev/null +++ b/raw/filings/0001692415/2023/0001493152-24-009955/rpt_disclosure.txt @@ -0,0 +1,195 @@ +for Review of Related Party Transactions +The +review of transactions with related persons policy is set forth in our Corporate Governance Committee Charter. The Corporate Governance +Committee is to oversee the administration of any related party transactions policy in effect with respect to transactions in which the +Company is a participant and involving directors, nominees for director, executive officers of the Company or holders of more than 5% +of the Company’s common stock or immediate family members of any such person. +Pay +versus Performance +In +accordance with rules adopted by the Securities and Exchange Commission (“SEC”) pursuant to the Dodd-Frank Wall Street Reform +and Consumer Protection Act of 2010, we provide the following disclosure regarding executive “Compensation Actually Paid” +(“CAP”) and certain performance measures required for Smaller Reporting Companies. The following table provides the information +required for our NEOs for each of the fiscal years ended December 31, 2024 and December 31, 2023, along with the financial information +required for each fiscal year: +Year +Summary +compensation table total CEO ($) (1)(2) +Compensation +actually paid to CEO ($) (1)(3) +Average +summary compensation table total for non-CEO NEOs ($) (2)(4) +Average +compensation actually paid to non-CEO NEOs ($) (3)(4) +Value of Initial Fixed $100 Investment based on Total shareholder return ($) +Net Income (in millions) ($) +2024 +716,917 +421,350 +501,475 +346,524 +8.40 +( 38 ) +2023 +1,261,300 +579,599 +1,033,550 +485,150 +14.89 +( 35 ) +(1) +For each year shown the +CEO was Dwight Egan . +(2) +Amounts in this column +represent the “Total” column set forth above in the Summary Compensation Table (“SCT”). See the footnotes +to the SCT for further detail regarding the amounts in these columns. +(3) +The dollar amounts reported +in these columns represent the amounts of “compensation actually paid.” The Amounts are computed in accordance with Item +402(v) of Regulation S-K by deducting and adding the following amounts from the “Total” column of the SCT (pursuant to +SEC rules, fair value at each measurement date is computed in a manner consistent with the fair value methodology used to account +for share-based payments in our financial statements under GAAP). +(4) +During 2024, there were +two Non-CEO NEO’s, Brian Brown, CFO, and Richard Abbott, President. During 2023, there was one Non-CEO NEO, Brian Brown, CFO. +18 +2024 +2023 +Dwight Egan +Average Non-CEO NEOs +Dwight Egan +Average Non-CEO NEOs +Total Compensation from Summary Compensation Table +$ 716,917 +$ 501,475 +$ 1,261,300 +$ 1,033,550 +Adjustments for Equity Awards +Adjustment for grant date values in the Summary Compensation Table +$ ( 305,250 ) +$ ( 191,475 ) +$ ( 845,550 ) +$ ( 701,550 ) +Year-end fair value of unvested awards granted in the current year +$ 171,875 +$ 107,813 +$ 442,225 +$ 364,642 +Year-over-year difference of year-end fair values for unvested awards granted in prior years +$ ( 136,300 ) +$ ( 70,694 ) +$ ( 188,416 ) +$ ( 153,709 ) +Fair values at vest date for awards granted and vested in current year +$ 46,291 +$ 29,038 +$ 115,083 +$ 95,458 +Difference in fair values between prior year-end fair values and vest date fair values for awards granted in prior years +$ ( 72,183 ) +$ ( 29,633 ) +$ ( 205,043 ) +$ ( 153,241 ) +Forfeitures during current year equal to prior year-end fair value +$ - +$ - +$ - +$ - +Dividends or dividend equivalents not otherwise included in total compensation +$ - +$ - +$ - +$ - +Total Adjustments for Equity Awards +$ ( 295,567 ) +$ ( 154,951 ) +$ ( 681,701 ) +$ ( 548,400 ) +Compensation Actually Paid (as calculated) +$ 421,350 +$ 346,524 +$ 579,599 +$ 485,150 +Narrative +Disclosure: Pay Versus Performance Table +The +illustrations below provide a graphical description of CAP (as calculated in accordance with the SEC rules) and the following measures: +● +Co-Diagnostics’ cumulative +TSR ; and +● +Co-Diagnostics’ Net +Income +CAP +and Cumulative TSR +CAP +and Net Income +19 +STOCK +OWNERSHIP +The +following table sets forth certain information, as of April 3, 2025, with respect to the holdings of (1) each person who is the beneficial +owner of more than 5% of our Common Stock, (2) each of our directors, (3) each named executive officer, and (4) all of our current directors +and executive officers as a group. +Beneficial +ownership of the common stock is determined in accordance with the rules of the Securities and Exchange Commission and includes any shares +of common stock over which a person exercises sole or shared voting or investment power, or of which a person has a right to acquire +ownership at any time within 60 days of April 3, 2025. Applicable percentage ownership in the following table is based on 33,572,643 +shares of common stock plus, for each individual, any securities that individual has the right to acquire within 60 days of April 3, +2025. +The +information in the table below is based on information known to us or ascertained by us from public filings made by the stockholders. +Except as otherwise indicated in the table below, addresses of the director, executive officers and named beneficial owners are in care +of Co-Diagnostics, Inc., 2401 S. Foothill Drive, Suite D, Salt Lake City, Utah 84109. +Number of Shares Beneficially Owned +Percentage +of Class +5% Stockholders +Vanguard Group (1) +1,781,283 +5.3 % +Named Executive Officers and Directors +Dwight Egan (2) +736,548 +2.2 % +Brian Brown +513,292 +1.5 % +Richard Abbott +618,652 +1.8 % +Edward Murphy (3) +261,667 +* +Eugene Durenard +211,667 +* +James Nelson (4) +274,167 +* +Richard Serbin (5) +234,612 +* +All Directors and Executive Officers as a Group (7 persons) +2,850,605 +8.4 % +*Represents +beneficial ownership of less than 1%. +(1) +Information obtained from +Schedule 13G/A filed with the SEC on February 13, 2024. 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jurisdiction of +incorporation +or organization) +(I.R.S. +Employer +Identification +Number) +2401 +S. Foothill Drive , Salt Lake City , Utah 84109 +(Address +of principal executive offices and zip code) +(801) +438-1036 +(Registrant’s +telephone number including area code) +Securities +registered pursuant to Section 12(b) of the Act: +Title +of each class +Trading +Symbol(s) +Name +of each exchange on which registered +Common +Stock +CODX +The +Nasdaq Capital Market +Securities +registered pursuant to Section 12(g) of the Act: None +Indicate +by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒ +Indicate +by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ☐ No ☒ +Indicate +by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act of 1934 +during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject +to such filing requirements for the past 90 days. Yes ☒ No ☐ +Indicate +by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data +File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding +12 months (or such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐ +Indicate +by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting +company or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller +reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. +Large +accelerated filer +☐ +Accelerated +filer +☐ +Non-accelerated +filer +☒ +Smaller +reporting company +☒ +Emerging +growth company +☐ +If +an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying +with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐ +Indicate +by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness +of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered +public accounting firm that prepared or issued its audit report. ☐ +If +securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant +included in the filing reflect the correction of an error to previously issued financial statements. ☐ +Indicate +by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation +received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐ +Indicate +by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒ +The +aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which +the common stock was last sold as of the last business day of the registrant’s most recently completed second fiscal quarter was +approximately $ 37,000,000 . +As +of March 21, 2025, there were 33,572,643 shares of common stock, par value $ 0.001 per share, outstanding. +Table +of Contents +Page +PART I +Item +1. +Business. +4 +Item +1A. +Risk Factors. +13 +Item +1B. +Unresolved Staff Comments. +25 +Item +1C. +Cybersecurity +26 +Item +2. +Properties. +27 +Item +3. +Legal Proceedings. +27 +Item +4. +Mine Safety Disclosures. +28 +PART II +Item +5. +Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. +29 +Item +6. +[Reserved.] +30 +Item +7. +Management’s Discussion and Analysis of Financial Condition and Results of Operations. +30 +Item +7A. +Quantitative and Qualitative Disclosures About Market Risk. +34 +Item +8. +Financial Statements and Supplementary Data. +35 +Item +9. +Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. +55 +Item +9A. +Controls and Procedures. +55 +Item +9B. +Other Information. +56 +Item +9C. +Disclosure Regarding Foreign Jurisdictions that Prevent Inspections. +56 +PART III +Item +10. +Directors, Executive Officers and Corporate Governance. +56 +Item +11. +Executive Compensation. +61 +Item +12. +Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. +64 +Item +13. +Certain Relationships and Related Transactions, and Director Independence. +65 +Item +14. +Principal Accountant Fees and Services. +65 +PART IV +Item +15. +Exhibits and Financial Statement Schedules. +66 +2 +PART +I +Forward-Looking +Statements +This +Annual Report on Form 10-K contains “forward-looking statements” that involve risks and uncertainties. All statements other +than statements of historical fact contained in this Annual Report and the documents incorporated by reference herein, including statements +regarding future events, our future financial performance, business strategy, and plans and objectives of management for future operations, +are forward-looking statements. We have attempted to identify forward-looking statements by terminology including “anticipates,” +“believes,” “can,” “continue,” “could,” “estimates,” “expects,” +“intends,” “may,” “plans,” “potential,” “predicts,” “should,” +or “will” or the negative of these terms or other comparable terminology. Although we do not make forward looking statements +unless we believe we have a reasonable basis for doing so, we cannot guarantee their accuracy. These statements are only predictions +and involve known and unknown risks, uncertainties and other factors which may affect our or our industry’s actual results, levels +of activity, performance or achievements expressed or implied by these forward-looking statements. Moreover, we operate in a highly regulated, +very competitive, and rapidly changing environment. New risks emerge from time to time, and it is not possible for us to predict all +risk factors, nor can we address the impact of all factors on our business or the extent to which any factor, or combination of factors, +may cause our actual results to differ materially from those contained in any forward-looking statements. +We +have based these forward-looking statements largely on our current expectations and projections about future events and financial trends +that we believe may affect our financial condition, results of operations, business strategy, short term and long-term business operations, +and financial needs. These forward-looking statements are subject to certain risks and uncertainties that could cause our actual results +to differ materially from those reflected in the forward-looking statements. Factors that could cause or contribute to such differences +include, but are not limited to, those discussed in this Annual Report, and in particular, the risks discussed under “ Item 1, +Business,” “Item 1A, Risk Factors,” and “Item 7, Management’s Discussion and Analysis of Financial Condition +and Results of Operations,” and those discussed in other documents we file with the Securities and Exchange Commission (the +“SEC”). In light of these risks, uncertainties and assumptions, the forward-looking events and circumstances discussed in +this Annual Report may not occur as described and actual results could differ materially and adversely from those anticipated or implied +in the forward-looking statement. +Important +factors that could cause actual results to differ materially from those in the forward-looking statements include, without limitation: +● +our +ability to obtain regulatory approval to market and sell our products; +● +the +results of clinical evaluations of our product candidates; +● +market +acceptance of any products that may be approved for commercialization; +● +our +ability to protect our intellectual property rights; +● +the +impact of any infringement actions or other litigation brought against us; +● +competition +from other providers and products; +● +our +ability to develop and commercialize new and improved products and services; +● +changes +in government regulation; +● +and +other factors (including the risks contained in the section entitled “Risk Factors” in other documents we file with the +SEC) relating to our industry, our operations and results of operations. +Should +one or more of these risks or uncertainties materialize, or should the underlying assumptions prove incorrect, actual results may differ +significantly from those anticipated, believed, estimated, expected, intended or planned. +Given +these risks and uncertainties, readers are cautioned not to place undue reliance on any forward-looking statements. Forward-looking statements +contained in this Annual Report speak only as of the date of this Annual Report. We undertake no obligation to update any forward-looking +statements as a result of new information, events or circumstances or other factors arising or coming to our attention after the date +hereof. +3 +As +used in this Annual Report, the terms “we”, “us”, “our”, “Company”, “CODX” +and “Co-Diagnostics” means Co-Diagnostics, Inc., a Utah corporation and its consolidated subsidiaries (the “Company”), +unless otherwise indicated. +ITEM +1: BUSINESS +Overview +Co-Diagnostics, +Inc., a Utah corporation (the “Company” or “CODX”), develops, manufactures and sells reagents used for diagnostic +tests that function via the detection and/or analysis of nucleic acid molecules (DNA or RNA), including robust and innovative molecular +tools for detection of infectious diseases. Our diagnostics systems enable dependable, low-cost, molecular testing for organisms and +genetic diseases by automating or simplifying historically complex procedures in both the development and administration of tests. CODX’s +technical advance involves a novel, proprietary approach to PCR test design of primer and probe structure (“Co-Primers ® ”) +that dramatically reduces one of the key vexing issues of PCR amplification: the exponential growth of primer-dimer amplification (false +positives) which adversely interferes with identification of the target DNA/RNA. Using our proprietary test design system and reagents, +we have designed and obtained regulatory approval to sell PCR diagnostic tests for the detection of COVID-19, influenza, tuberculosis, +hepatitis B and C, human papillomavirus, malaria, chikungunya, dengue, and the Zika virus. These initial diagnostic tests are cleared +for use in clinical labs only and not for point-of-care or at-home use. +We +are currently developing a unique, groundbreaking portable diagnostic device and test system designed for point-of-care and at-home use. +The system is comprised of our PCR instrument that we refer to as the Co-Dx™ PCR Pro™ instrument, our patent-pending diagnostic +test cup system and a mobile application to be installed on the user’s mobile device. We refer to the system as the “Co-Dx™ +PCR platform which has been designed to bring affordable, reliable polymerase chain reaction (“PCR”) testing to patients +in point-of-care and at-home settings. The Co-Dx PCR platform is subject to U.S. Food and Drug Administration (“FDA”) review +and is not available for sale at the time of this filing. In June 2024, we completed our first U.S. Food and Drug Administration (FDA) +application for 510(k) clearance for the Co-Dx™ PCR Pro™ instrument, the Co-Dx PCR COVID-19 Test, and the Co-Dx PCR mobile +app for over-the-counter (OTC) use. Following productive engagement with the FDA related to the regulatory submission, the Company withdrew +its 510(k) application. The decision to withdraw the submission was based on discussions with the FDA regarding the ability to detect +a potential deterioration of one component of the test, related to shelf-life stability. Following dialogue with the FDA and exploring +the various courses of action available, we determined that the best long-term solution would be to submit a version of the test that +has been enhanced to address the matter raised in the 510(k) review process. The Company plans to submit the next iteration of the Co-Dx +PCR COVID-19 test for 510(k) OTC clearance, following the collection of clinical evaluation data to support the new test’s performance. +A new submission also allows the Company to incorporate more recent Co-Dx PCR platform developments into the COVID-19 test, which Co-Dx +believes will also help create greater operational and manufacturing efficiencies, such as consolidating manufacturing processes to utilize +the next generation of test kits and instruments across all tests on the at-home and point-of-care Co-Dx PCR platform. There is no guarantee +that our Co-Dx PCR platform will receive the necessary regulatory approvals for commercialization, or that, if regulatory approval is +received, we will be able to successfully commercialize this platform. +4 +Technology +We +believe our proprietary and patented molecular diagnostics technology is paving the way for innovation in disease detection and life +sciences research through our enhanced detection of genetic material. For various reasons, including owning our own platform, we believe +we will be able to accomplish this faster and more economically than some competitors, allowing for significant margins while still positioning +ourselves as a low-cost provider of molecular diagnostics and screening services. For example, we were the first US-based company to +receive a CE-marking for a COVID-19 test in early 2020, as we worked to help slow the spread of the pandemic through our global network +of distributors covering clinical labs in more than 50 countries. Our Logix Smart ® COVID-19 test was designed, developed, submitted +for regulatory approval and ready to be used as an in vitro diagnostic or IVD in countries that accept CE marking for regulatory clearance +in a period of just over 30 days. This is a real-world example of how CODX technology can be used in an evolving epidemic or pandemic +to get diagnostic tools in the hands of medical professionals in a timely manner. It can be similarly used to design a test for mutated +strains of SARS-CoV-2 or other viruses should they not be detectable using currently available tests. +In +addition, continued development has demonstrated the unique properties of our Co-Primers technology that we believe makes it ideally suited +for a variety of applications where specificity is key to optimal results, including multiplexing several targets, enhanced Single Nucleotide +Polymorphism (“SNP”) detection and enrichment for next generation sequencing. +Our +scientists use the complex mathematics of DNA/RNA PCR test design to engineer and optimize PCR tests and to automate algorithms that +rapidly screen millions of possible options to pinpoint the optimum design. The intellectual property we use in our business consists +of the predictive mathematical algorithms and patented molecular structure used in the testing process, which together represent a major +advance in PCR testing systems. CODX technologies are now protected by more than 20 granted or pending US and foreign patents, as well +as certain trade secrets and copyrights. Ownership of our proprietary platform permits us the advantage of avoiding payment of patent +royalties required by other PCR test systems, which may allow the sale of diagnostic PCR tests at a lower price than competitors, while +enabling us to maintain profit margins. +Our +proprietary test design process involves identifying the optimal locations on the target genes for amplification and pairing the locations +with the optimized primer and probe structure to achieve outputs that meet the design input requirements identified from market research. +This is done by following planned and documented processes, procedures and testing. In other words, we use the data resulting from our +tests to verify whether we succeeded in designing what we intended. Verification involves a series of testing that concludes that the +product is ready to proceed to validation in an evaluation either in our laboratory or in an independent laboratory setting using initial +production tests to confirm that the product as designed meets the user needs. +Using +our proprietary test design system and reagents, we have designed and obtained regulatory approval in the European Community and in India +to sell PCR diagnostic tests for the detection of COVID-19, influenza, tuberculosis, hepatitis B and C, human papillomavirus, malaria, +chikungunya, dengue, and the Zika virus. In the United States, we obtained Emergency Use Authorization (“EUA”) for our Logix +Smart ® COVID-19 detection test from the FDA, and we sell that test to qualified labs. +In addition, our COVID-19 detection test and certain of our other suite of COVID-19 products have been cleared for sale in countries +such as the United Kingdom, Australia, India, and Mexico by the regulatory bodies in those countries and have been registered for sale +in many more countries. In connection with the sale of our tests we may sell diagnostic equipment from other manufacturers, including +an OEM’s PCR instrument which we refer to here as the “Co-Dx Box”. +In addition to testing for infectious disease, Co-Primers technology lends +itself to identifying any section of a DNA or RNA strand that describes any type of genetic trait, which creates several significant applications. +We, in conjunction with our customers, have designed and licensed tests that identify genetic traits in plant and animal genomes. We also +have commercialized three multiplexed tests to test mosquitos for the presence of diseases they carry, which enables municipalities to +concentrate their efforts in managing mosquito populations in specific areas where mosquitos carrying deadly viruses are known to breed. +5 +Co-Dx +PCR Platform +We +believe the benefits of affordable, high-quality diagnostics should be available to everyone. High-quality point-of-care polymerase chain +reaction (“PCR”) testing plays a crucial role in healthcare. It enables rapid diagnosis of infectious diseases, such as COVID-19 +or tuberculosis, facilitating timely treatment and containment measures. By delivering results on-site, it eliminates the need for sample +transportation, reducing the risk that the sample is transported incorrectly or lost, reducing turnaround time to results, and +allowing for immediate decision-making. Gold-standard PCR testing at the point of care ensures reliable detection of pathogens, minimizing +incorrect results. In short, high-quality PCR testing at home and at the point of care enhances patient care, public health response, +and helps control the spread of infectious diseases. That is why we are developing the Co-Dx PCR platform utilizing our Co-Primers™ +real-time PCR technology for at-home and point-of-care testing. Because we believe that testing for COVID-19 and other infectious diseases +will continue to be a consideration for public health worldwide, we initiated the Co-Dx PCR platform to facilitate frequent, affordable, +reliable PCR testing to patients in point-of-care and at-home settings, including schools, businesses, and the hospitality industry. +We believe this may be accomplished through the development of a testing platform comprised of a compact, relatively low-cost testing +device, the Co-Dx PCR Pro instrument, together with patent-pending diagnostic test cups that work with the instrument and an intuitive +mobile application, that is easy to use by professionals and non-professionals, all of which can provide PCR test results in around 30 +minutes. As user test results are analyzed and anonymized in the cloud, we believe this data may be useful for governmental health agencies +and the World Health Organization to determine where outbreaks of infectious diseases may be occurring and to enable them to act more +quickly and efficiently to slow-down or perhaps even prevent further spread. +The +6 ½” x 4 1/2” x 6”, 2 lbs. Co-Dx PCR Pro instrument operates via a smartphone app with simple-to-follow instructions +that includes videos to walk users through every step, from sample swab collection to the straightforward instrument operation. Results +are processed in the cloud and delivered back to the user’s smartphone or tablet in about 30 minutes using software designed from +the ground-up for this specific use. The PCR tests themselves (contained in the simple but unique, innovative test collection cups) are +powered by patented Co-Dx Co-Primers PCR technology. +The +initial diagnostic test designed for use on this platform, an at-home and point-of-care COVID-19 PCR test, was ultimately facilitated +by our development of a saliva or nasal swab-based PCR test that does not require RNA/DNA extraction (standard in laboratory-based PCR +testing). The final result is believed to be approximately equivalent to those processed by a high-complexity clinical laboratory. Our +COVID-19 PCR platform test has the advantages of increased speed over clinical laboratories, with results in around 30 minutes compared +to hours or even days, and ease of handling thanks to lyophilization (or freeze-drying) of our testing reagents to allow for storage +at room temperatures. In December 2023, we submitted our proprietary Co-Dx PCR COVID-19 test cups, together with the Co-Dx PCR Pro instrument +and mobile application, all designed for use in point-of-care and at-home settings, for review by the U.S. Food and Drug Administration +(FDA) for Emergency Use Authorization (EUA). In June 2024, we completed our first FDA application for 510(k) clearance for the Co-Dx +PCR Pro instrument, the Co-Dx PCR COVID-19 Test, and the Co-Dx PCR mobile app for over-the-counter (OTC) use. Following productive engagement +with the FDA related to the regulatory submission the Company withdrew its 510(k) application. The decision to withdraw the submission +was based on discussions with the FDA regarding the ability to detect a potential deterioration of one component of the test, related +to shelf-life stability. Following dialogue with the FDA and exploring the various courses of action available, we determined that the +best long-term solution would be to submit a version of the test that has been enhanced to address the matter raised in the 510(k) review +process. The Company plans to submit the next iteration of the Co-Dx PCR COVID-19 test for 510(k) OTC clearance, following the collection +of clinical evaluation data to support the new test’s performance. A new submission will also allow the Company to incorporate +more recent Co-Dx PCR platform developments into the COVID-19 test, which Co-Dx believes will also help create greater operational and +manufacturing efficiencies, such as consolidating manufacturing processes to utilize the next generation of test kits and instruments +across all tests on the at-home and point-of-care Co-Dx PCR platform. +We +expect to develop further diagnostic tests for use with the PCR Pro instrument, including a multiplex test for influenza A and B, RSV +and COVID-19. To that effect, in July 2023 we were awarded $1.2 million in funding from the National Institutes of Health (NIH) as part +of the Rapid Acceleration of Diagnostics (RADx ® ) Tech program for development of our upper respiratory panel diagnostic test for +use on the Company’s Co-Dx PCR platform. We are utilizing the funds from the RADx Tech award to complete development of our flu +A/B, COVID-19, and RSV multiplex test, preparatory for that test to begin clinical trials on the Co-Dx PCR Pro instrument. The NIH launched +the RADx initiative on April 29, 2020, with the goal of speeding innovation in the development, commercialization, and implementation +of technologies for COVID-19 testing, leveraging the existing NIH Point-of-Care Technology Research Network. The RADx Tech program is +managed by the National Institute of Biomedical Imaging and Bioengineering (NIBIB), to support the accelerated development of tests and +provide regulatory guidance during the COVID-19 pandemic and beyond. +6 +We +are also developing diagnostics tests for TB and HPV for use with our Co-Dx PCR platform. We have been awarded two grants totaling $6.8 +million for the TB test and one grant totaling $987,000 for the HPV test by the Bill & Melinda Gates Foundation to support the development +and manufacture of these tests for our Co-Dx PCR platform. In 2014, all United Nations Member States and the World Health Organization +(WHO) committed to ending the global TB epidemic by 2030, before the COVID-19 pandemic slowed, stalled or reversed progress of global +TB targets. The WHO reported a worldwide gap of roughly 2.7 million unidentified cases between the reported number of newly diagnosed +TB cases in 2023 and the estimated number of incident cases, highlighting the need for a dramatic increase of affordable, high-quality, +point-of-care TB diagnostics to enable rapid treatment decisions to be made for a disease that has a mortality rate of about 50% if left +untreated. The National Cancer Institute estimates that high-risk HPVs cause roughly 5% of all cancers worldwide, including cervical +cancer, the fourth most common cancer in women and which led to an estimated 350,000 cervical cancer deaths in 2022 according to the +WHO. About 94% of these deaths are in low- and middle-income countries, and all of which the WHO believes can be dramatically reduced +by access to diagnostics, vaccinations, and cancer screenings. +Infectious +Disease Product Offering +Using +our proprietary test design system and reagents, we and CoSara Diagnostics Pvt Ltd (“CoSara”), our consolidated joint venture +for development and manufacturing in India, design and sell PCR diagnostic tests for detection of diseases and pathogens such as COVID-19, +influenza, tuberculosis, hepatitis B and C, malaria, dengue, human papillomavirus, chikungunya, and Zika virus, all of which tests have +been designed and verified in our laboratories. Our tuberculosis test and Zika tests received CE marking in 2018, and a triplex test +for Zika, dengue and chikungunya received CE marking in 2019, qualifying the tests to be sold throughout the European community and in +most countries in Central and South America. In December 2019, CoSara received a license to manufacture and sell tuberculosis, hepatitis +B, hepatitis C, human papillomavirus 16/18 and malaria tests in India from the Central Drugs Standard Control Organization (“CDSCO”). +In February 2020, we received CE marking for our Logix Smart COVID-19 test followed by an EUA by the FDA in April 2020. Also, in April +2020, our COVID-19 test was approved for manufacture and sale in India by the CDSCO and in Mexico by the INDRE, Mexico’s equivalent +to the United States Center for Disease Control. In August 2020, we received approval from the Australian Department of Health Therapeutic +Goods Division to sell our COVID-19 test in Australia. +As +explained above, our Logix Smart COVID-19 test was designed, developed, submitted for regulatory clearance and ready to be used as an +in vitro diagnostic or IVD in countries that accept CE marking for regulatory clearance in a period of just over 30 days. This +is a real-world example of how CODX technology can be used in an evolving epidemic or pandemic to get diagnostic tools in the hands of +medical professionals in a timely manner. It can be similarly used to design a test for mutated strains of SARS-CoV-2 or other viruses +should they not be detectable using currently available tests. +Caribbean +and Central and South America +We +began selling PCR diagnostic tests to entities located in South and Central America and the Caribbean in 2018. In some of those countries, +there are limited regulatory hurdles, which allowed us to begin offering our tests immediately with CE markings. We have applied for +and received registrations for our tests in many of those countries that require registration, and our distributors in those countries +have provided us with in-country assistance in completing such registrations. +We +first offered our Zika test in this region because of the demand for such a test, followed by tests for tuberculosis, and our triplex +test for Zika, chikungunya, and dengue. Sales of those tests have not been material, but with the granting of CE marking and EUA for +our Logix Smart COVID-19, we experienced an increase in sales in this region. +India +In +January 2017, the Company entered into an agreement to manufacture diagnostics tests for seven infectious diseases with a pharmaceutical +manufacturing company in India and formed CoSara Diagnostics Pvt. Ltd. as a joint venture. The agreement provided for the construction +of a manufacturing plant and the manufacture of the tests named above and the joint sales and marketing of those tests in India. We have +received a license for the plant in Ranoli, India to manufacture approved tests and it is being used for testing and manufacturing of +our products for the Indian market. +The +CDSCO has given us the approval for manufacture and sale of the 15 tests referred to above, and the Company’s joint venture +manufactures and sells 14 of those tests under the SaraGene brand. The Company manages a reagent rental program in India with +thermocyclers purchased from a third-party manufacturer and which we refer to here as our Co-Dx Box. The placement of thermocyclers +in India has facilitated the sale of the SaraGene PCR tests in India. The WHO 2024 Global Tuberculosis Report indicates that India +was the country with the highest number of cases of tuberculosis in the world in 2023, with 26% of an estimated global incidence of +approximately 10.8 million cases. +7 +On +March 19, 2020, we announced that CoSara received authorization to manufacture and sell COVID-19 tests in India. Those tests in India +are branded as SaraGene COVID-19 tests and are sold exclusively by CoSara. The Indian government places restrictions on the price that +could be charged for COVID-19 tests which limited the revenue in India more than we experienced in other parts of the world. At the time +of this report, CoSara has received CDSCO clearance for RT-PCR tests for Mycobacterium tuberculosis, malaria, hepatitis B, hepatitis +C (including viral load tests for both hepatitis B and C), human papillomavirus (HPV), a test for high-risk HPV, two COVID-19 assays, +chikungunya, dengue, a dengue/chikungunya duplex test, an influenza A/influenza B/COVID-19 (“ABC”) multiplex test, and in +2024 CDSCO cleared the manufacture and sell SARAPLEX™ Influenza Multiplex (IFM) Test Kit to clinical laboratories as an in vitro +diagnostic for the detection and differentiation of Influenza A and Influenza B. +Europe +Molecular +diagnostics, such as our tests, are governed in Europe by the framework for IVDs, which encompasses diagnostic products such as reagents, +instruments and systems intended for use in diagnosis of disease. The regulatory system for some IVDs historically allowed for a self-certification +procedure, placing heavy responsibility on manufacturers. Non self-certified products were subject to the same standards as self-certified +products but were also subject to audit and review by a notified body prior to receiving approval to receiving CE marking. A CE-marking +is a manufacturer’s declaration that a product meets the requirements of the applicable European Commission (EC) directive. Examples +of current obligations include having in place a qualitative manufacturing process, user instructions that are clear and fit for purpose, +and ensuring that the ‘physical’ features of devices and diagnostics do not pose any danger. If a product fulfils these and +other related control requirements, it may bear a CE marking, as an indication that the product is compliant with EU legislation and +sold in the European Union. We have received CE marking for six of our tests including for COVID-19, COVID-19 (2 gene test), ABC (a triplex +test for Flu A, Flu B and COVID-19), a DS (Direct Saliva, extraction-free) COVID-19 test, tuberculosis, Zika, and our Zika, dengue, chikungunya +triplex tests. In May 2022, the EC published the In Vitro Diagnostic Regulation (IVDR), a new regulation that significantly revised the +requirements for CE marking of IVDs. To avoid potential shortages of essential healthcare products, the EC extended the transition deadlines +in 2024. Co-Dx is actively pursuing CE-IVD compliance under IVDR through the Annex IX route to conformity. For manufacturers actively +pursuing IVDR compliance, European regulators have allowed a grace period until 2028 for Class B devices to harmonize their devices and +Quality Management Systems (QMS) with the new regulation. +Co-Diagnostics +PCR tests are manufactured under an ISO 13485:2016 certified quality management system, relating to the design and manufacture of our +medical device products. The ISO certification indicates that we meet the standards required to pursue CE-marking for certain of our +products, subject to the requirements in the updated directive mentioned above. +United +States +Section +801(e) of the Federal Food, Drug, and Cosmetic Act, as amended (the “FDA Act”) covers certain medical devices that have not +yet received an approved Premarket Approval in the United States by the FDA, such as our products. We have not commenced any premarket +approval steps with the FDA for any of our Logix Smart PCR tests. Section 801(e) of the FDA Act applies to medical devices that are acceptable +to the importing country and that are manufactured under the FDA’s Good Manufacturing Practices, and grants Co-Diagnostics permission +to export all of our IVD products. We have received EUA clearance for our Logix Smart COVID-19 test, which allows sales to qualified +labs in the United States and facilitates the registration for sale in other countries as well. Under the FDA’s existing policy, +the FDA continues to review a prioritized subset of COVID-19 tests for EUAs, and emphasizes that traditional device premarket review +pathways remain open to all developers. We intend to pursue all appropriate FDA review pathways for products under development, including +traditional premarket review pathways. +Under +our EUA, we are actively selling our Logix Smart COVID-19 test to overseas customers and to CLIA certified laboratories in the United +States. The CLIA labs are able to use our test, or to further validate our COVID-19 tests (or other tests) as Laboratory Developed Tests +(LDTs), which refers to a diagnostic test that has been validated for use in the CLIA lab. LDTs may be used by the lab only in that laboratory. +CLIA laboratories develop the performance characteristics, perform the analytical validation for their LDTs and obtain licenses to offer +them as diagnostic services. We are currently marketing our Logix Smart COVID-19 test to CLIA laboratories throughout the US. +8 +Market +Opportunity +The +market opportunity for our tests changed radically with the emergence of the COVID-19 pandemic. Because we were able to respond rapidly +and produce a quality product, we have been able to build a worldwide distribution network that +has allowed us to export products throughout the world. We anticipate that our network of distributors that we have built over +the past five years will serve us well in sales and distribution of other diagnostic tests and our forthcoming PCR diagnostic platform. +The +molecular diagnostics market is a fast-growing portion of the in vitro (test tube-based, controlled environment) diagnostics market. +There are several advantages of PCR tests, such as the ones we market and sell, over other forms of diagnostic testing. These advantages +include higher specificity and sensitivity, the ability to perform multiplex tests and the ability to test for drug resistance or for +individual genes. +Mosquito +Vector Control Services +In +response to market demand, in June 2019 we introduced our first Vector Smart ® PCR tests to be used exclusively for mosquito-borne +pathogens in mosquito populations. Municipalities in the US and many other countries in the world are concerned about the diseases carried +by mosquitos, which infect the human population. To prevent outbreaks of potentially harmful viruses such as Zika or West Nile from infecting +the public, many municipalities conduct mitigation operations to eliminate the mosquito populations carrying the diseases. Because it +is too expensive and potentially harmful to the environment to treat all mosquito breeding areas, municipalities may identify and focus +their efforts on particular areas with mosquitos that are carrying the harmful viruses. To know where the host mosquitos with the harmful +viruses are located, traps are set, mosquitos collected and then tested. There are over 3,000 mosquito abatement districts throughout +the United States and almost all of them conduct testing to help make the spraying more effective. +Our +first vector related test was a triplex test that tests for West Nile, western equine encephalitis and St. Louis encephalitis. We began +shipping the tests in June 2019. We added a second test that tests mosquitos for Zika, chikungunya and dengue in a triplex test. Finally, +in November 2019, we completed a test for West Nile, eastern equine encephalitis and St. Louis encephalitis, specifically for use in +the eastern United States. As a result, mosquito abatement districts can test for three target viruses in one test as compared to performing +three different tests using other market available tests. Our products also allow municipalities to obtain test results in-house in a +matter of hours, instead of the days or weeks they might otherwise have to wait for a central lab to process the mosquito tests. +We +have sold our Vector Smart™ test products and/or related lab equipment to testing districts in different sections of the country +and are marketing our products through trade shows, electronic and regular mail solicitations. +9 +Competitive +Advantages of Co-Diagnostics +We +believe that we have the following competitive advantages: +● +Affordability: +Lower-cost test kits, a low-cost Co-Dx Box, and an affordable Co-Dx PCR platform for at-home and point-of-care testing (the +platform is subject to FDA review and not available for sale at the time of this filing). +● +Flexibility: +CODX’s tests have been designed to run on many customers’ DNA/RNA diagnostic testing machines. Our technology +is well suited to the new generation of point-of-care testing (POCT), compact and portable analysis machinery for field, clinical +and office applications. +● +Speed : +We believe our rapid assay design system software provides shorter time to product release. This has been demonstrated with the +conception, design, product manufacture, clinical verification and submission for a CE marking for our Logix Smart COVID-19 test +(under the previous directive) being approximately 30 days. +● +Accuracy : +We believe our technology allows us to build tests that are highly sensitive and specific, the two benchmarks for accuracy in PCR +testing. +● +Personalized +Medicine : We project that rising health care costs in developed and developing nations will increasingly require that health +care systems be patient-specific to eliminate waste, misdiagnoses, and ineffectiveness. A critical component will be accurate, more +affordable molecular diagnostics, especially in at-home and POCT settings, for which we are developing products. +● +Low-Cost +Provider : Our platform technology obviates the need to pay certain patent royalties typically required of our competitors, +which use third-party patented test platforms to design and manufacture their tests. +● +Worldwide +Footprint : With a dynamic technology that encompasses markets worldwide, we anticipate that we can identify the best target +markets, not only in low-to-middle income countries but also in developed nations. +● +Data +Collection : With the anticipated deployment of the Co-Dx PCR platform we expect to play a role in centralizing global data +collection on infectious diseases that may contribute to faster vaccination and therapeutic responses from health authorities. +● +Growth +Industry Category : We believe that real-time PCR testing is the fastest-growing segment of in vitro diagnostic testing. +● +Combination +Product Offering : Our tests can be a well-designed match for a new generation of compact and other small POCT devices now +entering the market, including our own Co-Dx Box and Co-Dx PCR Pro instrument. Used together, we believe these affordable tests and +devices have the potential to revolutionize the molecular diagnostics industry in cost, speed of test results and simplification. +● +Multiplexing: +Our existing multiplexed tests demonstrate that our Co-Primers-designed tests are able to test for multiple targets in the +same sample without the distortion caused by false negatives and false positives that often occur in multiplexed tests. +10 +Intellectual +Property +Much +of our future success and value depends on our proprietary technology, and therefore, our patent and intellectual property strategy is +of critical importance. Currently, our flagship Co-Primers technology is covered by two U.S. patents titled “Cooperative primers, +probes, and applications thereof” as well as by granted and pending foreign counterparts. We have another three U.S. patents directed +to our earlier work in primer and assay designs. For more recent works, we have filed international and U.S. patent applications directed +to “Methods and Compositions for Next Generation Sequencing (NGS) Library Preparation,” “Allele-Specific Design of +Cooperative Primers for Improved Nucleic Acid Variant Genotyping,” “Methods and Compositions Related to Cooperative Primers +and Reverse Transcription,” and “Systems, Methods, and Apparatus for Automated Self-Contained Biological Analysis” +which is the basis of our at-home and point-of-care PCR platform. We intend to continue building our patent portfolio as development +continues and resources are available. +We +also protect some of our technology and know-how as trade secrets and, where appropriate, we use and register trademarks to protect and +strengthen our products and proprietary brands. All trademarks, trade/product names, graphics and logos of Co-Diagnostics contained herein +are trademarks of Co-Diagnostics or its subsidiary, as applicable, in the U.S. and/or other countries. Solely for convenience, we may +refer to trademarks in this Annual Report on Form 10-K without the ™ or ® symbols, but such references are not intended to +indicate, in any way, that we will not assert, to the fullest extent permitted by law, our rights to our trademarks. +Major +Customers +The +Company had certain customers which were each responsible for generating 10% or more of the total revenue for the years ended December +31, 2024 and 2023, respectively. One customer accounted for approximately 31% of product revenue for the year ended December 31, 2024 +and two customers accounted for approximately 27% of product revenue for the year ended December 31, 2023. Two granting agencies accounted +for approximately 95% of grant revenue for the year ended December 31, 2024, and one granting agency accounted for 100% of grant revenue +for the year ended December 31, 2023. These customers and granting agencies may not account for the same percentage of product revenue +or grant revenue in future periods. If we were to sell +nothing to those customers in the future, it would have a material adverse effect on our financial condition unless we were able to replace +those customers with others. +Competition +The molecular diagnostics industry is extremely competitive. There are +many firms that provide some or all of the products we provide and provide many diagnostic tests that we have yet to develop. Many of +these competitors are larger than us and have significantly greater financial resources. Many of our competitors have a competitive advantage +in the diagnostic testing industry because they also have other lines of business in the diagnostics, pharmaceutical, or biotech industries +from which they derive revenues and for which they are well known and respected in the medical profession. Many of these competitors already +have an established customer base with industry standard technology, which we must overcome to be successful. In the diagnostic testing +and POCT industries, we compete with such companies as BioMerieux, Siemens, Qiagen, Roche Diagnostics and Cepheid and with such pharmaceutical +companies as Abbott Laboratories, Becton Dickinson and Johnson and Johnson. We also compete with companies from Asia in certain markets +who are willing to sell their tests for much less than we sell our tests, which creates competitive price pressure on us in certain regions, +particularly Asia and Latin America. +11 +We +expect competition to continue to increase as other established and emerging companies enter the market, as customer requirements evolve, +and as new products, services and technologies are introduced. Some of our existing or new competitors may have strong relationships +with current and potential customers, including governmental authorities, and, as a result, may be able to respond more quickly to new +or changing regulatory requirements, new or emerging technologies, and changes in customer requirements. +Government +Regulation +In +the United States, we are regulated by the FDA and our products must be approved, cleared, or authorized by the FDA before we are allowed +to sell our tests in the United States as in vitro diagnostics. The FDA granted us an EUA to manufacture and sell our Logix Smart +COVID-19 test to CLIA labs in the United States. The Company operates under an ISO 13485:2016 certified quality management system, relating +to the design and manufacture of our medical device products. Being ISO certified greatly facilitates our applications for regulatory +clearance, including CE marking, which allows us to sell any tests in most countries in Europe, South America and Asia, depending on +the country and following that country’s registration process. We currently have CE markings issued for our Logix Smart COVID-19 +test, tuberculosis test, our Zika virus test, a triplex test that tests for Zika, dengue, and chikungunya simultaneously, a triplex “ABC” +test that identifies and distinguishes between Flu A, Flu B and Covid-19, our SARS-CoV-2 2-gene multiplex test, and our DS (Direct Saliva, +extraction-free) COVID-19 test. In addition, our Logix Smart COVID-19 has received the required license to manufacture and sell in India +from India’s CDSCO, and The National Epidemiology Institute in Mexico evaluated our Logix Smart COVID-19 and ABC tests and approved +them for sale in Mexico. We have also received clearance to sell our Logix Smart COVID-19 test in Australia. +Employees +As +of December 31, 2024, we had 132 full-time and part-time employees at our executive offices and lab facilities in Salt Lake City, Utah. +We have engaged independent contractors to promote the use of our products and develop outlets for products and employ the services of +independent sales representatives on an “as needed” basis. +We +consider our people and the way we work to support each other and serve our customers to be critical to our success. The key human capital +measures and objectives that we focus on in managing our business are: maintaining a strong and collaborative company culture, increasing +our diversity, inclusion and belonging, offering fair and competitive compensation and benefits, investing in people and organizational +development, protecting and enriching employee health and wellness, and sustaining a culture of respectful and effective communications. +Organizational +History and Corporate Information +We +were incorporated as Co-Diagnostics, Inc., in Utah on April 18, 2013. Our principal executive office is located at 2401 S. Foothill Drive, +Salt Lake City, Utah 84109. Our telephone number is (801) 438-1036. Our web address is www.codiagnostics.com . The contents of +our website are not incorporated by reference in this Annual Report. +12 +ITEM +1A. RISK FACTORS +Risks +Related to Our Business and Industry +We +have limited commercial history upon which to base our prospects and are not certain that we will achieve profitability in the future. +We +have a limited operating history. We began operations in April 2013. Our accumulated retained earnings (deficit) were ($33.0 million) +and $4.6 million as of December 31, 2024 and 2023, respectively. We do not have any way of predicting when or if we will achieve profitability +in the future. Potential investors should be aware of the difficulties normally encountered by early commercial stage companies, many +of which are beyond our control, including substantial risks and expenses in the course of developing new diagnostic tests, obtaining +regulatory approval of clearance to commercialize such tests, establishing or entering new markets, organizing operations and marketing +procedures. The likelihood of our success must be considered in light of these risks, expenses, complications and delays, and the competitive +environment in which we operate. There is, therefore, nothing at this time upon which to base an assumption that our business plan will +prove successful, and we may not be able to generate significant revenue, raise additional capital or operate profitably. We will continue +to encounter risks and difficulties frequently experienced by early commercial stage companies, including scaling up our infrastructure +and headcount, and may encounter unforeseen expenses, difficulties or delays in connection with our growth. In addition, as a result +of the start-up nature of our business, we expect to continue to sustain substantial operating expenses and may not be able to continue +generating sufficient revenues to cover expenditures. Any investment in our company is therefore highly speculative and could result +in the loss of any investment. +Our +future success is dependent on our development of our Co-Dx PCR platform and securing regulatory approval for the platform including +the PCR Pro instrument and related diagnostic tests, demand for infectious disease diagnostics and upon our ability to develop and market +other commercially accepted diagnostic tests for our PCR platform. +Our +future success will depend, in part, on our development of our Co-Dx PCR platform and securing regulatory approval for the platform including +the PCR Pro instrument and related diagnostic tests, our ability to develop and sell sufficient quantities of other diagnostics tests, +and our ability to successfully and profitably market our Co-Dx PCR platform. Attracting new customers and distribution networks requires +substantial time and expense. Any failure to obtain regulatory approval for our product candidates and to increase sales of our diagnostic +tests in sufficient quantities to achieve profitability in a timely manner would adversely affect our operating results. Many factors +could affect the market acceptance and commercial success of any of our diagnostic tests and devices, including: +● +Our +ability to develop additional infectious disease diagnostic tests for which there is a commercial market; +● +Our +ability to obtain regulatory clearance to commercialize our product candidates; +● +our +ability to convince our potential customers of the advantages and economic value of our tests over competing technologies and diagnostic +tests; +● +the +breadth of our test menu relative to competitors; +● +changes +to policies, procedures or currently accepted best practices in clinical diagnostic testing; +● +the +extent and success of our marketing and sales efforts; and +● +our +ability to manufacture in quantity our commercial diagnostic tests and meet demand in a timely fashion. +13 +The +diagnostic market is highly competitive, and we may not be able to compete effectively against the larger, well-established companies +that dominate this market or emerging and small innovative companies that may seek to obtain or increase their share of the market. +The +markets for diagnostic products are intensely competitive, and many of our competitors are much larger and have substantially more financial +and human resources than we do. Many have long histories and strong reputations within the industry, and a relatively small number of +companies dominate these markets. +These +companies enjoy significant competitive advantages over us, including: +● +broad +product offerings, which address the needs of health care providers in a wide range of applications; +● +products +that are supported by long-term clinical data; +● +greater +experience in, and resources for, launching, marketing, distributing and selling products, including strong sales forces and established +distribution networks; +● +extensive +intellectual property portfolios and greater resources for patent protection; +● +greater +financial and other resources for product research and development; +● +greater +experience in obtaining and maintaining FDA and other regulatory clearances and approvals for products and product enhancements; +● +established +manufacturing operations and contract manufacturing relationships; +● +significantly +greater name recognition and widely recognized trademarks; and +● +established +relationships with healthcare providers and payers. +Our +products and any product candidates that we may introduce into the market may not enable us to overcome the competitive advantages of +these large and dominant companies. In addition, even if we successfully introduce additional product candidates into the market, emerging +and small innovative companies may seek to increase their market share and they may eventually possess competitive advantages, which +could adversely impact our business. Our competitors may also employ pricing strategies that could adversely affect the pricing of our +products. +We +depend on a limited number of third-party suppliers for key raw materials used in the manufacturing of our products, and the loss of +these third-party suppliers or their inability to supply us with adequate raw materials could harm our business. +We +rely on a limited number of third-party suppliers for the raw materials required for the production of our diagnostic products and product +candidates. Our dependence on a limited number of third-party suppliers involves several risks, including limited control over pricing, +availability, quality, and delivery schedules for raw materials. We have no supply agreements in place with any of our suppliers and +cannot be certain that our current suppliers will continue to provide us with the quantities of raw materials that we require or that +satisfy our anticipated specifications and quality requirements. Any supply interruption in limited or single sourced raw materials could +materially harm our ability to manufacture our products until a new source of supply, if any, could be identified and qualified. We may +be unable to find a sufficient alternative supply channel within a reasonable time or on commercially reasonable terms. Any performance +failure on the part of our suppliers could delay the production of our products and product candidates and delay the development and +commercialization of our product candidates, including limiting supplies necessary for commercial sale, clinical trials and regulatory +approvals, which could have a material adverse effect on our business. +In +order to be successful, we must expand our available product lines by commercializing new product candidates, but we may not be able +to do so in a timely fashion and at expected costs, or at all. +Although +we are currently manufacturing diagnostic kits for commercialization, in order to be successful, we will need to expand our product lines +to include other diagnostic products. To succeed in our commercialization efforts, we must effectively continue product development and +testing, find new strategic partners, obtain regulatory clearances and approvals, and enhance our sales and marketing capabilities. Because +of these uncertainties, there is no assurance that we will succeed in bringing any of our current or future product candidates to market. +If we fail in bringing our product candidates to market, or experience delays in doing so, we will not generate revenues as planned and +will need to curtail operations or seek additional financing earlier than otherwise anticipated. +We +are dependent on our senior management team, scientific team, and external advisors, and the loss of any of them could harm our business, +including by adversely affecting our ability to effectuate our business strategy. +The +members of our current senior management team may not be able to successfully implement our strategy. In addition, we have not entered +into employment agreements with any of the members of our senior management team. There are no assurances that the services of any of +these individuals will be available to us for any specified period of time. The successful integration of our senior management team, +the loss of members of our senior management team, scientific team and key external advisors, or our inability to attract or retain other +qualified personnel or advisors could have a material adverse effect on our business, financial condition and results of operations. +We may not have a sufficient number of qualified personnel to effectuate our business strategy, which could have a material adverse effect +on our business, financial condition and results of operations. +14 +If +we experience significant disruptions in our information technology systems, our business, results of operations and financial condition +could be adversely affected. +The +efficient operation of our business depends on our information technology systems. We rely on our information technology systems to effectively +manage our sales and marketing, accounting and financial functions; manufacturing processes; inventory; scientific and product development +functions; and our research and development functions. As such, our information technology systems are vulnerable to damage or interruption +including from earthquakes, fires, floods and other natural disasters; terrorist attacks and attacks by computer viruses or hackers; +power losses; and computer systems, or Internet, telecommunications or data network failures. The failure of our information technology +systems to perform as we anticipate or our failure to effectively implement new systems could disrupt our entire operation and could +result in decreased sales, increased overhead costs, excess inventory and product shortages, all of which could have a material adverse +effect on our reputation, business, results of operations and financial condition. +Cybersecurity +risks and the failure to maintain the integrity of company, employee or customer data could expose us to data loss, litigation and liability, +and our reputation could be significantly harmed. +We +and third-party service providers collect and retain large volumes of data, including personally identifiable information regarding clinical +trial participants and others, for business purposes, including for regulatory, research and development and commercialization purposes, +and our collaborators’ various information technology systems enter, process, summarize and report such data. We also maintain +personally identifiable information about our employees. The integrity and protection of our company, employee and clinical data is critical +to our business. We are subject to significant data security and privacy laws and regulations. These regulations impose significant requirements +on how we maintain, use, and protect such information. Maintaining compliance with these evolving regulations and requirements could +be difficult and may increase our expenses. In addition, a penetrated or compromised data system or the intentional, inadvertent or negligent +release or disclosure of data could result in theft, loss or fraudulent or unlawful use of company, employee or clinical data which could +harm our reputation, disrupt our operations, or result in remedial and other costs, fines or lawsuits. +Risks +Related to Our Capital Resources and Impairments +We +will require additional financing and our failure to obtain additional funding would force us to delay, reduce or eliminate our product +development programs or commercialization efforts. +We +currently have limited committed sources of capital, and we have limited liquidity. Our cash, cash equivalents, and marketable investment +securities as of December 31, 2024 were $29.7 million. We have entered into an Equity Distribution Agreement (the “ATM Agreement”) +with Piper Sandler & Co. (“Piper Sandler”), pursuant to which we may offer and sell shares of our common stock having +an aggregate offering price of up to $17,111,650 from time to time through Piper Sandler acting as our agent, under our prospectus supplement +dated October 18, 2024. As of December 31, 2024, we have sold 314,707 shares of common stock under the ATM Agreement resulting in net +proceeds to the Company of $0.2 million. We will require substantial future capital in order to continue operating our business, conduct +the research and development and regulatory clearance and approval activities necessary to bring our products to market, and to establish +effective marketing and sales capabilities. +If +adequate funds to develop our product candidates and fund operations are not available on a timely basis, we may terminate or delay the +development of one or more of our product candidates, or delay activities necessary to commercialize our product candidates. Additional +funding may not be available to us on acceptable terms, or at all. Any additional equity financing, if available, may not be available +on favorable terms and will most likely be dilutive to our current stockholders, and debt financing, if available, may involve more restrictive +covenants. Our ability to access capital when needed is not assured and, if not achieved on a timely basis, will materially harm our +business, financial condition and results of operations or could cause us to cease operations. +15 +Our +independent registered public accounting firm has included an explanatory paragraph relating to our ability to continue as a going concern +in its report on our audited financial statements. We may be unable to continue to operate without the threat of liquidation for the +foreseeable future. +Our +report from our independent registered public accounting firm for the year ended December 31, 2024 includes an explanatory paragraph +stating that our recurring losses from operations raises substantial doubt about our ability to continue as a going concern. If we are +unable to obtain sufficient additional funding, our business, prospects, financial condition and results of operations will be materially +and adversely affected, and we may be unable to continue as a going concern. If we are unable to continue as a going concern, we may +have to liquidate our assets and may receive less than the value at which those assets are carried on our consolidated financial statements, +and it is likely that investors will lose all or a part of their investment. Future reports from our independent registered public accounting +firm may also contain statements expressing doubt about our ability to continue as a going concern. If we seek additional financing to +fund our business activities in the future and there remains doubt about our ability to continue as a going concern, investors or other +financing sources may be unwilling to provide additional funding on commercially reasonable terms or at all. +Raising +additional capital by issuing securities or through debt financings or licensing arrangements will likely cause dilution to existing +stockholders, restrict our operations or require us to relinquish proprietary rights. +To +the extent that we raise additional capital through the sale of equity or convertible debt securities, your ownership interest will likely +be diluted, and the terms may include liquidation or other preferences that adversely affect your rights as a stockholder. Debt financing, +if available, may involve agreements that include covenants limiting or restricting our ability to take specific actions such as incurring +additional debt, making capital expenditures or declaring dividends. If we raise additional funds through collaboration and licensing +arrangements with third parties, we may have to relinquish valuable rights to our technologies or products or grant licenses on terms +that are not favorable to us. Any of these events could adversely affect our ability to achieve our product development and commercialization +goals and have a material adverse effect on our business, financial condition and results of operations. +Risks +Related to Regulatory Approval of Our Products and Other Government Regulations +We +received Emergency Use Authorization or EUA for our Logix Smart COVID-19 test in the US. For our existing EUA and any new EUA, the FDA +may revoke any EUA where it is determined that the underlying health emergency no longer exists or warrants such authorization, which +would adversely impact our ability to market our COVID-19 test in the United States. +The +FDA has the authority to grant an EUA to allow unapproved medical products to be used in an emergency to diagnose, treat or prevent serious +or life-threatening diseases or conditions when there are no adequate, approved and available alternatives. During the COVID 19 pandemic +the FDA determined that circumstances exist to justify the authorization of emergency use of medical devices, including alternative products +used as medical devices, during the COVID-19 pandemic. On April 3, 2020, we received an EUA from the FDA for our Logix Smart Coronavirus +Disease 2019 (COVID-19) kit for use on individuals who are suspected of COVID-19 by their healthcare provider. We +cannot predict how long the EUA for our COVID-19 test will remain in place. The FDA may revoke an EUA where it is determined that +the underlying health emergency no longer exists or warrants such authorization. The FDA may take such a position at any time and without +notice and, therefore, we cannot predict how long our EUAs will remain in place. The FDA may also revoke an EUA when the circumstances +justifying its issuance no longer exist, such as when an alternative is authorized for marketing through the standard procedures, including +through a 510(k) clearance. +If +our existing EUAs are revoked prior to us having received regulatory approval to commercialize our COVID-19 test through a traditional +pathway, we may not be able to obtain required clearances or approvals in a timely manner, or at all, and one or more of our competitors +may obtain the necessary clearances or approvals for their products before we do. In addition, we would be required to cease our commercialization +efforts, which would substantially and negatively impact our business. As a result, any such revocation could adversely impact our business, +financial condition and results of operations. +16 +In +June 2024, we filed a 510(k) application with the FDA for our PCR platform which we withdrew in February 2025 as a result of discussions +with the FDA. Our long-term success depends substantially on our ability to obtain regulatory clearance or approval and thereafter commercialize +our product candidates; we cannot be certain that we will be able to do so in a timely manner or at all. +In +June 2024, we filed a 510(k) application with the FDA for our PCR platform which we withdrew in February 2025 as a result of discussions +with the FDA. The process of obtaining regulatory clearances or approvals to market a medical diagnostic from the FDA or similar regulatory +authorities outside of the United States can be costly and time consuming, and there can be no assurance that such clearances or approvals +will be granted on a timely basis, or at all. The FDA’s 510(k) clearance process generally takes one to six months from the date +of submission, depending on whether a special or traditional 510(k) premarket notification has been submitted, but can take significantly +longer. An application for premarket approval, or PMA, must be submitted to the FDA if the device cannot be cleared through the 510(k) +clearance process or is not exempt from premarket review by the FDA. The PMA process almost always requires one or more clinical trials +and can take two to three years from the date of filing, or even longer. +If +we are required to obtain approval of any of our products through the PMA process, the costs associated with such a process will be significant, +which could adversely affect our financial performance and results of operations. In addition, a submission through the PMA process would +require us to delay commercialization of such product candidates until after approval is received, if ever. If we are unable to commercialize +our product candidates in a timely manner, or at all, our business will be adversely affected. +Similar +to our compliance with U.S. regulatory requirements, we must obtain and comply with international requirements, in order to market and +sell our products outside of the United States and we may only promote and market our products, if approved, as permitted by applicable +regulatory authorities. There is no guarantee that we will receive the necessary regulatory approvals for our product candidates either +inside the United States or internationally. If our product candidates do not receive necessary regulatory approvals, our business could +be materially and adversely affected. +Our +current and future relationships with third-party payers and current and potential customers in the United States and elsewhere may be +subject, directly or indirectly, to applicable anti-kickback, fraud and abuse, false claims, transparency, health information privacy +and security and other healthcare laws and regulations, which could expose us to criminal sanctions, civil penalties, contractual damages, +reputational harm administrative burdens and diminished profits and future earnings. +Our +current and future arrangements with third-party payers and current and potential customers, including providers and physicians, may +expose us to broadly applicable fraud and abuse and other healthcare laws and regulations, including, without limitation, the federal +Anti-Kickback Statute and the federal False Claims Act, which may constrain the business or financial arrangements and relationships +through which we sell, market and distribute our products. In addition, we may be subject to transparency laws and patient privacy regulations +by U.S. federal and state governments and by governments in foreign jurisdictions in which we conduct our business. The applicable federal, +state and foreign healthcare laws and regulations that may affect our ability to operate include: +● +the +federal Anti-Kickback Statute, which prohibits, among other things, persons from knowingly and willfully soliciting, offering, receiving +or providing remuneration, directly or indirectly, in cash or in kind, to induce or reward, or in return for, either the referral +of an individual for, or the purchase, order or recommendation of, any good or service, for which payment may be made under federal +healthcare programs, such as Medicare and Medicaid; +● +federal +civil and criminal false claims laws and civil monetary penalty laws, including the federal False Claims Act, which impose criminal +and civil penalties, including civil whistleblower or qui tam actions, against individuals or entities for knowingly presenting, +or causing to be presented, to the federal government, including the Medicare and Medicaid programs, claims for payment that are +false or fraudulent or making a false statement to avoid, decrease or conceal an obligation to pay money to the federal government; +● +the +federal Health Insurance Portability and Accountability Act of 1996, or HIPAA, which imposes criminal and civil liability for executing +a scheme to defraud any healthcare benefit program or making false statements relating to healthcare matters; +● +HIPAA, +as amended by the Health Information Technology for Economic and Clinical Health Act of 2009, or HITECH, and their respective implementing +regulations, which impose obligations on covered healthcare providers, health plans, and healthcare clearinghouses, as well as their +business associates that create, receive, maintain or transmit individually identifiable health information for or on behalf of a +covered entity, with respect to safeguarding the privacy, security and transmission of individually identifiable health information; +● +the +Physician Payments Sunshine Act, which requires (i) manufacturers of drugs, devices, biologics and medical supplies for which payment +is available under Medicare, Medicaid or the Children’s Health Insurance Program, with specific exceptions, to report annually +to CMS information related to certain “payments or other transfers of value” made to physicians, which is defined to +include doctors, dentists, optometrists, podiatrists and chiropractors, and teaching hospitals, (ii) applicable manufacturers and +applicable group purchasing organizations to report annually to CMS ownership and investment interests held in such entities by physicians +and their immediate family members, with data collection beginning on August 1, 2013, (iii) manufacturers to submit reports to CMS +by the 90 th day of each calendar year, and (iv) disclosure of such information by CMS on a publicly available website; +and +● +analogous +state and foreign laws and regulations, such as state anti-kickback and false claims laws, which may apply to sales or marketing +arrangements and claims involving healthcare items or services reimbursed by non-governmental third-party payers, including private +insurers; state and foreign laws that require medical device companies to comply with the medical device industry’s voluntary +compliance guidelines and the relevant compliance guidance promulgated by the federal government or otherwise restrict payments that +may be made to healthcare providers; state and foreign laws that require medical device manufacturers to report information related +to payments and other transfers of value to physicians and other healthcare providers or marketing expenditures; and state and foreign +laws governing the privacy and security of health information in certain circumstances, many of which differ from each other in significant +ways and often are not preempted by HIPAA, thus complicating compliance efforts. +17 +Efforts +to ensure that our business arrangements with third parties will comply with applicable healthcare laws and regulations may involve substantial +costs. It is possible that governmental authorities will conclude that our business practices may not comply with current or future statutes, +regulations or case law involving applicable fraud and abuse or other healthcare laws and regulations. If our operations are found to +be in violation of any of these laws or any other governmental regulations that may apply to us, we may be subject to significant civil, +criminal and administrative penalties, including, without limitation, damages, fines, imprisonment, exclusion from participation in government +healthcare programs, such as Medicare and Medicaid, and the curtailment or restructuring of our operations, which could have a material +adverse effect on our business. If any of the physicians or other healthcare providers or entities with whom we expect to do business, +including our collaborators, are found not to be in compliance with applicable laws, they may be subject to criminal, civil or administrative +sanctions, including exclusions from participation in government healthcare programs, which could also materially affect our business. +We +are subject to stringent and changing data protection laws, privacy policies and data protection obligations, which continue to evolve +and change over time. The actual or perceived failure by us or our third-party service providers or vendors to comply with such obligations +could harm our reputation, subject us to significant fines and liability, or otherwise adversely affect our business. +We +are subject to numerous data protection laws that govern the processing of individually identifiable information and health information +and other sensitive and personal information in the jurisdictions in which we operate. In many instances, these data protection laws, +regulations and standards apply not only to disclosures to third parties, but also to transfers of information between or among us and +other parties with which we have commercial relationships. The regulatory framework for data privacy, data security and data transfers +worldwide is rapidly evolving and, as a result, interpretation and implementation standards and enforcement practices are likely to remain +uncertain for the foreseeable future. These data protection laws may be interpreted and applied differently over time and from jurisdiction +to jurisdiction, and it is possible that they will be interpreted and applied in ways that will materially and adversely affect our business, +financial condition and results of operations. Failure to comply with any of these data protection laws could result in enforcement actions +against us, including fines, imprisonment of company officials and public censure, claims for damages by affected individuals, damage +to our reputation and loss of goodwill, any of which could have a material adverse effect on our business. +There +are numerous U.S. federal and state laws and regulations related to the privacy and security of personal information. These laws and +regulations include the Health Insurance Portability and Accountability Act of 1996, or HIPAA, as amended by the Health Information Technology +for Economic and Clinical Health Act of 2009, or HITECH, and their implementing regulations, or collectively referred to as the HIPAA +Rules, which establish a set of national privacy and security standards to safeguard Protected Health Information, or PHI, by health +plans, healthcare clearinghouses and certain healthcare providers, referred to as covered entities, and the business associates and their +subcontractors with whom such covered entities contract for services that involve the creation, receipt, maintenance or transmission +of PHI for or on behalf of a covered entity or another business associate. HIPAA requires covered entities and business associates to, +among other things, develop and maintain policies and procedures with respect to PHI that is used or disclosed, including the adoption +of administrative, physical and technical safeguards to protect such information and ensure the confidentiality, integrity and availability +of electronic PHI. As this applies to our business, we are required to maintain security standards for any PHI that we create, receive, +maintain or transmit. For example, we plan to offer cloud-based portal software to help our customers more efficiently use our products. +The software will maintain security safeguards that are designed to be consistent with the HIPAA Rules, but we cannot guarantee that +these safeguards will not fail or that they will not be deemed inadequate in the future. In addition, we could be subject to periodic +audits for compliance with the HIPAA Privacy and Security Standards by the U.S. HHS, and our customers. The U.S. HHS Office for Civil +Rights may impose significant penalties on entities subject to HIPAA for a failure to comply with a requirement of the HIPAA Rules. If +we are unable to properly protect the privacy and security of the PHI of our customers, we could be found to have breached our contracts. +Determining whether PHI has been handled in compliance with applicable privacy standards and our contractual obligations can be complex +and we cannot be sure how these regulations will be interpreted, enforced or applied to our operations. +In +addition, many states in which we operate have laws that protect the privacy and security of sensitive and personal information, including +health-related information. Certain state laws may be more stringent or broader in scope, or offer greater individual rights, with respect +to sensitive and personal information than federal, international or other state laws, and such laws may differ from each other, which +may complicate compliance efforts. +18 +Laws, +regulations and standards in many other jurisdictions also apply broadly to the Processing of personal information, which impose significant +compliance obligations. Complying with these numerous, complex and often changing regulations is expensive and difficult, and failure +to comply with any Data Protection Laws or any security incident or breach involving the misappropriation, loss or other unauthorized +use or disclosure of sensitive or confidential information, whether by us, one of our service providers or another third party, could +negatively affect our business, financial condition and results of operations, including but not limited to: investigation costs, material +fines and penalties; compensatory, special, punitive and statutory damages; litigation; consent orders regarding our privacy and security +practices; requirements that we provide notices, credit monitoring services or credit restoration services or other relevant services +to impacted individuals; adverse actions against our licenses to do business; and injunctive relief. +Many +statutory requirements, both in the United States and abroad, include obligations for companies to notify individuals of security breaches +involving certain personal information, which could result from breaches experienced by us or our third-party service providers. For +example, laws in all 50 U.S. states and the District of Columbia require businesses to provide notice to consumers whose unencrypted +personal information has been disclosed as a result of a data breach. These laws are not consistent, and compliance in the event of a +widespread data breach is difficult and may be costly. Moreover, states have been frequently amending existing laws, requiring attention +to changing regulatory requirements. We also may be contractually required to notify affected customers, regulators, credit reporting +agencies or other affected individuals of a security breach. Such notifications are costly, and the disclosures or the failure to comply +with such requirements, could lead to material adverse effects, including without limitation, negative publicity, a loss of customer +confidence in our services or security measures or breach of contract claims. There can be no assurance that the limitations of liability +in our contracts would be enforceable or adequate or would otherwise protect us from liabilities or damages if we fail to comply with +applicable Data Protection Laws, Data Protection Obligations or other legal obligations. In addition, although we may have contractual +protections with our third-party service providers, contractors and consultants, any actual or perceived security breach by our subcontractors +could harm our reputation and brand, expose us to potential liability or require us to expend significant resources on data security +and in responding to any such actual or perceived breach. Any contractual protections we may have from our third-party service providers, +contractors or consultants may not be sufficient to adequately protect us from any such liabilities and losses, and we may be unable +to enforce any such contractual protections. +We +expect that there will continue to be new proposed laws and regulations concerning data privacy and security, and we cannot yet determine +the impact such future laws, regulations and standards may have on our business. New laws, amendments to or re-interpretations of existing +laws, regulations, standards and other obligations may require us to incur additional costs and restrict our business operations. Because +the interpretation and application of health-related and Data Protection Laws and other obligations are still uncertain, and often contradictory +and in flux, it is possible that the scope and requirements of these laws may be interpreted and applied in a manner that is inconsistent +with our practices and our efforts to comply with the evolving data protection rules may be unsuccessful. If so, this could result in +government-imposed fines or orders requiring that we change our practices, which could adversely affect our business. +We +cannot assure you that our third-party partners and service providers with access to our or our customers’, suppliers’ and +employees’ personally identifiable and other sensitive or confidential information in relation to which we are responsible will +not breach contractual obligations imposed by us or violate Data Protection Laws, or that they will not experience security breaches +or attempts thereof, which could have a corresponding effect on our business, including putting us in breach of our obligations under +the Data Protection Laws, which could in turn adversely affect our business, results of operations and financial condition. We cannot +assure you that our contractual measures and our own privacy- and security-related safeguards will protect us from the risks associated +with the third-party processing, storage and transmission of such information. +We +may receive inquiries or be subject to investigations, proceedings or actions, by various government entities regarding our privacy and +information security practices and Processing (“Regulatory Proceedings”). These Regulatory Proceedings could result in a +material adverse effect, including without limitation, interruptions of, or required changes to, our business practices, the diversion +resources and the attention of management from our business, regulatory oversights and audits, discontinuance of necessary Processing, +or other remedies that adversely affect our business. +19 +In +addition to the possibility of fines, lawsuits, regulatory investigations, public censure, other claims and penalties, and significant +costs for remediation and damage to our reputation, we could be materially and adversely affected if legislation or regulations are expanded +to require changes in our data processing practices and policies or if governing jurisdictions interpret or implement their legislation +or regulations in ways that negatively impact our business. Complying with these various laws could cause us to incur substantial costs +or require us to change our business practices and compliance procedures in a manner adverse to our business. Any inability to adequately +address data privacy or security-related concerns, even if unfounded, or to comply with applicable laws, regulations, standards and other +obligations relating to data privacy and security, could result in additional cost and liability to us, harm our reputation and brand, +damage our relationships with customers and have a material and adverse impact on our business. +While +we maintain general liability insurance coverage, cyber insurance coverage and other insurance, we cannot assure that such coverage will +be adequate or otherwise protect us from or adequately mitigate liabilities or damages with respect to claims, costs, expenses, litigation, +fines, penalties, business loss, data loss, regulatory actions or material adverse effects arising out of our privacy and security practices, +Processing or security breaches we may experience, or that such coverage will continue to be available on acceptable terms or at all. +The successful assertion of one or more large claims against us that exceeds our available insurance coverage, or results in changes +to our insurance policies (including premium increases or the imposition of large deductible or co-insurance requirements), could have +an adverse effect on our business. In addition, we cannot be sure that our existing insurance coverage will continue to be available +on acceptable terms or that our insurers will not deny coverage as to any future claim. +We +may incur substantial costs in our efforts to comply with evolving global data protection laws and regulations, and any failure or perceived +failure by us to comply with such laws and regulations may harm our business and operations. +The +global data protection landscape is rapidly evolving, and we may be or become subject to or affected by numerous federal, state and foreign +laws and regulations, as well as regulatory guidance, governing the collection, use, disclosure, transfer, security and processing of +personal data, such as information that we collect about subjects and health care providers in connection with clinical trials. Implementation +standards and enforcement practices are likely to remain uncertain for the foreseeable future, which may create uncertainty in our business; +affect our or our service providers’ ability to operate in certain jurisdictions or to collect, store, transfer use and share personal +data; result in liability; or impose additional compliance or other costs on us. Any failure or perceived failure by us to comply with +federal, state, or foreign laws or self-regulatory standards could result in negative publicity, diversion of management time and effort +and proceedings against us by governmental entities or others. +In +the United States, numerous federal and state laws and regulations, including federal health information privacy laws (e.g., the Health +Insurance Portability and Accountability Act, as amended by the Health Information Technology for Economic and Clinical Health Act, or +collectively HIPAA), state data breach notification laws, state health information privacy laws, and federal and state consumer protection +laws (e.g., Section 5 of the Federal Trade Commission Act), that govern the collection, use, disclosure and protection of health-related +and other personal information could apply to our operations or the operations of our collaborators. In addition, we may obtain health +information from third parties (including research institutions from which we obtain clinical trial data) that are subject to privacy +and security requirements under HIPAA or other privacy and data security laws. Depending on the facts and circumstances, we could be +subject to criminal penalties if we knowingly obtain, use, or disclose protected health information maintained by a HIPAA-covered entity +in a manner that is not authorized or permitted by HIPAA. However, determining whether protected health information has been handled +in compliance with applicable privacy standards and our contractual obligations can be complex and may be subject to changing interpretation. +If +we are unable to properly protect the privacy and security of protected health information or other personal, sensitive, or confidential +information in our possession, we could be found to have breached our contracts. Further, if we fail to comply with applicable privacy +laws, including applicable HIPAA privacy and security standards, we could face significant administrative, civil and criminal penalties. +Enforcement activity can also result in financial liability and reputational harm, and responses to such enforcement activity can consume +significant internal and outside resources. Furthermore, state attorneys general are authorized to bring civil actions seeking either +injunctions or damages in response to violations that threaten the privacy of state residents. In addition, our ongoing efforts to comply +with evolving laws and regulations at the federal and state level may be costly and require continuous modifications to our compliance +policies, procedures, and systems. +20 +Many +state laws govern the privacy and security of personal information and data in specified circumstances, many of which differ from each +other in significant ways, are often not pre-empted by HIPAA, and may have a more prohibitive effect than HIPAA, thus complicating compliance +efforts. For example, the California Consumer Privacy Act of 2018 (the “CCPA”), which went into effect in January 2020 and +provides new data privacy rights for consumers and new operational requirements for companies, which may increase our compliance costs +and potential liability. The CCPA gives California residents expanded rights to access and delete their personal information, opt out +of certain personal information sharing, and receive detailed information about how their personal information is used. The CCPA provides +for civil penalties for violations, as well as a private right of action for data breaches that is expected to increase data breach litigation. +While there is currently an exception for protected health information that is subject to HIPAA and clinical trial regulations, as currently +written, the CCPA may impact certain of our business activities. In addition, the California Consumer Rights Act, or CPRA, was recently +enacted to strengthen elements of the CCPA and became effective on January 1, 2023. The CPRA imposes additional data protection obligations +on covered businesses, including additional consumer rights processes, limitations on data uses, new audit requirements for higher risk +data, and opt outs for certain uses of sensitive data and expands the application of the CCPA to all human resources personal information +of California-based employees. In addition, the CPRA created a new California data protection agency authorized to issue substantive +regulations and is expected to result in increased privacy and information security enforcement. A number of other states have considered +similar privacy proposals, and states have recently enacted their own privacy laws. For example, the Virginia Consumer Data Protection +Act became effective on January 1, 2023, and Colorado and Utah enacted similar laws that became effective in 2023, increasing the complexity +of compliance and the risk of failures to comply. These privacy laws may impact our business activities and exemplify the vulnerability +of our business to the evolving regulatory environment related to personal data. +In +addition to our operations in the United States, which may be subject to health care and other laws relating to the privacy and security +of health information and other personal information, we may be or become subject to European data privacy laws, regulations and guidelines. +The General Data Protection Regulation, (EU) 2016/679 (“GDPR”) became effective on May 25, 2018, and deals with the collection, +use, storage, disclosure, transfer, or other processing of personal data, including personal health data, regarding individuals in the +EEA. The GDPR imposes a broad range of strict requirements on companies subject to the GDPR, including requirements relating to having +legal bases for processing personal information relating to identifiable individuals and transferring such information outside the EEA, +including to the United States, providing details to those individuals regarding the processing of their personal health and other sensitive +data, obtaining consent of the individuals to whom the personal data relates, keeping personal information secure, having data processing +agreements with third parties who process personal information, responding to individuals’ requests to exercise their rights in +respect of their personal information, reporting security breaches involving personal data to the competent national data protection +authority and affected individuals, appointing data protection officers, conducting data protection impact assessments, and record-keeping. +The GDPR increases substantially the penalties to which we could be subject in the event of any non-compliance, including fines of up +to €10,000,000 or up to 2% of our total worldwide annual turnover for certain comparatively minor offenses, or up to €20,000,000 +or up to 4% of our total worldwide annual turnover, whichever is greater, for more serious offenses. The GDPR also confers a private +right of action on data subjects and consumer associations to lodge complaints with supervisory authorities, seek judicial remedies, +and obtain compensation for damages resulting from violations of the GDPR. In addition, the GDPR includes restrictions on cross-border +data transfers. +Following +the United Kingdom’s withdrawal from the European Union (i.e., Brexit), and the expiry of the Brexit transition period, which ended +on December 31, 2020, the EU GDPR has been implemented in the United Kingdom (as the UK GDPR). The UK GDPR sits alongside the UK Data +Protection Act 2018 which implements certain derogations in the EU GDPR into UK law. Under the UK GDPR, companies not established in +the UK but who process personal data in relation to the offering of goods or services to individuals in the UK, or to monitor their behavior +will be subject to the UK GDPR – the requirements of which are (at this time) largely aligned with those under the EU GDPR and +as such, may lead to similar compliance and operational costs with potential fines of up to £17.5 million or 4% of global turnover. +In 2022, the government of the United Kingdom proposed and debated the Data Protection and Digital Information Bill to harmonize the +2018 Data Protection Act, UK GDPR, and the Privacy and Electronic Communications Regulations under one legislative framework. However, +progress on the bill stalled as the government continues to assess the most optimal approach to data protection reform. +21 +We +currently sell some of our products in the EEA, and the GDPR increases our responsibility and liability in relation to personal data +that we process where such processing is subject to the GDPR, and we are required to have in place additional mechanisms and safeguards +to ensure compliance with the GDPR, including as implemented by individual countries. Compliance with the GDPR is a rigorous and time-intensive +process that increase our cost of doing business or require us to change our business practices, and despite those efforts, there is +a risk that we may be subject to fines and penalties, litigation, and reputational harm in connection with our European activities. We +expect that we will continue to face uncertainty as to whether our efforts to comply with any obligations under European privacy laws +will be sufficient. If we are investigated by a European data protection authority, we may face fines and other penalties. Any such investigation +or charges by European data protection authorities could have a negative effect on our existing business and on our ability to attract +and retain new clients or partners. +Risks +Related to Our Intellectual Property +If +the combination of patents, trade secrets and contractual provisions that we rely on to protect our intellectual property is inadequate, +our ability to commercialize our products successfully will be harmed, and we may not be able to operate our business profitably. +Our +success depends significantly on our ability to protect our proprietary rights to the technologies incorporated in our products. We rely +on a combination of patent protection, trade secret laws and nondisclosure, confidentiality and other contractual restrictions to protect +our proprietary technology. However, these may not adequately protect our rights or permit us to gain or keep any competitive advantage. +The +issuance of a patent is not conclusive as to its scope, validity or enforceability. The scope, validity or enforceability of our issued +patents can be challenged in litigation or proceedings before the U.S. Patent and Trademark Office, or the USPTO, or foreign patent offices. +In addition, our pending patent applications include claims to numerous important aspects of our products under development that are +not currently protected by any of our issued patents. We cannot assure you that any of our pending patent applications will result in +the issuance of patents to us. The USPTO or foreign patent offices may deny or require significant narrowing of claims in our pending +patent applications. Patents issued as a result of the pending patent applications, if any, may not provide us with significant commercial +protection or be issued in a form that is advantageous to us. Proceedings before the USPTO or foreign patent offices could result in +adverse decisions as to the priority of our inventions and the narrowing or invalidation of claims in issued patents. The laws of some +foreign countries may not protect our intellectual property rights to the same extent as the laws of the United States, if at all. +Our +competitors may successfully challenge and invalidate or render unenforceable our issued patents, including any patents that may issue +in the future, which could prevent or limit our ability to market our products and could limit our ability to stop competitors from marketing +products that are substantially equivalent to ours. In addition, competitors may be able to design around our patents or develop products +that provide outcomes that are comparable to our products but that are not covered by our patents. +In +the event a competitor infringes upon any of our patents or other intellectual property rights, enforcing our rights may be difficult, +time-consuming and expensive, and would divert management’s attention from managing our business. There can be no assurance that +we will be successful on the merits in any enforcement effort. In addition, we may not have sufficient resources to litigate, enforce +or defend our intellectual property rights. +We +could become subject to intellectual property litigation that could be costly, result in the diversion of management’s time and +efforts, require us to pay damages, prevent us from marketing our commercially available products or product candidates and/or reduce +the margins we may realize from our products that we may commercialize. +Whether +a product infringes a patent involves complex legal and factual issues, and the determination is often uncertain. There may be existing +patents of which we are unaware that our products under development may inadvertently infringe. The likelihood that patent infringement +claims may be brought against us increases as the number of participants in the in vitro diagnostics market increases and as we +achieve more visibility in the marketplace and introduce products to market. +Any +infringement claim against us, even if without merit, may cause us to incur substantial costs, and would place a significant strain on +our financial resources, divert the attention of management from our core business, and harm our reputation. In some cases, litigation +may be threatened or brought by a patent holding company or other adverse patent owner who has no relevant product revenues and against +whom our patents may provide little or no deterrence. If we were found to infringe any patents, we could be required to pay substantial +damages, including triple damages if an infringement is found to be willful, and royalties and could be prevented from selling our products +unless we obtain a license or are able to redesign our products to avoid infringement. We may not be able to obtain a license enabling +us to sell our products on reasonable terms, or at all, and there can be no assurance that we would be able to redesign our products +in a way that would not infringe those patents. If we fail to obtain any required licenses or make any necessary changes to our technologies +or the products that incorporate them, we may be unable to commercialize one or more of our products or may have to withdraw products +from the market, all of which would have a material adverse effect on our business, financial condition and results of operations. +22 +We +rely substantially on our trademarks and trade names. If our trademarks and trade names are not adequately protected, then we may not +be able to build name recognition in our markets of interest and our business may be harmed. +We +rely substantially upon trademarks to build and maintain the integrity of our brand. Our registered and unregistered trademarks or trade +names may be challenged, infringed, circumvented, declared unenforceable or determined to be violating or infringing on other intellectual +property rights. We may not be able to protect or enforce our rights to these trademarks and trade names, which we rely upon to build +name recognition among potential partners and customers in our markets of interest. At times, competitors or other third parties may +adopt trade names or trademarks similar to ours, thereby impeding our ability to build brand identity and possibly leading to market +confusion. Asserting claims against such third parties may be prohibitively expensive. In addition, there could be potential trade name +or trademark infringement, or dilution claims brought by owners of other trademarks against us. Over the long term, if we are unable +to establish name recognition based on our trademarks and trade names, then we may not be able to compete effectively, and our business +may be adversely affected. Our efforts to enforce or protect our proprietary rights related to trademarks, trade secrets, domain names +or other intellectual property may be ineffective, could result in substantial costs and diversion of resources and could harm our business, +financial condition and results of operations. +Risks +Related to Litigation from Operating Our Business +Current +or future litigation, government investigations and other legal proceedings may harm our business. +We +have been, currently are and may in the future become, involved in legal proceedings that could have a negative impact on our reputation, +business and financial condition and divert the attention of our management from the operation of our business. The types of legal proceedings +we may be or become subject to include patent and other intellectual property claims, product liability claims, employee claims, tort +or contract claims, federal or state regulatory investigations, securities class actions and shareholder derivative actions, and other +legal proceedings, investigations or claims. For example, we are currently parties to two securities class action claims and three derivative +actions. Litigation and other legal proceedings are inherently unpredictable and can result in excessive or unanticipated verdicts and/or +injunctive relief that affect how we operate our business. We obtain business insurance, including executive and corporate securities +liability insurance to insure against such claims should they arise. The insurance we have in place for such events may prove to be inadequate +to pay a damage award, we may have to pay the excess of this award out of our cash reserves, which could significantly harm our financial +condition. A legal proceeding claim, even one without merit, could harm our reputation in the industry, lead to significant legal fees, +and result in the diversion of management’s attention from managing our business. We could incur judgments or enter into settlements +of claims for monetary damages or for agreements to change the way we operate our business, or both. There may be an increase in the +scope of these matters or there may be additional lawsuits, claims, proceedings or investigations in the future, which could harm our +business, financial condition and results of operations. Adverse publicity about regulatory or legal action against us could damage our +reputation and brand image, undermine our customers’ confidence and reduce long-term demand for any of our products or other offerings, +even if the regulatory or legal action is unfounded or not material to our operations. For additional information, see “Item 3. +Legal Proceedings.” +23 +General +Risk Factors +The +price of our common stock may fluctuate substantially. +The +market price of our common stock may be subject to wide fluctuation in response to various factors, some of which are beyond our control. +Some factors that may cause the market price of our common stock to fluctuate, in addition to the other risks mentioned in this “Risk +Factors” section and elsewhere in this report, are: +● +sales +or purchases of our common stock by our shareholders, executives, and directors; +● +our +ability to obtain regulatory approval to commercialize our PCR platform on a timely basis or at all; +● +our +ability to enter new markets; +● +actual +or unanticipated fluctuations in our annual and quarterly financial results; +● +our +ability to obtain financings to continue and expand our commercial activities, expand our manufacturing operations, conduct research +and development activities including, but not limited to, human clinical trials, and other business activities; +● +our +ability to secure resources and the necessary personnel to continue and expand our commercial activities, develop additional diagnostic +tests, conduct clinical trials and gain approval for our diagnostic tests on our desired schedule; +● +commencement, +enrollment or results of our clinical trials of our diagnostic tests or any future clinical trials we may conduct; +● +changes +in the development status of our diagnostic tests; +● +any +delays or adverse developments or perceived adverse developments with respect to review by the FDA or other similar foreign regulatory +authorities of our planned clinical trials; +● +any +delay in our submission for studies or test approvals or adverse regulatory decisions, including failure to receive regulatory approval +or clearance for our diagnostic tests; +● +our +announcements or our competitors’ announcements regarding new tests, enhancements, significant contracts, acquisitions or strategic +investments; +● +failures +to meet external expectations or management guidance; +● +changes +in our capital structure or dividend policy, including future issuances of securities and sales of large blocks of common stock by +our shareholders; +● +announcements +and events surrounding financing efforts, including debt and equity securities; +● +competition +from existing technologies and diagnostic tests or new technologies and diagnostic tests that may emerge; +● +announcements +of acquisitions, partnerships, collaborations, joint ventures, new diagnostic tests, capital commitments, or other events by us or +our competitors; +● +changes +in general economic, political and market conditions in any of the regions in which we conduct our business; +● +changes +in industry conditions or perceptions; +● +changes +in valuations of similar companies or groups of companies; +● +analyst +research reports, recommendations and changes in recommendations, price targets and withdrawals of coverage; +● +departures +and additions of key personnel; +● +disputes +and litigations related to intellectual properties, proprietary rights, and contractual obligations; +● +changes +in applicable laws, rules, regulations, or accounting practices and other dynamics; +● +other +events or factors, many of which may be out of our control. +In +addition, if the market for stocks in our industry or industries related to our industry, or the stock market in general, experiences +a loss of investor confidence, the trading price of our common stock could decline for reasons unrelated to our business, financial condition +and results of operations. If any of the foregoing occurs, it could cause our stock price to fall and may expose us to lawsuits that, +even if unsuccessful, could be costly to defend and a distraction to management. +24 +Anti-takeover +provisions in our charter documents and Utah law could discourage, delay, or prevent a change of control of our Company and may affect +the trading price of our common stock. +We +are a Utah corporation and the anti-takeover provisions of the Utah Control Shares Acquisition Act may discourage, delay or prevent a +change of control by limiting the voting rights of control shares acquired in a control share acquisition. In addition, our Articles +of Incorporation and Bylaws may discourage, delay or prevent a change in our management or control over us that shareholders may consider +favorable. Among other things, our Amended and Restated Articles of Incorporation and Bylaws: +● +authorize +the issuance of “blank check” preferred stock that could be issued by our board of directors in response to a takeover +attempt; +● +provide +that vacancies on our board of directors, including newly created directorships, may be filled only by a majority vote of directors +then in office, except a vacancy occurring by reason of the removal of a director without cause shall be filled by vote of the shareholders; +● +no +right to cumulative voting; +● +limit +who may call special meetings of shareholders +These +provisions could have the effect of delaying or preventing a change of control, whether or not it is desired by, or beneficial to, our +shareholders. +We +do not currently intend to pay dividends on our common stock. +We +do not expect to pay cash dividends on our common stock. Any future dividend payments are within the absolute discretion of our board +of directors and will depend on, among other things, our results of operations, working capital requirements, capital expenditure requirements, +financial condition, contractual restrictions, business opportunities, anticipated cash needs, provisions of applicable law and other +factors that our board of directors may deem relevant. We may not generate sufficient cash from operations in the future to pay dividends +on our common stock. +We +are a “smaller reporting company” and the reduced disclosure requirements applicable to smaller reporting companies may make +our common stock less attractive to investors. +We +are currently a “smaller reporting company” as defined in the Securities Exchange Act of 1934. Smaller reporting companies +are able to provide simplified executive compensation disclosures in their filings, and have certain other decreased disclosure obligations +in their SEC filings, including, among other things, only being required to provide two years of audited financial statements in annual +reports. We cannot predict whether investors will find our common stock less attractive because of our reliance on any of these exemptions. +If some investors find our common stock less attractive as a result, there may be a less active trading market for our common stock and +our stock price may be more volatile. +We +incur substantial costs as a result of being a public company and our management expects to devote substantial time to public company +compliance programs. +As +a public company, we incur significant legal, insurance, accounting and other expenses, including costs associated with public company +reporting. We intend to invest resources to comply with evolving laws, regulations and standards, and this investment will result in +increased general and administrative expenses and may divert management’s time and attention from product development and commercialization +activities. If our efforts to comply with new laws, regulations and standards differ from the activities intended by regulatory or governing +bodies due to ambiguities related to practice, regulatory authorities may initiate legal proceedings against us, and our business may +be harmed. These laws and regulations could make it more difficult and costlier for us to obtain director and officer liability insurance +for our directors and officers, and we may be required to accept reduced coverage or incur substantially higher costs to obtain coverage. +These factors could also make it more difficult for us to attract and retain qualified executive officers and qualified members of our +board of directors, particularly to serve on our audit and compensation committees. In addition, if we are unable to continue to meet +the legal, regulatory and other requirements related to being a public company, we may not be able to maintain the listing of our common +stock on The NASDAQ Capital Market, which would likely have a material adverse effect on the trading price of our common stock. +We +incur substantial costs as a result of being a public company and are subject to the continued listing requirements of the NASDAQ Capital +Market, our management expects to devote substantial time to public company compliance programs. +As +a public company, we incur significant legal, insurance, accounting and other expenses, including costs associated with public company +reporting. We intend to invest resources to comply with evolving laws, regulations and standards, and this investment will result in +increased general and administrative expenses and may divert management’s time and attention from product development and commercialization +activities. If our efforts to comply with new laws, regulations and standards differ from the activities intended by regulatory or governing +bodies due to ambiguities related to practice, regulatory authorities may initiate legal proceedings against us, and our business may +be harmed. These laws and regulations could make it more difficult and costlier for us to obtain director and officer liability insurance +for our directors and officers, and we may be required to accept reduced coverage or incur substantially higher costs to obtain coverage. +These factors could also make it more difficult for us to attract and retain qualified executive officers and qualified members of our +board of directors, particularly to serve on our audit and compensation committees. In addition, if we are unable to continue to meet +the legal, regulatory and other requirements related to being a public company, we may not be able to maintain the listing of our common +stock on The NASDAQ Capital Market, which would likely have a material adverse effect on the trading price of our common stock. +Currently +our common stock is quoted on the NASDAQ Capital Market under the symbol “CODX”. We must satisfy certain minimum listing +maintenance requirements to maintain the NASDAQ Capital Market quotation, including certain governance requirements and a series of financial +tests relating to stockholders’ equity or net income or market value, public float, number of market makers and stockholders, market +capitalization, and maintaining a minimum bid price of $1.00 per share. +On +January 10, 2025, we received a notice from the Listing Qualifications Department of The NASDAQ Stock Market (the “Staff”) +stating that the bid price of our common stock for the previous 30 consecutive trading days had closed below the minimum $1.00 per share +required for continued listing on The NASDAQ Capital Market under NASDAQ Listing Rule 5550(a)(2). The Company has a period of 180 calendar +days, or until July 9, 2025 (the “Compliance Date”) to regain compliance with Listing Rule 5550(a)(2). To regain compliance, +the bid price of the Company’s common stock must close at $1 or more for a minimum of ten consecutive business days before the +Compliance Date. +If +the Company does not regain compliance with Rule 5550(a)(2) by July 9, 2025, the Company may be eligible for additional time. To qualify, +the Company will be required to meet the continued listing requirement for market value of publicly held shares and all other initial +listing standards for The Nasdaq Capital Market, with the exception of the bid price requirement, and will need to provide written notice +of its intention to cure the deficiency during the second compliance period, by effecting a reverse stock split, if necessary. If the +Company meets these requirements, the Staff will inform the Company that it has been granted an additional 180 calendar days. However, +if it appears to the Staff that the Company will not be able to cure the deficiency, or if the Company is otherwise not eligible, the +Staff will provide notice that its securities will be subject to delisting. We intend to actively monitor our bid price and will consider +available options to resolve the deficiency and regain compliance with the Nasdaq Listing Rules. +If +Nasdaq delists our common stock from trading on its exchange and we are not able to list our securities on another national securities +exchange, we expect our securities could be quoted on an over-the-counter market. If this were to occur, we could face significant material +adverse consequences, including: +● +a +limited availability of market quotations for our securities; +● +reduced +liquidity for our securities; +● +a +determination that our common stock is a “penny stock” which will require brokers trading in our common stock to adhere +to more stringent rules and possibly result in a reduced level of trading activity in the secondary trading market for our securities; +● +a +limited amount of news and analyst coverage; and +● +a +decreased ability to issue additional securities or obtain additional financing in the future. +ITEM +1B. UNRESOLVED STAFF COMMENTS +None. +25 +ITEM +1C. CYBERSECURITY +We +understand the importance of preventing, identifying, assessing and managing material risks associated with cybersecurity threats. Cybersecurity +processes to identify, assess and manage risks from cybersecurity threats have been incorporated as a part of our overall risk assessment +process and are designed to help protect our information assets and operations from internal and external cyber threats and protect employee +and customer information from unauthorized access or attack, as well as secure our network and systems. The Company’s cybersecurity +policies, standards, processes, and practices are based on recognized frameworks established by the National Institute of Standards and +Technology (“NIST”) and are included in the Company’s overall risk management system and processes. We have implemented +into our operations these cybersecurity processes, technologies and controls to identify, assess and manage material risks. Specifically, +we engage a third-party cybersecurity firm to assist with network and endpoint monitoring, cloud system monitoring and assessment of +our incident response procedures. Further, we employ periodic internal and external penetration testing by an independent cybersecurity +firm to inform our risk identification and assessment of critical, high, medium and minor material cybersecurity threats. +To +manage our material risks from cybersecurity threats and to protect against, detect, and prepare to respond to cybersecurity incidents, +we undertake the below listed activities: +● +Monitor +evolving cybersecurity standards and emerging data protection laws and implement changes to our processes to comply; +● +risk +assessments designed to help identify material cybersecurity risks to our critical systems, information, products, services, and +our broader enterprise IT environment; +● +The +Company leverages third-party vendors to house critical clinical trial data. These vendors are required to be GxP compliant which +entails strong cybersecurity controls that are validated by a third-party auditor. Furthermore, the Company has begun performing +security risk assessments prior to on-boarding new significant vendors. +● +The +Company provides regular, mandatory training for all levels of employees regarding cybersecurity threats as a means to equip the +Company’s employees with effective tools to address cybersecurity threats, and to communicate the Company’s evolving +information security policies, standards, processes, and practices. +● +Employ +multifactor authentication on internal and external systems; +● +Conduct +regular phishing email simulations for all employees; and +● +Carry +cybersecurity risk insurance that provides protection against the potential losses arising from a cybersecurity incident. +Our +incident response plan coordinates the activities that we and our third-party cybersecurity providers take to prepare to respond and +recover from cybersecurity incidents, which include processes to triage, assess severity, investigate, escalate, contain, and remediate +an incident, as well as to comply with potentially applicable legal obligations and mitigate brand and reputational damage. +As +part of the above processes, we engage with subject matter expert consultants to review our cybersecurity program to help identify areas +for continued focus, improvement, and compliance. +Our +processes also include assessing cybersecurity threat risks associated with our use of third-party services providers in normal course +of business use, including those in our supply chain or who have access to patient and employee data or our systems. Third-party risks +are included within our risk management process discussed above. In addition, we assess cybersecurity considerations in the selection +and oversight of our third-party services providers, including due diligence on the third parties that have access to our systems and +facilities that house systems and data. +We +do not believe that there are currently any known risks from cybersecurity threats that are reasonably likely to materially affect our +business strategy, results of operations or financial condition. However, cybersecurity threats may affect our business. See “ Cyber +security risks and the failure to maintain the integrity of company, employee or guest data could expose us to data loss, litigation +and liability, and our reputation could be significantly harmed. ” in “Item 1A. Risk Factors” of this Annual +Report on Form 10-K. +The +Audit Committee of the Board of Directors is responsible for oversight of our cybersecurity risk assessment, risk management, incident +response procedures and cybersecurity risks and provides updates to the Board of Directors regarding such oversight. Periodically during +each year, the Audit Committee receives an overview from our Vice President, Head of Technology of our cybersecurity threat risk management +and strategy processes, including potential impact on us, the efforts of management to manage the risks that are identified and our incident +response preparations. +Our +cybersecurity risk assessment, management and strategy processes are led by our Chief Technology Officer. Our Chief Technology Officer +has over 15 years of experience in various roles involving managing information security, managing privacy and data protection, developing +cybersecurity strategy, and implementing cybersecurity programs. The Chief Technology Officer was recently promoted and is training to +be a Certified Information Security Manager (CISM) , is informed about and monitors the prevention, mitigation, detection, and remediation +of cybersecurity incidents through management of the cybersecurity risk management and strategy processes described above, including +our incident response plan. +26 +ITEM +2. PROPERTIES +Our +headquarters are located at 2401 S. Foothill Drive, Salt Lake City, Utah. Our current facilities have approximately 54,000 square feet +of laboratory, manufacturing, storage and office space under leases that expire in 2026 through 2028. We believe the facilities we lease +are sufficient to meet our needs for the foreseeable future. +ITEM +3. LEGAL PROCEEDINGS +In +the ordinary course of business, we are at times subject to various legal proceedings and disputes, including the proceedings specifically +discussed below. We assess our liabilities and contingencies in connection with outstanding legal proceedings utilizing the latest information +available. Where it is probable that we will incur a loss and the amount of the loss can be reasonably estimated, we record a liability +in our consolidated financial statements. These legal reserves may be increased or decreased to reflect any relevant developments on +a quarterly basis. Where a loss is not probable or the amount of loss is not estimable, we do not accrue legal reserves. While the outcome +of legal proceedings is inherently uncertain, based on information currently available and available insurance coverage, our management +believes that it has established appropriate legal reserves. Any incremental liabilities arising from pending legal proceedings are not +expected to have a material adverse effect on our consolidated financial position, consolidated results of operations, or consolidated +cash flows. However, it is possible that the ultimate resolution of these matters, if unfavorable, may be material to our consolidated +financial position, consolidated results of operations, or consolidated cash flows. +Class +Actions and Shareholder Derivative Suits +Gelt +Securities Class Action (District of Utah) +On +June 15, 2020, Gelt Trading Co. (“Gelt”) filed a lawsuit in the United States District Court for the District of Utah (“District +of Utah”), against the Company and certain of our directors and officers, on behalf of itself and a putative class, seeking to +recover damages for alleged violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 (“Gelt Litigation”). +The complaint alleges that Co-Diagnostics and the individual defendants overstated the accuracy of the Company’s Logix Smart COVID-19 +test in statements on April 30, 2020 and May 1, 2020, and that plaintiff suffered losses when the Company’s stock price dropped +after public reports questioned the accuracy of the Logix Smart test on May 14, 2020. On July 15, 2020, plaintiff filed an amended complaint. +On March 10, 2021, the court appointed Gelt as Lead Plaintiff, and on April 7, 2021, Lead Plaintiff filed a second amended complaint +(“SAC”), which asserts the same Sections 10(b) and 20(a) claims against the same defendants on largely the same theory. On +May 5, 2021, the defendants moved to dismiss the SAC. On March 9, 2022, the court entered a Decision & Order denying the motion to +dismiss, but narrowing the challenged statements to only those made in the May 1, 2020 press release, and on April 13, 2022, the defendants +filed an answer to the SAC. On October 17, 2022, Gelt filed a motion to certify the putative class, and on August 18, 2023, the court +partially granted that motion, certifying a class of all those who purchased Co-Diagnostics securities between May 1, 2020 and May 14, +2020, dates inclusive, and who were damaged thereby. Fact and expert discovery are now closed, and the parties’ cross-motions for +summary judgment and to exclude certain expert testimony are now fully briefed. The court held oral argument on those motions on February +21, 2025. On March 4, 2025 a judgment was issued granting the Company’s motion for summary judgment and denying Lead Plaintiff’s +motion for partial summary judgment. +Shareholder +Derivative Lawsuits (District of Utah & Utah State Court) +On +September 17, 2020, a shareholder derivative lawsuit was filed in the District of Utah by Luis Aguilera, allegedly on behalf of Co-Diagnostics, +Inc., that substantially piggybacks on the Gelt Litigation referenced above. The lawsuit asserts that the defendants failed to prevent +the alleged securities law violations largely asserted in the Gelt Litigation. On December 2, 2020, a second shareholder derivative lawsuit +was filed in the District of Utah by Melvyn Klein asserting essentially the same claims, allegedly on behalf of Co-Diagnostics, as the +Aguilera shareholder derivative action. And on April 29, 2021, the District of Utah consolidated the two shareholder derivative cases, +with the Aguilera case serving as the lead case under the caption In re Co-Diagnostics, Inc. Derivative Litigation . On May 3, +2022, plaintiffs filed an amended complaint asserting claims for breach of fiduciary duty, unjust enrichment, and contribution under +Sections 10(b) and 21D of the Securities Exchange Act of 1934. Defendants answered the amended complaint on June 24, 2022. On January +25, 2024, the consolidated Aguilera derivative action was voluntarily dismissed without prejudice. +On +November 24, 2020, an additional shareholder derivative lawsuit was filed in the District of Utah by Matthew Wallace, allegedly on behalf +of Co-Diagnostics, Inc., that also piggybacks on the Gelt Litigation referenced above. It named the same defendants and asserted essentially +the same claims, allegedly on behalf of Co-Diagnostics, as in the other District of Utah shareholder derivative actions referenced above. +On January 25, 2021, another shareholder derivative lawsuit was filed in the District of Utah by Jason Reagan, asserting essentially +the same claims as in the Wallace lawsuit. On March 18, 2021, the court consolidated the two lawsuits, with the Wallace lawsuit serving +as the lead case. On April 30, 2021, plaintiffs filed an amended complaint asserting claims for breach of fiduciary duty against defendants +and claims for insider trading. On January 26, 2024, the court ordered the parties’ proposed revised case schedule, setting fact +and expert discovery deadlines throughout 2024 and early 2025; dispositive motions are due June 1, 2025, but no trial date has yet been +set. +27 +On +March 29, 2021, an additional shareholder derivative lawsuit was filed in the Third District Court in and for Salt Lake County, State +of Utah (“Utah State Court”) by Hua Ding, allegedly on behalf of Co-Diagnostics, Inc., that also piggybacks on the Gelt Litigation +referenced above. It names the same defendants and asserts essentially the same claims as in In re Co-Diagnostics, Inc. Derivative +Litigation pending in the District of Utah referenced above. On December 12, 2022, a second shareholder derivative lawsuit was filed +in Utah State Court by Kathryn Matuch asserting essentially the same claims, allegedly on behalf of Co-Diagnostics, as the Ding shareholder +derivative action. +The +defendants believe the claims asserted in all of the shareholder derivative lawsuits referenced above are without merit and intend to +defend vigorously against them, but there can be no assurances as to the outcome. +Stadium +Capital Securities Class Action (Southern District of New York) +On +August 16, 2022, Stadium Capital LLC (“Stadium”) filed a lawsuit in the United States District Court for the Southern District +of New York, against Co-Diagnostics, Inc., and certain of our officers, on behalf of itself and a putative class, seeking to recover +damages for alleged violations of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934. The complaint alleges that Co-Diagnostics +and the individual defendants overstated the demand for the Company’s Logix Smart COVID-19 test in statements on May 12, 2022 and +June 15, 2022, and that plaintiff suffered losses when the Company’s stock price dropped after the Company disclosed its financial +results for the quarter ended June 30, 2022 in a press release on August 11, 2022. On September 19, 2022, a second plaintiff, Drew Lee, +filed a similar complaint in the same court against the same defendants alleging essentially the same claims. On August 9, 2023, the +court consolidated these two securities class actions into the Stadium action and appointed Stadium as lead plaintiff. On September 21, +2023, Stadium filed a consolidated amended complaint, and on October 20, 2023, defendants moved to dismiss. On February 5, 2024, the +Court granted in part and denied in part the defendants’ motion to dismiss, and on April 19, 2024, the Court dismissed an additional +claim. Fact discovery on the remaining claims closed on November 15, 2024, and expert discovery is currently underway. Dispositive motions +are due March 21, 2025, and no trial date has yet been set. The defendants believe the claims are without merit and intend to defend +vigorously against them, but there can be no assurances as to the outcome. +Commercial +Litigation +Co-Diagnostics, +Inc. v. Hukui Technology, Inc., et al. (Third Judicial District Court, Salt Lake County, State of Utah, Civil No. 210902131, filed on +April 21, 2021). +The +Company filed a complaint against Defendants Hukui Technology, Inc., Hukui Tech, Inc., and Hukui Bio Co., Ltd (collectively, “Hukui”) +seeking a declaratory judgment that the Company is not obligated to any of them in any amount. On August 24, 2021, Hukui filed their +Answer and Counterclaim seeking damages on a number of theories, including breach of contract for letter agreements, breach of oral agreement, +promissory estoppel, unjust enrichment, and interference with economic relations. Hukui requested a money judgment against the Company +in an amount to be determined at trial. On September 20, 2021, Hukui filed their Unopposed Motion for Leave to Amend Answer to the Complaint, +Affirmative Defenses, and Counterclaims and, on October 14, 2021, Hukui filed their Amended Answer and Counterclaims seeking damages +on declaratory judgment, as well as breach of contract for letters of authorization, breach of oral agreement, promissory estoppel, unjust +enrichment, and interference with economic relations. In 2022 the parties exchanged their initial disclosures, exchanged written discovery +requests, and conducted a number of depositions on each side that were concluded in January 2023. On June 1, 2023 the Company filed a +Motion for Summary Judgment asking the court for summary judgment on its sole claim for declaratory relief and for summary judgment with +respect to all Hukui counterclaims. On November 7, 2023, the Court issued its decision and granted the Company summary judgment on its +sole claim for declaratory relief and on all Hukui counterclaims. On December 22, 2023, Hukui filed a notice of appeal of the final judgment +in its entirety with the Utah Supreme Court. The Utah Supreme Court subsequently issued an order transferring the case to the Utah Court +of Appeals. Hukui has filed its brief in support of its efforts to overturn the Court’s order granting the Company’s motion +for summary judgment. The Company has filed its reply brief in response to Hukui’s appellant brief. The Utah Court of Appeals has +not ruled on Hukui’s appeal. The Company believes the claims are without merit and intends to defend vigorously against them, but +there can be no assurances as to the outcome. +Co-Diagnostics, +Inc. v. Pantheon International Advisors Ltd. (Third Judicial District Court, Salt Lake County, State of Utah, Civil No. 210902609, filed +on May 14, 2021). +The +Company filed a complaint against Pantheon International Advisors (“Pantheon”) asking the court to declare that the Company +has no ongoing contractual business relationship with Pantheon, no monies owing, nor does Pantheon have any interest, right, title or +claim to any stock issued by the Company or ownership of any kind in the Company. Pantheon was served with a 30-Day Summons on September +9, 2021 to which it failed to respond, and a default judgement against Pantheon International Advisors was entered by the Court on November +28, 2021. The time to appeal from the judgment or seek to vacate the judgment has passed. +After +learning that the Company had initiated suit in Utah, and after learning of Company’s intent to serve it with process of that suit, +on May 24, 2021, Pantheon filed a claim against the Company in the Royal Courts of Justice Group, Queens Bench Division, Claim No. QB-21-002245, +stating that the Company owes Pantheon $2,860,809.79 for alleged breach of contract for failing to make payments purportedly due under +a contract allegedly entered into on October 18, 2018. The Company has filed its response to Pantheon’s claim. The Company is being +represented locally in the UK by Freshfields Bruckhaus Deringer LLP in that matter. The Company intends to vigorously defend against +the UK claims and will seek to the full extent possible to enforce its rights under the Declaratory Judgment already obtained in Utah +but there can be no assurances as to the outcome. +ITEM +4. MINE SAFETY DISCLOSURES +Not +applicable. +28 +PART +II +ITEM +5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER EQUITY SECURITIES +Market +Information +Our +common stock has been quoted on the NASDAQ market under the symbol “CODX” since July 12, 2017. +Holders +As +of March 21, 2025, the last reported sales price reported on NASDAQ for our common stock was $0.46 per share. As of March 21, 2025, we +had approximately 154 record holders of our common stock. The number of record holders was determined from the records of our transfer +agent and does not include beneficial owners of common stock whose shares are held in the names of various security brokers, dealers, +and registered clearing agencies. The transfer agent for our common stock is VStock Transfer LLC located at 18 Lafayette Pl, Woodmere, +New York 11598. +Dividends +We +have never declared or paid any cash dividends on our capital stock. The payment of dividends on our common stock in the future will +depend on our earnings, capital requirements, operating and financial condition and such other factors as our board of directors may +consider appropriate. We currently expect to use all available funds to finance the future development and expansion of our business +and do not anticipate paying dividends on our common stock in the foreseeable future. +Pursuant +to Section 16-10a-640 of the Utah Revised Business Corporation Act, no distribution may be made if, after giving it effect: +(a) +the +corporation would not be able to pay its debts as they become due in the usual course of business; or +(b) +the +corporation’s total assets would be less than the sum of its total liabilities plus, unless the articles of incorporation permit +otherwise, the amount that would be needed, if the corporation were to be dissolved at the time of the distribution, to satisfy the +preferential rights upon dissolution of shareholders whose preferential rights are superior to those receiving the distribution. +Securities +authorized for issuance under equity compensation plans +Information +about our equity compensation plans in Item 12 of Part III of this Annual Report on Form 10-K is incorporated herein by reference. +Recent +Sales of Unregistered Securities +None. +29 +ITEM +6. RESERVED +ITEM +7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULT OF OPERATIONS +The +following management’s discussion and analysis of financial condition and results of operations describes the principal factors +affecting the results of our operations, financial condition, and changes in financial condition. This discussion should be read in conjunction +with the accompanying audited financial statements, and notes thereto, included elsewhere in this report. In addition to historical information, +this Annual Report contains forward-looking statements that involve risks, uncertainties, and assumptions. Our actual results may differ +materially from those anticipated in these forward-looking statements as a result of certain factors, including but not limited to those +set forth under the caption “Item 1A. Risk Factors” in this Annual Report on Form 10-K. +Business +Overview +Co-Diagnostics, +Inc., a Utah corporation (the “Company” or “CODX”), develops, manufactures and sells reagents used for diagnostic +tests that function via the detection and/or analysis of nucleic acid molecules (DNA or RNA), including robust and innovative molecular +tools for detection of infectious diseases. Our diagnostics systems enable dependable, low-cost, molecular testing for organisms and +genetic diseases by automating or simplifying historically complex procedures in both the development and administration of tests. CODX’s +technical advance involves a novel, proprietary approach to PCR test design of primer and probe structure (“Co-Primers ® ”) +that dramatically reduces one of the key vexing issues of PCR amplification: the exponential growth of primer-dimer amplification (false +positives) which adversely interferes with identification of the target DNA/RNA. Using our proprietary test design system and reagents, +we have designed and obtained regulatory approval to sell PCR diagnostic tests for the detection of COVID-19, influenza, tuberculosis, +hepatitis B and C, human papillomavirus, malaria, chikungunya, dengue, and the Zika virus. These initial diagnostic tests are cleared +for use in clinical labs only and not for point-of-care or at-home use. +We +are currently developing a unique, groundbreaking portable diagnostic device and test system designed for point-of-care and at-home use. +The system is comprised of our PCR instrument that we refer to as the Co-Dx™ PCR Pro™ instrument, our patent-pending diagnostic +test cup system and a mobile application to be installed on the user’s mobile device. We refer to the system as the “Co-Dx™ +PCR platform which has been designed to bring affordable, reliable polymerase chain reaction (“PCR”) testing to patients +in point-of-care and at-home settings. The Co-Dx PCR platform is subject to U.S. Food and Drug Administration (“FDA”) review +and is not available for sale at the time of this filing. In June 2024, we completed our first U.S. Food and Drug Administration (FDA) +application for 510(k) clearance for the Co-Dx™ PCR Pro™ instrument, the Co-Dx PCR COVID-19 Test, and the Co-Dx PCR mobile +app for over-the-counter (OTC) use. Following productive engagement with the FDA related to the regulatory submission, the Company withdrew +its 510(k) application. The decision to withdraw the submission was based on discussions with the FDA regarding the ability to detect +a potential deterioration of one component of the test, related to shelf-life stability. Following dialogue with the FDA and exploring +the various courses of action available, we determined that the best long-term solution would be to submit a version of the test that +has been enhanced to address the matter raised in the 510(k) review process. The Company plans to submit the next iteration of the Co-Dx +PCR COVID-19 test for 510(k) OTC clearance, following the collection of clinical evaluation data to support the new test’s performance. +A new submission also allows the Company to incorporate more recent Co-Dx PCR platform developments into the COVID-19 test, which the Company +believes will also help create greater operational and manufacturing efficiencies, such as consolidating manufacturing processes to utilize +the next generation of test kits and instruments across all tests on the at-home and point-of-care Co-Dx PCR platform. There is no guarantee +that our Co-Dx PCR platform will receive the necessary regulatory approvals for commercialization, or that, if regulatory approval is +received, we will be able to successfully commercialize this platform. +Technology +We +believe our proprietary and patented molecular diagnostics technology is paving the way for innovation in disease detection and life +sciences research through our enhanced detection of genetic material. For various reasons, including owning our own platform, we believe +we will be able to accomplish this faster and more economically than some competitors, allowing for significant margins while still positioning +ourselves as a low-cost provider of molecular diagnostics and screening services. For example, we were the first US-based company to +receive a CE-marking for a COVID-19 test in early 2020, as we worked to help slow the spread of the pandemic through our global network +of distributors covering clinical labs in more than 50 countries. Our Logix Smart ® COVID-19 test was designed, developed, submitted +for regulatory approval and ready to be used as an in vitro diagnostic or IVD in countries that accept CE marking for regulatory clearance +in a period of just over 30 days. This is a real-world example of how CODX technology can be used in an evolving epidemic or pandemic +to get diagnostic tools in the hands of medical professionals in a timely manner. It can be similarly used to design a test for mutated +strains of SARS-CoV-2 or other viruses should they not be detectable using currently available tests. +30 +In +addition, continued development has demonstrated the unique properties of our Co-Primers technology that we believe makes it ideally suited +for a variety of applications where specificity is key to optimal results, including multiplexing several targets, enhanced Single Nucleotide +Polymorphism (“SNP”) detection and enrichment for next generation sequencing. +Our +scientists use the complex mathematics of DNA/RNA PCR test design to engineer and optimize PCR tests and to automate algorithms that +rapidly screen millions of possible options to pinpoint the optimum design. The intellectual property we use in our business consists +of the predictive mathematical algorithms and patented molecular structure used in the testing process, which together represent a major +advance in PCR testing systems. CODX technologies are now protected by more than 20 granted or pending US and foreign patents, as well +as certain trade secrets and copyrights. Ownership of our proprietary platform permits us the advantage of avoiding payment of patent +royalties required by other PCR test systems, which may allow the sale of diagnostic PCR tests at a lower price than competitors, while +enabling us to maintain profit margins. +Our +proprietary test design process involves identifying the optimal locations on the target genes for amplification and pairing the locations +with the optimized primer and probe structure to achieve outputs that meet the design input requirements identified from market research. +This is done by following planned and documented processes, procedures and testing. In other words, we use the data resulting from our +tests to verify whether we succeeded in designing what we intended. Verification involves a series of testing that concludes that the +product is ready to proceed to validation in an evaluation either in our laboratory or in an independent laboratory setting using initial +production tests to confirm that the product as designed meets the user needs. +Using +our proprietary test design system and reagents, we have designed and obtained regulatory approval in the European Community and in India +to sell PCR diagnostic tests for the detection of COVID-19, influenza, tuberculosis, hepatitis B and C, human papillomavirus, malaria, +chikungunya, dengue, and the Zika virus. In the United States, we obtained Emergency Use Authorization (“EUA”) for our Logix +Smart ® COVID-19 detection test from the FDA, and we sell that test to qualified labs. +In addition, our COVID-19 detection test and certain of our other suite of COVID-19 products have been cleared for sale in countries +such as the United Kingdom, Australia, India, and Mexico by the regulatory bodies in those countries and have been registered for sale +in many more countries. In connection with the sale of our tests we may sell diagnostic equipment from other manufacturers, including +an OEM’s PCR instrument which we refer to here as the “Co-Dx Box”. +In addition to testing for infectious disease, Co-Primers technology lends +itself to identifying any section of a DNA or RNA strand that describes any type of genetic trait, which creates several significant applications. +We, in conjunction with our customers, have designed and licensed tests that identify genetic traits in plant and animal genomes. We also +have commercialized three multiplexed tests to test mosquitos for the presence of diseases they carry, which enables municipalities to +concentrate their efforts in managing mosquito populations in specific areas where mosquitos carrying deadly viruses are known to breed. +RESULTS +OF OPERATIONS +Results +of Operations for the Years Ended December 31, 2024 and 2023 +The +table below provides a comparison of our operating results for the year ended December 31, 2024 as compared to the year ended December +31, 2023. +Years Ended December 31, +Year Change +2024 +2023 +Change +% +Product revenue +$ 770,048 +$ 991,473 +$ (221,425 ) +-22 % +Grant revenue +3,145,112 +5,820,565 +(2,675,453 ) +-46 % +Total revenue +3,915,160 +6,812,038 +(2,896,878 ) +-43 % +Cost of revenue +999,124 +4,184,949 +(3,185,825 ) +-76 % +Gross profit +2,916,036 +2,627,089 +288,947 +11 % +Operating expenses +Sales and marketing +4,483,339 +6,860,815 +(2,377,476 ) +-35 % +General and administrative +16,157,152 +14,279,441 +1,877,711 +13 % +Research and development +20,979,589 +22,962,593 +(1,983,004 ) +-9 % +Depreciation and amortization +1,377,266 +1,230,474 +146,792 +12 % +Total operating expenses +42,997,346 +45,333,323 +(2,335,977 ) +-5 % +Loss from operations +(40,081,310 ) +(42,706,234 ) +2,624,924 +-6 % +Other income +Interest income, net +1,091,825 +1,161,913 +(70,088 ) +-6 % +Realized gain on investments +870,745 +2,243,059 +(1,372,314 ) +-61 % +Gain (loss) on disposition of assets +8,291 +(2,578 ) +10,869 +-422 % +Gain on remeasurement of acquisition contingencies +714,876 +1,092,581 +(377,705 ) +-35 % +Gain (loss) on equity method investment in joint venture +(186,067 ) +100,703 +(286,770 ) +-285 % +Total other income, net +2,499,670 +4,595,678 +(2,096,008 ) +-46 % +Loss before income taxes +(37,581,640 ) +(38,110,556 ) +528,916 +-1 % +Income tax provision (benefit) +57,368 +(2,777,691 ) +2,835,059 +-102 % +Net loss +$ (37,639,008 ) +$ (35,332,865 ) +$ (2,306,143 ) +7 % +31 +Revenues +For +the year ended December 31, 2024, we generated $3.9 million of revenue compared to revenue of $6.8 million in the year ended December +31, 2023. The decrease in revenue of $2.9 million was primarily due to lower grant revenues, as the majority of revenue for grants previously +awarded was recognized in the prior year. +Cost +of Revenues and Gross Profit +Cost +of revenues decreased by $3.2 million from $4.2 million for the year ended December 31, 2023 to $1.0 million for the year ended December +31, 2024. Included within cost of revenues is a decrease of approximately $0.1 million for the year ended December 31, 2024, and an increase +of approximately $2.8 million for the year ended December 31, 2023, related to reserves against certain raw materials and finished goods +inventories. The initial recording of the reserves for obsolete inventory in the prior year, partially offset by the decrease in revenues +in the current year, resulted in a higher gross margin percentage. +Operating +Expenses +Total +operating expenses were $43.0 million for the year ended December 31, 2024 compared to total operating expenses of $45.3 million for +the year ended December 31, 2023. The decrease in operating expenses was primarily due to decreased stock-based compensation expense, +bad debt expense and expense related to development of and clinical trials for the Co-Dx PCR platform. These decreases were partially +offset by increased personnel related and legal expenses. +Sales +and marketing expenses for the year ended December 31, 2024 were $4.5 million compared to $6.9 million for the year ended December 31, +2023. The decrease of $2.4 million was primarily a result of decreased stock-based compensation expense, tradeshow and travel expenses, +consulting and professional services expenses, and personnel related expenses. +General +and administrative expenses for the year ended December 31, 2024 were $16.2 million compared to $14.3 million for the year ended December +31, 2023. The increase of $1.9 million was primarily due to increased legal expenses, partially offset by decreases in stock-based compensation +expense, bad debt expense, consulting and professional services expense, and insurance expense. +Research +and development expenses for the year ended December 31, 2024 were $21.0 million compared to $23.0 million for the year ended December +31, 2023. The decrease of $2.0 million was primarily a result of decreased expenses related to development of and clinical trials for +the Co-Dx PCR platform and stock-based compensation expense, partially offset by increases in personnel expense and professional services +expense. +Other +Income +Other +income was $2.5 million for the year ended December 31, 2024, compared to other income of $4.6 million for the year ended December 31, +2023. The decrease in other income of $2.1 million was primarily due to a change in the fair value of contingent consideration liabilities, +an increased loss related to the Company’s joint venture investment, and decreased realized gains from investments in marketable +securities. +32 +Net +Loss +We +realized a net loss for the year ended December 31, 2024 of $37.6 million compared to $35.3 million for the year ended December 31, 2023. +The larger net loss of $2.3 million was primarily the result of decreases in grant revenue, changes in the fair value of acquisition +contingencies, and decreases in realized gains from investments in marketable securities, partially offset by a decrease in operating +expenses. Additionally, we recorded income tax expense of $0.1 million during the year ended December 31, 2024, compared to an income +tax benefit of $2.8 million for the year ended December 31, 2023. The primary reason for the change in the provision for income taxes +is a result of the Company now recording a full valuation allowance. +LIQUIDITY +AND CAPITAL RESOURCES +At +December 31, 2024, we had cash and cash equivalents of $2.9 million and marketable investment securities of $26.8 million. We consider +our marketable investment securities an important part of our liquidity and focus such investments in securities that can readily be +converted into cash if needed. Additionally, our total current assets at December 31, 2024, were $32.3 million compared to total current +liabilities of $7.3 million. +Net +cash used in operating activities during the year ended December 31, 2024 was $29.2 million, compared to net cash used in operating activities +of $22.1 million for the year ended December 31, 2023. The increase in cash used in operating activities was primarily due to decreases +in revenue, grant funding, and realized gains on investments, and increases in cash-payable operating expenses. +Net +cash provided by investing activities was $17.1 million for the year ended December 31, 2024, compared to net cash provided by investing +activities of $15.4 million during the year ended December 31, 2023. The increase in cash provided by investing activities is primarily +due to interest and realized gains related to marketable investment securities, as well as the redemption of certain investments as they +matured. +Net +cash provided by financing activities was $0.1 million for the year ended December 31, 2024, compared to $1.4 million of cash used in +financing activities for the year ended December 31, 2023. The cash provided by financing activities during 2024 relates to issuances +of common stock, compared to cash used in financing activities for repurchases of outstanding common shares during 2023. +Since +commencing sales of our Logix Smart COVID-19 test in March 2020, we have used our cash generated from those sales to fund the purchase +of inventories and the development of our Co-Dx PCR Platform, and to pay our operating expenses. +Our +available capital resources may be consumed more rapidly than currently expected and we may need +or want to raise additional financing for strategic opportunities. It is anticipated that the Company will continue to generate +operating losses and use cash in operations in the near term. If needed, we expect additional investment +capital to come from additional issuances of our common stock or other equity based securities with existing and new investors similar +to those that have provided funding in the past. We have entered into an Equity Distribution Agreement (the “ATM Agreement”) +with Piper Sandler & Co. (“Piper Sandler”), pursuant to which we may offer and sell shares of our common stock having +an aggregate offering price of up to $17,111,650 from time to time through Piper Sandler acting as our agent, under our prospectus supplement +dated October 18, 2024. As of December 31, 2024, we have sold 314,707 shares of common stock under the ATM Agreement resulting in net +proceeds to the Company of $0.2 million. +Although +we are seeking to obtain additional equity and/or debt financing, such funding is not assured and may not be available to us on favorable +or acceptable terms and may involve significant restrictive covenants. Any additional equity financing is also not assured and, if available +to us, will most likely be dilutive to our current stockholders. If we are not able to obtain additional debt or equity financing on +a timely basis, the impact on us will be material and adverse. These uncertainties create substantial doubt about our ability to continue +as a going concern. The consolidated financial statements do not include any adjustments that might result from the outcome of these +uncertainties. +CRITICAL +ACCOUNTING POLICIES AND ESTIMATES +Our +management’s discussion and analysis of our financial condition and results of operations is based on our consolidated financial +statements, which have been prepared in accordance with United States generally accepted accounting principles (“GAAP”). +The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets +and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, as well as the reported +revenues and expenses incurred during the reporting periods. Our estimates are based on our historical experience and on various other +factors that we believe are reasonable under the circumstances. Actual results may differ from these estimates under different assumptions +or conditions. While our significant accounting policies are described in Item 8 of this Annual Report on Form 10-K, within Note 2 of +our consolidated financial statements in the section titled “Summary of Significant Accounting Policies”, we believe that +the accounting policies discussed below are critical to understanding our historical and future performance, as these policies relate +to the more significant areas involving management’s judgments and estimates. +Accounts +Receivable +Trade +accounts receivable are recorded at the invoiced amount, net of any allowance. The Company maintains an allowance for doubtful accounts +for amounts the Company does not expect to collect. In establishing the required allowance, management considers historical losses, current +market condition, customers’ financial condition, the age of receivables, and current payment patterns. Account balances are written +off against the allowance once the receivable is deemed uncollectible. If actual accounts receivable collections are less favorable than +those projected by management at the time of the assessment, however, additional accounts receivable write-downs may be required, which +could reduce our earnings. +33 +Intangible +Assets +The +useful lives of intangible assets with definite lives are based on the expected number of years the asset will generate revenue or otherwise +be used by us and the related amortization is based on the straight-line method. Goodwill, which has an indefinite life, is not amortized +but instead is tested at least annually for impairment, or more frequently when events or changes in circumstances indicate that the +asset might be impaired. Examples of such events or circumstances include: +● +the +assets’ ability to continue to generate income from operations and positive cash flow in future periods; +● +any +volatility or significant decline in our stock price and market capitalization compared to our net book value; +● +loss +of legal ownership or title to an asset; +● +significant +changes in our strategic business objectives and utilization of our assets; and +● +the +impact of significant negative industry or economic trends. +If +a change were to occur in any of the above-mentioned factors or estimates, the likelihood of a material change in our reported results +would increase. +Inventories +We +periodically review inventory for both potential obsolescence and potential declines in anticipated selling prices. In this review, we +make assumptions about the future demand for and market value of the inventory and based on these assumptions estimate the amount of +any obsolete, unmarketable, slow moving or overvalued inventory. We write down the value of our inventories by an amount equal to the +difference between the cost of the inventory and the net realizable value. If actual market conditions are less favorable than those +projected by management at the time of the assessment, however, additional inventory write-downs may be required, which could reduce +our earnings. +Income +Taxes +Significant +judgment is required in determining our provision for income taxes, current tax assets and liabilities, deferred tax assets and liabilities, +and our future taxable income, both as a whole and in various tax jurisdictions, for purposes of assessing our ability to realize future +benefit from our deferred tax assets. We recognize in the financial statements the impact of a tax position if that position is more +likely than not to be sustained during an audit, including resolution of related appeals or litigation processes, if any. While we believe +that we have appropriate support for the positions taken on our tax returns, we regularly assess the potential outcome of examinations +by tax authorities in determining the adequacy of our provision for income taxes. See Note 11 to our Consolidated Financial Statements +for more information on income taxes. +The +foregoing estimates, expectations and forward-looking statements are subject to change as we make strategic operating decisions from +time to time and as our revenue and expenses fluctuate from period to period. +ITEM +7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK +Not +required. +34 +ITEM +8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA. +CONSOLIDATED +FINANCIAL STATEMENTS +DECEMBER +31, 2024 AND 2023 +Table +of Contents +Report of Independent Registered Public Accounting Firms (PCAOB ID No. 270 ) +36 +Consolidated Balance Sheets +37 +Consolidated Statements of Operations +38 +Consolidated Statement of Changes in Stockholders’ Equity +39 +Consolidated Statements of Cash Flows +40 +Notes to Consolidated Financial Statements +41 +35 +Report +of Independent Registered Public Accounting Firm +To +the Board of Directors and Stockholders +Co-Diagnostics, +Inc. +Opinion +on the Consolidated Financial Statements +We have audited the accompanying consolidated balance sheets of Co-Diagnostics, +Inc. and subsidiaries (the Company) as of December 31, 2024 and 2023, the related consolidated statements of operations and comprehensive +loss, changes in stockholders’ equity, and cash flows for the years then ended, and the related notes (collectively, the consolidated +financial statements). In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, +the consolidated financial position of the Company as of December 31, 2024 and 2023, and the consolidated results of its operations and +its cash flows for the two-year period ended December 31, 2024, in conformity with accounting principles generally accepted in the United +States of America. +Going Concern +The financial statements have been prepared assuming +that the Company will continue as a going concern. As discussed in Note 1 to the financial statements, the Company has recurring losses +from operations and negative operating cash flows and needs to obtain additional financing to finance its operations. These issues raise +substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described +in Note 1. The financial statements do not include any adjustments that might result from the outcome of this uncertainty. +Basis +for Opinion +These consolidated financial statements are the responsibility of the Company’s +management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. +We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required +to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations +of the Securities and Exchange Commission and the PCAOB. +We conducted our audits in accordance with the standards of the PCAOB. +Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements +are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, +an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal +control over financial reporting, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal +control over financial reporting. Accordingly, we express no such opinion. +Our audits included performing procedures to assess the risks of material +misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those +risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial +statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as +evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for +our opinion. +Critical +Audit Matters +The critical audit matter communicated below is a matter arising from the +current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee +and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially +challenging, subjective, or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on +the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing separate +opinion on the critical audit matter or on the accounts or disclosures to which it relates. +Impairment +of Intangible Assets +In December 2021 the Company acquired in-process research and development +indefinite-lived intangible assets totaling $26,101,000. The Company assesses these assets for impairment at least annually or whenever +events or changes in circumstances occur that may indicate impairment. The Company’s analysis for the year ended December 31, 2024, +required significant judgment to assess qualitative factors in determining whether it is more likely than not that the indefinite-lived +intangible assets are impaired. As a result of their analysis, the Company determined there was no impairment as of year-end. +Auditing the Company’s annual impairment assessment was complex and +highly judgmental due to the significant judgment required in determining whether it is more likely than not the in-process research and +development indefinite-lived intangible assets are impaired. This required a high degree of auditor judgment, subjectivity and effort +in performing procedures and evaluating audit evidence to evaluate management’s assessment in evaluating these indefinite-lived +intangible assets for impairment. These procedures included among others: (1) evaluating management’s process for evaluating impairment, +(2) evaluating the factors assessed by management (3) evaluating other relevant factors in making our own determination, and (4) evaluating +and discussing considerations and conclusions made by management. +/s/ +Tanner LLC +We +have served as the Company’s auditor since 2023 +Salt +Lake City, Utah +March +27, 2025 +36 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +CONSOLIDATED +BALANCE SHEETS +December 31, 2024 +December 31, 2023 +Assets +Current assets +Cash and cash equivalents +$ 2,936,544 +$ 14,916,878 +Marketable investment securities +26,811,098 +43,631,510 +Accounts receivable, net +132,570 +303,926 +Inventory, net +1,072,724 +1,664,725 +Income taxes receivable +- +26,955 +Prepaid expenses and other current assets +1,338,762 +1,597,114 +Total current assets +32,291,698 +62,141,108 +Property and equipment, net +2,761,280 +3,035,729 +Operating lease right-of-use asset +2,114,876 +2,966,774 +Intangible assets, net +26,101,000 +26,403,667 +Investment in joint venture +731,065 +773,382 +Total assets +$ 63,999,919 +$ 95,320,660 +Liabilities and stockholders’ equity +Current liabilities +Accounts payable +$ 3,294,254 +$ 1,482,109 +Accrued expenses +2,562,169 +2,172,959 +Operating lease liability, current +915,619 +838,387 +Contingent consideration liabilities, current +502,819 +891,666 +Deferred revenue +40,857 +362,449 +Total current liabilities +7,315,718 +5,747,570 +Long-term liabilities +Income taxes payable +713,643 +659,186 +Operating lease liability +1,236,560 +2,152,180 +Contingent consideration liabilities +422,080 +748,109 +Total long-term liabilities +2,372,283 +3,559,475 +Total liabilities +9,688,001 +9,307,045 +Commitments and contingencies (Note 12) +- +- +Stockholders’ equity +Convertible preferred stock, $ 0.001 par value; 5,000,000 shares authorized; 0 shares issued and outstanding as of December 31, 2024 and December 31, 2023, respectively +- +- +Common stock, $ 0.001 par value; 100,000,000 shares authorized; 37,902,222 shares issued and 33,053,544 shares outstanding as of December 31, 2024 and 36,108,346 shares issued and 31,259,668 shares outstanding as of December 31, 2023 +37,902 +36,108 +Treasury stock, at cost; 4,848,678 shares held as of December 31, 2024 and December 31, 2023, respectively +( 15,575,795 ) +( 15,575,795 ) +Additional paid-in capital +102,472,210 +96,808,436 +Accumulated other comprehensive income +418,443 +146,700 +Accumulated earnings (deficit) +( 33,040,842 ) +4,598,166 +Total stockholders’ equity +54,311,918 +86,013,615 +Total liabilities and stockholders’ equity +$ 63,999,919 +$ 95,320,660 +See +accompanying notes to consolidated financial statements. +37 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS +2024 +2023 +Years Ended December 31, +2024 +2023 +Product revenue +$ 770,048 +$ 991,473 +Grant revenue +3,145,112 +5,820,565 +Total revenue +3,915,160 +6,812,038 +Cost of revenue +999,124 +4,184,949 +Gross profit +2,916,036 +2,627,089 +Operating expenses +Sales and marketing +4,483,339 +6,860,815 +General and administrative +16,157,152 +14,279,441 +Research and development +20,979,589 +22,962,593 +Depreciation and amortization +1,377,266 +1,230,474 +Total operating expenses +42,997,346 +45,333,323 +Loss from operations +( 40,081,310 ) +( 42,706,234 ) +Other income, net +Interest income, net +1,091,825 +1,161,913 +Realized gain on investments +870,745 +2,243,059 +Gain (loss) on disposition of assets +8,291 +( 2,578 ) +Gain on remeasurement of acquisition contingencies +714,876 +1,092,581 +Gain (loss) on equity method investment in joint venture +( 186,067 ) +100,703 +Total other income, net +2,499,670 +4,595,678 +Loss before income taxes +( 37,581,640 ) +( 38,110,556 ) +Income tax provision (benefit) +57,368 +( 2,777,691 ) +Net loss +$ ( 37,639,008 ) +$ ( 35,332,865 ) +Other comprehensive loss +Change in net unrealized gains on marketable securities, net of tax +271,743 +( 146,440 ) +Total other comprehensive income (loss) +$ 271,743 +$ ( 146,440 ) +Comprehensive loss +$ ( 37,367,265 ) +$ ( 35,479,305 ) +Loss per common share: +Basic and Diluted +$ ( 1.24 ) +$ ( 1.20 ) +Weighted average shares outstanding: +Basic and Diluted +30,335,350 +29,346,599 +See +accompanying notes to consolidated financial statements. +38 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENT OF CHANGES IN STOCKHOLDERS’ EQUITY +Shares +Amount +Shares +Amount +Stock +Capital +Income +(Deficit) +Equity +Convertible Preferred Stock +Common Stock +Treasury +Additional Paid-in +Accumulated Other Comprehensive +Accumulated +Earnings +Total Stockholders’ +Shares +Amount +Shares +Amount +Stock +Capital +Income +(Deficit) +Equity +Balance as of December 31, 2022 +- +$ - +34,754,265 +$ 34,754 +$ ( 14,211,866 ) +$ 88,472,935 +$ 293,140 +$ 39,931,031 +$ 114,519,994 +Stock-based compensation expense +- +- +1,354,081 +1,354 +- +8,335,501 +- +- +8,336,855 +Repurchases of common stock +- +- +- +- +( 1,363,929 ) +- +- +- +( 1,363,929 ) +Other comprehensive loss, net of tax +- +- +- +- +- +- +( 146,440 ) +- +( 146,440 ) +Net loss +- +- +- +- +- +- +- +( 35,332,865 ) +( 35,332,865 ) +Balance as of December 31, 2023 +- +$ - +36,108,346 +$ 36,108 +$ ( 15,575,795 ) +$ 96,808,436 +$ 146,700 +$ 4,598,166 +$ 86,013,615 +Balance +- +$ - +36,108,346 +$ 36,108 +$ ( 15,575,795 ) +$ 96,808,436 +$ 146,700 +$ 4,598,166 +$ 86,013,615 +Issuance of common stock related to at-the-market offering, net of offering costs +- +- +314,707 +315 +- +230,349 +- +- +230,664 +Stock-based compensation expense +- +- +1,479,169 +1,479 +- +5,433,425 +- +- +5,434,904 +Repurchases of common stock +- +- +- +- +- +- +- +- +- +Other comprehensive loss, net of tax +- +- +- +- +- +- +271,743 +- +271,743 +Net loss +- +- +- +- +- +- +- +( 37,639,008 ) +( 37,639,008 ) +Balance as of December 31, 2024 +- +$ - +37,902,222 +$ 37,902 +$ ( 15,575,795 ) +$ 102,472,210 +$ 418,443 +$ ( 33,040,842 ) +$ 54,311,918 +Balance +- +$ - +37,902,222 +$ 37,902 +$ ( 15,575,795 ) +$ 102,472,210 +$ 418,443 +$ ( 33,040,842 ) +$ 54,311,918 +See +accompanying notes to consolidated financial statements. +39 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +CONSOLIDATED +STATEMENTS OF CASH FLOWS +2024 +2023 +Years Ended December 31, +2024 +2023 +Cash flows from operating activities +Net loss +$ ( 37,639,008 ) +$ ( 35,332,865 ) +Adjustments to reconcile net loss to cash used in operating activities: +Depreciation and amortization +1,377,266 +1,230,474 +Stock-based compensation expense +5,434,904 +8,336,855 +Change in fair value of acquisition contingencies +( 714,876 ) +( 1,092,581 ) +Non-cash lease expense +13,510 +47,992 +Realized gain on investments +( 870,745 ) +( 2,243,059 ) +(Gain) loss from equity method investment +186,067 +( 100,703 ) +(Gain) loss on disposition of assets +( 8,291 ) +2,578 +Deferred income taxes +- +( 2,417,987 ) +Provision for (recoveries of) credit losses +( 15,035 ) +612,809 +Inventory obsolescence expense +326,512 +3,233,281 +Changes in assets and liabilities: +Accounts receivable +186,391 +2,536,988 +Prepaid expenses and other assets +412,056 +1,082,536 +Inventory +265,489 +413,140 +Deferred revenue +( 321,592 ) +362,449 +Income taxes payable +54,457 +( 522,098 ) +Accounts payable, accrued expenses and other liabilities +2,157,850 +1,768,326 +Net cash used in operating activities +( 29,155,045 ) +( 22,081,865 ) +Cash flows from investing activities +Purchases of property and equipment +( 748,352 ) +( 1,365,306 ) +Proceeds from maturities of marketable investment securities +58,765,487 +127,251,619 +Purchases of marketable securities +( 40,802,588 ) +( 110,497,444 ) +Investment in joint venture +( 143,750 ) +- +Net cash provided by investing activities +17,070,797 +15,388,869 +Cash flows from financing activities +Repurchases of common stock +- +( 1,363,929 ) +Issuance of common stock related to at-the-market offering, net of offering costs +103,914 +- +Net cash provided by (used in) financing activities +103,914 +( 1,363,929 ) +Net decrease in cash and cash equivalents +( 11,980,334 ) +( 8,056,925 ) +Cash and cash equivalents at beginning of period +14,916,878 +22,973,803 +Cash and cash equivalents at end of period +$ 2,936,544 +$ 14,916,878 +Supplemental disclosure of cash flow information +Income taxes paid +$ - +$ 55,975 +Supplemental disclosure of non-cash investing and financing transactions +Inventory moved to property, plant and equipment +$ - +$ 673 +Right-of-use assets obtained in exchange for new operating lease liabilities +$ - +$ 3,203,146 +Receivable from issuance of common stock, collected in 2025 +$ 126,750 +$ - +See +accompanying notes to consolidated financial statements. +40 +CO-DIAGNOSTICS, +INC. AND SUBSIDIARIES +NOTES +TO CONSOLIDATED FINANCIAL STATEMENTS +YEARS +ENDED DECEMBER 31, 2024 AND 2023 +Note +1 – Overview and Basis of Presentation +Description +of Business +Co-Diagnostics, +Inc., a Utah corporation (the “Company” or “CODX”), is a molecular diagnostics company that develops, +manufactures and markets state-of-the-art diagnostics technologies. The Company’s technologies are utilized for tests that are +designed using the detection and/or analysis of nucleic acid molecules (DNA or RNA). The Company also uses its proprietary +technology to design specific tests for its Co-Dx™ PCR platform and to locate genetic markers for use in applications other +than infectious disease. In connection with the sale of our tests we may sell diagnostic equipment from other manufacturers as +self-contained lab systems. +Use +of Estimates +The +preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates +and assumptions that affect the amounts reported in the financial statements and the accompanying notes. Such estimates include inventories, +receivables and other long-lived assets, legal and regulatory contingencies, income taxes, share based arrangements, and others. These +estimates and assumptions are based on management’s best estimates and judgments. Actual amounts and results could differ from +those estimates. +Basis +of Presentation +The +accompanying audited consolidated financial statements of Co-Diagnostics, Inc. and its wholly owned subsidiaries have been prepared to +reflect the financial position, results of operations and cash flows of the Company and have been prepared in accordance with accounting +principles generally accepted in the United States of America (“GAAP”). All intercompany balances and transactions have been +eliminated. +Liquidity +and Going Concern +In +accordance with Accounting Standards Codification (“ASC”) 205-40, Going Concern, (“ASC 205-40”) the Company evaluated +whether there are conditions and events, considered in the aggregate, that raise substantial doubt about the Company’s ability +to continue as a going concern within one year after the date on which this Annual Report on Form 10-K is filed. Based on the Company’s +cash, cash equivalents, and short-term investments as of December 31, 2024, the Company’s current and forecasted level of operations, +and its forecasted cash flows, the Company’s ability to continue as a going concern is dependent upon its ability to obtain the +necessary financing to meet its obligations and repay its liabilities arising from normal business operations when they come due, and +to generate profitable operations in the future. Management plans to provide for the Company’s capital requirements through equity +financing, including through selling shares under the Company’s ATM Agreement, seeking additional grant funding, and through operational +efficiencies. Our ability to obtain additional financing in equity capital markets is subject to several factors, including market and +economic conditions, our performance and investor sentiment with respect to us and our industry. Accordingly, there can be no assurance +that the Company will be able to raise a sufficient amount of additional capital to fund operations with terms acceptable to the Company, +or at all. Because certain elements of management’s plans to mitigate the conditions that raised substantial doubt about the Company’s +ability to continue as a going concern are outside of the Company’s control, including the ability to raise capital through equity +or other financings, those elements cannot be considered probable according to ASC 205-40, and therefore cannot be considered in the +evaluation of mitigating factors. As a result, management has concluded that substantial doubt exists about the Company’s ability +to continue as a going concern for 12 months from the date these consolidated financial statements are issued. +The +consolidated financial statements as of December 31, 2024 have been prepared under the assumption that the Company will continue as a +going concern for the next 12 months after these financial statements are issued, and that contemplates the realization of assets and +satisfaction of liabilities and commitments in the normal course of business. The Company’s ability to continue as a going concern +is dependent upon its uncertain ability to obtain additional capital, reduce expenditures, and execute on its business plans. These consolidated +financial statements do not include any adjustments that might result from the outcome of this uncertainty. +Note +2 – Summary of Significant Accounting Policies +Operating Segments +The Company operates as one operating segment. Operating segments +are defined as components of an entity for which separate financial information is regularly evaluated by the chief operating decision +maker (“CODM”), which is the Company’s Chief Executive Officer, in deciding how to allocate resources and assess performance. +The Company’s CODM evaluates financial information and resources and assesses the performance of these resources on a consolidated +basis. There is no expense or asset information that is supplemental to information disclosed within the consolidated financial statements, +that is regularly provided to the CODM. The allocation of resources and assessment of performance of the operating segment is based on +consolidated net loss and functional expenses as reported on our consolidated statements of operations and comprehensive loss. Because +the Company operates as one operating segment, financial segment information, including expense and asset information, can be +found in the consolidated financial statements. All material long-lived assets are based in the United States. +Reclassifications +Certain +prior year amounts have been reclassified to conform with the current year’s presentation. These reclassifications have no impact +on the previously reported results. +Cash +and Cash Equivalents +Cash +and cash equivalents consist of cash on hand, money market funds and highly liquid investments with an original maturity date of 90 days +or less from the date of purchase. The fair value of cash equivalents approximated their carrying value as of December 31, 2024 and December +31, 2023. The Company has its cash and cash equivalents with a large creditworthy financial institution and the balance exceeded federally +insured limits. The Company has not experienced any losses in such accounts, and management believes the Company is not exposed to any +significant credit risk on cash and cash equivalents. +41 +Marketable +Investment Securities +The +Company’s marketable investment securities are comprised of investments in certificates of deposit and U.S. Treasury bills and +notes. The Company designates investments in debt securities as available-for-sale. Available-for-sale debt securities with original +maturities of three months or less from the date of purchase are classified within cash and cash equivalents. Available-for-sale debt +securities with original maturities longer than three months are available to fund current operations and are classified as marketable +investment securities, within current assets on the consolidated balance sheets. The Company may sell these securities at any time for +use in its current operations or for other purposes, even prior to maturity. Available-for-sale debt securities are reported at fair +value with the related unrealized gains and losses included in accumulated other comprehensive income (loss), a component of stockholders’ +equity, net of tax. Realized gains and losses on the sale of marketable securities are determined using the average cost method on a +first-in, first-out basis and recorded in total other income (expense), net in the consolidated statements of operations and comprehensive +loss. +The +available-for-sale debt securities are subject to a periodic impairment review. For investments in an unrealized loss position, the Company +writes down the amortized cost basis of the investment if it is more likely than not that the Company will be required or will intend +to sell the investment before recovery of its amortized cost basis. For investments not likely to be sold before recovery of the amortized +cost basis, the Company determines whether a credit loss exists by considering information about the collectability of the instrument, +current market conditions, and reasonable and supportable forecasts of economic conditions. The Company recognizes an allowance for credit +losses up to the amount of the unrealized loss when appropriate. Allowances for credit losses and write-downs are recognized in total +other income (expense), net, and unrealized losses not related to credit losses are recognized in accumulated other comprehensive income +(loss). There are no allowances for credit losses recorded for the periods presented. +Accounts +Receivable +Trade +accounts receivable are recorded at the invoiced amount (net of allowance) and do not bear interest. The Company maintains an +allowance for credit losses for amounts the Company does not expect to collect. In establishing the required allowance, management +considers historical losses, current market condition, customers’ financial condition, the age of receivables, and current +payment patterns. Account balances are written off against the allowance once the receivable is deemed uncollectible. Recoveries of +trade receivables previously written off are recorded when collected. At December 31, 2024 total accounts receivable was $ 242,625 +with an allowance for uncollectable accounts of $ 110,055 +resulting in a net amount of $ 132,570 . +At December 31, 2023 total accounts receivable was $ 504,264 +with an allowance for uncollectable accounts of $ 200,338 +resulting in a net amount of $ 303,926 . At December 31, 2022 total accounts receivable was $ 6,552,249 with an allowance +for uncollectable accounts of $ 3,098,526 resulting in a net amount of $ 3,453,723 . +Equity-Method +Investments +Our +equity-method investments are initially recorded at cost and are included in other long-term assets in the accompanying consolidated +balance sheet. We adjust the carrying value of our investment based on our share of the earnings or losses in the periods which they +are reported by the investee until the carrying amount is zero. The earnings or losses are included in other income in the accompanying +consolidated statements of operations. +Inventory +Inventory +is stated at the lower of cost or net-realizable value. Inventory cost is determined on a first-in first-out basis that approximates +average cost in accordance with ASC 330-10-30-12. At December 31, 2024, the Company had $ 1,072,724 in inventory, of which $ 567,281 was +finished goods and $ 505,443 was raw materials. At December 31, 2023, the Company had $ 1,664,725 in inventory, of which $ 700,467 was finished +goods and $ 964,258 was raw materials. The Company establishes reserves to reduce low-moving, obsolete, or unusable inventories to their +estimated useful or scrap values. The Company recognized $ 54,987 and $ 2,760,011 related to the change in inventory reserves during the +years ended December 31, 2024 and 2023, respectively. +42 +Intangible +Assets +Indefinite-lived +intangible assets are not amortized, but rather tested for impairment at least annually on December 31, or more often if and when circumstances +indicate that the carrying value may not be recoverable. Finite-lived intangible assets are amortized over their useful lives. +Long-lived +Assets +Long-lived +assets, such as property and equipment, are stated at cost less accumulated depreciation and amortization. Depreciation is provided using +the straight-line method over the estimated useful lives of the property, generally from three to five years. Repairs and maintenance +costs are expensed as incurred except when such repairs significantly add to the useful life or productive capacity of the asset, in +which case the repairs are capitalized. +For +in-process research and development projects acquired in business combinations, the in-process research and development project is capitalized +and evaluated for impairment until the development process has been completed. Once the development process has been completed the asset +will be amortized over its remaining estimated useful life. The Company reviews its long-lived assets, including property and equipment, +indefinite-lived and finite-lived intangible assets, and ROU assets, for impairment whenever an event or change in facts and circumstances +indicates that their carrying amounts may not be recoverable. Recoverability of these assets is measured by comparing the carrying amount +to the estimated undiscounted future cash flows expected to be generated. If the carrying amount exceeds the undiscounted cash flows, +the assets are determined to be impaired and an impairment charge is recognized as the amount by which the carrying amount exceeds fair +value. +Revenue +Recognition +The +Company generates revenue from product sales and license sales. The Company recognizes revenue when all of the following criteria are +satisfied: (i) identification of the promised goods or services in the contract; (ii) determination of whether the promised goods or +services are performance obligations, including whether they are distinct in the context of the contract; (iii) measurement of the transaction +price, including the constraint on variable consideration; (iv) allocation of the transaction price to the performance obligations; and +(v) recognition of revenue when, or as the Company satisfies each performance obligation. Based on the criteria above, the Company typically +recognizes revenue upon delivery. +The +Company constrains revenue by giving consideration to factors that could otherwise lead to a probable reversal of revenue. The Company +records any payments received from customers prior to the Company fulfilling its performance obligation(s) as deferred revenue. +Grant +Revenue +The +Company may submit applications to receive grant funding from governmental and non-governmental entities. The Company accounts for grants +by analogizing to the contribution accounting model under ASC 958-605, Not-for-Profit Entities (“ASC 958”). Revenues from +grants, contracts, and awards provided by governmental and non-governmental agencies are recorded based upon the terms of the specific +agreements. The Company recognizes grant funding without conditions or continuing performance obligations as revenue in the consolidated +statements of operations and comprehensive income (loss). The Company recognizes grant funding with conditions or continuing performance +obligations as deferred revenue in the consolidated balance sheets if the conditions or performance obligations have not yet been met. +The Company recognized grant funding revenue of $ 3.1 million and $ 5.8 million during the years ended December 31, 2024 and 2023, respectively. +At December 31, 2024 and 2023, respectively, the Company has also recorded $ 0.1 million and $ 0.3 million of deferred revenue related +to grant funding for which the cash was received, but the underlying conditions or performance obligations have not yet been met. Cash +received from federal grants, contracts, and awards can be subject to audit by the grantor and, if the examination results in a disallowance +of any expenditure, repayment could be required. +Deferred +Revenue +Deferred +revenue primarily consists of payments received from customers prior to the Company fulfilling its performance obligation of providing +the product. When this occurs, the Company records a contract liability as deferred revenue. Deferred revenue is recognized as revenue +as the related performance obligations are satisfied. +43 +Research +and Development +Research +and development costs are expensed when incurred. The Company recorded $ 20,979,589 and $ 22,962,593 of research and development costs +for the years ended December 31, 2024 and 2023, respectively. +Stock-based +Compensation +The +Company has granted stock-based awards, including restricted stock, stock options, stock warrants and restricted stock units (“RSUs”), +to its employees, certain consultants and members of its board of directors. The Company records stock-based compensation based on the +grant date fair value of the awards and recognizes the fair value of those awards as expense using the straight-line method over the +requisite service period of the award. The Company estimates the grant date fair value of stock options using the Black-Scholes option-pricing +model. When an award is forfeited prior to the vesting date, the Company recognizes an adjustment for the previously recognized expense +in the period of the forfeiture. +Income +Taxes +The +Company accounts for income taxes in accordance with the liability method of accounting for income taxes. Under this method, deferred +income tax assets and deferred income tax liabilities represent the tax effect of temporary differences between financial reporting and +tax reporting measured at enacted tax rates in effect for the year in which the differences are expected to reverse. The Company recognizes +only the impact of tax positions that, based on their technical merits, are more likely than not to be sustained upon an audit by the +taxing authority. +Valuation +allowances are provided when it is more-likely-than-not that some or all of the deferred income tax assets may not be realized. In assessing +the need for a valuation allowance, the Company has considered its historical levels of income, expectations of future taxable income +and ongoing tax planning strategies. +Developing +the provision for income taxes, including the effective tax rate and analysis of potential tax exposure items, if any, requires significant +judgment and expertise in federal and state income tax laws, regulations and strategies, including the determination of deferred income +tax assets and liabilities and any estimated valuation allowances deemed necessary to value deferred income tax assets. Judgments and +tax strategies are subject to audit by various taxing authorities. The Company has uncertain income tax positions in the consolidated +financial statements, and adverse determinations by these taxing authorities could have a material adverse effect on the consolidated +financial positions, result of operations, or cash flows. +Net +Loss per Share +Basic +net loss per common share is computed by dividing net loss applicable to common shareholders by the weighted average number of shares +outstanding during each period. +Diluted +net loss per share is computed by dividing net loss attributable to common stockholders by the weighted-average number of shares of common +stock outstanding during the period increased by common shares that could be issued upon conversion or exercise of other outstanding +securities to the extent those additional common shares would be dilutive. The dilutive effect of potentially dilutive securities is +reflected in diluted net loss per share by application of the treasury stock method. During periods when the Company is in a net loss +position, basic net loss per share is the same as diluted net loss per share as the effects of potentially dilutive securities are anti-dilutive. +Comprehensive +Loss +Comprehensive +loss is comprised of net loss and unrealized gains and losses on marketable securities, net of income taxes. +Concentrations +Risk and Significant Customers +The +Company had certain customers which were each responsible for generating 10 % or more of the total revenue for the years ended December +31, 2024 and 2023, respectively. One customer accounted for approximately 31 % of product revenue for the year ended December 31, 2024 +and two customers accounted for approximately 27 % of product revenue for the year ended December 31, 2023. Two granting agencies accounted +for approximately 95 % of grant revenue for the year ended December 31, 2024, and one granting agency accounted for 100 % of grant revenue +for the year ended December 31, 2023. +44 +Two +customers accounted for more than 10 % of accounts receivable at December 31, 2024, and three customers accounted for more than 10 % of +accounts receivable at December 31, 2023. These customers together accounted for approximately 94 % and 97 % of accounts receivable at +December 31, 2024 and 2023, respectively. +Recently +Issued Accounting Standards +From +time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”) that are adopted +by the Company as of the specified effective date. If not discussed, management believes that the impact of recently issued standards, +which are not yet effective, will not have a material impact on the Company’s financial statements upon adoption. +In +November 2023, the FASB issued Accounting Standards Update (“ASU”) 2023-07, Segment Reporting (Topic 280): +Improvements to Reportable Segment Disclosures, which improves reportable segment disclosure requirements, primarily through +enhanced disclosures about significant segment expenses. The standard is effective for full year 2024 reporting, and for interim +reporting beginning in 2025. The adoption of this ASU did not change the way the Company evaluates its reportable segments and, as a +result, did not have a material impact on the Company’s segment-related disclosures. +In +December 2023, the FASB issued ASU 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which requires an entity +to disclose annually additional information related to the company’s income tax rate reconciliation and income taxes paid during +the period. The guidance should be applied prospectively with the option to apply the standard retrospectively. The standard becomes +effective for the Company for full year 2025 reporting. The Company does not expect a material impact on its consolidated financial statements +related to ASU 2023-09. +In +November 2024, the FASB issued ASU 2024-03, Income Statement (Subtopic 220-40): Reporting Comprehensive Income - Expense Disaggregation +Disclosures, which requires an entity to disclose on an annual and interim basis, disaggregated information about specific income statement +expense categories. The guidance should be applied prospectively with the option to apply the standard retrospectively. The standard +becomes effective for the Company for full year 2027 reporting. The Company is currently evaluating the impact of this new standard on +its consolidated financial statements. +Note +3 – Cash, Cash Equivalents, and Financial Instruments +The +following table shows the Company’s cash, cash equivalents, and marketable investment securities by significant investment category: +Schedule of Cash, Cash Equivalents and Marketable Investment Securities +December 31, 2024 +Adjusted Cost +Total Unrealized Gains / (Losses) +Fair Value +Cash and Cash Equivalents +Marketable Investment Securities +Cash +$ 2,936,544 +$ - +$ 2,936,544 +$ 2,936,544 +$ - +Level 2: +U.S. treasury securities +26,392,655 +418,443 +26,811,098 +- +26,811,098 +Subtotal +26,392,655 +418,443 +26,811,098 +- +26,811,098 +Total +$ 29,329,199 +$ 418,443 +$ 29,747,642 +$ 2,936,544 +$ 26,811,098 +December 31, 2023 +Adjusted Cost +Total Unrealized Gains / (Losses) +Fair Value +Cash and Cash Equivalents +Marketable Investment Securities +Cash +$ 4,317,449 +$ - +$ 4,317,449 +$ 4,317,449 +$ - +Level 1: +Money market funds +10,599,429 +- +10,599,429 +10,599,429 +- +Subtotal +10,599,429 +- +10,599,429 +10,599,429 +- +Level 2: +U.S. treasury securities +43,484,810 +146,700 +43,631,510 +- +43,631,510 +Subtotal +43,484,810 +146,700 +43,631,510 +- +43,631,510 +Total +$ 58,401,688 +$ 146,700 +$ 58,548,388 +$ 14,916,878 +$ 43,631,510 +Marketable +investment securities held as of December 31, 2024 mature over the next 12 months. +Note +4 – Fair Value Measurements +The +Company measures and records certain financial assets and liabilities at fair value on a recurring basis. Fair value is based on the +price that would be received from selling an asset or paid to transfer a liability in an orderly transaction between market participants +at the measurement date. +The +following three levels of inputs are used to measure the fair value of financial assets and liabilities: +Level +1: Quoted market prices in active markets for identical assets or liabilities. +Level +2: Observable market-based inputs or unobservable inputs that are corroborated by market data. +Level +3: Unobservable inputs that are not corroborated by market data. +45 +The +following table summarizes the assets and liabilities measured at fair value on a recurring basis as of December 31, 2024 and December +31, 2023, by level within the fair value hierarchy: +Schedule of Fair Value Assets and Liabilities +(Level 1) +(Level 2) +(Level 3) +Total +December 31, 2024 +(Level 1) +(Level 2) +(Level 3) +Total +Assets: +Cash equivalents +$ 441,000 +$ - +$ - +$ 441,000 +Marketable securities (U.S. treasury bills and notes) +- +26,811,098 +- +26,811,098 +Total assets measured at fair value +$ 441,000 +$ 26,811,098 +$ - +$ 27,252,098 +Liabilities: +Contingent consideration - common stock +$ - +$ - +$ 743,794 +$ 743,794 +Contingent consideration - warrants +- +- +181,105 +181,105 +Total liabilities measured at fair value +$ - +$ - +$ 924,899 +$ 924,899 +(Level 1) +(Level 2) +(Level 3) +Total +December 31, 2023 +(Level 1) +(Level 2) +(Level 3) +Total +Assets: +Cash equivalents +$ 13,806,864 +$ - +$ - +$ 13,806,864 +Marketable securities (U.S. treasury bills and notes) +- +43,631,510 +- +43,631,510 +Total assets measured at fair value +$ 13,806,864 +$ 43,631,510 +$ - +$ 57,438,374 +Liabilities: +Contingent consideration - common stock +$ - +$ - +$ 1,318,995 +$ 1,318,995 +Contingent consideration - warrants +- +- +320,780 +320,780 +Total liabilities measured at fair value +$ - +$ - +$ 1,639,775 +$ 1,639,775 +The +Company’s financial instruments that are measured at fair value on a recurring basis consist of certificates of deposit and U.S. +treasury bills and notes as of December 31, 2024 and 2023, respectively. +In +connection with previous acquisitions, the Company recorded a liability for contingent consideration in the form of shares of common +stock and warrants to purchase common stock, both to be issued when certain milestones are achieved. The fair value of contingent consideration +is calculated using a discounted probability weighted valuation model. Discount rates used in such calculations are a significant assumption +that are not observed in the market, and therefore, the resulting fair value represents a Level 3 measurement. +The +changes for Level 3 items measured at fair value on a recurring basis are as follows: +Schedule of Changes in the Fair Value Measurement +Fair value as of December 31, 2023 +$ 1,639,775 +Change in fair value of contingent consideration issued for business acquisitions +( 714,876 ) +Fair value as of December 31, 2024 +$ 924,899 +46 +The +fair value of the contingent consideration is based on the fair value of the contingent consideration-common stock and contingent consideration-warrants. +The fair value of the contingent consideration-common stock is equal to the probability-adjusted value of the Company’s common +stock as of the valuation date. The fair value of the contingent consideration-warrants is equal to the probability adjusted value of +a call option with terms consistent with the terms of the warrants as of the valuation date. Prior to the probability adjustments, the +warrants were valued based on the following inputs: +Schedule of Contingent Consideration Common Stock and Warrants +December 31, 2024 +December 31, 2023 +Stock price +$ 0.75 +$ 1.33 +Strike price +$ 9.13 +$ 9.13 +Volatility +246.4 % +187.5 % +Risk-free rate +4.3 % +4.0 % +Expected term (years) +2.0 +3.0 +Fair +Value of Other Financial Instruments +The +carrying amounts of certain financial instruments, including cash held in banks, accounts receivable, notes receivable, accounts payable, +accrued liabilities, and other liabilities approximate fair value due to their short-term maturities and are excluded from the fair value +tables above. +Note +5 – Property and Equipment +Property +and equipment, net consisted of the following: +Schedule of Property and Equipment +Estimated +December 31, +Useful Lives in years +2024 +2023 +Lab equipment +3 - 5 +$ 4,920,781 +$ 4,545,908 +Leasehold improvements +0 - 5 +947,674 +548,648 +Office equipment, furniture and other +2 - 5 +173,668 +173,668 +Less accumulated depreciation and amortization +( 3,280,843 ) +( 2,232,495 ) +Fixed assets, net +$ 2,761,280 +$ 3,035,729 +Note +6 – Intangible Assets +Intangible +assets, net consisted of the following: +Schedule of Intangible Assets, Net +December 31, 2024 +Weighted-Average +Gross +Net +Useful Life (1) +Carrying +Accumulated +Carrying +(in Years) +Amount +Amortization +Amount +In-process research and development +Indefinite +$ 26,101,000 +$ - +$ 26,101,000 +Non-competition agreements +2.7 +1,094,000 +( 1,094,000 ) +- +Total intangible assets +$ 27,195,000 +$ ( 1,094,000 ) +$ 26,101,000 +December 31, 2023 +Weighted-Average +Gross +Net +Useful Life (1) +Carrying +Accumulated +Carrying +(in Years) +Amount +Amortization +Amount +In-process research and development +Indefinite +$   26,101,000 +$ - +$ 26,101,000 +Non-competition agreements +2.7 +1,094,000 +( 791,333 ) +302,667 +Total intangible assets +$ 27,195,000 +$ ( 791,333 ) +$ 26,403,667 +(1) +Based +on weighted-average useful life established as of the acquisition date. +47 +Note +7 - Accrued Expenses +Accrued +expenses consisted of the following: +Schedule of Accrued Expenses +December 31, 2024 +December 31, 2023 +Payroll liabilities +$ 820,621 +$ 1,643,186 +Legal fees +1,666,914 +503,890 +Other accrued liabilities +74,634 +25,883 +Total accrued expenses +$ 2,562,169 +$ 2,172,959 +Note +8 – Revenue +The +following table sets forth revenue by geographic area: +Summary of Revenue by Geographic Area +2024 +2023 +Years Ended December 31, +2024 +2023 +United States +Product revenue +$ 378,212 +$ 659,618 +Grant revenue +3,145,112 +5,820,565 +Total United States +3,523,324 +6,480,183 +Rest of World +Product revenue +391,836 +331,855 +Grant revenue +- +- +Total Rest of World +391,836 +331,855 +Total +$ 3,915,160 +$ 6,812,038 +Revenue geographic area +$ 3,915,160 +$ 6,812,038 +Percentage of revenue by area: +United States +90 % +95 % +Rest of World +10 % +5 % +Deferred +Revenue +Changes +in the Company’s deferred revenue balance for the year ended December 31, 2024 were as follows: +Schedule of Deferred Revenue +Balance as of December 31, 2022 +$ - +Increase due to prepayments from customers +32,570 +Increase due to grant funding awarded +329,879 +Balance as of December 31, 2023 +$ 362,449 +Revenue recognized included in deferred revenue balance at the beginning of the period +( 301,972 ) +Decrease due to reclassification of previously deferred amounts +( 19,620 ) +Balance as of December 31, 2024 +$ 40,857 +Note +9 – Loss per Share +The +following table reconciles the numerator and the denominator used to calculate basic and diluted loss per share for years ended December +31, 2024 and 2023: +Schedule of Basis and Diluted Earnings Per Share +2024 +2023 +Years Ended December 31, +2024 +2023 +Numerator +Net loss, as reported +$ ( 37,639,008 ) +$ ( 35,332,865 ) +Denominator +Weighted average shares, basic +30,335,350 +29,346,599 +Dilutive effect of stock options, warrants and RSUs +- +- +Shares used to compute diluted loss per share +30,335,350 +29,346,599 +Basic loss per share +$ ( 1.24 ) +$ ( 1.20 ) +Diluted loss per share +$ ( 1.24 ) +$ ( 1.20 ) +48 +The +computation of diluted loss per share for the years ended December 31, 2024 and December 31, 2023 also excludes approximately 1.4 million +shares of common stock and approximately 465,000 warrants to purchase shares of common stock that are contingent upon the achievement +of certain milestones. +As +a result of incurring a net loss for the years ended December 31, 2024 and 2023, respectively, no potentially dilutive securities are +included in the calculation of diluted earnings per share because such effect would be anti-dilutive. The Company had potentially dilutive +securities as of December 31, 2024, consisting of: (i) 1,475,646 restricted stock units and (ii) 532,112 options and warrants, and potentially +dilutive securities as of December 31, 2023, consisting of: (i) 2,618,362 restricted stock units and (ii) 512,112 options. +Note +10 – Stock-Based Compensation +Stock +Incentive Plans +The +Company’s board of directors adopted, and shareholders approved, the Co-Diagnostics, Inc. Amended and Restated 2015 Long Term Incentive +Plan (the “Incentive Plan”) providing for the issuance of stock-based incentive awards to employees, officers, consultants, +directors and independent contractors. The number of awards available for issuance under the Incentive Plan was 3,061,949 at December +31, 2024. +Stock +Options +The +following table summarizes option activity during the years ended December 31, 2024 and 2023: +Schedule of Option Activity +Number of Options +Weighted Average Exercise Price +Weighted Average Fair Value +Weighted Average Remaining Contractual Life (Years) +Outstanding at December 31, 2022 +1,040,572 +$ 2.19 +$ 1.37 +5.88 +Granted +- +- +- +Expired +- +- +- +Forfeited/Cancelled +- +- +- +Exercised +- +- +Outstanding at December 31, 2023 +1,040,572 +$ 2.19 +$ 1.37 +4.89 +Granted +- +- +- +Expired +- +- +- +Forfeited/Cancelled +- +- +- +Exercised +- +- +- +Outstanding at December 31, 2024 +1,040,572 +$ 2.19 +$ 1.37 +3.88 +Exercisable at December 31, 2024 +1,040,572 +$ 2.19 +$ 1.37 +3.88 +49 +There +were no options exercised during the years ended December 31, 2024 and 2023, respectively. The aggregate intrinsic value of outstanding +options at December 31, 2024 and 2023 was approximately $ 0 and $ 0.2 million, respectively. As of December 31, 2024, there were no unvested +options and no unrecognized stock-based compensation expense related to options. +Restricted +Stock Units +The +grant date fair value of RSUs granted is determined using the closing market price of the Company’s common stock on the grant date +with the associated compensation expense amortized over the vesting period of the awards. The following table sets forth the outstanding +RSUs and related activity for the years ended December 31, 2024 and 2023: +Schedule of Outstanding Restricted Stock Units and Related Party +Number of RSUs +Weighted Average Grant Date Fair Value +Unvested at December 31, 2022 +2,426,725 +$ 6.95 +Granted +1,948,750 +1.92 +Vested +( 1,354,081 ) +6.17 +Forfeited/Cancelled +( 95,897 ) +6.16 +Unvested at December 31, 2023 +2,925,497 +$ 3.99 +Granted +1,555,000 +1.11 +Vested +( 1,479,169 ) +4.30 +Forfeited/Cancelled +( 259,012 ) +4.04 +Unvested at December 31, 2024 +2,742,316 +$ 2.50 +As +of December 31, 2024, there was $ 4.8 million of unrecognized stock-based compensation expense related to outstanding RSUs which is expected +to be recognized over a weighted-average period of 1.5 years. +Warrants +The +Company has issued warrants related to financings, acquisitions and as compensation to third parties for services provided. The Company +estimates the fair value of issued warrants on the date of issuance as determined using a Black-Scholes pricing model. The Company amortizes +the fair value of issued warrants using a vesting schedule based on the terms and conditions of each warrant if granted for services. +50 +The +following table summarizes warrant activity during the years ended December 31, 2024 and 2023: +Schedule of Warrant Activity +Number of Warrants +Weighted Average Exercise Price +Weighted Average Fair Value +Weighted Average Remaining Contractual Life (Years) +Outstanding at December 31, 2022 +485,000 +$ 8.81 +$ 2.43 +4.0 +Granted +- +- +- +Expired +- +- +- +Forfeited/Cancelled +- +- +- +Exercised +- +- +- +Outstanding at December 31, 2023 +485,000 +$ 8.81 +$ 1.29 +3.0 +Granted +- +- +- +Expired +- +- +- +Forfeited/Cancelled +- +- +- +Exercised +- +- +- +Outstanding at December 31, 2024 +485,000 +$ 8.81 +$ 1.00 +2.0 +There +were no warrants exercised during the years ended December 31, 2024 and 2023, respectively. The aggregate intrinsic value of outstanding +warrants at December 31, 2024 was approximately $ 0 . +The +total number of warrants exercisable at December 31, 2024 is 20,000 . The ability to exercise the approximately 465,000 warrants issued +in connection with acquisitions in prior years is contingent upon the achievement of certain development and revenue milestones on or +before January 1, 2027. There was no unrecognized stock-based compensation expense related to warrants. +Stock-Based +Compensation Expense +The +Company recognized stock-based compensation expense as follows: +Schedule of Recognized Stock-Based Compensation Expense +2024 +2023 +Years Ended December 31, +2024 +2023 +Cost of sales +$ 20,831 +$ 46,586 +Sales and marketing +1,068,175 +2,153,974 +General and administrative +3,985,281 +4,933,822 +Research and development +360,617 +1,202,473 +Total stock-based compensation expense +$ 5,434,904 +$ 8,336,855 +Note +11 – Income Taxes +The +components of the provision (benefit) for income taxes consist of the following for the years ended December 31, 2024 and 2023: +Schedule +of Components of Provision (Benefit) for Income Taxes +2024 +2023 +Years Ended December 31, +2024 +2023 +Current: +Federal +$ 40,031 +$ 84,435 +State +17,337 +( 540,240 ) +Total current +$ 57,368 +$ ( 455,805 ) +Deferred: +Federal +( 7,610,511 ) +( 7,228,611 ) +State +( 394,244 ) +( 2,068,509 ) +Change in valuation allowance +8,004,755 +6,975,234 +Total deferred +- +( 2,321,886 ) +Total income tax provision (benefit) +$ 57,368 +$ ( 2,777,691 ) +51 +A +reconciliation of income tax expense at the statutory federal income tax rate and income taxes as reflected in the financial statements +is as follows: +Schedule +of Benefit from Income Taxes and Effective Income Tax Rates +2024 +2023 +Years Ended December 31, +2024 +2023 +Federal income tax expense at statutory rate +21.0 % +21.0 % +State income tax expense, net of federal tax benefit +0.4 % +1.6 % +Permanent differences: +- Stock based compensation +- 2.0 % +- 3.5 % +- Contingent consideration remeasurement +0.4 % +0.6 % +- Other permanent differences +- 0.2 % +- 0.2 % +Research and development credits +1.8 % +4.6 % +Change in tax rate +0.0 +% +0.0 +% +Change in uncertain tax positions +- 0.3 % +1.2 % +Change in valuation allowance +- 21.3 % +- 18.3 % +Other +- 0.0 % +0.3 % +Effective income tax rate +- 0.2 % +7.3 % +Net +deferred tax liabilities consist of the following components as of December 31, 2024 and 2023: +Schedule of Deferred Tax Assets and Liabilities +2024 +2023 +December 31, +2024 +2023 +Deferred tax assets: +Accrued liabilities +$ 44,364 +$ 58,158 +Reserves and allowances +643,206 +734,631 +Deferred compensation +638,454 +620,551 +Section 174 costs +9,372,153 +7,337,629 +Lease liability +491,744 +742,131 +UNICAP +20,846 +43,943 +Net operating loss carryforwards +8,552,938 +4,040,601 +Research and development credits +2,314,332 +1,688,255 +Other +196 +- +Total gross deferred tax assets +22,078,233 +15,265,899 +Less valuation allowance +( 14,884,382 ) +( 6,938,829 ) +Total deferred tax assets +7,193,851 +8,327,070 +Deferred tax liabilities: +Property and equipment, net +( 418,148 ) +( 672,416 ) +Intangibles, net +( 5,963,713 ) +( 6,552,255 ) +Prepaids +( 233,162 ) +( 329,768 ) +Right of use asset +( 483,220 ) +( 736,226 ) +Other comprehensive income +( 95,608 ) +( 36,405 ) +Total deferred tax liabilities +( 7,193,851 ) +( 8,327,070 ) +Net deferred tax liability +$ - +$ - +Valuation allowances are established when necessary +to reduce deferred tax assets, including temporary differences and net operating loss carryforwards, to the amount expected to be realized +in the future. FASB guidance indicates that forming a conclusion that a valuation allowance is not needed is difficult when there is +negative evidence such as cumulative losses in recent years. The Company had cumulative losses from continuing operations for the three-year +period ended December 31, 2024. The Company considered this negative evidence along with all other available positive and negative evidence +and concluded that, at December 31, 2024, it is more likely than not that the Company’s U.S. deferred tax assets will not be realized. +As of December 31, 2024, a valuation allowance has been recorded on the Company’s deferred tax assets to recognize only the portion of +the deferred tax asset that is more likely than not to be recognized. The Company’s total valuation allowance was $ 14.9 million at December +31, 2024 and $ 6.9 million at December 31, 2023. +At +December 31, 2024, the Company had federal net operating loss carryforwards of $ 37.6 million and federal research and development credit +carryforwards of $ 2.0 million. The net operating losses have an indefinite carryforward period. If not utilized, the credits will begin +to expire in 2043. At December 31, 2024, the Company had state net operating loss carryforwards of $ 14.9 million and $ 0.9 million of +state research and development credit carryforwards. Of the total state net operating losses, approximately $ 10.8 million are attributable +to Utah. All of the Utah net operating losses are carried forward indefinitely. The remaining state net operating loss carryforwards +are attributable to various other states and begin to expire in 2044. If unused, the state research credit carryforward will expire in +2036. +52 +ASC +Topic 740-10-05 requires that the impact of a tax position be recognized in the financial statements if that position is more likely +than not of being sustained on audit, based on the technical merits of the position. Our unrecognized tax benefit balances included $ 1,200,035 +at December 31, 2024 and $ 1,078,431 at December 31, 2023 of tax positions that, if recognized, would reduce the annual effective tax +rate offset by deferred tax assets recorded for uncertain tax positions. During the next 12 months, the Company anticipates that approximately +$ 508,000 of previously unrecognized tax benefits, inclusive of interest and penalties, will be recognized due to the expiration of the +applicable statutes of limitations. Interest and penalties associated with uncertain tax positions are recorded as a component of income +tax expense. A reconciliation of the beginning and ending amount of unrecognized benefits is as follows: +Schedule of Unrecognized Tax Benefits +December 31, +2024 +2023 +Unrecognized tax benefits at the beginning of the year +$ 1,078,431 +$ 1,469,577 +Gross increases - current year tax positions +137,527 +273,569 +Gross increases - prior year tax positions +51,225 +66,127 +Gross decreases - prior year tax positions +( 67,148 ) +( 730,842 ) +Unrecognized tax benefits at end of year +$ 1,200,035 +$ 1,078,431 +Interest and penalties in year-end balance +$ 128,783 +$ 100,162 +The +Company is subject to taxation in the United States and other state jurisdictions. The tax years from December 31, 2021 through December +31, 2024 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which the Company +is subject. The Company is not currently under examination by any taxing authority. +Note +12 – Commitments and Contingencies +Lease +Obligations +The +Company leases administrative, R&D, sales and marketing and manufacturing facilities under non-cancellable operating leases and leases +cancellable with one month notice. The Company expenses the cancelable leases in the period incurred in accordance with the practical +expedient elected. During the year December 31, 2023, the Company amended two operating leases to extend the lease term and entered into +two new operating leases. As a result, the Company recognized additional operating lease liabilities and corresponding operating right-of-use +assets of $ 3,203,146 . +For +the years ended December 31, 2024 and 2023, respectively, components of lease expense are summarized as follows: +Schedule of Lease Expense +2024 +2023 +Years Ended +December 31, +2024 +2023 +Operating lease costs +$ 1,019,500 +$ 813,743 +Short-term lease costs +54,289 +198,261 +Total lease costs +$ 1,073,789 +$ 1,012,004 +As +of December 31, 2024, the maturities of the Company’s lease liabilities are as follows: +Schedule +of Maturities of Lease Liabilities +Years Ending +December 31, +2025 +$ 1,018,383 +2026 +714,630 +2027 +300,591 +2028 +308,462 +Total lease payments +2,342,066 +Less: imputed interest +189,887 +Present value of operating lease liabilities +2,152,179 +Less: current portion +915,619 +Long-term portion +$ 1,236,560 +53 +Other +information related to operating leases was as follows: +Schedule of Other Information Related to Operating Leases +Year Ended December 31, 2024 +Cash paid for operating leases included in operating cash flows +$ 1,050,279 +Remaining lease term of operating leases +2.8 +Discount rate of operating leases +6.2 % +Litigation +Liabilities +for loss contingencies arising from claims, assessments, litigation, fines, and penalties and other sources are recorded when it is probable +that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss contingencies +are expensed as incurred. +The +Company is a defendant in two class action claims and four derivative actions claiming that the Company promulgated false and misleading +press releases to increase the price of our stock to improperly benefit the officers and directors of the Company. The plaintiffs demand +compensatory damages sustained as a result of the Company’s alleged wrongdoing in an amount to be proven at trial. The Company +is also a party to three civil actions, two in the US and the other in the United Kingdom. Each of the civil actions is based on breach +of contract claims against the Company. The Company believes these lawsuits are without merit and intends to defend the cases vigorously. +The Company is unable to estimate a range of loss, if any, that could result were there to be an adverse final decision in these cases. +As of the date of this report, the Company does not believe it is probable that these cases will result in an unfavorable outcome; however, +if an unfavorable outcome were to occur in these cases, it is possible that the impact could be material to the Company’s results +of operations in the period(s) in which any such outcome becomes probable and estimable. +Note +13 – Share Repurchase Program +In +March 2022, the Company’s board of directors authorized a share repurchase program that would allow the Company to repurchase up +to $ 30.0 million of CODX common stock. The repurchase program does not obligate the Company to acquire any particular number of common +shares, and the repurchase program may be suspended or discontinued at any time at the Company’s discretion. The timing and amount +of any share repurchases under the share repurchase program will be determined by Co-Diagnostics’ management at its discretion +based on ongoing assessments of the capital needs of the business, the market price of the Company’s common stock, corporate and +regulatory requirements, and general market conditions. +For +accounting purposes, common stock repurchased under the stock repurchase program is recorded based upon the transaction date of the applicable +trade. Such repurchased shares are held in treasury and are presented using the cost method. These shares are not retired and are considered +issued but not outstanding. There were no shares repurchased under this program during the year ended December 31, 2024. +Note +14 – At-the-Market Agreement +We +have entered into an Equity Distribution Agreement (the “ATM Agreement”) with Piper Sandler & Co. (“Piper Sandler”), +pursuant to which we may offer and sell shares of our common stock having an aggregate offering price of up to $ 17,111,650 from time +to time through Piper Sandler acting as our agent, under our prospectus supplement dated October 18, 2024. As of December 31, 2024, we +have sold 314,707 shares of common stock under the ATM Agreement resulting in net proceeds to the Company of $ 0.2 million, of which $ 0.1 million was recorded in other current assets as of December +31, 2024 and subsequently collected in January 2025. As of December +31, 2024, the Company has up to $ 16.9 million remaining in aggregate gross proceeds that can be issued through the ATM Agreement. +Note +15 – Related Party Transactions +The +Company employs two employees who are related to current or former executive officers. Seth Egan, the Company’s Chief Commercialization +Officer, and Winston Egan, the Company’s Director of Customer Experience, are each sons of Dwight Egan, the Company’s President +and Chief Executive Officer and Chairman of the Board. During the year ended December 31, 2024, total compensation paid to Seth Egan, +including salaries, bonuses, and the grant date fair value of equity awards which vest over three years , was $ 0.4 million, and total +compensation paid to Winston Egan, including consulting fees, salaries, and bonuses, was $ 0.1 million. +Prior to the acquisition +of Advanced Conceptions by the Company in December 2021, the Company’s President, Richard Abbott was serving as President of Advanced +Conception. At the time of the acquisition, Mr. Abbott was an indirect shareholder of Advanced Conceptions, Inc. through his fifty percent +(50%) ownership interest in Whiteknob LLC. Whiteknob LLC owned 71.61% of Advanced Conceptions at the time of the acquisition. The terms +of the acquisition agreement between the Company and Advanced Conceptions include the opportunity for Whiteknob LLC to earn an additional +507,386 common shares and an additional 166,503 common stock purchase warrants of Co-Diagnostics upon the achievement of certain milestones. +Should those milestone events be achieved Mr. Abbott would have a fifty percent (50%) interest in the common shares and common stock +purchase warrants. +In +August 2023, the Company entered into a services agreement with CoSara, the Company’s equity method investment, under which CoSara +provides certain research and development consulting and support services. During the years ended December 31, 2024 and 2023, respectively, +the Company recognized $ 0.6 million and $ 0.2 million of expense related to this agreement. +Note +16 – Subsequent Events +On +January 10, 2025, the Company received a notice from the Listing Qualifications Department of The NASDAQ Stock Market (the “Staff”) +stating that the bid price of our common stock for the previous 30 consecutive trading days had closed below the minimum $1.00 per share +required for continued listing on The NASDAQ Capital Market under NASDAQ Listing Rule 5550(a)(2). The Company has a period of 180 calendar +days, or until July 9, 2025 (the “Compliance Date”) to regain compliance with Listing Rule 5550(a)(2). To regain compliance, +the bid price of the Company’s common stock must close at $1 or more for a minimum of ten consecutive business days before the +Compliance Date. +If +the Company does not regain compliance with Rule 5550(a)(2) by July 9, 2025, the Company may be eligible for additional time. To qualify, +the Company will be required to meet the continued listing requirement for market value of publicly held shares and all other initial +listing standards for The Nasdaq Capital Market, with the exception of the bid price requirement, and will need to provide written notice +of its intention to cure the deficiency during the second compliance period, by effecting a reverse stock split, if necessary. If the +Company meets these requirements, the Staff will inform the Company that it has been granted an additional 180 calendar days. However, +if it appears to the Staff that the Company will not be able to cure the deficiency, or if the Company is otherwise not eligible, the +Staff will provide notice that its securities will be subject to delisting. We intend to actively monitor our bid price and will consider +available options to resolve the deficiency and regain compliance with the Nasdaq Listing Rules. +54 +ITEM +9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE. +None. +ITEM +9A. CONTROLS AND PROCEDURES +Evaluation +of Disclosure Controls and Procedures +We +maintain a set of disclosure controls and procedures (as defined in Rule 13a-15(e) of the Exchange Act) designed to ensure that information +required to be disclosed in reports filed or submitted under the Exchange Act is recorded, processed, summarized, and reported within +the time periods specified in rules and forms adopted by the SEC. Disclosure controls and procedures include, without limitation, controls +and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under +the Exchange Act is accumulated and communicated to the Company’s management, including its principal executive and principal financial +officers, as appropriate to allow timely decisions regarding required disclosure. +Our +management, with the participation of our Chief Executive Officer and our Chief Financial Officer, evaluated the effectiveness of our +disclosure controls and procedures as of December 31, 2024. Based on the evaluation, management has concluded that our disclosure controls +and procedures are effective as of December 31, 2024 to provide reasonable assurance regarding the reliability of our financial reporting +and the preparation of our financial statements for external reporting purposes in accordance with U.S. generally accepted accounting +principles. +Changes +in Internal Control Over Financial Reporting +There +have not been any changes in the Company’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) +and 15d-15(f) under the Exchange Act) during the fourth quarter of 2024 that have materially affected, or are reasonably likely to materially +affect, the Company’s internal control over financial reporting. +Management’s +Annual Report on Internal Control over Financial Reporting +Our +management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) +under the Exchange Act). Our management, including our Chief Executive Officer and Chief Financial Officer, conducted an evaluation of +the effectiveness of our internal control over financial reporting as of December 31, 2024. In making its evaluation, management used +the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control – Integrated +Framework (2013). +Based +on this evaluation, management determined that our internal control over financial reporting was effective as of December 31, 2024. +This +Annual Report does not include an attestation report by our independent registered public accounting firm regarding internal control +over financial reporting since we are a non-accelerated filer. Management’s report was not subject to attestation by our registered +public accounting firm pursuant to rules of the SEC that permit non-accelerated filers to provide only management’s report in the +10-K. +55 +Inherent +Limitations on Effectiveness of Controls +Our +management, including our Chief Executive Officer and Chief Financial Officer, believes that our disclosure controls and procedures and +internal control over financial reporting are intended to be designed to provide reasonable assurance of achieving their objectives. +However, our management does not expect that our disclosure controls and procedures or our internal control over financial reporting +will prevent or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, +not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact +that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent +limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of +fraud, if any, have been detected. These inherent limitations include the realities that judgments in decision making can be faulty, +and that breakdowns can occur because of a simple error or mistake. Additionally, controls can be circumvented by the individual acts +of some persons, by collusion of two or more people or by management override of the controls. The design of any system of controls also +is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed +in achieving its stated goals under all potential future conditions; over time, controls may become inadequate because of changes in +conditions, or the degree of compliance with policies or procedures may deteriorate. Because of the inherent limitations in a cost–effective +control system, misstatements due to error or fraud may occur and not be detected. +ITEM +9B. OTHER INFORMATION +During +the three months ended December 31, 2024, none of our directors or officers adopted or terminated a “Rule 10-b5-1 trading arrangement” +or “non-Rule 10-b5-1 trading arrangement” as each term is identified in Item 408 of Regulation S-K. +ITEM +9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS. +None. +PART +III +ITEM +10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE. +The +following table sets forth the names, ages and positions of our executive officers and directors as of March 25, 2025. The following +is information on the business experience of each director and executive officer now serving and a discussion of the qualifications, +attributes and skills that led to the board of directors’ conclusion that each one is qualified to serve as a director or as an +executive officer as the case may be. Executive officers serve at the discretion of the board of directors. +Name +Age +Position +Dwight +Egan +71 +Chief +Executive Officer, President and Chairman of the Board +Brian +Brown +49 +Chief +Financial Officer and Secretary +Richard +Abbott +53 +President +Eugene +Durenard +55 +Director +James +Nelson +72 +Director +Richard +Serbin +80 +Director +Edward +Murphy +60 +Director +The +following is a brief summary of the background of each of our executive officers. +Dwight +Egan serves as our Chief Executive Officer and has been an officer and director of the Company since April 2013. Mr. Egan has been +engaged in private investment business from February 1999 to the present. He was a senior executive at Data Broadcasting Corporation, +a leading provider of wireless, real-time financial market data, news and sophisticated fixed- income portfolio analytics to 27,000 individual +and professional investors from 1995 to 1999. He co-founded and served as CEO and Chairman of the Board of Broadcast International, Inc. +from 1984 to 1995, when Data Broadcasting Corporation acquired Broadcast International and created CBS MarketWatch , a leading +financial news site and participated in its initial public offering. Mr. Egan’s prior experience in executive leadership positions +with public companies and working with capital markets qualifies him to serve as our Chairman Chief Executive Officer. +Brian +Brown became our Chief Financial Officer in February 2021. From July 2020 until February 2021, Mr. Brown served as the Chief Financial +Officer of A-Core Concrete Cutting, Inc. where his duties included overseeing the company’s accounting and finance departments, +mergers and acquisitions and responsibility for financial forecasting and budgeting. From January 2020 to July 2020, Mr. Brown was an +independent consultant. From August 2019 to December 2019, Mr. Brown served as the Vice President of Accounting, Treasury and Investor +Relations at Sportsman’s Warehouse Holdings, Inc., a public company reporting on Nasdaq Global Select under the symbol SPWH, where +his duties included overseeing the company’s accounting, treasury and investor relations departments, preparing the company’s +annual, quarterly and current reports with the SEC, overseeing all aspects of the company’s annual audit, including, but not limited +to, the preparation and review of audit support schedules, preparation of financial statements and footnotes, and providing support to +the company’s independent auditors. From October 2009 to August 2019, Mr. Brown served as the Director of Finance of Sportsman’s +Warehouse Holdings, Inc. where he assisted with the company’s initial public offering in April 2014 as well as effecting private +and secondary public offerings, acquisitions of a group of retail stores and preparing the company’s periodic and current reports +with the SEC and complying with the Sarbanes Oxley Act. From May 2005 to October 2009, Mr. Brown served as the Corporate Controller of +Franklin Covey Products where he developed and maintained the company’s internal controls over financial reporting structure in +accordance with the control standards required under Section 404 of the Sarbanes Oxley Act. From July 2001 to May 2005, Mr. Brown served +as an Assurance Senior at KPMG, LLP where he provided audit services to various clients in multiple industries. Mr. Brown holds a Bachelor +of Arts in Accounting and Masters of Professional Accountancy from the University of Utah. Mr. Brown is a licensed CPA in Utah. +Richard +Abbott has served as President of Co-Diagnostics since March 2024. Prior to being appointed as President, from January 2021 to March +2024, Mr. Abbott served as President of Advanced Conceptions, Inc., a privately held medical device company focused on the design of +automated instruments that solve challenging cross-disciplinary problems. Advanced Conceptions is a wholly owned subsidiary of Co-Diagnostics, +Inc. From September 2018 to January 2021, Mr. Abbott was a partner in SaltRidge, LLC through which he provided management services to +Advanced Conceptions and other consulting services. From August 2017 to August 2018, he served as the Chief Technology Officer for privately +held Vilicus, a cloud centered network provider of IoT devices for indoor agriculture. From October 2016 to July 2017, Mr. Abbott served +as the Chief Technology Officer for Fenome, a private company focused on the manipulation of phenotypic expression of indoor agriculture +crops via environmental control during growth and fruiting. Mr. Abbott holds a Master of Business Administration from The Wharton School +and a Master of Science, Mechanical Engineering and a Bachelors Mechanical Engineering from Brigham Young University. +56 +The +following is a brief summary of the background of each of our directors: +Eugene +Durenard has been a member of our board of directors since June 2019. Dr. Durenard is the Founder and CEO of Hyperbolic Holdings, +a Swiss-based holding, management consulting and strategy advisory company specialized in healthcare. For the last 7 years he has been +working with family offices on direct investments and philanthropy focused on life sciences. He serves on the advisory board of several +private companies in the biotech and MedTech sectors. After an initial career in proprietary research and trading at Salomon Brothers +and Credit Suisse in London, he co-founded Orion Investment Management in Bermuda specializing in quantitative asset and liability management +for institutions and private clients. He subsequently sold it to Capital G Bank and co-headed their asset management. Dr. Durenard spent +several years establishing personal connections with representatives of 40+ clusters of life science innovation, families operating healthcare +businesses and industry leaders globally. He regularly visits labs and incubators, meets with leading scientists and innovators in order +to keep abreast of current trends and developments. His advice is based on a thorough analysis that combines in-depth knowledge of science, +competitive forces and financial expertise. He has published several articles in asset-liability management industry magazines as well +as the book “Professional Automated Trading — Theory and Practice” (Wiley 2013). He has a PhD in Mathematics from Harvard +University. Dr. Durenard brings a thorough multi-asset class investment and entrepreneurial experience spanning 25 years to the Company’s +board of directors. We believe that Mr. Durenard’s knowledge of accounting and finance and his extensive experience in the life +science industry greatly benefits the Board. +James +Nelson has been a member of our board of directors since June 2019. Mr. Nelson is the retired Chairman and CEO of Sunworks, Inc., +a NASDAQ traded commercial, agriculture, and residential solar Integrator which he helped found in October 2010. Mr. Nelson spent most +of his career working in private equity as a general partner with Peterson Partners and with Millennial Capital Partners. In addition +to his investment and financial responsibilities, he served as CEO of two of his firms’ portfolio companies. Prior to his years +in private equity, Mr. Nelson served as Vice President of Marketing at Banana Republic, where he managed company-wide marketing, as well +as the company’s international expansion initiative. He was also general manager for Banana Republic’s catalog division. +He was Vice President of Marketing and Corporate Development at Saga Corporation, a multi-billion-dollar food service company. Mr. Nelson +began his executive career over 35 years ago at Bain and Company, a business strategy consulting firm, where he managed teams of consultants +on four continents. Mr. Nelson received his MBA from Brigham Young University, where he graduated summa cum laude and was named the Outstanding +Master of Business Administration Graduate. Mr. Nelson’s advice to the board of directors from his experiences as a chief executive +officer, strategic advisor and knowledge of capital markets greatly benefits our Board of Directors. +Richard +Serbin has been a member of our board of directors since May 2017. Mr. Serbin currently serves as a consultant to many companies +in the healthcare industry. Since January 2024, he has served as Chairman of the Board of Directors of Platform Pharmaceuticals. He was +the President of Corporate Development and In-House Legal Counsel at Life Science Institute, LLC, from June 1, 2013 to July 15, 2014. +He served as Director at Viropro Inc. from May 2013 to June 2014. He was Head of Business Advisory Board at Mazal Plant Pharmaceuticals +Inc. from October 2006 to September 2007 and also served as its Member of Business Advisory Board. He served as Chief Executive Officer +of Optigenex Inc. from July 2002 to September 15, 2005 and a director from July 2004 to September 2005. From January 1999 until July +2002 Mr. Serbin served as a consultant to various pharmaceutical companies. He served as the President of Bradley Pharmaceuticals. He +served as Vice President of Corporate Development at Ortho Pharmaceuticals, a Johnson & Johnson subsidiary, and practiced Patent +and FDA law at Revlon Johnson & Johnson and Schering-Plough. He served as Patent Attorney for Schering Plough Corporation and Chief +FDA Counsel for Revlon Corporation and Johnson and Johnson Corporation. Subsequently, he worked at Revlon Corporation, as its Chief Food, +Drug and Cosmetic Counsel. He founded Radius Scientific Corporation. He was J&J’s Vice President of Corporate Development, +and later led a successful public offering venture based on technology developed at Stanford Medical School. Mr. Serbin spent a large +portion of his career focusing on international markets and clients. While at J&J, Mr. Serbin served on the board of directors of +16 US and international subsidiary companies, including Ethicon, Ortho, J&J Consumer Products, Pittman-Moore, Mc Neil, and J&J +Development Corporation. He worked on multiple international acquisitions and strategic relationships, and sat on the board of directors +of several of its international subsidiaries, including those in India, Hong Kong, Japan, Taiwan, Germany, and England. Mr. Serbin has +a B.S. and a B. Pharmacy from Rutgers University and Rutgers University College of Pharmacy, a J.D. degree from Seton Hall Law School +and a Master’s Degree in Trade Regulations and Law from NYU Law School. Mr. Serbin’s experience in business, law and medicine +and knowledge gained as an advisor to the healthcare industry greatly benefits our Board of Directors, and is critical to our board of +directors as we continue to commercialize our products. +Edward +Murphy has been a member of our board of directors since June 2019. Since December 1999, Mr. Murphy has served as a senior vice president +and a partner of Dover Investments Ltd., a private investment firm. Throughout his career, Mr. Murphy’s duties have included investment +analysis of various types of investment projects in real estate and financial services. Currently, Mr. Murphy serves on the board of +directors of several Canadian and American publicly reporting companies that have interests in various industries. He has been a Director +at Empire Minerals Corporation Inc. since January 2016, at the Mosport Park Entertainment Corporation from April 30, 1997 until it became +Digicrypts Blockchain Solutions Inc. in June 2011 until he resigned in November 2022, at Lakefield Marketing Corporation since February +2018, CEO/CFO and Director of Credo Resources Inc. since September 2019, and at Essex Oil Ltd. since July 2021, and at Darkhorse Technologies +Ltd. since November 2021. He served as a Director at Aurquest Resources from May 2003 to December 2017. He has also served as Director +at E Ventures Inc. since April 2023. Mr. Murphy’s experience in the capital markets and his involvement in investment analysis +greatly benefits our Board of Directors. +Dwight +Egan – See narrative description above. +57 +Involvement +in Certain Legal Proceedings +To +the best of our knowledge, none of our directors or executive officers has been involved in any bankruptcy or criminal proceedings (other +than traffic and other minor offenses) or been subject to any of the items set forth under Item 401(f) of Regulation S-K, nor have there +been any judgments or injunctions brought against any of our directors or executive officers during the last ten years that we consider +material to the evaluation of the ability and integrity of any director or executive officer. +Board +and Committee Matters +Our +board of directors has five members. The Chairman of the Board and our Chief Executive Officer, Dwight Egan, is a member of the board +and is a full-time employee of the Company. Eugene Durenard, Edward Murphy, James Nelson and Richard Serbin are non-employee directors, +and the board has determined that these persons (who constitute a majority of the board) are “independent directors” under +the criteria set forth in Rule 5605(a)(2) of the Nasdaq Listing Rules. The board met seven times during the year ended December 31, 2024. +All directors attended more than seventy-five percent (75%) of the meetings of the board and committee meetings of which such director +was a member held during 2024. +We +maintain an audit committee of the board, a compensation committee of the board, a corporate governance committee of the board and a +nominating committee of the board, each of which is discussed below. Our board of directors may from time to time establish other standing +committees. In addition, from time to time, special committees may be established under the direction of our board of directors when +necessary to address specific issues. +The +following table sets forth a description of the four permanent board committees and the chairpersons and members of those committees, +all of whom are independent directors: +Committee +Independent +Chairperson +Independent +Members +Audit +Committee +Eugene +Durenard +Edward +Murphy +James +Nelson +Richard +S. Serbin +Compensation +Committee +Richard +S. Serbin +Edward +Murphy +Eugene +Durenard +James +Nelson +Governance +Committee +James +Nelson +Edward +Murphy +Eugene +Durenard +Richard +S. Serbin +Nominating +Committee +Edward +Murphy +James +Nelson +Eugene +Durenard +Richard +S. Serbin +Audit +Committee and Financial Expert +Our +audit committee currently is comprised of Messrs. Durenard, Nelson, Murphy and Serbin with Mr. Durenard serving as chairperson of the +audit committee. The functions of the audit committee include engaging an independent registered public accounting firm to audit our +annual financial statements, reviewing the independence of our auditors, the financial statements and the auditors’ report, and +reviewing management’s administration of our system of internal control over financial reporting and disclosure controls and procedures. +The board of directors has adopted a written audit committee charter. A current copy of the audit committee charter is available to security +holders on our website at www.codiagnostics.com. Our board has determined that all our directors that are serving on the audit committee +are “independent” under the definition of independence in the Marketplace rules of the NASDAQ listing standards. The Audit +Committee met four times during the year ended December 31, 2024. All committee members attended more than seventy-five percent (75%) +of the meetings of the Audit Committee held during 2024. +Our +board of directors has determined that Mr. Durenard meets the requirements of an “audit committee financial expert” as defined +in applicable SEC regulations. +58 +Compensation +Committee +Our +compensation committee currently includes Messrs. Serbin, Nelson, Murphy and Durenard with Mr. Serbin serving as chairperson of the compensation +committee. The functions of the compensation committee include reviewing and approving corporate goals relevant to compensation for executive +officers, evaluating the effectiveness of our compensation practices, evaluating and approving the compensation of our chief executive +officer and other executives, recommending compensation for board members, and reviewing and making recommendations regarding incentive +compensation and other employee benefit plans. The board of directors has adopted a written compensation committee charter. A current +copy of the compensation committee charter is available to shareholders on our website at www.codiagnostics.com. Our board has determined +that all of our directors serving on the compensation committee are “independent” under the definition of independence in +the Marketplace Rules of the NASDAQ listing standards. The Compensation Committee met two times as a separate committee in 2024. +Corporate +Governance Committee +Our +Corporate Governance Committee currently includes Messrs. Nelson, Murphy, Durenard and Serbin with Mr. Nelson serving as chairperson +of the Corporate Governance Committee. Among other items, the committee is tasked by the board of directors to develop and recommend +to the board the Corporate Governance Guidelines of the Company and oversee compliance therewith. A current copy of the Corporate Governance +committee charter is available to shareholders on our website at www.codiagnostics.com. Our board has determined all directors serving +on the Corporate Governance committee are “independent” under the definition of independence in the Marketplace Rules of +the NASDAQ listing standards. The Corporate Governance Committee did not meet as a separate committee in 2024, but rather, because the +committee is comprised of all four independent directors, committee matters were addressed as necessary in meetings of the board the +year ended December 31, 2024. +Nominating +Committee +Our +Nominating Committee was split from the Corporate Governance Committee in 2022 and currently includes Messrs. Nelson, Murphy, Durenard +and Serbin with Mr. Murphy serving as chairperson of the Nominating Committee. The Nominating Committee has been established by the board, +among other things to: assist the board in effecting board organization, membership and function including identifying qualified board +nominees; assist the board in effecting the organization, membership and function of board committees including the composition of board +committees and recommending qualified candidates therefor; evaluate and provide successor planning for the Chief Executive Officer and +other executive officers; and develop criteria for board membership, such as independence, term limits, age limits and ability of former +employees to serve on the board and the evaluation of candidates’ qualifications for nominations to the board and its committees +as well as removal therefrom. The Nominating Committee did not meet as a separate committee in 2024, but rather, because the committee +is comprised of all four independent directors, committee matters were addressed as necessary in meetings of the board for the year ended +December 31, 2024. +Board +Nominations +In +considering board candidates, the board seeks individuals of proven judgment and competence who have strong reputations in their respective +fields. Although we do not have a formal diversity policy, the board considers such factors as experience, education, employment history, +special talents or personal attributes, anticipated participation in board activities, and geographic and diversity factors. The process +for identifying and evaluating nominees would include detailed consideration of the recommendations and opinions of members of our board, +our executive officers, and our stockholders. There would be no difference in the process of evaluation of candidates recommended by +a stockholder and those recommended by other sources. +59 +Our +Amended and Restated Bylaws (the “Bylaws”) set forth procedures for shareholders to recommend nominees to the Company’s +board. Nominations of persons for election to the board of directors to be considered by the stockholders may be made at an annual meeting +of stockholders (i) pursuant to the Company’s notice of meeting, (ii) by or at the direction of the board of directors, or (iii) +by any stockholder of the Company who (A) was a stockholder of record at the time of giving of the notice, (B) is entitled to vote with +respect to such matter at the meeting, and (C) complies with the notice procedures set forth in the Bylaws. +The +following is a summary of key provisions from our Bylaws. For nominations to be properly brought before an annual meeting by a stockholder, +the stockholder making such nominations must have given timely notice in writing to the secretary of the Company. To be timely, a stockholder’s +notice shall be delivered to the secretary at the principal executive offices of the Company not later than the close of business on +the 7 5t h day nor earlier than the close of business on the 12 5t h day prior to the first anniversary of the preceding +year’s annual meeting; provided, however, that in the event that the date of the annual meeting is more than 30 days before or +more than 60 days after such anniversary date, notice by the stockholder to be timely must be so delivered not later than the close of +business on the later of (x) t he 75th day prior to the scheduled date of such annual meeting or (y) the 15th day following +the day on which public announcement of the date of such meeting is first made by the Company. To be in proper form, a stockholder’s +notice to the secretary must: set forth, as to the stockholder giving the notice and the beneficial owner, if any, on whose behalf the +nomination or proposal is made (A) the name and address of such stockholder, as they appear on the Company’s books, and of such +beneficial owner, if any, (B) the class or series and number of shares of the Company that are, directly or indirectly, owned beneficially +and of record by such stockholder and such beneficial owner, if any, as of the date of such notice, and (C) any other information relating +to such stockholder and beneficial owner, if any, that would be required to be disclosed in a proxy statement or other filings required +to be made in connection with solicitations of proxies for, as applicable, the proposal and/or for the election of directors in a contested +election pursuant to Section 14 of the Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder +(the “Exchange Act”). In addition, shareholders who intend to solicit proxies in support of director nominees other than +the company’s nominees must also comply with the additional requirements of Rule 14a-19(b). +The +notice shall set forth, as to each person, if any, whom the stockholder proposes to nominate for election or reelection as a director +(A) all information relating to such person that would be required to be disclosed in a proxy statement or other filings required to +be made in connection with solicitations of proxies for election of directors in a contested election pursuant to Section 14 of the Exchange +Act (including such person’s written consent to being named in the proxy statement as a nominee and to serving as a director if +elected) and (B) a description of all direct and indirect compensation and other monetary agreements, arrangements and understandings +during the past three years, and any other relationships, between or among such stockholder and beneficial owner, if any, and their respective +affiliates and associates, or others acting in concert therewith, on the one hand, and each proposed nominee, and his or her respective +affiliates and associates, or others acting in concert therewith, on the other hand, including, without limitation all information that +would be required to be disclosed pursuant to Rule 404 promulgated under Regulation S-K if the stockholder making the nomination and +any beneficial owner on whose behalf the nomination is made, if any, or any affiliate or associate thereof or person acting in concert +therewith, were the “registrant” for purposes of such rule and the nominee were a director or executive officer of such registrant; +and with respect to each nominee for election or reelection to the board of directors, include the completed and signed questionnaire, +representation, and agreement required by the Bylaws. The Company may require any proposed nominee to furnish such other information +as may reasonably be required by the Company to determine the eligibility of such proposed nominee to serve as an independent director +of the Company or that could be material to a reasonable stockholder’s understanding of the independence, or lack thereof, of such +nominee. +Communication +with the Board +We +have not, to date, developed a formal process for shareholder communications with the board of directors. We believe our current informal +process, in which any communication sent to the board of directors, either generally or in care of the chief executive officer, secretary +or other corporate officer or director, is forwarded to all members of the board of directors, has served the board’s and the shareholders’ +needs. +Conflicts +of Interests +On +an annual basis, each director and executive officer is obligated to complete a director and officer questionnaire that requires disclosure +of any transactions with our company, including related person transactions reportable under SEC rules, in which the director or executive +officer, or any member of his or her immediate family, have a direct or indirect material interest. Under our company’s standards +of conduct for employees, all employees, including the executive officers, are expected to avoid conflicts of interest. Pursuant to our +code of ethics for the chief executive officer and senior finance officers (as discussed below), such officers are prohibited from engaging +in any conflict of interest unless a specific exception has been granted by the board. All of our directors are subject to general fiduciary +standards to act in the best interests of our company and our shareholders. Conflicts of interest involving an executive officer or a +director are generally resolved by the board. +60 +Role +of the Board in Risk Oversight +Risk +is inherent with every business, and how well a business manages risk can ultimately determine its success. Management is responsible +for the day-to-day management of the risks that we face, while our board of directors, as a whole and through its committees, has responsibility +for the oversight of risk management. In its risk oversight role, our board of directors is responsible for satisfying itself that the +risk management processes designed and implemented by management are adequate and functioning as designed. +Our +board of directors does not have a standing risk management committee, but rather administers this oversight function directly through +our board of directors as a whole, as well as through various standing committees of the board of directors that address risks inherent +in their respective areas of oversight. In particular, our board of directors is responsible for monitoring and assessing strategic risk +exposure, including a determination of the nature and level of risk appropriate for us. Our Audit Committee has the responsibility to +consider and discuss our major financial risk exposures and the steps our management has taken to monitor and control these exposures, +including guidelines and policies to govern the process by which risk assessment and management is undertaken. The Audit Committee also +monitors oversight of the performance of our internal audit function. Our Corporate Governance Committee monitors the effectiveness of +our corporate governance guidelines, including whether they are successful in preventing illegal or improper liability-creating conduct. +Our Compensation Committee assesses and monitors whether any of our compensation policies and programs have the potential to encourage +excessive risk-taking or promote behaviors contra to our Code of Business Conduct. Our Nominating Committee assesses and monitors the +effectiveness of the board and its committees and evaluates board members and nominees for election to the board and succession planning +for the CEO and other executive officers. +Code +of Ethics +We +have adopted a code of ethics for our principal executive officer, principal financial officer, controller, or persons performing similar +functions. A copy of the code of ethics is included on our website at www.codiagnostics.com . +Insider +Trading Policy +We +have adopted an insider trading policy containing procedures governing the purchase, sale, and/or other dispositions of tour securities +by directors, officers and employees, and the company, that are reasonably designed to promote compliance with insider trading laws, +rules and regulations, and NASDAQ listing standards applicable to the Company. +Family +Relationships +There +are no family relationships among our directors and executive officers. +ITEM +11. EXECUTIVE COMPENSATION +We +are a “smaller reporting company” as defined in the rules and regulations of the SEC. As a smaller reporting company, we +may take advantage of specified reduced disclosure and other requirements that are otherwise applicable, in general, to public companies +that are not smaller reporting companies. Accordingly, this Report includes reduced disclosure about our executive compensation arrangements. +Summary +Compensation Table +The +table below summarizes the total compensation paid or earned by each of the named executive officers in their respective capacities for +the fiscal years ended December 31, 2024 and 2023. We have omitted in this report certain columns otherwise required to be included because +there was no compensation made with respect to such columns, as permitted by applicable SEC regulations. +Name and Principal Position +Year +Salary +Bonus (1) +Stock Awards (2) +All Other Comp +Total Compensation +Dwight Egan President & Chief Executive Officer +2024 +$ 391,667 +$ 20,000 +$ 305,250 +$ - +$ 716,917 +2023 +$ 375,000 +$ 40,750 +$ 845,550 +$ - +$ 1,261,300 +Brian Brown Chief Financial Officer and Secretary +2024 +$ 313,333 +$ 15,000 +$ 249,750 +$ - +$ 578,083 +2023 +$ 300,000 +$ 32,000 +$ 701,550 +$ - +$ 1,033,550 +Richard Abbott President +2024 +$ 276,666 +$ 15,000 +$ 133,200 +$ - +$ 424,866 +(1) +Bonuses +for the year ended December 31, 2023 include accrued bonus payments of $20,750 to Mr. Egan and $17,000 to Mr. Brown that were paid +in January 2024. +(2) +The +amounts reported in this column represent the aggregate grant date fair value of the restricted stock units, or RSUs, granted under +our 2015 Plan as computed in accordance with FASB ASC Topic 718. Note that the amounts reported in this column reflect the accounting +value for these equity awards and do not correspond to the actual economic value that may be received from the equity awards as the +RSUs vest over three years. +Narrative +Disclosure to Summary Compensation Table: We do not have written employment agreements with any of our executive officers. All of +our executive officers serve on an at-will basis. The base salaries for our named executive officers were determined by our compensation +committee after reviewing a number of factors, including: the responsibilities associated with the position, the seniority of the executive’s +position, the base salary level in prior years, and our financial position; and for executive officers other than our Chief Executive +Officer, recommendations made by our Chief Executive Officer. By utilizing a combination of objective and subjective performance factors +critical to our success, the board will award cash bonuses intended to incentivize our executive officers to achieve results that benefit +them and the Company. Performance factors include the achievement of predetermined financial performance objectives, adherence to financial +discipline measures and achievement of business development, product development and long-term business stability. The board may modify +or re-weight the objectives during the course of the fiscal year, if necessary, to reflect changes in our business plan. +61 +Outstanding +Equity Awards at Fiscal Year-End 2024 +The +following table contains certain information concerning outstanding equity awards for the Named Executive Officers as of December 31, +2024. +Option Awards +Stock Awards +Number of Securities Underlying Unexercised Options (#) +Option Exercise +Option Expiration +Number of Shares or Units of Stock That Have Not Vested +Market Value of Shares or Units of Stock That Have Not Vested +Number of Unearned Shares, Units or Other Rights That Have Not Vested +Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested +Name +Exercisable +Unexercisable +Price +Date +(#) +($) (1) +(#) +($) +Dwight Egan +50,000 +- +$ 2.63 +09/20/28 +- +- +- +- +50,000 +- +$ 1.10 +09/02/29 +- +- +- +- +- +- +- +- +45,833 (2) +$ 34,375 +- +- +- +- +- +- +51,667 (3) +$ 38,750 +- +- +- +- +- +- +137,500 (4) +$ 103,125 +- +- +- +- +- +- +229,167 (5) +$ 171,875 +- +- +Brian Brown +- +- +- +- +37,500 (2) +$ 28,125 +- +- +- +- +- +- +43,333 (3) +$ 32,500 +- +- +- +- +- +- +112,500 (4) +$ 84,375 +- +- +- +- +- +- +187,500 (5) +$ 140,625 +- +- +Richard Abbott +- +- +- +- +32,938 (6) +$ 24,704 +- +- +- +- +- +- +17,500 (3) +$ 13,125 +- +- +- +- +- +- +100,000 (5) +$ 75,000 +- +- +(1) +Based on $0.75 per share, which was the closing price of our common stock on December 31, 2024. +(2) +Consists of restricted stock units granted on 6/6/2022, which vest in 6 installments commencing on 11/23/2022 and continuing every six +months thereafter. +(3) +Consists of restricted stock units granted on 1/13/2023, which vest in 6 installments commencing on 5/23/2023 and continuing every six +months thereafter. +(4) +Consists of restricted stock units granted on 5/15/2023, which vest in 6 installments commencing on 11/23/2023 and continuing every six +months thereafter. +(5) +Consists of restricted stock units granted on 4/26/2024, which vest in 6 installments commencing on 11/23/2024 and continuing every six +months thereafter. +(6) +Consists of restricted stock units granted on 7/25/22, which vest in 6 installments commencing six months after the achievement of certain +specified milestones and continuing every six months thereafter. +Potential +Payments Upon Termination or Change of Control +At +the recommendation of the compensation committee of the board of directors, the Board approved the Co-Diagnostics, Inc. Change in Control +Severance Plan (the “Plan”). The Plan provides severance benefits to a select group of designated management or highly compensated +participants in the event their employment or affiliation with the Company or an affiliate is terminated due to a change in control (as +defined in the Plan). Participants entitled to benefits under the Plan are designated from time-to-time by the Compensation Committee +pursuant to the terms of an “Award Notice,” the form of which is appended to the Plan. The Award Notice identifies the eligible +participant and the Severance Multiplier (as defined in the Plan) to which the participant is entitled. The Compensation Committee approved +participation in the Plan for certain executives of the Company, including the Company’s CEO, Dwight Egan, with a Severance Multiplier +of three times his severance benefit and the Company’s CFO, Brian Brown, with a Severance Multiplier of two times his severance +benefit. +Under +the Plan, if a participant’s employment or affiliation is terminated without “cause” or by the participant for “good +reason” (each, as defined in the Plan) during the two-year period following a change in control, a participant will be entitled +to a severance benefit equal to the participant’s Severance Multiplier as set forth in the participant’s Award Notice, times +the sum of: (i) the participant’s annual base salary; and (ii) the greater of the participant’s target bonus or the average +of the three highest actual annual cash bonuses paid to participant over the five preceding completed years. +The +participant’s receipt of any of the payments or benefits is subject to the participant’s delivery to the Company of a separation +agreement of the type that are ordinarily entered into in similar situations, in a form acceptable to the Company, in its sole discretion, +which separation agreement may include a requirement for the participant to remain in the employ or service of the Company for a reasonable +period of time after completion of the Change in Control transaction to assist in any transition activities for which participant’s +services would be required. +Director +Compensation +We +use a combination of cash and stock-based incentive compensation to attract and retain qualified candidates to serve on its board of +directors. In setting director compensation, we consider the significant amount of time that directors expend in fulfilling their duties +as well as the skill level required by our members of the board. +62 +The +table below summarizes the compensation paid or accrued by us to each of our non-employee directors for the fiscal year ended December +31, 2024. +Name +Fees Earned or +Paid in Cash +Stock Awards: +Value of Restricted +Stock Units (1) +Total +Richard Serbin (2) +$ 100,000 +$ 122,100 +$ 222,100 +James Nelson (3) +$ 100,000 +$ 122,100 +$ 222,100 +Edward Murphy (4) +$ 100,000 +$ 122,100 +$ 222,100 +Eugene Durenard (5) +$ 100,000 +$ 122,100 +$ 222,100 +(1) +The +amounts reported in this column represent the aggregate grant date fair value of the restricted stock units, or RSUs, granted under +our 2015 Plan as computed in accordance with FASB ASC Topic 718. Note that the amounts reported in this column reflect the accounting +value for these equity awards and do not correspond to the actual economic value that may be received from the equity awards. The +RSUs vested immediately upon grant. +(2) +As +of December 31, 2024, Mr. Serbin had 151,667 RSU awards outstanding. +(3) +As +of December 31, 2024, Mr. Nelson had 151,667 RSU awards outstanding. +(4) +As +of December 31, 2024, Mr. Murphy had 151,667 RSU awards outstanding. +(5) +As +of December 31, 2024, Mr. Durenard had 151,667 RSU awards outstanding. +Our +non-employee directors receive cash compensation of $100,000 per year, paid quarterly. In 2023, they received 40,000 RSU’s vesting +1/6 th equally in November 2022, 2023, and 2024 and May 2023, 2024, and 2025, as well as 70,000 RSU’s vesting 1/6 th +equally in November 2023, 2024 and 2025 and May 2024, 2025 and 2026. In 2024, they also received 110,000 RSU’s vesting 1/6 th +equally in November 2024, 2025, and 2026 and May 2025, 2026, and 2027. In addition, non-employee directors may be entitled to receive +special awards of stock options or RSUs from time to time as determined by the board. The chairman of the board and the chairperson of +each of the audit, corporate governance, nomination, and compensation committees receive no additional fees for serving in such capacities. +There is no additional compensation for meeting attendance. Directors who are employees of the Company receive no additional compensation +for serving as directors. All stock options granted to outside directors are immediately exercisable and expire ten years from the date +of grant or 30 days after the date they cease to be directors. Directors are reimbursed for ordinary expenses incurred in connection +with attending board and committee meetings. +63 +Equity +Incentive Plans +Under +our Amended and Restated 2015 Long-term Incentive Plan (the “2015 Plan”), the board of directors may issue incentive stock-based +awards to employees, directors and consultants of the company. Options awarded generally expire ten years after being granted. Any stock-based +awards granted vest in accordance with the vesting schedule determined by the board of directors. Should an employee’s director’s +or consultant’s relationship with the company terminate before the vesting period is completed, the unvested portion of each grant +is forfeited. We continue to maintain and grant awards under the 2015 Plan which will remain in effect until its expiration by its terms. +The +purpose of our incentive plan is to advance the interests of our stockholders by enhancing our ability to attract, retain and motivate +persons who are expected to make important contributions to the company by providing them with both equity ownership opportunities and +performance-based incentives intended to align their interests with those of our stockholders. These plans are designed to provide us +with flexibility to select from among various equity-based compensation methods, and to be able to address changing accounting and tax +rules and corporate governance practices by optimally utilizing stock-based awards. +ITEM +12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS +The +following table sets forth certain information, as of March 21, 2025, with respect to the holdings of (1) each person who is the beneficial +owner of more than 5% of our Common Stock, (2) each of our directors, (3) each named executive officer, and (4) all of our current directors +and executive officers as a group. +Beneficial +ownership of the common stock is determined in accordance with the rules of the Securities and Exchange Commission and includes any shares +of common stock over which a person exercises sole or shared voting or investment power, or of which a person has a right to acquire +ownership at any time within 60 days of March 21, 2025. Applicable percentage ownership in the following table is based on 33,572,643 +shares of common stock plus, for each individual, any securities that individual has the right to acquire within 60 days of March 21, +2025. +The +information in the table below is based on information known to us or ascertained by us from public filings made by the stockholders. +Except as otherwise indicated in the table below, addresses of the director, executive officers and named beneficial owners are in care +of Co-Diagnostics, Inc., 2401 S. Foothill Drive, Suite D, Salt Lake City, Utah 84109. +Number of Shares Beneficially Owned +Percentage +of Class (1) +5% Stockholders +Vanguard Group (1) +1,781,283 +5.3 % +Named Executive Officers and Directors +Dwight Egan (2) +622,858 +1.8 % +Brian Brown +419,905 +1.3 % +Richard Abbott +604,731 +1.8 % +Edward Murphy (3) +213,333 +* +Eugene Durenard +163,333 +* +James Nelson (4) +225,833 +* +Richard Serbin (5) +186,278 +* +All Directors and Executive Officers as a Group (6 persons) +2,436,271 +7.2 % +*Represents +beneficial ownership of less than 1%. +(1) +Information +obtained from Schedule 13G/A filed with the SEC on February 13, 2024. Vanguard Group has an address of 100 Vanguard Blvd, Malvern, +PA, 19355. +(2) +Includes +exercisable options to acquire 100,000 shares of common stock. +(3) +Includes +exercisable options to acquire 50,000 shares of common stock. +(4) +Includes +exercisable options to acquire 50,000 shares of common stock. +(5) +Includes +exercisable options to acquire 20,445 shares of common stock. +Equity +Compensation Plan Information +Plan Category +(a) Number of Shares to be Issued upon Exercise of Outstanding Options and Rights +(b) Weighted-average Exercise Price of Outstanding Options and Rights +(c) Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Referenced in Column (a)) +Equity compensation plans approved by stockholders +3,782,888 (1) +$ 2.19 (2) +3,061,949 +Equity compensation plans not approved by stockholders +- +$ - +- +Total +3,782,888 (1) +$ 2.19 (2) +3,061,949 +(1) +Includes +options and restricted stock units outstanding under our 2015 Equity Incentive Plan. +(2) +Represents +weighted-average exercise price per share of common stock acquirable upon exercise of outstanding stock options. +64 +ITEM +13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE +The +Company employs two employees who are related to current or former executive officers. Seth Egan, the Company’s Chief Commercialization +Officer, and Winston Egan, the Company’s Director of Customer Experience, are each sons of Dwight Egan, the Company’s President +and Chief Executive Officer and Chairman of the Board. During the year ended December 31, 2024, total compensation paid to Seth Egan, +including salaries, bonuses, and the grant date fair value of equity awards which vest over three years, was $0.4 million, and total +compensation paid to Winston Egan, including consulting fees, salaries, and bonuses, was $0.1 million. +Prior +to the acquisition of Advanced Conceptions by the Company in December 2021, the Company’s President, Richard Abbott was serving +as President of Advanced Conception. At the time of the acquisition, Mr. Abbott was an indirect shareholder of Advanced Conceptions, +Inc. through his fifty percent (50%) ownership interest in Whiteknob LLC. Whiteknob LLC owned 71.61% of Advanced Conceptions at the time +of the acquisition. The terms of the acquisition agreement between the Company and Advanced Conceptions include the opportunity for Whiteknob +LLC to earn an additional 507,386 common shares and an additional 166,503 common stock purchase warrants of Co-Diagnostics upon the achievement +of certain milestones. Should those milestone events be achieved Mr. Abbott would have a fifty percent (50%) interest in the common shares +and common stock purchase warrants. +Policy +for Review of Related Party Transactions +The +review of transactions with related persons policy is set forth in our Corporate Governance Committee Charter. The Corporate Governance +Committee is to oversee the administration of any related party transactions policy in effect with respect to transactions in which the +Company is a participant and involving directors, nominees for director, executive officers of the Company or holders of more than 5% +of the Company’s common stock or immediate family members of any such person. +Director +Independence +For +information regarding the independence of our directors, see “Directors, Executive Officers and Corporate Governance” in +Part III, Item 10 of this Form 10-K. +ITEM +14. PRINCIPAL ACCOUNTANT FEES AND SERVICES +The +aggregate fees and expenses for professional services rendered by our principal accounting firm, Tanner LLC, for the years ended December +31, 2024 and 2023, respectively, are as follows: +Years Ended December 31, +2024 +2023 +Audit fees +$ 176,078 +$ 154,811 +Audit related fees +18,845 +- +Other consulting fees +- +287,838 +Tax fees +- +- +Total fees +$ 194,923 +$ 442,649 +Audit +fees consist of fees for professional services provided in connection with the audit of our annual consolidated financial statements, +review of our quarterly consolidated financial statements and our offerings. +Other +consulting fees relate to fees for products and services other than the services reported above and consist of federal and state research +tax credit consulting services (at a fixed fee). +The +audit committee has adopted a policy that requires advance approval of all services performed by the independent auditor when fees are +expected to exceed $15,000. The audit committee has delegated to the audit committee chairperson, Mr. Durenard, the authority to approve +services, subject to ratification by the audit committee at its next committee meeting. All fees incurred were pre-approved by the audit +committee. +65 +PART +IV +Item +15. Exhibits and Financial Statement Schedules. +(a) +The +following documents are filed as part of this Annual Report on Form 10-K: +(1) +Financial +Statements. The Consolidated Financial Statements filed as part of this Annual Report on Form 10-K are included in Part II, Item +8 of this Annual Report on Form 10-K. +(2) +Financial +statement schedules. There are no financial statements schedules included because they are either not applicable or the required +information is shown in the consolidated financial statements or the notes thereto. +(3) +Exhibits. +The exhibits required by Item 601 of Regulation S-K and Item 15(b) of this Annual Report are listed in the Exhibit Index below. The +exhibits listed in the Exhibit Index are incorporated by reference herein. +Exhibit +Number +Exhibit +Description +Filed +with this +Report +Incorporated +by +Reference +herein from Form or Schedule +Filing +Date +SEC +File/Reg. +Number +2.1*+ +Agreement and Plan of Merger by and between Co-Diagnostics, Inc, IDMO Acquisition Corp., Idaho Molecular Inc., and Company Representative dated as of December 21, 2021. +Form +8-K (Exhibit 2.1) +12/23/21 +001-38148 +2.1.2 +Amendment to Agreement and Plan of Merger by and among Co-Diagnostics, Inc., Idaho Molecular, Inc., and Kirk Ririe, as Company Representative +Form +8-K (Exhibit 2.2) +06/16/22 +001-38148 +2.2*+ +Agreement and Plan of Merger by and between Co-Diagnostics, Inc, ACI Acquisition Corp., Advanced Conceptions, Inc., and Company Representative dated as of December 21, 2021 +Form +8-K (Exhibit 2.2) +12/23/21 +001-38148 +2.2.1 +Amendment to Agreement and Plan of Merger by and among Co-Diagnostics, Inc., Advanced Conceptions, Inc., and Richard Abbott, as Company Representative +Form +8-K (Exhibit 2.1) +06/16/22 +001-38148 +3.1 +Articles of Incorporation +Draft +Registration Statement (Exhibit 3.1) +01/12/17 +377-01467 +3.1.1 +Amendment to the Articles of Incorporation +Draft +Registration Statement (Exhibit 3.1.1) +01/12/17 +377-01467 +3.1.2 +Articles of Amendment to Articles of Incorporation +Form +8-K (Exhibit 3.2) +01/03/19 +001-38148 +3.1.3 +Articles of Amendment +Form +10-K (Exhibit 3.1.3) +03/24/22 +001-38148 +3.1.3 +Articles of Amendment +Form +10-K (Exhibit 3.1.3) +03/16/2023 +001-38148 +3.2 +Amended and Restated Bylaws of Co-Diagnostics, Inc. +X +4.1 +Description of Registrant’s securities +X +4.2 +Form of Indenture +Registration +Statement (Exhibit 4.1) +03/16/23 +333-270628 +10.1 +Exclusive Agreement between Co-Diagnostics, Inc. and DNA Logix, Inc., dated April 18, 2014 +Draft +Registration Statement (Exhibit 10.2) +01/12/17 +377-01467 +10.2 # +Co-Diagnostics, Inc. Amended and Restated 2015 Long Term Incentive Plan +Form +S-8/A +11/20/20 +333-237684 +10.3 +Form of Indemnification Agreement +Form +S-1/A (Exhibit 10.13.8) +05/24/17 +333-217542 +10.4 +Shareholders’ Agreement between Co-Diagnostics and Synbiotics Limited, dated January 27, 2017 +Form +S-1 (Exhibit 10.16) +04/28/17 +333-217542 +10.5 +Amended Exclusive License Agreement between Co-Diagnostics, Brent Satterfield, and DNA Logix, Inc., dated January 1, 2017 +Form +S-1 (Exhibit 10.17) +04/28/17 +333-217542 +10.6 +Warrant Agreement between Co-Diagnostics, Inc and VStock Transfer, LLC. Dated December 31, 2021 (ACI Warrant) +Form +10-K (Exhibit 10.6) +03/24/22 +001-38148 +66 +10.7 +Warrant Agreement between Co-Diagnostics, Inc and VStock Transfer, LLC. Dated December 31, 2021 (IDMO Warrant) +Form +10-K (Exhibit 10.7) +03/24/22 +001-38148 +10.9 +Lease Agreement 2401 Foothill Drive +Form +10-K (Exhibit 10.9) +03/24/22 +001-38148 +10.9.1 +Amendment #1 to Lease +Form +10-K (Exhibit 10.9.1) +03/24/22 +001-38148 +10.9.2 +Amendment #2 to Lease +Form +10-K (Exhibit 10.9.2) +03/24/22 +001-38148 +10.10# +Co-Diagnostics, Inc. Change in Control Plan +Form +8-K (Exhibit 10.1) +05/16/23 +001-38148 +10.11 +Commercial Lease Agreement, dated June 1, 2023, between Ozone Biotech, LLC and Co-Diagnostics, Inc. +Form +10-Q (Exhibit 10.1) +08/10/23 +001-38148 +10.12 +Commercial Lease Agreement, dated September 18, 2023, between Ge Estate, LLC and Co-Diagnostics, Inc. +Form +10-Q (Exhibit 10.1) +11/09/23 +001-38148 +14.1 +Code of Ethics for Senior Financial Officers +Form +10-K (Exhibit 14.1) +03/30/20 +001-38148 +19 +Insider trading policies and procedures +X +21.1 +Subsidiaries of Registrant +X +23.1 +Consent of Tanner LLC +X +31.1 +Certification of Chief Executive Officer pursuant to section 302 of the Sarbanes-Oxley Act of 2002 +X +31.2 +Certification of Principal Financial Officer pursuant to section 302 of the Sarbanes-Oxley Act of 2002 +X +32.1 +Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 +X +32.2 +Certification of Principal Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 +X +97 +Co-Diagnostics, Inc. Clawback Policy +X +Form +10-K (Exhibit 97) +03/14/24 +001-38148 +101 +SCH +Inline +XBRL Taxonomy Extension Schema Document (A) +X +101.CAL +Inline +XBRL Taxonomy Extension Calculation Linkbase Document (A) +X +101.DEF +Inline +XBRL Taxonomy Extension Definition Linkbase Document (A) +X +101.LAB +Inline +XBRL Taxonomy Extension Label Linkbase Document (A) +X +101.PRE +Inline +XBRL Taxonomy Extension Presentation Linkbase Document (A) +X +104 +Cover +Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) +X +(A) +iXBRL +(INline Extensible Business Reporting Language) information +is furnished and not filed for purposes of Section 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange +Act of 1934. +X +# Management +Contract or Compensatory Plan or Arrangement +*Schedules +and exhibits to these Exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Company agrees to furnish supplementally +a copy of any omitted schedule or exhibit to the SEC upon request. ++ +Portions of Exhibit 2.1 and Exhibit 2.2 have been omitted as they contain information that (i) is not material and (ii) is the type of +information the issuer both customarily and actually treats as private and confidential. +Item +16. Form 10-K Summary. +None +67 +SIGNATURES +Pursuant +to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed +on its behalf by the undersigned thereunto duly authorized. +CO-DIAGNOSTICS, +INC. +Date: +March 27, 2025 +By: +/s/ +Dwight Egan +Dwight +Egan +Chief +Executive Officer, President and Director +(Principal +Executive Officer) +By: +/s/ +Brian Brown +Brian +Brown +Chief +Financial Officer +(Principal +Financial and Accounting Officer +Pursuant +to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the +registrant and in the capacities and on the date indicated. +Signature +Title +Date +/s/ +Dwight Egan +Chief +Executive Officer, President and Director +March +27, 2025 +Dwight +Egan +(Principal +Executive Officer) +/s/ +Brian Brown +Chief +Financial Officer +March +27, 2025 +Brian +Brown +(Principal +Financial and Accounting Officer) +/s/ +Eugene Durenard +Director +March +27, 2025 +Eugene +Durenard +/s/ +Edward Murphy +Director +March +27, 2025 +Edward +Murphy +/s/ +James Nelson +Director +March +27, 2025 +James +Nelson +/s/ +Richard Serbin +Director +March +27, 2025 +Richard +Serbin +68 \ No newline at end of file diff --git a/raw/filings/0001692415/2024/0001641172-25-000932/filing_metadata.csv b/raw/filings/0001692415/2024/0001641172-25-000932/filing_metadata.csv new file mode 100644 index 0000000000000000000000000000000000000000..5db85348113067f04fb2f22f8e795eeae0577ec5 --- /dev/null +++ b/raw/filings/0001692415/2024/0001641172-25-000932/filing_metadata.csv @@ -0,0 +1,2 @@ +cik,ticker,company_name,form,filing_date,report_date,acceptance_datetime,accession_number,primary_document,primary_doc_description,size,is_xbrl,is_inline_xbrl,document_url,filing_index_url,year,fiscal_year,is_primary_filing +0001692415,CODX,"Co-Diagnostics, Inc.",10-K,2025-03-27,2024-12-31,2025-03-28T00:10:24.000Z,0001641172-25-000932,form10-k.htm,,7794215,1,1,https://www.sec.gov/Archives/edgar/data/1692415/000164117225000932/form10-k.htm,https://www.sec.gov/Archives/edgar/data/1692415/000164117225000932/,2024,2024,1 diff --git a/raw/filings/0001692415/2024/0001641172-25-000932/item1.txt b/raw/filings/0001692415/2024/0001641172-25-000932/item1.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001692415/2024/0001641172-25-000932/item13.txt b/raw/filings/0001692415/2024/0001641172-25-000932/item13.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001692415/2024/0001641172-25-000932/item9a.txt b/raw/filings/0001692415/2024/0001641172-25-000932/item9a.txt new file mode 100644 index 0000000000000000000000000000000000000000..e69de29bb2d1d6434b8b29ae775ad8c2e48c5391 diff --git a/raw/filings/0001692415/2024/0001641172-25-000932/rp_note.txt b/raw/filings/0001692415/2024/0001641172-25-000932/rp_note.txt new file mode 100644 index 0000000000000000000000000000000000000000..63ae1374eac2c11f63d683eac449d9e954ec846d --- /dev/null +++ b/raw/filings/0001692415/2024/0001641172-25-000932/rp_note.txt @@ -0,0 +1,20 @@ +15 – Related Party Transactions +The +Company employs two employees who are related to current or former executive officers. Seth Egan, the Company’s Chief Commercialization +Officer, and Winston Egan, the Company’s Director of Customer Experience, are each sons of Dwight Egan, the Company’s President +and Chief Executive Officer and Chairman of the Board. During the year ended December 31, 2024, total compensation paid to Seth Egan, +including salaries, bonuses, and the grant date fair value of equity awards which vest over three years , was $ 0.4 million, and total +compensation paid to Winston Egan, including consulting fees, salaries, and bonuses, was $ 0.1 million. +Prior to the acquisition +of Advanced Conceptions by the Company in December 2021, the Company’s President, Richard Abbott was serving as President of Advanced +Conception. At the time of the acquisition, Mr. Abbott was an indirect shareholder of Advanced Conceptions, Inc. through his fifty percent +(50%) ownership interest in Whiteknob LLC. Whiteknob LLC owned 71.61% of Advanced Conceptions at the time of the acquisition. The terms +of the acquisition agreement between the Company and Advanced Conceptions include the opportunity for Whiteknob LLC to earn an additional +507,386 common shares and an additional 166,503 common stock purchase warrants of Co-Diagnostics upon the achievement of certain milestones. +Should those milestone events be achieved Mr. Abbott would have a fifty percent (50%) interest in the common shares and common stock +purchase warrants. +In +August 2023, the Company entered into a services agreement with CoSara, the Company’s equity method investment, under which CoSara +provides certain research and development consulting and support services. During the years ended December 31, 2024 and 2023, respectively, +the Company recognized $ 0.6 million and $ 0.2 million of expense related to this agreement. +Note \ No newline at end of file diff --git a/raw/filings/0001692415/2024/0001641172-25-000932/rpt_disclosure.txt b/raw/filings/0001692415/2024/0001641172-25-000932/rpt_disclosure.txt new file mode 100644 index 0000000000000000000000000000000000000000..94635aadd778638d52061ea4650b6d8159d8f8eb --- /dev/null +++ b/raw/filings/0001692415/2024/0001641172-25-000932/rpt_disclosure.txt @@ -0,0 +1,195 @@ +for Review of Related Party Transactions +The +review of transactions with related persons policy is set forth in our Corporate Governance Committee Charter. The Corporate Governance +Committee is to oversee the administration of any related party transactions policy in effect with respect to transactions in which the +Company is a participant and involving directors, nominees for director, executive officers of the Company or holders of more than 5% +of the Company’s common stock or immediate family members of any such person. +Pay +versus Performance +In +accordance with rules adopted by the Securities and Exchange Commission (“SEC”) pursuant to the Dodd-Frank Wall Street Reform +and Consumer Protection Act of 2010, we provide the following disclosure regarding executive “Compensation Actually Paid” +(“CAP”) and certain performance measures required for Smaller Reporting Companies. The following table provides the information +required for our NEOs for each of the fiscal years ended December 31, 2024 and December 31, 2023, along with the financial information +required for each fiscal year: +Year +Summary +compensation table total CEO ($) (1)(2) +Compensation +actually paid to CEO ($) (1)(3) +Average +summary compensation table total for non-CEO NEOs ($) (2)(4) +Average +compensation actually paid to non-CEO NEOs ($) (3)(4) +Value of Initial Fixed $100 Investment based on Total shareholder return ($) +Net Income (in millions) ($) +2024 +716,917 +421,350 +501,475 +346,524 +8.40 +( 38 ) +2023 +1,261,300 +579,599 +1,033,550 +485,150 +14.89 +( 35 ) +(1) +For each year shown the +CEO was Dwight Egan . +(2) +Amounts in this column +represent the “Total” column set forth above in the Summary Compensation Table (“SCT”). See the footnotes +to the SCT for further detail regarding the amounts in these columns. +(3) +The dollar amounts reported +in these columns represent the amounts of “compensation actually paid.” The Amounts are computed in accordance with Item +402(v) of Regulation S-K by deducting and adding the following amounts from the “Total” column of the SCT (pursuant to +SEC rules, fair value at each measurement date is computed in a manner consistent with the fair value methodology used to account +for share-based payments in our financial statements under GAAP). +(4) +During 2024, there were +two Non-CEO NEO’s, Brian Brown, CFO, and Richard Abbott, President. During 2023, there was one Non-CEO NEO, Brian Brown, CFO. +18 +2024 +2023 +Dwight Egan +Average Non-CEO NEOs +Dwight Egan +Average Non-CEO NEOs +Total Compensation from Summary Compensation Table +$ 716,917 +$ 501,475 +$ 1,261,300 +$ 1,033,550 +Adjustments for Equity Awards +Adjustment for grant date values in the Summary Compensation Table +$ ( 305,250 ) +$ ( 191,475 ) +$ ( 845,550 ) +$ ( 701,550 ) +Year-end fair value of unvested awards granted in the current year +$ 171,875 +$ 107,813 +$ 442,225 +$ 364,642 +Year-over-year difference of year-end fair values for unvested awards granted in prior years +$ ( 136,300 ) +$ ( 70,694 ) +$ ( 188,416 ) +$ ( 153,709 ) +Fair values at vest date for awards granted and vested in current year +$ 46,291 +$ 29,038 +$ 115,083 +$ 95,458 +Difference in fair values between prior year-end fair values and vest date fair values for awards granted in prior years +$ ( 72,183 ) +$ ( 29,633 ) +$ ( 205,043 ) +$ ( 153,241 ) +Forfeitures during current year equal to prior year-end fair value +$ - +$ - +$ - +$ - +Dividends or dividend equivalents not otherwise included in total compensation +$ - +$ - +$ - +$ - +Total Adjustments for Equity Awards +$ ( 295,567 ) +$ ( 154,951 ) +$ ( 681,701 ) +$ ( 548,400 ) +Compensation Actually Paid (as calculated) +$ 421,350 +$ 346,524 +$ 579,599 +$ 485,150 +Narrative +Disclosure: Pay Versus Performance Table +The +illustrations below provide a graphical description of CAP (as calculated in accordance with the SEC rules) and the following measures: +● +Co-Diagnostics’ cumulative +TSR ; and +● +Co-Diagnostics’ Net +Income +CAP +and Cumulative TSR +CAP +and Net Income +19 +STOCK +OWNERSHIP +The +following table sets forth certain information, as of April 3, 2025, with respect to the holdings of (1) each person who is the beneficial +owner of more than 5% of our Common Stock, (2) each of our directors, (3) each named executive officer, and (4) all of our current directors +and executive officers as a group. +Beneficial +ownership of the common stock is determined in accordance with the rules of the Securities and Exchange Commission and includes any shares +of common stock over which a person exercises sole or shared voting or investment power, or of which a person has a right to acquire +ownership at any time within 60 days of April 3, 2025. Applicable percentage ownership in the following table is based on 33,572,643 +shares of common stock plus, for each individual, any securities that individual has the right to acquire within 60 days of April 3, +2025. +The +information in the table below is based on information known to us or ascertained by us from public filings made by the stockholders. +Except as otherwise indicated in the table below, addresses of the director, executive officers and named beneficial owners are in care +of Co-Diagnostics, Inc., 2401 S. Foothill Drive, Suite D, Salt Lake City, Utah 84109. +Number of Shares Beneficially Owned +Percentage +of Class +5% Stockholders +Vanguard Group (1) +1,781,283 +5.3 % +Named Executive Officers and Directors +Dwight Egan (2) +736,548 +2.2 % +Brian Brown +513,292 +1.5 % +Richard Abbott +618,652 +1.8 % +Edward Murphy (3) +261,667 +* +Eugene Durenard +211,667 +* +James Nelson (4) +274,167 +* +Richard Serbin (5) +234,612 +* +All Directors and Executive Officers as a Group (7 persons) +2,850,605 +8.4 % +*Represents +beneficial ownership of less than 1%. +(1) +Information obtained from +Schedule 13G/A filed with the SEC on February 13, 2024. Vanguard Group has an address of 100 Vanguard Blvd, Malvern, PA, 19355. +(2) +Includes exercisable options +to acquire 100,000 shares of common stock. +(3) +Includes exercisable options +to acquire 50,000 shares of common stock. +(4) +Includes exercisable options +to acquire 50,000 shares of common stock. +(5) +Includes exercisable options +to acquire 20,445 shares of common stock. +PROPOSAL +NO. 2 – ADOPTION OF CO-DIAGNOSTICS, INC. \ No newline at end of file